2010 FERC Form 1 - Pacific Gas and Electric Company

2010
ANNUAL REPORT
of
Pacific Gas and Electric Company
77 Beale Street
P.O. Box 770000, B7C
San Francisco, CA 94177
to the
Public Utilities Commission
of the
State of California
For the Year Ended December 31, 2010
Volume No. 1 (Form 1)

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
LIST OF SCHEDULES (Electric Utility)
Year/Period of Report
End of 2010/Q4
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
1
General Information
101
2
Control Over Respondent
102
3
Corporations Controlled by Respondent
103
4
Officers
104
5
Directors
105
6
Information on Formula Rates
106(a)(b)
7
Important Changes During the Year
108-109
8
Comparative Balance Sheet
110-113
9
Statement of Income for the Year
114-117
10
Statement of Retained Earnings for the Year
118-119
11
Statement of Cash Flows
120-121
12
Notes to Financial Statements
122-123
13
Statement of Accum Comp Income, Comp Income, and Hedging Activities
122(a)(b)
14
Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep
200-201
15
Nuclear Fuel Materials
202-203
16
Electric Plant in Service
204-207
17
Electric Plant Leased to Others
213
NONE
18
Electric Plant Held for Future Use
214
NONE
19
Construction Work in Progress-Electric
216
20
Accumulated Provision for Depreciation of Electric Utility Plant
219
21
Investment of Subsidiary Companies
224-225
22
Materials and Supplies
227
23
Allowances
228(ab)-229(ab)
24
Extraordinary Property Losses
230
NONE
25
Unrecovered Plant and Regulatory Study Costs
230
NONE
26
Transmission Service and Generation Interconnection Study Costs
231
27
Other Regulatory Assets
232
28
Miscellaneous Deferred Debits
233
29
Accumulated Deferred Income Taxes
234
30
Capital Stock
250-251
31
Other Paid-in Capital
253
32
Capital Stock Expense
254
33
Long-Term Debt
256-257
34
Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax
261
35
Taxes Accrued, Prepaid and Charged During the Year
262-263
36
Accumulated Deferred Investment Tax Credits
266-267
FERC FORM NO. 1 (ED. 12-96) Page 2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
LIST OF SCHEDULES (Electric Utility) (continued)
Year/Period of Report
End of 2010/Q4
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
37
Other Deferred Credits
269
38
Accumulated Deferred Income Taxes-Accelerated Amortization Property
272-273
39
Accumulated Deferred Income Taxes-Other Property
274-275
40
Accumulated Deferred Income Taxes-Other
276-277
41
Other Regulatory Liabilities
278
42
Electric Operating Revenues
300-301
43
Sales of Electricity by Rate Schedules
304
44
Sales for Resale
310-311
45
Electric Operation and Maintenance Expenses
320-323
46
Purchased Power
326-327
47
Transmission of Electricity for Others
328-330
48
Transmission of Electricity by ISO/RTOs
331
NOT APPLICABLE
49
Transmission of Electricity by Others
332
50
Miscellaneous General Expenses-Electric
335
51
Depreciation and Amortization of Electric Plant
336-337
52
Regulatory Commission Expenses
350-351
53
Research, Development and Demonstration Activities
352-353
NONE
54
Distribution of Salaries and Wages
354-355
55
Common Utility Plant and Expenses
356
56
Amounts included in ISO/RTO Settlement Statements
397
57
Purchase and Sale of Ancillary Services
398
58
Monthly Transmission System Peak Load
400
59
Monthly ISO/RTO Transmission System Peak Load
400a
NOT APPLICABLE
60
Electric Energy Account
401
61
Monthly Peaks and Output
401
62
Steam Electric Generating Plant Statistics
402-403
63
Hydroelectric Generating Plant Statistics
406-407
64
Pumped Storage Generating Plant Statistics
408-409
65
Generating Plant Statistics Pages
410-411
66
Transmission Line Statistics Pages
422-423
FERC FORM NO. 1 (ED. 12-96) Page 3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
LIST OF SCHEDULES (Electric Utility) (continued)
Year/Period of Report
End of 2010/Q4
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
67
Transmission Lines Added During the Year
424-425
68
Substations
426-427
69
Transactions with Associated (Affiliated) Companies
429
70
Footnote Data
450
Stockholders' Reports Check appropriate box:
X Two copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO. 1 (ED. 12-96) Page 4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of
2010/Q4
Dinyar Mistry, Vice President and Controller
77 Beale Street, B7A
San Francisco, California 94105
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
California - October 10, 1905
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not Applicable.
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Electricity and natural gas distribution, electricity generation, procurement, and transmission, and
natural gas procurement, transportation, and storage.
State of California only.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1) Yes...Enter the date when such independent accountant was initially engaged:
(2) X No
FERC FORM No.1 (ED. 12-87) PAGE 101

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of
2010/Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controlling corporation or organization, manner in
which control was held, and extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
Effective January 1, 1997, PG&E Corporation became the holding company of Pacific Gas and Electric Company.
FERC FORM NO. 1 (ED. 12-96)
Page 102

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
CORPORATIONS CONTROLLED BY RESPONDENT
Year/Period of Report
End of 2010/Q4
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line
No.
Name of Company Controlled Kind of Business Percent Voting
Stock Owned
(a)
(b)
(c)
1 Calaska Energy Company
2
3
4
5
6 Eureka Energy Company
7
8
9
10
11
12
13 Midway Power, LLC
14
15
16
17
18 Natural Gas Corporation of California (NGC)
19
20
21
22
23
24 NGC Production Company
25 (The Utility has an indirect interest in
26 NGC Production Company by virtue of its
27 sole ownership of NGC.)
Formerly the Utility's 100
representative in the
Alaska Highway
Pipeline Project.
Formerly managed 100
the Utility's Utah coal
venture. Currently holds
part of the Marre Ranch
property in San Luis
Obispo County.
Formed to be the ownership 100
entity for real estate and
licenses for a suspended
development project.
Entity used to amortize 100
remaining Gas
Exploration and
Development Account
assets.
A wholly owned subsidiary
of NGC engaged in
financing capital
requirements of NGC.
Footnote
Ref.
(d)
FERC FORM NO. 1 (ED. 12-96) Page 103

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
CORPORATIONS CONTROLLED BY RESPONDENT
Year/Period of Report
End of 2010/Q4
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line
No.
1
Name of Company Controlled Kind of Business Percent Voting
Stock Owned
(a)
(b)
(c)
2 Newco Energy Corporation
3
4
5
6
7 Pacific California Gas System, Inc.
8
9
10
11 Pacific Conservation Services Company
12
13
14
15
16
17 Pacific Energy Fuels Company
18
19
20
21
22 Pacific Gas Properties Company
23
24
25
26
27
Formed to facilitate 100
implementation of the
Utility's original proposed
plan of reorganization.
Formed to hold the 100
intrastate gas pipeline
operations.
Formerly engaged in the 100
borrowing and lending
operations required
to fund the Utility's
conservation loan programs.
Formed to own and 100
finance the nuclear fuel
inventory previously owned
by Pacific Energy Trust.
Formed to hold Alaska 100
and California property
interests, previously
intended for LNG projects,
for sale or development.
Footnote
Ref.
(d)
FERC FORM NO. 1 (ED. 12-96) Page 103.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
CORPORATIONS CONTROLLED BY RESPONDENT
Year/Period of Report
End of 2010/Q4
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line
No.
1 PG&E CalHydro, LLC
2
3
4
5
6
Name of Company Controlled Kind of Business Percent Voting
Stock Owned
(a)
(b)
(c)
7 PG&E Energy Recovery Funding LLC
8
9
10
11 Standard Pacific Gas Line Incorporated
12
13
14
15
16
17
18 PG&E Real Estate, LLC
19
20
21
22
23
24
25
26
27
Formed for the purpose of 100
owning and operating a
system of hydroelectric
facilities and related
watershed.
Formed to retain ownership 100
of recovery property and
to issue securities.
Engaged in the transportation 85.71
of natural gas in California.
The Utility owns an 85.71%
interest and Chevron Pipe
Line Company owns the
remaining 14.29% interest.
A wholly-owned subsidiary of 100
Pacific Gas and Electric
Company, formed to conduct
real estate transactions,
most likely related to
purchase of property rights
of San Bruno incident
Footnote
Ref.
(d)
FERC FORM NO. 1 (ED. 12-96) Page 103.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
This Report Is:
(1) X An Original
(2) A Resubmission
OFFICERS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
Title Name of Officer Salary
for Year
(a)
(b)
(c)
President Christopher P. Johns
672,500
Senior VP and Chief Operating Officer John S. Keenan
616,250
Senior VP, Financial Services Kent M. Harvey
537,500
Senior VP, Energy Supply and Chief Nuclear Offcer John T. Conway
486,667
Senior VP, Human Resources John R. Simon
366,972
Senior VP and Chief Information Officer Patricia M. Lawicki
360,559
Senior VP, Engineering and Operations Edward A. Salas
348,823
Senior VP, Energy Delivery Geisha J. Williams
345,485
Senior VP, Corporate Affairs Greg S. Pruett
336,667
Senior VP, Regulatory Relations Thomas E. Bottorff
334,031
Senior VP and Chief Customer Officer Helen A. Burt
320,253
Senior VP, Shared Services and Chief Procurement Officer Desmond Bell
317,369
Senior VP, Energy Procurement Fong Wan
316,725
VP and Controller Dinyar B.Mistry
315,208
VP, Finance and CFO Sara A.Cherry
262,258
VP and Controller Stephen J. Cairns
309,000
VP, Finance and CFO Barbara L. Barcon
52,620
FERC FORM NO. 1 (ED. 12-96) Page 104

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 104 Line No.: 14 Column: a
(1) Mr. Mistry became VP and Controller on March 8, 2010.
Schedule Page: 104 Line No.: 15 Column: a
Ms. Cherry became VP, Finance and CFO on March 1, 2010.
Schedule Page: 104 Line No.: 16 Column: a
Mr. Cairns served as VP and Controller through March 7, 2010.
Schedule Page: 104 Line No.: 17 Column: a
Ms. Barcon served as VP, Finance and CFO through March 1, 2010.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
DIRECTORS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
Line
No.
Name (and Title) of Director
(a)
Principal Business Address
(b)
1 David R. Andrews, Esq. ***
c/o PG&E Corporation
2
One Market, Spear Tower, Suite 2400
3
4
5 Lewis Chew
San Francisco, CA 94105
c/o National Semiconductor Corporation
6
2900 Semiconductor Drive, Mail Stop G3-155
7
8
9 C. Lee Cox ***
Santa Clara, CA 95051
c/o PG&E Corporation
10 Non-Executive Chairman of the Board
One Market, Spear Tower, Suite 2400
11
12
13 Peter A. Darbee **
San Francisco, CA 94105
c/o PG&E Corporation
14
One Market, Spear Tower, Suite 2400
15
16
17 Maryellen C. Herringer ***
San Francisco, CA 94105
c/o PG&E Corporation
18
One Market, Spear Tower, Suite 2400
19
20
21 Roger H. Kimmel
San Francisco, CA 94105
c/o Rothschild Inc.
22
1251 Avenue of the Americas
23
24
25 Richard A. Meserve
New York, NY 10020
c/o Carnegie Institution of Washington
26
1530 P Street, NW
27
28
29 Forrest E. Miller
Washington, DC 20005
c/o AT&T Inc.
30
208 S. Akard Street, Suite 3701
31
32
33 Rosendo G. Parra
Dallas, TX 75202
c/o Daylight Partners
34
3725 Hunterwood Point
35
36
37 Barbara L. Rambo ***
Austin, TX 78746
c/o PG&E Corporation
38
One Market, Spear Tower, Suite 2400
39
40
41 Barry Lawson Williams ***
San Francisco, CA 94105
c/o Williams Pacific Ventures, Inc.
42
4 Embarcadero Center, Suite 3700
43
44
45 Christopher P Johns ***
San Francisco, CA 94111
c/o Pacific Gas and Electric Company
46
77 Beale Street, 32nd Floor
47
48
San Francisco, CA 94105
FERC FORM NO. 1 (ED. 12-95) Page 105

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 105 Line No.: 45 Column: a
Christopher P. Johns was elected as President of the Utility on August 1, 2009 and as a
director of the Utility on February 17, 2010.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Year/Period of Report
End of 2010/Q4
Does the respondent have formula rates?
Line
No.
FERC Rate Schedule or Tariff Number
FERC Proceeding
Yes
X No
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accepting the rate(s) or changes in the accepted rate.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
NOT APPLICABLE
FERC FORM NO. 1 (NEW. 12-08) Page 106

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Year/Period of Report
End of 2010/Q4
Does the respondent file with the Commission annual (or more frequent)
filings containing the inputs to the formula rate(s)?
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
X
Yes
No
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
Accession No.
Document Date
\ Filed Date
Docket No.
NOT APPLICABLE
Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
FERC FORM NO. 1 (NEW. 12-08)
Page 106a

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
INFORMATION ON FORMULA RATES
Formula Rate Variances
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
amounts reported in the Form 1.
2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the
Form 1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line
No. Page No(s). Schedule Column Line No
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
NOT APPLICABLE
FERC FORM NO. 1 (NEW. 12-08)
Page 106b

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
Date of Report
04/08/2011
Year/Period of Report
End of 2010/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO. 1 (ED. 12-96) Page 108

