UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM 10-K
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(Mark
One)
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x
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For
the Fiscal Year Ended December 31, 2008
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Or
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For
the transition period from _________
to ___________
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Commission
File
Number
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Exact
Name of Registrant
as
specified in its charter
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State
or Other Jurisdiction of
Incorporation
or Organization
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IRS
Employer
Identification
Number
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1-12609
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PG&E
CORPORATION
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California
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94-3234914
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1-2348
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PACIFIC
GAS AND ELECTRIC COMPANY
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California
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94-0742640
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 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)
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 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)
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Securities
registered pursuant to Section 12(b) of the Act:
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Title
of Each Class
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Name
of Each Exchange on Which Registered
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PG&E Corporation:
Common Stock, no par value
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New
York Stock Exchange
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Pacific Gas and Electric
Company: First Preferred Stock,
cumulative,
par value $25 per share:
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NYSE
Alternext
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Redeemable:
5% Series A, 5%, 4.80%, 4.50%, 4.36%
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Nonredeemable:
6%, 5.50%, 5%
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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:
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PG&E
Corporation
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Yes
x No
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Pacific
Gas and Electric Company
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Yes
x No
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Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act:
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PG&E
Corporation
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Yes
No x
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Pacific
Gas and Electric Company
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Yes
No x
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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.
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PG&E
Corporation
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Yesx No
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Pacific
Gas and Electric Company
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Yes
xNo
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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:
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PG&E
Corporation
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x
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Pacific
Gas and Electric Company
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x
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Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company (as
defined in Rule 12b-2 of the Exchange Act). (Check one):
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PG&E
Corporation
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Pacific
Gas and Electric Company
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Large
accelerated filer x
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Large
accelerated filer
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Accelerated
filer
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Accelerated
filer
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Non-accelerated
filer
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Non-accelerated
filer x
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Smaller
reporting company
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Smaller
reporting company
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
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PG&E
Corporation
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Yes
No x
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Pacific
Gas and Electric Company
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Yes
No x
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Aggregate
market value of voting and non-voting common equity held by non-affiliates of
the registrants as of June 30, 2008, the last business day of the most
recently completed second fiscal quarter:
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PG&E
Corporation Common Stock
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$14,179
million
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Pacific
Gas and Electric Company Common Stock
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Wholly
owned by PG&E Corporation
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Common
Stock outstanding as of February 20, 2009:
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PG&E
Corporation:
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365,764,340
shares
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Pacific
Gas and Electric Company:
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264,374,809
shares (wholly owned by PG&E
Corporation)
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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:
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Designated
portions of the combined 2008 Annual Report to
Shareholders
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Part I
(Items 1 and 1.A.), Part II (Items 5, 6, 7, 7A, 8 and
9A)
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Designated
portions of the Joint Proxy Statement relating to the 2009 Annual Meetings
of Shareholders
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Part III
(Items 10, 11, 12, 13 and 14)
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TABLE
OF CONTENTS
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Energy
Efficiency Programs
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Demand
Response Programs
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12
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Self-Generation
Incentive Program and California Solar Initiative
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12
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Low-Income
Energy Efficiency Programs and California Alternate Rates for
Energy
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1
Kilowatt (kW)
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=
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One
thousand watts
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1
Kilowatt-Hour (kWh)
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=
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One
kilowatt continuously for one hour
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1
Megawatt (MW)
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=
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One
thousand kilowatts
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1
Megawatt-Hour (MWh)
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=
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One
megawatt continuously for one hour
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1
Gigawatt (GW)
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=
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One
million kilowatts
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1
Gigawatt-Hour (GWh)
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=
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One
gigawatt continuously for one hour
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1
Kilovolt (kV)
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=
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One
thousand volts
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1
MVA
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=
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One
megavolt ampere
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1
Mcf
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=
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One
thousand cubic feet
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1
MMcf
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=
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One
million cubic feet
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1
Bcf
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=
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One
billion cubic feet
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1
MDth
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=
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One
thousand decatherms
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iii
Item
1. Business
PG&E
Corporation, incorporated in California in 1995, is a holding company whose
primary purpose is to hold interests in energy-based
businesses. PG&E Corporation conducts its business principally
through Pacific Gas and Electric Company (“Utility”) a public utility operating
in northern and central California. The Utility engages in the businesses of
electricity and natural gas distribution; electricity generation, procurement,
and transmission; and natural gas procurement, transportation, and storage. The
Utility was incorporated in California in 1905. PG&E Corporation
became the holding company of the Utility and its subsidiaries on
January 1, 1997.
The
Utility served approximately 5.1 million electricity distribution customers
and approximately 4.3 million natural gas distribution customers at
December 31, 2008. The Utility had approximately $40.5 billion of
assets at December 31, 2008 and generated revenues of approximately
$14.6 billion in 2008. Its revenues are generated mainly through the sale
and delivery of electricity and natural gas. The Utility is regulated primarily
by the California Public Utilities Commission (“CPUC”), and the Federal Energy
Regulatory Commission (“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 (“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, 2008, PG&E Corporation and its subsidiaries had
approximately 21,667 regular employees, including approximately 21,451 regular
employees of the Utility. Of the Utility's regular employees,
approximately 14,649 are covered by collective bargaining agreements with three
labor unions: the International Brotherhood of Electrical Workers, Local 1245,
AFL-CIO (“IBEW”); the Engineers and Scientists of California, IFPTE Local 20,
AFL-CIO and CLC (“ESC”); and the Service Employees International Union, Local
24/7 (“SEIU”). One IBEW collective bargaining agreement expires on
December 31, 2011 and the other IBEW collective bargaining agreement
expires on December 31, 2010. The ESC collective bargaining
agreement expires on December 31, 2009. The Utility and
the ESC reached an agreement in January 2009 to extend the collective bargaining
agreement until December 31, 2011, subject to ratification by members of the
ESC. The SEIU collective bargaining agreement expires on July 31,
2009.
This
combined Annual Report on Form 10-K, including the information incorporated
by reference from the joint Annual Report to Shareholders for the year ended
December 31, 2008 (“2008 Annual Report”), contains forward-looking statements
that are necessarily subject to various risks and uncertainties. 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, estimated tax
liabilities, the anticipated outcome of various regulatory and legal
proceedings, estimated future cash flows, and the level of future equity or debt
issuances, and are also identified by words such as “assume,” “expect,”
“intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,”
“anticipate,” “aim, “ “may,” “might,” “should,” “would,” “could,” “goal,”
“potential” and similar expressions. PG&E Corporation and the
Utility are not able to predict all the factors that may affect future
results. Some of the factors that could cause future results to
differ materially from those expressed or implied by the forward-looking
statements, or from historical results, include, but are not limited
to:
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·
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the
Utility’s ability to manage capital expenditures and its operating and
maintenance expenses within authorized levels;
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·
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the
outcome of pending and future regulatory proceedings and whether the
Utility is able to timely recover its costs through
rates;
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·
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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 including the ability of the Utility
and its counterparties to post or return collateral;
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·
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the
effect of weather, storms, earthquakes, fires, floods, disease, other
natural disasters, explosions, accidents, mechanical breakdowns, acts of
terrorism, and other events or hazards on the Utility’s facilities and
operations, its customers, and third parties on which the Utility
relies;
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·
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the
potential impacts of climate change on the Utility’s electricity and
natural gas businesses;
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·
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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;
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·
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operating
performance of Diablo Canyon, the availability of nuclear fuel, the
occurrence of unplanned outages at Diablo Canyon, or the temporary or
permanent cessation of operations at Diablo Canyon;
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·
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whether
the Utility can maintain the cost savings it has recognized from operating
efficiencies it has achieved and identify and successfully implement
additional sustainable cost-saving measures;
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·
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whether
the Utility incurs substantial expense to improve the safety and
reliability of its electric and natural gas systems;
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·
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whether
the Utility achieves the CPUC’s energy efficiency targets and recognizes
any incentives the Utility may earn in a timely manner;
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·
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the
impact of changes in federal or state laws, or their interpretation, on
energy policy and the regulation of utilities and their holding
companies;
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·
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the
impact of changing wholesale electric or gas market rules, including new
rules of the California Independent System Operator (“CAISO”) to
restructure the California wholesale electricity
market;
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·
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how
the CPUC administers the conditions imposed on PG&E Corporation when
it became the Utility’s holding company;
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·
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the
extent to which PG&E Corporation or the Utility incurs costs and
liabilities in connection with litigation that are not recoverable through
rates, from insurance, or from other third parties;
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·
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the
ability of PG&E Corporation, the Utility, and counterparties to access
capital markets and other sources of credit in a timely manner on
acceptable terms, especially given the recent deteriorating conditions in
the economy and financial markets;
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·
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the
impact of environmental laws and regulations and the costs of compliance
and remediation;
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·
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the
effect of municipalization, direct access, community choice aggregation,
or other forms of bypass; and
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·
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the
impact of changes in federal or state tax laws, policies, or
regulations.
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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.
For
more information about the significant risks that could affect PG&E
Corporation and the Utility's future financial condition and results of
operations, see the discussion under “Risk Factors” that appears near the end of
the section entitled “Management's
Discussion and Analysis of Financial Condition and Results of Operations”
(“MD&A”) in the 2008 Annual Report.
As a
public utility holding company, PG&E Corporation is subject to the
requirements of the Energy Policy Act of 2005 (“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 (“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
(“DOE”). PG&E Corporation and its subsidiaries are exempt 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. These books and records provisions are largely duplicative
of other provisions under the Federal Power Act of 1935 and state
law.
PG&E
Corporation is not a public utility under California law. The CPUC
has authorized the formation of public utility holding companies subject to
various conditions related to finance, human resources, records and bookkeeping,
and the transfer of customer information. The financial conditions provide
that:
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·
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the
Utility cannot guarantee any obligations of PG&E Corporation without
prior written consent from the
CPUC;
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·
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the
Utility's dividend policy must be established by the Utility's Board of
Directors as though the Utility were a stand-alone utility
company;
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·
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the
capital requirements of the Utility, as determined to be necessary and
prudent to meet the Utility's obligation to serve or to operate the
Utility in a prudent and efficient manner, must be given first priority by
PG&E Corporation's Board of Directors (known as the “first priority”
condition); and
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·
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the
Utility must maintain on average its CPUC-authorized utility capital
structure, although it can request a waiver of this condition if an
adverse financial event reduces the Utility's common equity component by
1% or more.
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(As
discussed below under “Item 3—Legal Proceedings,” the California Attorney
General and the City and County of San Francisco have alleged that PG&E
Corporation and its directors, as well as the directors of the Utility, violated
the CPUC’s holding company conditions during the California 2000-2001 energy
crisis. PG&E Corporation and the Utility believe that they have
complied with applicable statutes, CPUC decisions, rules and
orders.)
The CPUC
also has adopted complex and detailed rules governing transactions between
California's electricity and gas utilities and certain of their
affiliates. The rules address the use of the utilities’ names and
logos by their affiliates, the separation of utilities and their affiliates,
provision of utility information to affiliates, and energy procurement-related
transactions between the utilities and their affiliates. The rules
also prohibit each utility from engaging in certain practices that would
discriminate against energy service providers that compete with that utility's
affiliates. In December 2006, the CPUC revised its rules to, among
other changes:
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·
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emphasize
that the holding company may not aid or abet a utility's violation of the
rules or act as a conduit to provide confidential utility information to
an affiliate;
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·
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require
prior CPUC approval before the utility can contract with an affiliate for
resource procurement (e.g., electricity or
gas), except in blind transactions where the identity of the other party
is not known until the transaction is consummated;
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·
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require
certain key officers to provide annual certifications of compliance with
the affiliate rules;
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·
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prohibit
certain key officers from serving in the same position at both the utility
and the holding company (unless otherwise permitted by the CPUC), or, in
the alternative, prohibit the sharing of lobbying, regulatory relations
and certain legal services (except for legal services necessary to the
provision of permitted shared services);
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|
·
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require
the utility to obtain a “nonconsolidation opinion” indicating that it
would not be consolidated into a bankruptcy of its holding company;
and
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|
· |
make the CPUC's Energy Division responsible for hiring independent auditors to conduct biennial audits to verify that the utility is in compliance with the affiliate rules. |
The CPUC
has established specific penalties and enforcement procedures for affiliate
rules violations. Utilities are required to self-report affiliate
rules violations.
Various
aspects of the Utility's business are subject to a complex set of energy,
environmental and other laws, regulations and regulatory proceedings at the
federal, state and local levels. In addition to enacting PUHCA 2005
to replace the Public Utility Holding Company Act of 1935, as discussed above,
the EPAct significantly amended various federal energy laws applicable to
electric and natural gas markets, including the Federal Power Act of 1935, the
Natural Gas Act of 1938 and the Public Utility Regulatory Policies Act of 1978
(“PURPA”).
This
section and the “Ratemaking Mechanisms” section below summarize some of the more
significant laws, regulations and regulatory mechanisms affecting the Utility.
These summaries are not an exhaustive description of all the laws, regulations
and regulatory proceedings that affect the Utility. The energy laws, regulations
and regulatory proceedings may change or be implemented or applied in a way that
the Utility does not currently anticipate. For discussion of specific pending
regulatory proceedings that are expected to affect the Utility see the section
of MD&A entitled “Regulatory Matters” in the 2008 Annual
Report.
The FERC
regulates the transmission and wholesale sales of electricity in interstate
commerce and the transmission and sale of natural gas for resale in interstate
commerce. The FERC also regulates interconnections of transmission
systems with other electric systems and generation facilities; tariffs and
conditions of service of regional transmission organizations, including the
CAISO; and the terms and rates of wholesale electricity sales. The
EPAct granted the FERC significant new responsibilities to oversee the
reliability of the nation’s electricity transmission grid, to prevent market
manipulation, and to supplement state transmission siting efforts in certain
electric transmission corridors that are determined to be of national
interest. The EPAct also expanded the FERC’s authority to impose
penalties for violation of certain federal statutes, including the Federal Power
Act of 1935 and the Natural Gas Act of 1938, and for violations of FERC-approved
regulations. The FERC can impose penalties of up to $1,000,000 per day per
violation. The FERC has jurisdiction over the Utility's electricity
transmission revenue requirements and rates, the licensing of substantially all
of the Utility's hydroelectric generation facilities, and the interstate sale
and transportation of natural gas.
Electric Reliability Standards;
Development of Transmission Grid. As part of its directive to
oversee the development of mandatory electric reliability standards to protect
the national electric transmission system, the FERC certified the North American
Electric Reliability Corp. (“NERC”), as the nation’s Electric Reliability
Organization under the EPAct of 2005. The NERC is responsible for
developing and enforcing electric reliability standards, subject to FERC
approval. The FERC also has approved a delegation agreement under which the NERC
has delegated enforcement authority for the geographic area known as the Western
Interconnection to the Western Electricity Coordinating Council
(“WECC”). The Utility must self-certify compliance to the WECC on an
annual basis, and the compliance program encourages self-reporting of
violations. WECC staff, with participation by the NERC and the
FERC, will also perform a regular compliance audit of the Utility every three
years. In addition, the WECC and the NERC may perform spot checks or
other interim audits, reports, or investigations. Under FERC
authority the WECC, NERC, and/or FERC may impose penalties up to $1,000,000 per
day per violation.
The FERC
also has issued rules on electric transmission pricing reforms designed to
promote needed investment in energy infrastructure, to reduce transmission
congestion, and to require transmission organizations with organized electricity
markets to make long-term firm transmission rights available to load-serving
entities, so these entities can enter into long-term transmission service
arrangements without being exposed to unhedged congestion cost
risk. In addition, the CAISO is responsible for providing open access
electricity transmission service on a non-discriminatory basis, planning
transmission system additions, and ensuring the maintenance of adequate reserves
of generation capacity.
The
Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction,
operation and decommissioning of nuclear facilities, including the two nuclear
generating units at Diablo Canyon and the Utility’s retired nuclear generating
unit at Humboldt Bay (“Humboldt Bay Unit 3”). NRC regulations require
extensive monitoring and review of the safety, radiological, environmental and
security aspects of these facilities. In the event of non-compliance, the NRC
has the authority to impose fines or to force a shutdown of a nuclear plant, or
both. NRC safety and security requirements have, in the past, necessitated
substantial capital expenditures at Diablo Canyon, and additional significant
capital expenditures could be required in the future.
The NRC
operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC
operating license for Diablo Canyon Unit 2 expires in
August 2025. Under the terms of these licenses, there must be
sufficient storage capacity for the radioactive spent fuel produced by the
Diablo Canyon plant. For a discussion of the Utility’s spent fuel
storage project, see “Environmental Matters – Nuclear Fuel Disposal,”
below.
The
Utility's operations have been significantly affected by various statutes passed
by the California Legislature, including:
|
·
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Assembly Bill
1890. Assembly Bill 1890, enacted in 1996, mandated the
restructuring of the California electricity industry, commencing in 1998,
which was intended to create a competitive market for electricity
generation and give customers of the investor-owned utilities the ability
to choose “direct access” by buying energy from a service provider other
than the regulated utilities. (Subsequent legislation,
described below, suspended direct access during the California energy
crisis of 2000-2001.) Among other provisions, Assembly Bill
1890 also provided for the establishment of the CAISO, as a nonprofit
public benefit corporation, to operate and control the state-wide
electricity transmission grid and ensure efficient use and reliable
operation of the transmission grid.
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Assembly Bill
1X. Assembly Bill 1X was enacted during the
California 2000-2001 energy crisis when the California investor-owned
electric utilities were no longer able to buy
electricity. Assembly Bill 1X authorized the California
Department of Water Resources (“DWR”) beginning on February 1, 2001,
to purchase electricity and sell that electricity directly to the
investor-owned electric utilities' retail customers. Assembly Bill 1X
required the California investor-owned electric utilities to deliver
electricity purchased by the DWR under the contracts and to act as the
DWR's billing and collection agent. To ensure that the DWR
recovers its costs to procure electricity, Assembly Bill 1X required the
CPUC to suspend the right of retail end-user customers to become direct
access customers until the DWR no longer procures electricity pursuant to
Assembly Bill 1X. The current DWR contracts terminate at
various dates through
2015.
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Assembly Bill 57.
Assembly Bill 57, enacted in September 2002 and
amended by Senate Bill 1976, required the California investor-owned
utilities to resume purchasing power on January 1, 2003, required the CPUC
to allocate electricity to be provided under the DWR contracts among the
customers of the California investor-owned electric utilities, requires
the utilities to file short- and long-term electricity resource
procurement plans with the CPUC for approval, and authorizes the utilities
to timely recover their reasonable wholesale procurement costs incurred
under a CPUC-approved procurement plan through the establishment of new
electricity procurement balancing accounts that reflect differences
between recorded revenues and costs incurred under the approved
procurement plans.
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Senate Bill
1078. Senate Bill 1078, enacted in September 2002
(as amended by Senate Bill 107, enacted in September 2006 and effective on
January 1, 2007) established the renewables portfolio standard (“RPS”)
program, which requires each California retail seller of electricity,
except municipal utilities, to increase its purchases of eligible
renewable energy (such as
biomass,
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small
hydroelectric, wind, solar and geothermal energy) by at least 1% of its
retail sales, so that the amount of electricity purchased from eligible
renewable resources equals at least 20% of its total retail sales by the
end of 2010. An unexcused failure to satisfy the RPS targets
may result in a penalty of five cents per kilowatt hour with an annual
penalty cap of $25 million. The California Legislature is
considering proposals to increase the RPS mandate to at least 33% by
2020.
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Assembly Bill 380.
Assembly Bill 380, enacted in September 2005, requires the CPUC, in
consultation with the CAISO, to establish resource adequacy requirements
for all load-serving entities, including the California investor-owned
electric utilities but excluding local publicly owned electric
utilities. Assembly Bill 380 requires each load-serving entity
to maintain physical generating capacity adequate to meet its load
requirements, including peak demand and planning and operating reserves,
deliverable to locations and at times as may be necessary to provide
reliable electric service.
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Assembly Bill
32. Assembly Bill 32, enacted in September 2006,
requires the California Air Resources Board (“CARB”) to adopt regulations
to limit statewide greenhouse gas emission, to 1990 levels by 2020, with
certain limits beginning in 2012. (See “Environmental Matters”
below for more information.)
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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.)
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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 the
Utility’s performance, using measures such as the frequency and duration of
outages. The CPUC also conducts investigations into various matters, such as
deregulation, competition and the environment, in order to determine its future
policies. The CPUC consists of five members appointed by the Governor of
California and confirmed by the California State Senate for staggered six-year
terms.
PG&E
Corporation and the Utility entered into a settlement agreement with the CPUC on
December 19, 2003, to resolve the Utility's proceeding filed under Chapter 11 of
the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for
the Northern District of California (“Bankruptcy Court”) since April 2001,
referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter 11
Settlement Agreement established certain regulatory assets and addressed various
ratemaking matters to restore the Utility’s financial health and enable it to
emerge from Chapter 11. The terms of the Chapter 11 Settlement
Agreement were incorporated into the Utility’s plan of reorganization under
Chapter 11, which became effective on April 12, 2004. The Bankruptcy
Court retains jurisdiction to hear and determine disputes arising in connection
with the interpretation, implementation or enforcement of the Chapter 11
Settlement Agreement, in addition to other matters. (For more information, see
Note 15 of the Notes to the Consolidated Financial Statements included in
the 2008 Annual Report.)
The
California Energy Resources Conservation and Development Commission, commonly
called the California Energy Commission (“CEC”), is the state's primary energy
policy and planning agency. The CEC is responsible for licensing of all thermal
power plants over 50 MW, overseeing funding programs that support public
interest energy research, advancing energy science and technology through
research, development and demonstration, and providing market support to
existing, new and emerging renewable technologies. In addition, the CEC is
responsible for 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 MattersWater Quality” below.)
The
Utility has over 520 franchise agreements with various cities and counties that
permit the Utility to install, operate, and maintain the Utility's electric and
natural gas facilities in the public streets and roads. In exchange
for the right to use public streets and roads, the Utility pays annual fees to
the cities and counties. Franchise fees are computed pursuant to
statute under either the Broughton Act or the Franchise Act of
1937. In addition, charter cities can negotiate their
fees. In most cases, the Utility’s franchise agreements are for an
indeterminate term, with no expiration date. The Utility has several
franchise agreements that have a specified term, including an agreement with a
large charter city. The franchise agreements generally require that
the Utility install and maintain the electric and gas facilities in compliance
with regulations adopted by cities and counties in the exercise of their police
powers relating to the use of the public streets. The Utility also
periodically obtains permits, authorizations and licenses in connection with
distribution of electricity and natural gas. Under these permits,
authorizations and licenses, the Utility has rights to occupy and/or use public
property for the operation of the Utility's business and to conduct certain
related operations.
Competition
Historically,
energy utilities operated as regulated monopolies within service territories in
which they were essentially the sole suppliers of natural gas and electricity
services. These utilities owned and operated all of the businesses and
facilities necessary to generate, transport and distribute energy. Services were
priced on a combined, or bundled, basis with rates charged by the energy
companies designed to include all the costs of providing these services. Under
traditional cost-of-service regulation, the utilities undertook a continuing
obligation to serve their customers, in return for which the utilities were
authorized to charge regulated rates sufficient to recover their costs of
service, including timely recovery of their operating expenses and a reasonable
return on their invested capital. The objective of this regulatory policy was to
provide universal access to safe and reliable utility services. Regulation was
designed in part to take the place of competition and ensure that these services
were provided at fair prices.
In recent
years, energy utilities have faced intensifying pressures to unbundle, or price
separately, those services that are no longer considered natural monopolies. The
most significant of these services are the commodity components—the supply of
electricity and natural gas. The driving forces behind these competitive
pressures have been customers who believe that they can obtain energy at lower
unit prices and competitors who want access to those customers. Regulators and
legislators responded to these forces by providing for more competition in the
energy industry. Regulators and legislators, to varying degrees, have required
utilities to unbundle rates in order to allow customers to compare unit prices
of the utilities and other providers when selecting their energy service
provider.
Federal. At the
federal level, many provisions of the EPAct support the development of
competition in the wholesale electric market. The EPAct has directed the FERC to
develop rules to encourage fair and efficient competitive markets by employing
best practices in market rules and reducing barriers to trade between markets
and among regions. The EPAct also gives the FERC authority to prevent
accumulation and exercise of market power by assuring that proposed mergers and
acquisitions of public utility companies and their holding companies are in the
public interest and by addressing market power in jurisdictional wholesale
markets through its new powers to establish and enforce rules prohibiting market
manipulation.
Even
before the passage of the EPAct, the FERC's policies supported the development
of a competitive electricity generation industry. FERC Order 888,
issued in 1996, established standard terms and conditions for parties seeking
access to regulated utilities' transmission grids. Order 888 requires
all public utilities that own, control, or operate facilities used for
transmitting electric energy in interstate commerce to have on file an open
access non-discriminatory transmission tariff (“OATT”) that contains minimum
terms and conditions of non-discriminatory service. The FERC's
subsequent Order 2000, issued in late 1999, established national standards for
regional transmission organizations, and advanced the view that a regulated,
unbundled transmission sector should facilitate competition in both wholesale
electricity generation and retail electricity markets. On February 16, 2007, the
FERC issued Order 890, which is designed to: (1) strengthen the form of the OATT
adopted in Order 888 to ensure that tariffs achieve their original purpose of
remedying undue discrimination; (2) provide greater specificity in the form of
the OATT to reduce opportunities for undue discrimination and facilitate the
FERC’s enforcement; and (3) increase transparency in the rules applicable to
planning and use of the transmission system.
The FERC
also has issued rules on the interconnection of generators to require regulated
transmission providers, such as the Utility or the CAISO, to use standard
interconnection procedures and a standard agreement for generator
interconnections. These rules are intended to limit opportunities for
transmission providers to favor their own generation, facilitate market entry
for generation
competitors
by streamlining and standardizing interconnection procedures, and encourage
needed investment in generation and transmission. Under the rules and associated
tariffs, a new generator is required to pay for the transmission system upgrades
needed in order to interconnect the generator. The generator will be reimbursed
over a five-year period after the power plant achieves commercial operation. The
cost of the network upgrades is then recovered by the regulated transmission
provider in its overall transmission rates.
