10-K 1 form10k.htm FORM 10-K FOR THE YEAR ENDED 12/31/06 Form 10-K for the year ended 12/31/06

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, 2006
Or
o
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
 
PG&E Corporation
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)
 
Pacific Gas and Electric Company
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:
American Stock Exchange
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 o
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 ¨ No x
Pacific Gas and Electric Company
Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 
PG&E Corporation
Yes x No o
Pacific Gas and Electric Company
Yes x No ¨

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, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
PG&E Corporation
Large accelerated filer x
Accelerated filer ¨
Non-accelerated filer ¨
Pacific Gas and Electric Company
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer x


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation
Yes ¨ No x
Pacific Gas and Electric Company
Yes o No x

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2006, the last business day of the second fiscal quarter:
PG&E Corporation Common Stock
$13,640 million
Pacific Gas and Electric Company Common Stock
Wholly owned by PG&E Corporation
Common Stock outstanding as of February 20, 2007:
 
PG&E Corporation:
350,817,275 (excluding shares held by a wholly owned subsidiary)
Pacific Gas and Electric Company:
Wholly owned by PG&E Corporation

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:
Designated portions of the combined 2006 Annual Report to Shareholders
Part I (Item 1, Item 1.A.), Part II (Items 5, 6, 7, 7A, 8 and 9A)
Designated portions of the Joint Proxy Statement relating to the 2007
Part III (Items 10, 11, 12, 13 and 14)
Annual Meetings of Shareholders
 



TABLE OF CONTENTS

 
 
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Item 1.     Business 1
  General 1
 
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Energy Efficiency Programs
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Demand Response Programs
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Self-Generation Incentive, California Solar Initiative
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Low-Income Energy Efficiency Programs and California Alternate Rates for Energy
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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


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PG&E Corporation, incorporated in California in 1995, is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility engages in the businesses of electricity and natural gas distribution, electricity generation, procurement and transmission, and natural gas procurement, transportation and storage. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997.

The Utility served approximately 5.1 million electricity distribution customers and approximately 4.2 million natural gas distribution customers at December 31, 2006. The Utility had approximately $34.4 billion of assets at December 31, 2006, and generated revenues of approximately $12.5 billion in 2006. 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, and the Federal Energy Regulatory Commission, or the 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. 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.com, and the Utility's website, www.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, 2006, PG&E Corporation and its subsidiaries had approximately 20,400 employees, including approximately 20,200 employees of the Utility. Of the Utility's employees, approximately 13,400 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO, or the IBEW; the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC, or the ESC; and the Service Employees International Union, Local 24/7, or the SEIU. The ESC and IBEW collective bargaining agreements expire on December 31, 2008. The SEIU collective bargaining agreement expires on February 28, 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, 2006, or the 2006 Annual Report, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations and projections about future events, and assumptions regarding these events and management's knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated Utility rate base, estimated environmental remediation liabilities, the anticipated outcome of various regulatory and legal proceedings, 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” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:
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·  
the Utility’s ability to timely recover costs through rates;
 
·  
the outcome of regulatory proceedings, including ratemaking proceedings pending at the CPUC and the FERC;
 
·  
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 markets; 
 
·  
the effect of weather, storms, earthquakes, fires, floods, disease, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards that could affect the Utility’s facilities and operations, its customers and third parties on which the Utility relies;
 
·  
the potential impacts of climate change on the Utility’s electricity and natural gas operations;
 
·  
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, or other reasons;
 
·  
operating performance of the Utility’s Diablo Canyon nuclear generating facilities, or Diablo Canyon, the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;
 
·  
the ability of the Utility to recognize benefits from its initiatives to improve its business processes and customer service;
 
·  
the ability of the Utility to timely complete its planned capital investment projects;
 
·  
the impact of changes in federal or state laws, or their interpretation, on energy policy and the regulation of utilities and their holding companies;
 
·  
the impact of changing wholesale electric or gas market rules, including the California Independent System Operator’s, or the CAISO’s, new rules to restructure the California wholesale electricity market;
 
·  
how the CPUC administers the conditions imposed on PG&E Corporation when it became the Utility’s holding company;
 
·  
the extent to which PG&E Corporation or the Utility incurs costs in connection with pending litigation that are not recoverable through rates, from third parties, or through insurance recoveries;
 
·  
the ability of PG&E Corporation and/or the Utility to access capital markets and other sources of credit;
 
·  
the impact of environmental laws and regulations and the costs of compliance and remediation; and
 
·  
the effect of municipalization, direct access, community choice aggregation, or other forms of bypass.
 
For more information about the more significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation's and the Utility's future financial condition and results of operations, see the discussion under the heading “Risk Factors” that appears near the end of the section entitled “Management's Discussion and Analysis of Financial Condition and Results of Operations,” or the MD&A, in the 2006 Annual Report that is incorporated by reference into this Annual Report on Form 10-K. 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.

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As a public utility holding company, PG&E Corporation is subject to the requirements of the Energy Policy Act of 2005, or the EPAct, which became effective on February 8, 2006. Among its key provisions, the EPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005, or PUHCA 2005. Under PUHCA 2005, public utility holding companies fall principally under the regulatory oversight of the FERC, an independent agency within the U.S. Department of Energy, or the DOE.

During 2006, the FERC issued rules implementing PUHCA 2005 that impose on holding companies and their subsidiaries various requirements concerning access to books and records, accounting, record retention and the filing of reports. On June 15, 2006, PG&E Corporation filed a notification of waiver with the FERC, which was deemed granted by operation of law on August 14, 2006. The effect of this waiver is to exempt PG&E Corporation and its subsidiaries from all requirements of PUHCA 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes. The books and records provisions to which PG&E Corporation and its subsidiaries remain subject under PUHCA 2005 are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.

In addition to enacting PUHCA 2005, the EPAct also significantly modified the FERC's authority and standard of review for mergers and consolidations involving public utilities and their holding companies under Section 203 of the Federal Power Act of 1935.


PG&E Corporation is not a public utility under the laws of California. The CPUC has authorized the formation of public utility holding companies subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:

·  
the Utility cannot guarantee any obligations of PG&E Corporation without prior written consent from the CPUC;
 
·  
the Utility's dividend policy must be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company;
 
·  
the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation's Board of Directors (known as the “first priority” condition); and
 
·  
The Utility must maintain on average its CPUC-authorized utility capital structure, although it can request a waiver of this condition if an adverse financial event reduces the Utility's equity ratio by 1% or more.
 