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
1. Changes in and important additions to franchise rights:
On February 23, 2010, the City of San Jose adopted amendments to Pacific Gas and
Electric Company’s (the "Utility") gas and electric franchise agreements which
provide for an increase in the franchise fee by three-tenths of one percent (0.3%).
The increase in the franchise fee is collected as a surcharge to customers within the
City of San Jose. The California Public Utilities Commission (“CPUC”) approved the
franchise fee surcharge effective May 5, 2010.
On May 28, 2010, the City of Fresno ("City") adopted a new gas franchise for the
Utility, under Ordinance No. 2010-16, replacing the existing gas franchise that
expired in June, 2010. The new gas franchise went into effect June 27, 2010 and is
for a 50 year term. Under the new franchise, the City receives a total franchise fee
of two (2) percent, of which one (1) percent is collected as a surcharge to customers
within the City. The CPUC approved the franchise fee surcharge on September 16,
2010, with an effective date of August 16, 2010.
2. Acquisition of ownership in other companies by reorganization, merger, or
consolidation with other companies:
None.
3. Purchase or sale of an operating unit or system:
Sale:
Transaction Date Sale To: Equipment Type Location Amount 1
Nov. 11. 2010 TPUD-Hyampom ETP Operating Trinity 761,002
System
County
4. Important leaseholds that have been acquired or given, assigned or surrendered:
Effective
Location Lessor/Lessee Lease Term
Date
(St., City)
Type
Term
Commencement
Date
Annual
Rent
5/3/10 1/1/09 345
Sacramento
St, Auburn
9/30/10 1/1/11 118 S 3rd
Street, King
City
10/15/10 10/15/10 1070 Airport
Blvd, Santa
Rosa
11/1/10 12/1/10 900 Cherry
Ave., 3rd
Floor, San
Bruno
11/8/10 1/5/11 850 Stillwater
Road, West
Sacramento
Twentieth
District
Agricultural
Association
JIM APPLING
Laier and
Kantock
SFO Business
Centers, Inc.
HARSCH
INVESTMENT
CORP.
Lease
Renewal
Lease
Renewal
Lease
Expansion
(580 sq.
ft.)
36
months
36
months
36
months
New Lease 18
months
Lease
Renewal
12
months
$10,164
$21,967.32
$12,000
$222,240
$1,328,811.
60
11/15/10 12/1/2010 2700 Ygnacio,
Suite 210,
Walnut Creek
Pacific 2700
Ygnacio
Corporation
New Lease 18
months
$113,011.20
FERC FORM NO. 1 (ED. 12-96) Page 109.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
12/8/10 1/1/11 410 N Main
St, Fort
Bragg
12/10/10 12/15/10 125 Venture
Dr, San Luis
Obispo
12/20/10 3/1/10 375 Fifth St,
Hollister
12/31/10 1/1/08 2570
Cloverdale
Ave., Suites
19 & 20,
Concord
MS CORDELIA
SHAMPANIER
Vachell Lane
Properties
City of
Hollister
THE SCHMIDT
FAMILY TRUST
Lease
Renewal
36
months
New Lease 3
months
New Vacant
Land Lease
Lease
Surrender/
Lease
Expiration
120
months
36
months
$11,423.16
$90,000
$3,984
$28,644.36
5. Important extension or reduction of transmission or distribution system:
Electric:
On July 16, 2010, the Gill Ranch Gas Storage 115 kV Load Interconnection Project
became operational. Located in Madera, California, PG&E constructed a 10-mile long
overhead tap line from the Dairyland-Mendota 115 kV circuit to the customer-owned
Gill Ranch Substation. Completion of this project enables the Gill Ranch customer to
obtain transmission service from PG&E’s electric grid.
On August 1, 2010, the Oakland Station C-X No. 3 115 kV Underground Cable Project was
energized for service. This project, located in Alameda County, installed a single
3.7 miles underground cable between Oakland C and Oakland X Substations. This
project increases the area transmission capacity, thereby ensures reliable
transmission service for electric customers in North Oakland area.
On August 27, 2010, PG&E took ownership of the Carberry Switching Substation that was
energized on June 22, 2010. Located in Shasta County near Burney, California, the
new 230 kV switching station was constructed to interconnect the Hatchet Ridge Wind
Farm with PG&E’s electric grid. The wind farm is owned by a third-party developer,
and it has a total output of approximately 100 MW. The new switching station is
equipped with protection, control, and communication equipment enabling the existing
230 kV Pit No. 3 to Round Mountain circuit to loop into the station for electric
power delivery.
On November 23, 2010, the TransBay Cable Project interconnected with PG&E’s electric
grid. This third-party-owned project installed a high-voltage direct-current cable
and associated onshore facilities into PG&E’s grid. The 53-mile submarine cable
improves electric transmission reliability to San Francisco by providing 400 MW of
electric power transfer capability from Pittsburg Substation in Contra Costa County,
to Potrero Substation in San Francisco County, California.
On December 1, 2010, the 7th Standard Substation located in Kern County was released
to Operations. New transmission and distribution facilities, including control and
protection equipment, were installed to provide additional capacity to reliably serve
electric customers in Northwest Bakersfield and the surrounding area in Kern County,
California.
On December 22, 2010, the PG&E-owned Colusa Generating Station interconnected to the
Delevan Switching Substation for commercial operation. Located near Maxwell in
FERC FORM NO. 1 (ED. 12-96) Page 109.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
Colusa County, California, the switching Station was energized on February 3, 2010.
The switching station has protection, control, and communication equipment that
enables power output from the 660 MW generation station be delivered to the
transmission corridor between Cottonwood and Vaca Dixon Substations.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities
or guarantees including issuance of short-term debt and commercial paper having maturity
of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee:
a) Financings:
At December 31, 2010, the Utility had $10.15 billion of unsecured senior notes
outstanding with various interest rates and maturity dates, including the
following issuances made during 2010.
On April 1, 2010, the Utility issued $250 million of 30-year unsecured Senior
Notes. The issuance was a re-opening of the 5.80% 30-year Senior Notes issued in
March 2007. In a bond re-opening, all of the terms of the new issue are
identical to that of the original issue including coupon, interest payment dates,
maturity date, etc. The Senior Notes were authorized by the California Public
Utilities Commission (“CPUC”) Decision No. 08-10-013.
On September 15, 2010, the Utility issued $550 million of unsecured Senior Notes
due October 1, 2020 at a coupon of 3.50%. The Senior Notes were authorized by
the CPUC Decision No. 08-10-013.
On October 12, 2010, the Utility issued $250 principal amount of Floating Rate
Senior Notes due October 11, 2011. The Senior Notes were authorized by CPUC
Decision No. 04-10-037 as modified by Decision Nos. 05-04-023, 06-11-006 and
09-05-002.
On November 18, 2010, the Utility issued $250 million of 10-year unsecured Senior
Notes and $250 million 30-year unsecured Senior Notes. Issuances were
re-openings of the 3.50% 10-year Senior Notes and the 5.40% 30-year Senior Notes
issued in September 15, 2010 and November 18, 2009, respectively. The Senior
Notes were authorized by the CPUC Decision No. 08-10-013.
On April 8, 2010, the California Infrastructure and Economic Development Bank
(I-Bank), issued $50 million of tax-exempt pollution control bond series 2010 E
at a yield of 2.25%, due on November 1, 2026 with a 2-year mandatory put. The
proceeds were loaned to the Utility to repurchase pollution control bonds series
2005 E. The pollution control bonds were authorized by the CPUC Decision No.
08-10-013.
Refer to Note 4, Debt, of the Notes to Financial Statements on page 123 of the
FERC Form 3-Q.
b) Bank Credit Facilities:
On June 8, 2010, the Utility entered into a $750 million revolving credit
facility agreement. This credit facility will expire on February 26, 2012 and
does not support the letters of credit program. At December 31, 2010, the
Utility had nothing outstanding under this revolving credit facility.
At December 31, 2010, the Utility had $329 million of letters of credit
outstanding under the Utility’s $1.94 billion revolving credit facility.
FERC FORM NO. 1 (ED. 12-96) Page 109.3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
The revolving credit facility also provides liquidity support for commercial
paper offerings. At December 31, 2010, the Utility had $603 million of
commercial paper outstanding. The short-term borrowings are authorized by CPUC
Decision No. 04-10-037 as modified by Decision Nos. 05-04-023, 06-11-006 and
09-05-002.
Refer to Note 4, Debt, of the Notes to Financial Statements on page 123 of the
FERC Form 3-Q.
c) Surety Bonds and Financial Guarantees Backed by Insurance:
From October 1, 2010 through December 31, 2010, $865,000 in surety bonds was
authorized by CPUC Decision No. 08-10-013. At December 31, 2010, there was
$11,959,000 in long-term surety bond obligations outstanding.
d) Capital Support:
CCPUC Decision No. 91-12-057 (as modified by Decision No. 99-04-068) authorized
the Utility to provide capital support to regulated and unregulated subsidiaries.
At December 31, 2010, the Utility has no outstanding future capital commitments
to unregulated subsidiaries and affiliates.
e) Preferred repayments: None
7. Changes in articles of incorporation or amendments to charter. Explain the nature
and purpose of such changes or amendments:
None.
8. State the estimated annual effect and nature of any important wage scale changes
during the period:
As provided for in labor agreements with the International Brotherhood of Electrical
Workers (“IBEW”), Local 1245, representing a majority of the Utility’s employees in
physical and clerical classifications; the Engineers and Scientists of California
(“ESC”), representing certain Utility employees in the technical and engineering
classifications; and, the Service Employees International Union (“SEIU”),
representing certain Utility security officers at Diablo Canyon Nuclear Power Plant,
the following general wage increases were granted effective January 1, 2010:
IBEW Physical and Clerical classifications 3.75%
ESC classifications 3.75%
SEIU classifications 4.50%
The full annual cost of the above general wage increases is approximately $40.3
million.
9. State briefly the status of any materially important legal proceedings pending at the
end of the period and the results of any such proceedings culminated during the
period:
Refer to Note 15 of the Notes to Financial Statements on page 123, which discusses
materially important pending legal matters.
FERC FORM NO. 1 (ED. 12-96) Page 109.4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
Further, refer to Part I, Item 3 in PG&E Corporation's and the Utility’s combined
Annual Report on Form 10-K for the year ended December 31, 2010, which describes
certain legal proceedings pursuant to Item 103 of Regulation S-K of the Securities
Exchange Act of 1934, as amended. Four copies of the Form 10—K report are filed in
accordance with Instruction III(b) of Instructions For Filing the FERC Form No. 1.
10. Describe briefly any material important transactions of the respondent not disclosed
elsewhere in this report in which an officer, director, security holder reported in
the last Annual Report FERC Form 1, 1-F, 2 or 2-A, voting trustee, associated company
or known associate of any of these persons was a party or in which such person had a
material interest:
Refer to the PG&E Corporation and Pacific Gas and Electric Company Joint Proxy
Statement dated March 30, 2011 which describes certain related person transactions
pursuant to Item 7 of Schedule 14A under the Securities Exchange Act of 1934, as
amended and to Note 14 of the Notes to Financial Statements on page 123 of the FERC
Form 1, which describes certain material related party agreements and transactions.
A copy of the proxy statement is attached.
11. Reserved
12. If the important changes during the year relating to the respondent company appearing
in the annual report to stockholders are applicable in every respect and furnish the
data required by instructions to 1 to 11 above, such notes may be included on this
page.
Four copies of PG&E Corporation’s and Pacific Gas and Electric Company’s combined
Annual Report on Form 10-K for the year ended December 31, 2010, and four copies of
PG&E Corporation and Pacific Gas and Electric Company’s joint 2010 Annual Report To
Shareholders have been filed in accordance with Instruction III(b) of the
Instructions for Filing the FERC Form No. 1.
13. Describe fully any changes in officers, directors, major security holders and voting
powers of the respondent that may have occurred during the reporting period:
Directors
The following individual was elected as a director of the Utility:
• Christopher P. Johns
Officers
The following individuals were elected as officers of the Utility:
• Sara A. Cherry, Vice President, Finance and Chief Financial Officer
• Anil K. Suri, Vice President and Chief Risk and Audit Officer
• M. Kirk Johnson, Vice President, Gas Engineering and Operations
• Janet C. Loduca, Vice President, Corporate Relations
The following officers’ titles changed:
• Stephen J. Cairns, Vice President, Internal Audit and Compliance (formerly Vice
President and Controller)
• William D. Hayes, Vice President, Gas Maintenance and Construction (formerly Vice
President, Maintenance and Construction)
• Dinyar B. Mistry, Vice President and Controller (formerly Vice President and Chief
FERC FORM NO. 1 (ED. 12-96) Page 109.5

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
Risk and Audit Officer)
• Mark S. Johnson, Vice President, Electric Transmission, Planning and Engineering
(formerly Vice President, Electric Operations and Engineering)
• Randal S. Livingston, Vice President, Gas Transmission Programs (formerly Vice
President, Power Generation)
• Placido J. Martinez, Vice President, Electric Distribution, Planning and
Engineering (formerly Vice President, Engineering)
• Gregory K. Kiraly, Vice President, SmartMeter Operations (formerly Vice President,
Electric Maintenance and Construction)
The following individual is no longer an officer of the Utility:
• Barbara L. Barcon, Vice President, Finance and Chief Financial Officer
Major Security Holders
Changes to the major holders of the Utility’s First Preferred Stock are as follows:
• Cede & Co., P.O. Box 20, Bowling Green Station, New York, NY 10004-9998, increased
its share ownership from 9,113,478 shares as of September 30, 2010 to 9,142,905
shares as of December 31, 2010 (approximately 89% of the total preferred shares
outstanding).
• John R Vaughn & Shirley M Vaughn TR UA Oct 18 93 John & Shirley Vaughn Living
Trust, Box 1125, Groveland, CA 95321-1125 are major shareholders with 12,000
shares of preferred stock.
• Elena E. Skidmore, 2826 N. Ridge Rd Lot 24, Perry, OH 44081-9524, is no longer a
major shareholder.
Dividend Payments
Refer to Note 6, Common Stock, of the Notes to Financial Statements on page 123 of
the FERC Form 1.
14. If respondent participates in a cash management program, describe the significant
events or transactions causing the proprietary capital to be less than 30 percent,
and the extent to which respondent has amounts loaned or money advanced to its
parent, subsidiary, or affiliated companies. Also, describe any plans to regain at
least a 30 percent proprietary ratio:
Not applicable.
FERC FORM NO. 1 (ED. 12-96) Page 109.6