State. At the
state level, Assembly Bill 1890 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 through the Power Exchange
(“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 to make compliance filings as required by the
FERC in the California refund proceeding, which is still pending at the
FERC. (For information about the status of the California refund
proceeding and the remaining disputed claims made by power suppliers in the
Utility’s Chapter 11 proceeding, see Note 15 of the Notes to the Consolidated
Financial Statements in the 2008 Annual Report.) The CAISO, which was
established pursuant to AB 1890 to take control of the California investor-owned
electric transmission facilities located in California, currently administers a
real-time or “spot” wholesale market for the sale of electric energy. This
market is used to allocate space on the transmission lines, maintain operating
reserves, and match supply with demand in real time. The CAISO’s MRTU
initiative is intended to restructure the California electricity market and to
enhance power grid reliability, including the implementation of a new day-ahead
market. The CAISO also will provide congestion revenue rights to
allow market participants, including load-serving entities, to hedge the
financial risk of CAISO-imposed congestion charges in the MRTU day-ahead
market. The MRTU tariffs will apply to all load-serving entities,
including the investor-owned utilities, serving California
consumers. The CAISO has delayed the start date of MRTU several times
but is now targeting April 1, 2009. Also, in January 2008, the CPUC
staff issued its recommendation to establish a statewide wholesale electric
capacity market to replace the current resource adequacy program. Any
changes the CPUC adopts would be subject to FERC approval.
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 for the customers of the
investor-owned electric utilities, 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, but allowed existing direct access customers to
continue being served by alternative energy service providers, rather than
investor-owned electric utilities. The CPUC has assessed an additional charge on
certain direct access customers to avoid a shift of costs from direct access
customers to customers who receive bundled service. The CPUC is
actively investigating how the DWR can terminate its obligations under the power
contracts, by assignment or otherwise, to hasten the reinstatement of direct
access.
In
addition, the Utility’s customers may, under certain circumstances, obtain power
from a “community choice aggregator” instead of from the
Utility. California 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. No cities or counties are currently operating as
community choice aggregators, but the San Joaquin Valley Power Authority has
filed an implementation plan and stated that it may begin operating in
2009. In addition, the County of Marin and several cities in that
county have voted to pursue community choice aggregation and have formed a joint
powers agency to do so, but have not yet filed an implementation
plan.
FERC
Order 636, issued in 1992, required interstate natural gas pipeline companies to
divide their services into separate gas commodity sales, transportation and
storage services. Under Order 636, interstate natural gas pipeline companies
must provide transportation service 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 the FERC’s rules and regulations applicable to interstate
pipelines; the Utility’s pipeline operations are instead subject to the
jurisdiction of the CPUC. The Utility’s gas transmission and storage
system has operated under the CPUC-approved “Gas Accord” market structure since
1998. This market structure largely mimics the regulatory framework
required by the FERC for interstate gas pipelines. The CPUC
divides
the
Utility's natural gas customers into two categories: “core” customers, which are
primarily small commercial and residential customers, and “non-core” customers,
which are primarily industrial, large commercial and electric generation
customers. Under the Gas Accord structure, non-core customers have
access to capacity rights for firm service, as well as interruptible (or
“as-available”) services. All services are offered on a
nondiscriminatory basis to any creditworthy customer. The Gas Accord
market structure has resulted in a robust wholesale gas commodity market at the
Utility’s “citygate,” which refers to the interconnection between the big
“backbone” gas transmission system and the smaller, downstream local
transmission systems.
The
Utility’s first Gas Accord, a settlement agreement reached among the Utility and
many interested parties, was approved by the CPUC in 1997, took effect on March
1, 1998, and was renewed, with slight modifications, for various successive
periods. In September 2007, the CPUC approved the Gas Accord IV
covering 2008 through 2010. The Gas Accord separated the Utility’s
natural gas transmission and storage rates from its distribution services and
rates. The Gas Accord also changed the nature of the Utility’s
transmission and storage services by creating path-specific transmission
services, firm and interruptible service offerings, standard and negotiated rate
options, and a secondary market for trading of firm capacity
rights. Additionally, the Gas Accord eliminated balancing account
protection for some services, increasing the Utility’s risk/reward
potential.
The
Utility competes with other natural gas pipeline companies for customers
transporting natural gas into the southern California market on the basis of
transportation rates, access to competitively priced supplies of natural gas,
and the quality and reliability of transportation services. The most important
competitive factor affecting the Utility's market share for transportation of
natural gas to the southern California market is the total delivered cost of
western Canadian natural gas relative to the total delivered cost of natural gas
from the southwestern United States. The total delivered cost of natural gas
includes, in addition to the commodity cost, transportation costs on all
pipelines that are used to deliver the natural gas, which, in the Utility's
case, includes the cost of transportation of the natural gas from Canada to the
California border and the amount that the Utility charges for transportation
from the border to southern California. In general, when the total cost of
western Canadian natural gas increases relative to other competing natural gas
sources, the Utility's market share of transportation services into southern
California decreases. The Utility also competes for storage services
with other third-party storage providers, primarily in northern
California.
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 230-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 proposed Jordan Cove liquefied natural gas (“LNG”)
terminal in Coos Bay, Oregon, being developed by Fort Chicago Energy 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. It is expected
that the FERC will issue a certificate authorizing construction and operation of
the pipeline in 2009.
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
Energy Partners, L.P. PG&E Corporation cannot predict whether
Fort Chicago Energy 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 capacity
contracts. Assuming the required permits, authorizations, and
long-term capacity commitments are timely received and that other conditions are
timely satisfied, the proposed LNG terminal and the proposed Pacific Connector
Gas Pipeline could begin commercial operation in 2013.
Ratemaking
Mechanisms
The
Utility’s rates for electricity and natural gas utility services are based on
its costs of providing service (“cost-of-service ratemaking”). Before
setting rates, the CPUC and the FERC determine the annual amount of revenue
(“revenue requirements”) that the Utility is authorized to collect from its
customers. The CPUC determines the Utility’s revenue requirements
associated with electricity and gas distribution operations, electricity
generation, and natural gas transportation and storage. The FERC
determines the Utility’s revenue requirements associated with its electricity
transmission operations.
Revenue
requirements are designed to allow a utility an opportunity to recover its
reasonable operating and capital costs of
providing
utility services as well as a return of, and a fair rate of return on, its
investment in utility facilities (“rate base”). Revenue requirements
are primarily determined based on the Utility’s forecast of future
costs. These costs include the Utility’s costs of electricity and
natural gas purchased for its customers, operating expenses, administrative and
general expenses, depreciation, taxes, and public purpose programs.
Regulatory
balancing accounts are used to adjust the Utility’s revenue
requirements. Sales balancing accounts track differences between the
Utility’s recorded revenues and its authorized revenue requirements, due
primarily to sales fluctuations. In general, electricity sales are
higher in the summer months and natural gas sales are higher in the winter
months. Cost balancing accounts track differences between the
Utility’s incurred costs and its authorized revenue requirements, most
importantly for energy commodity costs and volumes that can be affected by
seasonal demand, weather, and other factors. Balances in all
CPUC-authorized accounts are subject to review, verification audit, and
adjustment, if necessary, by the CPUC.
To
develop retail rates, the revenue requirements are allocated among customer
classes (mainly residential, commercial, industrial and agricultural) and to
various service components (mainly customer, demand, and
energy). Specific rate components are designed to produce the
required revenue. Rate changes become effective prospectively on or
after the date of CPUC or FERC decisions. Most rate changes approved
by the CPUC throughout the year are consolidated to take effect on the first day
of the following year.
Through
cost-of-service ratemaking, rates are developed to produce the revenue
requirements, including the authorized return on rate base. The
Utility may be unable to earn its authorized rate of return because the CPUC or
the FERC excludes the Utility’s actual costs from the revenue requirements or
because the Utility’s actual costs are higher than those reflected in the
revenue requirements.
While the
CPUC generally uses cost-of-service ratemaking to develop revenue requirements
and rates, it selectively uses incentive ratemaking, which bases rates on the
extent to which the utilities meet objective or fixed standards or goals, such
as reliability standards or energy efficiency goals, instead of on the cost of
providing service.
The
General Rate Case (“GRC”) is the primary proceeding in which the CPUC determines
the amount of revenue requirements that the Utility is authorized to collect
from customers to recover the Utility’s basic business and operational costs
related to its electricity and natural gas distribution and electricity
generation operations. The CPUC generally conducts a GRC every three
years. The CPUC sets revenue requirement levels for a three-year rate
period based on a forecast of costs for the first or “test”
year. Typical interveners in the Utility's GRC include the CPUC’s
Division of Ratepayer Advocates and The Utility Reform Network. On
March 15, 2007, the CPUC approved a multi-party settlement agreement to resolve
the Utility’s 2007 GRC. The decision set the Utility’s electricity
and natural gas distribution and electricity generation revenue requirements for
a four-year period, from 2007 through 2010, rather than for a typical three-year
period. Under the decision, the Utility’s next GRC will be effective
January 1, 2011. The Utility intends to submit a draft of the 2011 GRC
application and revenue requirement request to the CPUC in July or August
2009. For more information, see the section of MD&A entitled
“Results of Operations” in the 2008 Annual Report.
The CPUC
may authorize the Utility to receive annual increases for the years between GRCs
in the base revenues authorized for the test year of a GRC in order to avoid a
reduction in earnings in those years due to, among other things, inflation and
increases in invested capital. These adjustments are known as attrition rate
adjustments. Attrition rate adjustments provide increases in the revenue
requirements that the Utility is authorized to collect in rates for electricity
and natural gas distribution and electricity generation
operations. The CPUC’s decision in the Utility’s 2007 GRC includes a
provision for attrition adjustments made in 2008, and to be made in 2009 and
2010. For more information, see the section of MD&A entitled
“Results of Operations” in the 2008 Annual Report.
Cost
of Capital Proceedings
The CPUC
generally conducts a 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.
The CPUC then establishes the authorized return on each component that the
Utility will collect in its authorized rates. In May 2008, the CPUC
adopted a uniform three-year cost of capital mechanism to set the cost of
capital for the Utility and the other two California investor-owned electric
utilities. The utilities are required to file full cost of capital
applications by April 20 of every third year, beginning on April 20,
2010.
The cost
of capital mechanism uses an interest rate index (the 12-month October through
September average of the Moody's Investors Service utility bond index) to
trigger changes in the authorized cost of debt, preferred stock, and
equity. In any year in which the 12-month October through September
average for the index increases or decreases by more than 100 basis points
(“deadband”) from the benchmark, the cost of equity will be adjusted by one-half
of the difference between the 12-month average and the benchmark. In
addition, if the mechanism is triggered, the costs of long-term debt and
preferred stock will be adjusted to reflect the actual August month-end embedded
costs in that year and forecasted interest rates for variable long-term debt and
any new long-term debt and preferred stock forecasted to be issued in the coming
year. The 12-month October 2007 through September 2008 average of the
Moody's Investors Service utility bond index did not trigger a change in the
authorized cost of debt, preferred stock, or equity for 2009.
The
Utility’s current CPUC-authorized capital structure consists of 46% long-term
debt, 2% preferred stock and 52% common equity. The Utility’s current
CPUC-authorized rate of return that the Utility may earn on its electricity and
natural gas distribution and electricity generation rate base is 6.05% for
long-term debt, 5.68% for preferred stock and 11.35% for common equity,
resulting in an overall rate of return on rate base of 8.79%. This
capital structure and authorized rate of return will be maintained through 2010,
unless the automatic adjustment mechanism is triggered. The utilities
may apply for an adjustment to either the cost of capital or the capital
structure sooner based on extraordinary circumstances.
Although
the FERC has authority to set the Utility’s rate of return for its electricity
transmission operations, the rate of return is often unspecified if the
Utility's transmission rates are determined through a negotiated rate
settlement.
The 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.
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. California law also requires the CPUC to authorize funding
for the California Solar Initiative and other self-generation programs as
discussed below. Additionally, the CPUC has authorized funding for
demand response programs.
For 2008,
the CPUC authorized the Utility to collect revenue requirements of approximately
$741.7 million of which approximately $656.6 million is collected from electric
customers to fund electric public purpose and other programs and approximately
$85.1 million is collected from gas customers to fund natural gas public purpose
and other programs. The CPUC is responsible for authorizing the programs,
funding levels and cost recovery mechanisms for the Utility's operation of these
programs. The CEC administers both the electric and natural gas public interest
research and development programs and the renewable energy program on a
statewide basis. In 2008, the Utility transferred approximately
$79.5 million to the CEC for CEC-administered gas and electric programs.
See the discussion below for a further description of these programs and
authorized funding amounts.
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Energy Efficiency
Programs. The Utility’s energy efficiency programs are designed to
encourage the manufacture, design, distribution and customer use of energy
efficient appliances and other energy-using products. The CPUC authorized
funding of $403 million for 2008 gas and electric programs, including
funding for the CEC-administered programs. The Utility intends to file an
amended application on March 2, 2009 to seek CPUC approval and funding
authorization of approximately $1.8 billion for the Utility’s 2009-2011
energy efficiency programs, an approximate increase of $860 million over
the 2006-2008 budget. On October 16, 2008, the CPUC authorized
bridge funding for 2009 of $394.9 million to allow the Utility to continue
existing energy efficiency programs until the CPUC issues a final decision
on the 2009-2011 application.
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The CPUC
has set certain goals for energy efficiency savings and has established an
incentive ratemaking mechanism to encourage the California investor-owned
utilities to promote energy efficiency and to meet the CPUC’s goals over the
2006-2008 and 2009-2011 program cycles. To earn an award a utility
must (1) achieve at least 85% of the CPUC’s overall energy savings goal over the
three-year program cycle and (2) achieve at least 80% of the CPUC’s individual
kWh, kW, and gas therm savings goals over the three-year program
cycle. If the utility achieves between 85% and 99% of the CPUC’s
overall savings goal, 9% of the verified net benefits (i.e., energy resource savings
minus total energy efficiency program costs) will accrue to shareholders and 91%
of the verified net benefits will accrue to customers. If the
utility achieves 100% or more of the CPUC’s overall savings goal, then 12%
of the total verified net benefits will accrue to shareholders and 88% will
accrue to customers. If the utility achieves less than 65% of any one of
the individual metric savings goals (i.e., kWh, kW, or gas therm),
then the Utility must reimburse customers based on the greater of (1) 5 cents
per
kWh, 45
cents per therm, and $25 per kW for each kWh, therm, or kW unit
below the 65% threshold, or (2) a dollar-for-dollar payback of negative net
benefits, also known as a cost-effectiveness guarantee. The maximum
award that the Utility could earn, and the maximum amount that the Utility could
be required to reimburse customers over the 2006-2008 program
cycle is $180 million.
On
January 29, 2009, the CPUC instituted a new proceeding to modify the existing
incentive ratemaking mechanism, to adopt a new framework to review the
utilities’ 2008 energy efficiency performance and to conduct a final review of
the utilities’ performance over the 2006-2008 program period. The CPUC also
plans to develop a long-term incentive mechanism for program periods beginning
in 2009 and beyond. For more information, see the section of MD&A entitled
“Regulatory Matters─Energy Efficiency Programs and Incentive Ratemaking” in the
2008 Annual Report.
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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. The
2008 authorized funding for Demand Response Programs was $38 million. The CPUC has not
yet approved the Utility’s request for funding of approximately $148
million for the Utility’s 2009-2011 demand response
programs. On December 18, 2008, the CPUC authorized bridge
funding of $41 million to continue certain demand response programs in
2009 until a final decision is issued on the Utility’s
request.
|
In
addition, on February 14, 2008, the CPUC approved the Utility’s multi-year air
conditioning direct load control program and authorized funding of $179 million
through June 1, 2011 to implement this program. The 2008 authorized funding
level was approximately $37 million. Customers who enroll in this
program will allow the Utility to remotely control the temperature settings of
their central air conditioners to temporarily decrease their energy usage during
local or system emergencies. The decision will allow the Utility to
enroll approximately 397,000 air conditioning load control devices to achieve
approximately 305 MW of load reduction capacity by June 2011.
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·
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Self-Generation Incentive
Program and California Solar Initiative. The
Utility administers the self-generation incentive program (“SGIP”)
authorized by the CPUC to provide incentives to electricity customers who
install certain types of clean or renewable distributed generation
resources that meet all or a portion of their onsite energy
usage. The CPUC approved a budget for the SGIP of approximately
$36 million in each of 2008 and 2009. In late 2006, the CPUC also
established the California Solar Initiative (“CSI”) to bring 1,940 MW of
solar power on-line by 2017 in California and authorized the California
investor-owned utilities to collect an additional $2.2 billion over the
2007 through 2016 period from their customers to fund customer incentives
for the installation of retail solar energy projects to serve onsite load
to meet this goal. Of the total amount authorized, the Utility
has been allocated $946 million to fund customer incentives, research,
development and demonstration activities (with an emphasis on the
demonstration of solar and solar-related technologies), and administration
expenses. The California Legislature modified the CSI program
to include participation of the California municipal utilities. The
current overall goal of the CSI is to install 3,000 MW (through both
investor-owned electric utilities and electric municipal utilities)
through 2017.
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|
·
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Low-Income Energy Efficiency
Programs and California Alternate Rates for Energy. The
CPUC authorized the Utility to collect approximately $86 million for these
programs in 2008. The CPUC has authorized the Utility to
collect approximately $422 million to support the Utility’s energy
efficiency programs for low-income and fixed-income customers over
2009-2011. The Utility also provides a discount rate called the
California Alternate Rates for Energy (“CARE”) for low-income
customers. This rate subsidy is paid for by the Utility's other
customers. The extent of the subsidy, during any given year,
depends upon the number of customers participating in the
program. In 2008, the amount of this subsidy was approximately
$526.6 million, including avoided customer surcharges. The CPUC
also authorized the Utility to recover approximately $28 million in
administrative costs relating to the CARE subsidy over
2009-2011.
|
Each
California investor-owned electric utility is responsible for procuring
electricity to meet customer demand, plus applicable reserve margins, not
satisfied from that utility's own generation facilities and existing electricity
contracts (including DWR allocated contracts). To accomplish this, each utility
must submit a long-term procurement plan covering a ten-year period to the CPUC
for approval. Each long-term procurement plan must be designed to reduce
greenhouse gas emissions and use the State of California’s preferred loading
order to meet forecasted demand (i.e., increases in future
demand will be offset through energy efficiency programs, demand response
programs, renewable generation resources, distributed generation resources, and
new conventional generation). In December 2007, the CPUC approved the
utilities’ long-term procurement plans, covering the 2007-2016 period, subject
to certain required modifications. California legislation, Assembly
Bill 57, allows the utilities to recover the costs
incurred
in compliance with their CPUC-approved procurement plans without further
after-the-fact reasonableness review. Each utility may, if
appropriate, conduct a competitive request for offers (“RFO”) within the
parameters permitted in its approved plan to meet the utility’s projected need
for electricity resources. Contracts that are entered into after the
RFO process are submitted to the CPUC for approval, along with a request for the
CPUC to authorize revenue requirements to recover the associated
costs. The utilities conduct separate competitive solicitations to
meet their renewable energy resource requirements. The utilities submit the
renewable energy contracts after the conclusion of these solicitations to the
CPUC for approval and authorization of the associated revenue
requirements. For more information about the Utility’s approved
long-term procurement plan covering 2007-2016, see “Electric Utility Operations
— Electricity Resources-Future Long-Term Generation Resources”
below.
The
Utility recovers its electricity procurement costs and the fuel costs for the
Utility’s own generation facilities (but excluding the costs of electricity
allocated to the Utility’s customers under DWR contracts) through the Energy
Resource Recovery Account (“ERRA”), a balancing account authorized by the CPUC
in accordance with Assembly Bill 57. 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 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 purchase
costs.
The CPUC
has approved several power purchase agreements that the Utility has entered into
with third parties in accordance with the Utility’s CPUC-approved long-term
procurement plan and to meet renewable energy and resource adequacy
requirements. The CPUC also authorized the Utility to recover fixed
and variable costs associated with these contracts through the
ERRA.
For new
non-renewable generation purchased from third parties under power purchase
agreements, the Utility may 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 existing direct access customers and community choice
aggregation customers. (For information about the status of direct
access and community choice aggregation, see the section above entitled
“Competition in the Electricity Industry.”)
The
non-bypassable charge can be imposed from the date of signing a power purchase
agreement and last for 10 years from the date the new generation unit comes on
line or for the term of the contract, whichever is less. Utilities
are allowed to justify a cost recovery period longer than 10 years on a
case-by-case basis. If a utility elects to use the net capacity cost
allocation method, the net capacity costs would be allocated for the term of the
contract or 10 years, whichever is less, starting on the date the new generation
unit comes on line. Under this allocation mechanism, the energy
rights to the contract are auctioned off to maximize the energy revenues and
minimize the net capacity costs that would be subject to
allocation. If no bids are accepted for the energy rights, the
Utility would retain the rights to the energy and would value it at market
prices for the purposes of determining the net capacity costs to be allocated
until the next periodic auction.
The
CPUC-authorized revenue requirements for capital costs and non-fuel operating
and maintenance costs for operating Utility-owned generation facilities are
addressed in the Utility’s GRC. The CPUC-authorized revenue
requirements to recover the initial capital costs for utility-owned generation
projects are recovered through a balancing account, the Utility Generation
Balancing Account (“UGBA”), which tracks the difference between the
CPUC-approved forecast of initial capital costs, adjusted from time to time as
permitted by the CPUC, and actual costs. The initial revenue
requirement for the Utility-owned projects generally would begin to accrue in
the UGBA as of the new facility’s commercial operation date or the date a
completed facility is transferred to the Utility, and would be included in rates
on January 1 of the following year. For more information, see the
section of MD&A entitled “Capital Expenditures – New Generation Facilities”
in the 2008 Annual Report.
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. The Utility acts as a billing and collection agent for the DWR for these amounts; however, amounts collected for the DWR and any adjustments are not included in the Utility's revenues.
The
Utility'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 (“TO
rate case”). The Utility generally files a TO rate case every year,
setting 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. For more information about the Utility’s TO rate
cases, see the section of MD&A entitled “Regulatory Matters — Electric
Transmission Owner Rate Cases” in the 2008 Annual Report.
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. These revenues include:
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·
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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
|
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·
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revenues
that the CAISO collects from transmission users to relieve congestion on
the Utility’s transmission line (either in the form of financial hedges,
such as firm transmission rights relating to future deliveries of
electricity, or in the form of a usage charge to manage congestion
relating to real-time delivery of
electricity).
|
These
revenues are adjusted by the 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
also charges the Utility for reliability service costs and imposes a
transmission access charge for the Utility’s use of the CAISO-controlled
electric transmission grid in serving its customers. The CAISO's transmission
access charge methodology, approved by the FERC in December 2004, provides for a
transition over a 10-year period, from 2000-2009, to a uniform statewide
high-voltage transmission rate. This rate is based on the revenue
requirements associated with facilities operated at 200 kV and above of all
transmission-owning entities that become participating transmission owners under
the CAISO tariff. The transmission access charge methodology 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.
Natural
Gas
On
September 20, 2007, the CPUC issued a final decision approving a multi-party
settlement agreement, known as the Gas Accord IV, to establish the Utility’s
natural gas transmission and storage rates and associated revenue requirements
from January 1,
2008
through December 31, 2010. The Gas Accord IV establishes a 2008
natural gas transmission and storage revenue requirement of $446 million
(approximately 0.6% above the currently authorized revenue requirement for
2007), a 2009 revenue requirement of $459 million (approximately 2.8% above
the proposed 2008 revenue requirement), and a 2010 revenue requirement of
$471 million (approximately 2.7% above the proposed 2009 revenue
requirement). A substantial portion of the authorized revenue
requirements, primarily those costs allocated to core customers, will continue
to be assured of recovery through balancing account mechanisms and/or fixed
reservation charges. The Utility’s ability to recover the remaining
revenue requirements will continue to depend on throughput volumes, gas prices,
and the extent to which non-core customers and other shippers contract for firm
transmission services. This volumetric cost recovery risk associated with each
function (backbone transmission, local transmission, and storage) is summarized
below:
Backbone
Transmission. The backbone transmission revenue requirement is
recovered through a combination of firm, two-part rates (consisting of fixed
monthly reservation charges and volumetric usage charges) and as-available,
one-part rates (consisting only of volumetric usage charges). The mix
of firm and as-available backbone services provided by the Utility continually
changes. As a result, the Utility’s recovery of its backbone
transmission costs is subject to volumetric and price risk to the extent
backbone capacity is sold on an as-available basis. Core procurement
entities (including core customers served by the Utility) are the primary
long-term subscribers to backbone capacity. Core customers are
allocated approximately 36% of the total backbone capacity on the Utility’s
system. Core customers pay approximately 72% of the costs of the backbone
capacity that is allocated to them through fixed reservation
charges.
Local
Transmission. The local transmission revenue requirement is
allocated approximately 71% to core customers and 29% to non-core
customers. The Utility recovers the portion allocated to core
customers through a balancing account, but the Utility’s recovery of the portion
allocated to non-core customers is subject to volumetric and price
risk.
Storage. The
storage revenue requirement is allocated approximately 71% to core customers,
13% to non-core storage service, and 17% to pipeline load balancing
service. The Utility recovers the portion allocated to core customers
through a balancing account, but the Utility’s recovery of the portion allocated
to non-core customers is subject to volumetric and price risk. The
revenue requirement for pipeline load balancing service is recovered in backbone
transmission rates and is subject to the same cost recovery risks described
above for backbone transmission.
Taken
together, the backbone transmission, local transmission, and storage costs that
are either protected through balancing accounts or recovered through long-term
firm contract reservation charges amount to approximately 49% of the Utility’s
total revenue requirement for gas transmission and storage.
Certain
of the Utility's natural gas distribution costs and balancing account balances
are allocated to customers in the CPUC’s Biennial Cost Allocation Proceeding.
This proceeding normally occurs every two years and is updated in the interim
year for purposes of adjusting natural gas rates to recover from customers any
under-collection, or refund to customers any over-collection, in the balancing
accounts. Balancing accounts for gas distribution and other authorized expenses
accumulate differences between authorized amounts and actual
revenues.
The
Utility sets the natural gas procurement rate for core customers monthly, based
on the forecasted costs of natural gas, core pipeline capacity and storage
costs. The Utility reflects the difference between actual natural gas purchase
costs and forecasted natural gas purchase costs in several natural gas balancing
accounts, with under-collections and over-collections taken into account in
subsequent monthly rates.
The
Utility recovers the cost of gas (subject to the ratemaking mechanism discussed
below), acquired on behalf of core customers, through its retail gas
rates. The Utility is protected against after-the-fact reasonableness
reviews of these gas procurement costs under an incentive mechanism, the
CPIM. Under the CPIM, the Utility's purchase costs for a fixed
twelve-month period are compared to an aggregate market-based benchmark based on
a weighted average of published monthly and daily natural gas price indices at
the points where the Utility typically purchases natural gas. Costs
that fall within a tolerance band, which is 99% to 102% of the benchmark, are
considered reasonable and are fully recovered in customers' rates. One-half of
the costs above 102% of the benchmark are recoverable in customers' rates, and
the Utility's customers receive in their rates 80% of any savings resulting from
the Utility's cost of natural gas that is less than 99% of the benchmark. The
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. The Utility also
has received CPUC approval for a long-term gas hedging program on behalf of core
customers, through 2011. The costs of the hedging program are
recovered directly from gas customers, outside the CPIM mechanism, and are
subject only to a compliance review, not an after-the
fact
reasonableness review. (For more information see the section entitled “Risk
Management Activities” in the 2008 Annual Report).
