PG&E CORP
10-Qs and 10-Ks
PROXIES
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, 2009
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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
þ
No
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Pacific
Gas and Electric Company
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Yes
þ
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
þ
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Pacific
Gas and Electric Company
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Yes
No
þ
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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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Yes
þ
No
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Pacific
Gas and Electric Company
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Yes
þ
No
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Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T
(§ 232.405 of this chapter) during the preceding 12 months (or for
such shorter period that the registrant was required to submit and post such
files).
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PG&E
Corporation
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Yes
þ
No
o
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Pacific
Gas and Electric Company
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Yes
o
No
o
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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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þ
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Pacific
Gas and Electric Company
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þ
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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
þ
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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
þ
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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
þ
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Pacific
Gas and Electric Company
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Yes
No
þ
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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, 2009, 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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$14,193
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 17, 2010:
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PG&E
Corporation:
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371,333,780
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 2009 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 2010 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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Security Ownership of Certain Beneficial Owners and Management
and Relate
d Stockholder Matters
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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
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, 2009. The Utility had approximately
$42.7 billion in assets at December 31, 2009 and generated revenues of
$13.4 billion in 2009. 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”). In addition, the
Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction,
operation, and decommissioning of the Utility’s nuclear generation
facilities.
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 or
furnish various reports with the Securities and Exchange Commission
(“SEC”). These reports, including Annual Reports on Form 10-K,
Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any
amendments to those reports filed or furnished pursuant to Sections 13(a) or
15(d) of the Securities Exchange Act of 1934, as amended, are available free of
charge on both PG&E Corporation's website,
www.pgecorp.com
, and the
Utility's website,
www.pge.com
, as
promptly as practicable after they are filed with, or furnished to, the SEC
. The information contained on these websites is not incorporated by
reference into this Annual Report on Form 10-K and should not be considered
part of this report.
At
December 31, 2009, PG&E Corporation and its subsidiaries had 19,425 regular
employees, including 19,401 regular employees of the Utility. Of the
Utility’s regular employees, 12,648 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, 2010, and the other expires on
December 31, 2011. The ESC collective bargaining agreement
expires on December 31, 2011. The SEIU collective bargaining
agreement expires on July 31, 2012.
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, 2009 (“2009 Annual Report”) and the Joint Proxy Statement relating
to the 2010 Annual Meetings of Shareholders, contains forward-looking statements
that are necessarily subject to various risks and
uncertainties. These statements are based on current estimates,
expectations and projections about future events, and assumptions regarding
these events and management's knowledge of facts as of the date of this
report. These forward-looking statements relate to, among other
matters, estimated capital expenditures, estimated Utility rate base, estimated
environmental remediation liabilities, estimated tax
liabilities,
1
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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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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explosions,
fires, accidents, mechanical breakdowns, the disruption of information
technology and systems, and similar events that may occur while operating
and maintaining an electric and natural gas system in a large service
territory with varying geographic conditions, that can cause unplanned
outages, reduce generating output, damage the Utility’s assets or
operations, subject the Utility to third-party claims for property damage
or personal injury, or result in the imposition of civil, criminal, or
regulatory fines or penalties on the Utility;
|
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·
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the
impact of storms, earthquakes, floods, drought, wildfires, disease and
similar natural disasters, or acts of terrorism or vandalism that affect
customer demand, or that damage or disrupt the facilities, operations, or
information technology and systems owned by the Utility, its customers, or
third parties on which the Utility relies;
|
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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 that include the development of
alternative technologies that enable customers to increase their reliance
on self-generation, or other reasons;
|
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·
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the
occurrence of unplanned outages at the Utility’s two nuclear generating
units at the Diablo Canyon Power Plant (“Diablo Canyon”), the availability
of nuclear fuel, the outcome of the Utility’s application to renew the
operating licenses for Diablo Canyon, and potential changes in laws or
regulations promulgated by the NRC or other environmental agencies with
respect to the storage of spent nuclear fuel, security, safety, or other
matters associated with the operations at Diablo
Canyon;
|
|
·
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whether
the Utility can maintain the cost savings that it has recognized from
operating efficiencies that it has achieved and identify and successfully
implement additional sustainable cost-saving measures;
|
|
·
|
whether
the Utility earns incentive revenues or incurs obligations under incentive
ratemaking mechanisms, such as the CPUC’s incentive ratemaking mechanism
relating to energy savings achieved through implementation of the
utilities’ customer energy efficiency programs;
|
|
·
|
the
impact of federal or state laws, or their interpretation, on energy policy
and the regulation of utilities and their holding
companies;
|
|
·
|
whether
the new day-ahead, hour-ahead, and real-time wholesale electricity markets
established by the California Independent System Operator (“CAISO”) that
became operational on April 1, 2009 will continue to function effectively
and whether the Utility can successfully implement “dynamic pricing” by
offering electric rates that can vary with the customer’s time of use and
are more closely aligned with wholesale electricity
prices;
|
|
·
|
how
the CPUC administers the conditions imposed on PG&E Corporation when
it became the Utility’s holding company;
|
2
|
·
|
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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the
ability of PG&E Corporation, the Utility, and counterparties to access
capital markets and other sources of credit in a timely manner on
acceptable terms;
|
|
·
|
the
impact of environmental laws and regulations and the costs of compliance
and remediation;
|
|
·
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the
loss of customers due to municipalization of the Utility’s electric
distribution facilities, the level of “direct access” by which consumers
procure electricity from alternative energy providers, implementation of “
community choice aggregation,” which permits cities and counties to
purchase and sell electricity for their local residents and businesses, or
other forms of bypass; and
|
|
·
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the
outcome of federal or state tax audits and the impact of changes in
federal or state tax laws, policies, or
regulations.
|
For more information about the significant risks that could affect the
outcome of these forward-looking statements and PG&E Corporation’s and the
Utility’s future financial condition and results of operations, see the
discussion under the heading “Risk Factors” that appears near the end of the
section entitled "Management's Discussion and Analysis of Financial Condition
and Results of Operations" (“MD&A”) in the 2009 Annual
Report. PG&E Corporation and the Utility do not undertake an
obligation to update forward-looking statements, whether in response to new
information, future events, or otherwise.
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. 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:
|
·
|
the
Utility cannot guarantee any obligations of PG&E Corporation without
prior written consent from the
CPUC;
|
|
·
|
the
Utility’s dividend policy must be established by the Utility's Board of
Directors as though the Utility were a stand-alone utility
company;
|
|
·
|
the
capital requirements of the Utility, as determined to be necessary and
prudent to meet the Utility's obligation to serve or to operate the
Utility in a prudent and efficient manner, must be given first priority by
PG&E Corporation's Board of Directors (known as the “first priority”
condition); and
|
|
·
|
the
Utility must maintain on average its CPUC-authorized utility capital
structure, although it can request a waiver of this condition if an
adverse financial event reduces the Utility's common equity component by
1% or more.
|
3
The CPUC
also has adopted complex and detailed rules governing transactions between
California's electricity and gas utilities and certain of their
affiliates. The rules address the use of the utilities’ names and
logos by their affiliates, the separation of utilities and their affiliates,
provision of utility information to affiliates, and energy procurement-related
transactions between the utilities and their affiliates. The rules
also prohibit each utility from engaging in certain practices that would
discriminate against energy service providers that compete with that utility's
affiliates. In December 2006, the CPUC revised its rules to, among
other changes:
|
·
|
emphasize
that the holding company may not aid or abet a utility's violation of the
rules or act as a conduit to provide confidential utility information to
an affiliate;
|
|
·
|
require
prior CPUC approval before the utility can contract with an affiliate for
resource procurement (
e.g.,
electricity or
gas), except in blind transactions where the identity of the other party
is not known until the transaction is
consummated;
|
|
·
|
require
certain key officers to provide annual certifications of compliance with
the affiliate rules;
|
|
·
|
prohibit
certain key officers from serving in the same position at both the utility
and the holding company (unless otherwise permitted by the CPUC), or, in
the alternative, prohibit the sharing of lobbying, regulatory relations
and certain legal services (except for legal services necessary to the
provision of permitted shared
services);
|
|
·
|
require
the utility to obtain a “nonconsolidation opinion” indicating that it
would not be consolidated into a bankruptcy of its holding company;
and
|
|
·
|
make
the CPUC's Energy Division responsible for hiring independent auditors to
conduct biennial audits to verify that the utility is in compliance with
the affiliate rules.
|
The CPUC
has established specific penalties and enforcement procedures for affiliate
rules violations. Utilities are required to self-report affiliate
rules violations.
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 2009 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
FERC has authority to impose penalties of up to $1,000,000 per day for violation
of certain federal statutes, including the Federal Power Act of 1935 and the
Natural Gas Act of 1938, and for violations of FERC-approved
regulations. The FERC has jurisdiction over the Utility'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.
4
Electric Reliability Standards;
Development of Transmission Grid
. The FERC has the
responsibility to approve and enforce mandatory standards governing the
reliability of the nation’s electricity transmission grid, including standards
to protect the nation’s bulk power system against potential disruptions from
cyber and physical security breaches; to prevent market manipulation, and to
supplement state transmission siting efforts in certain electric transmission
corridors that are determined to be of national interest. The FERC
certified the North American Electric Reliability Corporation (“NERC”) as the
nation’s Electric Reliability Organization under the EPAct 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, pursuant to FERC orders, the CAISO is responsible
for providing open access electricity transmission service on a
non-discriminatory basis, planning transmission system additions, and ensuring
the maintenance of adequate reserves of generation capacity.
Prevention of Market
Manipulation
. The FERC has broad authority to police and
penalize the exercise of market power or behavior intended to manipulate prices
paid in FERC-jurisdictional transactions. The FERC has adopted rules
to prohibit market manipulation, modeling its new rules on SEC Rule 10b-5, which
prohibits fraud and manipulation in the purchase or sale of
securities. Under the FERC's new regulations, it is unlawful for any
entity, directly or indirectly, in connection with the purchase or sale of
natural gas, electric energy, or transportation/transmission services subject to
the jurisdiction of the FERC (1) to use or employ any device, scheme, or
artifice to defraud, (2) to make any untrue statement of a material fact or to
omit to state a material fact necessary in order to make the statements made, in
the light of the circumstances under which they were made, not misleading, or
(3) to engage in any act, practice, or course of business that operates or would
operate as a fraud or deceit upon any person.
QF Regulation
.
Under PURPA,
electric utilities are required to purchase energy and capacity from independent
power producers that are qualifying cogeneration facilities
(“QFs”). To implement the purchase requirements of PURPA, the CPUC
required California investor-owned electric utilities to enter into long-term
power purchase agreements with QFs and approved the applicable terms,
conditions, prices, and eligibility requirements. The EPAct
significantly amended the purchase requirements of PURPA. As amended,
Section 210(m) of PURPA authorizes the FERC to waive the obligation of an
electric utility under Section 210 of PURPA to purchase the electricity offered
to it by a QF (under a new contract or obligation), if the FERC finds that the
QF has nondiscriminatory access to one of three defined categories of
competitive wholesale electricity markets. The statute permits such
waivers as to a particular QF or on a “service territory-wide
basis.” The Utility is assessing whether it will file a request with
the FERC to terminate its obligations under PURPA to enter into new QF purchase
obligations.
The NRC
oversees the licensing, construction, operation and decommissioning of nuclear
facilities, including the two nuclear generating units at Diablo Canyon and the
Utility’s retired nuclear generating unit at Humboldt Bay (“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
5
requirements
have, in the past, necessitated substantial capital expenditures at Diablo
Canyon, and additional significant capital expenditures could be required in the
future.
In
addition, as required by NRC regulations, only certain key management personnel
and other designated individuals may receive information from the NRC or other
government agency relating to Diablo Canyon that is deemed to be classified by
the governmental agency. In connection with this requirement, the
Board of Directors of PG&E Corporation has adopted a resolution
acknowledging that neither PG&E Corporation nor any director or officer of
PG&E Corporation will (1) have access to such classified information or
special nuclear material in the custody of the Utility, or (2) participate in
any decision or matter pertaining to the protection of classified information
and/or special nuclear material in the custody of the Utility.
California Legislature.
The
Utility’s operations have been significantly affected by statutes passed by the
California legislature, including laws related to electric industry
restructuring, the 2000-2001 California energy crisis, electric resource
adequacy, renewable energy resources, power plant siting and permitting, and
greenhouse gas (“GHG”) emissions and other environmental matters.
The CPUC
.
The CPUC consists of five
members appointed by the Governor of California and confirmed by the California
State Senate for staggered six-year terms. The CPUC has jurisdiction
to 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.
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 14 of the Notes to the Consolidated
Financial Statements included in the 2009 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.
6
The
Utility obtains permits, authorizations, and licenses in connection with the
construction and operation of the Utility's generation facilities, electricity
transmission lines, natural gas transportation pipelines, and gas compressor
station facilities. Discharge permits, various Air Pollution Control
District permits, U.S. Department of Agriculture-Forest Service permits, FERC
hydroelectric generation facility and transmission line licenses, and NRC
licenses are some of the more significant examples. Some licenses and
permits may be revoked or modified by the granting agency if facts develop or
events occur that differ significantly from the facts and projections assumed in
granting the approval. Furthermore, discharge permits and other
approvals and licenses are granted for a term less than the expected life of the
associated facility. Licenses and permits may require periodic
renewal, which may result in additional requirements being imposed by the
granting agency. (For more information, see “Environmental Matters —
Water Quality” below.) In addition, the Utility must comply with
regulations to be issued by the California Air Resources Board (“CARB”) relating
to GHG emissions. (For more information see “Environmental Matters —
Air Quality and Climate Change” 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.
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
7
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, California Assembly Bill 1890, enacted in 1996, mandated the
restructuring of the California electricity industry beginning in 1998 to allow
customers of the California investor-owned electric utilities to purchase energy
from a service provider other than the regulated utilities (the ability to
choose an energy provider is referred to as “direct
access”). Assembly Bill 1890 established 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”). Following
the 2000-2001 California 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
14 of the Notes to the Consolidated Financial Statements in the 2009 Annual
Report.)
California
Assembly Bill 1X authorized the California Department of Water Resources
(“DWR”), beginning in February 1, 2001, to purchase electricity and sell that
electricity directly to the utilities' retail customers. Assembly
Bill 1X requires the utilities to deliver electricity purchased by the DWR under
the contracts and to act as the DWR’s billing and collection
agent. To ensure that the DWR recovers the costs that it incurs under
its power purchase contracts, the CPUC suspended direct access on
September 20, 2001, but allowed existing direct access customers to
continue being served by alternative energy service
providers. California Senate Bill 695, enacted on October 11, 2009,
requires the CPUC to adopt and implement a schedule by April 11, 2010 to reopen
direct access on a gradual basis over a period of not less than three years and
not more than five years. The statute imposes an annual limit on the
amount of electricity that can be purchased by direct access customers of a
particular utility. The annual limit for each utility is increased
each year until it reaches an amount equal to each utility’s historical maximum
amount of energy provided by other service providers in that utility’s service
territory during any one-year period. Further legislative action is
required to exceed these limits.
Assembly
Bill 1890 also provided for the establishment of the CAISO, as a nonprofit
public benefit corporation, to operate and control the state-wide electricity
transmission grid and ensure efficient use and reliable operation of the
transmission grid. On April 1, 2009, the CAISO implemented new
day-ahead, hour-ahead, and
8
real-time
wholesale electricity markets subject to bid caps that increase over time, as
part of the implementation of the CAISO’s Market Redesign and Technology Upgrade
initiative (“MRTU”). Market participants, including load-serving
entities like the Utility, are permitted to hedge the financial risk of
CAISO-imposed congestion charges in the MRTU day-ahead market by acquiring
congestion revenue rights. 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
that the CPUC adopts would be subject to FERC approval. On October
29, 2009, the CPUC opened a new rulemaking proceeding to continue oversight of
the current resource adequacy program, consider program refinements, and
establish annual local procurement obligations.
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' electricity provider of
last resort. Assembly Bill 117 provides that a community choice
aggregator can 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 and allowing a community choice aggregator
to start service in phases. 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.
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 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’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. In September 2009,
the Utility filed an application with the CPUC to continue a majority of the Gas
Accord IV’s terms and conditions for the Utility’s natural gas transportation
and storage services from 2011 through 2014.
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
9
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 Williams Gas Pipeline Company, LLC,
have been jointly pursuing the development of a new 234-mile interstate gas
transmission pipeline that would increase natural gas supplies for the 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., as lead
investor, 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 be capable of
delivering 1 Bcf per day. On December 17, 2009, the FERC issued an order to
authorize construction and operation of the LNG terminal and the Pacific
Connector Gas Pipeline.
The
development and construction of the Pacific Connector Gas Pipeline and the
proposed LNG terminal are subject to obtaining all remaining required federal,
state and local permits and authorizations, as well as commitments under
long-term capacity contracts of sufficient volumes to justify moving forward
with construction of the terminal and the pipeline. Assuming these
are obtained and other conditions are timely satisfied, the proposed Pacific
Connector Gas Pipeline and LNG terminal could begin commercial operation by late
2014. However, PG&E Corporation cannot predict whether such
conditions will be met and whether the construction of the proposed LNG terminal
and associated pipeline will occur.
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.
10
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 some of 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. On December 21, 2009, the Utility filed its application for
the next GRC to establish revenue requirements for 2011 through
2013. For more information, see the section of MD&A entitled
“Regulatory Matters” in the 2009 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 provided
for attrition adjustments for 2008, 2009, and 2010. For more
information, see the section of MD&A entitled “Results of Operations” in the
2009 Annual Report.
Cost
of Capital Proceedings
The CPUC
authorizes the Utility's capital structure (i.e., the relative weightings of
common equity, preferred equity, and debt) and the authorized rates of return on
each component that the Utility may earn on its electricity and natural gas
distribution and electricity generation assets. The current
authorized capital structure, consisting of 52% equity, 46% long-term debt, and
2% preferred stock, will be maintained through 2012 unless the automatic
adjustment mechanism described below is triggered. The Utility’s
current authorized rates of return that the Utility may earn on its electricity
and natural gas distribution and electricity generation rate base are 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%. The
CPUC has authorized the Utility to maintain these rates through
2010.
The
CPUC’s 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
11
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 Utility may apply for an adjustment to
either the cost of capital or the capital structure sooner based on
extraordinary circumstances. The Utility’s next full cost of capital
application must be filed by April 20, 2012, so that any resulting changes would
become effective on January 1, 2013.
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.