Name of Respondent
This Report Is:
Date of Report Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011 End of 2010/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
Title of Account
(a)
UTILITY PLANT
Utility Plant (101-106, 114)
Construction Work in Progress (107)
TOTAL Utility Plant (Enter Total of lines 2 and 3)
(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)
Net Utility Plant (Enter Total of line 4 less 5)
Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)
Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
Nuclear Fuel Assemblies in Reactor (120.3)
Spent Nuclear Fuel (120.4)
Nuclear Fuel Under Capital Leases (120.6)
(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utility Plant (Enter Total of lines 6 and 13)
Utility Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Property (121)
(Less) Accum. Prov. for Depr. and Amort. (122)
Investments in Associated Companies (123)
Investment in Subsidiary Companies (123.1)
(For Cost of Account 123.1, See Footnote Page 224, line 42)
Noncurrent Portion of Allowances
Other Investments (124)
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)
Special Funds (Non Major Only) (129)
Long-Term Portion of Derivative Assets (175)
Long-Term Portion of Derivative Assets – Hedges (176)
TOTAL Other Property and Investments (Lines 18-21 and 23-31)
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)
Special Deposits (132-134)
Working Fund (135)
Temporary Cash Investments (136)
Notes Receivable (141)
Customer Accounts Receivable (142)
Other Accounts Receivable (143)
(Less) Accum. Prov. for Uncollectible Acct.-Credit (144)
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistributed (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
Merchandise (155)
Other Materials and Supplies (156)
Nuclear Materials Held for Sale (157)
Allowances (158.1 and 158.2)
Ref.
Page No.
(b)
200-201
200-201
200-201
202-203
202-203
224-225
228-229
227
227
227
227
227
227
202-203/227
228-229
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
51,551,661,569 47,904,159,113
1,377,023,361 1,880,810,974
52,928,684,930 49,784,970,087
25,060,388,172 24,183,592,649
27,868,296,758 25,601,377,438
281,347,356 213,404,552
0 0
301,814,427 282,637,283
1,570,143,594 1,499,757,195
0 0
1,697,958,450 1,612,579,237
455,346,927 383,219,793
28,323,643,685 25,984,597,231
0 0
55,601,557 54,824,273
24,587,641 25,011,186
0 0
0 0
115,151,066 133,708,094
0 0
3,488,597 3,602,527
0 0
0 0
0 0
2,009,045,545 1,899,001,318
0 0
67,059,253 59,405,376
1,390,062 4,767,170
2,220,722,164 2,125,495,671
0 0
44,435,787 49,676,271
524,476,356 594,263,154
126,030 144,255
3,800,000 281,238,152
0 0
1,118,498,245 1,057,146,098
1,358,186,666 1,370,842,175
80,956,900 67,653,038
0 0
105,193,991 40,082,030
1,143,343 403,420
0 0
0 0
205,202,946 199,534,201
0 0
0 0
0 0
0 0
FERC FORM NO. 1 (REV. 12-03) Page 110

Name of Respondent
This Report Is:
Date of Report Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011 End of 2010/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued)
Line
No.
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
Title of Account
(a)
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)
Gas Stored Underground - Current (164.1)
Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
Prepayments (165)
Advances for Gas (166-167)
Interest and Dividends Receivable (171)
Rents Receivable (172)
Accrued Utility Revenues (173)
Miscellaneous Current and Accrued Assets (174)
Derivative Instrument Assets (175)
(Less) Long-Term Portion of Derivative Instrument Assets (175)
Derivative Instrument Assets - Hedges (176)
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176
Total Current and Accrued Assets (Lines 34 through 66)
DEFERRED DEBITS
Unamortized Debt Expenses (181)
Extraordinary Property Losses (182.1)
Unrecovered Plant and Regulatory Study Costs (182.2)
Other Regulatory Assets (182.3)
Prelim. Survey and Investigation Charges (Electric) (183)
Preliminary Natural Gas Survey and Investigation Charges 183.1)
Other Preliminary Survey and Investigation Charges (183.2)
Clearing Accounts (184)
Temporary Facilities (185)
Miscellaneous Deferred Debits (186)
Def. Losses from Disposition of Utility Plt. (187)
Research, Devel. and Demonstration Expend. (188)
Unamortized Loss on Reaquired Debt (189)
Accumulated Deferred Income Taxes (190)
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
Ref.
Page No.
(b)
227
230a
230b
232
233
352-353
234
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
0 0
0 0
151,139,525 113,638,846
0 0
70,557,735 71,115,771
0 0
1,779 27,166
0 0
649,179,020 671,230,961
446,253,293 201,593,062
109,356,761 133,371,719
67,059,253 59,405,376
2,032,074 6,988,870
1,390,062 4,767,170
4,640,177,336 4,659,470,567
82,785,690 77,037,490
0 0
0 0
6,898,245,621 6,500,673,291
0 0
0 0
0 0
-42,884 0
0 0
36,607,942 25,012,656
0 0
0 0
205,785,774 229,138,517
1,204,703,785 798,521,555
0 0
8,428,085,928 7,630,383,509
43,668,230,670 40,454,771,251
FERC FORM NO. 1 (REV. 12-03) Page 111

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 110 Line No.: 2 Column: c
Consistent with prior periods, the amounts shown for Utility Plant in Line 2 and
Accumulated Depreciation in Line 5, columns c and d, are reported on a regulatory basis of
accounting. They do not reflect accounting entries in the Utility’s 2010 and 2009 Annual
Report to Stockholders in accordance with generally accepted accounting principles
("GAAP"). These entries totaling $7,091,071,387 for column c and $7,085,436,368 for column
d reduced in equal amounts Utility Plant and Accumulated Depreciation for the impairment
of Diablo Canyon, Helms, and South Yuba generation facilities.
Schedule Page: 110 Line No.: 2 Column: d
Refer to the footnote for Line 2, column c.
Schedule Page: 110 Line No.: 5 Column: c
This line is reported on a regulatory basis of accounting as described in the footnote for
Line 2. Further, it does not reflect accounting entries in the Utility’s 2010 Annual
Report to Stockholders in accordance with GAAP, which reduced accumulated depreciation by
$3,114,186,964 and increased regulatory liabilities by $3,228,952,134 and regulatory
assets by $114,765,170 for removal costs that are collected or will be collected in rates
through depreciation in accordance with regulatory treatment. These amounts do not
represent SFAS No. 143 asset retirement obligations. Historically, these removal costs had
been recorded in accumulated depreciation. However, as a result of guidance from the SEC,
the Utility reclassified this obligation to a regulatory liability in its balance sheet in
accordance with GAAP.
Schedule Page: 110 Line No.: 5 Column: d
This line is reported on a regulatory basis of accounting as described in the footnote for
Line 2. Further, it does not reflect accounting entries in the Utility’s 2009 Annual
Report to Stockholders in accordance with GAAP, which reduced accumulated depreciation by
$2,898,850,137 and increased regulatory liabilities by $2,932,544,412 and regulatory
assets by $33,694,275 for removal costs that are collected or will be collected in rates
through depreciation in accordance with regulatory treatment. These amounts do not
represent SFAS No. 143 asset retirement obligations. Historically, these removal costs had
been recorded in accumulated depreciation. However, as a result of a guidance from the
SEC, the Utility reclassified this obligation to a regulatory liability in its balance
sheet in accordance with GAAP.
Schedule Page: 110 Line No.: 72 Column: c
Refer to the footnote for Line 5, column c on page 110.
Schedule Page: 110 Line No.: 72 Column: d
Refer to the footnote for Line 5, column d on page 110.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
Title of Account
(a)
This Report is:
(1) x An Original
(2) A Resubmission
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Date of Report Year/Period of Report
(mo, da, yr)
04/08/2011 end of 2010/Q4
Ref.
Page No.
(b)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)
250-251
3 Preferred Stock Issued (204)
250-251
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207)
7 Other Paid-In Capital (208-211)
253
8 Installments Received on Capital Stock (212)
252
9 (Less) Discount on Capital Stock (213)
254
10 (Less) Capital Stock Expense (214)
254b
11 Retained Earnings (215, 215.1, 216)
118-119
12 Unappropriated Undistributed Subsidiary Earnings (216.1)
118-119
13 (Less) Reaquired Capital Stock (217)
250-251
14 Noncorporate Proprietorship (Non-major only) (218)
15 Accumulated Other Comprehensive Income (219)
122(a)(b)
16 Total Proprietary Capital (lines 2 through 15)
17 LONG-TERM DEBT
18 Bonds (221)
256-257
19 (Less) Reaquired Bonds (222)
256-257
20 Advances from Associated Companies (223)
256-257
21 Other Long-Term Debt (224)
256-257
22 Unamortized Premium on Long-Term Debt (225)
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)
24 Total Long-Term Debt (lines 18 through 23)
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227)
27 Accumulated Provision for Property Insurance (228.1)
28 Accumulated Provision for Injuries and Damages (228.2)
29 Accumulated Provision for Pensions and Benefits (228.3)
30 Accumulated Miscellaneous Operating Provisions (228.4)
31 Accumulated Provision for Rate Refunds (229)
32 Long-Term Portion of Derivative Instrument Liabilities
33 Long-Term Portion of Derivative Instrument Liabilities - Hedges
34 Asset Retirement Obligations (230)
35 Total Other Noncurrent Liabilities (lines 26 through 34)
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)
38 Accounts Payable (232)
39 Notes Payable to Associated Companies (233)
40 Accounts Payable to Associated Companies (234)
41 Customer Deposits (235)
42 Taxes Accrued (236)
262-263
43 Interest Accrued (237)
44 Dividends Declared (238)
45 Matured Long-Term Debt (239)
Current Year
End of Quarter/Year
Balance
(c)
1,321,874,045
257,994,575
0
0
1,805,194,230
1,471,315,126
0
6,916,899
28,951,886
7,152,022,210
-56,446,867
0
0
-194,989,625
11,721,094,909
11,574,970,000
157,870,000
835,423,939
0
9,231,288
60,352,757
12,201,402,470
248,172,000
0
551,806,111
2,174,470,892
698,843,330
0
478,132,160
0
1,585,815,096
5,737,239,589
853,033,000
2,247,948,817
0
27,299,951
208,541,524
139,808,619
865,519,911
2,319,386
0
Prior Year
End Balance
12/31
(d)
1,321,874,045
257,994,575
0
0
1,805,194,230
1,285,216,984
0
6,916,899
28,951,886
6,742,267,017
-37,749,013
0
0
-153,509,857
11,185,419,196
10,292,870,000
130,770,000
1,228,658,740
0
10,451,757
44,288,280
11,356,922,217
282,061,868
0
346,971,093
1,717,471,821
699,130,593
0
390,940,892
0
1,593,221,421
5,029,797,688
833,000,000
2,104,495,952
0
28,497,220
232,465,911
239,620,508
823,404,848
2,319,386
0
FERC FORM NO. 1 (rev. 12-03) Page 112

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
Title of Account
(a)
This Report is:
(1) x An Original
(2) A Resubmission
Date of Report Year/Period of Report
(mo, da, yr)
04/08/2011 end of 2010/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS) (continued)
Ref.
Page No.
(b)
46 Matured Interest (240)
47 Tax Collections Payable (241)
48 Miscellaneous Current and Accrued Liabilities (242)
49 Obligations Under Capital Leases-Current (243)
50 Derivative Instrument Liabilities (244)
51 (Less) Long-Term Portion of Derivative Instrument Liabilities
52 Derivative Instrument Liabilities - Hedges (245)
53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54 Total Current and Accrued Liabilities (lines 37 through 53)
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)
57 Accumulated Deferred Investment Tax Credits (255)
266-267
58 Deferred Gains from Disposition of Utility Plant (256)
59 Other Deferred Credits (253)
269
60 Other Regulatory Liabilities (254)
278
61 Unamortized Gain on Reaquired Debt (257)
62 Accum. Deferred Income Taxes-Accel. Amort.(281)
272-277
63 Accum. Deferred Income Taxes-Other Property (282)
64 Accum. Deferred Income Taxes-Other (283)
65 Total Deferred Credits (lines 56 through 64)
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)
Current Year
End of Quarter/Year
Balance
(c)
0
33,810,228
386,287,937
33,889,732
853,743,310
478,132,160
0
0
5,174,070,255
174,590,245
86,901,904
0
291,224,347
1,297,388,735
2,118,462
1,114,030,466
5,747,788,152
120,381,136
8,834,423,447
43,668,230,670
Prior Year
End Balance
12/31
(d)
0
27,824,887
501,942,009
31,976,884
622,506,229
390,940,892
0
0
5,057,112,942
187,490,351
88,731,266
0
350,483,973
1,299,060,254
2,357,210
1,105,025,558
4,458,577,370
333,793,226
7,825,519,208
40,454,771,251
FERC FORM NO. 1 (rev. 12-03) Page 113

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 112 Line No.: 38 Column: c
Includes pre-petition Accounts Payable of $745,225,951 and $772,750,084 for columns c and
d, respectively, which are classified as Accounts Payable - Disputed claims and customer
refunds in the Utility's balance sheet prepared on a GAAP basis of accounting.
Schedule Page: 112 Line No.: 38 Column: d
Refer to the footnote for Line 38, column c.
Schedule Page: 112 Line No.: 60 Column: c
Refer to the footnote for Line 5, column c on page 110.
Schedule Page: 112 Line No.: 60 Column: d
Refer to the footnote for Line 5, column d on page 110.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
Title of Account
(a)
UTILITY OPERATING INCOME
This Report Is:
(1) X An Original
(2) A Resubmission
STATEMENT OF INCOME
(Ref.)
Page No.
(b)
Total
Current Year to
Date Balance for
Quarter/Year
(c)
Date of Report
(Mo, Da, Yr)
04/08/2011
Total
Prior Year to
Date Balance for
Quarter/Year
(d)
Year/Period of Report
End of 2010/Q4
Quarterly
1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utility function for the current year quarter.
4. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l)
the quarter to date amounts for other utility function for the prior year quarter.
5. If additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
1
2
3
Operating Revenues (400)
Operating Expenses
4 Operation Expenses (401)
5 Maintenance Expenses (402)
6 Depreciation Expense (403)
7 Depreciation Expense for Asset Retirement Costs (403.1)
8 Amort. & Depl. of Utility Plant (404-405)
9 Amort. of Utility Plant Acq. Adj. (406)
10
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debits (407.3)
13 (Less) Regulatory Credits (407.4)
14 Taxes Other Than Income Taxes (408.1)
15 Income Taxes - Federal (409.1)
16 - Other (409.1)
17 Provision for Deferred Income Taxes (410.1)
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1)
19 Investment Tax Credit Adj. - Net (411.4)
20 (Less) Gains from Disp. of Utility Plant (411.6)
21 Losses from Disp. of Utility Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8)
23
Losses from Disposition of Allowances (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27
300-301
320-323
320-323
336-337
336-337
336-337
336-337
262-263
262-263
262-263
234, 272-277
234, 272-277
266
14,047,926,654 13,581,518,250
8,565,389,378 8,304,949,297
741,807,721 779,586,105
1,340,829,045 1,235,452,361
168,490,264 153,068,563
396,651,034 352,745,485
-63 339,809
364,857,677 357,636,341
-28,506,846 -583,723,565
138,182,731 -35,256,248
1,412,672,694 -194,984,540
885,198,948 -1,422,763,922
1,541,206 114,142
17,916 333,738
12,213,615,691 11,791,450,032
1,834,310,963 1,790,068,218
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
FERC FORM NO. 1/3-Q (REV. 02-04) Page 114