(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 natural gas distribution companies and their non-regulated affiliates. The rules address the use of the regulated utilities’ names and logos by their non-regulated affiliates, the separation of regulated utilities and their non-regulated affiliates, information exchange among the affiliates, and energy procurement-related transactions among regulated utilities and their non-regulated 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 non-regulated affiliates. In December 2006, the CPUC revised its rules to, among other changes:

·  
emphasize that the holding company may not aid or abet a utility's violation of the rules or act as a conduit to provide confidential information to an affiliate;

·  
require prior CPUC approval before the utility can contract with an affiliate for resource procurement (e.g., electricity or gas), except in blind transactions where the identity of the other party is not known until the transaction is consummated;

·  
require certain key officers to provide annual certifications of compliance with the affiliate rules;

3
·  
prohibit certain key officers from serving in the same position at both the utility and the holding company, 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;

·  
adopt as part of the affiliate rules the utilities’ current requirements to maintain a balanced capital structure (proportions of equity, long term debt, and preferred stock) consistent with that most recently determined to be reasonable by the CPUC; and
 
·  
make the CPUC's Energy Division responsible for hiring the independent auditors to conduct the biennial audits to verify that the utility is in compliance with the affiliate rules.

The CPUC has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.


Various aspects of the Utility's business are subject to a complex set of energy, environmental and other governmental laws, regulations and regulatory proceedings at the federal, state and local levels. In addition to enacting PUHCA 2005 to replace the Public Utility Holding Company Act of 1935 as discussed above, the EPAct significantly amended various federal energy laws applicable to electric and natural gas markets, including the Federal Power Act of 1935, the Natural Gas Act of 1938 and the Public Utility Regulatory Policies Act of 1978, or 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 regulatory proceedings affecting the Utility, see the section of the MD&A entitled “Regulatory Matters” in the 2006 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 bulk power system, the FERC certified the North American Electric Reliability Corp., or the NERC, as the nation’s Electric Reliability Organization under the EPAct. The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC review. All proposed reliability standards must be submitted by the NERC to the FERC for its approval. The NERC has requested the FERC to approve a delegation agreement to permit the NERC to delegate its enforcement authority for a geographic area known as the Western Interconnection to the Western Electricity Coordinating Council. Failure of the Utility to comply with FERC-approved electric reliability standards may subject the Utility to penalties.  In addition, the CAISO is responsible for providing open access electricity transmission service on a non-discriminatory basis, planning transmission system additions and assuring the maintenance of adequate reserves of generation capacity.

The FERC also has issued a rule on electric transmission pricing reforms designed to promote needed investment in energy infrastructure and to reduce transmission congestion. In addition, the FERC issued a rule to require transmission organizations with organized electricity markets to make available to load-serving entities long-term firm transmission rights so these entities can enter into long-term transmission service arrangements without being exposed to unhedged congestion cost risk.

4
Prevention of Market Manipulation. The EPAct also gave the FERC broader authority to police and penalize the exercise of market power or behavior intended to manipulate the prices paid in FERC-jurisdictional transactions. In January 2006, the FERC adopted rules to prohibit market manipulation, modeling its new rules on SEC Rule 10b-5, which prohibits fraud and manipulation in the purchase or sale of securities. Under the FERC's new regulations, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas, electric energy, or transportation/transmission services subject to the jurisdiction of the FERC: (1) to use or employ any device, scheme or artifice to defraud, (2) to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (3) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any person.

Several parties, including the Utility and the State of California, are seeking refunds on behalf of California electricity purchasers from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and California Power Exchange, or PX, wholesale electricity markets between May 2000 and June 2001 through various proceedings pending at the FERC and other judicial proceedings. Many issues raised in these proceedings, including the extent of the FERC’s refund authority, and the amount of potential refunds after taking into account certain costs incurred by the electricity suppliers, have not been resolved. It is uncertain when these proceedings will be concluded.

The Utility has entered into settlements with various electricity suppliers resolving certain disputed claims and the Utility's refund claims against these power suppliers. The Utility continues to pursue additional refunds through settlement discussions with other electricity suppliers. Future amounts received under these settlements, and any future settlements with electricity suppliers, will be credited to customers after deductions for contingencies and amounts related to certain wholesale power purchases. For further discussion, see the section of Note 17: Commitments and Contingencies - California Energy Crisis Proceedings, of the Notes to the Consolidated Financial Statements in the 2006 Annual Report.

QF Regulation. Under PURPA, electric utilities were required to purchase energy and capacity from independent power producers that are qualifying cogeneration facilities, or QFs. To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with QFs and approved the applicable terms, conditions, prices and eligibility requirements. The EPAct significantly amended the purchase requirements of PURPA. As amended, Section 210(m) of PURPA authorizes the FERC to waive the obligation of an electric utility under Section 210 of PURPA to purchase the electricity offered to it by a QF (under a new contract or obligation) if the FERC finds that the QF has nondiscriminatory access to one of three defined categories of competitive wholesale electricity markets. The statute permits such waivers as to a particular QF or on a “service territory-wide basis.” The Utility plans to wait until after the new day-ahead market structure provided for in the CAISO’s Market Redesign and Technology Update, or MRTU, initiative to restructure the California electricity market becomes effective to assess whether it will file a request with the FERC to terminate its obligations under PURPA to enter into new QF purchase obligations.


The Nuclear Regulatory Commission, or the NRC, oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay, or 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 this plant. For a discussion of the Utility’s spent fuel storage project, see “Environmental Matters - Nuclear Fuel Disposal,” below.



The Utility's operations have been significantly affected by various statutes passed by the California legislature, including:

·  
Assembly Bill 1890. Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry, commencing in 1998 with the implementation of a market framework for electricity generation in which generators and other energy providers were permitted to charge market-based rates for wholesale electricity and the investor-owned utilities’ customers were given the choice to become “direct access” customers by buying energy from an alternate service provider other than the regulated utilities. Among other provisions, Assembly Bill 1890 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.

5
·  
Assembly Bill 1X. Assembly Bill 1X, enacted during the California 2000-2001 energy crisis, authorized the California Department of Water Resources, or the 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 long-term contracts and to act as the DWR's billing and collection agent.
    
·  
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 recover their reasonable wholesale procurement costs incurred under a CPUC-approved procurement plan through the establishment of new electricity procurement balancing accounts to allow timely recovery by the utilities of 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 SB 107 enacted in September 2006 and effective on January 1, 2007) established the Renewables Portfolio Standard Program, which requires each California retail seller of electricity, except municipal utilities, to increase its purchases of eligible renewable energy (such as biomass, small hydro, wind, solar and geothermal energy) by at least 1% of its retail sales per year, the annual procurement target, so that the amount of electricity purchased from eligible renewable resources equals at least 20% of its total retail sales by 2010.
 
·  
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, but not limited to, 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 to address climate change, requires the California Air Resources Board, or the CARB, to adopt regulations to limit statewide greenhouse gas emissions, to 1990 levels by 2020. (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.)


The CPUC has jurisdiction to set the rates, terms and conditions of service for the Utility's electricity distribution, electricity generation, natural gas distribution, and natural gas transportation and storage services in California. The CPUC also has jurisdiction over the Utility's issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility's electricity and natural gas retail customers, rate of return, rates of depreciation, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning and aspects of the siting of the electricity transmission system. Ratemaking for retail sales from the Utility's generation facilities is under the jurisdiction of the CPUC. To the extent that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews utility performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms.