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 contracts allocated to the Utility under Assembly Bill
1X). To accomplish this, each utility must submit a long-term
procurement plan covering a 10-year period to the CPUC for
approval. Each long-term procurement plan must be designed to reduce
GHG emissions and use the State of California’s preferred loading order to meet
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 electricity procurement plans, covering 2007 through 2016, 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 through 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
12
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 various power purchase agreements that the Utility has entered into
with third parties in accordance with the Utility’s CPUC-approved long-term
procurement plan and to 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 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 can 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 are allocated for the term of the
contract or 10 years, whichever is shorter, starting on the date the new
generation unit comes on line. Under this allocation mechanism, the
energy rights to the contract are auctioned off to maximize the energy revenues
and minimize the net capacity costs 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.
California
Senate Bill 695, enacted on October 11, 2009, also includes a mechanism for
recovery of above-market costs from direct access and community choice
aggregation customers. The CPUC has not yet implemented this portion
of Senate Bill 695.
The
CPUC-authorized revenue requirements for capital costs and non-fuel operating
and maintenance costs for operating Utility-owned generation facilities are
addressed in the Utility’s GRC. The CPUC-authorized revenue
requirements to recover the initial capital costs for utility-owned generation
projects are recovered through a balancing account, the Utility Generation
Balancing Account (“UGBA”), which tracks the difference between the
CPUC-approved forecast of initial capital costs, adjusted from time to time as
permitted by the CPUC, and actual costs. The initial revenue
requirement for Utility-owned projects generally would begin to accrue in the
UGBA as of the new facility’s commercial operation date or the date a completed
facility is transferred to the Utility, and would be included in rates on
January 1 of the following year. For more information, see the
section of MD&A entitled “Capital Expenditures — Proposed New Generation
Facilities” in the 2009 Annual Report.
During
the 2000-2001 California energy crisis, the DWR entered into long-term contracts
to purchase electricity from third parties. The electricity provided
under these contracts has been allocated to the electric customers of the three
California investor-owned electric utilities. The DWR pays for its
costs of purchasing electricity from a revenue requirement collected from these
customers through a rate component called the DWR “power charge.” The
rates that these customers pay also include a “bond charge” to pay a share of
the DWR’s revenue requirements to recover costs associated with the DWR's $11.3
billion bond offering completed in November 2002. The proceeds of
this bond offering were used to repay the State of California and lenders to the
DWR for electricity purchases made before the implementation of the DWR's
revenue requirement and to provide
13
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 (1) charges under the Utility's
transmission owner tariff, and (2) charges under specific contracts with
wholesale transmission customers that the Utility entered into before the CAISO
began its operations in March 1998. These wholesale customers are
referred to as existing transmission contract customers and are charged
individualized rates based on the terms of their contracts. Other
customers pay transmission rates that are established by the FERC in the
Utility'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 ratemaking proceeding to determine the amount of revenue
requirements that the Utility is authorized to recover for its electric
transmission costs and to earn its return on equity is the transmission owner
rate case (“TO rate case”). The Utility generally files a TO rate
case every year, 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 2009 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:
|
·
|
the
proceeds received from the CAISO for wholesale wheeling service (i.e., the
transfer of electricity that is being sold in the wholesale market) that
the CAISO provides to third parties using the Utility’s transmission
facilities, and
|
|
·
|
revenues
that the CAISO collects from transmission users to relieve congestion on
the Utility’s transmission line (either in the form of financial hedges,
such as firm transmission rights relating to future deliveries of
electricity, or in the form of a usage charge to manage congestion
relating to real-time delivery of
electricity).
|
These
revenues are adjusted by the shortfall or surplus resulting from any cost
differences between the amount that the Utility is entitled to receive from
existing transmission contract customers under specific contracts and the amount
that the Utility is entitled to receive or be charged for scheduling services
under the CAISO’s rules and protocols.
The CAISO
also charges the Utility for reliability service costs and imposes a
transmission access charge on the Utility for the use of the CAISO-controlled
electric transmission grid in serving its customers. The CAISO's
transmission access charge methodology, approved by the FERC in December 2004,
provided for a transition over a 10-year period, from 2001 to2010, 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
results 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
14
differential,
which is capped at $32 million per year during the 10-year transition
period, is recovered in retail transmission rates.
The
Utility’s authorized natural gas transmission and storage rates and associated
revenue requirements from January 1, 2008 through December 31, 2010 have been
set in accordance with the CPUC-approved settlement agreement known as the Gas
Accord IV. On September 18, 2009, the Utility filed an application
with the CPUC to establish the Utility’s natural gas transmission and storage
revenue requirements from January 1, 2011 through 2014 and to continue a
majority of the terms and conditions of the Gas Accord IV. A decision
on the Utility’s application, known as the Gas Accord V, is expected by the end
of 2010. A substantial portion of the authorized revenue
requirements, primarily those costs allocated to core customers, would continue
to be assured of recovery through balancing account mechanisms and/or fixed
reservation charges. The Utility’s ability to recover the remaining
revenue requirements would 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 that
backbone capacity is sold on an as-available basis. Core procurement
entities (including core customers served by the Utility) are the primary
long-term subscribers to backbone capacity. Core customers are
allocated approximately 36% 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,
12% 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.
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.
15
Natural
Gas Procurement
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 the Core Procurement Incentive
Mechanism (“CPIM”). Under the CPIM, the Utility's purchase costs for
a fixed 12-month period are compared to an aggregate market-based benchmark
based on a weighted average of published monthly and daily natural gas price
indices at the points where the Utility typically purchases natural
gas. Costs that fall within a tolerance band, which is 99% to 102% of
the 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
through 2011 on behalf of core customers. 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 Note 10: Derivatives and
Hedging Activities, of the Notes to the Consolidated Financial Statements in the
2009 Annual Report).
In
January 2010, the CPUC approved a joint settlement agreement among the Utility,
the CPUC’s Division of Ratepayer Advocates, and The Utility Reform Network to
incorporate a portion of hedging costs for core customers into the Utility’s
CPIM. The settlement agreement has an initial term of seven years,
through October 2017, which can be extended by agreement of the
parties. As a result, the settlement agreement permits the Utility to
develop and implement a sustained core hedging program.
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.”
The
Utility is required to maintain physical generating capacity adequate to meet
its customers’ demand for electricity (“load”), including peak demand and
planning and operating reserves, deliverable to the locations and at times as
may be necessary to provide reliable electric service. The Utility is
required to dispatch, or schedule, all of the electricity resources within its
portfolio, including electricity provided under DWR contracts, in the most
cost-effective way
.
16
The
following table shows the percentage of the Utility's total actual deliveries of
electricity in 2009 represented by each major electricity resource:
Total
2009 Actual Electricity Delivered 79,585 GWh:
|
Owned
generation:
|
||
|
Nuclear
|
20.5%
|
|
|
Large
Hydroelectric
|
10.5%
|
|
|
Small
Hydroelectric
|
1.4%
|
|
|
Fossil
fuel-fired
|
3.9%
|
|
|
Total
|
36.3%
|
|
|
DWR
|
18.0%
|
|
|
Qualifying
Facilities
|
18.8%
|
|
|
Irrigation
Districts
|
3.7%
|
|
|
Other
Power Purchases
|
23.2%
|
At
December 31, 2009, 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:
|
||||||
|
Gateway Generating Station
(1)
|
Contra
Costa
|
1
|
530
|
|||
|
Humboldt
Bay
(2)
|
Humboldt
|
2
|
105
|
|||
|
Mobile
turbines
|
Humboldt
|
2
|
30
|
|||
|
Fossil
fuel subtotal
|
5
|
665
|
||||
|
Total
|
117
|
6,801
|
|
(1)
|
The
Gateway Generating Station became operational in January
2009.
|
|
(2)
|
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. For the twelve
months period ended December 31, 2009, the Utility’s Diablo Canyon power
plant achieved an average overall capacity factor of approximately
83%. The NRC operating license for Unit 1 expires in November 2024,
and the NRC operating license for Unit 2 expires in
August 2025. In November 2009, the Utility filed an application
at the NRC requesting that each of these licenses be renewed for 20
years. The license renewal process is expected to take several years
as the NRC holds public hearings and conducts safety and environmental analyses
and site audits. (See the discussion under the heading “Risk Factors”
that appears in the MD&A section of the 2009 Annual
Report.) Under the terms of the NRC operating 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.
17
The
ability of the Utility to produce nuclear generation depends on the availability
of nuclear fuel. The Utility has entered into various purchase
agreements for nuclear fuel that are intended to ensure long-term fuel
supply. For more information about these agreements, see Note 16:
Commitments and Contingencies — Nuclear Fuel Agreements, of the Notes to the
Consolidated Financial Statements in the 2009 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 actual refueling schedule and outage duration will
depend on the scope of the work required for a particular outage and other
factors.
|
2010
|
2011
|
2012
|
2013
|
2014
|
|||||
|
Unit
1
|
|||||||||
|
Refueling
|
October
|
-
|
April
|
-
|
February
|
||||
|
Duration
(days)
|
40
|
-
|
30
|
-
|
30
|
||||
|
Startup
|
November
|
-
|
May
|
-
|
March
|
||||
|
Unit
2
|
|||||||||
|
Refueling
|
-
|
May
|
-
|
February
|
September
|
||||
|
Duration
(days)
|
-
|
30
|
-
|
30
|
35
|
||||
|
Startup
|
-
|
June
|
-
|
March
|
October
|
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. Most of the Utility’s
hydroelectric generation units are classified as “large” hydro facilities, as
their unit capacity exceeds 30 MW. The system includes 99 reservoirs,
56 diversions, 170 dams, 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 three years, the FERC renewed three hydroelectric licenses associated with
a total of 435 MW of hydroelectric power. The Utility is in the
process of renewing licenses for projects associated with approximately 1,073 MW
of hydroelectric power. Although the original licenses associated
with 516 MW of the 1,073 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 two
generation facilities to be owned and operated by the
Utility. Construction of the Colusa Generating Station, a 657 MW
combined cycle generating facility to be located in Colusa County, California,
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 by November 2010. Also, in December
2008, the Utility began 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. 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 September 2010.
DWR
Power Purchases
During
2009, electricity from the DWR contracts allocated to the Utility provided
approximately 18.0% 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 these
contracts expire or are novated to the Utility.
18
Third-Party
Power Purchase Agreements
Qualifying Facility Power Purchase
Agreements.
As described above under “The Utility’s Regulatory
Environment-Federal Energy Regulation,” the Utility is required to purchase
energy and capacity from independent power producers that are QFs. As
of December 31, 2009, the Utility had power purchase agreements with 240 QFs for
approximately 3,900 MW that are in operation. Agreements for
approximately 3,600 MW expire at various dates between 2010 and
2028. QF power purchase agreements for approximately 300 MW have no
specific expiration dates and will terminate only when the owner of the QF
exercises its termination option. The Utility also has power purchase
agreements with approximately 75 inoperative QFs. The total of
approximately 3,900 MW consists of 2,500 MW from cogeneration projects, and
1,400 MW from renewable generation resources, as discussed below. QF
power purchases accounted for 18.8% of the Utility’s 2009 electricity
deliveries. No single QF accounted for more than 5% of the Utility’s
2009 electricity deliveries.
Irrigation Districts and Water
Agencies.
The Utility also has entered into contracts with
various irrigation districts and water agencies to purchase hydroelectric
power. These agreements are based on debt service requirements
(regardless of the amount of power supplied), and include variable payments to
the counterparty for operation and maintenance costs. These contracts
will expire on various dates between 2010 and 2031. In 2009, they
accounted for 3.7% of the Utility’s electricity deliveries.
Other Power Purchase
Agreements.
The Utility has entered into power purchase
agreements, including agreements to purchase renewable energy that were entered
into following annual solicitations and separate bilateral
negotiations. In addition, in accordance with the Utility’s
CPUC-approved long-term procurement plan, the Utility has entered into power
purchase agreements for conventional generation resources. During
2009, the Utility’s purchases under these agreements accounted for 9.0% of the
Utility’s deliveries. When market prices and forecasted load
conditions are favorable, the Utility also has the ability to procure
electricity through the spot bilateral and CAISO markets. Electricity
purchased in these markets accounted for 14.2% of the Utility’s deliveries in
2009.
For more
information regarding the Utility’s power purchase contracts, see Note 16:
Commitments and Contingencies — Third-Party Power Purchase Agreements, of the
Notes to the Consolidated Financial Statements in the 2009 Annual
Report.
California
law requires California retail sellers of electricity, such as the Utility, to
comply with a renewable portfolio standard (“RPS”) by increasing their
deliveries of renewable energy (such as biomass, small hydroelectric, wind,
solar, and geothermal energy) each year, so that the amount of electricity
delivered from renewable resources equals at least 20% of their total retail
sales by the end of 2010. If a retail seller is unable to meet its
target for a particular year, the current CPUC “flexible compliance” rules allow
the deficit to be carried forward for up to three years so that future
deliveries of renewable power can be used to make up the deficit.
The
amount of electricity the Utility delivered from renewable resources during 2009
equaled 14.4 % of the Utility’s total retail electricity sales at December 31,
2009. Most renewable energy deliveries resulted from third party
contracts, mainly QF agreements and bilateral contracts. Additional
renewable resources included the Utility’s small hydro and solar facilities and
certain irrigation district contracts (small hydro
facilities). (Under California law only hydroelectric generation
resources with a capacity of 30 MW or less can qualify as a renewable resource
for purposes of meeting the RPS mandate. Most of the Utility’s
hydroelectric generating units have a capacity in excess of 30 MW and do not
qualify as RPS-eligible resources.)
19
Total
2009 renewable deliveries are stated in the table below.
|
Type
|
GWh
|
%
of Bundled Load
|
||||||
|
Biopower
|
3,439 | 4.3 | % | |||||
|
Geothermal
|
3,412 | 4.3 | % | |||||
|
Wind
|
2,524 | 3.2 | % | |||||
|
Small
Hydroelectric
|
2,044 | 2.6 | % | |||||
|
Solar
|
22 | 0.0 | % | |||||
|
Total
|
11,441 | 14.4 | % | |||||
For more
information regarding the Utility’s renewable energy contracts, see Note 16:
Commitments and Contingencies — Third-Party Power Purchase Agreements, of the
Notes to the Consolidated Financial Statements in the 2009 Annual
Report.
In
compliance with California’s Clean Energy Action Plan, the Utility plans to meet
future electricity demand by focusing first on reducing consumption through
energy efficiency and demand response programs, then by securing environmentally
preferred energy resources, such as renewable generation and distributed
generation (including solar power), and finally by relying on clean and
efficient fossil-fueled generation resources. The Utility’s
CPUC-approved long-term electricity procurement plan, covering 2007-2016,
forecasts that the Utility will need to obtain an additional 800 to 1,200 MW of
new generation resources by 2015 above the Utility's planned additions of
renewable resources, energy efficiency, demand reduction programs, and
previously approved contracts for new generation resources. Due to
the cancellation of two projects selected in its 2004 RFO for new long-term
generation resources, the Utility was authorized to increase the new generation
resource need to obtain 1,112 to 1,512 MW.
The CPUC
allows the California investor-owned utilities to acquire ownership of new
conventional generation resources only through purchase and sale agreements
(“PSAs”) ( a PSA is a “turnkey” arrangement in which a new generating facility
is constructed by a third party and then sold to the Utility upon satisfaction
of certain contractual requirements). The utilities are prohibited
from submitting offers for utility-build generation in their respective RFOs
until questions can be resolved about how to compare offers for utility-owned
generation with offers from independent power producers. The
utilities are permitted to propose utility-owned generation projects through a
separate application outside of the RFO process in the following circumstances:
(1) to mitigate market power demonstrated by the utility to be held by others,
(2) to support a use of preferred resources, such as renewable energy sources,
(3) to take advantage of a unique and fleeting opportunity (such as a bankruptcy
settlement), and (4) to meet unique reliability needs.
For a
discussion of the Utility-owned generation projects the Utility has requested
that the CPUC approve, see the section of MD&A entitled “Capital
Expenditures — Proposed New Generation Facilities” in the 2009 Annual
Report.
20
At
December 31, 2009, 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 57,848 MVA. Electricity is transmitted across
these lines and substations and is then distributed to customers through 141,213
circuit miles of distribution lines and substations with a capacity of 27,896
MVA. In 2009, the Utility delivered 85,629 GWh to its customers,
including 5,643 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 the 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
high-voltage transmission line to improve regional reliability in the Fresno,
California area and ultimately enable access to new renewable generation
resources (referred to as the “Central California Clean Energy Transmission
Project”). A
s
previously disclosed, the Utility has been exploring the feasibility of
obtaining regulatory approval for a potential investment in a proposed 1,000
mile high-voltage electric transmission project that would run from British
Columbia, Canada to Northern California. The project would provide
access to potential new renewable generation resources, improve regional
transmission reliability, and provide opportunities for other market
participants to use the new facilities. The supply of and need for
new renewable generation have evolved since the Utility began exploring the
feasibility of obtaining regulatory approval for the potential investment, as
has the interest from potential partners. In lieu of the
1,000
mile high-voltage
transmission line
,
the Utility is
in continuing discussions with various stakeholders to explore whether, in light
of these changing circumstances, a different version of this project or another
transmission project in this region should be pursued as part of its overall
renewable energy supply
strategy.
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 141,213 circuit miles of distribution
lines
21
(of which
approximately 20% are underground and approximately 80% are
overhead). There are 93 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 600 distribution
substations and 118 low-voltage distribution substations. The 53
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 1,116 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.
2009 Electricity
Deliveries.
The following table shows the percentage of the
Utility’s total 2009 electricity deliveries represented by each of its major
customer classes.
Total
2009 Electricity Delivered: 85,629 GWh
|
Residential
Customers
|
36%
|
|
Commercial
Customers
|
39%
|
|
Industrial
Customers
|
17%
|
|
Agricultural
and Other Customers
|
8%
|
The
following table shows certain of the Utility's operating statistics from 2005 to
2009 for electricity sold or delivered, including the classification of sales
and revenues by type of service.