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
STATEMENT OF INCOME FOR THE YEAR (Continued)
Year/Period of Report
End of 2010/Q4
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY
GAS UTILITY
OTHER UTILITY
Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Line
(in dollars)
(in dollars)
(in dollars)
(in dollars)
(in dollars)
(in dollars)
No.
(g)
(h)
(i)
(j)
(k)
(l)
1
10,706,164,801 10,307,526,947 3,341,761,853 3,273,991,303
2
3
6,183,144,147 6,121,031,886 2,382,245,231 2,183,917,411
4
600,193,101 611,428,529 141,614,620
168,157,576
5
1,003,132,970 917,938,487 337,696,075
317,513,874
6
7
135,064,742 123,405,745 33,425,522
29,662,818
8
9
10
11
395,409,117 352,745,485 1,241,917
12
-63 339,809 13
286,256,380 277,589,276 78,601,297
80,047,065
14
-17,814,651 -493,161,635 -10,692,195
-90,561,930
15
40,969,983 -4,636,442 97,212,748
-30,619,806
16
1,017,479,838 -96,156,146 395,192,856
-98,828,394
17
505,776,896 -1,067,776,232 379,422,052
-354,987,690
18
19
1,190,142 114,142 351,064
20
21
17,916 333,738 22
23
24
9,136,850,736 8,877,173,728 3,076,764,955 2,914,276,304
25
1,569,314,065 1,430,353,219 264,996,898
359,714,999
26
FERC FORM NO. 1 (ED. 12-96) Page 115

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
Title of Account
(a)
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
STATEMENT OF INCOME FOR THE YEAR (continued)
TOTAL
(Ref.)
Page No. Current Year Previous Year
(b)
(c)
(d)
Year/Period of Report
End of 2010/Q4
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
Net Utility Operating Income (Carried forward from page 114)
Other Income and Deductions
Other Income
Nonutilty Operating Income
Revenues From Merchandising, Jobbing and Contract Work (415)
(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
Revenues From Nonutility Operations (417)
(Less) Expenses of Nonutility Operations (417.1)
Nonoperating Rental Income (418)
Equity in Earnings of Subsidiary Companies (418.1)
Interest and Dividend Income (419)
Allowance for Other Funds Used During Construction (419.1)
Miscellaneous Nonoperating Income (421)
Gain on Disposition of Property (421.1)
TOTAL Other Income (Enter Total of lines 31 thru 40)
Other Income Deductions
Loss on Disposition of Property (421.2)
Miscellaneous Amortization (425)
Donations (426.1)
Life Insurance (426.2)
Penalties (426.3)
Exp. for Certain Civic, Political & Related Activities (426.4)
Other Deductions (426.5)
TOTAL Other Income Deductions (Total of lines 43 thru 49)
Taxes Applic. to Other Income and Deductions
Taxes Other Than Income Taxes (408.2)
Income Taxes-Federal (409.2)
Income Taxes-Other (409.2)
Provision for Deferred Inc. Taxes (410.2)
(Less) Provision for Deferred Income Taxes-Cr. (411.2)
Investment Tax Credit Adj.-Net (411.5)
(Less) Investment Tax Credits (420)
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
Net Other Income and Deductions (Total of lines 41, 50, 59)
Interest Charges
Interest on Long-Term Debt (427)
Amort. of Debt Disc. and Expense (428)
Amortization of Loss on Reaquired Debt (428.1)
(Less) Amort. of Premium on Debt-Credit (429)
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
Interest on Debt to Assoc. Companies (430)
Other Interest Expense (431)
(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
Net Interest Charges (Total of lines 62 thru 69)
Income Before Extraordinary Items (Total of lines 27, 60 and 70)
Extraordinary Items
Extraordinary Income (434)
(Less) Extraordinary Deductions (435)
Net Extraordinary Items (Total of line 73 less line 74)
Income Taxes-Federal and Other (409.3)
Extraordinary Items After Taxes (line 75 less line 76)
Net Income (Total of line 71 and 77)
119
262-263
262-263
262-263
234, 272-277
234, 272-277
262-263
1,834,310,963 1,790,068,218
754,262 433,416
2,559,093 2,559,093
-17,426,049 -8,444,978
8,529,707 32,170,116
109,912,938 95,257,573
27,550,069 40,384,368
4,522,526 235,971
134,894,022 161,728,727
144,635 144,635
26,394,691 21,013,586
8,874,433 37,355
61,104,624 13,999,980
170,887,068 133,665,739
267,405,451 168,861,295
307,415 278,058
-4,780,586 19,975,159
-4,297,798 -9,695,357
-18,948,658 -1,534,209
8,534,545 -1,789,810
-4,664,829 -4,932,000
-40,919,001 5,881,461
-91,592,428 -13,014,029
563,459,250 515,739,699
25,683,948 24,341,572
24,097,306 25,622,330
1,220,470 1,220,470
238,748 238,748
44,740,932 66,008,284
15,413,510 -59,564,513
50,190,897 43,637,633
621,744,831 527,050,521
1,120,973,704 1,250,003,668
1,120,973,704 1,250,003,668
FERC FORM NO. 1/3-Q (REV. 02-04) Page 117

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 114 Line No.: 2 Column: c
Includes interdepartmental operating revenues in Line 2 and operations expenses in Line 4
from electric and gas operations:
Twelve Months Ended
Twelve Months Ended
December 31, 2010 December 31, 2009
Revenues Expenses Revenues Expenses
Electric $ 22,540,420 $123,351,684 $ 18,740,759 $120,463,882
Gas 122,014,454 21,203,190 119,824,594 18,101,471
------------ ------------ ------------ ------------
Total $144,554,874 $144,554,874 $138,565,353 $138,565,353
=========== ============ ============ ============
Schedule Page: 114 Line No.: 4 Column: c
Refer to the footnote for Line 2, column c.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
STATEMENT OF RETAINED EARNINGS
Year/Period of Report
End of
2010/Q4
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
Account Affected
(b)
Current
Quarter/Year
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
18 Reserves for excess earnings on FERC hydroelectric project
19 licenses pursuant to Federal Power Act Section 10(d)
20
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24 Preferred Dividend
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
31 Common Stock Dividend
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
39 Reserves for excess earnings on FERC hydroelectric project
40 licenses pursuant to Federal Power Act Section 10(d)
215
6,613,952,832
1,138,399,753
-16,651,398
-16,651,398
-13,916,365
-13,916,365
-716,000,000
-716,000,000
1,271,805
7,007,056,627
16,651,398
6,002,116,305
1,258,448,646
( 13,332,724)
( 13,332,724)
( 13,916,369)
( 13,916,369)
( 624,000,000)
( 624,000,000)
4,636,975
6,613,952,833
13,332,724
FERC FORM NO. 1/3-Q (REV. 02-04) Page 118

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
STATEMENT OF RETAINED EARNINGS
Year/Period of Report
End of
2010/Q4
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
Account Affected
(b)
Current
Quarter/Year
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Other adjustments
53 Balance-End of Year (Total lines 49 thru 52)
16,651,398
128,314,185
144,965,583
7,152,022,210
-37,749,013
-17,426,049
-1,271,805
-56,446,867
13,332,724
114,981,460
128,314,184
6,742,267,017
( 24,667,060)
( 8,444,978)
( 4,636,975)
( 37,749,013)
FERC FORM NO. 1/3-Q (REV. 02-04) Page 119

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 118 Line No.: 29 Column: c
The following is the detail of dividends declared on First Preferred Stocks for the period
ended December 31, 2010:
No. of Dividends Total
Class of Stock Shares Per Share Declared
6.00% Cumulative, Redeemable 4,211,662 $1.500 $ 6,317,514
5.50% Cumulative, Redeemable 1,173,163 1.375 1,613,108
5.00% Cumulative, Redeemable 400,000 1.250 500,002
5.00% Cumulative, Redeemable 1,778,172 1.250 2,222,719
5.00% Cumulative, Redeemable - Series A 934,322 1.250 1,167,909
4.80% Cumulative, Redeemable 793,031 1.200 951,637
4.50% Cumulative, Redeemable 611,142 1.125 687,538
4.36% Cumulative, Redeemable 418,291 1.090 455,938
-----------
Total $13,916,365
===========
Schedule Page: 118 Line No.: 29 Column: d
The following is the detail of dividends declared on First Preferred Stocks for the period
ended December 31, 2009:
No. of Dividends Total
Class of Stock Shares Per Share Declared
6.00% Cumulative, Redeemable 4,211,662 $1.500 $ 6,317,516
5.50% Cumulative, Redeemable 1,173,163 1.375 1,613,109
5.00% Cumulative, Redeemable 400,000 1.250 500,002
5.00% Cumulative, Redeemable 1,778,172 1.250 2,222,719
5.00% Cumulative, Redeemable - Series A 934,322 1.250 1,167,909
4.80% Cumulative, Redeemable 793,031 1.200 951,637
4.50% Cumulative, Redeemable 611,142 1.125 687,538
4.36% Cumulative, Redeemable 418,291 1.090 455,939
-----------
Total $13,916,369
===========
Schedule Page: 118 Line No.: 31 Column: c
This represents dividends declared on Common Stock to PG&E Corporation.
Schedule Page: 118 Line No.: 31 Column: d
This represents dividends declared on Common Stock to PG&E Corporation.
Schedule Page: 118 Line No.: 40 Column: a
The contra primary account affected is account 216. The FERC software does not allow
entry on this Line 40, column b.
Schedule Page: 118 Line No.: 52 Column: c
This is comprised of the following:
2010 2009
Utility subsidiary earnings reflected in
operations and maintenance accounts ($ 1,271,805) ($994,220)
Reclassification to Account 216 of
equity of dissolved subsidiaries - (3,642,746)
Other - ( 9)
---------- ----------
Total ($1,271,805) ($4,636,975)
============ ==========
Schedule Page: 118 Line No.: 52 Column: d
Refer to the footnote for line 52, column c.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line
Description (See Instruction No. 1 for Explanation of Codes)
No.
(a)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion
5 Amortization of
6 Unamortized Loss or Gain on Reacquired Debt
7 Expenses, Discount and Premium - Long Term Debt
8 Deferred Income Taxes (Net)
9 Investment Tax Credit Adjustment (Net)
10 Net (Increase) Decrease in Receivables
11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses
14 Net (Increase) Decrease in Other Regulatory Assets
15 Net Increase (Decrease) in Other Regulatory Liabilities
16 (Less) Allowance for Other Funds Used During Construction
17 (Less) Undistributed Earnings from Subsidiary Companies
18 Other (provide details in footnote):
19
20
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32 Purchases of nuclear decommissioning trust investments
33 Other
34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38
39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43 Payments to Advances by Assoc. and Subsidiary Companies
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
Current Year to Date
Quarter/Year
(b)
1,120,973,704
1,515,281,004
23,858,558
14,812,402
761,481,591
-4,664,829
-49,827,400
-43,909,347
-40,309,068
366,236
25,318,130
109,912,938
-18,557,028
56,285,941
3,288,311,012
-3,766,201,897
-144,436,347
-109,912,938
-1,456,220,929
-353,739
-5,257,299,974
21,591,000
-441,933,314
Previous Year to Date
Quarter/Year
(c)
1,250,003,668
1,388,520,924
25,383,583
16,553,588
791,854,460
-4,932,000
-592,355,717
109,764,592
-54,908,630
-32,491,883
48,293,640
95,257,573
-14,835,924
102,558,139
2,967,822,715
-3,921,706,484
-132,244,860
-95,257,573
-1,414,275,940
-378,883
-5,373,348,594
11,269,000
-771,429
-430,049,578
FERC FORM NO. 1 (ED. 12-96) Page 120

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line
Description (See Instruction No. 1 for Explanation of Codes)
No.
(a)
46 Loans Made or Purchased
47 Collections on Loans
48 Net (Increase) Decrease in Restricted Cash
49 Net (Increase) Decrease in Receivables
50 Net (Increase ) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
53 Other (provide details in footnote):
54 Proceeds from nuclear decommissioning trust sales
55 Other
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68 Equity infusion from PG&E Corporation
69
70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):
77 Customer Advances for Construction
78 Net Decrease in Short-Term Debt (c)
79 Other
80 Dividends on Preferred Stock
81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)
87
88 Cash and Cash Equivalents at Beginning of Period
89
90 Cash and Cash Equivalents at End of period
Current Year to Date
Quarter/Year
(b)
69,786,798
1,405,022,499
-3,656,565
-4,206,489,556
1,327,370,233
16,671,570
190,000,000
1,534,041,803
-95,000,000
-14,938,478
-58,705,277
-13,916,365
-716,000,000
635,481,683
-282,696,861
331,058,678
48,361,817
Previous Year to Date
Quarter/Year
(c)
657,221,132
1,351,000,000
197,747
-3,784,481,722
1,384,745,000
542,281,831
718,000,000
2,645,026,831
-909,000,000
1,582,462
3,660,856
-13,916,369
-624,000,000
1,103,353,780
286,694,773
44,363,905
331,058,678
FERC FORM NO. 1 (ED. 12-96) Page 121

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 120 Line No.: 18 Column: b
This consists of the following:
2010 2009
(Increase) Decrease in Other Working Capital $ (346,309,904) $ 273,643,456
Increase (Decrease) in Other Noncurrent
Assets and Liabilities 259,081,549 (214,388,127)
Others
Nuclear Fuel Lease Amortization 85,379,213 72,716,944
Other-net 58,135,083 (29,414,134)
-------------- --------------
Total $ 56,285,941 $ 102,558,139
============== ==============
Schedule Page: 120 Line No.: 18 Column: c
Refer to the footnote on Line 18, column b
Schedule Page: 120 Line No.: 90 Column: b
This consists of the following:
2010 2009
Cash (131) $ 44,435,787 $ 49,676,271
Working Funds (135) 126,030 144,255
Temporary Cash Investments (136) 3,800,000 281,238,152
-------------- --------------
Total $ 48,361,817 $ 331,058,678
============== ==============
Supplemental disclosures of cash flow information
(in millions):
Cash paid for:
Interest (net of amounts capitalized) $ (546) $ (578)
Income taxes paid (refunded), net (171) 170
Supplemental disclosures of noncash
investing and financing activities:
Capital expenditures financed through
accounts payable 364 273
Schedule Page: 120 Line No.: 90 Column: c
Refer to the footnote on Line 90, column b
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
Date of Report
04/08/2011
Year/Period of Report
End of 2010/Q4
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO. 1 (ED. 12-96) Page 122