6
PG&E Corporation and the Utility entered into a settlement agreement with the CPUC on December 19, 2003 to resolve the Utility's proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California, or the Bankruptcy Court, since April 2001, referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters in order to restore the Utility’s financial health and enable it to emerge from Chapter 11 and fully resume its traditional role of providing safe and reliable electric and gas service at just and reasonable rates, subject to CPUC regulation. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11 which became effective on April 12, 2004. Although the Utility's operations are no longer subject to the oversight of the Bankruptcy Court, the Bankruptcy Court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of the Chapter 11 Settlement Agreement, in addition to other matters. (For more information, see Note 15 of the Notes to the Consolidated Financial Statements included in the 2006 Annual Report.)


The California Energy Resources Conservation and Development Commission, commonly called the California Energy

Commission, or the CEC, is the state's primary energy policy and planning agency. The CEC is responsible for licensing of all thermal power plants over 50 MW, overseeing funding programs that support public interest energy research, advancing energy science and technology through research, development and demonstration, and providing market support to existing, new and emerging renewable technologies. In addition, the CEC is responsible for forecasting future energy needs used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.


The Utility obtains permits, authorizations and licenses in connection with the construction and operation of the Utility's generation facilities, electricity transmission lines, natural gas transportation pipelines and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the more significant examples. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. (For more information see “Environmental Matters - Water Quality” below.)

The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate and maintain the Utility's electric, natural gas, oil and water 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. However, there are 38 charter cities that can set fees of their own determination. The Utility also periodically obtains permits, authorizations and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations and licenses, the Utility has rights to occupy and/or use public property for the operation of the Utility's business and to conduct certain related operations.


Historically, energy utilities operated as regulated monopolies within service territories where 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.

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Even before the passage of the EPAct, the FERC's policies supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities' transmission grids. Order 888 requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to have on file open access non-discriminatory transmission tariffs, or OATT, that contain minimum terms and conditions of non-discriminatory service. The FERC's subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations, and advanced the view that a regulated, unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. On February 16, 2007, the FERC issued Order 890 that is designed to (1) strengthen the form of OATT adopted in Order 888 to ensure that it achieves its original purpose of remedying undue discrimination; (2) provide greater specificity in the form of OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement; and (3) increase transparency in the rules applicable to planning and use of the transmission system.

The FERC also has issued rules on the interconnection of generators larger than 20 MW with a transmission system to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections. These rules are intended to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generation and transmission. Under the rules and associated tariffs, a new generator is required to pay for the transmission system upgrades needed in order to interconnect the generator. The generator will be reimbursed over a five-year period after the power plant achieves commercial operation. The cost of the network upgrades then is recovered by the regulated transmission provider in its overall transmission rates.

State. At the state level, Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry commencing in 1998. Assembly Bill 1890 established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity through transactions conducted on the PX. As a result of the California 2000-2001 energy crisis, the PX filed a petition for bankruptcy protection and now operates solely to reconcile remaining refund amounts owed and make compliance filings as required by the FERC in the California refund proceeding still pending at the FERC. Established pursuant to AB 1890 to take control of the California investor-owned electric transmission facilities in California, the CAISO currently administers a real-time or “spot” wholesale market for the sale of electric energy. The market is used to allocate space on the transmission lines, maintain operating reserves and match supply with demand in real time. In September 2006, the FERC approved the CAISO’s proposal to establish its MRTU initiative to restructure the California electricity market and to enhance power grid reliability. The FERC directed the CAISO to make certain changes to the MRTU proposal, including a requirement to comply with the FERC’s new rule that regional transmission organizations provide long-term transmission rights to users of the transmission grid. The MRTU tariffs, currently estimated to become effective on January 31, 2008, will apply to all load-serving entities, including the investor-owned utilities, serving California consumers.

Assembly Bill 1890 also permitted retail end-use customers to choose their energy service provider by becoming a direct access customer. 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 on behalf of the customers of the California investor-owned electric utilities. The CPUC suspended direct access on September 20, 2001. 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 has been asked to open a proceeding to determine whether to re-establish direct access by January 1, 2008. Although the Utility supports the ability of customers to choose their energy provider, the Utility believes there are a number of important policy and implementation questions that must be addressed before re-establishing direct access in order to ensure that all customers are treated equitably, with no undue cost responsibility burdens or risks being placed either on any one customer group or on the utilities.

The Utility’s customers may also obtain power from a “community choice aggregator” instead of obtaining power from the Utility. California Assembly Bill 117, enacted in 2002, permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators. Under Assembly Bill 117, the Utility 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. The CPUC has adopted rules to implement community choice aggregation, including the imposition of a surcharge on retail end-users of the community choice aggregator to prevent a shifting of costs to customers of a utility who receive bundled services. 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.

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FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of California and are exempt from FERC rules and regulations applicable to interstate pipelines. Instead, the Utility’s pipeline operations are subject to the jurisdiction of the CPUC.

                 The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998. This market structure largely mimics the regulatory framework required by FERC for interstate gas pipelines. The original Gas Accord, approved by the CPUC in 1998, is a CPUC-approved settlement agreement reached among the Utility and many interested parties, under which the natural gas transportation and storage services that the Utility provides were separated for ratemaking purposes from the Utility's distribution services. The Gas Accord changed the terms of service and rate structure for natural gas transportation, allowing the Utility's core customers (i.e., residential and small commercial customers) greater flexibility to purchase natural gas from competing suppliers. The Utility's noncore customers (i.e., industrial, larger commercial and electric generation 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.

Under the Gas Accord structure noncore customers have access to capacity rights for firm service, as well as interruptible (or “as-available”) services. All services are offered on a nondiscriminatory basis to any creditworthy customer. The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utility’s “citygate,” which refers to the interconnection between the big “backbone” gas transmission system and the smaller, downstream local transmission systems.

In December 2004, the CPUC approved the Gas Accord III which retained the Gas Accord market structure and resolved the rates, terms and conditions of service for the Utility’s natural gas and transportation system through 2007. The Utility is obligated to file a new rate case proposing gas transmission and storage rates and terms and conditions of service, for the period commencing January 1, 2008.  The Utility currently is scheduled to submit that filing on March 15, 2007.  In the event the CPUC does not issue a final decision approving new rates effective January 1, 2008, the Gas Accord III provides that the rates and terms and conditions of service in effect as of December 31, 2007, will remain in effect, with an automatic 2 percent escalation in the rates as of January 1, 2008.

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.

PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Northwest Pipeline Corporation, have agreed to jointly pursue the development of a new 232-mile interstate gas transmission pipeline that would increase natural gas supplies for the entire West Coast region of the United States. The proposed Pacific Connector Gas Pipeline, together with the Jordan Cove liquefied natural gas, or LNG, terminal in Coos Bay, Oregon, being developed by Fort Chicago Partners, L.P., would open growing West Coast natural gas markets to diverse worldwide natural gas supply sources, providing additional alternatives to traditional Canadian, Southwest and Rocky Mountain supplies and increasing supply options and reliability. The proposed Pacific Connector Gas Pipeline would connect the proposed Jordan Cove LNG terminal to Northwest Pipeline Corporation’s pipeline system in Oregon, and to the Utility's backbone gas transmission system near Malin, Oregon. Other potential interconnects include Tuscarora Gas Transmission Company’s pipeline system which serves northern Nevada. The proposed Pacific Connector Gas Pipeline would be capable of delivering 1 bcf per day to the West Coast natural gas market, to customers in the Pacific Northwest through Northwest Pipeline Corporation's pipeline system, to the Utility's system for delivery to customers in California, and to customers in northern Nevada through Tuscarora Gas Transmission Company’s pipeline system. On May 1, 2006, the FERC approved a request to begin the environmental assessment process for the Pacific Connector Gas Pipeline under the National Environmental Policy Act. The public will have an opportunity to participate in this process.  The full application to request the FERC’s authorization to construct the Pacific Connector Gas Pipeline is scheduled to be submitted to the FERC in April 2007. The development and construction of the Pacific Connector Gas Pipeline depends upon the construction of the proposed LNG terminal at Jordan Cove by Fort Chicago Partners, L.P. PG&E Corporation cannot predict whether Fort Chicago Partners, L.P. will be successful in completing the development and construction of its proposed LNG terminal.  In addition, the development and construction of the proposed LNG terminal and the proposed Pacific Connector Gas Pipeline are subject to obtaining required permits, regulatory approvals, and commitments under long-term transportation contracts. Assuming the required permits, authorizations, and long-term transportation commitments are timely received and that other conditions are timely satisfied, it is anticipated that the proposed LNG terminal and the proposed Pacific Connector Gas Pipeline would begin commercial operation in 2011.

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The Utility’s rates for electricity and natural gas utility services are based on its costs of service. Before rates can be set, the CPUC and the FERC must determine the amount of “revenue requirements” that the Utility can collect from its customers. The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations.

Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of providing utility services, including a return of, and a fair rate of return on, its investment in utility facilities, or rate base. Revenue requirements are primarily determined based on the Utility’s forecast of future costs, including the costs of purchasing electricity and natural gas for the Utility's customers. The components of revenue requirements for electricity and natural gas utility service include depreciation, operating, administrative and general expenses, taxes and return on investment, as applicable, for each area of these services, including distribution, transmission, transportation, generation, procurement and public purpose programs.

The Utility’s regulatory balancing accounts are used as a mechanism for the Utility to recover amounts incurred for certain costs, primarily commodity costs. Sales balancing accounts accumulate differences between revenues and the Utility's authorized revenue requirements. Cost balancing accounts accumulate differences between incurred costs and authorized revenue requirements. The Utility also obtained CPUC approval for balancing account treatment of variances between forecasted and actual commodity costs and volumes. 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, the Utility may be unable to earn its authorized rate of return.

The amount of authorized revenue requirements are allocated among customer classes (mainly residential, commercial, industrial and agricultural) and specific rates are established to produce the required revenue. The Utility's rates reflect the sum of individual revenue requirement components authorized by the CPUC and the FERC. Changes in any individual revenue requirement affect customers' rates and could affect the Utility's revenues. The timing of the CPUC and other regulatory decisions affect when the Utility is able to record the authorized revenues. In annual true-up proceedings, the Utility requests the CPUC to authorize an adjustment to electric and gas rates effective to (1) reflect over- and under-collections in the Utility's major electric and gas balancing accounts, and (2) implement various other electricity and gas revenue requirement changes authorized by the CPUC or the FERC. Generally, rate changes become effective on the first day of the following year. Balances in all CPUC-authorized accounts are subject to review, verification audit and adjustment, if necessary, by the CPUC.



The General Rate Case, or GRC, is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC every three years. The CPUC sets revenue requirement levels for a three-year rate period based on a forecast of costs for the first, or test, year. Typical interveners in the Utility's GRC include the CPUC’s Division of Ratepayer Advocates, or the DRA, and The Utility Reform Network, or TURN. On August 21, 2006, the Utility, together with the DRA and other parties, filed a motion with the CPUC seeking approval of a settlement agreement reached among the parties to resolve all of the issues raised by these parties and all revenue requirement-related issues raised by other parties in the Utility’s 2007 GRC proceeding. The settlement agreement proposes to set the Utility’s revenue requirements for a four-year period, 2007-2010, rather than for a typical three-year period. Under this proposal, the Utility’s next GRC would be effective January 1, 2011. On February 13, 2007, the administrative law judge overseeing the GRC issued a proposed decision that recommends modifications to the settlement agreement. On the same day, an alternate proposed decision was issued by the assigned CPUC Commissioner in the GRC that recommends that the settlement agreement be approved. For more information, see “Regulatory Matters - 2007 General Rate Case” in the MD&A in the 2006 Annual Report.

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The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC in order to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations. The proposed settlement agreement in the Utility’s 2007 GRC includes a provision for attrition adjustments to be made in 2008, 2009 and 2010.


The CPUC generally conducts an annual cost of capital 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 relative weightings of common equity, preferred equity and debt in the Utility's total authorized capital structure for a specific year. The CPUC then establishes the authorized return on each component that the Utility will collect in its authorized rates. The Chapter 11 Settlement Agreement requires the CPUC to authorize a minimum return on equity for the Utility of 11.22% until the Utility receives a credit rating of “A3” from Moody’s Investor Services or “A-” from Standard & Poor’s Rating Services. The Utility’s CPUC-authorized capital structure for 2006 and 2007 consists of 46% long-term debt, 2% preferred stock and 52% equity. The Utility’s CPUC-authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base for 2006 and 2007 is 6.02% for long-term debt, 5.87% for preferred stock and 11.35% for equity, resulting in an overall rate of return on rate base of 8.79%. The CPUC will next re-evaluate the level of the Utility’s authorized return on equity and capital structure for the calendar year 2008. The Utility is required to file its 2008 cost of capital application by May 8, 2007.

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 have been previously set in the Gas Accord, described below, 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.