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
Customers
(average for the year):
|
||||||||||||||||||||
|
Residential
|
4,492,359 | 4,488,884 | 4,464,483 | 4,417,638 | 4,353,458 | |||||||||||||||
|
Commercial
|
528,786 | 527,045 | 521,732 | 515,297 | 509,786 | |||||||||||||||
|
Industrial
|
1,285 | 1,265 | 1,261 | 1,212 | 1,271 | |||||||||||||||
|
Agricultural
|
83,581 | 81,757 | 80,366 | 79,006 | 78,876 | |||||||||||||||
|
Public
street and highway lighting
|
31,227 | 30,474 | 29,643 | 28,799 | 28,021 | |||||||||||||||
|
Other
electric utilities
|
2 | 2 | 2 | 4 | 4 | |||||||||||||||
|
Total
|
5,137,240 | 5,129,427 | 5,097,487 | 5,041,956 | 4,971,416 | |||||||||||||||
|
Deliveries
(in GWh):
(1)
|
||||||||||||||||||||
|
Residential
|
31,234 | 31,454 | 30,796 | 31,014 | 29,752 | |||||||||||||||
|
Commercial
|
32,958 | 34,053 | 33,986 | 33,492 | 32,375 | |||||||||||||||
|
Industrial
|
14,806 | 16,148 | 15,159 | 15,166 | 14,932 | |||||||||||||||
|
Agricultural
|
5,804 | 5,594 | 5,402 | 3,839 | 3,742 | |||||||||||||||
|
Public
street and highway lighting
|
826 | 877 | 833 | 785 | 792 | |||||||||||||||
|
Other
electric utilities
|
1 | 1 | 3 | 14 | 33 | |||||||||||||||
|
Subtotal
|
85,629 | 88,127 | 86,179 | 84,310 | 81,626 | |||||||||||||||
|
California
Department of Water Resources (DWR)
|
(13,244 | ) | (13,344 | ) | (21,193 | ) | (19,585 | ) | (20,476 | ) | ||||||||||
|
Total
non-DWR electricity
|
72,385 | 74,783 | 64,986 | 64,725 | 61,150 | |||||||||||||||
|
Revenues
(in millions):
|
||||||||||||||||||||
|
Residential
|
$ | 4,759 | $ | 4,656 | $ | 4,580 | $ | 4,491 | $ | 3,856 | ||||||||||
|
Commercial
|
4,538 | 4,413 | 4,484 | 4,414 | 4,114 | |||||||||||||||
22
|
Industrial
|
1,392 | 1,400 | 1,252 | 1,293 | 1,232 | |||||||||||||||
|
Agricultural
|
770 | 727 | 664 | 483 | 446 | |||||||||||||||
|
Public
street and highway lighting
|
74 | 75 | 78 | 72 | 66 | |||||||||||||||
|
Other
electric utilities
|
66 | 126 | 85 | 59 | 4 | |||||||||||||||
|
Subtotal
|
11,599 | 11,397 | 11,143 | 10,812 | 9,718 | |||||||||||||||
|
DWR
|
(1,987 | ) | (1,325 | ) | (2,229 | ) | (2,119 | ) | (1,699 | ) | ||||||||||
|
Miscellaneous
|
221 | 336 | 215 | 261 | 235 | |||||||||||||||
|
Regulatory
balancing accounts
|
424 | 330 | 352 | (202 | ) | (327 | ) | |||||||||||||
|
Total electricity
operating revenues
|
$ | 10,257 | $ | 10,738 | $ | 9,481 | $ | 8,752 | $ | 7,927 | ||||||||||
|
Other
Data:
|
||||||||||||||||||||
|
Average annual
residential usage (kWh)
|
6,953 | 7,007 | 6,898 | 7,020 | 6,834 | |||||||||||||||
|
Average
billed revenues (cents per kWh):
|
||||||||||||||||||||
|
Residential
|
$ | 15.24 | $ | 14.80 | $ | 14.87 | $ | 14.48 | $ | 12.96 | ||||||||||
|
Commercial
|
13.77 | 12.96 | 13.19 | 13.18 | 12.71 | |||||||||||||||
|
Industrial
|
9.40 | 8.67 | 8.26 | 8.53 | 8.25 | |||||||||||||||
|
Agricultural
|
13.27 | 13.00 | 12.29 | 12.58 | 11.92 | |||||||||||||||
|
Net plant investment
per customer
|
$ | 4,336 | $ | 3,994 | $ | 3,418 | $ | 3,148 | $ | 2,966 |
|
|
(1)
|
These
amounts include electricity provided to direct access customers who
procure their own supplies of
electricity.
|
Natural
Gas Utility Operations
The
Utility owns and operates an integrated natural gas transportation, storage, and
distribution system in California that extends throughout all or a part of 39 of
California’s 58 counties and includes most of northern and central
California. In 2009, the Utility served approximately 4.3 million
natural gas distribution customers. The total volume of natural gas
throughput during 2009 was approximately 845 Bcf.
As of
December 31, 2009, the Utility’s natural gas system consisted of 42,142 miles of
distribution pipelines, 6,438 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 Company, El Paso Natural Gas
Company, Questar Southern Trails Pipeline Company, and Kern River Pipeline
Company), has a receipt capacity of approximately 1.07 Bcf per
day. The Utility's Line 400/401 interconnects with the natural gas
transportation pipeline of 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 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.
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
23
industrial,
larger commercial, and electric generation natural gas customers. In
2009, core customers represented more than 99% of the Utility’s total natural
gas customers and 38% of its total natural gas deliveries, while non-core
customers comprised less than 1% of the Utility’s total natural gas customers
and 62% of its total natural gas deliveries.
The
Utility provides natural gas transportation services to all core and non-core
customers connected to the Utility’s system in its service
territory. Core customers can purchase natural gas procurement
service (i.e.
,
natural
gas supply) from either the Utility or alternate energy service
providers. When the Utility provides both transportation and
procurement services, the Utility refers to the combined service as “bundled”
natural gas service. Currently, over 97% of core customers,
representing over 96% of 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.
2009 Natural Gas
Deliveries.
The following table shows the percentage of the
Utility's total 2009 natural gas deliveries represented by each of the Utility's
major customer classes.
Total
2009 Natural Gas Deliveries: 845 Bcf
|
Residential
Customers
|
27%
|
|
Transport-only
Customers (non-core)
|
62%
|
|
Commercial
Customers
|
11%
|
24
The
following table shows the Utility's operating statistics from 2005 through 2009
(excluding subsidiaries) for natural gas, including the classification of sales
and revenues by type of service.
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
Customers
(average for the year):
|
||||||||||||||||||||
|
Residential
|
4,046,364 | 4,043,616 | 4,030,499 | 3,989,331 | 3,929,117 | |||||||||||||||
|
Commercial
|
223,709 | 224,617 | 223,330 | 220,024 | 216,749 | |||||||||||||||
|
Industrial
|
928 | 926 | 958 | 988 | 962 | |||||||||||||||
|
Other
gas utilities
|
6 | 6 | 6 | 6 | 6 | |||||||||||||||
|
Total
|
4,271,007 | 4,269,165 | 4,254,793 | 4,210,349 | 4,146,834 | |||||||||||||||
|
Gas
supply (MMcf):
|
||||||||||||||||||||
|
Purchased
from suppliers in:
|
||||||||||||||||||||
|
Canada
|
190,485 | 189,608 | 199,870 | 202,274 | 204,884 | |||||||||||||||
|
California
(1)
|
(41,714 | ) | (53,126 | ) | (23,065 | ) | (13,401 | ) | (18,951 | ) | ||||||||||
|
Other
states
|
115,543 | 123,833 | 101,271 | 103,658 | 103,237 | |||||||||||||||
|
Total
purchased
|
264,314 | 260,315 | 278,076 | 292,531 | 289,170 | |||||||||||||||
|
Net
(to storage) from storage
|
876 | 560 | (1,120 | ) | 4,359 | (3,659 | ) | |||||||||||||
|
Total
|
265,190 | 260,875 | 276,956 | 296,890 | 285,511 | |||||||||||||||
|
Utility
use, losses, etc.
(2)
|
(12,423 | ) | 1,758 | (12,760 | ) | (27,610 | ) | (14,312 | ) | |||||||||||
|
Net
gas for sales
|
252,767 | 262,633 | 264,196 | 269,280 | 271,199 | |||||||||||||||
|
Bundled
gas sales (MMcf):
|
||||||||||||||||||||
|
Residential
|
195,217 | 198,699 | 196,903 | 196,092 | 194,108 | |||||||||||||||
|
Commercial
|
57,550 | 63,934 | 67,293 | 73,178 | 77,056 | |||||||||||||||
|
Industrial
|
— | — | — | 10 | 35 | |||||||||||||||
|
Other
gas utilities
|
— | — | — | — | — | |||||||||||||||
|
Total
|
252,767 | 262,633 | 264,196 | 269,280 | 271,199 | |||||||||||||||
|
Transportation
only (MMcf):
|
568,715 | 569,535 | 605,259 | 559,270 | 572,869 | |||||||||||||||
|
Revenues
(in millions):
|
||||||||||||||||||||
|
Bundled
gas sales:
|
||||||||||||||||||||
|
Residential
|
$ | 1,953 | $ | 2,574 | $ | 2,378 | $ | 2,452 | $ | 2,336 | ||||||||||
|
Commercial
|
496 | 792 | 766 | 859 | 885 | |||||||||||||||
|
Industrial
|
— | — | — | — | — | |||||||||||||||
|
Other
gas utilities
|
— | — | — | — | — | |||||||||||||||
|
Miscellaneous
|
55 | (30 | ) | 87 | 121 | (22 | ) | |||||||||||||
|
Regulatory
balancing accounts
|
289 | 221 | 186 | 40 | 340 | |||||||||||||||
|
Bundled
gas revenues
|
3,557 | 3,417 | 3,472 | 3,539 | ||||||||||||||||
|
Transportation
service only revenue
|
349 | 333 | 340 | 315 | 237 | |||||||||||||||
|
Operating
revenues
|
$ | 3,142 | $ | 3,890 | $ | 3,757 | $ | 3,787 | $ | 3,776 | ||||||||||
|
Selected
Statistics:
|
||||||||||||||||||||
|
Average
annual residential usage (Mcf)
|
48 | 49 | 49 | 49 | 49 | |||||||||||||||
|
Average
billed bundled gas sales revenues per Mcf:
|
||||||||||||||||||||
|
Residential
|
$ | 10.00 | $ | 12.95 | $ | 12.07 | $ | 12.50 | $ | 12.04 | ||||||||||
|
Commercial
|
8.62 | 12.38 | 11.38 | 11.73 | 11.48 | |||||||||||||||
|
Industrial
|
— | — | — | 1.03 | 0.61 | |||||||||||||||
|
Average
billed transportation only revenue per Mcf
|
0.61 | 0.59 | 0.56 | 0.56 | 0.42 | |||||||||||||||
|
Net
plant investment per customer
|
$ | 1,557 | $ | 1,344 | $ | 1,375 | $ | 1,304 | $ | 1,262 | ||||||||||
|
(1)
|
In
the years presented, the sale of excess supplies to parties located in
California exceeded purchases from parties located in
California.
|
|
(2)
|
Includes
fuel for the Utility's fossil fuel-fired generation
plants.
|
25
|
Natural Gas
Supplies
|
|
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 2009, the Utility purchased approximately 264,314
MMcf of natural gas (net of the sale of excess supply of gas). 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 13% of the total
natural gas volume the Utility purchased during 2009.
The
following table shows the total volume and the average price of natural gas in
dollars per MMcf of the Utility's natural gas purchases by region during each of
the last five years. The average prices for Canadian and U.S. Southwest gas
shown below include the commodity natural gas prices, pipeline demand or
reservation charges, transportation charges, and other pipeline
assessments. The volumes purchased are shown net of sales of excess
supplies of gas. In the years presented below, the sale of excess
supplies to parties located in California exceeded purchases from parties
located in California.
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
|||||
|
Canada
|
190,485
|
$3.74
|
189,608
|
$8.29
|
199,870
|
$6.63
|
202,274
|
$6.27
|
204,884
|
$7.12
|
||||
|
California
(1)
|
(41,714)
|
$4.16
|
(53,126)
|
$9.24
|
(23,065)
|
$6.77
|
(13,401)
|
$7.04
|
(18,951)
|
$7.70
|
||||
|
Other
states (substantially all U.S. southwest)
|
115,543
|
$3.50
|
123,833
|
$7.05
|
101,271
|
$6.30
|
103,658
|
$6.51
|
103,237
|
$7.10
|
||||
|
Total/weighted
average
|
264,314
|
$3.57
|
260,315
|
$7.51
|
278,076
|
$6.50
|
292,531
|
$6.32
|
289,170
|
$7.07
|
||||
(1)
California purchases include supplies transported into California by
others.
Gas
Gathering Facilities
The
Utility's gas gathering system collects natural gas from third-party wells in
California. During 2009, 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 42 miles of gas gathering
pipelines. The Utility receives gas well production at approximately
185 metering facilities. The Utility’s gas gathering system is geographically
dispersed and is located in 7 California counties. Approximately 139
MMcf per day of natural gas produced in northern California was delivered into
the Utility’s gas gathering system during 2009.
In 2009,
approximately 54% of the gas transported on the Utility’s system came from
western Canada. The Utility has a number of arrangements with
interstate and Canadian third-party transportation service providers to serve
core customers' service demands. The Utility has firm transportation
agreements for delivery of natural gas from western Canada to the United
States-Canada border with TransCanada NOVA Gas Transmission, Ltd. and
TransCanada Foothills Pipe Lines Ltd., B.C. System. These
companies' pipeline systems connect at the border to the pipeline system owned
by TransCanada’s Gas Transmission Northwest Corporation (“GTN”), which provides
natural gas transportation services to a point of interconnection with the
Utility’s natural gas transportation system on the Oregon-California border near
Malin, Oregon. The Utility, the largest firm shipper on GTN’s
pipeline, has 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 was replaced beginning November 1, 2009 by three smaller contracts totaling
the same amount with staggered terms.
During
2009, approximately 40% 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
26
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 2009 to support the Utility’s needs
for its core customers, including the contract quantities, contract durations,
and associated demand charges, net of sales of excess supplies, for capacity
reservations. These agreements require the Utility to pay fixed
demand charges for reserving firm capacity on the pipelines. The total demand
charges may change periodically as a result of changes in regulated tariff rates
approved by the National Energy Board of Canada in the case of TransCanada NOVA
Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C.
System, and by the FERC in all other cases. The Utility may, upon
prior notice and with the CPUC’s approval, extend 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,
2009
(In
millions)
|
||||
|
TransCanada
NOVA Gas Transmission, Ltd.
|
10/31/2011
|
619
|
$30.9
|
||||
|
TransCanada
Foothills Pipe Lines Ltd., B.C. System
|
10/31/2011
|
611
|
10.5
|
||||
|
Gas
Transmission Northwest Corporation
(1)
|
Various
|
610
|
69.9
|
||||
|
Transwestern
Pipeline Company
(2)
|
Various
|
227
|
17.3
|
||||
|
El
Paso Natural Gas Company
(3)
|
Various
|
202
|
21.8
|
|
(1)
|
As
of December 31, 2009, the Utility had three active contracts with Gas
Transmission Northwest Corporation with expiration dates ranging from
October 31, 2011 to October 31,
2020.
|
|
(2)
|
As
of December 31, 2009, the Utility had two active contracts with
Transwestern Pipeline Company with expiration dates ranging from February
28, 2010 to February 29, 2012.
|
|
(3)
|
As of December 31, 2009, the
Utility had three active contracts with El Paso Natural Gas Company with
expiration dates ranging from June 30, 2010 to June 30,
2012.
|
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 (“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 1.5 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 receiving final approval from the FERC and satisfying
other conditions, the Ruby Pipeline is anticipated to be in service in the first
quarter of 2011.
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 2009,
the CPUC authorized the Utility to collect revenue requirements of $751 million
from electric customers to fund electric public purpose and other programs and
$132 million 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 2009, the Utility transferred $82
million from its revenue requirements to the CEC for
CEC-administered
27
gas and
electric 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 the Utility to collect
revenue requirements of $479 million for 2009 gas and electric programs,
including the CEC-administered programs. The CPUC has authorized the
Utility to collect $1.3 billion of revenue requirements to fund its 2010-2012
programs, a 42% increase over 2006-2008 authorized funding
levels. The CPUC has adopted a long-term energy efficiency strategic
plan designed to encourage innovative market transformation activities, such as
the pursuit of zero net energy buildings, in addition to traditional energy
efficiency rebate programs.
The CPUC
established an incentive ratemaking mechanism to encourage the California
investor-owned utilities to promote energy efficiency and to meet the CPUC’s
energy savings goals. This incentive ratemaking mechanism applied to
the utilities’ 2006 through 2008 energy efficiency program cycles.
In
accordance with this mechanism, the CPUC has awarded the Utility incentive
revenues totaling $75 million through December 31, 2009 based on the energy
savings achieved through implementation of the Utility’s energy efficiency
programs during the 2006 through 2008 program cycle. Consistent with the
incentive award process previously adopted by the CPUC, the CPUC held back an
additional $40.3 million of incentive revenues subject to verification of final
energy savings and the completion of the true-up process in 2010.
It is
uncertain what form of incentive ratemaking, if any, the CPUC will establish for
energy efficiency programs in 2009 and later years. For more
information, see the section of MD&A entitled “Regulatory Matters — Energy
Efficiency Programs and Incentive Ratemaking” in the 2009 Annual
Report.
Demand
response programs provide financial incentives and other benefits to
participating customers to curtail on-peak energy use. On August 20,
2009, the CPUC approved the Utility’s 2009-2011 demand response programs and
authorized funding of $109 million. 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. 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.
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 CPUC also has ordered the Utility to install
advanced metering and billing systems to enable the Utility to implement
“dynamic pricing” for electricity customers to encourage efficient energy
consumption and cost-effective demand response by more closely aligning retail
rates with the wholesale electricity market. “Dynamic pricing”
includes rates that are based on critical peak prices and time of
use. Customers may choose an alternate rate plan
structure. The Utility is required to implement dynamic pricing by
May 2010 for larger customers and by November 2011 for small and medium
non-residential customers. The Utility has requested that the CPUC
authorize the Utility to recover estimated costs of approximately $160 million
to implement dynamic pricing, including approximately $32 million as an
allowance for unforeseen costs the Utility may incur in connection with such a
large and complex capital project. (See the discussion under the
heading “Risk Factors” that appears in the MD&A section of the 2009 Annual
Report.)
28
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 and energy storage 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 2010 and
2011. The CPUC also approved the use of carryover funds through
2015. In late 2006, the CPUC 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.
The CPUC
has authorized the Utility to collect approximately $417 million to support the
Utility’s energy efficiency programs for low-income and fixed-income customers
over 2009 through 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 and their actual
energy usage. In 2009, the amount of this subsidy was approximately
$637 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 through 2011.