On June
26, 2008, the CPUC opened a proceeding to examine the California gas utilities’
gas cost incentive mechanisms and the treatment of hedging costs under those
incentive mechanisms for core customers. The CPUC will determine
whether the utilities’ hedging plans should be incorporated into their incentive
mechanisms and whether re-examination of the utilities’ current incentive
mechanisms is necessary. It is uncertain when the CPUC will issue a
final decision.
The
Utility's interstate and Canadian natural gas transportation agreements with
third-party service providers are governed by tariffs that detail rates, rules,
and terms of service for the provision of natural gas transportation services to
the Utility on interstate and Canadian pipelines. United States tariffs are
approved for each pipeline for service to all of its shippers, including the
Utility, by the FERC in a FERC ratemaking review process, and the applicable
Canadian tariffs are approved by the Alberta Utilities Commission and the
National Energy Board. The Utility's agreements with interstate and Canadian
natural gas transportation service providers are administered as part of the
Utility's core natural gas procurement business. Their purpose is to transport
natural gas from the points at which the Utility takes delivery of natural gas
(typically in Canada and the southwestern United States) to the points at which
the Utility's natural gas transportation system begins. For
more information see the discussion below under “Natural Gas Utility Operations
– Interstate and Canadian Natural Gas Transportation Services
Agreements.”
Electric
Utility Operations
The
following table shows the percentage of the Utility's total sources of
electricity for 2008 represented by each major electricity
resource:
|
Owned
generation (nuclear, fossil fuel-fired and hydroelectric
facilities)
|
30%
|
|
DWR
|
15%
|
|
Qualifying
Facilities/Renewables
|
18%
|
|
Irrigation
Districts
|
2%
|
|
Other
Power Purchases
|
35%
|
The
Utility is required to dispatch, or schedule, all of the electricity resources
within its portfolio, including electricity provided under DWR contracts, in the
most cost-effective way. Least-cost dispatch requires the Utility, in certain
cases, to schedule more electricity than is necessary to meet its retail load
and therefore to sell this electricity on the wholesale electricity market. The Utility typically
schedules excess electricity when the expected sales proceeds exceed the
variable costs to operate a generation facility or buy electricity under an
optional contract. Proceeds from the
sale of surplus electricity are allocated between the Utility and the DWR, based
on the percentage of volume supplied by each entity to the Utility's total
load. The Utility's net proceeds from the sale of surplus electricity
after deducting the portion allocated to the DWR are recorded as a reduction to
the cost of electricity.
At
December 31, 2008, the Utility owned and operated the following generation
facilities, all located in California, listed by energy source:
|
Generation
Type
|
County
Location
|
Number
of
Units
|
Net
Operating
Capacity
(MW)
|
|||
|
Nuclear:
|
||||||
|
Diablo
Canyon
|
San
Luis Obispo
|
2
|
2,240
|
|||
|
Hydroelectric:
|
||||||
|
Conventional
|
16
counties in northern
and
central California
|
107
|
2,684
|
|||
|
Helms
pumped storage
|
Fresno
|
3
|
1,212
|
|||
|
Hydroelectric
subtotal
|
110
|
3,896
|
||||
|
Fossil
fuel:
|
||||||
|
Humboldt
Bay(1)
|
Humboldt
|
2
|
105
|
|||
|
Mobile
turbines
|
Humboldt
|
2
|
30
|
|||
|
Fossil
fuel subtotal
|
4
|
135
|
||||
|
Total
|
116
|
6,271
|
(1) The Humboldt Bay
facilities consist of a retired nuclear generation unit, Humboldt Bay Unit 3,
and two operating fossil fuel-fired
plants. As described
below,
the CPUC has approved the Utility’s application to re-power the two fossil
fuel-fired plants.
Diablo Canyon Power
Plant. The Utility's Diablo Canyon power plant consists of two
nuclear power reactor units, Units 1 and 2, with a total-plant net generation
capacity of approximately 2,240 MW of electricity. Unit 1 began commercial
operation in May 1985, and the operating license for this unit expires in
November 2024. Unit 2 began commercial operation in March 1986, and the
operating license for this unit expires in August 2025. For the
10-year period ended December 31, 2008, the Utility's Diablo Canyon power
plant achieved an average overall capacity factor of approximately
89.9%.
The
Utility has entered into various purchase agreements for nuclear fuel that are
intended to ensure long-term fuel supply. For more information about
these agreements, see Note 17: Commitments and Contingencies— Nuclear Fuel
Agreements, of the Notes to the Consolidated Financial Statements in the 2008
Annual Report.
The
following table outlines the Diablo Canyon power plant's refueling schedule for
the next five years. The Diablo Canyon power plant refueling outages
are typically scheduled every 20 months. The average length of a
refueling outage over the last five years has been approximately
51 days. The Utility will replace the steam generators in Unit 1
during the scheduled refueling outage that began in January 2009. Due
to this additional work, this refueling outage is expected to last approximately
76 days. The actual refueling schedule and outage duration will
depend on the scope of the work required for a particular outage and other
factors.
|
2009
|
2010
|
2011
|
2012
|
2013
|
|||||
|
Unit
1
|
|||||||||
|
Refueling
|
January
|
October
|
April
|
||||||
|
Duration
(days)
|
76
|
35
|
30
|
||||||
|
Startup
|
April
|
November
|
May
|
||||||
|
Unit
2
|
|||||||||
|
Refueling
|
October
|
-
|
May
|
February
|
|||||
|
Duration
(days)
|
35
|
-
|
30
|
30
|
|||||
|
Startup
|
November
|
-
|
June
|
March
|
In
addition, as discussed below under “Environmental Matters — Nuclear Fuel
Disposal,” in June 2009, the Utility expects to begin loading spent fuel into
the newly constructed on-site dry cask storage facility. To provide
another storage alternative to the dry cask storage facility, 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 there is a delay in loading spent fuel into the dry cask
storage facility beyond 2010, and if the Utility is otherwise unable to increase
its on-site storage capacity, the operation of Unit 1 may have to be curtailed
or halted as early as 2010 and the operation of Unit 2 may have to be curtailed
or halted as early as 2011, 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 69 powerhouses, including a pumped storage facility, with a
total generating capacity of 3,896 MW. The system includes 99 reservoirs,
56 diversions, 170 dams, 184 miles of canals, 44 miles of flumes, 135 miles of
tunnels, 19 miles of pipe, and 5 miles of natural waterways. The system also
includes water rights as specified in 90 permits or licenses and 160 statements
of water diversion and use. All of the Utility's powerhouses are
licensed by the FERC (except for three small powerhouses not subject to FERC
licensing requirements), with license terms between 30 and 50 years. In the
last five years, the FERC renewed three hydroelectric licenses with a total of
415 MW of hydroelectric power. The Utility is in the process of
renewing licenses for projects with approximately 1,183 MW of additional
hydroelectric power. Although the original licenses associated with
599 MW of the 1,183 MW have expired, the licenses are automatically renewed each
year until completion of the relicensing process. Licenses associated
with approximately 2,701 MW of hydroelectric power will expire between 2018 and
2043.
New Generation
Facilities. In addition to the Utility-owned resources shown
in the table above, the Utility has been engaged in the development of three
generation facilities to be owned and operated by the Utility. On January 4,
2009, the 530-MW Gateway Generating Station located in Antioch, California,
reached full load commercial production and is expected to reach final project
completion at the end of the first quarter of 2009. In June 2008, the
CPUC approved the construction of the Colusa Generating Station, a 657- MW
combined cycle generating facility to be located in Colusa County,
California. Final environmental permitting was approved on September
29, 2008 and construction began on October 1, 2008. Subject to
meeting operational performance requirements and other conditions, it is
anticipated that the Colusa Generating Station will commence operations in
2010. Also, in September 2008, the CEC issued its final decision
authorizing the construction of a 163-MW power plant to re-power the Utility’s
existing power plant at Humboldt Bay, which is at the end of its useful
life. Demolition of existing structures on the site is complete and
the contractor began preparing the site for construction in December
2008. Subject to obtaining required permits, meeting construction
schedules, operational performance requirements and other conditions, it is
anticipated that the Humboldt Bay project will commence operations in
2010. For more information, see the section of MD&A entitled
“Capital Expenditures ─ New
Generation
Facilities” in the 2008 Annual Report.
DWR
Power Purchases
During
2008, electricity from the DWR contracts allocated to the Utility provided
approximately 15% of the electricity delivered to the Utility's
customers. The DWR purchased the electricity under contracts with
various generators. The Utility, as an agent, is responsible for
administration and dispatch of these DWR contracts and acts as a billing and
collection agent. The DWR remains legally and financially responsible
for its contracts. The Utility expects that the amount of power
supplied under the DWR’s contracts will diminish in the future as the contracts
expire or terminate. For more information regarding the DWR
contracts, see Note 17: Commitments and Contingencies – California Department of
Water Resources Contracts, of the Notes to the Consolidated Financial Statements
in the 2008 Annual Report.
Qualifying Facility Power Purchase
Agreements. As of December 31, 2008, the Utility had power
purchase agreements with 246 QFs for approximately 3,900 MW that are in
operation. Agreements for approximately 3,600 MW expire at various
dates between 2009 and 2028. QF power purchase agreements for
approximately 300 MW have no specific expiration dates and will terminate only
when the owner of the QF exercises its termination option. The
Utility also has power purchase agreements with approximately 74 inoperative
QFs. The total of approximately 3,900 MW consists of roughly 2,500 MW
from cogeneration projects, 600 MW from wind projects and 800 MW from projects
with other fuel sources, including biomass, waste-to-energy, geothermal, solar,
and hydroelectric. QF power purchase agreements accounted for
approximately 18%, 20%, and 20%, of the Utility’s 2008, 2007, and 2006
electricity sources, respectively. No single QF accounted for more
than 5% of the Utility's 2008, 2007, or 2006 electricity sources.
Irrigation Districts and Water
Agencies. The Utility has contracts with various irrigation
districts and water agencies to purchase hydroelectric power. Under
these contracts, the Utility must make specified semi-annual minimum payments
based on the irrigation districts' and water agencies' debt service
requirements, whether or not any hydroelectric power is supplied, and variable
payments for operation and maintenance costs incurred by the
suppliers. These contracts expire on various dates from 2010 to
2031. The Utility's irrigation district and water agency contracts
accounted for approximately 2%, 3%, and 6% of the Utility’s electricity sources
in 2008, 2007, and 2006, respectively.
Renewable Energy
Contracts. California law requires each California retail
seller of electricity, except for municipal utilities, to increase its purchases
of renewable energy (such as biomass, small hydroelectric, wind, solar, and
geothermal energy) by at least 1% of its retail sales, so that the amount of
electricity delivered from renewable resources equals at least 20% of its total
retail sales by the end of 2010. During 2008, the Utility
entered into new renewable power purchase contracts that will help the Utility
meet this RPS by 2010.
Long-Term Power Purchase Agreements.
In accordance with the Utility’s CPUC-approved long-term procurement
plans, the Utility has entered into several power purchase agreements with third
parties. The Utility’s obligations under a portion of these
agreements are contingent on the third party’s development of a new generation
facility to provide the power to be purchased by the Utility under the
agreements.
For more
information regarding the Utility's power purchase contracts, see Note 17:
Commitments and Contingencies— Third-Party Power Purchase Agreements, of the
Notes to the Consolidated Financial Statements in the 2008 Annual
Report.
The
Utility’s CPUC-approved long-term electricity procurement plan, covering
procurement during 2007-2016, forecasts that the Utility will need to obtain an
additional 800 to 1,200 MW of new conventional generation by 2015 above the
Utility's planned additions of renewable resources, energy efficiency, demand
reduction programs, and previously approved contracts for new generation
resources.
The
utilities are permitted to acquire ownership of new conventional generation
resources only through purchase and sale agreements (“PSAs”) (i.e., a PSA is a “turnkey”
arrangement in which a new generating facility is constructed by a third party
and then sold to the Utility upon satisfaction of certain contractual
requirements) and engineering, construction, and
procurement arrangements proposed by third parties. The
utilities are prohibited from submitting offers for utility-build generation in
their respective RFOs until questions can be resolved about how to compare
offers for utility-owned generation with offers from independent power
producers. The utilities are permitted to propose utility-owned
generation projects through a separate application outside of the RFO process in
the following circumstances: (1) to mitigate market power demonstrated by the
utility to be held by others, (2) to support a use of preferred resources, such
as renewable energy sources, (3) to take advantage of a unique and
fleeting
opportunity
(such as a bankruptcy settlement), and (4) to meet unique reliability needs. On July 21, 2008, the Utility received offers from
third parties in response to the Utility’s April 1, 2008 RFO for 800 MW to 1,200
MW of dispatchable and operationally flexible new generation resources to be
on-line no later than May 2015. The Utility’s RFO requested offers
for both PSAs and power purchase agreements. In the fourth quarter of
2008 the Utility developed its RFO shortlist of participants and is currently
involved in negotiations with potential counterparties. The Utility
anticipates executing contracts and requesting CPUC approval of the executed
contracts in the first half of 2009.
In
addition, on February 24, 2009, the Utility requested the CPUC to approve the
Utility’s proposed development of renewable generation resources based on solar
photovoltaics (“PV”) technology. The Utility’s proposal includes the
development and construction of up to 250 MW of Utility-owned PV generating
facilities, to be deployed over a period of five years and the execution of
power purchase agreements for up to 250 MW of PV projects to be developed by
independent power producers. For more information regarding the
Utility's proposal, see the section of MD&A entitled “Capital Expenditures ─
Proposed New Generation Facilities” in the 2008 Annual Report.
Electricity
Transmission
At
December 31, 2008, the Utility owned 18,650 circuit miles of interconnected
transmission lines operated at voltages of 500 kV to 60 kV and transmission
substations with a capacity of 56,401 MVA. Electricity is transmitted across
these lines and substations and is then distributed to customers through 141,036
circuit miles of distribution lines and substations with a capacity of 27,137
MVA. In 2008, the Utility delivered 88,127 GWh to its customers; including 6,191
GWh delivered to direct access customers. The Utility is interconnected with
electric power systems in the WECC, which includes 14 western states, Alberta
and British Columbia, Canada, and parts of Mexico.
During
1998, in connection with electric industry restructuring, the California
investor-owned electric utilities relinquished control, but not ownership, of
their transmission facilities to the CAISO. The Utility entered into a
Transmission Control Agreement with the CAISO and other participating
transmission owners (including Southern California Edison Company, San Diego
Gas & Electric Company, and several California municipal utilities)
under which the transmission owners have assigned operational control of their
electric transmission systems to the CAISO. The Utility is required to give the
CAISO two years notice and receive approval from the FERC if it wishes to
withdraw from the Transmission Control Agreement and take back operational
control of its transmission facilities.
The
CAISO, which is regulated by the FERC, controls the operation of the
transmission system and provides open access transmission service on a
nondiscriminatory basis. The CAISO also is responsible for ensuring that the
reliability of the transmission system is maintained. The Utility
acts as a scheduling coordinator to schedule electricity deliveries to the
transmission grid. The Utility also acts as a scheduling coordinator to deliver
electricity produced by several governmental entities to the transmission grid
under contracts the Utility entered into with these entities before the CAISO
commenced operation in 1998. In addition, under the mandatory
reliability standards implemented following EPAct, all users, owners, and
operators of the transmission system, including the Utility, are also
responsible for maintaining reliability through compliance with the reliability
standards. See the discussion of reliability standards above under
“The Utility’s Regulatory Environment-Federal Energy Regulation.”
The
Utility expects to undertake various additional transmission projects over the
next few years to upgrade and expand the Utility’s transmission system in order
to accommodate system load growth, to secure access to renewable generation
resources, to replace aging or obsolete equipment, to maintain system
reliability, and to
reduce reliance on generation provided under reliability must run (“RMR”)
agreements with the CAISO. (RMR agreements require various power
plant owners, including the Utility, to keep designated units in certain power
plants, known as RMR units, available to generate electricity upon the CAISO's
demand when the generation from those RMR units is needed for local transmission
system reliability.) Potential transmission projects include a 500-kV
transmission line to improve access to new renewable generation resources and to
reduce RMR generation contracts in the Fresno, California area (referred to as
the “Central California Clean Energy Transmission Project”) and a high voltage
transmission line between Northern California and British Columbia, Canada to
access renewable generation resources in British Columbia. In addition,
the Utility is currently working with several stakeholders in the western United
States to assess the feasibility of new large-scale electric transmission
expansion projects to address regional electricity needs over the long term.
The
Utility's electricity distribution network extends through 47 of California's 58
counties, comprising most of northern and central California. The Utility's
network consists of 141,036 circuit miles of distribution lines (of which
approximately 19% are underground and approximately 81% are overhead). There are
92 transmission substations and 48 transmission-switching stations. A
transmission substation is a fenced facility where voltage is transformed from
one transmission voltage level to another. The Utility’s network includes 607
distribution substations and 110 low-voltage distribution substations. The 49
combined transmission and distribution substations have both transmission and
distribution transformers.
The
Utility's distribution network interconnects to the Utility's electricity
transmission system at 1,106 points. This interconnection between the Utility's
distribution network and the transmission system typically occurs at
distribution substations where transformers and switching equipment reduce the
high-voltage transmission levels at which the electricity transmission system
transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging
from 44 kV to 2.4 kV, suitable for distribution to the Utility's customers. The
distribution substations serve as the central hubs of the Utility's electricity
distribution network and consist of transformers, voltage regulation equipment,
protective devices and structural equipment. Emanating from each substation are
primary and secondary distribution lines connected to local transformers and
switching equipment that link distribution lines and provide delivery to
end-users. In some cases, the Utility sells electricity from its distribution
lines or other facilities to entities, such as municipal and other utilities,
that then resell the electricity.
During
2006, the Utility began the installation of an advanced metering infrastructure,
known as the SmartMeter™ program, for virtually all of the Utility's electric
and gas customers. These meters enable the Utility to measure usage
on an hourly basis for electricity and on a daily basis for natural gas, which
can allow for demand-response rates to encourage customers to reduce energy
consumption during peak demand periods, thus reducing peak period procurement
costs. Advanced meters can record usage in time intervals and be read
remotely. The Utility expects to complete the installation of the
network infrastructure and advanced meters throughout its service territory by
the end of 2011. The Utility also has requested the CPUC to approve
the Utility’s proposal to upgrade elements of the Utility’s SmartMeter™
program. The Utility seeks approval to install solid-state electric
meters and associated devices that would offer an expanded range of service
features for customers and increased operational efficiencies for the
Utility. These upgraded meters and associated devices would provide
additional energy conservation and demand response options for electric
customers. In addition, the solid-state electric meters are designed
to facilitate the Utility’s ability to incorporate future advanced metering
technology innovations in a timely and cost-effective manner. (For
more information about the advanced metering infrastructure, see the section of
MD&A entitled “Capital Expenditures ─ SmartMeter™ Program” in the 2008
Annual Report.)
2008 Electricity
Deliveries. The following table
shows the percentage of the Utility's total 2008 electricity deliveries
represented by each of its major customer classes:
Total
2008 Electricity Delivered: 88,127 GWh
|
Agricultural
and Other Customers
|
7%
|
|
Industrial
Customers
|
18%
|
|
Residential
Customers
|
36%
|
|
Commercial
Customers
|
39%
|
The
following table shows certain of the Utility's operating statistics from 2004 to
2008 for electricity sold or delivered, including the classification of sales
and revenues by type of service.
|
2008
|
2007
|
2006
|
2005
|
2004
|
||||||||||||||||
|
Customers
(average for the year):
|
||||||||||||||||||||
|
Residential
|
4,488,884 | 4,464,483 | 4,417,638 | 4,353,458 | 4,366,897 | |||||||||||||||
|
Commercial
|
527,045 | 521,732 | 515,297 | 509,786 | 509,501 | |||||||||||||||
|
Industrial
|
1,265 | 1,261 | 1,212 | 1,271 | 1,339 | |||||||||||||||
|
Agricultural
|
81,757 | 80,366 | 79,006 | 78,876 | 80,276 | |||||||||||||||
|
Public
street and highway lighting
|
30,474 | 29,643 | 28,799 | 28,021 | 27,176 | |||||||||||||||
|
Other
electric utilities
|
2 | 2 | 4 | 4 | 3 | |||||||||||||||
|
Total
(1)
|
5,129,427 | 5,097,487 | 5,041,956 | 4,971,416 | 4,985,192 | |||||||||||||||
|
Deliveries
(in GWh):(2)
|
||||||||||||||||||||
|
Residential
|
31,454 | 30,796 | 31,014 | 29,752 | 29,453 | |||||||||||||||
|
Commercial
|
34,053 | 33,986 | 33,492 | 32,375 | 32,268 | |||||||||||||||
|
Industrial
|
16,148 | 15,159 | 15,166 | 14,932 | 14,796 | |||||||||||||||
|
Agricultural
|
5,594 | 5,402 | 3,839 | 3,742 | 4,300 | |||||||||||||||
|
Public
street and highway lighting
|
877 | 833 | 785 | 792 | 2,091 | |||||||||||||||
|
Other
electric utilities
|
1 | 3 | 14 | 33 | 28 | |||||||||||||||
|
Subtotal
|
88,127 | 86,179 | 84,310 | 81,626 | 82,936 | |||||||||||||||
|
California
Department of Water Resources (DWR)
|
(13,344 | ) | (21,193 | ) | (19,585 | ) | (20,476 | ) | (19,938 | ) | ||||||||||
|
Total
non-DWR electricity
|
74,783 | 64,986 | 64,725 | 61,150 | 62,998 | |||||||||||||||
|
Revenues
(in millions):
|
||||||||||||||||||||
|
Residential
|
$ | 4,656 | $ | 4,580 | $ | 4,491 | $ | 3,856 | $ | 3,718 | ||||||||||
|
Commercial
|
4,413 | 4,484 | 4,414 | 4,114 | 4,179 | |||||||||||||||
|
Industrial
|
1,400 | 1,252 | 1,293 | 1,232 | 1,204 | |||||||||||||||
|
Agricultural
|
727 | 664 | 483 | 446 | 491 | |||||||||||||||
|
Public
street and highway lighting
|
75 | 78 | 72 | 66 | 71 | |||||||||||||||
|
Other
electric utilities
|
126 | 85 | 59 | 4 | 22 | |||||||||||||||
|
Subtotal
|
11,397 | 11,143 | 10,812 | 9,718 | 9,685 | |||||||||||||||
|
DWR
|
(1,325 | ) | (2,229 | ) | (2,119 | ) | (1,699 | ) | (1,933 | ) | ||||||||||
|
Direct
access credits
|
— | — | — | — | — | |||||||||||||||
|
Miscellaneous
|
336 | 215 | 261 | 235 | (248 | ) | ||||||||||||||
|
Regulatory
balancing accounts
|
330 | 352 | (202 | ) | (327 | ) | 363 | |||||||||||||
|
Total
electricity operating revenues
|
$ | 10,738 | $ | 9,481 | $ | 8,752 | $ | 7,927 | $ | 7,867 | ||||||||||
|
Other
Data:
|
||||||||||||||||||||
|
Average
annual residential usage (kWh)
|
7,007 | 6,898 | 7,020 | 6,834 | 6,744 | |||||||||||||||
|
Average
billed revenues (cents per kWh):
|
||||||||||||||||||||
|
Residential
|
14.80 | 14.87 | 14.48 | 12.96 | 12.62 | |||||||||||||||
|
Commercial
|
12.96 | 13.19 | 13.18 | 12.71 | 12.95 | |||||||||||||||
|
Industrial
|
8.67 | 8.26 | 8.53 | 8.25 | 8.14 | |||||||||||||||
|
Agricultural
|
13.00 | 12.29 | 12.58 | 11.92 | 11.41 | |||||||||||||||
|
Net
plant investment per customer
|
$ | 3,994 | $ | 3,418 | $ | 3,148 | $ | 2,966 | $ | 2,790 | ||||||||||
|
(1)
|
Starting
in 2005, the Utility’s methodology used to count customers changed from
the number of billings to the number of active service
agreements.
|
|
(2)
|
These
amounts include electricity provided to direct access customers who
procure their own supplies of
electricity.
|
The
Utility owns and operates an integrated natural gas transportation, storage and
distribution system in California that extends throughout all or a part of 40 of
California's 58 counties and includes most of northern and central
California. In 2008, the Utility served approximately
4.3 million natural gas distribution customers. The total volume of natural
gas throughput during 2008 was approximately 839 Bcf.
As of
December 31, 2008, the Utility's natural gas system consisted of 42,017
miles of distribution pipelines, 6,418 miles of backbone and local transmission
pipelines, and three storage facilities. The Utility’s backbone transmission
system, composed primarily of Lines 300, 400 and 401, is used to transport gas
from the Utility’s interconnection with interstate pipelines, other local
distribution companies, and California gas fields to the Utility’s local
transmission and distribution systems. The Utility's Line 300, which
interconnects with the U.S. Southwest and Rocky Mountain pipeline systems owned
by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company,
Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a
receipt capacity of approximately 1.07 Bcf per day. The Utility's
Line 400/401 interconnects with the natural gas transportation pipeline of Gas
Transmission Northwest Corporation at the California-Oregon
border. This line has a receipt capacity at the border of
approximately 2.02 Bcf per day. Through interconnections with other
interstate pipelines, the Utility can receive natural gas from all the major
natural gas basins in western North America, including basins in western Canada,
the Rocky Mountains and the southwestern United States. The Utility
also is supplied by natural gas fields in California.
The
Utility also owns and operates three underground natural gas storage fields
connected to the Utility's transmission and storage system. These storage fields
have a combined firm capacity of approximately 47 Bcf. In addition, two
independent storage operators are interconnected to the Utility's northern
California transportation system.
The
Utility, along with Gill Ranch Storage, LLC, a subsidiary of Northwest Natural
Gas Company, is developing an underground natural gas storage facility near
Fresno, California. It is expected that construction of the initial phase, to
consist of approximately 20 Bcf of total capacity, will be completed in
2010. The Utility has a 25% interest in the initial phase of the
proposed storage facility. Development of the storage facility is
subject to CPUC approval, including the CPUC’s environmental review as required
by the California Environmental Quality Act. The Utility expects the
CPUC to issue a final decision in late 2009.
The CPUC
divides the Utility's natural gas customers into two categories: core and
non-core customers. This classification is based largely on a customer's annual
natural gas usage. The core customer class is comprised mainly of residential
and smaller commercial natural gas customers. The non-core customer class is
comprised of industrial, larger commercial and electric generation natural gas
customers. In 2008, core customers represented more than 99% of the Utility's
total customers and 37% of its total natural
gas
deliveries, while non-core customers comprised less than 1% of the Utility's
total customers and 63% of its total natural gas deliveries.