The Utility administers, and/or funds, several state-mandated and CPUC-authorized public purpose and other programs. 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. In addition, California law requires the CPUC to authorize funding for the California Solar Initiative discussed below, and other self-generation programs. In addition, the CPUC has authorized additional funding for energy efficiency and demand response programs. For 2006 expenditures, the CPUC has authorized the Utility to collect revenue requirements of approximately $583 million from electricity customers to fund these electricity public purpose and other programs and to collect revenue requirements of approximately $99 million from gas customers to fund these natural gas public purpose 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 efficiency programs. The CEC administers both the electric public interest research and development program and the renewable energy program on a statewide basis. In 2006, the Utility transferred $109 million to the CEC for these programs. These programs include:
 

 
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Energy Efficiency Programs. The CPUC has authorized 2006 through 2008 energy efficiency portfolio plans and program funding levels, not including funding for evaluation, measurement and verification, or EM&V activities for the Utility and the other investor-owned California utilities. The CPUC approved funding of approximately $867 million for the Utility's energy efficiency programs over the 2006 through 2008 period, 20% of which is to be awarded to third parties through a competitive bid process. The CPUC also has authorized funding for EM&V activities of approximately $75 million for the Utility over the 2006 through 2008 period. The increased energy efficiency funding level is part of a larger effort by the State of California to reduce consumption of fossil fuels. The increased funding level will enable both residential and business customers to take more advantage of the diverse mix of energy efficiency programs.    
 
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Demand Response Programs. Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. In March 2006, the CPUC authorized 2006 through 2008 demand response programs and funding levels for the Utility and other investor-owned California utilities. The CPUC approved funding of approximately $109 million for the Utility’s demand response programs over the 2006 through 2008 period, which include some demand response programs that will be provided by third parties. In November 2006, the CPUC approved augmented demand response programs for the Utility and other investor-owned California utilities in order to promote system reliability during the summer peak demand periods of 2007 and 2008. These augmented programs were approved within the existing authorized budget. Programs requiring additional funding beyond the already authorized level will require further regulatory authorization. On February 15, 2007, the CPUC approved the Utility’s proposal to start a limited deployment of an airconditioning load control program that is expected to yield 5 MW of load relief for summer 2007. In early spring 2007, the Utility anticipates requesting that the CPUC approve an expanded air conditioning load control program that is expected to yield approximately 300 MW of additional load relief by the end of 2010. These increased demand response programs are part of an effort by the state of California to promote demand reduction through price-responsive programs and reliability-triggered programs.

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Self-Generation Incentive and California Solar Initiative. The Utility administers the self-generation incentive program authorized by the CPUC to provide incentives to electricity customers who install clean or renewable distributed generation resources that meets all or a portion of their onsite energy usage. The CPUC also authorized the California investor-owned utilities to collect an additional $2.1 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. The goal of this program, called the California Solar Initiative, or the CSI, is to bring 1,940 MW of solar power on-line by 2017 through the California investor-owned utilities. 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. California Senate Bill 1, enacted in August 2006, modified the CSI program to include participation of the California municipal utilities. The overall goal of the CSI is to install 3,000 MW (through both investor-owned electric utilities and electric municipal utilities) through 2017.

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Low-Income Energy Efficiency Programs and California Alternate Rates for Energy. The CPUC has approved funding of $78 million in each of 2007 and 2008 to support energy efficiency programs for low-income and fixed-income customers. The Utility also provides a discount rate called the California Alternate Rates for Energy, or CARE, for low-income customers. This rate subsidy is paid for by the Utility's other customers. For 2006, the amount of this subsidy was approximately $458 million (including avoided surcharges).
 

In December 2006, the CPUC approved the Utility’s proposal to allow customers to choose to neutralize greenhouse gas emissions associated with their energy use. Beginning in 2007, customers who choose to enroll in the program will pay a small premium on their monthly utility bill, based on their energy usage, to fund environmental projects aimed at removing carbon dioxide and other greenhouse gases from the air. The Utility estimates that this program will generate approximately $20 million during its first three years to fund these greenhouse gas reduction projects, which will initially be focused on forest restoration and conservation projects in California. The Utility would select projects to fund through a competitive bidding process using stringent criteria and protocols developed by an independent non-profit organization, the California Climate Action Registry. Project types are expected to expand beyond forestry, such as potentially to dairy biogas methane reduction projects, as more certification protocols become available. The greenhouse gas reduction projects will be overseen by an external advisory group consisting of a wide range of community groups, businesses and non-profit conservation agencies. The program will be reviewed by independent auditors and the Utility will regularly report program results to the CPUC, as well as to all participating customers.



Each California investor-owned electric utility is responsible to procure 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). Each utility must submit a long-term procurement plan covering a ten-year period to the CPUC for approval. California legislation, Assembly Bill 57, allows the California investor-owned utilities to recover their wholesale electricity procurement costs incurred in compliance with their CPUC-approved procurement plans. After CPUC approval of the procurement plans, the utilities may, if appropriate, conduct a competitive request for offers, or RFO, from providers of all potential sources of new generation (e.g., conventional or renewable resources to be provided under turnkey developments, buyouts or power purchase agreements) to meet the utility’s projected need for electricity resources. Agreements entered into after the conclusion of the competitive bidding process are submitted to the CPUC for approval, along with a request for the CPUC to authorize revenue requirements to recover the costs associated with that contract. If necessary, the utilities conduct separate competitive solicitations to meet their resource adequacy and renewable energy resource requirements. The utilities submit the contracts after the conclusion of these solicitations to the CPUC for approval and authorization of the associated revenue requirements.

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The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility under DWR contracts) through the Energy Resource Recovery Account, or the 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 the DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer. The CPUC also performs periodic compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power procurement costs.

The authorized revenue requirements for capital costs and non-fuel operating and maintenance costs for Utility-owned generation are addressed in the Utility’s GRC. The revenue requirement to recover the initial capital costs for CPUC-approved utility owned generation projects will be recovered through a balancing account, the Utility Generation Balancing Account, or the UGBA, which will track 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.


During 2006, the CPUC approved several power purchase agreements 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 to recover fixed and variable costs associated with these contracts through the ERRA.

For new non-renewable generation purchased from third parties under power purchase agreements, the utilities may elect to recover any above-market costs through either (1) the imposition of a non-bypassable charge imposed on bundled and departing customers only or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the utilities’ service territory, including direct access customers and community choice aggregation customers. (For information about the status of direct access and community choice aggregation, see the section above entitled “Competition  - 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 spot market prices for the purposes of determining the net capacity costs to be allocated until the next periodic auction.


During 2006, the CPUC approved three agreements related to Utility-owned generation projects. The CPUC also authorized the amount of revenue requirements that the Utility is authorized to recover related to each project to recover capital costs and non-fuel operations and maintenance costs.