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Introduction:
The accompanying financial statements on pages 110 through 121 of this Form 1 report of Pacific Gas and Electric Company
(the “Utility”) were prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission (“FERC”)
as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of
accounting other than accounting principles generally accepted in the United States of America (“GAAP”). The primary differences
from the Utility’s GAAP-basis financial statements as presented in the Form 1 are that (1) subsidiaries are not consolidated and are
shown under the equity method of accounting, (2) deferred income tax assets and liabilities are not offset against each other but are
shown as separate items on the balance sheet and are long-term, (3) cost of removal is reported in accumulated depreciation for FERC
reporting purposes (GAAP requires that cost of removal be classified as a regulatory liability), (4) there is no current liability
classification of the current portion of long-term debt for FERC reporting, (5) there is no reclassification of negative balances of
balancing accounts from current assets to current liabilities for FERC reporting, (6) there is no reclassification of price risk
management activities relating to the offsetting of financial assets and financial liabilities in the balance sheet for FERC reporting, and
(7) interdepartmental revenues and expenses between electric and gas operations of the Utility are not eliminated for FERC reporting .
The notes below are excerpts from PG&E Corporation and the Utility’s combined Annual Report on Form 10-K for the year
ended December 31, 2010, as filed with the Securities and Exchange Commission (“SEC”) on February 17, 2011. The following
disclosures contain information in accordance with SEC reporting requirements. As such, due to the differences between FERC and
SEC reporting requirements, certain amounts disclosed in the following notes may not agree to balances in the FERC financial
statements.
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2010
NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
PG&E Corporation 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 generates revenues mainly through the sale and delivery of electricity and natural gas to
customers. The Utility is regulated by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory
Commission (“FERC”). The Utility’s accounts for electric and gas operations are maintained in accordance with the Uniform System
of Accounts prescribed by the FERC.
This is a combined annual report of PG&E Corporation and the Utility. The Notes to the Consolidated Financial Statements
apply to both PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of
PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements
include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been
eliminated from the Consolidated Financial Statements.
The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally
accepted in the United States of America (“GAAP”) for annual financial statements and in accordance with the instructions to Form
10-K and Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”). The preparation of financial statements
in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future
regulatory decisions and economic conditions that are difficult to predict. Some of the more critical estimates and assumptions relate
to the Utility’s regulatory assets and liabilities, environmental remediation liabilities, asset retirement obligations (“ARO”), and
pension plan and other postretirement plan obligations. In addition, management has made significant estimates and assumptions for
accruals related to the rupture of a natural gas transmission pipeline owned and operated by the Utility in the City of San Bruno,
California on September 9, 2010, as well as accruals for various legal matters. (See Note 15 below.) Management believes that its
estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. Actual results could
FERC FORM NO. 1 (ED. 12-88) Page 123.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
differ materially from those estimates.
NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cash and Cash Equivalents
Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Cash
equivalents are stated at cost, which approximates fair value. PG&E Corporation and the Utility invest their cash primarily in money
market funds.
Restricted Cash
Restricted cash consists primarily of the Utility’s cash held in escrow pending the resolution of the remaining disputed claims
made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”). (See Note 13
below.) Restricted cash also includes the Utility’s deposits of cash and cash equivalents made under certain third-party agreements.
Allowance for Doubtful Accounts Receivable
PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record accounts receivable at estimated
net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of
receivables, current economic conditions, and assessment of customer collectability.
Inventories
Inventories are carried at weighted average cost and are valued at the lower of weighted-average cost or market. Inventories
include materials, supplies, and natural gas stored underground. Materials and supplies are charged to inventory when purchased and
then expensed or capitalized to plant, as appropriate, when consumed or installed. Natural gas stored underground represents
purchases that are injected into inventory and then expensed at average cost when withdrawn and distributed to customers or used in
electric generation.
Property, Plant, and Equipment
Property, plant, and equipment are reported at their original cost. These original costs include labor and materials,
construction overhead, and allowance for funds used during construction (“AFUDC”).
(in millions)
The Utility’s balances at December 31, 2010 are as follows:
Gross Plant as of
December 31, 2010
Accumulated
Depreciation as of
December 31, 2010
Net Plant as of
December 31, 2010
Electricity generating facilities (1) $ 6,012 $ (1,404) $ 4,608
Electricity distribution facilities 20,991 (7,161) 13,830
Electricity transmission 6,505 (1,829) 4,676
Natural gas distribution facilities 7,443 (2,819) 4,624
Natural gas transportation and storage 3,939 (1,613) 2,326
Construction work in progress 1,384 - 1,384
Total $ 46,274 $ (14,826) $ 31,448
(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted average cost. Nuclear fuel
in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.)
The Utility’s balances at December 31, 2009 are as follows:
FERC FORM NO. 1 (ED. 12-88) Page 123.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(in millions)
Gross Plant as of
December 31, 2009
Accumulated
Depreciation as of
December 31, 2009
Net Plant as of
December 31, 2009
Electricity generating facilities (1) $ 4,777 $ (1,279) $ 3,498
Electricity distribution facilities 19,924 (6,924) 13,000
Electricity transmission 5,780 (1,751) 4,029
Natural gas distribution facilities 7,069 (2,667) 4,402
Natural gas transportation and storage 3,628 (1,554) 2,074
Construction work in progress 1,888 - 1,888
Total $ 43,066 $ (14,175) $ 28,891
(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted average cost. Nuclear fuel
in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.)
AFUDC
AFUDC is a method used to compensate the Utility for the estimated cost of debt (interest) and equity funds used to finance
regulated plant additions and is capitalized as part of the cost of construction projects. AFUDC is recoverable from customers through
rates over the life of the related property once the property is placed in service. The portion of AFUDC related to the cost of debt is
recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded
AFUDC of $110 million and $50 million during 2010, $95 million and $44 million during 2009, $70 million and $44 million during
2008, related to equity and debt, respectively.
Depreciation
The Utility depreciates property, plant, and equipment on a straight-line basis over the estimated useful lives. The composite,
or group, method of depreciation is used, in which a single depreciation rate is applied to the gross investment in a particular class of
property. The Utility’s composite depreciation rate was 3.38% in 2010, 3.43% in 2009, and 3.38% in 2008.
Electricity generating facilities
Electricity distribution facilities
Electricity transmission
Natural gas distribution facilities
Natural gas transportation and storage
Estimated Useful Lives
4 to 37 years
16 to 58 years
40 to 70 years
24 to 52 years
25 to 48 years
The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the
depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original
cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the
original cost of the retired assets, net of salvage value, is charged to accumulated depreciation. The cost of repairs and maintenance,
including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense
as incurred.
Capitalized Software Costs
PG&E Corporation and the Utility capitalize costs incurred during the application development stage of internal use software
projects to property, plant, and equipment. PG&E Corporation and the Utility amortize capitalized software costs ratably over the
expected lives of the software, ranging from 3 to 15 years and commencing upon operational use. Capitalized software costs totaled
$580 million at December 31, 2010 and $562 million at December 31, 2009, net of accumulated amortization of $386 million at
December 31, 2010 and $315 million at December 31, 2009. Amortization expense for capitalized software was $94 million in 2010,
$37 million in 2009, and $73 million in 2008. Amortization expense is estimated to be approximately $120 million annually for 2011
FERC FORM NO. 1 (ED. 12-88) Page 123.3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
through 2015.
Regulation and Regulated Operations
As a regulated entity, the Utility’s rates are designed to recover the costs of providing service. The Utility capitalizes and
records, as a regulatory asset, costs that would otherwise be charged to expense if it is probable that the incurred costs will be
recovered in future rates. Regulatory assets are amortized over the future periods that the costs are recovered. If costs expected to be
incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory
liabilities. In addition, amounts that are probable of being credited or refunded to customers in the future are recorded as regulatory
liabilities.
The Utility uses regulatory balancing accounts to accumulate differences between actual billed and unbilled revenues and the
Utility’s authorized revenue requirements for the period. The Utility also uses regulatory balancing accounts to accumulate differences
between incurred costs and actual billed and unbilled revenues, as well as differences between incurred costs and authorized revenue
meant to recover those costs. Under-collections that are probable of recovery through regulated rates are recorded as regulatory
balancing account assets. Over-collections that are probable of being refunded to customers are recorded as regulatory balancing
account liabilities. For further discussion please see “Revenue Recognition” below.
To the extent that portions of the Utility’s operations cease to be subject to cost-of-service rate regulation, or recovery is no
longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
Intangible Assets
Intangible assets primarily consist of hydroelectric facility licenses with lives ranging from 19 to 40 years. The gross carrying
amount of the hydroelectric facility licenses and other agreements was $112 million at December 31, 2010 and $110 million at
December 31, 2009. The accumulated amortization was $44 million at December 31, 2010 and $40 million at December 31, 2009.
The Utility’s amortization expense related to intangible assets was $4 million in 2010, 2009, and 2008. The estimated annual
amortization expense for 2011 through 2015 based on the December 31, 2010 intangible assets balance is $3 million. Intangible assets
are recorded to other noncurrent assets – other in the Consolidated Balance Sheets.
Asset Retirement Obligations
PG&E Corporation and the Utility record an ARO at fair value in the period in which the obligation is incurred if the fair
value can be reasonably estimated. In the same period, the associated asset retirement costs are capitalized as part of the carrying
amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the long-lived asset. PG&E Corporation and the Utility also record a liability if a legal obligation
to perform an asset retirement exists and can be reasonably estimated, but performance is conditional upon a future event. The Utility
recognizes regulatory assets or liabilities as a result of timing differences between the recognition of costs and the costs recovered
through the ratemaking process.
The Utility has an ARO for its nuclear generation and certain fossil fueled generation facilities. The Utility has also identified
AROs related to asbestos contamination in buildings, potential site restoration at certain hydroelectric facilities, fuel storage tanks, and
contractual obligations to restore leased property to pre-lease condition. Additionally, the Utility has recorded AROs related to gas
distribution, gas transmission, electric distribution, and electric transmission system assets.
Detailed studies of the cost to decommission the Utility’s nuclear power plants are conducted every three years in conjunction
with the Nuclear Decommissioning Cost Triennial Proceedings (“NDCTP”) conducted by the CPUC. The decommissioning cost
estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs
may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements;
technology; and costs of labor, materials, and equipment. Estimated cash flows were revised as a result of the studies completed in the
first quarter of 2009.
FERC FORM NO. 1 (ED. 12-88) Page 123.4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
For GAAP purposes, the Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimate of
decommissioning its nuclear power facilities and records this as an adjustment to ARO on its Consolidated Balance Sheets. The total
nuclear decommissioning obligation accrued in accordance with GAAP was $1.2 billion at December 31, 2010 and $1.4 billion at
December 31, 2009. For regulatory purposes, the estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear
power plants was approximately $2.3 billion at December 31, 2010 and 2009 (or approximately $4.4 billion and $4.6 billion in future
dollars, respectively). These estimates are based on the 2009 decommissioning cost studies, prepared in accordance with CPUC
requirements.
Differences between amounts collected in rates for decommissioning the Utility’s nuclear power facilities and the
decommissioning obligation recorded in accordance with GAAP are reflected as a regulatory liability. (See Note 3 below.)
A reconciliation of the changes in the ARO liability is as follows:
(in millions)
ARO liability at December 31, 2008 $ 1,684
Revision in estimated cash flows (129)
Accretion 98
Liabilities settled (60)
ARO liability at December 31, 2009 1,593
Revision in estimated cash flows (23)
Accretion 93
Liabilities settled (77)
ARO liability at December 31, 2010 $ 1,586
The Utility has identified additional ARO for which a reasonable estimate of fair value could not be made. The Utility has not
recognized a liability related to these additional obligations, which include obligations to restore land to its pre-use condition under the
terms of certain land rights agreements, removal and proper disposal of lead-based paint contained in some Utility facilities, removal
of certain communications equipment from leased property, and retirement activities associated with substation and certain
hydroelectric facilities. The Utility was not able to reasonably estimate the ARO associated with these assets because the settlement
date of the obligation was indeterminate and information sufficient to reasonably estimate the settlement date or range of settlement
dates does not exist. Land rights, communications equipment leases, and substation facilities will be maintained for the foreseeable
future, and therefore, the Utility cannot reasonably estimate the settlement date or range of settlement dates for the obligations
associated with these assets. The Utility does not have information available that specifies which facilities contain lead-based paint
and, therefore, cannot reasonably estimate the settlement date(s) associated with the obligation. The Utility will maintain and continue
to operate its hydroelectric facilities until the operation of a facility becomes uneconomical. The operation of the majority of the
Utility’s hydroelectric facilities is currently, and for the foreseeable future, economically beneficial. Therefore, the settlement date
cannot be determined at this time.
Impairment of Long-Lived Assets
PG&E Corporation and the Utility evaluate the carrying amounts of long-lived assets for impairment, based on projections of
undiscounted future cash flows, whenever events occur or circumstances change that may affect the recoverability or the estimated life
of long-lived assets. If this evaluation indicates that such cash flows are not expected to fully recover the assets, the assets are written
down to their estimated fair value. No significant impairments were recorded in 2010, 2009, or 2008.
Gains and Losses on Debt Extinguishments
Gains and losses on debt extinguishments associated with regulated operations are deferred and amortized over the remaining
original amortization period of the debt reacquired, consistent with recovery of costs through regulated rates. PG&E Corporation and
the Utility recorded unamortized loss on debt extinguishments, net of gain, of $204 million and $227 million at December 31, 2010
FERC FORM NO. 1 (ED. 12-88) Page 123.5