The
Utility provides natural gas transportation services to all core and non-core
customers connected to the Utility's system in its service territory. Core
customers can purchase natural gas procurement service (i.e., natural gas supply)
from either the Utility or alternate energy service providers. When the Utility
provides both transportation and procurement services, the Utility refers to the
combined service as bundled natural gas service. Currently, over 99% of core
customers, representing over 96% of core market demand, receive bundled natural
gas service from the Utility.
The
Utility does not provide procurement service to non-core customers. However,
some non-core customers are permitted to elect core service and receive Utility
procurement service through that avenue. Electricity generators, QF
cogenerators, enhanced oil recovery customers, refiners, and other large
non-core customers may not elect core service, and smaller non-core customers
must contract for a minimum five-year term if they elect core service. These
restrictions were put in place because large increases in demand for the
Utility's procurement service caused by significant transfers of non-core
customers to core service would raise prices for all other core procurement
customers and obligate the Utility to reinforce its pipeline system to provide
core service reliability on a short-term basis to serve this new
load.
The
Utility offers backbone gas transmission, gas delivery (local transmission and
distribution), and gas storage services as separate and distinct services to its
non-core customers. Access to the Utility's backbone gas transmission system is
available for all natural gas marketers and shippers, as well as non-core
customers.
The
Utility has regulatory balancing accounts for core customers designed to ensure
that the Utility's results of operations over the long term are not affected by
weather variations, conservation or changes in their consumption levels. The
Utility's results of operations can, however, be affected by non-core
consumption levels because there are fewer regulatory balancing accounts related
to non-core customers. Approximately 97% of the Utility's natural gas
distribution base revenues are recovered from core customers and 3% are
recovered from non-core customers.
The
California Gas Report is prepared by the California electric and natural gas
utilities to present an outlook for natural gas requirements and supplies for
California over a long-term planning horizon. It is prepared in even-numbered
years followed by a supplemental report in odd-numbered years. The 2008
California Gas Report forecasts average annual growth in the Utility's natural
gas deliveries (for core customers and non-core transportation) of approximately
0.2% for the years 2008 through 2030. The natural gas requirements forecast is
subject to many uncertainties, and there are many factors that can influence the
demand for natural gas, including weather conditions, level of economic
activity, conservation, price, and the number and location of electricity
generation facilities.
Total
2008 Natural Gas Deliveries: 839 Bcf
|
Residential
Customers
|
26%
|
|
Transport-only
Customers (non-core)
|
63%
|
|
Commercial
Customers
|
11%
|
The
following table shows the Utility's operating statistics from 2004 through 2008
(excluding subsidiaries) for natural gas, including the classification of sales
and revenues by type of service:
|
2008
|
2007
|
2006
|
2005
|
2004
|
||||||||||||||||
|
Customers
(average for the year):
|
||||||||||||||||||||
|
Residential
|
4,043,616 | 4,030,499 | 3,989,331 | 3,929,117 | 3,812,914 | |||||||||||||||
|
Commercial
|
224,617 | 223,330 | 220,024 | 216,749 | 215,547 | |||||||||||||||
|
Industrial
|
926 | 958 | 988 | 962 | 2,178 | |||||||||||||||
|
Other
gas utilities
|
6 | 6 | 6 | 6 | 6 | |||||||||||||||
|
Total
|
4,269,165 | 4,254,793 | 4,210,349 | 4,146,834 | 4,030,645 | |||||||||||||||
|
Gas
supply (MMcf):
|
||||||||||||||||||||
|
Purchased
from suppliers in:
|
||||||||||||||||||||
|
Canada
|
189,608 | 199,870 | 202,274 | 204,884 | 205,180 | |||||||||||||||
|
California
|
(53,126 | ) | (23,065 | ) | (13,401 | ) | (18,951 | ) | (9,108 | ) | ||||||||||
|
Other
states
|
123,833 | 101,271 | 103,658 | 103,237 | 103,801 | |||||||||||||||
|
Total
purchased
|
260,315 | 278,076 | 292,531 | 289,170 | 299,873 | |||||||||||||||
|
Net
(to storage) from storage
|
560 | (1,120 | ) | 4,359 | (3,659 | ) | (532 | ) | ||||||||||||
|
Total
|
260,875 | 276,956 | 296,890 | 285,511 | 299,341 | |||||||||||||||
|
Utility
use, losses, etc. (1)
|
1,758 | (12,760 | ) | (27,610 | ) | (14,312 | ) | (19,287 | ) | |||||||||||
|
Net
gas for sales
|
262,633 | 264,196 | 269,280 | 271,199 | 280,054 | |||||||||||||||
|
Bundled
gas sales (MMcf):
|
||||||||||||||||||||
|
Residential
|
198,699 | 196,903 | 196,092 | 194,108 | 201,601 | |||||||||||||||
|
Commercial
|
63,934 | 67,293 | 73,178 | 77,056 | 78,080 | |||||||||||||||
|
Industrial
|
10 | 35 | 373 | |||||||||||||||||
|
Other
gas utilities
|
— | — | — | — | — | |||||||||||||||
|
Total
|
262,633 | 264,196 | 269,280 | 271,199 | 280,054 | |||||||||||||||
|
Transportation
only (MMcf):
|
569,535 | 605,259 | 559,270 | 572,869 | 597,706 | |||||||||||||||
|
Revenues
(in millions):
|
||||||||||||||||||||
|
Bundled
gas sales:
|
||||||||||||||||||||
|
Residential
|
$ | 2,574 | $ | 2,378 | $ | 2,452 | $ | 2,336 | $ | 1,944 | ||||||||||
|
Commercial
|
792 | 766 | 859 | 885 | 712 | |||||||||||||||
|
Industrial
|
||||||||||||||||||||
|
Other
gas utilities
|
||||||||||||||||||||
|
Miscellaneous
|
(30 | ) | 87 | 121 | (22 | ) | (29 | ) | ||||||||||||
|
Regulatory
balancing accounts
|
221 | 186 | 40 | 340 | 316 | |||||||||||||||
|
Bundled
gas revenues
|
3,557 | 3,417 | 3,472 | 3,539 | 2,943 | |||||||||||||||
|
Transportation
service only revenue
|
333 | 340 | 315 | 237 | 270 | |||||||||||||||
|
Operating
revenues
|
$ | 3,890 | $ | 3,757 | $ | 3,787 | $ | 3,776 | $ | 3,213 | ||||||||||
|
Selected
Statistics:
|
||||||||||||||||||||
|
Average
annual residential usage (Mcf)
|
49 | 49 | 49 | 49 | 53 | |||||||||||||||
|
Average
billed bundled gas sales revenues per Mcf:
|
||||||||||||||||||||
|
Residential
|
$ | 12.95 | $ | 12.07 | $ | 12.50 | $ | 12.04 | $ | 9.64 | ||||||||||
|
Commercial
|
12.38 | 11.38 | 11.73 | 11.48 | 9.12 | |||||||||||||||
|
Industrial
|
1.03 | 0.61 | (0.56 | ) | ||||||||||||||||
|
Average
billed transportation only revenue per Mcf
|
0.59 | 0.56 | 0.56 | 0.42 | 0.45 | |||||||||||||||
|
Net
plant investment per customer
|
$ | 1,344 | $ | 1,375 | $ | 1,304 | $ | 1,262 | $ | 1,266 | ||||||||||
|
(1)
|
Includes
fuel for the Utility's fossil fuel-fired generation
plants.
|
The
Utility purchases natural gas to serve the Utility's core customers directly
from producers and marketers in both Canada and the United States. The contract
lengths and natural gas sources of the Utility's portfolio of natural gas
purchase contracts have fluctuated generally based on market
conditions. During 2008, the Utility purchased approximately 260,315
MMcf of natural gas (net of the sale of excess supply) from suppliers.
Consistent with existing CPUC policy directives, substantially all this natural
gas was purchased under contracts with a term of one year or less. The Utility's
largest individual supplier represented approximately 10% of the total natural
gas volume the Utility purchased during 2008.
The
following table shows the total volume and the average price of natural gas in
dollars per MMcf of the Utility's natural gas purchases by region during each of
the last five years. The average prices for Canadian and U.S. Southwest gas
shown below include the commodity natural gas prices, pipeline demand or
reservation charges, transportation charges and other pipeline assessments. The
volumes purchased are shown net of sales of excess supplies of
gas. In 2008, the sale of excess supplies to parties located in
California exceeded purchases from parties located in California.
|
2008
|
2007
|
2006
|
2005
|
2004
|
|||||||||||
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
||||||
|
Canada
|
189,608
|
$8.29
|
199,870
|
$6.63
|
202,274
|
$6.27
|
204,884
|
$7.12
|
205,180
|
$5.37
|
|||||
|
California
(1)
|
(53,126)
|
$9.24
|
(23,065)
|
$6.77
|
(13,401)
|
$7.04
|
(18,951)
|
$7.70
|
(9,108)
|
$4.89
|
|||||
|
Other
states (substantially all U.S. southwest)
|
123,833
|
$7.05
|
101,271
|
$6.30
|
103,658
|
$6.51
|
103,237
|
$7.10
|
103,801
|
$5.44
|
|||||
|
Total/weighted
average
|
260,315
|
$7.51
|
278,076
|
$6.50
|
292,531
|
$6.32
|
289,170
|
$7.07
|
299,873
|
$5.41
|
|||||
(1)
California purchases include supplies from various California producers and
supplies transported into California by others.
The
Utility's gas gathering system collects natural gas from third-party wells in
California. During 2008, approximately 6% of the gas transported on the
Utility's system came from various California producers, with the balance coming
from supplies transported into California by others. The natural gas well
production is processed by producers to remove various impurities from the
natural gas stream and the Utility then odorizes the natural gas so that it may
be detected in the event of a leak. The facilities include approximately 110.3
miles of gas gathering pipelines. The Utility receives gas well production at
approximately 188 metering facilities. The Utility’s gas gathering system is
geographically dispersed and is located in 8 California counties. Approximately
138 MMcf per day of natural gas produced in northern California was delivered
into the Utility's gas gathering system during 2008.
In 2008,
approximately 52% of the gas transported on the Utility's system came from
western Canada. The Utility has a number of arrangements with interstate and
Canadian third-party transportation service providers to serve core customers'
service demands. The Utility has firm transportation agreements for delivery of
natural gas from western Canada to the United States- Canadian border with
TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe
Lines Ltd., B.C. System. These companies' pipeline systems
connect at the border to the pipeline system owned by TransCanada’s Gas
Transmission Northwest Corporation (“GTN”), which provides natural gas
transportation services to a point of interconnection with the Utility's natural
gas transportation system on the Oregon-California border near Malin, Oregon.
The Utility, the largest firm shipper on GTN’s pipeline, has a firm
transportation agreement with GTN for these services. As described
below, as part of the FERC-approved all-party settlement of GTN’s most recent
general rate case, the Utility’s contract with GTN will be replaced beginning
November 1, 2009 by three smaller contracts totaling the same amount with
staggered terms.
During
2008, approximately 42% of the gas transported on the Utility's system came from
the western United States, excluding California. The Utility has firm
transportation agreements with Transwestern Pipeline Company and El Paso Natural
Gas Company to transport this natural gas from supply points in this region to
interconnection points with the Utility's natural gas transportation system in
the area of California near Topock, Arizona.
The
following table shows certain information about the Utility's firm natural gas
transportation agreements in effect during 2008, including the contract
quantities, contract durations and associated demand charges, net of sales of
excess supplies, for capacity reservations. These agreements require the Utility
to pay fixed demand charges for reserving firm capacity on the pipelines. The
total demand charges may change periodically as a result of changes in regulated
tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas
Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C.
System, and by the FERC in all other cases. The Utility may, upon
prior notice and with the CPUC’s approval, extend each of these natural gas
transportation agreements. On the FERC-regulated pipelines, the Utility has
either a right of first refusal or evergreen rights allowing it to renew natural
gas transportation agreements at the end of their terms. If another prospective
shipper also wants the capacity, the Utility would be required to match the
competing bid with respect to both price and term.
|
Pipeline
|
Expiration
Date
|
Quantity
MDth
per day
|
Demand
Charges
for
the Year Ended
December 31,
2008
(In
millions)
|
||||
|
TransCanada
NOVA Gas Transmission, Ltd.
|
10/31/2011
|
(1)
|
619
|
$29.5
|
|||
|
TransCanada
Foothills Pipe Lines Ltd., B.C. System
|
10/31/2011
|
611
|
15.7
|
||||
|
Gas
Transmission Northwest Corporation
|
10/31/2009
|
610
|
89.6
|
||||
|
Transwestern
Pipeline Company (1)
|
Various
|
180
|
15.9
|
||||
|
El
Paso Natural Gas Company (2)
|
Various
|
267
|
17.2
|
|
(1)
|
As
of December 31, 2008, the Utility had two active contracts with
Transwestern Pipeline Company with expiration dates ranging from February
28, 2009 to March 31, 2010.
|
|
(2)
|
As of December 31, 2008, the
Utility had three active contracts with El Paso Natural Gas Company with
expiration dates ranging from February 28, 2009 to June 30,
2012.
|
As
required by the all-party settlement of GTN’s most recent general rate case
approved by the FERC on January 7, 2008, the Utility has entered into three
smaller contracts with GTN with terms that begin on November 1, 2009 and
terminate on various dates unless renewed, as follows:
|
Expiration
Date
|
Quantity
MDth
per day
|
Estimated
Demand Charges
2009-2011 (In
millions)
|
||||
|
10/31/2011
|
250
|
$58
|
||||
|
10/31/2016
|
280
|
71
|
||||
|
10/31/2020
|
80
|
20
|
Also, as
part of the same settlement, the Utility has entered into a separate contract
with GTN for firm transportation service to support the Utility’s need for
natural gas for electric power plant fuel. This new contract is for a quantity
of 50 MDth/d for a 59-month term, July 1, 2009, through May 31,
2014.
In
addition, in December 2008, the CPUC approved an agreement between the Utility
and El Paso Corporation for the Utility to subscribe for 375 MDth per day of
firm service rights on El Paso Corporation’s proposed 680-mile, 42-inch natural
gas transmission pipeline (the “Ruby Pipeline”) that would begin at the Opal Hub
in Wyoming and terminate at the Malin, Oregon, interconnect, near California’s
northern border. The Ruby Pipeline is expected to have an initial
capacity of 1.2 Bcf per day and be expandable to 2 Bcf per day. The
proposed Ruby Pipeline would connect Rocky Mountain natural gas producers with
northern California, Nevada, and the Pacific Northwest to provide natural gas
users with competitively priced natural gas. Subject to obtaining the
required regulatory and other approvals and necessary customer commitments, the
Ruby Pipeline is anticipated to be in service in the first quarter of
2011.
Environmental
Matters
The
following discussion includes certain forward-looking information relating to
estimated expenditures for environmental protection measures and the possible
future impact of environmental compliance measures. The information below
reflects current estimates, which are periodically evaluated and revised. Future
estimates and actual results may differ materially from those indicated below.
These estimates are subject to a number of assumptions and uncertainties,
including changing laws and regulations, the ultimate outcome of complex factual
investigations, evolving technologies, selection of compliance alternatives, the
nature and extent of required remediation, the extent of the facility owner's
responsibility, and the availability of recoveries or contributions from third
parties.
The
Utility is subject to a number of federal, state and local laws and requirements
relating to the protection of the environment and the safety and health of the
Utility's personnel and the public. These laws and requirements relate to a
broad range of activities, including:
|
·
|
the
discharge of pollutants into air, water and
soil;
|
|
·
|
the
identification, generation, storage, handling, transportation, treatment,
disposal, record keeping, labeling, reporting, remediation and emergency
response in connection with hazardous and radioactive substances;
and
|
|
·
|
environmental
impacts of land use, including endangered species and habitat
protection.
|
The
penalties for violation of these laws and requirements can be severe, and may
include significant fines, damages and criminal or civil sanctions. These laws
and requirements also may require the Utility, under certain circumstances, to
interrupt or curtail operations. To comply with these laws and requirements, the
Utility may need to spend substantial amounts from time to time to construct,
acquire, modify or replace equipment, acquire permits and/or marketable
allowances or other emission credits for facility operations and clean-up or
decommission waste disposal areas at the Utility's current or former facilities
and at third-party sites where the Utility’s wastes may have been
disposed.
Generally,
the Utility has recovered the costs of complying with environmental laws and
regulations in the Utility's rates, subject to reasonableness
review. Environmental costs associated with the clean-up of sites
that contain hazardous substances are subject to a special ratemaking mechanism
under which the Utility is authorized to recover hazardous waste remediation
costs for environmental claims from customers (e.g., for costs of cleaning
up the Utility's facilities and sites where the Utility’s hazardous substances
have been sent). This mechanism allows the Utility to include 90% of
eligible hazardous waste remediation costs in the Utility's rates without a
reasonableness review. (One exception to this is the Hinkley natural
gas compressor site discussed below. The cost of environmental
remediation associated with this site is not recoverable from
customers.) Ten percent of any net insurance recoveries associated
with hazardous waste remediation sites are assigned to the Utility's
customers. The balances of any insurance recoveries (90%) are
retained by the Utility until it has been reimbursed for the 10% share of
clean-up costs not included in rates. Any insurance recoveries above
full cost reimbursement levels are allocated 60% to customers and 40% to the
Utility. Finally, 10% of any
recoveries
from the Utility's claims against third parties associated with hazardous waste
remediation sites are retained by the Utility, with the remainder, 90% of any
such recoveries, assigned to the Utility's customers.
Hazardous
waste remediation costs are rising and are likely to be significant into the
foreseeable future. Based on the Utility's past experience, it
believes that it can recover most of the future costs that it may incur to
remediate hazardous waste through rates and insurance recoveries. The
Utility cannot provide assurance, however, that these costs will not be
material, or that the Utility will be able to recover its costs in the
future.
For more
information about environmental remediation liabilities, see Note 17 of the
“Notes to the Consolidated Financial Statements” in the 2008 Annual
Report.
The
Utility's electricity generation plants, natural gas pipeline operations, fleet
and fuel storage tanks are subject to numerous air pollution control laws,
including the federal Clean Air Act, as well as state and local
statutes. These laws and regulations cover, among other pollutants,
those contributing to the formation of ground-level ozone, carbon monoxide,
sulfur dioxide, nitrogen oxide and particulate matter. In addition,
various laws and regulations addressing climate change and greenhouse gas
emissions (“GHG”) are being considered or implemented at the federal and state
levels, as discussed below. Fossil fuel-fired plants and gas
compressor stations used in the Utility's pipeline operations are sources of air
pollutants and, therefore, are subject to substantial regulation and enforcement
oversight by the applicable governmental agencies. In addition, greenhouse gas
emissions from natural gas consumed by the Utility’s customers would be subject
to regulation by the California Air Resources Board (“CARB”), as discussed
below.
At the federal level, several
legislative initiatives have been introduced recently in Congress aimed at
addressing climate change through imposition of nation-wide regulatory limits on
the emissions of GHGs. No such legislation has yet been enacted by
Congress, but extensive hearings and discussion are expected in the coming
year. At the state level, California enacted Assembly Bill 32 (“AB
32”), the California Global Warming Solutions Act of 2006, to address climate
change. AB 32 requires the gradual reduction of GHG emissions in
California to 1990 levels by 2020 on a schedule beginning in 2012. AB
32 also authorizes the CARB to monitor and enforce compliance with the GHG
reduction program and to consider implementing market-based mechanisms,
including trading of GHG emissions allowances. In 2007, the CARB adopted a
state-wide GHG 1990 emissions baseline of 427 million metric tons of carbon
dioxide (or its equivalent). This 1990 baseline serves as the 2020
emissions reduction target for the state of California. (The CARB has
not yet determined specific GHG reduction limits applicable to the utility
sector or individual utilities within the utility sector.) In 2007,
the CARB also adopted a regulation that requires the California investor-owned
utilities and other GHG emitters to file verified reports of their annual GHG
emissions. On December 12, 2008, the CARB adopted a scoping plan that
contains recommendations for achieving the maximum technologically feasible and
cost-effective GHG reductions to meet the 2020 reduction target, including
increased reliance on renewable resources and energy efficiency and the
development of a multi-sector cap-and-trade program. The CARB is
required to adopt regulations to implement the scoping plan not later than
January 1, 2011 to become effective on January 1, 2012.
California
Senate Bill 1368, enacted in 2006, prohibits any load-serving entity in
California, including investor-owned electric utilities, from entering into a
long-term financial commitment for baseload electricity generation unless the
generation complies with a GHG emission performance standard. As
required by Senate Bill 1368, on January 25, 2007, the CPUC adopted an interim
GHG emissions performance standard of 1,100 pounds of carbon dioxide per MWh
that applies to new commitments for baseload electricity procured under
contracts with a term of five years or longer or generated by the
Utility. After a state-wide GHG emissions limit is established and is
in operation, in accordance with AB 32, the CPUC will re-evaluate its interim
GHG emissions performance standard and determine whether to continue, modify or
rescind it.
These
California laws, as well as current federal and other state regulatory
initiatives relating to emissions of carbon dioxide and other GHGs, particulates
and other pollutants, could cause the Utility's compliance costs and capital
expenditures to increase. Although the Utility’s existing and forecast emissions
of GHGs are relatively low compared to average emissions by other electric
utilities and generators elsewhere in the country, these laws could require the
Utility to replace equipment, install additional pollution controls, purchase
various emission allowances at as yet undefined prices, or curtail
operations. The Utility expects that it will recover the associated
costs and capital expenditures in rates consistent with the recovery of other
reasonable costs of complying with environmental laws and
regulations.
The
Utility's Diablo Canyon power plant employs a “once-through” cooling water
system that is regulated under a Clean Water Act National Pollutant Discharge
Elimination System (“NPDES”) permit issued by the Central Coast Regional Water
Quality Control Board (“Central Coast Board”). This permit allows the Diablo
Canyon power plant to discharge the cooling water at a temperature no more than
22 degrees above the temperature of the ambient receiving water, and requires
that the beneficial uses of the
water be
protected. The beneficial uses of water in this region include industrial water
supply, marine and wildlife habitat, shellfish harvesting, and preservation of
rare and endangered species. In January 2000, the Central Coast
Board issued a proposed draft cease and desist order alleging that, although the
temperature limit has never been exceeded, the Diablo Canyon power plant's
discharge was not protective of beneficial uses. For more
information, see the discussion below in “Item 3—Legal Proceedings—Diablo Canyon
Power Plant.”
There is
continuing uncertainty about the status of state and federal regulations issued
under Section 316(b) of the Clean Water Act, which require that cooling water
intake structures at electric power plants reflect the best technology available
to minimize adverse environmental impacts. In July 2004, the U.S.
Environmental Protection Agency (“EPA”) issued regulations to implement Section
316(b) intended to reduce impacts to aquatic organisms by establishing a set of
performance standards for cooling water intake structures. These
regulations provided each facility with a number of compliance options and
permitted site-specific variances based on a cost-benefit
analysis. The EPA regulations also allowed the use of environmental
mitigation or restoration to meet compliance requirements in certain cases. In response to the
EPA regulations, the California State Water Resources Control Board (“Water
Board”) issued a proposed policy to address once-through cooling. The
Water Board’s current proposal would require the installation of cooling towers
at nuclear facilities by January 1, 2021, unless the installation of cooling
towers would conflict with a nuclear safety requirement. Further, in
January 2009, legislation proposed in the California Senate would ban
once-through cooling, effective January 2015.
Various
parties separately challenged the EPA's regulations and in January 2007, the
U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a
decision holding that environmental restoration cannot be used as a compliance
option and that site-specific compliance variances based on a cost-benefit test
could not be used. The Second Circuit remanded significant provisions of
the regulations to the EPA for reconsideration and in July 2007, the EPA
suspended its regulations. The U.S. Supreme Court is expected to
issue a decision by mid-2009 regarding the cost-benefit test. Depending
on the form of the final regulations that may ultimately be adopted by the EPA
or the Water Board, the Utility may incur significant capital expense to comply
with the final regulations, which the Utility would seek to recover through
rates. If the final regulations adopted by the EPA, the Water Board, or
the California Legislature, require the installation of cooling towers at Diablo
Canyon, and if installation of such cooling towers is not technically or
economically feasible, the Utility may be forced to cease operations at Diablo
Canyon and may incur a material charge.
Many of
the Utility's facilities and operations are located in, or pass through, areas
that are designated as critical habitats for federal or state-listed endangered,
threatened or sensitive species. The Utility may be required to incur additional
costs or be subjected to additional restrictions on operations if additional
threatened or endangered species are listed or additional critical habitats are
designated at or near the Utility's facilities or operations. The Utility is
seeking to secure “habitat conservation plans” to ensure long-term compliance
with state and federal endangered species acts. The Utility expects that it will
be able to recover costs of complying with state and federal endangered species
acts through rates.
The
Utility's facilities are subject to the requirements issued by the EPA under the
Resource Conservation and Recovery Act (“RCRA”) and the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended
(“CERCLA”), as well as other state hazardous waste laws and other environmental
requirements. CERCLA and similar state laws impose liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons that contributed to the release of a hazardous substance into the
environment. These persons include the owner or operator of the site where the
release occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at the site, and in some cases corporate successors
to the operators or arrangers. Under CERCLA, these persons may be subject to
joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment, damages to natural
resources and the costs of required health studies. In the ordinary
course of the Utility's operations, the Utility generates waste that falls
within CERCLA's definition of hazardous substances and, as a result, has been
and may be jointly and severally liable under CERCLA for all or part of the
costs required to clean up sites at which these hazardous substances have been
released into the environment.
The
Utility assesses, on an ongoing basis, measures that may be necessary to comply
with federal, state and local laws and regulations related to hazardous
materials and hazardous waste compliance and remediation activities. The Utility
has a comprehensive program to comply with hazardous waste storage, handling and
disposal requirements issued by the EPA under RCRA and CERCLA, state hazardous
waste laws and other environmental requirements.
The
Utility has been, and may be, required to pay for environmental remediation at
sites where the Utility has been, or may be, a potentially responsible party
under CERCLA and similar state environmental laws. These sites include former
manufactured gas plant sites, power plant sites, gas gathering sites, compressor
stations and sites where the Utility stores, recycles and disposes of
potentially hazardous materials. Under federal and California laws, the Utility
may be responsible for remediation of hazardous
substances
even if it did not deposit those substances on the site.
Operations
at the Utility's current and former generation facilities may have resulted in
contaminated soil or groundwater. Although the Utility sold most of its
geothermal and fossil fuel-fired plants, in many cases the Utility retained
pre-closing environmental liability under various environmental laws. The
Utility currently is investigating or remediating several such sites with the
oversight of various governmental agencies. Additionally, the
Utility’s Hunters Point power plant in San Francisco closed in May 2006 and is
in the decommissioning process. Remedial investigations are
substantially complete, and the Utility anticipates that the California
Department of Toxic Substances Control will approve the remediation plan by the
second quarter of 2009. The Utility spent approximately $1 million in
2008 and estimates that it will spend approximately $12 million in 2009 and
approximately $15 million in 2010 for remediation at this site.