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Gateway Generating Station. In June 2006, the CPUC authorized the Utility to acquire the equipment, permits and contracts relating to a partially completed 530-MW power plant in Antioch, California, referred to as the Gateway Generating Station, or Gateway. The Utility completed the acquisition in November 2006. The CPUC authorized the Utility to recover approximately $295 million in capital costs to complete the construction of the facility as well as costs for its operation. On February 15, 2007, the CPUC approved the Utility’s request to recover an additional approximately $75 million necessary to convert the plant from fresh water cooling to dry cooling in order to reduce the environmental impact of the facility and as a result of changes to Gateway’s environmental permits. The Utility also has requested the CEC to amend the facility’s current permit to authorize the plant to be converted from fresh water cooling to dry cooling. The Utility expects that the CEC will issue a decision in the second quarter of 2007. Subject to obtaining the permit amendment from the CEC, meeting construction schedules, operational performance requirements and other conditions, the Utility estimates that it will complete construction of the Gateway facility and commence operations in 2009

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Colusa Power Plant. In November 2006, the CPUC approved an agreement for the development and construction of a 657-MW power plant to be located in Colusa County, California. The CPUC adopted an initial capital cost for the Colusa project that is equal to the sum of the fixed contract costs plus the Utility’s estimated owner’s costs and a contingency amount to account for the risk and uncertainty in the estimation of owner’s costs. (Owner’s costs include the Utility’s expenses for

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 Colusa Power Plant. In November 2006, the CPUC approved an agreement for the development and construction of a 657-MW power plant to be located in Colusa County, California. The CPUC adopted an initial capital cost for the Colusa project that is equal to the sum of the fixed contract costs plus the Utility’s estimated owner’s costs and a contingency amount to account for the risk and uncertainty in the estimation of owner’s costs. (Owner’s costs include the Utility’s expenses for legal, engineering and consulting services as well as the costs for internal personnel and overhead related to the project.) The CPUC also authorized the Utility to adjust the initial capital cost for the Colusa project to reflect any actual incentive payments made to, or liquidated damages received from, the contractors through notification to the CPUC but without a reasonableness review. Subject to obtaining required permits, meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Colusa project will commence operations in 2010 at an estimated cost of approximately $673 million.
 
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Humboldt Bay. In November 2006, the CPUC also approved an agreement for the construction of a 163-MW power plant to re-power the Utility’s existing Humboldt Bay power plant, which is at the end of its useful life. The CPUC adopted an initial capital cost of the Humboldt Bay project equal to the sum of the fixed contract costs plus the Utility’s estimated owner’s costs, but limited the contingency amount for owner’s costs to 5 percent of the fixed contract cost and estimated owner’s costs. Subject to obtaining required permits and meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Humboldt Bay project will commence operations in 2009 at an estimated cost of approximately $239 million. 

On December 11, 2006, the Utility submitted its 2006 long-term procurement plan covering procurement over 2007-2016 to the CPUC for approval. For more information about the 2006 plan, see the section of MD&A in the 2006 Annual Report entitled “Regulatory Matters - Electricity Generation Resources.”


During the California 2000-2001 energy crisis, the DWR entered into long-term contracts to purchase electricity from third parties. The electricity provided under these contracts has been allocated to the electric customers of the three California investor-owned electric utilities. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from these customers through a rate component called the DWR “power charge.” The rates that these customers pay also include a “bond charge” to pay a share of the DWR's revenue requirements to recover costs associated with the DWR's $11.3 billion bond offering completed in November 2002. The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR's revenue requirement and to provide the DWR with funds to make its electricity purchases. Because the Utility acts as a billing and collection agent for the DWR, amounts collected for the DWR and any adjustments are not included in the Utility's revenues.


The Utility's electricity transmission revenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues: charges under the Utility's transmission owner tariff and charges under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations in March 1998. These wholesale customers are referred to as existing transmission contract customers and are charged individualized rates based on the terms of their contracts. Other customers pay transmission rates that are established by the FERC in the Utility's transmission owner tariff rate cases. These FERC-approved rates are included by the CPUC in the Utility's retail electric rates, consistent with the federal filed rate doctrine, and are collected from retail electric customers receiving bundled service.


The primary FERC rate-making proceeding to determine the amount of revenue requirements the Utility is authorized to recover for its electric transmission costs and to earn its return on equity is the transmission owner rate case. A transmission owner rate case is generally held every year and sets rates for a one-year period. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process. The Utility's transmission owner tariff includes two rate components. The primary component consists of base transmission rates intended to recover the Utility's operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity. The Utility derives the majority of the Utility's transmission revenue from base transmission rates. The other component consists of rates intended to reflect credits and charges from the CAISO. The CAISO credits the Utility for transmission revenues received by the CAISO. The CAISO also charges the Utility for reliability service costs and imposes a transmission access charge for the Utility’s use of CAISO-controlled transmission facilities in serving its customers. These credits and charges are described below.

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On August 1, 2006, the Utility filed its transmission owner rate case application with the FERC requesting authorization of an annual transmission revenue requirement effective October 1, 2006. On September 29, 2006, the FERC issued an order accepting the Utility’s rate application, suspending the requested rate changes for five months to become effective March 1, 2007, subject to refund. On February 15, 2007, the Utility submitted an offer of settlement reached by the parties and requested that the settlement judge recommend that the FERC approve the settlement.  For more information, see “Regulatory Matters - FERC Transmission Rate Case” in the MD&A in the 2006 Annual Report.


CAISO transmission 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).

The amount of CAISO transmission revenues is adjusted by the shortfall or surplus resulting from any cost differences between the amount the Utility is entitled 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 CAISO’s rules and protocols.


The CAISO has entered into reliability must run, or RMR, agreements with various power plant owners, including the Utility, that require designated units in certain power plants, known as RMR units, to remain available to generate electricity upon the CAISO's demand when the generation from those RMR units is needed for local transmission system reliability. RMR agreements are established or extended by the CAISO on an annual basis.  As a participating transmission owner under the Transmission Control Agreement with the CAISO, the Utility is responsible for reimbursing the CAISO for the RMR payments it makes to power plant owners within or adjacent to the Utility's service territory. The Utility tracks these costs in the reliability services balancing account. Periodically, the Utility’s transmission owner rates are adjusted to refund over-collections to the Utility’s customers as a result of the effect of these reliability service costs or to collect any under-collections from customers. During 2006, the CPUC adopted rules to implement state law requirements for California investor-owned utilities to meet resource adequacy requirements, including rules to address local transmission system reliability issues.  As the utilities fulfill their responsibility to meet these requirements, the number of RMR agreements with the CAISO and the associated costs will decline.  

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 2006 Annual Report.


The CAISO imposes a transmission access charge on users of the CAISO-controlled electric transmission grid. The CAISO's transmission access charge methodology approved by the FERC in December 2004, provides for a transition over a 10-year period to a uniform statewide high-voltage transmission rate, based on the revenue requirements associated with facilities operated at 200 kV and above of all transmission owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology may result in a cost shift from transmission owners whose costs for existing transmission facilities at 200 kV and above are higher than that embedded in the uniform transmission access charge rate, to transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The Utility's obligation for this cost differential has been capped at $32 million per year during the 10-year transition period.