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
and 2009, respectively. The amortization expense related to this loss was $23 million in 2010, $25 million in 2009, and $26 million in
2008. Deferred gains and losses on debt extinguishments are recorded to other and other noncurrent assets – regulatory assets in the
Consolidated Balance Sheets.
Gains and losses on debt extinguishments associated with unregulated operations are fully recognized at the time such debt is
reacquired and are reported as a component of interest expense.
Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss) reports a measure for accumulated changes in equity of an enterprise that
result from transactions and other economic events, other than transactions with shareholders. The following table sets forth the
after-tax changes in each component of accumulated other comprehensive income (loss):
Employee Benefit Plans – Accumulated Other Comprehensive
Income (Loss)
(in millions) 2010 2009 2008
Balance at beginning of year $ (160) $ (221) $ 10
Period change in pension benefits and
other benefits:
Unrecognized prior service cost (1) (29) (1) 37
Unrecognized net gain (loss) (2) (110) 363 (1,583)
Unrecognized net transition
obligation (3) 15 15 15
Transfer to regulatory account (4)
(5) 82 (316) 1,300
Balance at end of year $ (202) $ (160) $ (221)
(1) Net of income tax benefit (expense) of $20 million, $1 million, $(27) million for December 31, 2010, 2009, and 2008,
respectively.
(2) Net of income tax benefit (expense) of $73 million, $(216) million, $1,088 million for December 31, 2010, 2009, and 2008,
respectively.
(3) Net of income tax benefit (expense) of $(11) million for December 31, 2010, 2009, and 2008.
(4) Net of income tax benefit (expense) of $(57) million, $218 million, $(894) million for December 31, 2010, 2009, and 2008,
respectively.
(5) Amounts transferred to the pension regulatory asset are probable of recovery from customers in future rates.
There was no material difference between PG&E Corporation’s and the Utility’s accumulated other comprehensive income
(loss) for the periods presented above.
Revenue Recognition
The Utility recognizes revenues after persuasive evidence of an arrangement exists, delivery has occurred, or services have
been rendered; the price to the customer is fixed or determinable and collectability is reasonably assured. Revenues meet these criteria
as the electricity and natural gas services are delivered, and include amounts for services rendered but not yet billed at the end of the
period.
The Utility recognizes revenues after the CPUC or the FERC has authorized rate recovery, amounts are objectively
determinable and probable of recovery, and amounts will be collected within 24 months. (See Note 3 below.)
The CPUC authorizes most of the Utility’s revenue requirements in its general rate case (“GRC”), which generally occurs
FERC FORM NO. 1 (ED. 12-88) Page 123.6

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
every three years. The Utility’s ability to recover revenue requirements authorized by the CPUC in the GRC does not depend on the
volume of the Utility’s sales of electricity and natural gas services. Generally, the revenue recognition criteria are met ratably over the
year.
The CPUC also has authorized the Utility to collect additional revenue requirements to recover certain costs that the Utility
has been authorized to pass on to customers, including costs to purchase electricity and natural gas; to fund public purpose, demand
response, and customer energy efficiency programs; and to recover certain capital expenditures. Generally, the revenue recognition
criteria for pass through costs billed to customers are met at the time the costs are incurred.
The Utility’s revenues and earnings also are affected by incentive ratemaking mechanisms that adjust rates depending on the
extent the Utility meets certain performance criteria. (See Note 15 below.)
The FERC authorizes the Utility’s revenue requirements in annual transmission owner rate cases. The Utility’s ability to
recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is
recognized only for amounts billed and unbilled.
In determining whether revenue transactions should be presented net of the related expenses, the Utility considers various
factors, including whether the Utility takes title to the product being delivered, has latitude in establishing price for the product, and is
subject to the customer credit risk. In January 2001, the California Department of Water Resources (“DWR”) began purchasing
electricity to meet the portion of demand of the California investor-owned electric utilities that was not being satisfied from the
utilities’ own generation facilities and existing electricity contracts. The Utility acts as a billing and collection agent on behalf of the
DWR and does not have any authority to set prices for the energy delivered. The Utility does not assume customer credit risk nor take
title to the electricity being delivered to the customer. Therefore, the Utility presents the electricity revenues for amounts delivered to
customers net of the cost of electricity delivered by the DWR.
Income Taxes
PG&E Corporation and the Utility use the liability method of accounting for income taxes. Income tax provision (benefit)
includes current and deferred income taxes resulting from operations during the year. Investment tax credits are deferred and
amortized to income over time. The Utility amortizes its investment tax credits over the life of the related property in accordance with
regulatory treatment. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period or the life
of the arrangement for its tax equity arrangements. (See Note 9 below.)
PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to
be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit
recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being
realized upon settlement. The difference between a tax position taken or expected to be taken in a tax return and the benefit
recognized and measured pursuant to this guidance represents an unrecognized tax benefit.
PG&E Corporation files a consolidated U.S. federal income tax return that includes domestic subsidiaries in which its
ownership is 80% or more. In addition, PG&E Corporation files a combined state income tax return in California. PG&E Corporation
and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a
stand-alone basis.
Nuclear Decommissioning Trusts
The Utility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay. 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 Nuclear Regulatory Commission (“NRC”) license and release of the property for unrestricted use. The
Utility's nuclear decommissioning costs are recovered from customers through rates.
The Utility classifies its investments held in the nuclear decommissioning trust as “available-for-sale.” As the Utility’s
FERC FORM NO. 1 (ED. 12-88) Page 123.7

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its
investments at their discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on
the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers. Therefore, trust earnings
are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings
or accumulated other comprehensive income. The cost of debt and equity securities sold is determined by specific identification.
Accounting for Derivatives and Hedging Activities
Derivative instruments are recorded in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets at fair value,
unless they qualify for the normal purchase and sales exception. Changes in the fair value of derivative instruments are recorded in
earnings or, to the extent that they are recoverable through regulated rates, are deferred and recorded in regulatory accounts.
Derivative instruments may be designated as cash flow hedges when they are entered into in order to hedge variable price risk
associated with the purchase of commodities. For cash flow hedges, fair value changes are deferred in accumulated other
comprehensive income and recognized in earnings as the hedged transactions occur, unless they are recovered in rates, in which case
they are recorded in regulatory accounts.
As of September 30, 2009, the Utility de-designated all cash flow hedge relationships. Due to the regulatory accounting
treatment described above, the de-designation of cash flow hedge relationships had no impact on net income or the Consolidated
Balance Sheets.
The normal purchase and sales exception to derivative accounting requires, among other things, physical delivery of
quantities expected to be used or sold over a reasonable period in the normal course of business. Transactions for which the normal
purchase and sales exception is elected are not reflected in the Consolidated Balance Sheets at fair value. They are accounted for
under the accrual method of accounting. Therefore, expenses are recognized as incurred.
PG&E Corporation and the Utility offset the cash collateral paid or cash collateral received against the fair value amounts
recognized for derivative instruments executed with the same counterparty under a master netting arrangement where the right of offset
exists and where PG&E Corporation and the Utility intends to set off. (See Note 10 below.)
Fair Value Measurements
PG&E Corporation and the Utility determine the fair value of certain assets and liabilities based on assumptions that market
participants would use in pricing the assets or liabilities. Fair value is defined as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market participants at the measurement date, or the “exit price.” PG&E
Corporation and the Utility utilize a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value
and give precedence to observable inputs in determining fair value. An instrument’s level within the hierarchy is based on the lowest
level of any significant input to the fair value measurement. The hierarchy gives the highest priority to unadjusted quoted prices in
active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3
measurements). (See Note 11 below.)
Adoption of New Accounting Pronouncements
Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities
On January 1, 2010, PG&E Corporation and the Utility adopted an accounting standards update that changes when and how
to determine, or re-determine, whether an entity is a variable interest entity (“VIE”), which could require consolidation. In addition,
the accounting standards update replaces the quantitative approach for determining who has a controlling financial interest in a VIE
with a qualitative approach and requires ongoing assessments of whether an entity is the primary beneficiary of a VIE. The adoption
of the accounting standards update did not have a material impact on PG&E Corporation’s or the Utility’s Consolidated Financial
Statements.
PG&E Corporation and the Utility are required to consolidate any entities that they control. In most cases, control can be
FERC FORM NO. 1 (ED. 12-88) Page 123.8

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on
ownership or voting interests alone. These entities are referred to as VIEs. A VIE is an entity that does not have sufficient equity at
risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any
characteristics of a controlling financial interest. An enterprise has a controlling financial interest if it has the obligation to absorb
expected losses or receive expected gains that could potentially be significant to a VIE and the power to direct the activities that are
most significant to a VIE’s economic performance. An enterprise that has a controlling financial interest is known as the VIE’s
primary beneficiary and is required to consolidate the VIE.
Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. In determining whether the
Utility has a controlling financial interest in a VIE, the Utility must first assess whether it absorbs any of the VIE’s expected losses or
receives any portion of the VIE’s expected residual returns, as a result of power purchase agreements. This assessment includes an
evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders. These
VIEs are typically exposed to credit risk, production risk, commodity price risk, and any applicable tax incentive risks, among others.
The Utility analyzes the variability in the VIE’s gross margin and the impact of power purchase agreements on the gross margin to
determine whether the Utility absorbs variability, resulting in a variable interest. Factors that may be considered when assessing the
impact of a power purchase agreement on the VIE’s gross margin include the pricing structure of the power purchase agreement and
the cost of inputs and production, which depend on the technology of the power plant.
For each variable interest, the Utility must also assess whether it has the power to direct the activities of the power plant that
most directly impact the VIE’s economic performance. This assessment considers any decision-making rights associated with
designing the VIE, any dispatch rights, any operating and maintenance activities, and any re-marketing activities of the power plant
after the end of the power purchase agreement with the Utility.
The Utility held a variable interest in several entities that own power plants that generate electricity for sale to the Utility
under power purchase agreements. Each of these VIEs was designed to own a power plant that would generate electricity for sale to
the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, and hydroelectric. Under each of
these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE. The Utility did not
provide any other support to these VIEs, and the Utility’s financial exposure is limited to the amount it pays for delivered electricity
and capacity. (See Note 15 below.) The Utility does not have the power to direct the activities that are most significant to these VIE’s
economic performance. As a result, the Utility does not have a controlling financial interest in any of these VIEs. Therefore, at
December 31, 2010, the Utility was not the primary beneficiary of, and did not consolidate, any of these VIEs.
The Utility continued to consolidate PG&E Energy Recovery Funding LLC (“PERF”) at December 31, 2010, as the Utility is
the primary beneficiary of PERF. The Utility has a controlling financial interest in PERF since the Utility is exposed to PERF’s losses
and returns through the Utility’s 100% equity investment in PERF and the Utility was involved in the design of PERF, which was an
activity that was significant to PERF’s economic performance. The assets of PERF were $897 million at December 31, 2010 and
primarily consisted of assets related to energy recovery bonds (“ERBs”), which are included in other noncurrent assets – regulatory
assets in the Consolidated Balance Sheets. The liabilities of PERF were $827 million at December 31, 2010 and consisted of energy
recovery bonds, which are included in current and noncurrent liabilities in the Consolidated Balance Sheets. (See Note 5 below.) The
assets of PERF are only available to settle the liabilities of PERF.
As of December 31, 2010, PG&E Corporation’s affiliates had entered into four tax equity agreements with privately held
companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation will
provide payments of up to $300 million to these companies, and in return, receive the benefits from local rebates, federal investment
tax credits or grants, and a share of these companies’ customer payments. PG&E Corporation could be required to pay up to an
additional $41 million in the event that its ownership interests are liquidated when in a deficit position. However, PG&E
Corporation’s financial exposure from these agreements is generally limited to its lease payments and investment contributions to these
companies. As of December 31, 2010, PG&E Corporation had made total payments of $149 million under these agreements primarily
related to its lease payments and investment contributions to these companies. These amounts are recorded in other noncurrent assets
– other in PG&E Corporation’s Consolidated Balance Sheet. PG&E Corporation holds a variable interest in these companies as a
result of these agreements. When determining whether PG&E Corporation is the primary beneficiary of these companies, it evaluated
which party has control over their significant economic activities such as designing the companies, vendor selection, construction,
FERC FORM NO. 1 (ED. 12-88) Page 123.9

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
customer selection, and re-marketing activities at the end of customer leases. As these activities are under the control of these
companies, PG&E Corporation was not the primary beneficiary of, and did not consolidate, any of these companies at December 31,
2010.
NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
Regulatory Assets
Current Regulatory Assets
At December 31, 2010 and 2009, the Utility had current regulatory assets of $599 million and $427 million, respectively,
consisting primarily of price risk management regulatory assets. The current portion of price risk management regulatory assets
represents the deferral of unrealized losses related to price risk management derivative instruments with terms of one year or less. (See
Note 10 below.)
Long-Term Regulatory Assets
Long-term regulatory assets are composed of the following:
Balance at December 31,
(in millions) 2010 2009
Pension benefits $ 1,759 $ 1,386
Deferred income taxes 1,250 1,027
Energy recovery bonds 735 1,124
Utility retained generation 666 737
Environmental compliance costs 450 408
Price risk management 424 346
Unamortized loss, net of gain, on reacquired debt 181 203
Other 381 291
Total long-term regulatory assets $ 5,846 $ 5,522
The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking
purposes and amounts recognized in accordance with GAAP, which also includes amounts that otherwise would be fully recorded to
accumulated other comprehensive loss in the Consolidated Balance Sheets. (See Note 12 below.)
The regulatory assets for deferred income taxes represent deferred income tax benefits previously passed through to
customers. The CPUC requires the Utility to pass through certain tax benefits to customers by reducing rates, thereby ignoring the
effect of deferred taxes on rates. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover these
regulatory assets over average plant depreciation lives of 1 to 45 years.
The regulatory asset for ERBs represents the refinancing of the regulatory asset provided for in the settlement agreement
entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11 of the
U.S. Bankruptcy Code (“Chapter 11 Settlement Agreement”). (See Note 5 below.) The regulatory asset is amortized over the life of
the bonds, consistent with the period over which the related revenues and bond-related expenses are recognized. The Utility expects to
fully recover this asset by the end of 2012 when the ERBs mature.
In connection with the Chapter 11 Settlement Agreement, the CPUC authorized the Utility to recover $1.2 billion of costs
related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the
respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. The
weighted average remaining life of the assets is 13 years.
The regulatory assets for environmental compliance costs represent the portion of estimated environmental remediation costs
FERC FORM NO. 1 (ED. 12-88) Page 123.10