In
addition, the federal Toxic Substances Control Act regulates the use, disposal
and clean-up of polychlorinated biphenyls (“PCBs”), which are used in certain
electrical equipment. The Utility has removed from service all of the
distribution capacitors and network transformers containing high concentrations
of PCBs, representing the vast majority of PCBs that had existed in the
Utility's electricity distribution system.
The
Utility is assessing whether and to what extent remedial action may be necessary
to mitigate potential hazards posed by certain retired manufactured gas plant
sites. During their operation, from the mid-1800s through the early 1900s,
manufactured gas plants produced lampblack and tar residues. The residues from
these operations, which may remain at some sites, contain chemical compounds
that now are classified as hazardous. There are 95 such sites within the
Utility’s service territory that are owned by the Utility or third parties. The
Utility has determined that it is liable for the remediation of 41 sites, is
potentially liable for remediation of an additional 24 sites, and is not liable
for remediation at the remaining 30 sites. The Utility has a program,
in cooperation with environmental agencies and third party owners, to evaluate
and take appropriate action to mitigate any potential health or environmental
hazards at the 41 sites for which the Utility is liable. The Utility spent
approximately $12 million in 2008 and expects to spend approximately $27
million in 2009 and $20 million in 2010 on these sites. The Utility expects that
expenses at these sites will increase as remedial actions related to these sites
are approved by regulatory agencies and claims by third party owners are
settled. Although it is likely that the Utility will incur
remediation costs related to some of these sites, the Utility cannot quantify
the potential amount.
Under
environmental laws, such as CERCLA, the Utility has been or may be required to
take remedial action at third-party sites used for the disposal of waste from
the Utility's facilities, or to pay for associated clean-up costs or natural
resource damages. The Utility is currently aware of five such sites where
investigation or clean-up activities are currently underway. At the
Geothermal Incorporated site in Lake County, California, the Utility
substantially completed closure of the disposal facility, which was abandoned by
its operator. The Utility was the major responsible party and led the
remediation effort on behalf of the responsible parties. For the
Casmalia disposal facility near Santa Maria, California, the Utility and several
parties that sent waste to the site have entered into a court-approved agreement
with the EPA that requires the Utility and the other parties to perform certain
site investigation and remediation measures. Other responsible
parties are involved with the Utility in investigation and cleaning up the three
other disposal sites with oversight from the regulatory agencies. The
Utility contributes to these sites under cost sharing agreements or court
approved settlements
In
addition, the Utility has been named as a defendant in a civil lawsuit in which
plaintiffs allege that the Utility is responsible for performing or paying for
remedial action at sites that it no longer owns or never
owned. Remedial actions may include investigations, health and
ecological assessments, and removal of wastes.
Groundwater
at the Utility’s Hinkley and Topock natural gas compressor stations contains
hexavalent chromium as a result of the Utility’s past operating practices. The
Utility has a comprehensive program to monitor a network of groundwater wells at
both the Hinkley and Topock natural gas compressor stations. At
Hinkley, the Utility is cooperating with the Regional Water Quality Control
Board to evaluate and remediate the chromium groundwater
plume. Measures have been implemented to control movement of the
plume, while full-scale in-situ treatment systems operate to reduce the mass of
the plume. An evaluation of the performance of these interim remedy
measures, as well as possible future measures, is underway as part of the
development of a final remedy at the Hinkley site. In 2008, the
Utility spent approximately $15 million on remediation activities at Hinkley,
and currently estimates it will spend at least $16 million in 2009 and $6
million in 2010. Environmental remediation costs associated with the
Hinkley natural gas compressor site are not recoverable from
customers.
At the
Topock gas compressor station, located near Needles, California, the Utility has
implemented interim measures including a system of extraction wells and a
treatment plant designed to prevent movement of a hexavalent chromium plume
toward the Colorado River. In addition, the Utility is working with
the agencies to complete investigations at this site and to develop a long-term
plan for clean up of the plume. A final cleanup draft plan has been
developed for agency and stakeholder review; approval of a final version of that
plan is scheduled to occur by the first quarter of 2010. In 2008, the Utility spent
approximately $23 million on the interim measures and for work on the long term
site solution. The Utility currently estimates that it will spend at
least $19 million
in 2009
and $18 million in 2010 for remediation activities at
Topock. Although work at the Topock site poses several technical and
regulatory obstacles, the Utility’s remediation costs for Topock are subject to
the ratemaking mechanism described above. The Utility does not expect the
remediation of the Topock and Hinkley gas compressor sites to have a material
adverse effect on its results of operations or financial condition. The Utility
does not expect that it will incur any material expenditures related to any
remediation at its Kettleman natural gas compressor station.
As part
of the Nuclear Waste Policy Act of 1982, Congress authorized the DOE and
electric utilities with commercial nuclear power plants to enter into contracts
under which the DOE would be required to dispose of the utilities' spent nuclear
fuel and high-level radioactive waste no later than January 31, 1998, in
exchange for fees paid by the utilities. In 1983, the DOE entered
into a contract with the Utility to dispose of nuclear waste from the Utility’s
two nuclear generating units at Diablo Canyon and its retired nuclear facility
at Humboldt Bay. The DOE failed to develop a permanent storage site
by January 31, 1998. The Utility believes that the existing spent
fuel pools at Diablo Canyon (which include newly constructed temporary storage
racks) have sufficient capacity to enable the Utility to operate Diablo Canyon
until October 2010 for Unit 1 and May 2011 for Unit 2. Because the
DOE failed to develop a permanent storage site, the Utility obtained a permit
from the NRC to build an on-site dry cask storage facility to store spent fuel
through at least 2024. After various parties appealed the NRC’s
issuance of the permit, the U.S. Court of Appeals for the Ninth Circuit (the
“Ninth Circuit”) issued a decision in 2006 requiring the NRC to issue a
supplemental environmental assessment report on the potential environmental
consequences in the event of a terrorist attack at Diablo Canyon, as well as to
review other contentions raised by the appealing parties related to potential
terrorism threats. In August 2007, the NRC staff issued a final
supplemental environmental assessment report concluding there would be no
significant environmental impacts from potential terrorist acts directed at the
Diablo Canyon storage facility.
In
October 2008, the NRC rejected the final contention that had been made
during the appeal. The appellant has filed a petition for review of the NRC’s
order in the Ninth Circuit. Although the appellant did not seek to obtain
an order prohibiting the Utility from loading spent fuel, the petition stated
that they may seek a stay of fuel loading at the facility. On December 31,
2008, the appellate court granted the Utility’s request to intervene in the
proceeding. All briefs by all parties are scheduled to be filed by
April 8, 2009.
The
construction of the dry cask storage facility is complete and the initial
movement of spent nuclear fuel to dry cask storage is expected to begin in June
2009. If the Utility is unable to begin loading spent fuel by October
2010 for Unit 1 or May 2011 for Unit 2 and if the Utility is otherwise unable to
increase its on-site storage capacity, the Utility would have to curtail or halt
operations in the unit until such time as additional safe storage for spent fuel
is made available.
As a
consequence of the DOE’s failure to develop a permanent national repository for
spent nuclear fuel and high-level radioactive waste, the Utility and other
nuclear power plant owners sued the DOE for breach of contract. In
October 2006, the U.S. Court of Federal Claims found the DOE had breached its
contract and awarded the Utility approximately $42.8 million of the $92 million
incurred by the Utility through 2004 to construct on-site storage at Diablo
Canyon and Humboldt Bay Unit 3. Following the Utility’s appeal of the award, the
U.S. Court of Appeals for the Federal Circuit reversed the lower court on issues
relating to the calculation of damages and ordered the lower court to
re-calculate the award. Although various motions by the DOE for
reconsideration are still pending, the judge in the lower court conducted a
status conference on January 15, 2009 and has scheduled another conference for
July 9, 2009. The Utility expects the final award will approximate
$91 million for costs incurred through 2004 and that the Utility will recover
all of its costs incurred after 2004 to build on-site storage
facilities. Amounts recovered from the DOE will be credited to
customers through rates.
Nuclear
Decommissioning
The
Utility's nuclear power facilities consist of two units at Diablo Canyon and the
retired facility at Humboldt Bay Unit 3. Nuclear decommissioning requires the
safe removal of nuclear facilities from service and the reduction of residual
radioactivity to a level that permits termination of the NRC license and release
of the property for unrestricted use. The Utility makes contributions
to trusts to provide for the eventual decommissioning of each nuclear
unit. In the Utility’s 2005 Nuclear Decommissioning Cost Triennial
Proceeding, used to determine the level of Utility trust contributions and
related revenue requirement, the CPUC assumed that the eventual decommissioning
of Diablo Canyon Unit 1 would be scheduled to begin in 2024 and be completed in
2044; that decommissioning of Diablo Canyon Unit 2 would be scheduled to begin
in 2025 and be completed in 2041; and that decommissioning of Humboldt Bay Unit
3 would be scheduled to begin in 2009 and be completed in 2015. A
premature shutdown of the Diablo Canyon units would increase the likelihood of
an earlier start to decommissioning. The Utility’s decommissioning
cost estimates are based on the 2005 decommissioning cost studies, prepared in
accordance with CPUC requirements. The decommissioning cost estimates
are based on the plant location and cost characteristics for the Utility's
nuclear power plants. Actual decommissioning costs may vary from
these estimates as a result of changes in assumptions such as decommissioning
dates, regulatory requirements,
technology,
and costs of labor, materials and equipment. The Utility recovers its
revenue requirements for estimated nuclear decommissioning costs from customers
through a non-bypassable charge that the Utility expects will continue until
those costs are fully recovered. Decommissioning costs recovered in
rates are placed in nuclear decommissioning trusts. The funds in the
decommissioning trusts, along with accumulated earnings, will be used
exclusively for decommissioning and dismantling the Utility's nuclear
facilities.
For more
information about nuclear decommissioning, including the estimated
decommissioning costs, see Note 13 of the Notes to the Consolidated
Financial Statements in the 2008 Annual Report.
Electric
and magnetic fields (“EMFs”) naturally result from the generation, transmission,
distribution and use of electricity. In November 1993, the CPUC
adopted an interim EMF policy for California energy utilities that, among other
things, requires California energy utilities to take no-cost and low-cost steps
to reduce EMFs from new or upgraded utility facilities. California
energy utilities were required to fund an EMF education program and an EMF
research program managed by the California Department of Health
Services. In October 2002, the California Department of Health
Services released its report to the CPUC and the public, based primarily on its
review of studies by others, evaluating the possible risks from
EMFs. The report's conclusions contrast with other recent
reports by authoritative health agencies in that the California Department of
Health Services' report has assigned a higher probability to the possibility of
a causal connection between EMF exposures and a number of diseases and
conditions, including childhood leukemia, adult leukemia, amyotrophic lateral
sclerosis and miscarriages.
On
January 26, 2006, the CPUC issued a decision which affirms the CPUC’s
“low-cost/no-cost, prudent avoidance” policy to reduce EMF exposure for new
utility transmission and substation projects. The CPUC ordered the continued use
of a 4% of project cost benchmark for EMF reduction measures. The
CPUC also reaffirmed that it has exclusive jurisdiction with respect to utility
EMF matters.
The
Utility currently is not involved in third-party litigation concerning EMFs. In
August 1996, the California Supreme Court held that homeowners are barred
from suing utilities for alleged property value losses caused by fear of EMFs
from power lines. In a case involving allegations of personal injury, a
California appeals court held that the CPUC has exclusive jurisdiction over
personal injury and wrongful death claims arising from allegations of harmful
exposure to EMFs, and barred plaintiffs' personal injury claims. The California
Supreme Court declined to hear the plaintiffs’ appeal of this
decision.
A
discussion of the significant risks associated with investments in the
securities of PG&E Corporation and the Utility is set forth under the
heading “Risk Factors” in the MD&A in the 2008 Annual Report, which
information is incorporated by reference and included in Exhibit 13 to this
report.
None.
The
Utility owns or has obtained the right to occupy and/or use real property
comprising the Utility's electricity and natural gas distribution facilities,
natural gas gathering facilities and generation facilities, and natural gas and
electricity transmission facilities, all of which are described above under
“Electric Utility Operations” and “Natural Gas Utility
Operations.” In total, the Utility occupies 9.8 million square
feet of real property, including 8.5 million square feet that the Utility
owns. Of the 9.8 million square feet of occupied real property,
approximately 1.7 million square feet represent the Utility's corporate
headquarters located in several Utility owned buildings in San Francisco,
California. The Utility occupies or uses real property that it does
not own primarily through various leases, easements, rights-of-way, permits or
licenses from private landowners or governmental authorities. The
Utility currently owns approximately 167,000 acres of land, approximately
140,000 acres of which it will encumber with conservation easements and/or
donate to public agencies or non-profit conservation organizations under the
Chapter 11 Settlement Agreement. Approximately 75,000 acres of this
land may be donated in fee and encumbered with conservation
easements. The remaining land contains the Utility's or a joint
licensee's hydroelectric generation facilities and will only be encumbered with
conservation easements. As contemplated in the Chapter 11 Settlement Agreement,
the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship
Council (“Council”) to oversee the development and implementation of a Land
Conservation Plan (“LCP”) that will articulate the long-term management
objectives for the 140,000 acres. The Council is governed by an
18-member Board of Directors that represents a range of diverse interests,
including the CPUC, California environmental agencies, organizations
representing underserved and minority constituencies, agricultural and business
interests, and public officials. The Utility has appointed 1 out of
18
members
of the Board of Directors of the Council. In December 2007, the
Council adopted the LCP and submitted it to the Utility.
The
Utility has accepted the LCP and will seek authorization from the CPUC, the FERC
and other approving entities to proceed with the transactions necessary to
implement the LCP.
PG&E
Corporation also leases approximately 74,000 square feet of office space from a
third party in San Francisco, California. This lease expires in
2012.
Item
3. Legal
Proceedings
In
addition to the following legal proceedings, PG&E Corporation and the
Utility are involved in various legal proceedings in the ordinary course of
their business.
The
Utility's Diablo Canyon power plant employs a “once-through” cooling water
system that is regulated under a Clean Water Act permit issued by the Central
Coast Board. This permit allows the Diablo Canyon power plant to
discharge the cooling water at a temperature no more than 22 degrees above the
temperature of the ambient receiving water, and requires that the beneficial
uses of the water be protected. The beneficial uses of water in this
region include industrial water supply, marine and wildlife habitat, shellfish
harvesting, and preservation of rare and endangered species. In
January 2000, the Central Coast Board issued a proposed draft cease and
desist order alleging that, although the temperature limit has never been
exceeded, the Utility's Diablo Canyon power plant's discharge was not protective
of beneficial uses.
In
October 2000, the Utility and the Central Coast Board reached a tentative
settlement under which the Central Coast Board agreed to find that the Utility's
discharge of cooling water from the Diablo Canyon power plant protects
beneficial uses and that the intake technology reflects the best technology
available, as defined in the federal Clean Water Act. As part of the
tentative settlement, the Utility agreed to take measures to preserve certain
acreage north of the plant and to fund approximately $6 million in
environmental projects and future environmental monitoring related to coastal
resources. On March 21, 2003, the Central Coast Board voted to
accept the settlement agreement. On June 17, 2003, the
settlement agreement was executed by the Utility, the Central Coast Board and
the California Attorney General's Office. A condition to the
effectiveness of the settlement agreement is that the Central Coast Board renew
Diablo Canyon's NPDES permit.
At its
July 10, 2003 meeting, the Central Coast Board did not renew the NPDES
permit and continued the permit renewal hearing indefinitely. Several
Central Coast Board members indicated that they no longer supported the
settlement agreement, and the Central Coast Board requested a team of
independent scientists, as part of a technical working group, to develop
additional information on possible mitigation measures for Central Coast Board
staff. In January 2005, the Central Coast Board published the
scientists' draft report recommending several such mitigation
measures. If the Central Coast Board adopts the scientists'
recommendations, and if the Utility ultimately is required to implement the
projects proposed in the draft report, it could incur costs of up to
approximately $30 million. The Utility would seek to recover
these costs through rates charged to customers. The Water Board is
developing a state policy for the implementation of Section 316(b) of the Clean
Water Act, the adoption of which could affect future negotiations between the
Central Coast Board and the Utility. For more information about the
draft state policy, see “Environmental Matters—Water Quality”
above.
PG&E
Corporation and the Utility believe that the ultimate outcome of this matter
will not have a material adverse impact on their Utility's financial condition
or results of operations.
On
January 10, 2002, the California Attorney General filed a complaint in the
Superior Court for the County of San Francisco (“Superior Court”) against
PG&E Corporation and its directors, as well as against directors of the
Utility, based on allegations of unfair or fraudulent business acts or practices
in violation of California Business and Professions Code Section 17200
(“Section 17200”). Among other allegations, the California
Attorney General alleged that past transfers of funds from the Utility to
PG&E Corporation during the period from 1997 through 2000 (primarily in the
form of dividends and stock repurchases), and allegedly from PG&E
Corporation to other affiliates of PG&E Corporation, violated various
conditions established by the CPUC in decisions approving the holding company
formation. The California Attorney General alleged that the
defendants violated these conditions when PG&E Corporation allegedly failed
to provide adequate financial support to the Utility during the California
energy crisis.
The
complaint seeks injunctive relief, the appointment of a receiver, restitution in
an amount according to proof, civil penalties of $2,500 against each defendant
for each violation of Section 17200, a total penalty of not less than
$500 million and costs of suit. The California Attorney
General's complaint also seeks restitution of assets allegedly wrongfully
transferred to PG&E Corporation from the Utility.
On
February 11, 2002, a complaint entitled City and County of San Francisco;
People of the State of California v. PG&E Corporation, and Does
1-150, was filed in the Superior Court. The complaint contains
some of the same allegations contained in the California Attorney General's
complaint, including allegations of unfair competition in violation of Section
17200. In addition, the complaint alleges causes of action for
conversion, claiming that PG&E Corporation “took at least $5.2 billion
from the Utility,” and for unjust enrichment. The City and County of San
Francisco (“CCSF”) seeks injunctive relief, the appointment of a receiver,
restitution, disgorgement, the imposition of a constructive trust, civil
penalties of $2,500 against each defendant for each violation of Section 17200
and costs of suit.
The
complaints, which have been consolidated in the Superior Court, were filed after
the CPUC issued two decisions in its investigative proceeding commenced in April
2001 into whether the California investor-owned electric utilities, including
the Utility, complied with past CPUC decisions, rules and orders authorizing
their holding company formations and/or governing affiliate transactions, as
well as applicable statutes. The order states that the CPUC would,
among other matters, investigate the utilities' transfer of money to their
holding companies, including during times when their utility subsidiaries were
experiencing financial difficulties, the failure of the holding companies to
financially assist the utilities when needed, the transfer by the holding
companies of assets to unregulated subsidiaries, and the holding companies'
actions to “ringfence” their unregulated subsidiaries. In May 2005,
the CPUC closed this investigation without making any findings.
PG&E
Corporation believes that the intercompany transactions challenged by the
California Attorney General and CCSF were in full compliance with applicable law
and CPUC conditions. The challenged transactions forming the bulk of
the restitution claims were regular quarterly dividends and stock
repurchases. As part of its annual cost of capital proceedings, the
Utility advised the CPUC in advance of its forecast stock repurchases and
dividends. The CPUC did not challenge or question those
payments.
In
January 2006, the Ninth Circuit issued a decision on the parties’ appeals of
various rulings by the Bankruptcy Court and the U.S. District Court for the
Northern District of California concerning jurisdictional issues. The
Ninth Circuit found that the Superior Court had jurisdiction over the California
Attorney General’s and CCSF’s restitution claims. (In October 2006,
the U.S. Supreme Court declined to grant PG&E Corporation’s request to
review the Ninth Circuit’s decision.) The Ninth Circuit did not
address the California Attorney General’s and CCSF’s underlying allegations that
PG&E Corporation and the other defendants violated Section
17200. The Ninth Circuit also did not decide the issue of who would
be entitled to receive the proceeds, if any, of a restitution award, and
PG&E Corporation continues to believe that any such proceeds would be the
property of the Utility. Pursuant to the Chapter 11 Settlement
Agreement, the CPUC released all claims against PG&E Corporation or the
Utility arising out of or in any way related to the energy crisis, including the
CPUC’s investigation into past PG&E Corporation actions during the
California energy crisis. Accordingly, PG&E Corporation believes
that any claims for such proceeds by the CPUC would be precluded.
While the
Ninth Circuit appeal was pending, the Superior Court held a trial in December
2004 to consider the appropriate standard to determine what constitutes a
separate violation of Section 17200 in order to determine the magnitude of
potential penalties under Section 17200 (up to $2,500 per separate “violation”).
The Superior Court did not address the question of whether any violations
occurred. In March 2005, the Superior Court issued a decision
rejecting the “per victim” and “per [customer] bill” approaches advocated by the
plaintiffs, standards that potentially could have resulted in millions of
separate “violations.” The Superior Court found that the appropriate
standard was each transfer of money from the Utility to PG&E Corporation
that plaintiffs allege violated Section 17200. In July 2005, the
California Court of Appeal summarily denied a petition filed by the California
Attorney General and CCSF seeking to overturn this decision. The next
case management conference in Superior Court is scheduled on February 26,
2009.
PG&E
Corporation believes that the California Attorney General’s and CCSF’s
allegations have no merit and will continue to vigorously respond to and defend
against the litigation. PG&E
Corporation believes that the ultimate outcome of this matter would not result
in a material adverse effect on PG&E Corporation’s financial condition or
results of operations.
Not
applicable.
The
names, ages and positions of PG&E Corporation “executive officers,” as
defined by Rule 3b-7 of the General Rules and Regulations under the
Securities and Exchange Act of 1934 (“Exchange Act”) at February 20, 2009, are
as follows:
|
Name
|
Age
|
Position
|
||
|
Peter
A. Darbee
|
56
|
Chairman
of the Board, Chief Executive Officer, and President
|
||
|
Kent
M. Harvey
|
50
|
Senior
Vice President and Chief Risk and Audit Officer
|
||
|
Christopher
P. Johns
|
48
|
Senior
Vice President, Chief Financial Officer, and Treasurer
|
||
|
John
S. Keenan
|
60
|
Senior
Vice President and Chief Operating Officer, Pacific Gas and
Electric Company
|
||
|
Nancy
E. McFadden
|
50
|
Senior
Vice President, Public Affairs
|
||
|
Hyun
Park
|
47
|
Senior
Vice President and General Counsel
|
||
|
Greg
S. Pruett
|
51
|
Senior
Vice President, Corporate Relations
|
||
|
Rand
L. Rosenberg
|
55
|
Senior
Vice President, Corporate Strategy and Development
|
||
|
John
R. Simon
|
44
|
Senior
Vice President, Human
Resources
|
All
officers of PG&E Corporation serve at the pleasure of the Board of
Directors. During the past five years through February 20, 2009, the executive
officers of PG&E Corporation had the following business experience. Except
as otherwise noted, all positions have been held at PG&E
Corporation.
|
Name
|
Position
|
Period
Held Office
|
||
|
Peter
A. Darbee
|
Chairman
of the Board, Chief Executive Officer, and President
|
September 19,
2007 to present
|
||
|
President
and Chief Executive Officer, Pacific Gas and Electric
Company
|
September
5, 2008 to present
|
|||
|
Chairman
of the Board and Chief Executive Officer
|
July
1, 2007 to September 18, 2007
|
|||
|
Chairman
of the Board, Chief Executive Officer, and President
|
January
1, 2006 to June 30, 2007
|
|||
|
Chairman
of the Board, Pacific Gas and Electric Company
|
January 1,
2006 to May 31, 2007
|
|||
|
President
and Chief Executive Officer
|
January 1,
2005 to December 31, 2005
|
|||
|
Senior
Vice President and Chief Financial Officer
|
September
20, 1999 to December 31, 2004
|
|||
|
Kent
M. Harvey
|
Senior
Vice President and Chief Risk and Audit Officer
|
October 1,
2005 to present
|
||
|
Senior
Vice President, Chief Financial Officer, and Treasurer, Pacific Gas
and Electric Company
|
November 1,
2000 to September 30, 2005
|
|||
|
Christopher
P. Johns
|
Senior
Vice President, Chief Financial Officer, and Treasurer
|
October 4,
2005 to present
|
||
|
Senior
Vice President and Treasurer, Pacific Gas and Electric
Company
|
June
1, 2007 to present
|
|||
|
Senior
Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and
Electric Company
|
October 1,
2005 to May 31, 2007
|
|||
|
Senior
Vice President, Chief Financial Officer, and Controller
|
January 1,
2005 to October 3, 2005
|
|||
|
Senior
Vice President and Controller
|
September 19,
2001 to December 31, 2004
|
|||
|
John
S. Keenan
|
Senior
Vice President and Chief Operating Officer, Pacific Gas and Electric
Company
|
January
1, 2008 to present
|
||
|
Senior
Vice President, Generation and Chief Nuclear Officer, Pacific Gas and
Electric Company
|
December 19,
2005 to December 31, 2007
|
|||
|
Vice
President, Fossil Generation, Progress Energy
|
November 10,
2003 to December 18, 2005
|
|||
|
Nancy
E. McFadden
|
Senior
Vice President, Public Affairs
|
March
1, 2007 to present
|
||
|
Senior
Vice President, Public Affairs, Pacific Gas and Electric
Company
|
June
20, 2007 to present
|
|||
|
Vice
President, Governmental Relations, Pacific Gas and Electric
Company
|
September
26, 2005 to February 28, 2007
|
|||
|
Chairperson,
California Medical Assistance Commission
|
November
13, 2003 to November 30, 2005
|
|||
|
Hyun
Park
|
Senior
Vice President and General Counsel
|
November 13,
2006 to present
|
||
|
Vice
President, General Counsel, and Secretary, Allegheny Energy,
Inc.
|
April 5,
2005 to October 17, 2006
|
|||
|
Senior
Vice President, General Counsel, and Secretary, Sithe Energies,
Inc.
|
March
2000 to February 2005
|
|||
|
Greg
S. Pruett
|
Senior
Vice President, Corporate Relations
|
November
1, 2007 to present
|
||
|
Vice
President, Corporate Relations
|
March
1, 2007 to October 31, 2007
|
|||
|
Vice
President, Communications and Marketing, American Gas
Association
|
April
10, 2006 to February 23, 2007
|
|||
|
Chief
Public Affairs Officer, Bechtel National, Inc.
|
June
12, 2004 to September 12, 2005
|
|||
|
Vice
President, Corporate Communications, PG&E Corporation
|
January
1, 1998 to September 12, 2003
|
|||
|
Rand
L. Rosenberg
|
Senior
Vice President, Corporate Strategy and Development
|
November 1,
2005 to present
|
||
|
Executive
Vice President and Chief Financial Officer, Infospace,
Inc.