15


Under a ratemaking pact called the Gas Accord, the Utility's natural gas transportation and storage services were separated for ratemaking purposes from its distribution services. The Gas Accord established natural gas transportation rates and natural gas storage rates. In December 2004, the CPUC approved a multi-party settlement agreement, the Gas Accord III, to retain the Gas Accord market structure, and resolve the rates, and terms and conditions of service for the Utility's natural gas transportation and storage system for the three-year period 2005 through 2007. Under this framework, the costs associated with the Utility’s local transportation and gas storage assets that are used for service to core customers are recovered through balancing account mechanisms that adjust for the difference between actual usage and forecast usage. In addition, approximately 65% of the costs associated with the Utility’s backbone gas transmission system that is used to serve core customers are recovered through fixed charges. The remaining 35% of these costs are recoverable through volumetric charges. Revenues from these charges vary depending on the level of throughput volume. The costs that are recoverable through balancing accounts or fixed reservation charges account for approximately 45% of the Utility’s total revenue requirement for gas transmission and storage. The remainder of the Utility’s gas transmission and storage costs are recovered from core customers through volumetric charges and from noncore customers under firm or interruptible transmission or storage contracts. The Utility’s recovery of this portion of its costs depend on the level of throughput volume, gas prices, and the extent to which noncore customers contract for firm services.

The Utility is obligated to file a new rate case proposing gas transmission and storage rates and terms and conditions of service, for the period commencing January 1, 2008. The Utility currently is scheduled to submit that filing on March 15, 2007. In the event the CPUC does not issue a final decision approving new rates effective January 1, 2008, Gas Accord III provides that the rates and terms and conditions of service in effect as of December 31, 2007, will remain in effect, with an automatic 2 percent escalation in the rates as of January 1, 2008.


Certain of the Utility's natural gas distribution costs and balancing account balances are allocated to customers in the Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues.


The Utility sets the natural gas procurement rate for core customers monthly based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.

The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core procurement customers, through its retail gas rates. The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under an incentive mechanism known as the Core Procurement Incentive Mechanism, or CPIM. Under the CPIM, the Utility's purchase costs for a 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. The CPIM establishes a “tolerance band” around the benchmark index price, and all costs within the tolerance band are fully recovered from core customers. If total natural gas costs fall below the tolerance band, the Utility’s customers and shareholders will share 75% and 25% of the savings below the tolerance band, respectively. Conversely, if total natural gas costs rise above the tolerance band, the Utility’s core customers and shareholders share equally the costs above the tolerance band. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income. (For more information see the “Risk Management Activities” section of MD&A in the 2006 Annual Report).


The Utility's interstate and Canadian natural gas transportation agreements with third-party service providers are governed by tariffs that detail rates, rules and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Energy and Utilities Board 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.

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The following table shows the percentage of the Utility's total sources of electricity for 2006 represented by each major electricity resource:
Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities)
40%
DWR
24%
Qualifying Facilities/Renewables
20%
Irrigation Districts
6%
Other Power Purchases
10%

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 to sell this additional 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, 2006, 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 and two operating fossil fuel-fired plants. As described above, the CPUC has approved the Utility’s application to re-power the two fossil fuel-fired plants.
 
 
In May 2006, the Utility retired its fossil fuel-fired plant at Hunters Point in San Francisco after the completion of a new 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line. The Utility is in the process of decommissioning the Hunters Point power plant. The completed transmission line provides additional transmission system reliability in San Francisco and northern San Mateo County that allowed the Hunters Point fossil-fueled power plant in San Francisco to be retired.
 
Diablo Canyon Power Plant. The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, 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, 2006, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 89.8%.

The Utility has entered into various purchase agreements for nuclear fuel with terms ranging from two to five years 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 2006 Annual Report.

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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 16 to 21 months. The average length of a refueling outage over the last five years has been approximately 48 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the replacement of the steam generators in Unit 2 in 2008 and in Unit 1 in 2009. The capital expenditures necessary to complete these projects are discussed further in the “Capital Expenditures” section of MD&A in the 2006 Annual Report. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of approximately 80 days for steam generator replacements. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

 
 
2007
 
2008
 
2009
 
2010
2011
Unit 1
 
 
 
 
 
 
 
 
  
   Refueling
 
April
 
-
 
January
 
October
  
   Duration (days)
 
28
 
-
 
74
 
28
  
   Startup
 
May
 
-
 
April
 
November
  
Unit 2
 
 
 
 
 
 
 
 
  
   Refueling
 
-
 
February
 
October
 
-
April
   Duration (days)
 
-
 
76
 
28
 
-
28
   Startup
 
-
 
April
 
November
 
-
May

In addition, as discussed below under “Environmental Matters - Nuclear Fuel Disposal,” the Utility is constructing an on-site dry cask storage facility to store the spent nuclear fuel that is expected to be completed by 2008. To provide another storage alternative in the event that construction of the dry cask storage facility is delayed, in December 2006, the Utility completed the installation of temporary storage racks in each unit's existing spent fuel storage pool that increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. If the Utility is unable to complete the dry cask storage facility, or if construction is delayed beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2010 with respect to Unit 1 and 2011 with respect to Unit 2 until such time as additional spent fuel can be safely stored.

Hydroelectric Generation Facilities. The Utility's hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 76 diversions, 174 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 87 permits or licenses and 160 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses totaling approximately 7.7 MW, all of the Utility's powerhouses are licensed by the FERC. Pursuant to the Federal Power Act, the term of a hydroelectric project license issued by the FERC is between 30 and 50 years. In the last five years, the FERC has renewed six hydroelectric project licenses associated with a total of 699 MW. The Utility is in the process of seeking FERC renewal of licenses associated with approximately 1,314 MW of hydroelectric power. Although the original licenses associated with 917 MW of the 1,314 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately 2,569 MW, including the 699 MW recently relicensed, will expire between 2013 and 2043.


During 2006, electricity from the DWR contracts allocated to the Utility provided approximately 24% 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 the DWR's electricity procurement contracts allocated to the Utility’s customers. The DWR remains legally and financially responsible for its electricity procurement contracts. As described above under “Ratemaking Mechanisms,” the Utility acts as a billing and collection agent to collect the DWR's revenue requirements from the Utility's customers. For more information regarding the DWR contracts, see Note 17: Commitments and Contingencies - Third Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2006 Annual Report.

 
Qualifying Facility Power Purchase Agreements. As of December 31, 2006, the Utility had agreements with 268 QFs for approximately 4,150 MW that are in operation. Agreements for approximately 3,800 MW expire at various dates between 2007 and 2028. QF power purchase agreements for approximately 350 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 68 inoperative

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QFs. The total of approximately 4,150 MW consists of approximately 2,550 MW from cogeneration projects, 600 MW from wind projects and 1,000 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar and hydroelectric.

QF power purchase agreements accounted for approximately 20% of the Utility’s 2006 electricity sources, 22% of the Utility’s 2005 electricity sources and approximately 23% of the Utility's 2004 electricity sources. No single QF accounted for more than 5% of the Utility's 2006, 2005 or 2004 electricity sources.