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 following:
|
·
|
the
discharge of pollutants into the air, water, and
soil;
|
|
·
|
the
transportation, handling, storage and disposal of spent nuclear
fuel;
|
|
·
|
the
identification, generation, storage, handling, transportation, treatment,
disposal, record keeping, labeling, reporting, remediation and emergency
response in connection with hazardous and radioactive
substances;
|
|
·
|
the
reporting and reduction of carbon dioxide (“CO2”) and other GHG emissions;
and
|
|
·
|
the
environmental impacts of land use, including endangered species and
habitat protection.
|
The
penalties for violation of these laws and requirements can be severe and may
include significant fines, damages, and criminal or civil
sanctions. These laws and requirements also may require the Utility,
under certain circumstances, to interrupt or curtail operations. To
comply with these laws and requirements, the Utility may need to spend
substantial amounts from time to time to construct, acquire, modify, or replace
equipment, acquire permits and/or emission allowances or other emission credits
for facility operations and clean-up, or decommission waste disposal areas at
the Utility's current or former facilities and at third-party sites where the
Utility’s wastes may have been disposed.
The
Utility’s estimated costs to comply with environmental laws and regulations are
based on current estimates and assumptions that are subject to
change. In addition, the Utility is likely to incur costs as it
develops
29
and
implements strategies to mitigate the impact of its operations on the
environment, including climate change and its foreseeable impact on the
Utility’s future operations. The actual amount of costs that the
Utility will incur is subject to many factors, including changing laws and
regulations, the ultimate outcome of complex factual investigations, evolving
technologies, selection of compliance alternatives, the nature and extent of
required remediation, the extent of the facility owner's responsibility, the
availability of recoveries or contributions from third parties, and the
development of market-based strategies to address climate
change. Generally, the Utility has recovered the costs of complying
with environmental laws and regulations in the Utility'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 described below under “Hazardous Waste Compliance and
Remediation.” In the future, the Utility’s operations are likely to
be affected by climate change. See the section of MD&A entitled
“Environmental Matters” and “Risk Factors” in the 2009 Annual Report for a
discussion of the operating, regulatory, and litigation risks posed by climate
change and associated with the Utility’s environmental compliance
obligations.
PG&E
Corporation and the Utility believe the link between man-made GHG emissions and
global climate change is clear and convincing and that mandatory GHG reductions
are necessary. PG&E Corporation and the Utility believe the
development of a market-based cap-and-trade system, in conjunction with
successful energy efficiency and demand-side management programs and the
development of renewable energy resources, can reduce GHG emissions while
diversifying energy supply resources and minimizing costs to
customers.
Regulation
. The
Utility's electricity generation plants, natural gas pipeline operations, fleet,
and fuel storage tanks are subject to numerous air pollution control laws,
including the federal Clean Air Act, as well as state and local
statutes. These laws and regulations cover, among other pollutants,
those contributing to the formation of ground-level ozone, carbon monoxide,
sulfur dioxide (“SO2”), nitrogen oxide (“NOx”) and particulate
matter. In addition, various laws and regulations addressing climate
change and GHG emissions are being considered or implemented at the federal,
regional, state, and local levels. 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, GHG
emissions from natural gas consumed by the Utility’s customers will be subject
to regulation by the 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 nationwide
regulatory limits on the emissions of GHG. No such legislation has
yet been enacted by Congress, but extensive hearings and discussion are expected
in the coming year. In September 2009, the U.S. Environmental
Protection Agency (“EPA”), which is charged with implementation and enforcement
of the Clean Air Act, issued regulations requiring the reporting of GHG
emissions from sources emitting greater than 25,000 tonnes (CO2-equivalent) per
year. The EPA’s regulations, which will apply to certain of the
Utility’s power plants and gas compressor stations, will require reporting of
2010 emissions in 2011 and annually thereafter. Also in September
2009, the EPA and the Department of Transportation’s National Highway Traffic
Safety Administration proposed regulations that would reduce GHG emissions and
improve fuel economy of new cars and trucks. As a result of
provisions in the Clean Air Act, if the EPA regulates motor vehicle emissions,
then the EPA must regulate GHG emissions from stationary sources, such as power
plants and natural gas compressor stations, as well. In November
2009, the EPA issued a finding that GHG emissions cause or contribute to air
pollution that endangers public health and welfare. This so-called
“Endangerment Finding” was necessary before EPA could issue its final motor
vehicle GHG emissions regulations or proceed with regulating stationary
sources. While the specific date is not certain, it is likely that
EPA will issue its motor vehicle GHG regulations in 2010.
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 a cap-and-trade program. In 2007, the CARB
adopted a state-wide GHG 1990 emissions baseline of 427 million metric tons of
CO2 (or its equivalent). This 1990 baseline serves as the 2020
emissions limit for the state of California. On December 12, 2008,
the CARB adopted a scoping plan that contains recommendations for achieving the
maximum technologically feasible and cost-effective GHG
30
reductions
to meet the 2020 reduction target. These recommendations include
implementing a 33% RPS by 2020, increasing energy efficiency goals, expanding
the use of combined heat and power facilities, and developing 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. In November 2009, the CARB
released proposed regulations to establish a cap-and-trade program and is
scheduled to consider the final draft of these regulations in October
2010. (For more information about the proposed cap-and-trade program,
see the section of MD&A entitled “Environmental Matters” and “Risk Factors”
in the 2009 Annual Report.)
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 CO2 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 statewide 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.
Climate Change
Mitigation and Adaption Strategies.
During 2009, the Utility
continued its programs to develop strategies to mitigate the impact of the
Utility’s operations (including customer energy usage) on the environment and to
develop its strategy to plan for the actions that it will need to take to adapt
to the likely impacts that climate change will have on the Utility’s future
operations. With respect to electric operations, climate scientists
project that climate change will lead to increased electricity demand due to
more extreme and frequent hot weather events, and reduced hydroelectric
generation due to reductions in snowpack in the Sierra Nevada. The
Utility is analyzing and exploring a combination of operating changes to its
hydroelectric system that may include, but are not limited to, higher winter
carryover reservoir storage levels, reduced conveyance flows in canals and
flumes during winter storm periods, reduced discretionary reservoir releases
during the late spring and summer period and increased sediment releases from
diversion dams. If the Utility’s future hydroelectric generation is
reduced due to drought conditions or climate change, the Utility might have to
replace some of this electricity from other sources, including natural
gas. The amount of fossil-fueled generation needed to replace
decreased hydroelectric generation can be reduced if non-intermittent renewable
energy resources
, such as geothermal and
biomass, are timely developed.
With respect to natural gas operations,
the Utility has taken voluntary proactive steps to reduce the release of
methane, a GHG released as part of the delivery of natural gas. As
part of this overall commitment to
methane
emission reduction, and in preparation
for compliance with AB 32 and potential federal regulation of GHG emissions, the
Utility has replaced old cast iron and steel gas mains and implemented a
technique called cross-compression, a process by which natural gas is
transferred from one pipeline to another during large pipeline construction and
repair projects. Cross-compression reduces the amount of natural gas
vented to the atmosphere by 85% to 90%. In late 2008, the Utility
also conducted focused surveys for high-volume gas leaks at its Topock and
Kettleman compressor stations to reduce methane emissions.
The Utility believes its strategies to
reduce GHG emissions—such as energy efficiency and demand response programs,
infrastructure improvements, and the support of renewable energy development
—are also effective strategies for adapting to the expected increased demand for
electricity in extreme hot weather events likely to be caused by climate
change. PG&E Corporation and the Utility are also assessing the
benefits and challenges associated with various climate change policies and
identifying how a comprehensive program can be structured to mitigate overall
costs to customers and the economy as a whole while ensuring that the
environmental objectives of the program are met.
Emissions Data.
PG&E Corporation and the Utility
track and report their annual environmental performance results across a broad
spectrum of areas. The Utility was among the earliest companies to
voluntarily quantify and report its GHG emissions, which the Utility believes is
an essential first step in the longer-term effort to effectively and efficiently
address climate change. The Utility is a charter member of the
California Climate Action Registry (“CCAR”) and has voluntarily reported its GHG
emissions to CCAR on an annual basis since 2002, when it became the first
investor-owned utility in California to voluntarily complete a
third-party-verified inventory of its
31
CO2
emissions. In 2009, the Utility also voluntarily reported its 2008
GHG emissions to The Climate Registry (“TCR”), a new non-profit organization
that is developing consistent reporting and measurement standards across
industry sectors in North America. In 2009, the Utility complied with
AB 32’s annual GHG emission reporting requirement by reporting its 2008 GHG
emissions to the CARB.
PG&E Corporation and the Utility also publish third-party-verified GHG
emissions data in their annual Corporate Responsibility Report. As a
result of the time necessary for a thorough, third-party verification of the
Utility’s GHG emissions in accordance with the highest standards developed by
the CCAR and TCR, preliminary emissions data for 2008 are the most recent data
available. Final emissions data will be made publicly available by
CCAR on their website as well as reported in the next Corporate Responsibility
Report expected to be posted to PG&E Corporation’s and the Utility’s
websites in July 2010. For information about the sources of electric
generation that the Utility delivered to customers in 2009, see “Electric
Utility Operations-Electric Generation Resources” above.
Total
2008 GHG Emissions by Source Category
|
Source
|
Amount
(per million metric tonnes CO2 – equivalent)
|
|||
|
Delivered
Electricity
(1)
|
23.84 | |||
|
Electricity
Transmission and Distribution Line Losses
|
1.41 | |||
|
Process
and Fugitive Emissions from Natural Gas System
|
1.32 | |||
|
Gas
Compressor Stations
|
0.31 | |||
|
Transportation
(Fleet vehicles)
|
0.11 | |||
|
Facility
Gas and Electricity Use
|
0.05 | |||
|
Electrical
Equipment
|
0.06 | |||
|
Other
De Minimis Emissions
(2)
|
0.00 | |||
|
Total
|
27.10 | |||
(1)
Since the Utility purchases a portion of its electricity from the
wholesale market, the Utility is not able to track some of its delivered
electricity back to a specific generator. Therefore, there is some
unavoidable uncertainty in the Utility’s total emissions and the Utility’s
emission rate for delivered electricity
.
Emissions data for
the Utility’s owned generation resources is shown below.
(2)
Includes de minimis emissions from PG&E Corporation.
Benchmarking
Greenhouse Gas Emissions for Delivered Electricity
The Utility’s
third-party-verified CO2 emissions rate associated with the electricity
delivered to customers in 2008 was 641 pounds of CO2 per MWh, which is a
slight increase over the 2007 emissions rate of 636 pounds of CO2 per
MWh. Even with this increase, the Utility’s 2008 emissions rate was
still less than half the national average as shown in the following
table:
|
Amount
(Pounds of CO2 per MWh)
|
|
|
U.S.
Average
(1)
|
1,329
|
|
California’s
Average
(1)
|
724
|
|
Pacific
Gas and Electric Company
(2)
|
641
|
(1)
Source: U.S. Environmental Protection Agency eGRID 2007 Version 1.1 (updated
December 2008 and based on 2005 data).
(2)
Since the Utility purchases a portion of its electricity from the wholesale
market, the Utility is not able to track some of its delivered electricity back
to a specific generator. Therefore, there is some unavoidable
uncertainty in the Utility’s total emissions and the Utility’s emission rate for
delivered electricity.
32
Emissions
Data for Utility-Owned Generation
In
addition to GHG emissions data provided above, the table below sets forth
information about the GHG emissions from the Utility’s owned generation
facilities. The Utility’s owned generation (primarily from nuclear
and hydroelectric facilities) comprised approximately 30% of the Utility’s
delivered electricity in 2008. The Utility’s retained fossil-fueled
generation comprised less than 1% of the Utility’s delivered electricity in
2008.
|
2008
|
2007
|
|
|
Total
NOx Emissions (tons)
|
1,163
|
1,123
|
|
NOx
Emissions Rates (pounds/MWh)
|
||
|
Fossil
Plants
|
4.26
|
4.65
|
|
All
Plants
|
0.09
|
0.08
|
|
Total
SO2 Emissions (tons)
|
27
|
43
|
|
SO2
Emissions Rates (pounds/MWh)
|
||
|
Fossil
Plants
|
0.0980
|
0.1781
|
|
All
Plants
|
0.0021
|
0.0031
|
|
Total
CO2 Emissions (tons)
|
406,990
|
379,196
|
|
CO2
Emissions Rates (pounds/MWh)
|
||
|
Fossil
Plants
|
1,566
|
1,570
|
|
All
Plants
|
32
|
28
|
|
Other
Emissions Statistics
|
||
|
Sulfur
Hexafluoride (“SF6”) Emissions
|
||
|
Total
SF6 Emissions (pounds)
|
5,938
|
3,928
|
|
Total
SF6 Emissions (tons CO2-equivalent)
|
70,959
|
46,940
|
|
SF6
Emissions Leak Rate
|
1.9%
|
1.3%
|
|
Methane
Emissions
|
||
|
Total
Methane Emissions (tons)
|
62,686
|
53,342
|
|
Total
Methane Emissions (tons CO2-equivalent)
|
1,316,397
|
1,120,179
|
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 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
33
EPA regulations, the California State Water Resources Control Board (“Water Board”) initiated a process to develop a once-though cooling policy and has issued several policy proposals. The Water Board’s current proposal does not include a cost-benefit variance, but provides for additional evaluation of the costs and benefits of cooling tower retrofits at the state's two nuclear facilities. Based on the results of the evaluation, if the policy is not modified to include a cost-benefit variance, compliance with the proposed policy would require Diablo Canyon to install cooling towers by December 2024.
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 granted review of
the cost-benefit question and in April 2009, issued a decision overturning the
Second Circuit, finding the EPA’s use of a cost-benefit test
reasonable. Depending on the form of the final regulations that may
ultimately be adopted by the EPA 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 or the Water Board 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.
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 (“MGP”) 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.
Generation
Facilities
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
34
Substances
Control will approve the soil and groundwater remediation plan by the second
quarter of 2010. The Utility spent approximately $16 million in 2009
and estimates that it will spend approximately $24 million in 2010 and
approximately $16 million in 2011 for remediation at this site.
Former
Manufactured Gas Plant Sites
The
Utility is assessing whether and to what extent remedial action may be necessary
to mitigate potential hazards posed by certain retired MGP
sites. During their operation, from the mid-1800s through the early
1900s, MGPs produced lampblack and coal tar residues. The residues
from these operations, which may remain at some sites, contain chemical
compounds that now are classified as hazardous. The Utility has a
program, in cooperation with environmental agencies and third-party owners, to
evaluate and take appropriate action to mitigate any potential environmental
concerns at 41 MGP sites that the Utility owned or operated in the
past. The Utility spent approximately $22 million in 2009 and expects
to spend approximately $37 million in 2010 and $39 million in 2011 on these
sites. As part of this program, the Utility recently contacted the
owners of property located on three former MGP sites in urban residential areas
of San Francisco to offer to test the soil for residues, and depending on the
results of such tests, to take appropriate remedial action. Until the
Utility’s investigation is complete, the extent of the Utility’s obligation to
remediate is established, and remedial actions are determined, the Utility is
unable to determine the amounts it may spend in the future to remediate these
sites.
Third-Party
Owned Disposal Sites
Under
environmental laws, such as CERCLA, the Utility has been or may be required to
take remedial action at third-party sites used for the disposal of waste from
the Utility'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 investigating and cleaning up the three
other disposal sites with oversight from the regulatory agencies. The
Utility contributes to the remediation expenses for 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.
Natural
Gas Compressor Stations
Groundwater
at the Utility’s Hinkley and Topock natural gas compressor stations contains
hexavalent chromium as a result of the Utility’s past operating
practices. The Utility has a comprehensive program to monitor a
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 2009, the
Utility spent approximately $14 million on remediation activities at Hinkley,
and currently estimates it will spend at least $19 million in 2010 and $4
million in 2011.
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
environmental agencies to complete investigations at this site and to develop a
long-term plan for clean-up of the plume. A final clean-up 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 2009, the Utility spent
approximately $19 million on the interim measures and for work on the long-term
site solution. The Utility currently estimates that it will spend at
least $24
35
million
in 2010 and $23 million in 2011 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 below. 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.
Hazardous
Substance Ratemaking Mechanism
Environmental
costs associated with the clean-up of sites that contain hazardous substances
are subject to a CPUC-approved 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. (The cost of
environmental remediation associated with the Hinkley natural gas compressor
site is not recoverable from customers under this mechanism.) 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.
Although
the Utility has provided for known environmental obligations that are probable
and reasonably estimable, estimated costs may vary significantly from actual
costs, and the amount of additional future costs may be material to results of
operations in the period in which they are recognized. For more
information about environmental remediation liabilities, see the sections of
MD&A entitled “Environmental Matters” and “Critical Accounting Polices” and
Note 16 of the Notes to the Consolidated Financial Statements in the 2009 Annual
Report which information is incorporated herein by reference and included in
Exhibit 13 to this report.
As part
of the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department
of Energy (“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.
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. The construction of the dry cask storage
facility is complete. During 2009, the Utility moved all the spent
nuclear fuel that was scheduled to be moved into dry cask storage. An
appeal of the NRC’s issuance of the permit is still pending in the U.S. Court of
Appeals for the Ninth Circuit. The appellants claim that the NRC
failed to adequately consider environmental impacts of a potential terrorist
attack at Diablo Canyon. It is uncertain when the appeal will be
addressed by the Ninth Circuit.
As a
result of the DOE’s failure to build a repository for nuclear waste, the Utility
and other nuclear power plant owners sued the DOE to recover costs that they
incurred to build on-site spent nuclear fuel storage facilities. The
Utility seeks to recover $92 million of costs that it incurred through
2004. After several years of litigation, in
36
2008 the
U.S. Court of Appeals for the Federal Circuit (“Federal Circuit”) issued an
order clarifying the method to calculate damages to be awarded to the utilities
for breach of their contracts by the DOE. Although the DOE has
conceded that the Utility is entitled to recover approximately $82 million based
on this method, the DOE continues to challenge the method in related
litigation. In October 2009, a trial was held in the U.S. Federal
Court of Claims to determine the appropriate amounts owed to the Utility based
on the methodology approved by the Federal Circuit. The parties are waiting for
the court to issue its decision. The Utility also will seek to
recover costs incurred after 2004 to build on-site storage
facilities.
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, which is used to determine the level of Utility trust contributions
and related revenue requirement, the CPUC assumed that the eventual
decommissioning of Diablo Canyon Unit 1 would be scheduled to begin in 2024 and
be completed in 2044, that decommissioning of Diablo Canyon Unit 2 would be
scheduled to begin in 2025 and be completed in 2041, and that decommissioning of
Humboldt Bay Unit 3 would be scheduled to begin in 2009 and be completed in
2015. A premature shutdown of the Diablo Canyon units would increase
the likelihood of an earlier start to decommissioning. The Utility’s
decommissioning cost estimates are based on the 2005 decommissioning cost
studies, prepared in accordance with CPUC requirements. The
decommissioning cost estimates are based on the plant location and cost
characteristics for the Utility's nuclear power plants. Actual
decommissioning costs may vary from these estimates to the extent the
assumptions on which the estimates are based (such as assumptions about
decommissioning dates, regulatory requirements, technology, and costs of labor,
materials, and equipment) differ from actual results. The Utility
recovers its revenue requirements for estimated nuclear decommissioning costs
from customers through a non-bypassable charge that the Utility expects will
continue until those costs are fully recovered. Decommissioning costs
recovered in rates are placed in nuclear decommissioning trusts. The
funds in the decommissioning trusts, along with accumulated earnings, will be
used exclusively for decommissioning and dismantling the Utility's nuclear
facilities.