|
September
2000 to January 20, 2001
|
|||
|
John
R. Simon
|
Senior
Vice President, Human Resources
|
April
16, 2007 to present
|
||
|
Senior
Vice President, Human Resources, Pacific Gas and Electric
Company
|
April
16, 2007 to present
|
|||
|
Executive
Vice President, Global Human Capital, TeleTech Holdings,
Inc.
|
March
21, 2006 to April 13, 2007
|
|||
|
Senior
Vice President, Human Capital, TeleTech Holdings, Inc.
|
July
31, 2001 to March 20, 2006
|
The
names, ages and positions of the Utility's “executive officers,” as defined by
Rule 3b-7 of the General Rules and Regulations under the Exchange Act at
February 20, 2009, are as follows:
|
Name
|
Age
|
Position
|
||
|
Peter
A. Darbee
|
56
|
President
and Chief Executive Officer
|
||
|
John
S. Keenan
|
60
|
Senior
Vice President and Chief Operating Officer
|
||
|
Desmond
A. Bell
|
46
|
Senior
Vice President, Shared Services and Chief Procurement
Officer
|
||
|
Thomas
E. Bottorff
|
55
|
Senior
Vice President, Regulatory Relations
|
||
|
Helen
A. Burt
|
52
|
Senior
Vice President and Chief Customer Officer
|
||
|
John
T. Conway
|
51
|
Senior
Vice President, Generation and Chief Nuclear Officer
|
||
|
Christopher
P. Johns
|
48
|
Senior
Vice President and Treasurer
|
||
|
Patricia
M. Lawicki
|
48
|
Senior
Vice President and Chief Information Officer
|
||
|
Nancy
E. McFadden
|
50
|
Senior
Vice President, Public Affairs
|
||
|
Hyun
Park
|
47
|
Senior
Vice President and General Counsel, PG&E
Corporation
|
||
|
Greg
S. Pruett
|
51
|
Senior
Vice President, Corporate Relations, PG&E
Corporation
|
||
|
Edward
A. Salas
|
52
|
Senior
Vice President, Engineering and Operations
|
||
|
John
R. Simon
|
44
|
Senior
Vice President, Human Resources
|
||
|
Fong
Wan
|
47
|
Senior
Vice President, Energy Procurement
|
||
|
Geisha
J. Williams
|
47
|
Senior
Vice President, Energy Delivery
|
||
|
Barbara
L. Barcon
|
52
|
Vice
President, Finance and Chief Financial
Officer
|
All
officers of the Utility serve at the pleasure of the Board of
Directors. During the past five years through February 20, 2009 the
executive officers of the Utility had the following business
experience. Except as otherwise noted, all positions have been held
at Pacific Gas and Electric Company.
|
Name
|
Position
|
Period
Held Office
|
||
|
Peter
A. Darbee
|
President
and Chief Executive Officer
|
September
5, 2008 to present
|
||
|
Chairman
of the Board, Chief Executive Officer, and President, PG&E
Corporation
|
September
19, 2007 to present
|
|||
|
Chairman
of the Board and Chief Executive Officer, PG&E
Corporation
|
July
1, 2007 to September 18, 2007
|
|||
|
Chairman
of the Board, Pacific Gas and Electric Company
|
January 1,
2006 to May 31, 2007
|
|||
|
Chairman
of the Board, Chief Executive Officer, and President, PG&E
Corporation
|
January 1,
2006 to June 30, 2007
|
|||
|
President
and Chief Executive Officer, PG&E Corporation
|
January 1,
2005 to December 31, 2005
|
|||
|
Senior
Vice President and Chief Financial Officer, PG&E
Corporation
|
September
20, 1999 to December 31, 2004
|
|||
|
John
S. Keenan
|
Senior
Vice President and Chief Operating Officer
|
January
1, 2008 to present
|
||
|
Senior
Vice President, Generation and Chief Nuclear Officer
|
December 19,
2005 to December 31, 2007
|
|||
|
Vice
President, Fossil Generation, Progress Energy
|
November 10,
2003 to December 18, 2005
|
|||
|
Desmond
A. Bell
|
Senior
Vice President, Shared Services and Chief Procurement
Officer
|
October
1, 2008 to present
|
||
|
Vice
President, Shared Services and Chief Procurement Officer
|
March
1, 2008 to September 30, 2008
|
|||
|
Vice
President and Chief of Staff
|
March
19, 2007 to February 29, 2008
|
|||
|
Vice
President, Parts Logistics, Bombardier Aerospace
|
April
2003 to September 2006
|
|||
|
Thomas
E. Bottorff
|
Senior
Vice President, Regulatory Relations
|
October 14,
2005 to present
|
||
|
Senior
Vice President, Customer Service and Revenue
|
March 1,
2004 to October 13, 2005
|
|||
|
Vice
President, Customer Service
|
June 1,
1999 to February 29, 2004
|
|||
|
Helen
A. Burt
|
Senior
Vice President and Chief Customer Officer
|
February
27, 2006 to present
|
||
|
Management
Consultant, The Burt Group
|
January
2003 to February 2006
|
|||
|
John
T. Conway
|
Senior
Vice President, Generation and Chief Nuclear Officer
|
October
1 , 2008 to present
|
||
|
Senior
Vice President and Chief Nuclear Officer
|
March
1, 2008 to September 30, 2008
|
|||
|
Site
Vice President, Diablo Canyon Power Plant
|
May
20, 2007 to February 29, 2008
|
|||
|
Site
Vice President, Monticello Nuclear Plant, Nuclear Management
Company
|
May
2005 to June 1, 2007
|
|||
|
Site
Director, Monticello Nuclear Plant, Nuclear Management
Company
|
April
2004 to May 2005
|
|||
|
Vice
President, Nine Mile Point, Constellation Energy Group
|
November
2001 to August 2003
|
|||
|
Christopher
P. Johns
|
Senior
Vice President and Treasurer
|
June
1, 2007 to present
|
||
|
Senior
Vice President, Chief Financial Officer, and Treasurer, PG&E
Corporation
|
October 4,
2005 to present
|
|||
|
Senior
Vice President, Chief Financial Officer, and Treasurer
|
October 1,
2005 to May 31, 2007
|
|||
|
Senior
Vice President, Chief Financial Officer, and Controller, PG&E
Corporation
|
January 1,
2005 to October 3, 2005
|
|||
|
Senior
Vice President and Controller, PG&E Corporation
|
September 19,
2001 to December 31, 2004
|
|||
|
Patricia
M. Lawicki
|
Senior
Vice President and Chief Information Officer
|
November
1, 2007 to present
|
||
|
Vice
President and Chief Information Officer
|
January
12, 2005 to October 31, 2007
|
|||
|
Vice
President, Chief Information Officer, NiSource, Inc.
|
April
23, 2003 to January 7, 2005
|
|||
|
Nancy
E. McFadden
|
Senior
Vice President, Public Affairs
|
June
20, 2007 to present
|
||
|
Senior
Vice President, Public Affairs, PG&E Corporation
|
March
1, 2007 to present
|
|||
|
Vice
President, Governmental Relations
|
September
26, 2005 to February 28, 2007
|
|||
|
Chairperson,
California Medical Assistance Commission
|
November
13, 2003 to November 30, 2005
|
|||
|
Hyun
Park
|
Senior
Vice President and General Counsel, PG&E Corporation
|
November 13,
2006 to present
|
||
|
Vice
President, General Counsel, and Secretary, Allegheny Energy,
Inc.
|
April 5,
2005 to October 17, 2006
|
|||
|
Senior
Vice President, General Counsel, and Secretary, Sithe Energies,
Inc.
|
March
2000 to February 2005
|
|||
|
Greg
S. Pruett
|
Senior
Vice President, Corporate Relations, PG&E Corporation
|
November
1, 2007 to present
|
||
|
Vice
President, Corporate Relations, PG&E Corporation
|
March
1, 2007 to October 31, 2007
|
|||
|
Vice
President, Communications and Marketing, American Gas
Association
|
April
10, 2006 to February 23, 2007
|
|||
|
Chief
Public Affairs Officer, Bechtel National, Inc.
|
June
12, 2004 to September 12, 2005
|
|||
|
Vice
President, Corporate Communications, PG&E Corporation
|
January
1, 1998 to September 12, 2003
|
|||
|
Edward
A. Salas
|
Senior
Vice President, Engineering and Operations
|
April
11, 2007 to present
|
||
|
Staff
Vice President, Network Planning, Verizon Wireless
|
May
2004 to April 2007
|
|||
|
Contractor,
Verizon Wireless, Local Number Portability Implementation
|
May
2003 to April 2004
|
|||
|
John
R. Simon
|
Senior
Vice President, Human Resources
|
April
16, 2007 to present
|
||
|
Senior
Vice President, Human Resources, PG&E Corporation
|
April
16, 2007 to present
|
|||
|
Executive
Vice President, Global Human Capital, TeleTech
|
March
21, 2006 to April 13, 2007
|
|||
|
Senior
Vice President, Human Capital, TeleTech Holdings, Inc.
|
July
13, 2001 to March 20, 2006
|
|||
|
Fong
Wan
|
Senior
Vice President, Energy Procurement
|
October
1, 2008 to present
|
||
|
Vice
President, Energy Procurement
|
January 9,
2006 to September 30, 2008
|
|||
|
Vice
President, Power Contracts and Electric Resource
Development
|
May 1,
2004 to January 8, 2006
|
|||
|
Vice
President, Risk Initiatives, PG&E Corporation Support Services,
Inc.
|
November
1, 2000 to April 30, 2004
|
|||
|
Geisha
J. Williams
|
Senior
Vice President, Energy Delivery
|
December
1, 2007 to present
|
||
|
Vice
President, Power Systems, Distribution, Florida Power and Light
Company
|
July
2003 to July 2007
|
|||
|
Barbara
L. Barcon
|
Vice
President, Finance and Chief Financial Officer
|
March
24, 2008 to present
|
||
|
Senior
Vice President, The Gores Group - Glendon Partners Private Equity
Firm
|
2007
to 2008
|
|||
|
Vice
President, Financial Process Excellence, Northrop Grumman
Corporation
|
2004
to 2007
|
|||
|
Vice
President, Planning and Analysis, Northrop Grumman
Corporation
|
2003
to 2004
|
As of
February 20, 2009, there were 85,658 holders of record of PG&E
Corporation common stock. PG&E Corporation common stock is listed
on the New York Stock Exchange and the Swiss stock exchanges. The
high and low sales prices of PG&E Corporation common stock for each quarter
of the two most recent fiscal years are set forth under the heading “Quarterly
Consolidated Financial Data (Unaudited)” in the 2008 Annual Report, which
information is incorporated by reference and included in Exhibit 13 to this
report. Information about the frequency and amount of dividends on
common stock paid by PG&E Corporation and the Utility is set forth in the
table entitled “Selected Financial Data” in the 2008 Annual Report, which
information is incorporated by reference and included in Exhibit 13 to this
report. The discussion of dividends with respect to PG&E
Corporation's and the Utility’s common stock is set forth under the section of
MD&A entitled “Liquidity and Financial Resources — Dividends” in the 2008
Annual Report, which information is incorporated by reference and included in
Exhibit 13 to this report.
During the quarter ended December 31,
2008, PG&E Corporation made equity contributions totaling $180 million to
the Utility in order to maintain the 52% common equity target authorized by the
CPUC and to ensure that the Utility has adequate capital to fund its capital
expenditures.
Neither PG&E Corporation nor the
Utility made any sales of unregistered equity securities during
2008.
PG&E
Corporation common stock:
|
Period
|
Total
Number of Shares Purchased
|
Average
Price Paid Per Share
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
|
Approximate
Dollar Value of Shares that May Yet be Purchased Under the Plans or
Programs
|
|||||||
|
October
1 through October 31, 2008
|
-
|
$
|
-
|
$
|
-
|
||||||
|
November
1 through November 30, 2008
|
-
|
$
|
-
|
$
|
-
|
||||||
|
December
1 through December 31, 2008
|
3,872
|
(1)
|
$
|
$38.71
|
-
|
$
|
-
|
||||
|
Total
|
3,872
|
$
|
$38.71
|
-
|
$
|
-
|
|||||
|
(1)
Shares tendered to satisfy tax withholding obligations arising upon the
vesting of PG&E Corporation restricted
stock.
|
|||||||||||
During
the fourth quarter of 2008, the Utility did not redeem or repurchase any shares
of its various series of preferred stock outstanding.
Item
6. Selected Financial
Data
A summary
of selected financial information, for each of PG&E Corporation and Pacific
Gas and Electric Company for each of the last five fiscal years, is set forth
under the heading “Selected Financial Data” in the 2008 Annual Report, which
information is incorporated by reference and included in Exhibit 13 to this
report.
A
discussion of PG&E Corporation's and Pacific Gas and Electric Company's
consolidated financial condition and results of operations is set forth under
the heading “Management's Discussion and Analysis of Financial Condition and
Results of Operations” in the 2008 Annual Report, which discussion is
incorporated by reference and included in Exhibit 13 to this
report.
Information
responding to Item 7A appears in the 2008 Annual Report under the heading
“Management's Discussion and Analysis of Financial Condition and Results of
Operations—Risk Management Activities,” and under Notes 2, 11 and 12 of the
Notes to the Consolidated Financial Statements of the 2008 Annual Report, which
information is incorporated by reference and included in Exhibit 13 to this
report.
Information
responding to Item 8 appears in the 2008 Annual Report under the following
headings for PG&E Corporation: “Consolidated Statements of Income,”
“Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and
“Consolidated Statements of Shareholders' Equity;” under the following headings
for Pacific Gas and Electric Company: “Consolidated Statements of Income,”
“Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and
“Consolidated Statements of Shareholders' Equity;” and under the following
headings for PG&E Corporation and Pacific Gas and Electric Company jointly:
“Notes to the Consolidated Financial Statements,” “Quarterly Consolidated
Financial Data (Unaudited),” and “Report of Independent Registered Public
Accounting Firm,” which information is incorporated by reference and included in
Exhibit 13 to this report.
Not
applicable.
Based on
an evaluation of PG&E Corporation's and the Utility's disclosure controls
and procedures as of December 31, 2008, PG&E Corporation's and the
Utility's respective principal executive officers and principal financial
officers have concluded that such controls and procedures are effective to
ensure that information required to be disclosed by PG&E Corporation and the
Utility in reports that the companies file or submit under the Securities
Exchange Act of 1934 (“1934 Act”) is recorded, processed, summarized and
reported within the time periods specified in the SEC rules and
forms. In addition, PG&E Corporation's and the Utility's
respective principal executive officers and principal financial officers have
concluded that such controls and procedures were effective in ensuring that
information required to be disclosed by PG&E Corporation and the Utility in
the reports that PG&E Corporation and the Utility file or submit under the
1934 Act is accumulated and communicated to PG&E Corporation’s and the
Utility’s management, including PG&E Corporation's and the Utility's
respective principal executive officers and principal financial officers, or
persons performing similar functions, as appropriate to allow timely decisions
regarding required disclosure.
There
were no changes in internal control over financial reporting that occurred
during the quarter ended December 31, 2008 that have materially affected,
or are reasonably likely to materially affect, PG&E Corporation's or the
Utility's internal control over financial reporting.
Management
of PG&E Corporation and the Utility have prepared an annual report on
internal control over financial reporting. Management's report,
together with the report of the independent registered public accounting firm,
appears in the 2008 Annual Report under the heading “Management's Report on
Internal Control Over Financial Reporting” and “Report of Independent Registered
Public Accounting Firm,” which information is incorporated by reference and
included in Exhibit 13 to this report.
Item
9B. Other
Information
Not
applicable.
PART
III
Information
regarding executive officers of PG&E Corporation and Pacific Gas and
Electric Company is included above in a separate item captioned “Executive
Officers of the Registrants” at the end of Part I of this
report. Other information responding to Item 10 is included under the
heading “Item No. 1: Election of Directors of PG&E Corporation and
Pacific Gas and Electric Company” and under the heading “Section 16(a)
Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating
to the 2009 Annual Meetings of Shareholders, which information is hereby
incorporated by reference.
Website
Availability of Code of Ethics, Corporate Governance and Other
Documents
The
following documents are available both on PG&E Corporation's website www.pgecorp.com, and Pacific
Gas and Electric Company's website, www.pge.com: (1) the
codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and
Electric Company applicable to their respective directors and employees,
including their respective Chief Executive Officers, Chief Financial Officers,
Controllers and other executive officers, (2) PG&E Corporation's and
Pacific Gas and Electric Company's corporate governance guidelines, and
(3) key Board Committee charters, including charters for the companies'
Audit Committees and the PG&E Corporation Nominating and Governance
Committee and Compensation Committee. Shareholders also may obtain
print copies of these documents by submitting a written request to Linda Y.H.
Cheng, Vice President, Corporate Governance and Corporate Secretary of PG&E
Corporation and Pacific Gas and Electric Company, One Market, Spear Tower, Suite
2400, San Francisco, California 94105.
If any
amendments are made to, or any waivers are granted with respect to, provisions
of the codes of conduct and ethics adopted by PG&E Corporation and Pacific
Gas and Electric Company that apply to their respective Chief Executive
Officers, Chief Financial Officers or Controllers, the company whose code is so
affected will disclose the nature of such amendment or waiver on its respective
website and any waivers to the code will be disclosed in a Current Report on
Form 8-K filed within 4 business days of the waiver.
Procedures
for Shareholder Recommendations of Nominees to the Boards of
Directors
During
2008 there were no material changes to the procedures described in PG&E
Corporation’s and the Utility’s Joint Proxy
Statement
relating to the 2008 Annual Meetings of Shareholders by which security holders
may recommend nominees to PG&E Corporation’s or the Utility’s Boards of
Directors.
Audit
Committees and Audit Committee Financial Expert
Information
regarding the Audit Committees of PG&E Corporation and the Utility and the
“audit committee financial expert” as defined by the SEC is included under the
heading “Information Regarding the Boards of Directors of PG&E Corporation
and Pacific Gas and Electric Company Board Committees Audit Committees” in
the Joint Proxy Statement relating to the 2009 Annual Meetings of Shareholders,
which information is hereby incorporated by reference.
Information
responding to Item 11, for each of PG&E Corporation and Pacific Gas and
Electric Company, is included under the
headings “Compensation Discussion and Analysis,” “Compensation Committee
Report,” “Summary Compensation Table - 2008,” “Grants of Plan-based
Awards in 2008,” “Outstanding Equity Awards at Fiscal Year End - 2008,” “Option
Exercises and Stock Vested During 2008,” “Pension Benefits – 2008,”
“Non-Qualified Deferred Compensation,” “Compensation of Non-Employee Directors,”
and “Potential Payments Upon Resignation, Retirement, Termination, Change in
Control, Death, or Disability” in the Joint Proxy Statement relating to the 2009
Annual Meetings of Shareholders, which information is hereby incorporated by
reference.
Information
responding to Item 12, for each of PG&E Corporation and Pacific Gas and
Electric Company, is included under the heading “Security Ownership of
Management” and under the heading “Principal Shareholders” in the Joint Proxy
Statement relating to the 2009 Annual Meetings of Shareholders, which
information is hereby incorporated by reference.
Equity
Compensation Plan Information
The
following table provides information as of December 31, 2008 concerning
shares of PG&E Corporation common stock authorized for issuance under
PG&E Corporation's existing equity compensation plans.
|
Plan
Category
|
(a)
Number
of Securities to
be
Issued Upon Exercise
of
Outstanding Options,
Warrants
and Rights
|
(b)
Weighted
Average
Exercise
Price of
Outstanding
Options,
Warrants
and Rights
|
(c)
Number
of Securities
Remaining
Available for
Future
Issuance Under
Equity
Compensation Plans
(Excluding
Securities
Reflected
in Column(a))
|
|||
|
Equity
compensation plans approved by shareholders
|
3,062,874(1)
|
$23.45
|
10,342,381(2)
|
|||
|
Equity
compensation plans not approved by
shareholders
|
—
|
—
|
—
|
|||
|
Total
equity compensation plans
|
3,062,874(1)
|
$23.45
|
10,342,381(2)
|
|
|
(1) Includes
94,613 phantom stock units and restricted stock units. The
weighted average exercise price reported in column (b) does not take these
awards into account.
|
|
|
(2) Represents
the total number of shares available for issuance under the PG&E
Corporation's Long-Term Incentive Program (“LTIP”) and the PG&E
Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) as of
December 31, 2008. Outstanding stock-based awards granted
under the LTIP include stock options, restricted stock and phantom
stock. The LTIP expired on December 31, 2005. The
2006 LTIP, which became effective on January 1, 2006, authorizes up to 12
million shares to be issued pursuant to awards granted under the 2006
LTIP. Outstanding stock-based awards granted under the 2006
LTIP include stock options, restricted stock, restricted stock units, and
phantom stock. For a description of the LTIP and the 2006 LTIP,
see Note 14 of the Notes to the Consolidated Financial Statements in
the 2008 Annual Report.
|
Item
13. Certain Relationships and
Related Transactions, and Director Independence
Information
responding to Item 13, for each of PG&E Corporation and Pacific Gas and
Electric Company, is included under the headings “Related Person Transactions,”
“Review, Approval, and Ratification of Related Person Transactions” and
“Information Regarding the Boards of Directors of PG&E Corporation and
Pacific Gas and Electric Company Director Independence” in the Joint Proxy
Statement relating to the 2009 Annual Meetings of Shareholders, which
information is hereby incorporated by reference.
Information
responding to Item 14, for each of PG&E Corporation and Pacific Gas and
Electric Company, is included under the heading “Information Regarding the
Independent Registered Public Accounting Firm of PG&E Corporation and
Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the
2009 Annual Meetings of Shareholders, which information is hereby incorporated
by reference.
Item
15. Exhibits and Financial
Statement Schedules
(a) The
following documents are filed as a part of this report:
1. The
following consolidated financial statements, supplemental information and report
of independent registered public accounting firm are contained in the 2008
Annual Report and are incorporated by reference in this report:
Consolidated
Statements of Income for the Years Ended December 31, 2008, 2007, and 2006
for each of PG&E Corporation and Pacific Gas and Electric
Company.
Consolidated
Balance Sheets at December 31, 2008 and 2007 for each of PG&E
Corporation and Pacific Gas and Electric Company.
Consolidated
Statements of Cash Flows for the Years Ended December 31, 2008, 2007, and 2006
for each of PG&E Corporation and Pacific Gas and Electric
Company.
Consolidated
Statements of Shareholders' Equity for the Years Ended December 31, 2008,
2007, and 2006 for each of PG&E Corporation and Pacific Gas and Electric
Company.
Notes to
the Consolidated Financial Statements.
Quarterly
Consolidated Financial Data (Unaudited).
Report of
Independent Registered Public Accounting Firm (Deloitte & Touche
LLP).
2. The
following financial statement schedules and report of independent registered
public accounting firm are filed as part of this report:
Report of
Independent Registered Public Accounting Firm (Deloitte & Touche
LLP).
I—Condensed
Financial Information of Parent as of December 31, 2008 and 2007 and for
the Years Ended December 31, 2008, 2007, and 2006.
II—Consolidated
Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific
Gas and Electric Company for the Years Ended December 31, 2008, 2007, and
2006.
Schedules
not included are omitted because of the absence of conditions under which they
are required or because the required information is provided in the consolidated
financial statements, including the notes thereto.
3. Exhibits
required by Item 601 of Regulation S-K:
|
Exhibit
Number
|
Exhibit
Description
|
|
|
2.1
|
Order
of the U.S. Bankruptcy Court for the Northern District of California dated
December 22, 2003, Confirming Plan of Reorganization of Pacific Gas
and Electric Company, including Plan of Reorganization, dated July 31,
2003 as modified by modifications dated November 6, 2003 and December 19,
2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of
Reorganization omitted) (incorporated by reference to Pacific Gas and
Electric Company's Registration Statement on Form S-3 No. 333-109994,
Exhibit 2.1)
|
|
|
2.2
|
Order
of the U.S. Bankruptcy Court for the Northern District of California dated
February 27, 2004 Approving Technical Corrections to Plan of
Reorganization of Pacific Gas and Electric Company and Supplementing
Confirmation Order to Incorporate such Corrections (incorporated by
reference to Pacific Gas and Electric Company's Registration Statement on
Form S-3 No. 333-109994, Exhibit 2.2)
|
|
|
3.1
|
Restated
Articles of Incorporation of PG&E Corporation effective as of May 29,
2002 (incorporated by reference to PG&E Corporation's Quarterly Report
on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609),
Exhibit 3.1)
|
|
|
3.2
|
Certificate
of Determination for PG&E Corporation Series A Preferred Stock filed
December 22, 2000 (incorporated by reference to PG&E Corporation's
Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit
3.2)
|
|
|
3.3
|
Bylaws
of PG&E Corporation amended as of January 1, 2009
|
|
|
3.4
|
Restated
Articles of Incorporation of Pacific Gas and Electric Company effective as
of April 12, 2004 (incorporated by reference to Pacific Gas and
Electric Company's Form 8-K filed April 12, 2004 (File
No. 1-2348), Exhibit 3)
|
|
|
3.5
|
Bylaws
of Pacific Gas and Electric Company amended as of January 1,
2009
|
|
|
4.1
|
Indenture,
dated as of April 22, 2005, supplementing, amending and restating the
Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a
First Supplemental Indenture, dated as of March 23, 2004, and a Second
Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas
and Electric Company and The Bank of New York Trust Company, N.A.
(incorporated by reference to PG&E Corporation and Pacific Gas and
Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File
No. 1-2348), Exhibit 4.1)
|
|
|
4.2
|
First
Supplemental Indenture dated as of March 13, 2007 relating to the issuance
of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037
(incorporated by reference from Pacific Gas and Electric Company’s Current
Report on Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit
4.1)
|
|
|
4.3
|
Second
Supplemental Indenture dated as of December 4, 2007 relating to the
issuance of $500,000,000 principal amount of 5.625% Senior Notes due
November 30, 2017(incorporated by reference from Pacific Gas and
Electric Company’s Current Report on Form 8-K dated March 14, 2007 (file
No. 1-2348), Exhibit 4.1)
|
|
|
4.4
|
Third
Supplemental Indenture dated as of March 3, 2008 relating to the issuance
of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due
February 15, 2038 (incorporated by reference to Pacific Gas and Electric
Company’s Current Report on Form 8-K dated March 3, 2008 (File No.