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
that the Utility expects to recover in future rates as actual remediation costs are incurred. The Utility expects to recover these costs
over the next 32 years. (See Note 15 below.)
Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative
instruments with terms in excess of one year. (See Note 10 below.)
The regulatory assets for unamortized loss, net of gain, on reacquired debt represent costs related to debt reacquired or
redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the next
16 years, which is the remaining amortization period of the reacquired debt. The Utility expects to fully recover these costs by 2026.
At December 31, 2010 and 2009, “other” primarily consisted of regulatory assets relating to ARO expenses for
decommissioning of the Utility’s fossil-fuel generation facilities that are probable of future recovery through the ratemaking process;
costs that the Utility incurred in terminating a 30-year power purchase agreement which are being amortized and collected in rates
through September 2014; and costs incurred in relation to the Utility’s plan of reorganization under Chapter 11 that became effective
in April 2004. Additionally, at December 31, 2010, “other” included removal costs associated with the replacement of old
electromechanical meters with SmartMeter devices.
In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the
Utility earns a return only on its retained generation regulatory assets and regulatory assets for unamortized loss, net of gain, on
reacquired debt.
Regulatory Liabilities
Current Regulatory Liabilities
At December 31, 2010 and 2009, the Utility had current regulatory liabilities of $81 million and $163 million, respectively,
primarily consisting of amounts that the Utility expects to refund to customers for over-collected electric transmission rates and
amounts that the Utility expects to refund to electric transmission customers for their portion of settlements the Utility entered into with
various electricity suppliers to resolve certain remaining Chapter 11 disputed claims. Current regulatory liabilities are included in
current liabilities – other in the Consolidated Balance Sheets.
Long-Term Regulatory Liabilities
Long-term regulatory liabilities are composed of the following:
Balance at December 31,
(in millions) 2010 2009
Cost of removal obligation $ 3,229 $ 2,933
Recoveries in excess of ARO 600 488
Public purpose programs 573 508
Other 123 196
Total long-term regulatory liabilities $ 4,525 $ 4,125
The regulatory liability for the Utility’s cost of removal obligations represents differences between amounts collected in rates
for asset removal costs and the asset removal costs recorded in accordance with GAAP.
The regulatory liability for recoveries in excess of ARO represents differences between amounts collected in rates for
decommissioning the Utility’s nuclear power facilities and the ARO expenses recorded in accordance with GAAP. Decommissioning
costs recovered in rates are placed in nuclear decommissioning trusts. The regulatory liability for recoveries in excess of ARO also
represents the deferral of realized and unrealized gains and losses on those nuclear decommissioning trust assets.
The regulatory liability for public purpose programs represents amounts received from customers designated for public
FERC FORM NO. 1 (ED. 12-88) Page 123.11

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
purpose programs costs that are expected to be incurred in the future. The public purpose programs regulatory liabilities primarily
consist of revenues collected from customers to pay for costs that the Utility expects to incur in the future under energy efficiency
programs designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other
energy-using products; under the California Solar Initiative program to promote the use of solar energy in residential homes and
commercial, industrial, and agricultural properties; and under the Self-Generation Incentive program to promote distributed generation
technologies installed on the customer’s side of the Utility meter that provide electricity and gas for all or a portion of that customer’s
load.
“Other” at December 31, 2010 and 2009 primarily consisted of regulatory liabilities related to the gain associated with the
Utility’s acquisition of the permits and other assets related to the Gateway Generating Station as part of a settlement that the Utility
entered into with Mirant Corporation and insurance recoveries for hazardous substance remediation.
Regulatory Balancing Accounts
The Utility’s current regulatory balancing accounts represent the amounts expected to be received from or refunded to the
Utility’s customers through authorized rate adjustments within the next 12 months. Regulatory balancing accounts that the Utility does
not expect to collect or refund in the next 12 months are included in other noncurrent assets – regulatory assets and noncurrent
liabilities – regulatory liabilities in the Consolidated Balance Sheets.
Current Regulatory Balancing Accounts, net
Receivable (Payable)
Balance at December 31,
(in millions) 2010 2009
Utility generation $ 303 $ 355
Public purpose programs 164 83
Distribution revenue adjustment mechanism 145 152
Gas fixed cost 56 93
Hazardous substance 38 30
Other 143 115
Total regulatory balancing accounts, net $ 849 $ 828
The utility generation balancing account is used to record and recover the authorized revenue requirements associated with
Utility-owned electric generation, including capital and related non-fuel operating and maintenance expenses. The distribution revenue
adjustment mechanism balancing account is used to record and recover the authorized electric distribution revenue requirements and
certain other electric distribution-related authorized costs. The Utility’s recovery of these revenue requirements is independent, or
“decoupled,” from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash
collected from customers will fluctuate depending on the volume of electricity sales. During periods of more temperate weather, there
is generally an under-collection in this balancing account due to lower electricity sales and lower rates. During the warmer months of
summer, there is generally an over-collection due to higher rates and electric usage that cause an increase in generation billings.
The public purpose programs balancing accounts primarily track the recovery of the authorized public purpose program
revenue requirements and incentive awards earned by the Utility for implementing customer energy efficiency programs. The public
purpose programs primarily consist of the energy efficiency programs; low-income energy efficiency programs; research, development,
and demonstration programs; and renewable energy programs.
The gas fixed cost balancing account is used to track the recovery of CPUC-authorized gas distribution revenue requirements
and certain other gas distribution-related costs. The under-collected or over-collected position of this account is dependent on
seasonality and volatility in gas volumes.
FERC FORM NO. 1 (ED. 12-88) Page 123.12

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The hazardous substance balancing accounts are used to track recoverable hazardous substance clean up costs through the
CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs. The current
balance represents eligible remediation costs incurred by the Utility during 2009 that will be recovered through an annual true-up filing
with the CPUC in January 2011. (See Note 15 below.)
At December 31, 2010 and 2009, “other” primarily consisted of balancing accounts that track recovery of the authorized
revenue requirements and costs related to the SmartMeterTM advanced metering project.
NOTE 4: DEBT
Long-Term Debt
The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:
December 31,
(in millions) 2010 2009
PG&E Corporation
Convertible subordinated notes, 9.50%, due 2010 $ - $ 247
Less: current portion - (247)
Total convertible subordinated notes - -
Senior notes, 5.75%, due 2014 350 350
Unamortized discount (1) (2)
Total senior notes 349 348
Total PG&E Corporation long-term debt, net of current portion 349 348
Utility
Senior notes:
4.20% due 2011 500 500
6.25% due 2013 400 400
4.80% due 2014 1,000 1,000
5.625% due 2017 700 700
8.25% due 2018 800 800
3.50% due 2020 800 -
6.05% due 2034 3,000 3,000
5.80% due 2037 950 700
6.35% due 2038 400 400
6.25% due 2039 550 550
5.40% due 2040 800 550
Less: current portion (500) -
Unamortized discount, net of premium (52) (35)
Total senior notes 9,348 8,565
Pollution control bonds:
Series 1996 C, E, F, 1997 B, variable rates (1), due 2026 (2) 614 614
Series 1996 A, 5.35%, due 2016 (3) 200 200
Series 2004 A-D, 4.75%, due 2023 (3) 345 345
Series 2008 G and F, 3.75% (4), due 2018 and 2026 - 95
Series 2009 A-D, variable rates (5), due 2016 and 2026 (6) 309 309
Series 2010 E, 2.25%, due 2026 (7) 50 -
Less: current portion (309) (95)
Total pollution control bonds 1,209 1,468
FERC FORM NO. 1 (ED. 12-88) Page 123.13

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Total Utility long-term debt, net of current portion 10,557 10,033
Total consolidated long-term debt, net of current portion $ 10,906 $ 10,381
(1) At December 31, 2010, interest rates on these bonds and the related loans ranged from 0.26% to 0.31%.
(2) Each series of these bonds is supported by a separate direct-pay letter of credit that expires on February 26, 2012. Although the stated maturity
date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains a
consent from the issuer to the continuation of the series without a credit facility.
(3) The Utility has obtained credit support from insurance companies for these bonds.
(4) These bonds bore interest at 3.75% per year through September 19, 2010, and were subject to mandatory tender on September 20, 2010. The
Utility repurchased these bonds on September 20, 2010.
(5) At December 31, 2010, interest rates on these bonds and the related loans ranged from 0.22% to 0.29%.
(6) Each series of these bonds is supported by a separate direct-pay letter of credit that expires on October 29, 2011. The Utility may choose to
provide a substitute letter of credit for any series of these bonds, subject to a rating requirement.
(7) These bonds bear interest at 2.25% per year through April 1, 2012, are subject to mandatory tender on April 2, 2012, and may be remarketed in a
fixed or variable rate mode.
PG&E Corporation
Convertible Subordinated Notes
PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of
PG&E Corporation’s 9.5% Convertible Subordinated Notes at a conversion price of $15.09 per share between June 23 and June 29,
2010. These notes were no longer outstanding as of December 31, 2010.
Utility
Senior Notes
On April 1, 2010, the Utility issued $250 million principal amount of 5.8% Senior Notes due March 1, 2037.
On September 15, 2010, the Utility issued $550 million principal amount of 3.5% Senior Notes due October 1, 2020.
On November 18, 2010, the Utility issued $250 million principal amount of 3.5% Senior Notes due October 1, 2020 and $250
million of 5.4% Senior Notes due January 15, 2040.
Pollution Control Bonds
The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank
have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility. Under the
pollution control bond loan agreements related to the Series 1996 A bonds, the Series 2004 A–D bonds, and the Series 2010 E bonds,
the Utility is obligated to pay on the due dates an amount equal to the principal; premium, if any; and interest on these bonds to the
trustees for these bonds. With respect to the Series 1996 C, E, and F bonds; the Series 1997 B bonds; and the Series 2009 A–D bonds
which currently bear interest at variable rates, the Utility reimburses the letter of credit providers for their payments to the trustee for
these bonds, or if a letter of credit provider fails to pay under its respective letter of credit, the Utility is obligated to pay the principal;
premium, if any; and interest on those bonds. All payments on the Series 1996 C, E, and F bonds; the Series 1997 B bonds; and the
Series 2009 A–D bonds are made through draws on separate direct-pay letters of credit for each series issued by a financial institution.
The Utility has obtained credit support from insurance companies for the Series 1996 A bonds and the Series 2004 A–D
bonds such that if the Utility does not pay the principal and interest on any series of these insured bonds, the bond insurer for that
series will pay the principal and interest.
FERC FORM NO. 1 (ED. 12-88) Page 123.14

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
On April 8, 2010, the California Infrastructure and Economic Development Bank issued $50 million of tax-exempt pollution
control bonds Series 2010 E due November 1, 2026 and loaned the proceeds to the Utility. The proceeds were used to refund the
corresponding related series of pollution control bonds issued in 2005 which were repurchased by the Utility in 2008. The Series 2010
E bonds bear interest at 2.25% per year through April 1, 2012 and are subject to mandatory tender on April 2, 2012 at a price of 100%
of the principal amount plus accrued interest. Thereafter, this series of bonds may be remarketed in a fixed or variable rate mode.
Interest is currently payable semi-annually in arrears on April 1 and October 1.
On September 20, 2010, the Utility repurchased $50 million principal amount of pollution control bonds Series 2008 F and
$45 million principal amount of pollution control bonds Series 2008 G that were subject to mandatory tender on the same date. The
Utility, as bondholder, will be both the payer and the recipient of principal and interest payments until the bonds are remarketed to the
public. As of December 31, 2010, the bonds have not been remarketed to the public.
All of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal
facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant and were issued as “exempt
facility bonds” within the meaning of the Internal Revenue Code of 1954, as amended. In 1999, the Utility sold the Geysers
geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sale agreements stating that Geysers Power
Company, LLC will use the bond-financed facilities solely as pollution control facilities. The Utility has no knowledge that Geysers
Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.
Repayment Schedule
PG&E Corporation’s and the Utility’s combined aggregate principal repayment amounts of long-term debt at December 31,
2010 are reflected in the table below:
(in millions, except interest rates) 2011 2012 2013 2014 2015 Thereafter Total
Long-term debt:
PG&E Corporation
Average fixed interest rate - - - 5.75% - - 5.75%
Fixed rate obligations $ - $ - $ - $ 350 $ - $ - $ 350
Utility
Average fixed interest rate 4.20% 2.25% 6.25% 4.80% - 5.85% 5.67%
Fixed rate obligations $ 500 $ 50(2) $ 400 $ 1,000 $ - $ 8,545 $ 10,495
Variable interest rate as of December 31, 2010 0.27% 0.28% - - - - 0.28%
Variable rate obligations $ 309(1) $ 614(3) $ - $ - $ - $ - $ 923
Less: current portion (809) - - - - - (809)
Total consolidated long-term debt $ - $ 664 $ 400 $ 1,350 $ - $ 8,545 $ 10,959
(1) These bonds, due from 2016 through 2026, are backed by direct-pay letters of credit that expire on October 29, 2011. The bonds will be subject to a
mandatory redemption unless the letter of credit is extended or replaced or the issuer consents to the continuation of these series without a credit facility.
Accordingly, the bonds have been classified for repayment purposes in 2011.
(2) These bonds, due in 2026, are subject to mandatory tender on April 2, 2012 and may be remarketed in a fixed or variable rate mode. Accordingly, the
bonds have been classified for repayment purposes in 2012.
(3) These bonds, due in 2026, are backed by direct-pay letters of credit that expire on February 26, 2012. The bonds will be subject to a mandatory
redemption unless the letters of credit are extended or replaced. Accordingly, the bonds have been classified for repayment purposes in 2012.
Credit Facilities and Short-Term Borrowings
The following table summarizes PG&E Corporation’s and the Utility’s borrowings on outstanding credit facilities at
FERC FORM NO. 1 (ED. 12-88) Page 123.15