In April
2009, the Utility filed an application in the 2009 Nuclear Decommissioning
Triennial Proceeding with new decommissioning cost estimates and other funding
assumptions, such as projected cost escalation factors and projected earnings of
the funds for 2010, 2011, and 2012. Hearings were completed in
October 2009, and a CPUC decision is expected in the second quarter of
2010. For more information about nuclear decommissioning, including
the estimated decommissioning costs, see Note 12 of the Notes to the
Consolidated Financial Statements in the 2009 Annual Report.
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.
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
37
studies
by others, evaluating the possible risks from EMFs. The report's
conclusions contrast with other
recent
reports by authoritative health agencies in that the California Department of
Health Services' report has assigned a higher probability to the possibility of
a causal connection between EMF exposures and a number of diseases and
conditions, including childhood leukemia, adult leukemia, amyotrophic lateral
sclerosis, and miscarriages.
On
January 26, 2006, the CPUC issued a decision that affirms the CPUC’s
“low-cost/no-cost, prudent avoidance” policy to reduce EMF exposure for new
utility transmission and substation projects. The CPUC ordered the
continued use of a 4% of project cost benchmark for EMF reduction
measures. The CPUC also reaffirmed that it has exclusive jurisdiction
with respect to utility EMF matters.
The
Utility currently is not involved in third-party litigation concerning
EMFs. In August 1996, the California Supreme Court held that
homeowners are barred from suing utilities for alleged property value losses
caused by fear of EMFs from power lines. In a case involving
allegations of personal injury, a California appeals court held that the CPUC
has exclusive jurisdiction over personal injury and wrongful death claims
arising from allegations of harmful exposure to EMFs, and barred plaintiffs'
personal injury claims. The California Supreme Court declined to hear
the plaintiffs’ appeal of this decision.
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 2009 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” which
information is incorporated herein by reference. In total, the
Utility occupies 9.8 million square feet of real property, including 8.5
million square feet that the Utility owns. Of the 9.8 million square
feet of occupied real property, approximately 1.7 million square feet
represent the Utility's corporate headquarters located in several Utility-owned
buildings in San Francisco, California. The Utility occupies or uses
real property that it does not own primarily through various leases, easements,
rights-of-way, permits, or licenses from private landowners or governmental
authorities.
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 or is otherwise used for utility
operations 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.
38
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.
In
addition to the following legal proceedings, PG&E Corporation and the
Utility are involved in various legal proceedings in the ordinary course of
their business. For more information regarding PG&E Corporation’s
and the Utility’s liability for legal matters, see Note 16 of the Notes to
the Consolidated Financial Statements of the 2009 Annual Report.
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.
Not
applicable.
39
The
names, ages and positions of PG&E Corporation “executive officers,” as
defined by Rule 3b-7 of the General Rules and Regulations under the
Securities and Exchange Act of 1934 (“Exchange Act”) at February 1, 2010 were as
follows.
|
Name
|
Age
|
Position
|
||
|
Peter
A. Darbee
|
57
|
Chairman
of the Board, Chief Executive Officer, and President
|
||
|
Kent
M. Harvey
|
51
|
Senior
Vice President and Chief Financial Officer
|
||
|
Christopher
P. Johns
|
49
|
President,
Pacific Gas and Electric Company
|
||
|
Nancy
E. McFadden
|
51
|
Senior
Vice President and Senior Advisor to the Chairman and Chief Executive
Officer
|
||
|
Hyun
Park
|
48
|
Senior
Vice President and General Counsel
|
||
|
Greg
S. Pruett
|
52
|
Senior
Vice President, Corporate Affairs
|
||
|
Rand
L. Rosenberg
|
56
|
Senior
Vice President, Corporate Strategy and Development
|
||
|
John
R. Simon
|
45
|
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 1, 2010, 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 July 31, 2009
|
|||
|
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
|
|||
|
Kent
M. Harvey
|
Senior
Vice President and Chief Financial Officer
|
August
1, 2009 to present
|
||
|
Senior
Vice President, Financial Services, Pacific Gas and Electric
Company
|
August
1, 2009 to present
|
|||
|
Senior
Vice President and Chief Risk and Audit Officer
|
October 1,
2005 to July 31, 2009
|
|||
|
Senior
Vice President, Chief Financial Officer, and Treasurer, Pacific Gas
and Electric Company
|
November 1,
2000 to September 30, 2005
|
|||
|
Christopher
P. Johns
|
President,
Pacific Gas and Electric Company
|
August
1, 2009 to present
|
||
|
Senior
Vice President and Chief Financial Officer
|
May
1, 2009 to July 31, 2009
|
|||
|
Senior
Vice President, Financial Services, Pacific Gas and Electric
Company
|
May
1, 2009 to July 31, 2009
|
|||
|
Senior
Vice President, Chief Financial Officer, and Treasurer
|
October 4,
2005 to April 30, 2009
|
|||
|
Senior
Vice President and Treasurer, Pacific Gas and Electric
Company
|
June
1, 2007 to April 30, 2009
|
|||
|
Senior
Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and
Electric Company
|
October 1,
2005 to May 31, 2007
|
|||
|
Senior
Vice President, Chief Financial Officer, and Controller
|
January 2,
2005 to October 3, 2005
|
40
|
Nancy
E. McFadden
|
Senior
Vice President and Senior Advisor to the Chairman and Chief Executive
Officer
|
November
1, 2009 to present
|
||
|
Senior
Vice President, Public Affairs
|
March
1, 2007 to October 31, 2009
|
|||
|
Senior
Vice President, Public Affairs, Pacific Gas and Electric
Company
|
June
20, 2007 to October 31, 2009
|
|||
|
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 January 1, 2006
|
|||
|
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 Affairs
|
November
1, 2009 to present
|
||
|
Senior
Vice President, Corporate Affairs, Pacific Gas and Electric
Company
|
November
1, 2009 to present
|
|||
|
Senior
Vice President, Corporate Relations
|
November
1, 2007 to October 31, 2009
|
|||
|
Senior
Vice President, Corporate Relations, Pacific Gas and Electric
Company
|
March
1, 2009 to October 31, 2009
|
|||
|
Vice
President, Corporate Relations
|
March
1, 2007 to October 31, 2007
|
|||
|
Vice
President, Communications and Marketing, American Gas
Association
|
April
10, 2006 to February 23, 2007
|
|||
|
Chief
Public Affairs Officer, Bechtel National, Inc.
|
June
12, 2004 to September 12, 2005
|
|||
|
Rand
L. Rosenberg
|
Senior
Vice President, Corporate Strategy and Development
|
November 1,
2005 to present
|
||
|
John
R. Simon
|
Senior
Vice President, Human Resources
|
April
16, 2007 to present
|
||
|
Senior
Vice President, Human Resources, Pacific Gas and Electric
Company
|
April
16, 2007 to present
|
|||
|
Executive
Vice President, Global Human Capital, TeleTech Holdings,
Inc.
|
March
21, 2006 to April 13, 2007
|
|||
|
Senior
Vice President, Human Capital, TeleTech Holdings, Inc.
|
July
31, 2001 to March 20, 2006
|
The
names, ages and positions of the Utility's “executive officers,” as defined by
Rule 3b-7 of the General Rules and Regulations under the Exchange Act at
February 1, 2010 were as follows:
|
Name
|
Age
|
Position
|
||
|
Peter
A. Darbee
|
57
|
Chairman
of the Board, Chief Executive Officer, and President, PG&E
Corporation
|
||
|
Christopher
P. Johns
|
49
|
President
|
||
|
John
S. Keenan
|
61
|
Senior
Vice President and Chief Operating Officer
|
||
|
Desmond
A. Bell
|
47
|
Senior
Vice President, Shared Services and Chief Procurement
Officer
|
||
|
Thomas
E. Bottorff
|
56
|
Senior
Vice President, Regulatory Relations
|
||
|
Helen
A. Burt
|
53
|
Senior
Vice President and Chief Customer Officer
|
||
|
John
T. Conway
|
52
|
Senior
Vice President, Energy Supply and Chief Nuclear Officer
|
||
|
Patricia
M. Lawicki
|
49
|
Senior
Vice President and Chief Information Officer
|
||
|
Kent
M. Harvey
|
51
|
Senior
Vice President, Financial Services
|
||
|
Nancy
E. McFadden
|
51
|
Senior
Vice President and Senior Advisor to the Chairman and Chief Executive
Officer
|
||
|
Hyun
Park
|
48
|
Senior
Vice President and General Counsel, PG&E
Corporation
|
41
|
Greg
S. Pruett
|
52
|
Senior
Vice President, Corporate Affairs
|
||
|
Edward
A. Salas
|
53
|
Senior
Vice President, Engineering and Operations
|
||
|
John
R. Simon
|
45
|
Senior
Vice President, Human Resources
|
||
|
Fong
Wan
|
48
|
Senior
Vice President, Energy Procurement
|
||
|
Geisha
J. Williams
|
48
|
Senior
Vice President, Energy Delivery
|
||
|
Barbara
L. Barcon
|
53
|
Vice
President, Finance and Chief Financial
Officer
|
All
officers of the Utility serve at the pleasure of the Board of
Directors. During the past five years through February 1, 2010, 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
|
Chairman
of the Board, Chief Executive Officer, and President, PG&E
Corporation
|
September 19,
2007 to present
|
||
|
President
and Chief Executive Officer
|
September
5, 2008 to July 31, 2009
|
|||
|
Chairman
of the Board and Chief Executive Officer, PG&E
Corporation
|
July
1, 2007 to September 18, 2007
|
|||
|
Chairman
of the Board
|
January 1,
2006 to May 31, 2007
|
|||
|
Chairman
of the Board, Chief Executive Officer, and President, PG&E
Corporation
|
January 1,
2006 to June 30, 2007
|
|||
|
President
and Chief Executive Officer, PG&E Corporation
|
January 1,
2005 to December 31, 2005
|
|||
|
Christopher
P. Johns
|
President
|
August
1, 2009 to present
|
||
|
Senior
Vice President, Financial Services
|
May
1, 2009 to July 31, 2009
|
|||
|
Senior
Vice President, and Chief Financial Officer, PG&E
Corporation
|
May
1, 2009 to July 31, 2009
|
|||
|
Senior
Vice President and Treasurer
|
June
1, 2007 to April 30, 2009
|
|||
|
Senior
Vice President, Chief Financial Officer, and Treasurer, PG&E
Corporation
|
October 4,
2005 to April 30, 2009
|
|||
|
Senior
Vice President, Chief Financial Officer, and Treasurer
|
October 1,
2005 to May 31, 2007
|
|||
|
Senior
Vice President, Chief Financial Officer, and Controller, PG&E
Corporation
|
January 2,
2005 to October 3, 2005
|
|||
|
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
|
|||
|
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
|
42
|
John
T. Conway
|
Senior
Vice President, Energy Supply and Chief Nuclear Officer
Senior
Vice President, Generation and Chief Nuclear Officer
|
April
1, 2009 to present
October
1, 2008 to March 31, 2009
|
||
|
Senior
Vice President and Chief Nuclear Officer
|
March
1, 2008 to September 30, 2008
|
|||
|
Site
Vice President, Diablo Canyon Power Plant
|
May
29, 2007 to February 29, 2008
|
|||
|
Site
Vice President, Monticello Nuclear Plant, Nuclear Management
Company
|
May
2005 to May 2007
|
|||
|
Site
Director, Monticello Nuclear Plant, Nuclear Management
Company
|
April
2004 to May 2005
|
|||
|
Kent
M. Harvey
|
Senior
Vice President, Financial Services
|
August
1, 2009 to present
|
||
|
Senior
Vice President and Chief Financial Officer, PG&E
Corporation
|
August
1, 2009 to present
|
|||
|
Senior
Vice President and Chief Risk and Audit Officer, PG&E
Corporation
|
October 1,
2005 to July 31, 2009
|
|||
|
Senior
Vice President, Chief Financial Officer, and Treasurer
|
November 1,
2000 to September 30, 2005
|
|||
|
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
|
|||
|
Nancy
E. McFadden
|
Senior
Vice President and Special Advisor to the Chairman and Chief Executive
Officer, PG&E Corporation
|
November
1, 2009 to present
|
||
|
Senior
Vice President, Public Affairs
|
June
20, 2007 to October 31, 2009
|
|||
|
Senior
Vice President, Public Affairs, PG&E Corporation
|
March
1, 2007 to October 31, 2009
|
|||
|
Vice
President, Governmental Relations
|
September
26, 2005 to February 28, 2007
|
|||
|
Chairperson,
California Medical Assistance Commission
|
November
13, 2003 to January 1, 2006
|
|||
|
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 Affairs
|
November
1, 2009 to present
|
||
|
Senior
Vice President, Corporate Affairs, PG&E Corporation
|
November
1, 2009 to present
|
|||
|
Senior
Vice President, Corporate Relations
|
March
1, 2009 to October 31, 2009
|
|||
|
Senior
Vice President, Corporate Relations, PG&E Corporation
|
November
1, 2007 to October 31, 2009
|
|||
|
Vice
President, Corporate Relations, PG&E Corporation
|
March
1, 2007 to October 31, 2007
|
|||
|
Vice
President, Communications and Marketing, American Gas
Association
|
April
10, 2006 to February 23, 2007
|
|||
|
Chief
Public Affairs Officer, Bechtel National, Inc.
|
June
12, 2004 to September 12, 2005
|
|||
|
Edward
A. Salas
|
Senior
Vice President, Engineering and Operations
|
April
11, 2007 to present
|
||
|
Staff
Vice President, Network Planning, Verizon Wireless
|
May
2004 to April 2007
|
|||
|
John
R. Simon
|
Senior
Vice President, Human Resources
|
April
16, 2007 to present
|
||
|
Senior
Vice President, Human Resources, PG&E Corporation
|
April
16, 2007 to present
|
|||
|
Executive
Vice President, Global Human Capital, TeleTech
|
March
21, 2006 to April 13, 2007
|
|||
|
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
|
43
|
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
|
|||
Item 5.
Market for Registrant's Common
Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
As of
February 16, 2010, there were 81,642 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 2009 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 declared by PG&E Corporation and the Utility is set forth in
the table entitled “Selected Financial Data” and in Note 6 of the Notes to the
Consolidated Financial Statements in the 2009 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” and Note 6 of
the Notes to the Consolidated Financial Statements in the 2009 Annual Report,
which information is incorporated by reference and included in Exhibit 13 to
this report.
Sales of Unregistered Equity
Securities
During the quarter ended December 31,
2009, PG&E Corporation made equity contributions totaling $30 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.
The Utility did not make any sales of
unregistered equity securities during 2009.
During the quarter ended December 31,
2009, PG&E Corporation did not redeem or repurchase any shares of common
stock outstanding. During the fourth quarter of 2009, 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 the
Utility for each of the last five fiscal years, is set forth under the heading
“Selected Financial Data” in the 2009 Annual Report, which information is
incorporated by reference and included in Exhibit 13 to this
report.
A
discussion of PG&E Corporation's and the Utility’s consolidated financial
condition and results of operations is set forth under the heading “Management's
Discussion and Analysis of Financial Condition and
44
Results
of Operations” in the 2009 Annual Report, which discussion is incorporated by
reference and included in Exhibit 13 to this report.
Information
responding to Item 7A appears in the 2009 Annual Report under the heading
“Management's Discussion and Analysis of Financial Condition and Results of
Operations—Risk Management Activities,” and under Notes 10 and 11 of the Notes
to the Consolidated Financial Statements of the 2009 Annual Report, which
information is incorporated by reference and included in Exhibit 13 to this
report.
Information
responding to Item 8 appears in the 2009 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 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 “Reports of Independent Registered Public Accounting Firm,”
which information is incorporated by reference and included in Exhibit 13
to this report.
Not
applicable.
Item
9A.
Controls and
Procedures
Based on
an evaluation of PG&E Corporation's and the Utility's disclosure controls
and procedures as of December 31, 2009, 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, 2009 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 2009 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.
45
Item
9B.
Other
Information
Election
of New Director
On
February 17, 2010, the Board of Directors of the Utility elected Christopher P.
Johns, who is currently the President of the Utility, as a director of the
Utility, effective February 17, 2010. The Utility’s Board of
Directors also appointed Mr. Johns as a member of the Board’s Executive
Committee, effective February 17, 2010.
To
accommodate the election of Mr. Johns, the Board of Directors of the Utility
amended the Utility’s Bylaws to increase the authorized number of directors from
11 to 12, effective February 17, 2010. Under the Utility’s Bylaws,
the authorized number of directors may not be less than 9 nor more than 17, but
within that range the Board of Directors may set the exact number of directors
by an amendment to the Bylaws. The text of the Utility’s Bylaws, as
amended, is attached to this report as Exhibit 3.5.
Under the
Utility’s Corporate Governance Guidelines, at least 75% of its Board is required
to be composed of independent directors, defined as directors who (1) are
neither current nor former officers or employees of, nor consultants to,
PG&E Corporation, the Utility, or its subsidiaries, (2) are neither current
nor former officers or employees of any other corporation on whose board of
directors any officer of the Utility serves as a member, and (3) otherwise meet
the definition of “independence” set forth in the applicable stock exchange
rules. The composition of the Utility’s Board of Directors currently
meets the Corporate Governance Guidelines.
There are
no arrangements or understandings pursuant to which Mr. Johns was selected as a
director of the Utility. Mr. Johns does not have any relationship or
related transaction with PG&E Corporation or the Utility that would require
disclosure pursuant to Item 404(a) of Securities and Exchange Commission
Regulation S-K.
Information
regarding executive officers of PG&E Corporation and the Utility is included
above in a separate item captioned “Executive Officers of the Registrants” at
the end of Part I of this report. Other information regarding
directors is included under the heading “Nominees for Director of PG&E
Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement
relating to the 2010 Annual Meetings of Shareholders, which information is
hereby incorporated by reference. Information regarding compliance
with Section 16 of the Exchange Act is included under the heading
“Section 16(a) Beneficial Ownership Reporting Compliance” in the Joint
Proxy Statement relating to the 2010 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 the
Utility’s website,
www.pge.com
: (1) the
codes of conduct and ethics adopted by PG&E Corporation and the Utility
applicable to their respective directors and employees, including their
respective Chief Executive Officers, Chief Financial Officers, Controllers and
other executive officers, (2) PG&E Corporation's and the Utility's
corporate governance guidelines, and (3) key Board Committee charters,
including charters for the companies' Audit Committees and the PG&E
Corporation Nominating and Governance Committee and Compensation
Committee.