1-2348), Exhibit 4.1)
|
|
|
4.5
|
Fourth
Supplemental Indenture dated as of October 21, 2008 relating to the
Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25%
Senior Notes due October 15, 2018 (incorporated by reference to Pacific
Gas and Electric Company’s Current Report on Form 8-K dated October 21,
2008 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.6
|
Indenture
related to PG&E Corporation's 7.5% Convertible Subordinated Notes due
June 2007, dated as of June 25, 2002, between PG&E Corporation
and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E
Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609),
Exhibit 99.1).
|
|
|
4.7
|
Supplemental
Indenture related to PG&E Corporation's 9.50% Convertible Subordinated
Notes due June 2010, dated as of October 18, 2002, between PG&E
Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to
PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended
September 30, 2002 (File No. 1-12609),
Exhibit 4.1)
|
|
|
10.1
|
Amended
and Restated Unsecured Revolving Credit Agreement entered into among
Pacific Gas and Electric Company, Citicorp North America, Inc., as
administrative agent and a lender, JPMorgan Securities Inc., as
syndication agent, Barclays Bank Plc and BNP Paribas, as documentation
agents and lenders, Deutsche Bank Securities Inc., as documentation agent,
and other lenders, dated February 26, 2007 (incorporated by reference to
PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for
the quarter ended March 31, 2007 (File No. 1-12609 and File
No. 1-2348), Exhibit 10.2)
|
|
|
10.2
|
Amended
and Restated Unsecured Revolving Credit Agreement entered into among
PG&E Corporation, BNP Paribas, as administrative agent and a lender,
Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V.,
Bank of America, N.A., and Barclays Bank Plc, as documentation agents and
lenders, and other lenders, dated February 26, 2007 (incorporated by
reference to PG&E Corporation and Pacific Gas and Electric Company's
Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File
No. 1-12609 and File No. 1-2348),
Exhibit 10.2)
|
|
|
10.3
|
Settlement
Agreement among California Public Utilities Commission, Pacific Gas and
Electric Company and PG&E Corporation, dated as of December 19, 2003,
together with appendices (incorporated by reference to PG&E
Corporation's and Pacific Gas and Electric Company's Form 8-K filed
December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit
99)
|
|
|
10.4
|
Transmission
Control Agreement among the California Independent System Operator (CAISO)
and the Participating Transmission Owners, including Pacific Gas and
Electric Company, effective as of March 31, 1998, as amended (CAISO,
FERC Electric Tariff No. 7) (incorporated by reference to PG&E
Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the
year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348),
Exhibit 10.8)
|
|
|
10.5
|
Operating
Agreement, as amended on November 12, 2004, effective as of December 22,
2004, between the State of California Department of Water Resources and
Pacific Gas and Electric Company (incorporated by reference to PG&E
Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the
year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348),
Exhibit 10.9)
|
|
|
*10.6
|
PG&E
Corporation Supplemental Retirement Savings Plan amended effective as of
September 19, 2001, and frozen after December 31, 2004 (incorporated by
reference to PG&E Corporation’s Form 10-K for the year ended December
31, 2004) (File No. 1-12609), Exhibit 10.10)
|
|
|
*10.7
|
PG&E
Corporation 2005 Supplemental Retirement Savings Plan effective as of
January 1, 2005 (as amended to comply with Internal Revenue Code Section
409A regulations effective as of January 1, 2009)
|
|
|
*10.8
|
Letter
regarding Compensation Arrangement between PG&E Corporation and Peter
A. Darbee effective July 1, 2003 (incorporated by reference to PG&E
Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30,
2003 (File No. 1-12609), Exhibit 10.4)
|
|
|
*10.9
|
Restricted
Stock Award Agreement between PG&E Corporation and Peter A. Darbee
dated January 3, 2007 (incorporated by reference to PG&E Corporation's
and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2007 (File No. 1-12609 and File
No. 12348), Exhibit 10.3)
|
|
|
*10.10
|
Amendment
to January 3, 2007 Restricted Stock Agreement between PG&E Corporation
and Peter A. Darbee, effective May 9, 2008 (incorporated by reference to
PG&E Corporation's Form 10-Q for the quarter ended June 30, 2008 (File
No. 1-12609), Exhibit 10.1)
|
|
|
*10.11
|
Amended
and Restated Restricted Stock Unit Agreement between Peter A. Darbee and
PG&E Corporation (as amended to comply with Internal Revenue Code
Section 409A regulations effective as of January 1,
2009)
|
|
|
*10.12
|
Restricted
Stock Unit Agreement between Peter A. Darbee and PG&E Corporation
dated January 2, 2009
|
|
|
*10.13
|
Letter
regarding Compensation Arrangement between Pacific Gas and Electric
Company and William T. Morrow dated June 20, 2006 (incorporated by
reference to PG&E Corporation's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2006 (File No. 1-12609), Exhibit
10.1)
|
|
|
*10.14
|
Restricted
Stock Award Agreement between PG&E Corporation and William T. Morrow
dated January 29, 2007 (incorporated by reference to PG&E
Corporation's Quarterly Report on Form 10-Q for the quarter ended March
31, 2007 (File No. 1-12609), Exhibit 10.4)
|
|
|
*10.15
|
Performance
Share Agreement between PG&E Corporation and William T. Morrow dated
November 6, 2007 (incorporated by reference to PG&E Corporation’s Form
10-K for the year ended December 31, 2007) (File No. 1-12609), Exhibit
10.13)
|
|
|
*10.16
|
Restricted
Stock Award Agreement between PG&E Corporation and William T. Morrow
dated November 6, 2007 (incorporated by reference to PG&E
Corporation’s Form 10-K for the year ended December 31, 2007) (File No.
1-12609), Exhibit 10.14)
|
|
|
*10.17
|
Separation
Agreement between William T. Morrow and Pacific Gas and Electric Company
dated July 8, 2008 (incorporated by reference to PG&E Corporation's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 2008 (File No. 1-12609), Exhibit
10)
|
|
|
*10.18
|
Letter
regarding Compensation Arrangement between PG&E Corporation and Rand
L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E
Corporation’s Form 10-K for the year ended December 31, 2005) (File No.
1-12609), Exhibit 10.18)
|
|
|
*10.19
|
Letter
regarding Compensation Arrangement between PG&E Corporation and Hyun
Park dated October 10, 2006 (incorporated by reference to PG&E
Corporation’s Form 10-K for the year ended December 31, 2006) (File No.
1-12609), Exhibit 10.18)
|
|
|
*10.20
|
Letter
regarding Compensation Agreement between PG&E Corporation and G.
Robert Powell dated August 8, 2005 (incorporated by reference
to PG&E Corporation’s Form 10-K for the year ended December 31, 2007)
(File No. 1-12609), Exhibit 10.17)
|
|
|
*10.21
|
Letter
regarding Compensation Agreement between Pacific Gas and Electric Company
and John S. Keenan dated November 21, 2005
|
|
|
*10.22
|
Letter
regarding Compensation Agreement between Pacific Gas and Electric Company
and Barbara Barcon dated March 3, 2008 (incorporated by reference to
PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2008 (File No. 1-12609), Exhibit 10.3)
|
|
|
*10.23
|
Separation
Agreement between PG&E Corporation and G. Robert Powell dated March 6,
2008 (incorporated by reference to PG&E Corporation's Quarterly Report
on Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609),
Exhibit 10.4)
|
|
|
*10.24
|
PG&E
Corporation 2005 Deferred Compensation Plan for Non-Employee Directors,
effective as of January 1, 2005 (as amended to comply with Internal
Revenue Code Section 409A regulations effective as of January 1,
2009)
|
|
|
*10.25
|
Description
of Short-Term Incentive Plan for Officers of PG&E Corporation and its
subsidiaries, effective January 1, 2008 (incorporated by reference to
PG&E Corporation's Form 10-K for the year ended December 31, 2007
(File No. 1-12609), Exhibit 10.19)
|
|
|
*10.26
|
Description
of Short-Term Incentive Plan for Officers of PG&E Corporation and its
subsidiaries, effective January 1, 2009
|
|
|
*10.27
|
Amendment
to PG&E Corporation Short-Term Incentive Programs and Other Bonus
Programs, effective January 1, 2009 (amendment to comply with Internal
Revenue Code Section 409A regulations)
|
|
|
*10.28
|
Amendment
to Pacific Gas and Electric Company Short-Term Incentive Programs and
Other Bonus Programs, effective January 1, 2009 (amendment to comply with
Internal Revenue Code Section 409A regulations)
|
|
|
*10.29
|
Supplemental
Executive Retirement Plan of PG&E Corporation as amended effective as
of January 1, 2009 (amended to comply with Internal Revenue Code Section
409A Regulations)
|
|
|
*10.30
|
Pacific
Gas and Electric Company Relocation Assistance Program for
Officers
|
|
|
*10.31
|
Postretirement
Life Insurance Plan of the Pacific Gas and Electric Company (incorporated
by reference to Pacific Gas and Electric Company's Form 10-K for fiscal
year 1991 (File No. 1-2348), Exhibit 10.16)
|
|
|
*10.32
|
Amendment
to Postretirement Life Insurance Plan of the Pacific Gas and Electric
Company dated December 30, 2008 (amendment to comply with Internal Revenue
Code Section 409A regulations)
|
|
|
*10.33
|
PG&E
Corporation Non-Employee Director Stock Incentive Plan (a component of the
PG&E Corporation Long-Term Incentive Program) as amended effective as
of July 1, 2004 (reflecting amendments adopted by the PG&E Corporation
Board of Directors on June 16, 2004 set forth in resolutions filed as
Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric
Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
2004)
(incorporated by reference to PG&E Corporation’s and Pacific
Gas and Electric Company’s Form 10-K for the year ended December 31, 2004
(File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
|
|
|
*10.34
|
Resolution
of the PG&E Corporation Board of Directors dated February 20, 2008,
adopting director compensation arrangement effective January 1,
2008 (incorporated by reference to PG&E Corporation's and Pacific
Gas and Electric Company's Quarterly Report on Form 10-K for the year
ended December 31, 2007 (File No. 1-12609 and File No. 12348),
Exhibit 10.28)
|
|
|
*10.35
|
Resolution
of the Pacific Gas and Electric Company Board of Directors dated February
20, 2008, adopting director compensation arrangement effective January 1,
2008 (incorporated by reference to PG&E Corporation's and Pacific
Gas and Electric Company's Quarterly Report on Form 10-K for the year
ended December 31, 2007 (File No. 1-12609 and File No. 12348),
Exhibit 10.29)
|
|
|
*10.36
|
Resolution
of the PG&E Corporation Board of Directors dated September 17, 2008,
adopting director compensation arrangement effective January 1,
2009
|
|
|
*10.37
|
Resolution
of the Pacific Gas and Electric Company Board of Directors dated September
17, 2008, adopting director compensation arrangement effective January 1,
2009
|
|
|
*10.38
|
PG&E
Corporation 2006 Long-Term Incentive Plan, as amended through February 18,
2009
|
|
|
*10.39
|
PG&E
Corporation Long-Term Incentive Program (including the PG&E
Corporation Stock Option Plan and Performance Unit Plan), as amended May
16, 2001, (incorporated by reference to PG&E Corporation's Quarterly
Report on Form 10-Q for the quarter ended June 30, 2001 (File
No. 1-12609), Exhibit 10)
|
|
|
*10.40
|
Form
of Restricted Stock Award Agreement for 2004 grants made under the
PG&E Corporation Long-Term Incentive Program (incorporated by
reference to PG&E Corporation's Form 10-K for the year ended December
31, 2003 (File No. 1-12609), Exhibit 10.37)
|
|
|
*10.41
|
Form
of Restricted Stock Agreement for 2005 grants under the PG&E
Corporation Long-Term Incentive Program (incorporated by reference to
PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed
January 6, 2005 (File No. 12609 and File No. 1-2348),
Exhibit 99.3)
|
|
|
*10.42
|
Form
of Restricted Stock Agreement for 2006 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed
January 9, 2006, Exhibit 99.1)
|
|
|
*10.43
|
Form
of Restricted Stock Agreement for 2007 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the
PG&E Corporation 2006 Long-Term Incentive Plan made on February 15,
2006) (incorporated by reference to PG&E Corporation's Form 10-K for
the year ended December 31, 2006 (File No. 1-12609),
Exhibit 10.39)
|
|
|
*10.44
|
Form
of Restricted Stock Agreement for 2008 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation's Form 10-Q for the quarter ended March 31, 2008
(File No. 1-12609), Exhibit 10.5)
|
|
|
*10.45
|
Form
of Amendment to Restricted Stock Agreements for grants made between
January 2005 and March 2008 (amendments to comply with Internal Revenue
Code Section 409A Regulations)
|
|
|
*10.46
|
Form
of Non-Qualified Stock Option Agreement under the PG&E Corporation
Long-Term Incentive Program (incorporated by reference to PG&E
Corporation and Pacific Gas and Electric Company's Form 8-K filed
January 6, 2005 (File No. 12609 and File No. 1-2348),
Exhibit 99.1)
|
|
|
*10.47
|
Form
of Performance Share Agreement for 2005 grants under the PG&E
Corporation Long-Term Incentive Program (incorporated by reference to
PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed
January 6, 2005 (File No. 12609 and File No. 1-2348),
Exhibit 99.2)
|
|
|
*10.48
|
Form
of Performance Share Agreement for 2006 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed
January 9, 2006, Exhibit 99.2)
|
|
|
*10.49
|
Form
of Performance Share Agreement for 2007 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the
PG&E Corporation 2006 Long-Term Incentive Plan made on February 15,
2006) (incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2006 (File No. 1-12609),
Exhibit 10.44)
|
|
|
*10.50
|
Form
of Performance Share Agreement for 2008 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation's Form 10-Q for the quarter ended March 31, 2008
(File No. 1-12609), Exhibit 10.6)
|
|
|
*10.51
|
|
Form
of Amended and Restated Performance Share Agreement for 2006 grants
(amendments to comply with Internal Revenue Code Section 409A
Regulations)
|
|
*10.52
|
Form
of Amended and Restated Performance Share Agreement for 2007 grants
(amendments to comply with Internal Revenue Code Section 409A
Regulations)
|
|
|
*10.53
|
Form
of Amended and Restated Performance Share Agreement for 2008 grants
(amendments to comply with Internal Revenue Code Section 409A
Regulations)
|
|
|
*10.54
|
PG&E
Corporation Executive Stock Ownership Program Guidelines as amended
effective February 17, 2009
|
|
|
*10.55
|
PG&E
Corporation Officer Severance Policy, as amended effective as of February
15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2005 (File No. 1-12609),
Exhibit 10.48)
|
|
|
*10.56
|
PG&E
Corporation Officer Severance Policy, as amended effective as of January
1, 2009 (amended to comply with Internal Revenue Code Section 409A
regulations)
|
|
|
*10.57
|
PG&E
Corporation Golden Parachute Restriction Policy effective as of February
15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2005 (File No. 1-12609),
Exhibit 10.49)
|
|
|
*10.58
|
Amendment
to PG&E Corporation Golden Parachute Restriction Policy dated December
31, 2008 (amendment to comply with Internal Revenue Code Section 409A
Regulations)
|
|
|
*10.59
|
PG&E
Corporation Director Grantor Trust Agreement dated April 1, 1998
(incorporated by reference to PG&E Corporation's Quarterly Report on
Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609),
Exhibit 10.1)
|
|
|
*10.60
|
PG&E
Corporation Officer Grantor Trust Agreement dated April 1, 1998, as
updated effective January 1, 2005 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2004 (File
No. 1-12609), Exhibit 10.39)
|
|
|
*10.61
|
Resolution
of the Board of Directors of PG&E Corporation regarding
indemnification of officers and directors dated December 18, 1996
(incorporated by reference to PG&E Corporation's Form 10-K for the
year ended December 31, 2004 (File No. 1-12609),
Exhibit 10.40)
|
|
|
*10.62
|
Resolution
of the Board of Directors of Pacific Gas and Electric Company regarding
indemnification of officers and directors dated July 19, 1995
(incorporated by reference to Pacific Gas and Electric Company’s Form 10-K
for the year ended December 31, 2004 (File No. 1-2348),
Exhibit 10.41)
|
|
|
11
|
Computation
of Earnings Per Common Share
|
|
|
12.1
|
Computation
of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric
Company
|
|
|
12.2
|
Computation
of Ratios of Earnings to Combined Fixed Charges and Preferred Stock
Dividends for Pacific Gas and Electric Company
|
|
|
13
|
The
following portions of the 2008 Annual Report to Shareholders of PG&E
Corporation and Pacific Gas and Electric Company are included: “Selected
Financial Data,” “Management's Discussion and Analysis of Financial
Condition and Results of Operations,” financial statements of PG&E
Corporation entitled “Consolidated Statements of Income,” “Consolidated
Balance Sheets,” “Consolidated Statements of Cash Flows,” and
“Consolidated Statements of Shareholders' Equity,” financial statements of
Pacific Gas and Electric Company entitled “Consolidated Statements of
Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash
Flows,” and “Consolidated Statements of Shareholders' Equity,” “Notes to
the Consolidated Financial Statements,” “Quarterly Consolidated Financial
Data (Unaudited),” “Management's Report on Internal Control Over Financial
Reporting,” and “Report of Independent Registered Public Accounting
Firm.”
|
|
|
21
|
Subsidiaries
of the Registrant
|
|
|
23
|
Consent
of Independent Registered Public Accounting Firm (Deloitte & Touche
LLP)
|
|
|
24.1
|
Resolutions
of the Boards of Directors of PG&E Corporation and Pacific Gas and
Electric Company authorizing the execution of the Form
10-K
|
|
|
24.2
|
Powers
of Attorney
|
|
|
31.1
|
Certifications
of the Chief Executive Officer and the Chief Financial Officer of PG&E
Corporation required by Section 302 of the Sarbanes-Oxley Act of
2002
|
|
|
31.2
|
Certifications
of the Chief Executive Officer and the Chief Financial Officer of Pacific
Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act
of 2002
|
|
|
**32.1
|
Certifications
of the Chief Executive Officer and the Chief Financial Officer of PG&E
Corporation required by Section 906 of the Sarbanes-Oxley Act of
2002
|
|
|
**32.2
|
Certifications
of the Chief Executive Officer and the Chief Financial Officer of Pacific
Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act
of 2002
|
*
Management contract or compensatory agreement.
** Pursuant
to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather
than filed with this report.
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrants have duly caused this Annual Report on Form 10-K
for the year ended December 31, 2008 to be signed on their behalf by the
undersigned, thereunto duly authorized.
|
PG&E
CORPORATION
|
PACIFIC
GAS AND ELECTRIC COMPANY
|
||
|
(Registrant)
*PETER
A. DARBEE
|
(Registrant)
*PETER
A. DARBEE
|
||
|
By:
|
Peter
A. Darbee
Chairman
of the Board, Chief Executive Officer,
and
President
|
By:
|
Peter
A. Darbee
President
and Chief Executive Officer
|
|
Date:
|
February
24, 2009
|
Date:
|
February
24, 2009
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrants and in the
capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
|||||||
|
A.
Principal Executive Officers
|
|||||||||
|
*PETER
A. DARBEE
|
Chairman
of the Board, Chief Executive Officer, President, and Director (PG&E
Corporation)
|
February
24, 2009
|
|||||||
|
Peter
A. Darbee
|
|||||||||
|
President
and Chief Executive Officer (Pacific Gas and Electric
Company)
|
|||||||||
|
|
|||||||||
|
B. Principal
Financial Officers
|
|||||||||
|
*CHRISTOPHER
P. JOHNS
|
Senior
Vice President, Chief Financial Officer, and Treasurer (PG&E
Corporation)
|
February
24, 2009
|
|||||||
|
Christopher
P. Johns
|
|||||||||
|
*BARBARA
L. BARCON
|
Vice
President, Finance and Chief Financial Officer
(Pacific
Gas and Electric Company)
|
February
24, 2009
|
|||||||
|
Barbara
L. Barcon
|
|||||||||
|
C.
Principal Accounting Officer
|
|||||||||
|
*STEPHEN
J. CAIRNS
|
Vice
President and Controller (PG&E Corporation and (Pacific Gas and
Electric Company)
|
February
24, 2009
|
|||||||
|
*Stephen
J. Cairns
|
|||||||||
|
D.
Directors
|
|||||||||
|
*DAVID
R. ANDREWS
|
Director
|
February
24, 2009
|
|||||||
|
David
R. Andrews
|
|||||||||
|
*C.
LEE COX
|
Director
|
February
24, 2009
|
|||||||
|
C.
Lee Cox
|
|||||||||
|
*MARYELLEN
C. HERRINGER
|
Director
|
February
24, 2009
|
|||||||
|
Maryellen
C. Herringer
|
|||||||||
|
*ROGER
H. KIMMEL
|
Director
|
February
24, 2009
|
|||||||
|
Roger
H. Kimmel
|
|||||||||
|
*RICHARD
A. MESERVE
|
Director
|
February
24, 2009
|
|||||||
|
Richard
A. Meserve
|
|||||||||
|
*MARY
S. METZ
|
Director
|
February
24, 2009
|
|||||||
|
Mary
S. Metz
|
|||||||||
|
|
|||||||||
|
*FORREST
E. MILLER
|
Director
|
February
24, 2009
|
|||||||
|
Forrest
E. Miller
|
|||||||||
|
*BARBARA
L. RAMBO
|
Director
|
February
24, 2009
|
|||||||
|
Barbara
L. Rambo
|
|||||||||
|
*BARRY
LAWSON WILLIAMS
|
Director
|
February
24, 2009
|
|||||||
|
Barry
Lawson Williams
|
|||||||||
|
*By:
|
HYUN
PARK
|
||||||||
|
HYUN
PARK, Attorney-in-Fact
|
|||||||||
|
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
|
To the
Board of Directors and Shareholders of
PG&E
Corporation and Pacific Gas and Electric Company
San
Francisco, California
We have
audited the consolidated financial statements of PG&E Corporation and
subsidiaries (the “Company”) and Pacific Gas and Electric Company and
subsidiaries (the “Utility”) as of December 31, 2008 and 2007, and for each
of the three years in the period ended December 31, 2008, and the Company’s
and the Utility’s internal control over financial reporting as of
December 31, 2008, and have issued our report thereon dated
February 19, 2009 (which expresses an unqualified opinion and includes for
the Company and Utility an explanatory paragraph stating that in January
2008 new accounting standards were adopted for addressing fair value measurement
and an amendment to an interpretation of accounting standards for offsetting
amounts related to certain contracts, in 2007 a new interpretation of accounting
standards for uncertainty in income taxes, and in 2006 new accounting standards
for defined benefit pensions and other postretirement plans and share-based
payments); such consolidated financial statements and our report are included in
your 2008 Annual Report to Shareholders of the Company and the Utility and are
incorporated herein by reference. Our audits also included the consolidated
financial statement schedules of the Company and Utility listed in
Item 15(a)2. These consolidated financial statement schedules are the
responsibility of the Company’s and the Utility’s management. Our responsibility
is to express an opinion based on our audits. In our opinion, such consolidated
financial statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present fairly, in all
material respects, the information set forth therein.
DELOITTE
& TOUCHE LLP
February 19,
2009
San Francisco, CA
PG&E
CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF
PARENT
CONDENSED
STATEMENTS OF INCOME
(in
millions, except per share amounts)
|
Year
Ended December 31,
|
|||
|
2008
|
2007
|
2006
|
|
|
Administrative
service revenue
|
119
|
102
|
110
|
|
Equity
in earnings of subsidiaries
|
1,182
|
1,006
|
964
|
|
Operating
expenses
|
(105)
|
(112)
|
(115)
|
|
Interest
income
|
4
|
15
|
15
|
|
Interest
expense
|
(30)
|
(31)
|
(30)
|
|
Other
income (expense)
|
(46)
|
(6)
|
(1)
|
|
Income
before income taxes
|
1,124
|
974
|
943
|
|
Income
tax benefit
|
60
|
32
|
48
|
|
Income
from continuing operations
|
1,184
|
1,006
|
991
|
|
Gain
on disposal of NEGT
|
154
|
-
|
-
|
|
Net
income before intercompany eliminations
|
1,338
|
1,006
|
991
|
|
Weighted
average common shares outstanding, basic
|
357
|
351
|
346
|
|
Weighted
average common shares outstanding, diluted
|
358
|
353
|
349
|
|
Earnings
per common share, basic(1)
|
$3.64
|
$2.79
|
$2.78
|
|
Earnings
per common share, diluted(1)
|
$3.63
|
$2.78
|
$2.76
|
(1)PG&E
Corporation adopted the consensus reached by Emerging Issues Task Force, or
EITF, in EITF issue No. 03-06, "Participating Securities and the Two-Class
Method under FASB Statement No. 128," or EITF 03-06, as ratified by the
Financial Accounting Standards Board on March 31, 2004.
PG&E
Corporation currently has outstanding $280 million principal amount of
convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are
entitled to receive (non-cumulative) dividend payments without exercising the
conversion option. These Convertible Notes, which were issued in June 2002,
meet the criteria of a participating security in the calculation of earnings per
share using the "two-class" method.
Accordingly,
the basic and diluted earnings per share calculations for each of the years in
the three year period ended December 31, 2008 reflect the allocation of
earnings between PG&E Corporation common stock and the participating
security.