Renewable Energy Contracts. California law requires that each California retail seller of electricity, except for municipal utilities, increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2010. During 2006, the Utility entered into several new renewable power purchase contracts that will help the Utility meet its goals. Currently, power from eligible renewable energy resources comprises approximately 12% of the Utility’s retail sales. The Utility expects to comply with its 2004, 2005, 2006 and 2007 annual targets. Although the Utility expects it will achieve the 20% target using the “flexible compliance” rules by 2010, actual deliveries of renewable power may not comprise 20% of its bundled retail sales by 2010 due to such factors as the time required for the construction of new generation facilities and/or needed transmission capacity. Failure to satisfy the targets may result in a penalty of five cents per kWh, with an annual penalty cap of $25 million. The exact amount of any penalty and conditions under which it would be applied is subject to the CPUC’s review of the circumstances for under-delivery.

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 2007 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 6% of the Utility’s 2006 electricity sources, and approximately 5% of the Utility’s 2005 and 2004 electricity sources.

Other Power Purchase Agreements. After competitive solicitations, bilateral negotiations, and request for offers or proposals, were conducted, the Utility entered into several agreements with third party power providers during 2006 to meet the Utility’s intermediate and long-term generation resource needs. Under these contracts, the Utility will purchase power from facilities that may start as early as January 1, 2007 to as late as 2011. These combined agreements cover an aggregate of 7,129 MW of contractual capacity that expire between December 31, 2010 and January 31, 2036. Payments are not required under these agreements until the underlying generation facilities are operational.

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 2006 Annual Report.


In accordance with the Utility’s CPUC-approved procurement plan covering 2004-2014, the Utility has entered into contracts covering 2,780 MW of new long-term electricity generation resources in northern California. Three of the agreements provide for the construction of generation facilities to be owned and operated by the Utility: the 530-MW Gateway power plant located in Antioch, California; the 657-MW Colusa power plant located in Colusa, California; and the 163-MW power plant to re-power the Utility’s existing Humboldt Bay power plant, which is at the end of its useful life. Subject to obtaining required permits and meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Gateway and Humboldt Bay plants will commence operations in 2009 and the Colusa plant will commence operations in 2010. The Utility also executed five power purchase agreements that would provide approximately 1,430 MW of capacity with terms from 10 to 20 years. If permitting and construction schedules are met, the new generation facilities supporting these power purchase agreements are anticipated to begin delivering power to the grid during 2009 through 2010.
 
On December 11, 2006, the Utility submitted its 2006 long-term electricity procurement plan covering procurement over 2007-2016 to the CPUC for approval. The plan forecasts a need for up to an additional 2,300 MW of new dispatchable and operationally flexible capacity to come on line starting in 2011 to ensure continued reliable service. For more information about the 2006 plan, see the section of MD&A in the 2006 Annual Report entitled “Regulatory Matters - Electricity Generation Resources.”

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At December 31, 2006, the Utility owned 18,640 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 53,094 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 140,049 circuit miles of distribution lines and substations with a capacity of 26,079 MVA. In 2006, the Utility delivered 84,310 GWh to its customers, including 7,604 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

In 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 has 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 assuring 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 April 2006, the Utility completed a new 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line. The completed transmission line provides additional transmission system reliability in San Francisco and northern San Mateo County. As result of the completion of the transmission line, the Utility was able to retire the Hunters Point power plant in San Francisco. The Utility expects to undertake various 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, and to replace aging or obsolete equipment to maintain system reliability and reduce reliance on RMR generation. These potential projects include the construction of the Midway-Gregg 500-kV transmission line designed to increase access to southern California and Southwest generation resources and to reduce RMR generation contracts in the Fresno, California, area.  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.  In addition, the CPUC has adopted a procedure to enable the utilities to recover the cost of electric transmission facilities necessary to interconnect renewable energy resources if those costs cannot be recovered in FERC-approved rates.


The Utility's electricity distribution network extends throughout all or a part of 47 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of 140,049 circuit miles of distribution lines (of which approximately 19% are underground and approximately 81% are overhead). There are 94 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. There are 602 distribution substations and 110 low-voltage distribution substations. There are 55 combined transmission and distribution substations. 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 system for virtually all of the Utility's residential and small commercial electric and gas customers.  These meters will enable the Utility to measure usage of electricity on a time-of-use basis and to charge demand-responsive rates to encourage customers to reduce energy consumption during peak demand periods and

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to reduce 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. In 2006, the CPUC also approved the Utility’s proposal to offer customers a new voluntary billing option called critical peak pricing, or CPP, under which customers will be able to take advantage of electricity prices that vary by day and hour, potentially reducing their bills by shifting their energy use away from critical peak periods. By shifting energy demand away from critical peak periods, the Utility anticipates that it would need to purchase less power for critical peak periods. (For more information about the advanced metering initiative, see the section entitled “Capital Expenditures” in the MD&A portion of the 2006 Annual Report.)


The following table shows the percentage of the Utility's total 2006 electricity deliveries represented by each of its major customer classes.

Total 2006 Electricity Delivered: 84,310 GWh

Agricultural and Other Customers
    
5
%
Industrial Customers
    
18
%
Residential Customers
    
37
%
Commercial Customers
    
40
%


The following table shows certain of the Utility's operating statistics from 2002 to 2006 for electricity sold or delivered, including the classification of sales and revenues by type of service.
 
 
  
2006
  
2005
  
2004
  
2003
  
2002
  
Customers (average for the year):
                       
Residential
    
4,417,638
    
4,353,458
    
4,366,897
    
4,286,085
    
4,171,365
  
Commercial
    
515,297
    
509,786
    
509,501
    
493,638
    
483,946
  
Industrial
    
1,212
    
1,271
    
1,339
    
1,372
    
1,249
  
Agricultural
    
79,006
    
78,876
    
80,276
    
81,378
    
78,738
  
Public street and highway lighting
    
28,799
    
28,021
    
27,176
    
26,650
    
24,119
  
Other electric utilities
    
4
    
4
    
3
    
4
    
5
  
Total (1)
    
5,041,956
    
4,971,416
    
4,985,192
    
4,889,127
    
4,759,422
  
Deliveries (in GWh):(2)
                       
Residential
    
31,014
    
29,752
    
29,453
    
29,024
    
27,435
  
Commercial
    
33,492
    
32,375
    
32,268
    
31,889
    
31,328
  
Industrial
    
15,166
    
14,932
    
14,796
    
14,653
    
14,729
  
Agricultural
    
3,839
    
3,742
    
4,300
    
3,909
    
4,000
  
Public street and highway lighting
    
785
    
792
    
2,091
    
605
    
674
  
Other electric utilities
    
14
    
33
    
28
    
76
    
64
  
Subtotal
    
84,310
    
81,626
    
82,936
    
80,156
    
78,230
  
California Department of Water Resources (DWR)
    
(19,585
)
  
(20,476
)
  
(19,938
)
  
(23,554
)
  
(21,031
)
Total non-DWR electricity
    
64,725
    
61,150
    
62,998
    
56,602
    
57,199
  
Revenues (in millions):