If any
amendments are made to, or any waivers are granted with respect to, provisions
of the codes of conduct and ethics adopted by PG&E Corporation and the
Utility that apply to their respective Chief Executive Officers, Chief Financial
Officers, or Controllers, the company whose code is so affected will disclose
the nature of such amendment or waiver on its respective website and any waivers
to the code will be disclosed in a Current Report on Form 8-K filed within
four business days of the waiver.
46
Procedures
for Shareholder Recommendations of Nominees to the Boards of
Directors
During
2009 there were no material changes to the procedures described in PG&E
Corporation’s and the Utility’s Joint Proxy Statement relating to the
2009 Annual Meetings of Shareholders by which security holders may recommend
nominees to PG&E Corporation’s or Pacific Gas and Electric Company’s Boards
of Directors.
Audit
Committees and Audit Committee Financial Expert
Information
regarding the Audit Committees of PG&E Corporation and the Utility and the
“audit committee financial expert” as defined by the SEC is included under the
heading “Corporate Governance Board Committees Audit Committees” in the
Joint Proxy Statement relating to the 2010 Annual Meetings of Shareholders,
which information is hereby incorporated by reference.
Information
responding to Item 11, for each of PG&E Corporation and the Utility, is
included under the headings “Compensation Discussion and Analysis (CD&A),”
“Compensation Committee Report,” “Summary Compensation Table - 2009,”
“Grants of Plan-Based Awards in 2009,” “Outstanding Equity Awards at Fiscal Year
End - 2009,” “Option Exercises and Stock Vested During 2009,” “Pension Benefits
– 2009,” “Non-Qualified Deferred Compensation,” “Potential Payments
Upon Resignation, Retirement, Termination, Change in Control, Death, or
Disability” and “2009 Director Compensation” in the Joint Proxy Statement
relating to the 2010 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
Item 12.
Security Ownership of Certain
Beneficial Owners and Management and Related Stockholder
Matters
Information
regarding the beneficial ownership of securities for each of PG&E
Corporation and the Utility, is included under the heading “Security Ownership
of Management” and under the heading “Other Information - Principal
Shareholders” in the Joint Proxy Statement relating to the 2010 Annual Meetings
of Shareholders, which information is hereby incorporated by
reference.
Equity
Compensation Plan Information
The
following table provides information as of December 31, 2009 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
|
2,723,349
(1)
|
$23.99
|
9,703,937
(2)
|
|||
|
Equity
compensation plans not approved by
shareholders
|
—
|
—
|
—
|
|||
|
Total
equity compensation plans
|
2,723,349
(1)
|
$23.99
|
9,703,937
(2)
|
|
|
(1) Includes
748,620 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, 2009. 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 13 of the Notes to the Consolidated Financial Statements in
the 2009 Annual Report.
|
47
Item
13.
Certain Relationships and
Related Transactions, and Director Independence
Information
responding to Item 13, for each of PG&E Corporation and the Utility , is
included under the headings “Related Person Transactions,” “Review, Approval,
and Ratification of Related 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 2010
Annual Meetings of Shareholders, which information is hereby incorporated by
reference.
Information
responding to Item 14, for each of PG&E Corporation and the Utility, is
included under the heading “Information Regarding the Independent Registered
Public Accounting Firm for PG&E Corporation and Pacific Gas and Electric
Company” in the Joint Proxy Statement relating to the 2010 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 2009
Annual Report and are incorporated by reference in this report:
Consolidated
Statements of Income for the Years Ended December 31, 2009, 2008, and 2007
for each of PG&E Corporation and Pacific Gas and Electric
Company.
Consolidated
Balance Sheets at December 31, 2009 and 2008 for each of PG&E
Corporation and Pacific Gas and Electric Company.
Consolidated
Statements of Cash Flows for the Years Ended December 31, 2009, 2008, and 2007
for each of PG&E Corporation and Pacific Gas and Electric
Company.
Consolidated
Statements of Equity for the Years Ended December 31, 2009, 2008, and 2007
for PG&E Corporation.
Consolidated
Statements of Shareholders’ Equity for the Years Ended December 31, 2009, 2008,
and 2007 for 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:
Reports
of Independent Registered Public Accounting Firm (Deloitte & Touche
LLP).
48
I—Condensed
Financial Information of Parent as of December 31, 2009 and 2008 and for
the Years Ended December 31, 2009, 2008, and 2007.
II—Consolidated
Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific
Gas and Electric Company for the Years Ended December 31, 2009, 2008, and
2007.
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.
49
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 September 16, 2009 (incorporated by
reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the
Quarter ended September 30, 2009 (File No. 1-12609), Exhibit
3.1)
|
|
|
3.4
|
Restated
Articles of Incorporation of Pacific Gas and Electric Company effective as
of April 12, 2004 (incorporated by reference to Pacific Gas and
Electric Company's Form 8-K filed April 12, 2004 (File
No. 1-2348), Exhibit 3)
|
|
|
3.5
|
Bylaws
of Pacific Gas and Electric Company amended as of February 17,
2010
|
|
|
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 Quarterly Report on Form 10-Q for the quarter ended
March 31, 2005 (File No. 1-12609 and File No. 1-2348),
Exhibit 4.1)
|
|
|
4.2
|
First
Supplemental Indenture dated as of March 13, 2007 relating to the
Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes
due March 1, 2037 (incorporated by reference from Pacific Gas and Electric
Company’s 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
Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes
due November 30, 2017 (incorporated by reference from Pacific Gas and
Electric Company’s 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 Utility’s
issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior
Notes due February 15, 2038 (incorporated by reference to Pacific Gas and
Electric Company’s Current Report on Form 8-K dated March 3, 2008 (File
No. 1-2348), Exhibit 4.1)
|
50
|
Exhibit
Number
|
Exhibit Description | |
|
4.5
|
Fourth
Supplemental Indenture dated as of October 21, 2008 relating to the
Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25%
Senior Notes due October 15, 2018 (incorporated by reference to Pacific
Gas and Electric Company’s Current Report on Form 8-K dated October 21,
2008 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.6
|
Fifth
Supplemental Indenture dated as of November 18, 2008 relating to the
Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25%
Senior Notes due December 1, 2013 and $200 million principal
amount of its 8.25% Senior Notes due October 15, 2018 (incorporated
by reference to Pacific Gas and Electric Company’s Current Report on Form
8-K dated November 18, 2008 (File No. 1-2348), Exhibit
4.1)
|
|
|
4.7
|
Sixth
Supplemental Indenture, dated as of March 6, 2009 relating to the
issuance of $550,000,000 aggregate principal amount of Pacific Gas and
Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated
by reference to Pacific Gas and Electric Company’s Current Report on Form
8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.8
|
Seventh
Supplemental Indenture dated as of June 11, 2009 relating to the
issuance of $500,000,000 aggregate principal amount of Pacific Gas and
Electric Company’s Floating Rate Senior Notes due June 10, 2010
(incorporated by reference to Pacific Gas and Electric Company’s Current
Report on Form 8-K dated June 11, 2009 (File No. 1-2348), Exhibit
4.1)
|
|
|
4.9
|
Eighth
Supplemental Indenture dated as of November 18, 2009 relating to the
issuance of $550,000,000 aggregate principal amount of Pacific Gas and
Electric Company’s Senior Notes due January 15, 2040 (incorporated by
reference to Pacific Gas and Electric Company’s Current Report on Form 8-K
dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.10
|
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).
|
|
|
4.11
|
Supplemental
Indenture amending PG&E Corporation's 7.5% Convertible Subordinated
Notes due 2007 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)
|
|
|
4.12
|
Senior
Note Indenture related to PG&E Corporation’s 5.75% Senior Notes due
April 1, 2014, dated as of March 12, 2009, between PG&E Corporation
and Deutsche Bank Trust Company Americas as Trustee (incorporated by
reference to PG&E Corporation’s Current Report on Form 8-K dated March
10, 2009 (File No. 1-12609), Exhibit 4.1)
|
|
|
4.13
|
First
Supplemental Indenture, dated as of March 12, 2009 relating to the
issuance of $350,000,000 aggregate principal amount of PG&E
Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by
reference to PG&E Corporation’s Current Report on Form 8-K dated March
10, 2009 (File No. 1-12609), Exhibit 4.2)
|
|
|
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)
|
51
|
Exhibit
Number
|
Exhibit Description | |
|
10.2
|
Amendment
and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman
Brothers Bank, FSB has been removed as a lender under the Amended and
Restated Unsecured Revolving Credit Agreement entered into among Pacific
Gas and Electric Company, Citicorp North America, Inc., as administrative
agent and a lender, JPMorgan Securities Inc., as syndication agent,
Barclays Bank Plc and BNP Paribas, as documentation agents and lenders,
Deutsche Bank Securities Inc., as documentation agent, and other lenders,
dated February 26, 2007, filed as Exhibit 10.1 above (incorporated by
reference to PG&E Corporation and Pacific Gas and Electric Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File
No. 1-12609 and File No. 1-2348),
Exhibit 10.2)
|
|
|
10.3
|
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 10.1)
|
|
|
10.4
|
Amendment
and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman
Brothers Bank, FSB has been removed as a lender under the Amended and
Restated Unsecured Revolving Credit Agreement entered into among PG&E
Corporation, BNP Paribas, as administrative agent and a lender, Deutsche
Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of
America, N.A., and Barclays Bank Plc, as documentation agents and lenders,
and other lenders, dated February 26, 2007, filed as Exhibit 10.3 above
(incorporated by reference to PG&E Corporation and Pacific Gas and
Electric Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2009 (File No. 1-12609 and File No. 1-2348),
Exhibit 10.1)
|
|
|
10.5
|
Settlement
Agreement among California Public Utilities Commission, Pacific Gas and
Electric Company and PG&E Corporation, dated as of December 19, 2003,
together with appendices (incorporated by reference to PG&E
Corporation'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)
|
|
|
10.6
|
Transmission
Control Agreement among the California Independent System Operator (CAISO)
and the Participating Transmission Owners, including Pacific Gas and
Electric Company, effective as of March 31, 1998, as amended (CAISO,
FERC Electric Tariff No. 7) (incorporated by reference to PG&E
Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the
year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348),
Exhibit 10.8)
|
|
|
10.7
|
Operating
Agreement, as amended on November 12, 2004, effective as of December 22,
2004, between the State of California Department of Water Resources and
Pacific Gas and Electric Company (incorporated by reference to PG&E
Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the
year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348),
Exhibit 10.9)
|
|
|
*10.8
|
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 Annual Report on Form 10-K for the
year ended December 31, 2004) (File No. 1-12609), Exhibit
10.10)
|
|
|
*10.9
|
PG&E
Corporation 2005 Supplemental Retirement Savings Plan effective as of
January 1, 2005 (as amended to comply with Internal Revenue Code Section
409A regulations effective as of January 1, 2009 and as further amended
with respect to investment options effective as of July 13,
2009)
|
|
|
*10.10
|
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)
|
52
|
Exhibit
Number
|
Exhibit Description | |
|
*10.11
|
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)
|
|
|
*10.12
|
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 Quarterly Report on Form 10-Q for the quarter ended
June 30, 2008 (File No. 1-12609),
Exhibit 10.1)
|
|
|
*10.13
|
Amended
and Restated Restricted Stock Unit Agreement between Peter A. Darbee and
PG&E Corporation (as amended to comply with Internal Revenue Code
Section 409A regulations effective as of January 1, 2009) (incorporated by
reference to PG&E Corporation's Annual Report on Form 10-K for the
year ended December 31, 2008 (File No. 1-12609),
Exhibit 10.11)
|
|
|
*10.14
|
Restricted
Stock Unit Agreement between Peter A. Darbee and PG&E Corporation
dated January 2, 2009 (incorporated by reference to PG&E Corporation's
Annual Report on Form 10-K for the year ended December 31, 2008 (File
No. 1-12609), Exhibit 10.12)
|
|
|
*10.15
|
Letter
regarding Compensation Arrangement between PG&E Corporation and Rand
L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E
Corporation’s Annual Report on Form 10-K for the year ended December 31,
2005) (File No. 1-12609), Exhibit 10.18)
|
|
|
*10.16
|
Letter
regarding Compensation Arrangement between PG&E Corporation and Hyun
Park dated October 10, 2006 (incorporated by reference to PG&E
Corporation’s Annual Report on Form 10-K for the year ended December 31,
2006) (File No. 1-12609), Exhibit 10.18)
|
|
|
*10.17
|
Letter
regarding Compensation Agreement between Pacific Gas and Electric Company
and John S. Keenan dated November 21, 2005 (incorporated by reference to
Pacific Gas and Electric Company’s Annual Report on Form 10-K for the year
ended December 31, 2008 (File No. 1-2348),
Exhibit 10.21)
|
|
|
*10.18
|
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)
|
|
|
*10.19
|
PG&E
Corporation 2005 Deferred Compensation Plan for Non-Employee Directors,
effective as of January 1, 2005 (as amended to comply with Internal
Revenue Code Section 409A regulations effective as of January 1, 2009)
(incorporated by reference to PG&E Corporation's Annual Report on Form
10-K for the year ended December 31, 2008 (File No. 1-12609),
Exhibit 10.24)
|
|
|
*10.20
|
Description
of Short-Term Incentive Plan for Officers of PG&E Corporation and its
subsidiaries, effective January 1, 2009 (incorporated by reference to
PG&E Corporation's Annual Report on Form 10-K for the year ended
December 31, 2008 (File No. 1-12609),
Exhibit 10.26)
|
|
|
*10.21
|
Description
of Short-Term Incentive Plan for Officers of PG&E Corporation and its
subsidiaries, effective January 1, 2010
|
|
|
*10.22
|
Amendment
to PG&E Corporation Short-Term Incentive Programs and Other Bonus
Programs, effective January 1, 2009 (amendment to comply with Internal
Revenue Code Section 409A regulations) (incorporated by reference to
PG&E Corporation's Annual Report on Form 10-K for the year ended
December 31, 2008 (File No. 1-12609),
Exhibit 10.27)
|
|
|
*10.23
|
Amendment
to Pacific Gas and Electric Company Short-Term Incentive Programs and
Other Bonus Programs, effective January 1, 2009 (amendment to comply with
Internal Revenue Code Section 409A regulations) (incorporated by reference
to Pacific Gas and Electric Company’s Annual Report on Form 10-K for the
year ended December 31, 2008 (File No. 1-2348),
Exhibit 10.28)
|
53
|
Exhibit
Number
|
Exhibit Description | |
|
*10.24
|
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) (incorporated by reference to PG&E Corporation's
Annual Report on Form 10-K for the year ended December 31, 2008 (File
No. 1-12609), Exhibit 10.29)
|
|
|
*10.25
|
Pacific
Gas and Electric Company Relocation Assistance Program for Officers
(incorporated by reference to Pacific Gas and Electric Company’s Annual
Report on Form 10-K for the year ended December 31, 2008 (File
No. 1-2348), Exhibit 10.30)
|
|
|
*10.26
|
Postretirement
Life Insurance Plan of the Pacific Gas and Electric Company (incorporated
by reference to Pacific Gas and Electric Company's Annual Report on Form
10-K for fiscal year 1991 (File No. 1-2348),
Exhibit 10.16)
|
|
|
*10.27
|
Amendment
to Postretirement Life Insurance Plan of the Pacific Gas and Electric
Company dated December 30, 2008 (amendment to comply with Internal Revenue
Code Section 409A regulations) (incorporated by reference to Pacific Gas
and Electric Company’s Annual Report on Form 10-K for the year ended
December 31, 2008 (File No. 1-2348),
Exhibit 10.32)
|
|
|
*10.28
|
PG&E
Corporation Non-Employee Director Stock Incentive Plan (a component of the
PG&E Corporation Long-Term Incentive Program) as amended effective as
of July 1, 2004 (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 Annual Report on Form 10-K for the year ended
December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit
10.27)
|
|
|
*10.29
|
Resolution
of the PG&E Corporation Board of Directors dated September 17, 2008,
adopting director compensation arrangement effective January 1, 2009
(incorporated by reference to PG&E Corporation's and Pacific Gas and
Electric Company's Annual Report on Form 10-K for the year ended December
31, 2008 (File No. 1-12609 and File No. 12348),
Exhibit 10.36)
|
|
|
*10.30
|
Resolution
of the Pacific Gas and Electric Company Board of Directors dated September
17, 2008, adopting director compensation arrangement effective January 1,
2009 (incorporated by reference to PG&E Corporation's and Pacific Gas
and Electric Company's Annual Report on Form 10-K for the year ended
December 31, 2008 (File No. 1-12609 and File No. 12348),
Exhibit 10.37)
|
|
|
*10.31
|
PG&E
Corporation 2006 Long-Term Incentive Plan, as amended through December
16, 2009
|
|
|
*10.32
|
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)
|
|
|
*10.33
|
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 Current Report
on Form 8-K filed January 6, 2005 (File No. 12609 and File
No. 1-2348), Exhibit 99.3)
|
|
|
*10.34
|
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 Current Report
on Form 8-K filed January 9, 2006, Exhibit 99.1)
|
|
|
*10.35
|
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 Annual Report
on Form 10-K for the year ended December 31, 2006 (File No. 1-12609),
Exhibit 10.39)
|
54
|
Exhibit
Number
|
Exhibit Description | |
|
*10.36
|
Form
of Restricted Stock Agreement for 2008 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2008 (File No. 1-12609),
Exhibit 10.5)
|
|
|
*10.37
|
Form
of Amendment to Restricted Stock Agreements for grants made between
January 2005 and March 2008 (amendments to comply with Internal Revenue
Code Section 409A Regulations) (incorporated by reference to PG&E
Corporation's Annual Report on Form 10-K for the year ended December 31,
2008 (File No. 1-12609), Exhibit 10.45)
|
|
|
*10.38
|
Form
of Restricted Stock Unit Agreement for 2009 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2009 (File No. 1-12609),
Exhibit 10.2)
|
|
|
*10.39
|
Form
of Performance Share Agreement for 2009 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2009 (File No. 1-12609),
Exhibit 10.3)
|
|
|
*10.40
|
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 Current Report on Form
8-K filed January 6, 2005 (File No. 12609 and File
No. 1-2348), Exhibit 99.1)
|
|
|
*10.41
|
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 Current Report
on Form 8-K filed January 9, 2006, Exhibit 99.2)
|
|
|
*10.42
|
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 Annual Report
on Form 10-K for the year ended December 31, 2006 (File No. 1-12609),
Exhibit 10.44)
|
|
|
*10.43
|
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 Quarterly Report on Form 10-Q for the quarter ended
March 31, 2008 (File No. 1-12609),
Exhibit 10.6)
|
|
|
*10.44
|
Form
of Amended and Restated Performance Share Agreement for 2006 grants
(amendments to comply with Internal Revenue Code Section 409A Regulations)
(incorporated by reference to PG&E Corporation's Annual Report on Form
10-K for the year ended December 31, 2008 (File No. 1-12609),
Exhibit 10.51)
|
|
|
*10.45
|
Form
of Amended and Restated Performance Share Agreement for 2007 grants
(amendments to comply with Internal Revenue Code Section 409A
Regulations)
(
incorporated by reference to PG&E Corporation's Annual Report
on Form 10-K for the year ended December 31, 2008 (File No. 1-12609),
Exhibit 10.52)
|
|
|
*10.46
|
Form
of Amended and Restated Performance Share Agreement for 2008 grants
(amendments to comply with Internal Revenue Code Section 409A
Regulations)
(
incorporated by reference to PG&E Corporation's Annual Report
on Form 10-K for the year ended December 31, 2008 (File No. 1-12609),
Exhibit 10.53)
|
|
|
*10.47
|
PG&E
Corporation Executive Stock Ownership Program Guidelines as amended
effective February 17, 2009 (incorporated by reference to PG&E
Corporation's Annual Report on Form 10-K for the year ended December 31,
2008 (File No. 1-12609), Exhibit 10.54)
|
|
|
*10.48
|
PG&E
Corporation Officer Severance Policy, as amended effective as of February
15, 2006 (incorporated by reference to PG&E Corporation's Annual
Report on Form 10-K for the year ended December 31, 2005 (File
No. 1-12609), Exhibit 10.48)
|
55
|
Exhibit
Number
|
Exhibit Description | |
|
*10.49
|
PG&E
Corporation Officer Severance Policy, as amended effective as of January
1, 2009 (amended to comply with Internal Revenue Code Section 409A
regulations) (incorporated by reference to PG&E Corporation's Annual
Report on Form 10-K for the year ended December 31, 2008 (File
No. 1-12609), Exhibit 10.56)
|
|
|
*10.50
|
PG&E
Corporation Golden Parachute Restriction Policy effective as of February
15, 2006 (incorporated by reference to PG&E Corporation's Annual
Report on Form 10-K for the year ended December 31, 2005 (File
No. 1-12609), Exhibit 10.49)
|
|
|
*10.51
|
Amendment
to PG&E Corporation Golden Parachute Restriction Policy dated December
31, 2008 (amendment to comply with Internal Revenue Code Section 409A
Regulations) (incorporated by reference to PG&E Corporation's Annual
Report on Form 10-K for the year ended December 31, 2008 (File
No. 1-12609), Exhibit 10.58)
|
|
|
*10.52
|
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)
|
|
|
*10.53
|
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 Annual Report on Form 10-K for the year ended December 31,
2004 (File No. 1-12609), Exhibit 10.39)
|
|
|
*10.54
|
PG&E
Corporation and Pacific Gas and Electric Company Executive Incentive
Compensation Recoupment Policy effective as of February 17,
2009
|
|
|
*10.55
|
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 Annual Report on Form
10-K for the year ended December 31, 2004 (File No. 1-12609),
Exhibit 10.40)
|
|
|
*10.56
|
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 Annual
Report on Form 10-K for the year ended December 31, 2004 (File
No. 1-2348), Exhibit 10.41)
|
|
|
12.1
|
Computation
of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric
Company
|
|
|
12.2
|
Computation
of Ratios of Earnings to Combined Fixed Charges and Preferred Stock
Dividends for Pacific Gas and Electric Company
|
|
|
12.3
|
Computation
of Ratios of Earnings to Fixed Charges for PG&E
Corporation
|
|
|
13
|
The
following portions of the 2009 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 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
|
56
|
Exhibit
Number
|
Exhibit Description | |
|
31.1
|
Certifications
of the Chief Executive Officer and the Chief Financial Officer of PG&E
Corporation required by Section 302 of the Sarbanes-Oxley Act of
2002
|
|
|
31.2
|
Certifications
of the Chief Executive Officer and the Chief Financial Officer of Pacific
Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act
of 2002
|
|
|
**32.1
|
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
|
|
|
***101.INS
|
XBRL
Instance Document
|
|
|
***101.SCH
|
XBRL
Taxonomy Extension Schema Document
|
|
|
***101.CAL
|
XBRL
Taxonomy Extension Calculation Linkbase Document
|
|
|
***101.LAB
|
XBRL
Taxonomy Extension Labels Linkbase Document
|
|
|
***101.PRE
|
XBRL
Taxonomy Extension Presentation Linkbase Document
|
|
|
***101.DEF
|
XBRL
Taxonomy Extension Definition Linkbase Document
|
|
* Management
contract or compensatory agreement.