PG&E
CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF
PARENT – (Continued)
CONDENSED
BALANCE SHEETS
(in
millions)
|
Balance at
December 31,
|
||
|
2008
|
2007
|
|
|
ASSETS
|
||
|
Current
Assets:
|
||
|
Cash
and cash equivalents
|
$
167
|
$
204
|
|
Advances
to affiliates
|
28
|
30
|
|
Income
taxes receivable
|
148
|
46
|
|
Other
current assets
|
14
|
3
|
|
Total
current assets
|
357
|
283
|
|
Equipment
|
17
|
17
|
|
Accumulated
depreciation
|
(15)
|
(15)
|
|
Net
equipment
|
2
|
2
|
|
Investments
in subsidiaries
|
9,539
|
8,886
|
|
Other
investments
|
68
|
87
|
|
Deferred
income taxes
|
51
|
51
|
|
Other
|
4
|
9
|
|
Total
Assets
|
$
10,021
|
$
9,318
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||
|
Current
Liabilities:
|
||
|
Accounts
payable—related parties
|
$
34
|
$
40
|
|
Accounts
payable—other
|
18
|
24
|
|
Other
|
189
|
174
|
|
Total
current liabilities
|
241
|
238
|
|
Noncurrent
Liabilities:
|
||
|
Long-term
debt
|
280
|
280
|
|
Income
taxes payable
|
23
|
131
|
|
Other
|
100
|
116
|
|
Total
noncurrent liabilities
|
403
|
527
|
|
Common
Shareholders' Equity
|
||
|
Common
stock
|
5,984
|
6,110
|
|
Common
stock held by subsidiary
|
-
|
(718)
|
|
Reinvested
earnings
|
3,614
|
3,151
|
|
Accumulated
other comprehensive income
|
(221)
|
10
|
|
Total
common shareholders' equity
|
9,377
|
8,553
|
|
Total
Liabilities and Shareholders' Equity
|
$
10,021
|
$
9,318
|
PG&E
CORPORATION
SCHEDULE
I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED
STATEMENTS OF CASH FLOWS
(in
millions)
|
Year
Ended December 31,
|
||||||||||
|
2008
|
2007
|
2006
|
||||||||
|
Cash
Flows from Operating Activities:
|
||||||||||
|
Net
income
|
$
|
1,338
|
$
|
1,006
|
$
|
991
|
||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||||
|
Depreciation
and amortization
|
3
|
1
|
-
|
|||||||
|
Equity
in earnings of subsidiaries
|
(1,180)
|
(1,006)
|
(964)
|
|||||||
|
Noncurrent
income taxes receivable/payable
|
(108)
|
4
|
-
|
|||||||
|
Other
|
(81)
)
|
(19)
)
|
132
|
|||||||
|
Net
cash used in operating activities
|
(28)
|
24
|
159
|
|||||||
|
Cash
Flows From Investing Activities:
|
||||||||||
|
Capital
expenditures
|
-
|
(1)
|
(1)
|
|||||||
|
Investment
in subsidiaries
|
(275)
|
(405)
|
-
|
|||||||
|
Dividends
received from subsidiaries
|
596
|
509
|
460
|
|||||||
|
Other
|
(12)
|
-
|
-
|
|||||||
|
Net
cash provided by investing activities
|
309
|
103
|
459
|
|||||||
|
Cash
Flows From Financing Activities(1):
|
||||||||||
|
Common
stock issued
|
225
|
175
|
131
|
|||||||
|
Common
stock repurchased
|
-
|
-
|
(114)
|
|||||||
|
Common
stock dividends paid
|
(546)
|
(496)
|
(456)
|
|||||||
|
Other
|
2
|
12
|
(43)
|
|||||||
|
Net
cash used in financing activities
|
(319)
|
(309)
|
(482)
|
|||||||
|
Net
change in cash and cash equivalents
|
(38)
|
(182)
|
136
|
|||||||
|
Cash
and cash equivalents at January 1
|
204
|
386
|
250
|
|||||||
|
Cash
and cash equivalents at December 31
|
$
|
166
|
$
|
204
|
$
|
386
|
||||
|
(1)
On January 15, 2008, PG&E Corporation paid a quarterly common
stock dividend of $0.36 per share. On April 15, July 15, and
October 15, 2008, PG&E Corporation paid quarterly common stock
dividends of $0.39 per share. Of the total dividend payments
made by PG&E Corporation in 2008, approximately $28 million was paid
to Elm Power Corporation, a wholly owned subsidiary of PG&E
Corporation.
On
January 15, 2007, PG&E Corporation paid a quarterly common stock
dividend of $0.33 per share. On April 15, July 15, and October
15, 2007, PG&E Corporation paid quarterly common stock dividends of
$0.36 per share. Of the total dividend payments made by
PG&E Corporation in 2007, approximately $35 million was paid to Elm
Power Corporation, a wholly owned subsidiary of PG&E
Corporation.
On
January 16, April 15, July 15, and October 15, 2006, PG&E Corporation
paid a quarterly common stock dividend of $0.33 per share, totaling
approximately $489 million. Of the total dividend payments made
by PG&E Corporation in 2006, approximately $33 million was paid to Elm
Power Corporation, a wholly owned subsidiary of PG&E
Corporation.
|
||||||||||
PG&E
Corporation
SCHEDULE
II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For
the Years Ended December 31, 2008, 2007, and 2006
|
Additions
|
|||||
|
Description
|
Balance
at Beginning of Period
|
Charged
to Costs and Expenses
|
Charged
to Other Accounts
|
Deductions(3)
|
Balance
at End of Period
|
|
(in
millions)
|
|||||
|
Valuation
and qualifying accounts deducted from assets:
|
|||||
|
2008:
|
|||||
|
Allowance
for uncollectible accounts(1)(2)
|
$
58
|
$
68
|
$
11
|
$
61
|
$
76
|
|
2007:
|
|||||
|
Allowance
for uncollectible accounts(1)(2)
|
$
50
|
$
20
|
$
-
|
$
12
|
$
58
|
|
2006:
|
|||||
|
Allowance
for uncollectible accounts(1)(2)
|
$
77
|
$
2
|
$
-
|
$
29
|
$
50
|
|
(1)
Allowance for uncollectible accounts is deducted from “Accounts receivable
Customers, net.”
|
|||||
|
(2)
Allowance for uncollectible accounts does not include
NEGT.
|
|||||
|
(3)
Deductions consist principally of write-offs, net of collections of
receivables previously written
off.
|
|||||
Pacific
Gas and Electric Company
SCHEDULE
II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For
the Years Ended December 31, 2008, 2007, and 2006
|
Additions
|
|||||
|
Description
|
Balance
at Beginning of Period
|
Charged
to Costs and Expenses
|
Charged
to Other Accounts
|
Deductions(2)
|
Balance
at End of Period
|
|
(in
millions)
|
|||||
|
Valuation
and qualifying accounts deducted from assets:
|
|||||
|
2008:
|
|||||
|
Allowance
for uncollectible accounts(1)
|
$
58
|
$
68
|
$
11
|
$
61
|
$
76
|
|
2007:
|
|||||
|
Allowance
for uncollectible accounts(1)
|
$
50
|
$
20
|
$
-
|
$
12
|
$
58
|
|
2006:
|
|||||
|
Allowance
for uncollectible accounts(1)
|
$
77
|
$
2
|
$
-
|
$
29
|
$
50
|
|
(1)
Allowance for uncollectible accounts is deducted from “Accounts receivable
Customers, net.”
|
|||||
|
(2)
Deductions consist principally of write-offs, net of collections of
receivables previously written off.
|
|||||
EXHIBIT
INDEX
|
Exhibit
Number
|
Exhibit
Description
|
|
|
2.1
|
Order
of the U.S. Bankruptcy Court for the Northern District of California dated
December 22, 2003, Confirming Plan of Reorganization of Pacific Gas
and Electric Company, including Plan of Reorganization, dated July 31,
2003 as modified by modifications dated November 6, 2003 and December 19,
2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of
Reorganization omitted) (incorporated by reference to Pacific Gas and
Electric Company's Registration Statement on Form S-3 No. 333-109994,
Exhibit 2.1)
|
|
|
2.2
|
Order
of the U.S. Bankruptcy Court for the Northern District of California dated
February 27, 2004 Approving Technical Corrections to Plan of
Reorganization of Pacific Gas and Electric Company and Supplementing
Confirmation Order to Incorporate such Corrections (incorporated by
reference to Pacific Gas and Electric Company's Registration Statement on
Form S-3 No. 333-109994, Exhibit 2.2)
|
|
|
3.1
|
Restated
Articles of Incorporation of PG&E Corporation effective as of May 29,
2002 (incorporated by reference to PG&E Corporation's Quarterly Report
on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609),
Exhibit 3.1)
|
|
|
3.2
|
Certificate
of Determination for PG&E Corporation Series A Preferred Stock filed
December 22, 2000 (incorporated by reference to PG&E Corporation's
Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit
3.2)
|
|
|
3.3
|
Bylaws
of PG&E Corporation amended as of January 1, 2009
|
|
|
3.4
|
Restated
Articles of Incorporation of Pacific Gas and Electric Company effective as
of April 12, 2004 (incorporated by reference to Pacific Gas and
Electric Company's Form 8-K filed April 12, 2004 (File
No. 1-2348), Exhibit 3)
|
|
|
3.5
|
Bylaws
of Pacific Gas and Electric Company amended as of January 1,
2009
|
|
|
4.1
|
Indenture,
dated as of April 22, 2005, supplementing, amending and restating the
Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a
First Supplemental Indenture, dated as of March 23, 2004, and a Second
Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas
and Electric Company and The Bank of New York Trust Company, N.A.
(incorporated by reference to PG&E Corporation and Pacific Gas and
Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File
No. 1-2348), Exhibit 4.1)
|
|
|
4.2
|
First
Supplemental Indenture dated as of March 13, 2007 relating to the issuance
of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037
(incorporated by reference from Pacific Gas and Electric Company’s Current
Report on Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit
4.1)
|
|
|
4.3
|
Second
Supplemental Indenture dated as of December 4, 2007 relating to the
issuance of $500,000,000 principal amount of 5.625% Senior Notes due
November 30, 2017(incorporated by reference from Pacific Gas and
Electric Company’s Current Report on Form 8-K dated March 14, 2007 (file
No. 1-2348), Exhibit 4.1)
|
|
|
4.4
|
Third
Supplemental Indenture dated as of March 3, 2008 relating to the issuance
of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due
February 15, 2038 (incorporated by reference to Pacific Gas and Electric
Company’s Current Report on Form 8-K dated March 3, 2008 (File No.
1-2348), Exhibit 4.1)
|
|
|
4.5
|
Fourth
Supplemental Indenture dated as of October 21, 2008 relating to the
Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25%
Senior Notes due October 15, 2018 (incorporated by reference to Pacific
Gas and Electric Company’s Current Report on Form 8-K dated October 21,
2008 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.6
|
Indenture
related to PG&E Corporation's 7.5% Convertible Subordinated Notes due
June 2007, dated as of June 25, 2002, between PG&E Corporation
and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E
Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609),
Exhibit 99.1).
|
|
|
4.7
|
Supplemental
Indenture related to PG&E Corporation's 9.50% Convertible Subordinated
Notes due June 2010, dated as of October 18, 2002, between PG&E
Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to
PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended
September 30, 2002 (File No. 1-12609),
Exhibit 4.1)
|
|
|
10.1
|
Amended
and Restated Unsecured Revolving Credit Agreement entered into among
Pacific Gas and Electric Company, Citicorp North America, Inc., as
administrative agent and a lender, JPMorgan Securities Inc., as
syndication agent, Barclays Bank Plc and BNP Paribas, as documentation
agents and lenders, Deutsche Bank Securities Inc., as documentation agent,
and other lenders, dated February 26, 2007 (incorporated by reference to
PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for
the quarter ended March 31, 2007 (File No. 1-12609 and File
No. 1-2348), Exhibit 10.2)
|
|
|
10.2
|
Amended
and Restated Unsecured Revolving Credit Agreement entered into among
PG&E Corporation, BNP Paribas, as administrative agent and a lender,
Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V.,
Bank of America, N.A., and Barclays Bank Plc, as documentation agents and
lenders, and other lenders, dated February 26, 2007 (incorporated by
reference to PG&E Corporation and Pacific Gas and Electric Company's
Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File
No. 1-12609 and File No. 1-2348),
Exhibit 10.2)
|
|
|
10.3
|
Settlement
Agreement among California Public Utilities Commission, Pacific Gas and
Electric Company and PG&E Corporation, dated as of December 19, 2003,
together with appendices (incorporated by reference to PG&E
Corporation's and Pacific Gas and Electric Company's Form 8-K filed
December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit
99)
|
|
|
10.4
|
Transmission
Control Agreement among the California Independent System Operator (CAISO)
and the Participating Transmission Owners, including Pacific Gas and
Electric Company, effective as of March 31, 1998, as amended (CAISO,
FERC Electric Tariff No. 7) (incorporated by reference to PG&E
Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the
year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348),
Exhibit 10.8)
|
|
|
10.5
|
Operating
Agreement, as amended on November 12, 2004, effective as of December 22,
2004, between the State of California Department of Water Resources and
Pacific Gas and Electric Company (incorporated by reference to PG&E
Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the
year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348),
Exhibit 10.9)
|
|
|
*10.6
|
PG&E
Corporation Supplemental Retirement Savings Plan amended effective as of
September 19, 2001, and frozen after December 31, 2004 (incorporated by
reference to PG&E Corporation’s Form 10-K for the year ended December
31, 2004) (File No. 1-12609), Exhibit 10.10)
|
|
|
*10.7
|
PG&E
Corporation 2005 Supplemental Retirement Savings Plan effective as of
January 1, 2005 (as amended to comply with Internal Revenue Code Section
409A regulations effective as of January 1, 2009)
|
|
|
*10.8
|
Letter
regarding Compensation Arrangement between PG&E Corporation and Peter
A. Darbee effective July 1, 2003 (incorporated by reference to PG&E
Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30,
2003 (File No. 1-12609), Exhibit 10.4)
|
|
|
*10.9
|
Restricted
Stock Award Agreement between PG&E Corporation and Peter A. Darbee
dated January 3, 2007 (incorporated by reference to PG&E Corporation's
and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2007 (File No. 1-12609 and File
No. 12348), Exhibit 10.3)
|
|
|
*10.10
|
Amendment
to January 3, 2007 Restricted Stock Agreement between PG&E Corporation
and Peter A. Darbee, effective May 9, 2008 (incorporated by reference to
PG&E Corporation's Form 10-Q for the quarter ended June 30, 2008 (File
No. 1-12609), Exhibit 10.1)
|
|
|
*10.11
|
Amended
and Restated Restricted Stock Unit Agreement between Peter A. Darbee and
PG&E Corporation (as amended to comply with Internal Revenue Code
Section 409A regulations effective as of January 1,
2009)
|
|
|
*10.12
|
Restricted
Stock Unit Agreement between Peter A. Darbee and PG&E Corporation
dated January 2, 2009
|
|
|
*10.13
|
Letter
regarding Compensation Arrangement between Pacific Gas and Electric
Company and William T. Morrow dated June 20, 2006 (incorporated by
reference to PG&E Corporation's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2006 (File No. 1-12609), Exhibit
10.1)
|
|
|
*10.14
|
Restricted
Stock Award Agreement between PG&E Corporation and William T. Morrow
dated January 29, 2007 (incorporated by reference to PG&E
Corporation's Quarterly Report on Form 10-Q for the quarter ended March
31, 2007 (File No. 1-12609), Exhibit 10.4)
|
|
|
*10.15
|
Performance
Share Agreement between PG&E Corporation and William T. Morrow dated
November 6, 2007 (incorporated by reference to PG&E Corporation’s Form
10-K for the year ended December 31, 2007) (File No. 1-12609), Exhibit
10.13)
|
|
|
*10.16
|
Restricted
Stock Award Agreement between PG&E Corporation and William T. Morrow
dated November 6, 2007 (incorporated by reference to PG&E
Corporation’s Form 10-K for the year ended December 31, 2007) (File No.
1-12609), Exhibit 10.14)
|
|
|
*10.17
|
Separation
Agreement between William T. Morrow and Pacific Gas and Electric Company
dated July 8, 2008 (incorporated by reference to PG&E Corporation's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 2008 (File No. 1-12609), Exhibit
10)
|
|
|
*10.18
|
Letter
regarding Compensation Arrangement between PG&E Corporation and Rand
L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E
Corporation’s Form 10-K for the year ended December 31, 2005) (File No.
1-12609), Exhibit 10.18)
|
|
|
*10.19
|
Letter
regarding Compensation Arrangement between PG&E Corporation and Hyun
Park dated October 10, 2006 (incorporated by reference to PG&E
Corporation’s Form 10-K for the year ended December 31, 2006) (File No.
1-12609), Exhibit 10.18)
|
|
|
*10.20
|
Letter
regarding Compensation Agreement between PG&E Corporation and G.
Robert Powell dated August 8, 2005 (incorporated by reference
to PG&E Corporation’s Form 10-K for the year ended December 31, 2007)
(File No. 1-12609), Exhibit 10.17)
|
|
|
*10.21
|
Letter
regarding Compensation Agreement between Pacific Gas and Electric Company
and John S. Keenan dated November 21, 2005
|
|
|
*10.22
|
Letter
regarding Compensation Agreement between Pacific Gas and Electric Company
and Barbara Barcon dated March 3, 2008 (incorporated by reference to
PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2008 (File No. 1-12609), Exhibit 10.3)
|
|
|
*10.23
|
Separation
Agreement between PG&E Corporation and G. Robert Powell dated March 6,
2008 (incorporated by reference to PG&E Corporation's Quarterly Report
on Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609),
Exhibit 10.4)
|
|
|
*10.24
|
PG&E
Corporation 2005 Deferred Compensation Plan for Non-Employee Directors,
effective as of January 1, 2005 (as amended to comply with Internal
Revenue Code Section 409A regulations effective as of January 1,
2009)
|
|
|
*10.25
|
Description
of Short-Term Incentive Plan for Officers of PG&E Corporation and its
subsidiaries, effective January 1, 2008 (incorporated by reference to
PG&E Corporation's Form 10-K for the year ended December 31, 2007
(File No. 1-12609), Exhibit 10.19)
|
|
|
*10.26
|
Description
of Short-Term Incentive Plan for Officers of PG&E Corporation and its
subsidiaries, effective January 1, 2009
|
|
|
*10.27
|
Amendment
to PG&E Corporation Short-Term Incentive Programs and Other Bonus
Programs, effective January 1, 2009 (amendment to comply with Internal
Revenue Code Section 409A regulations)
|
|
|
*10.28
|
Amendment
to Pacific Gas and Electric Company Short-Term Incentive Programs and
Other Bonus Programs, effective January 1, 2009 (amendment to comply with
Internal Revenue Code Section 409A regulations)
|
|
|
*10.29
|
Supplemental
Executive Retirement Plan of PG&E Corporation as amended effective as
of January 1, 2009 (amended to comply with Internal Revenue Code Section
409A Regulations)
|
|
|
*10.30
|
Pacific
Gas and Electric Company Relocation Assistance Program for
Officers
|
|
|
*10.31
|
Postretirement
Life Insurance Plan of the Pacific Gas and Electric Company (incorporated
by reference to Pacific Gas and Electric Company's Form 10-K for fiscal
year 1991 (File No. 1-2348), Exhibit 10.16)
|
|
|
*10.32
|
Amendment
to Postretirement Life Insurance Plan of the Pacific Gas and Electric
Company dated December 30, 2008 (amendment to comply with Internal Revenue
Code Section 409A regulations)
|
|
|
*10.33
|
PG&E
Corporation Non-Employee Director Stock Incentive Plan (a component of the
PG&E Corporation Long-Term Incentive Program) as amended effective as
of July 1, 2004 (reflecting amendments adopted by the PG&E Corporation
Board of Directors on June 16, 2004 set forth in resolutions filed as
Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric
Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
2004)
(incorporated by reference to PG&E Corporation’s and Pacific
Gas and Electric Company’s Form 10-K for the year ended December 31, 2004
(File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
|
|
|
*10.34
|
Resolution
of the PG&E Corporation Board of Directors dated February 20, 2008,
adopting director compensation arrangement effective January 1,
2008 (incorporated by reference to PG&E Corporation's and Pacific
Gas and Electric Company's Quarterly Report on Form 10-K for the year
ended December 31, 2007 (File No. 1-12609 and File No. 12348),
Exhibit 10.28)
|
|
|
*10.35
|
Resolution
of the Pacific Gas and Electric Company Board of Directors dated February
20, 2008, adopting director compensation arrangement effective January 1,
2008 (incorporated by reference to PG&E Corporation's and Pacific
Gas and Electric Company's Quarterly Report on Form 10-K for the year
ended December 31, 2007 (File No. 1-12609 and File No. 12348),
Exhibit 10.29)
|
|
|
*10.36
|
Resolution
of the PG&E Corporation Board of Directors dated September 17, 2008,
adopting director compensation arrangement effective January 1,
2009
|
|
|
*10.37
|
Resolution
of the Pacific Gas and Electric Company Board of Directors dated September
17, 2008, adopting director compensation arrangement effective January 1,
2009
|
|
|
*10.38
|
PG&E
Corporation 2006 Long-Term Incentive Plan, as amended through February 18,
2009
|
|
|
*10.39
|
PG&E
Corporation Long-Term Incentive Program (including the PG&E
Corporation Stock Option Plan and Performance Unit Plan), as amended May
16, 2001, (incorporated by reference to PG&E Corporation's Quarterly
Report on Form 10-Q for the quarter ended June 30, 2001 (File
No. 1-12609), Exhibit 10)
|
|
|
*10.40
|
Form
of Restricted Stock Award Agreement for 2004 grants made under the
PG&E Corporation Long-Term Incentive Program (incorporated by
reference to PG&E Corporation's Form 10-K for the year ended December
31, 2003 (File No. 1-12609), Exhibit 10.37)
|
|
|
*10.41
|
Form
of Restricted Stock Agreement for 2005 grants under the PG&E
Corporation Long-Term Incentive Program (incorporated by reference to
PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed
January 6, 2005 (File No. 12609 and File No. 1-2348),
Exhibit 99.3)
|
|
|
*10.42
|
Form
of Restricted Stock Agreement for 2006 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed
January 9, 2006, Exhibit 99.1)
|
|
|
*10.43
|
Form
of Restricted Stock Agreement for 2007 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the
PG&E Corporation 2006 Long-Term Incentive Plan made on February 15,
2006) (incorporated by reference to PG&E Corporation's Form 10-K for
the year ended December 31, 2006 (File No. 1-12609),
Exhibit 10.39)
|
|
|
*10.44
|
Form
of Restricted Stock Agreement for 2008 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation's Form 10-Q for the quarter ended March 31, 2008
(File No. 1-12609), Exhibit 10.5)
|
|
|
*10.45
|
Form
of Amendment to Restricted Stock Agreements for grants made between
January 2005 and March 2008 (amendments to comply with Internal Revenue
Code Section 409A Regulations)
|
|
|
*10.46
|
Form
of Non-Qualified Stock Option Agreement under the PG&E Corporation
Long-Term Incentive Program (incorporated by reference to PG&E
Corporation and Pacific Gas and Electric Company's Form 8-K filed
January 6, 2005 (File No. 12609 and File No. 1-2348),
Exhibit 99.1)
|
|
|
*10.47
|
Form
of Performance Share Agreement for 2005 grants under the PG&E
Corporation Long-Term Incentive Program (incorporated by reference to
PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed
January 6, 2005 (File No. 12609 and File No. 1-2348),
Exhibit 99.2)
|
|
|
*10.48
|
Form
of Performance Share Agreement for 2006 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed
January 9, 2006, Exhibit 99.2)
|
|
|
*10.49
|
Form
of Performance Share Agreement for 2007 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the
PG&E Corporation 2006 Long-Term Incentive Plan made on February 15,
2006) (incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2006 (File No. 1-12609),
Exhibit 10.44)
|
|
|
*10.50
|
Form
of Performance Share Agreement for 2008 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation's Form 10-Q for the quarter ended March 31, 2008
(File No. 1-12609), Exhibit 10.6)
|
|
|
*10.51
|
|
Form
of Amended and Restated Performance Share Agreement for 2006 grants
(amendments to comply with Internal Revenue Code Section 409A
Regulations)
|
|
*10.52
|
Form
of Amended and Restated Performance Share Agreement for 2007 grants
(amendments to comply with Internal Revenue Code Section 409A
Regulations)
|
|
|
*10.53
|
Form
of Amended and Restated Performance Share Agreement for 2008 grants
(amendments to comply with Internal Revenue Code Section 409A
Regulations)
|
|
|
*10.54
|
PG&E
Corporation Executive Stock Ownership Program Guidelines as amended
effective February 17, 2009
|
|
|
*10.55
|
PG&E
Corporation Officer Severance Policy, as amended effective as of February
15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2005 (File No. 1-12609),
Exhibit 10.48)
|
|
|
*10.56
|
PG&E
Corporation Officer Severance Policy, as amended effective as of January
1, 2009 (amended to comply with Internal Revenue Code Section 409A
regulations)
|
|
|
*10.57
|
PG&E
Corporation Golden Parachute Restriction Policy effective as of February
15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2005 (File No. 1-12609),
Exhibit 10.49)
|
|
|
*10.58
|
Amendment
to PG&E Corporation Golden Parachute Restriction Policy dated December
31, 2008 (amendment to comply with Internal Revenue Code Section 409A
Regulations)
|
|
|
*10.59
|
PG&E
Corporation Director Grantor Trust Agreement dated April 1, 1998
(incorporated by reference to PG&E Corporation's Quarterly Report on
Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609),
Exhibit 10.1)
|
|
|
*10.60
|
PG&E
Corporation Officer Grantor Trust Agreement dated April 1, 1998, as
updated effective January 1, 2005 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2004 (File
No. 1-12609), Exhibit 10.39)
|
|
|
*10.61
|
Resolution
of the Board of Directors of PG&E Corporation regarding
indemnification of officers and directors dated December 18, 1996
(incorporated by reference to PG&E Corporation's Form 10-K for the
year ended December 31, 2004 (File No. 1-12609),
Exhibit 10.40)
|
|
|
*10.62
|
Resolution
of the Board of Directors of Pacific Gas and Electric Company regarding
indemnification of officers and directors dated July 19, 1995
(incorporated by reference to Pacific Gas and Electric Company’s Form 10-K
for the year ended December 31, 2004 (File No. 1-2348),
Exhibit 10.41)
|
|
|
11
|
Computation
of Earnings Per Common Share
|
|
|
12.1
|
Computation
of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric
Company
|
|
|
12.2
|
Computation
of Ratios of Earnings to Combined Fixed Charges and Preferred Stock
Dividends for Pacific Gas and Electric Company
|
|
|
13
|
The
following portions of the 2008 Annual Report to Shareholders of PG&E
Corporation and Pacific Gas and Electric Company are included: “Selected
Financial Data,” “Management's Discussion and Analysis of Financial
Condition and Results of Operations,” financial statements of PG&E
Corporation entitled “Consolidated Statements of Income,” “Consolidated
Balance Sheets,” “Consolidated Statements of Cash Flows,” and
“Consolidated Statements of Shareholders' Equity,” financial statements of
Pacific Gas and Electric Company entitled “Consolidated Statements of
Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash
Flows,” and “Consolidated Statements of Shareholders' Equity,” “Notes to
the Consolidated Financial Statements,” “Quarterly Consolidated Financial
Data (Unaudited),” “Management's Report on Internal Control Over Financial
Reporting,” and “Report of Independent Registered Public Accounting
Firm.”
|
|
|
21
|
Subsidiaries
of the Registrant
|
|
|
23
|
Consent
of Independent Registered Public Accounting Firm (Deloitte & Touche
LLP)
|
|
|
24.1
|
Resolutions
of the Boards of Directors of PG&E Corporation and Pacific Gas and
Electric Company authorizing the execution of the Form
10-K
|
|
|
24.2
|
Powers
of Attorney
|
|
|
31.1
|
Certifications
of the Chief Executive Officer and the Chief Financial Officer of PG&E
Corporation required by Section 302 of the Sarbanes-Oxley Act of
2002
|
|
|
31.2
|
Certifications
of the Chief Executive Officer and the Chief Financial Officer of Pacific
Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act
of 2002
|
|
|
**32.1
|
Certifications
of the Chief Executive Officer and the Chief Financial Officer of PG&E
Corporation required by Section 906 of the Sarbanes-Oxley Act of
2002
|
|
|
**32.2
|
Certifications
of the Chief Executive Officer and the Chief Financial Officer of Pacific
Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act
of 2002
|
*
Management contract or compensatory agreement.
** Pursuant
to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather
than filed with this report.