|
**
|
Pursuant
to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished
rather than filed with this report.
|
|
***
|
Pursuant
to Rule 406T of SEC Regulation S-T, these interactive data files are
deemed not filed or part of a registration statement or prospectus for
purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18
of the Securities Exchange Act of 1934 and otherwise are not subject to
liability under these sections. These files are being submitted
only by PG&E Corporation and not by its subsidiary, Pacific Gas and
Electric Company.
|
57
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, 2009 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)
*CHRISTOPHER
P. JOHNS
|
||
|
By:
|
Peter
A. Darbee
Chairman
of the Board, Chief Executive Officer,
and
President
|
By:
|
Christopher
P. Johns
President
|
|
Date:
|
February
19, 2010
|
Date:
|
February
19, 2010
|
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, and President (PG&E
Corporation)
|
February
19, 2010
|
||||||
|
Peter
A. Darbee
|
||||||||
|
*CHRISTOPHER
P. JOHNS
|
President
(Pacific Gas and Electric Company)
|
February
19, 2010
|
||||||
|
Christopher P.
Johns
|
||||||||
|
|
||||||||
|
B. Principal
Financial Officers
|
||||||||
|
*KENT
M. HARVEY
|
Senior
Vice President, Chief Financial Officer, and Treasurer (PG&E
Corporation)
|
February
19, 2010
|
||||||
|
Kent
M. Harvey
|
||||||||
|
*BARBARA
L. BARCON
|
Vice
President, Finance and Chief Financial Officer (Pacific Gas and
Electric Company)
|
February
19, 2010
|
||||||
|
Barbara
L. Barcon
|
||||||||
|
C.
Principal Accounting Officer
|
||||||||
|
*STEPHEN
J. CAIRNS
|
Vice
President and Controller (PG&E Corporation and
Pacific
Gas and Electric Company)
|
February
19, 2010
|
||||||
|
Stephen
J. Cairns
|
||||||||
|
D. Directors
|
||||||||
|
*DAVID
R. ANDREWS
|
Director
|
February
19, 2010
|
||||||
|
David
R. Andrews
|
||||||||
|
*LEWIS
CHEW
|
Director
|
February
19, 2010
|
||||||
|
Lewis
Chew
|
||||||||
58
|
*C.
LEE COX
|
Director
|
February
19, 2010
|
||||||
|
C.
Lee Cox
|
||||||||
|
*PETER
A. DARBEE
|
Director
|
February
19, 2010
|
||||||
|
Peter
A. Darbee
|
||||||||
|
*MARYELLEN
C. HERRINGER
|
Director
|
February
19, 2010
|
||||||
|
Maryellen
C. Herringer
|
||||||||
|
*CHRISTOPHER
P. JOHNS
|
Director
(Pacific Gas and Electric Company only)
|
February
19, 2010
|
||||||
|
Christopher
P. Johns
|
||||||||
|
*ROGER
H. KIMMEL
|
Director
|
February
19. 2010
|
||||||
|
Roger
H. Kimmel
|
||||||||
|
*RICHARD
A. MESERVE
|
Director
|
February
19. 2010
|
||||||
|
Richard
A. Meserve
|
||||||||
|
*FORREST
E. MILLER
|
Director
|
February
19, 2010
|
||||||
|
Forrest
E. Miller
|
||||||||
|
|
||||||||
|
*ROSENDO
G. PARRA
|
Director
|
February
19, 2010
|
||||||
|
Rosendo
G. Parra
|
||||||||
|
*BARBARA
L. RAMBO
|
Director
|
February
19, 2010
|
||||||
|
Barbara
L. Rambo
|
||||||||
|
*BARRY
LAWSON WILLIAMS
|
Director
|
February
19, 2010
|
||||||
|
Barry
Lawson Williams
|
||||||||
|
*By:
|
HYUN
PARK.
|
|||||||
|
HYUN
PARK, Attorney-in-Fact
|
||||||||
59
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, 2009 and 2008, and for each
of the three years in the period ended December 31, 2009, and the Company’s
and the Utility’s internal control over financial reporting as of
December 31, 2009, and have issued our report thereon dated
February 19, 2010; such consolidated financial statements and our report
are included in your 2009 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,
2010
San
Francisco, CA
60
PG&E
CORPORATION
SCHEDULE I
—
CONDENSED FINANCIAL INFORMATION OF
PARENT
—
(Continued)
CONDENSED
STATEMENTS OF INCOME
(in
millions, except per share amounts)
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Administrative
service revenue
|
$ | 59 | $ | 119 | $ | 102 | ||||||
|
Equity
in earnings of subsidiaries
|
1,231 | 1,182 | 1,006 | |||||||||
|
Operating
expenses
|
(61 | ) | (105 | ) | (112 | ) | ||||||
|
Interest
income
|
1 | 4 | 15 | |||||||||
|
Interest
expense
|
(43 | ) | (30 | ) | (31 | ) | ||||||
|
Other
income (expense)
|
11 | (46 | ) | (6 | ) | |||||||
|
Income
before income taxes
|
1,198 | 1,124 | 974 | |||||||||
|
Income
tax benefit
|
22 | 60 | 32 | |||||||||
|
Income
from continuing operations
|
1,220 | 1,184 | 1,006 | |||||||||
|
Gain
on disposal of National Energy & Gas Transmission, Inc.
(“NEGT”)
|
- | 154 | - | |||||||||
|
Income
Available for Common Shareholders
|
$ | 1,220 | $ | 1,338 | $ | 1,006 | ||||||
|
Weighted
average common shares outstanding, basic
|
368 | 357 | 351 | |||||||||
|
Weighted
average common shares outstanding, diluted
|
386 | 358 | 353 | |||||||||
|
Earnings
per common share, basic
|
$ | 3.25 | $ | 3.64 | $ | 2.79 | ||||||
|
Earnings
per common share, diluted
|
$ | 3.20 | $ | 3.63 | $ | 2.78 | ||||||
PG&E
Corporation currently has outstanding $247 million principal amount of
convertible subordinated 9.50% notes due 2010 (“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,
are entitled to receive pass-through dividends and meet the criteria of a
participating security in the calculation of earnings per share (“EPS”) using
the "two-class" method for basic EPS.
In
calculating diluted EPS, PG&E Corporation applies the if-converted method to
reflect the dilutive effect of the Convertible Notes to the extent that the
impact is dilutive when compared to basic EPS. In addition, PG&E
Corporation applies the treasury stock method of reflecting the dilutive effect
of outstanding stock-based compensation in the calculation of diluted
EPS.
Accordingly,
the basic and diluted earnings per share calculations for 2008 and 2007 reflect
the allocation of earnings between PG&E Corporation common stock and the
participating security.
61
PG&E
CORPORATION
SCHEDULE I
—
CONDENSED FINANCIAL INFORMATION OF
PARENT
CONDENSED
BALANCE SHEETS
(in
millions)
|
Balance at
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
||||||||
|
Current
Assets
:
|
||||||||
|
Cash
and cash equivalents
|
$ | 193 | $ | 167 | ||||
|
Advances
to affiliates
|
20 | 28 | ||||||
|
Deferred
income taxes
|
3 | - | ||||||
|
Income
taxes receivable
|
9 | 148 | ||||||
|
Other
current assets
|
5 | 14 | ||||||
|
Total
current assets
|
230 | 357 | ||||||
|
Equipment
|
14 | 17 | ||||||
|
Accumulated
depreciation
|
(13 | ) | (15 | ) | ||||
|
Net
equipment
|
1 | 2 | ||||||
|
Investments
in subsidiaries
|
10,935 | 9,539 | ||||||
|
Other
investments
|
84 | 68 | ||||||
|
Deferred
income taxes
|
32 | 51 | ||||||
|
Other
|
4 | 4 | ||||||
|
Total
Assets
|
$ | 11,286 | $ | 10,021 | ||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||
|
Current
Liabilities:
|
||||||||
|
Accounts
payable—related parties
|
$ | 32 | $ | 34 | ||||
|
Accounts
payable—other
|
2 | 18 | ||||||
|
Long-term
debt – classified as current
|
247 | - | ||||||
|
Income
taxes payable
|
12 | - | ||||||
|
Other
|
199 | 189 | ||||||
|
Total
current liabilities
|
492 | 241 | ||||||
|
Noncurrent
Liabilities:
|
||||||||
|
Long-term
debt
|
348 | 280 | ||||||
|
Income
taxes payable
|
14 | 23 | ||||||
|
Other
|
99 | 100 | ||||||
|
Total
noncurrent liabilities
|
461 | 403 | ||||||
|
Common
Shareholders' Equity
|
||||||||
|
Common
stock
|
6,280 | 5,984 | ||||||
|
Common
stock held by subsidiary
|
- | - | ||||||
|
Reinvested
earnings
|
4,213 | 3,614 | ||||||
|
Accumulated
other comprehensive income
|
(160 | ) | (221 | ) | ||||
|
Total
common shareholders' equity
|
10,333 | 9,377 | ||||||
|
Total
Liabilities and Shareholders' Equity
|
$ | 11,286 | $ | 10,021 | ||||
62
PG&E
CORPORATION
SCHEDULE
I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED
STATEMENTS OF CASH FLOWS
(in
millions)
|
Year
Ended December 31,
|
||||||||||
|
2009
|
2008
|
2007
|
||||||||
|
Cash
Flows from Operating Activities:
|
||||||||||
| Net Income | $ | 1,220 | $ | 1,338 | $ | 1,066 | ||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||||
|
Depreciation
and amortization
|
20
|
27
|
34
|
|||||||
|
Equity
in earnings of subsidiaries
|
(1,231)
|
(1,180)
|
(1,006)
|
|||||||
|
Noncurrent
income taxes receivable/payable
|
(9)
|
(108)
|
4
|
|||||||
|
Current
income taxes receivable/payable
|
148
|
46
|
-
|
|||||||
|
Other
|
(13)
|
(150)
|
(14)
|
|||||||
|
Net
cash provided by (used in) operating activities
|
135
|
(27)
|
24
|
|||||||
|
Cash
Flows From Investing Activities:
|
||||||||||
|
Investment
in subsidiaries
|
(721)
|
(275)
|
(405)
|
|||||||
|
Dividends
received from subsidiaries
|
624
|
596
|
509
|
|||||||
|
Other
|
10
|
(12)
|
(1)
|
|||||||
|
Net
cash (used in) provided by investing activities
|
(87)
|
309
|
103
|
|||||||
|
Cash
Flows From Financing Activities
(1)
:
|
||||||||||
|
Proceeds
from issuance of long-term debt, net of discount and issuance costs of $2
million in 2009
|
348
|
-
|
-
|
|||||||
|
Common
stock issued
|
219
|
225
|
175
|
|||||||
|
Common
stock dividends paid
|
(590)
|
(546)
|
(496)
|
|||||||
|
Other
|
1
|
2
|
12
|
|||||||
|
Net
cash used in financing activities
|
(22)
|
(319)
|
(309)
|
|||||||
|
Net
change in cash and cash equivalents
|
26
|
(37)
|
(182)
|
|||||||
|
Cash
and cash equivalents at January 1
|
167
|
204
|
386
|
|||||||
|
Cash
and cash equivalents at December 31
|
$
|
193
|
$
|
167
|
$
|
204
|
||||
|
(1)
On January 15, 2009, PG&E Corporation paid a quarterly common stock
dividend of $0.39 per share. On April 15, July 15, and October
15, 2009, PG&E Corporation paid quarterly common stock dividends of
$0.42 per share.
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.
|
63
Pacific
Gas and Electric Company
SCHEDULE
II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For
the Years Ended December 31, 2009, 2008, and 2007
|
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:
|
||||||||||||||||||||
|
2009:
|
||||||||||||||||||||
|
Allowance
for uncollectible accounts
(1)
|
$ | 76 | $ | 68 | $ | - | $ | 76 | $ | 68 | ||||||||||
|
2008:
|
||||||||||||||||||||
|
Allowance
for uncollectible accounts
(1)
|
$ | 58 | $ | 68 | $ | 11 | $ | 61 | $ | 76 | ||||||||||
|
2007:
|
||||||||||||||||||||
|
Allowance
for uncollectible accounts
(1)
|
$ | 50 | $ | 20 | $ | - | $ | 12 | $ | 58 | ||||||||||
|
(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.
|
||||||||||||||||||||
64
PG&E
Corporation
SCHEDULE
II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For
the Years Ended December 31, 2009, 2008, and 2007
|
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:
|
||||||||||||||||||||
|
2009:
|
||||||||||||||||||||
|
Allowance
for uncollectible accounts
(1)(2)
|
$ | 76 | $ | 68 | $ | - | $ | 76 | $ | 68 | ||||||||||
|
2008:
|
||||||||||||||||||||
|
Allowance
for uncollectible accounts
(1)(2)
|
$ | 58 | $ | 68 | $ | 11 | $ | 61 | $ | 76 | ||||||||||
|
2007:
|
||||||||||||||||||||
|
Allowance
for uncollectible accounts
(1)(2)
|
$ | 50 | $ | 20 | $ | - | $ | 12 | $ | 58 | ||||||||||
|
(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.
|
||||||||||||||||||||
65
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 September 16, 2009 (incorporated by
reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the
Quarter ended September 30, 2009 (File No. 1-12609), Exhibit
3.1)
|
|
|
3.4
|
Restated
Articles of Incorporation of Pacific Gas and Electric Company effective as
of April 12, 2004 (incorporated by reference to Pacific Gas and
Electric Company's Form 8-K filed April 12, 2004 (File
No. 1-2348), Exhibit 3)
|
|
|
3.5
|
Bylaws
of Pacific Gas and Electric Company amended as of February 17,
2010
|
|
|
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 Quarterly Report on Form 10-Q for the quarter ended
March 31, 2005 (File No. 1-12609 and File No. 1-2348),
Exhibit 4.1)
|
|
|
4.2
|
First
Supplemental Indenture dated as of March 13, 2007 relating to the
Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes
due March 1, 2037 (incorporated by reference from Pacific Gas and Electric
Company’s 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
Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes
due November 30, 2017 (incorporated by reference from Pacific Gas and
Electric Company’s 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 Utility’s
issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior
Notes due February 15, 2038 (incorporated by reference to Pacific Gas and
Electric Company’s 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
|
Fifth
Supplemental Indenture dated as of November 18, 2008 relating to the
Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25%
Senior Notes due December 1, 2013 and $200 million principal
amount of its 8.25% Senior Notes due October 15, 2018 (incorporated
by reference to Pacific Gas and Electric Company’s Current Report on Form
8-K dated November 18, 2008 (File No. 1-2348), Exhibit
4.1)
|
|
|
4.7
|
Sixth
Supplemental Indenture, dated as of March 6, 2009 relating to the
issuance of $550,000,000 aggregate principal amount of Pacific Gas and
Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated
by reference to Pacific Gas and Electric Company’s Current Report on Form
8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.8
|
Seventh
Supplemental Indenture dated as of June 11, 2009 relating to the
issuance of $500,000,000 aggregate principal amount of Pacific Gas and
Electric Company’s Floating Rate Senior Notes due June 10, 2010
(incorporated by reference to Pacific Gas and Electric Company’s Current
Report on Form 8-K dated June 11, 2009 (File No. 1-2348), Exhibit
4.1)
|
|
|
4.9
|
Eighth
Supplemental Indenture dated as of November 18, 2009 relating to the
issuance of $550,000,000 aggregate principal amount of Pacific Gas and
Electric Company’s Senior Notes due January 15, 2040 (incorporated by
reference to Pacific Gas and Electric Company’s Current Report on Form 8-K
dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.10
|
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).
|
|
|
4.11
|
Supplemental
Indenture amending PG&E Corporation's 7.5% Convertible Subordinated
Notes due 2007 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)
|
|
|
4.12
|
Senior
Note Indenture related to PG&E Corporation’s 5.75% Senior Notes due
April 1, 2014, dated as of March 12, 2009, between PG&E Corporation
and Deutsche Bank Trust Company Americas as Trustee (incorporated by
reference to PG&E Corporation’s Current Report on Form 8-K dated March
10, 2009 (File No. 1-12609), Exhibit 4.1)
|
|
|
4.13
|
First
Supplemental Indenture, dated as of March 12, 2009 relating to the
issuance of $350,000,000 aggregate principal amount of PG&E
Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by
reference to PG&E Corporation’s Current Report on Form 8-K dated March
10, 2009 (File No. 1-12609), Exhibit 4.2)
|
|
|
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
|
Amendment
and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman
Brothers Bank, FSB has been removed as a lender under the Amended and
Restated Unsecured Revolving Credit Agreement entered into among Pacific
Gas and Electric Company, Citicorp North America, Inc., as administrative
agent and a lender, JPMorgan Securities Inc., as syndication agent,
Barclays Bank Plc and BNP Paribas, as documentation agents and lenders,
Deutsche Bank Securities Inc., as documentation agent, and other lenders,
dated February 26, 2007, filed as Exhibit 10.1 above (incorporated by
reference to PG&E Corporation and Pacific Gas and Electric Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File
No. 1-12609 and File No. 1-2348),
Exhibit 10.2)
|
|
|
10.3
|
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 10.1)
|
|
|
10.4
|
Amendment
and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman
Brothers Bank, FSB has been removed as a lender under the Amended and
Restated Unsecured Revolving Credit Agreement entered into among PG&E
Corporation, BNP Paribas, as administrative agent and a lender, Deutsche
Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of
America, N.A., and Barclays Bank Plc, as documentation agents and lenders,
and other lenders, dated February 26, 2007, filed as Exhibit 10.3 above
(incorporated by reference to PG&E Corporation and Pacific Gas and
Electric Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2009 (File No. 1-12609 and File No. 1-2348),
Exhibit 10.1)
|
|
|
10.5
|
Settlement
Agreement among California Public Utilities Commission, Pacific Gas and
Electric Company and PG&E Corporation, dated as of December 19, 2003,
together with appendices (incorporated by reference to PG&E
Corporation'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)
|
|
|
10.6
|
Transmission
Control Agreement among the California Independent System Operator (CAISO)
and the Participating Transmission Owners, including Pacific Gas and
Electric Company, effective as of March 31, 1998, as amended (CAISO,
FERC Electric Tariff No. 7) (incorporated by reference to PG&E
Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the
year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348),
Exhibit 10.8)
|
|
|
10.7
|
Operating
Agreement, as amended on November 12, 2004, effective as of December 22,
2004, between the State of California Department of Water Resources and
Pacific Gas and Electric Company (incorporated by reference to PG&E
Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the
year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348),
Exhibit 10.9)
|
|
|
*10.8
|
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 Annual Report on Form 10-K for the
year ended December 31, 2004) (File No. 1-12609), Exhibit
10.10)
|
|
|
*10.9
|
PG&E
Corporation 2005 Supplemental Retirement Savings Plan effective as of
January 1, 2005 (as amended to comply with Internal Revenue Code Section
409A regulations effective as of January 1, 2009 and as further amended
with respect to investment options effective as of July 13,
2009)
|
|
|
*10.10
|
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)
|
|
|
*10.11
|
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)
|
|
|
*10.12
|
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 Quarterly Report on Form 10-Q for the quarter ended
June 30, 2008 (File No. 1-12609),
Exhibit 10.1)
|
|
|
*10.13
|
Amended
and Restated Restricted Stock Unit Agreement between Peter A. Darbee and
PG&E Corporation (as amended to comply with Internal Revenue Code
Section 409A regulations effective as of January 1, 2009) (incorporated by
reference to PG&E Corporation's Annual Report on Form 10-K for the
year ended December 31, 2008 (File No. 1-12609),
Exhibit 10.11)
|
|
|
*10.14
|
Restricted
Stock Unit Agreement between Peter A. Darbee and PG&E Corporation
dated January 2, 2009 (incorporated by reference to PG&E Corporation's
Annual Report on Form 10-K for the year ended December 31, 2008 (File
No. 1-12609), Exhibit 10.12)
|
|
|
*10.15
|
Letter
regarding Compensation Arrangement between PG&E Corporation and Rand
L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E
Corporation’s Annual Report on Form 10-K for the year ended December 31,
2005) (File No. 1-12609), Exhibit 10.18)
|
|
|
*10.16
|
Letter
regarding Compensation Arrangement between PG&E Corporation and Hyun
Park dated October 10, 2006 (incorporated by reference to PG&E
Corporation’s Annual Report on Form 10-K for the year ended December 31,
2006) (File No. 1-12609), Exhibit 10.18)
|
|
|
*10.17
|
Letter
regarding Compensation Agreement between Pacific Gas and Electric Company
and John S. Keenan dated November 21, 2005 (incorporated by reference to
Pacific Gas and Electric Company’s Annual Report on Form 10-K for the year
ended December 31, 2008 (File No. 1-2348),
Exhibit 10.21)
|
|
|
*10.18
|
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)
|
|
|
*10.19
|
PG&E
Corporation 2005 Deferred Compensation Plan for Non-Employee Directors,
effective as of January 1, 2005 (as amended to comply with Internal
Revenue Code Section 409A regulations effective as of January 1, 2009)
(incorporated by reference to PG&E Corporation's Annual Report on Form
10-K for the year ended December 31, 2008 (File No. 1-12609),
Exhibit 10.24)
|
|
|
*10.20
|
Description
of Short-Term Incentive Plan for Officers of PG&E Corporation and its
subsidiaries, effective January 1, 2009 (incorporated by reference to
PG&E Corporation's Annual Report on Form 10-K for the year ended
December 31, 2008 (File No. 1-12609),
Exhibit 10.26)
|
|
|
*10.21
|
Description
of Short-Term Incentive Plan for Officers of PG&E Corporation and its
subsidiaries, effective January 1, 2010
|
|
|
*10.22
|
Amendment
to PG&E Corporation Short-Term Incentive Programs and Other Bonus
Programs, effective January 1, 2009 (amendment to comply with Internal
Revenue Code Section 409A regulations) (incorporated by reference to
PG&E Corporation's Annual Report on Form 10-K for the year ended
December 31, 2008 (File No. 1-12609),
Exhibit 10.27)
|
|
|
*10.23
|
Amendment
to Pacific Gas and Electric Company Short-Term Incentive Programs and
Other Bonus Programs, effective January 1, 2009 (amendment to comply with
Internal Revenue Code Section 409A regulations) (incorporated by reference
to Pacific Gas and Electric Company’s Annual Report on Form 10-K for the
year ended December 31, 2008 (File No. 1-2348),
Exhibit 10.28)
|
|
|
*10.24
|
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) (incorporated by reference to PG&E Corporation's
Annual Report on Form 10-K for the year ended December 31, 2008 (File
No. 1-12609), Exhibit 10.29)
|
|
|
*10.25
|
Pacific
Gas and Electric Company Relocation Assistance Program for Officers
(incorporated by reference to Pacific Gas and Electric Company’s Annual
Report on Form 10-K for the year ended December 31, 2008 (File
No. 1-2348), Exhibit 10.30)
|
|
|
*10.26
|
Postretirement
Life Insurance Plan of the Pacific Gas and Electric Company (incorporated
by reference to Pacific Gas and Electric Company's Annual Report on Form
10-K for fiscal year 1991 (File No. 1-2348),
Exhibit 10.16)
|
|
|
*10.27
|
Amendment
to Postretirement Life Insurance Plan of the Pacific Gas and Electric
Company dated December 30, 2008 (amendment to comply with Internal Revenue
Code Section 409A regulations) (incorporated by reference to Pacific Gas
and Electric Company’s Annual Report on Form 10-K for the year ended
December 31, 2008 (File No. 1-2348),
Exhibit 10.32)
|
|
|
*10.28
|
PG&E
Corporation Non-Employee Director Stock Incentive Plan (a component of the
PG&E Corporation Long-Term Incentive Program) as amended effective as
of July 1, 2004 (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 Annual Report on Form 10-K for the year ended
December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit
10.27)
|
|
|
*10.29
|
Resolution
of the PG&E Corporation Board of Directors dated September 17, 2008,
adopting director compensation arrangement effective January 1, 2009
(incorporated by reference to PG&E Corporation's and Pacific Gas and
Electric Company's Annual Report on Form 10-K for the year ended December
31, 2008 (File No. 1-12609 and File No. 12348),
Exhibit 10.36)
|
|
|
*10.30
|
Resolution
of the Pacific Gas and Electric Company Board of Directors dated September
17, 2008, adopting director compensation arrangement effective January 1,
2009 (incorporated by reference to PG&E Corporation's and Pacific Gas
and Electric Company's Annual Report on Form 10-K for the year ended
December 31, 2008 (File No. 1-12609 and File No. 12348),
Exhibit 10.37)
|
|
|
*10.31
|
PG&E
Corporation 2006 Long-Term Incentive Plan, as amended through December
16, 2009
|
|
|
*10.32
|
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)
|
|
|
*10.33
|
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 Current Report
on Form 8-K filed January 6, 2005 (File No. 12609 and File
No. 1-2348), Exhibit 99.3)
|
|
|
*10.34
|
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 Current Report
on Form 8-K filed January 9, 2006, Exhibit 99.1)
|
|
|
*10.35
|
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 Annual Report
on Form 10-K for the year ended December 31, 2006 (File No. 1-12609),
Exhibit 10.39)
|
|
|
*10.36
|
Form
of Restricted Stock Agreement for 2008 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2008 (File No. 1-12609),
Exhibit 10.5)
|
|
|
*10.37
|
Form
of Amendment to Restricted Stock Agreements for grants made between
January 2005 and March 2008 (amendments to comply with Internal Revenue
Code Section 409A Regulations) (incorporated by reference to PG&E
Corporation's Annual Report on Form 10-K for the year ended December 31,
2008 (File No. 1-12609), Exhibit 10.45)
|
|
|
*10.38
|
Form
of Restricted Stock Unit Agreement for 2009 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2009 (File No. 1-12609),
Exhibit 10.2)
|
|
|
*10.39
|
Form
of Performance Share Agreement for 2009 grants under the PG&E
Corporation 2006 Long-Term Incentive Plan (incorporated by reference to
PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2009 (File No. 1-12609),
Exhibit 10.3)
|
|
|
*10.40
|
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 Current Report on Form
8-K filed January 6, 2005 (File No. 12609 and File
No. 1-2348), Exhibit 99.1)
|
|
|
*10.41
|
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 Current Report
on Form 8-K filed January 9, 2006, Exhibit 99.2)
|
|
|
*10.42
|
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 Annual Report
on Form 10-K for the year ended December 31, 2006 (File No. 1-12609),
Exhibit 10.44)
|
|
|
*10.43
|
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 Quarterly Report on Form 10-Q for the quarter ended
March 31, 2008 (File No. 1-12609),
Exhibit 10.6)
|
|
|
*10.44
|
Form
of Amended and Restated Performance Share Agreement for 2006 grants
(amendments to comply with Internal Revenue Code Section 409A Regulations)
(incorporated by reference to PG&E Corporation's Annual Report on Form
10-K for the year ended December 31, 2008 (File No. 1-12609),
Exhibit 10.51)
|
|
|
*10.45
|
Form
of Amended and Restated Performance Share Agreement for 2007 grants
(amendments to comply with Internal Revenue Code Section 409A
Regulations)
(
incorporated by reference to PG&E Corporation's Annual Report
on Form 10-K for the year ended December 31, 2008 (File No. 1-12609),
Exhibit 10.52)
|
|
|
*10.46
|
Form
of Amended and Restated Performance Share Agreement for 2008 grants
(amendments to comply with Internal Revenue Code Section 409A
Regulations)
(
incorporated by reference to PG&E Corporation's Annual Report
on Form 10-K for the year ended December 31, 2008 (File No. 1-12609),
Exhibit 10.53)
|
|
|
*10.47
|
PG&E
Corporation Executive Stock Ownership Program Guidelines as amended
effective February 17, 2009 (incorporated by reference to PG&E
Corporation's Annual Report on Form 10-K for the year ended December 31,
2008 (File No. 1-12609), Exhibit 10.54)
|
|
|
*10.48
|
PG&E
Corporation Officer Severance Policy, as amended effective as of February
15, 2006 (incorporated by reference to PG&E Corporation's Annual
Report on Form 10-K for the year ended December 31, 2005 (File
No. 1-12609), Exhibit 10.48)
|
|
|
*10.49
|
PG&E
Corporation Officer Severance Policy, as amended effective as of January
1, 2009 (amended to comply with Internal Revenue Code Section 409A
regulations) (incorporated by reference to PG&E Corporation's Annual
Report on Form 10-K for the year ended December 31, 2008 (File
No. 1-12609), Exhibit 10.56)
|
|
|
*10.50
|
PG&E
Corporation Golden Parachute Restriction Policy effective as of February
15, 2006 (incorporated by reference to PG&E Corporation's Annual
Report on Form 10-K for the year ended December 31, 2005 (File
No. 1-12609), Exhibit 10.49)
|
|
|
*10.51
|
Amendment
to PG&E Corporation Golden Parachute Restriction Policy dated December
31, 2008 (amendment to comply with Internal Revenue Code Section 409A
Regulations) (incorporated by reference to PG&E Corporation's Annual
Report on Form 10-K for the year ended December 31, 2008 (File
No. 1-12609), Exhibit 10.58)
|
|
|
*10.52
|
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)
|
|
|
*10.53
|
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 Annual Report on Form 10-K for the year ended December 31,
2004 (File No. 1-12609), Exhibit 10.39)
|
|
|
*10.54
|
PG&E
Corporation and Pacific Gas and Electric Company Executive Incentive
Compensation Recoupment Policy effective as of February 17,
2009
|
|
|
*10.55
|
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 Annual Report on Form
10-K for the year ended December 31, 2004 (File No. 1-12609),
Exhibit 10.40)
|
|
|
*10.56
|
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 Annual
Report on Form 10-K for the year ended December 31, 2004 (File
No. 1-2348), Exhibit 10.41)
|
|
|
12.1
|
Computation
of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric
Company
|
|
|
12.2
|
Computation
of Ratios of Earnings to Combined Fixed Charges and Preferred Stock
Dividends for Pacific Gas and Electric Company
|
|
|
12.3
|
Computation
of Ratios of Earnings to Fixed Charges for PG&E
Corporation
|
|
|
13
|
The
following portions of the 2009 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 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
|
|
|
***101.INS
|
XBRL
Instance Document
|
|
|
***101.SCH
|
XBRL
Taxonomy Extension Schema Document
|
|
|
***101.CAL
|
XBRL
Taxonomy Extension Calculation Linkbase Document
|
|
|
***101.LAB
|
XBRL
Taxonomy Extension Labels Linkbase Document
|
|
|
***101.PRE
|
XBRL
Taxonomy Extension Presentation Linkbase Document
|
|
|
***101.DEF
|
XBRL
Taxonomy Extension Definition Linkbase Document
|
|
* Management
contract or compensatory agreement.
|
**
|
Pursuant
to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished
rather than filed with this report.
|
|
***
|
Pursuant
to Rule 406T of SEC Regulation S-T, these interactive data files are
deemed not filed or part of a registration statement or prospectus for
purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18
of the Securities Exchange Act of 1934 and otherwise are not subject to
liability under these sections. These files are being submitted
only by PG&E Corporation and not by its subsidiary, Pacific Gas and
Electric Company.
|
TABLE OF CONTENTS
Part IprintItem 1. BusinessprintItem 1A. Risk FactorsprintItem 1B. Unresolved Staff CommentsprintItem 2. PropertiesprintItem 3. Legal ProceedingsprintItem 4. Submission Of Matters To A Vote Of Security HoldersprintPart IIprintItem 5. Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesprintItem 6. Selected Financial DataprintItem 7. Management's Discussion and Analysis Of Financial Condition and Results Of OperationsprintItem 7A. Quantitative and Qualitative Disclosures About Market RiskprintItem 8. Financial Statements and Supplementary DataprintItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureprintItem 9A. Controls and ProceduresprintItem 9B. Other InformationprintPart IIIprintItem 10. Directors, Executive Officers and Corporate GovernanceprintItem 11. Executive CompensationprintItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersprintItem 13. Certain Relationships and Related Transactions, and Director IndependenceprintItem 14. Principal Accountant Fees and ServicesprintPart IVprintItem 15. Exhibits and Financial Statement Schedulesprint