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
December 31, 2010:
Letters of
Commercial
Termination Facility Credit Out- Cash Paper
(in millions) Date Limit standing Borrowings Backup Availability
PG&E Corporation February 2012 $ 187 (1) $ - $ - N/A $ 187
Utility February 2012 1,940 (2) 329 - $ 603 1,008
Utility February 2012 750 (3) N/A - - 750
Total credit facilities $ 2,877 $ 329 $ - $ 603 $ 1,945
(1) Includes a $87 million sublimit for letters of credit and a $100 million commitment for “swingline” loans, defined as loans that are made available on
a same-day basis and are repayable in full within 30 days.
(2) Includes a $921 million sublimit for letters of credit and a $200 million commitment for swingline loans.
(3) Includes a $75 million commitment for swingline loans.
PG&E Corporation
Revolving credit facility
PG&E Corporation has a $187 million revolving credit facility with a syndicate of lenders that expires on February 26, 2012.
Borrowings under the revolving credit facility and letters of credit may be used for working capital and other corporate purposes.
PG&E Corporation can, at any time, repay amounts outstanding in whole or in part. At PG&E Corporation’s request and at the sole
discretion of each lender, the revolving credit facility may be extended for additional periods. PG&E Corporation has the right to
increase, in one or more requests given no more than once a year, the aggregate facility by up to $100 million provided that certain
conditions are met. The fees and interest rates that PG&E Corporation pays under the revolving credit facility vary depending on the
Utility’s unsecured debt ratings issued by Standard & Poor’s (“S&P”) ratings service and Moody’s Investors Service (“Moody’s”).
The revolving credit facility includes usual and customary covenants for credit facilities of this type, including covenants
limiting liens, mergers, sales of all or substantially all of PG&E Corporation’s assets, and other fundamental changes. In general, the
covenants, representations, and events of default mirror those in the Utility’s revolving credit facility, discussed below. In addition, the
revolving credit facility requires that PG&E Corporation maintain a ratio of total consolidated debt to total consolidated capitalization
of at most 65% and that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the
voting securities of the Utility. At December 31, 2010, PG&E Corporation met both of these tests.
Utility
Revolving credit facilities
The Utility has a $1.9 billion revolving credit facility with a syndicate of lenders that expires on February 26, 2012.
Borrowings under the revolving credit facility and letters of credit are used primarily for liquidity and to provide credit enhancements
to counterparties for natural gas and energy procurement transactions.
On June 8, 2010, the Utility entered into a $750 million unsecured revolving credit agreement with a syndicate of lenders. Of
the total credit capacity, $500 million was used to replace the $500 million Floating Rate Senior Notes that matured on June 10, 2010.
The aggregate facility of $750 million includes a $75 million commitment for swingline loans, or loans that are made available on a
same-day basis and are repayable in full within 30 days. The Utility can, at any time, repay amounts outstanding in whole or in part.
The credit agreement expires on February 26, 2012, unless extended for additional periods at the Utility’s request and at the sole
discretion of each lender.
Borrowings under the credit agreement (other than swingline loans) will bear interest based, at the Utility’s election, at (1)
London Interbank Offered Rate (“LIBOR”) plus an applicable margin or (2) the base rate, which will equal the higher of the (i)
FERC FORM NO. 1 (ED. 12-88) Page 123.16

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
administrative agent’s announced base rate, (ii) 0.5% above the federal funds rate, or (iii) the one-month LIBOR plus an applicable
margin. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods. The Utility also will pay a facility fee
on the total commitments of the lenders under the credit agreement. The applicable margin for LIBOR loans and the facility fee will
be based on the Utility’s senior unsecured, non-credit enhanced debt ratings issued by S&P and Moody’s. Facility fees are payable
quarterly in arrears.
The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving
credit facilities so that liquidity from the revolving credit facility is available to repay outstanding commercial paper.
The revolving credit facilities include usual and customary covenants for credit facilities of this type, including covenants
limiting liens to those permitted under the senior note indenture, mergers, sales of all or substantially all of the Utility’s assets, and
other fundamental changes. Both the $750 million and $1.9 billion revolving credit facilities require that the Utility maintain a ratio of
total consolidated debt to total consolidated capitalization of, at most, 65% as of the end of each fiscal quarter. At December 31,
2010, the Utility met this ratio test.
Commercial Paper Program
The Utility has a $1.75 billion commercial paper program, the borrowings from which are used primarily to cover fluctuations
in cash flow requirements. Liquidity support for these borrowings is provided by available capacity under the Utility’s revolving credit
facilities, as described above. The commercial paper may have maturities up to 365 days and ranks equally with the Utility’s other
unsubordinated and unsecured indebtedness. Commercial paper notes are sold at an interest rate dictated by the market at the time of
issuance. At December 31, 2010, the average yield was 0.51%.
Other Short-term Borrowings
On October 12, 2010, the Utility issued $250 million principal amount of Floating Rate Senior Notes due October 11, 2011.
The interest rate for the Floating Rate Senior Notes is equal to the three-month LIBOR plus 0.58% and will reset quarterly beginning
on January 11, 2011. At December 31, 2010, the interest rate on the Floating Rate Senior Notes was 0.87%. On January 11, 2011, the
interest rate was reset to 0.88%.
NOTE 5: ENERGY RECOVERY BONDS
In 2005, PERF issued two separate series of ERBs in the aggregate amount of $2.7 billion to refinance a regulatory asset that
the Utility recorded in connection with the Chapter 11 Settlement Agreement. The proceeds of the ERBs were used by PERF to
purchase from the Utility the right, known as “recovery property,” to be paid a specified amount from a dedicated rate component
(“DRC”) to be collected from the Utility’s electricity customers. DRC charges are authorized by the CPUC under state legislation and
will be paid by the Utility’s electricity customers until the ERBs are fully retired. Under the terms of a recovery property servicing
agreement, DRC charges are collected by the Utility and remitted to PERF for payment of principal, interest, and miscellaneous
expenses associated with the bonds.
The first series of ERBs issued on February 10, 2005 included five classes aggregating to a $1.9 billion principal amount with
scheduled maturities ranging from September 25, 2006 to December 25, 2012. Interest rates on the remaining two outstanding classes
are 4.37% for the earlier maturing class and 4.47% for the later maturing class. The proceeds of the first series of ERBs were paid by
PERF to the Utility and were used by the Utility to refinance the remaining unamortized after-tax balance of the settlement regulatory
asset. The second series of ERBs, issued on November 9, 2005, included three classes aggregating to an $844 million principal
amount, with scheduled maturities ranging from June 25, 2009 to December 25, 2012. Interest rates on the remaining two classes are
5.03% for the earlier maturing class and 5.12% for the later maturing class. The proceeds of the second series of ERBs were paid by
PERF to the Utility to pre-fund the Utility’s tax liability that will be due as the Utility collects the DRC charges from customers.
The total amount of ERB principal outstanding was $827 million at December 31, 2010 and $1.2 billion at December 31,
2009. The scheduled principal repayments for ERBs are reflected in the table below:
FERC FORM NO. 1 (ED. 12-88) Page 123.17

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(in millions) 2011 2012 Total
Utility
Average fixed interest rate 4.59% 4.66% 4.63%
Energy recovery bonds $ 404 $ 423 $ 827
While PERF is a wholly owned consolidated subsidiary of the Utility, it is legally separate from the Utility. The assets
(including the recovery property) of PERF are not available to creditors of the Utility or PG&E Corporation, and the recovery property
is not legally an asset of the Utility or PG&E Corporation.
NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION
PG&E Corporation
Of the 395,227,205 shares of PG&E Corporation common stock outstanding at December 31, 2010, 475,880 shares were
granted as restricted stock under the PG&E Corporation Long-Term Incentive Program and the 2006 Long-Term Incentive Plan
(“2006 LTIP”) and 5,105,505 shares were issued for the accounts of participants in PG&E Corporation’s 401(k) plan and Dividend
Reinvestment and Stock Purchase Plan (“DRSPP”). In addition, between June 23 and June 29, 2010, PG&E Corporation issued
16,370,779 shares of common stock upon conversion of the $247 million principal amount of Convertible Subordinated Notes. (See
Note 4 above.)
On November 4, 2010, PG&E Corporation entered into an Equity Distribution Agreement pursuant to which PG&E
Corporation's sales agents may offer and sell, from time to time, PG&E Corporation common stock having an aggregate gross offering
price of up to $400 million. Sales of the shares are made by means of ordinary brokers’ transactions on the New York Stock
Exchange, or in such other transactions as agreed upon by PG&E Corporation and the sales agents and in conformance with applicable
securities laws. As of December 31, 2010, PG&E Corporation had issued 2,357,796 shares of its common stock pursuant to the Equity
Distribution Agreement for cash proceeds of $110 million, net of fees and commissions paid of $1 million.
Utility
Dividends
As of December 31, 2010, PG&E Corporation held all of the Utility’s outstanding common stock.
The Boards of Directors of PG&E Corporation and the Utility have each adopted a dividend policy. Under the Utility’s
Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s
preferred stock have been paid.
PG&E Corporation and the Utility each have revolving credit facilities that require the company to maintain a ratio of
consolidated total debt to consolidated capitalization of at most 65%. This covenant, along with the CPUC’s requirement for the
Utility to maintain the 52% equity component of its capital structure, are considered to be restrictions on the payment of dividends.
Based on the calculation of these ratios for each company, no amount of PG&E Corporation’s retained earnings and $5.3 billion of the
Utility’s retained earnings were restricted at December 31, 2010.
In addition, the Utility was required to maintain at least $9.7 billion of its net assets as equity in order to maintain the capital
structure of at least 52% equity at December 31, 2010. As a result, $9.7 billion of the Utility’s net assets are restricted and may not be
transferred to PG&E Corporation in the form of cash dividends.
The Boards of Directors of PG&E Corporation and the Utility declare dividends quarterly. On December 15, 2010, the
Board of Directors of PG&E Corporation declared a quarterly dividend of $0.455 per share, totaling $183 million, which was paid on
January 15, 2011 to shareholders of record on December 31, 2010.
Long-Term Incentive Plan
FERC FORM NO. 1 (ED. 12-88) Page 123.18

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The 2006 LTIP permits the award of various forms of incentive awards, including stock options, stock appreciation rights,
restricted stock awards, restricted stock units, performance shares, deferred compensation awards, and other stock-based awards, to
eligible employees of PG&E Corporation and its subsidiaries. Non-employee directors of PG&E Corporation are also eligible to
receive restricted stock and either stock options or restricted stock units under the formula grant provisions of the 2006 LTIP. A
maximum of 12 million shares of PG&E Corporation common stock (subject to adjustment for changes in capital structure, stock
dividends, or other similar events) has been reserved for issuance under the 2006 LTIP, of which 7,856,348 shares were available for
award at December 31, 2010.
Awards made under the PG&E Corporation LTIP before December 31, 2005 and still outstanding continue to be governed by
the terms and conditions of the PG&E Corporation LTIP.
PG&E Corporation and the Utility use an estimated annual forfeiture rate of 2.5% for stock options and restricted stock and
2% for performance shares, based on historic forfeiture rates, for purposes of determining compensation expense for share-based
incentive awards. The following table provides a summary of total compensation expense for PG&E Corporation and the Utility for
share-based incentive awards for 2010, 2009, and 2008:
(in millions) 2010 2009 2008
Stock Options $ - $ - $ 2
Restricted Stock 14 9 22
Restricted Stock Units 9 11 -
Performance Shares:
Liability Awards 22 37 33
Equity Awards 11 - -
Total Compensation Expense (pre-tax) $ 56 $ 57 $ 57
Total Compensation Expense (after-tax) $ 33 $ 34 $ 34
There were no significant stock-based compensation costs capitalized during 2010, 2009 and 2008. There was no material
difference between PG&E Corporation and the Utility for the information disclosed above.
Stock Options
The exercise price of stock options granted under the 2006 LTIP and all other outstanding stock options is equal to the market
price of PG&E Corporation’s common stock on the date of grant. Stock options generally have a 10-year term and vest over four
years of continuous service, subject to accelerated vesting in certain circumstances.
The following table summarizes total intrinsic value (fair market value of PG&E Corporation’s common stock less exercise
price) of options exercised:
PG&E Corporation
(in millions) 2010 2009 2008
Intrinsic value of options exercised $ 15 $ 18 $ 13
The tax benefit from stock options exercised totaled $0.5 million, $6 million, and $4 million for 2010, 2009, and 2008
respectively.
The following table summarizes stock option activity for 2010:
FERC FORM NO. 1 (ED. 12-88) Page 123.19
Weighted
Average
Remaining

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Weighted Average Contractual Aggregate
Options Shares Exercise Price Term Intrinsic Value
Outstanding at January 1 1,975,341 $ 23.99
Granted 1,742 42.97
Exercised (605,585) 22.67
Forfeited or expired (1,587) 30.13
Outstanding at December 31 1,369,911 25.16 2.76 $ 31,068,628
Expected to vest at December 31 21,401 37.77 7.89 $ 215,584
Exercisable at December 31 1,348,510 $ 24.96 2.68 $ 30,853,045
As of December 31, 2010, there was less than $1 million of total unrecognized compensation cost related to outstanding
stock options.
Restricted Stock
During 2010, PG&E Corporation awarded 10,540 shares of restricted common stock to eligible participants under the 2006
LTIP. The terms of the restricted stock award agreements provide that the shares will vest over a five year period. Although the
recipients of restricted stock possess voting rights, they may not sell or transfer their shares until the shares vest.
Prior to 2010, PG&E Corporation also awarded restricted stock to eligible employees under the 2006 LTIP. The terms of
these restricted stock award agreements provide that 60% of the shares will vest over a period of three years at the rate of 20% per
year. If PG&E Corporation’s annual total shareholder return (“TSR”) is in the top quartile of its comparator group, as measured for
the three immediately preceding calendar years, the restrictions on the remaining 40% of the shares will lapse in the third year. If
PG&E Corporation’s TSR is not in the top quartile for that period, then the restrictions on the remaining 40% of the shares will lapse
in the fifth year. Compensation expense related to the portion of the restricted stock award that is subject to conditions based on TSR
is recognized over the shorter of the requisite service period and three years. Dividends declared on restricted stock are paid to
recipients only when the restricted stock vests.
The weighted average grant-date fair value per-share of restricted stock granted during 2010, 2009, and 2008 was $42.97,
$35.53, and $37.91, respectively. The total fair value of restricted stock that vested during 2010, 2009, and 2008 was $8 million, $24
million, and $19 million, respectively. The tax benefit from restricted stock that vested during 2010, 2009, and 2008 was not material.
The following table summarizes restricted stock activity for 2010:
Number of Shares of
Weighted Average Grant-
Restricted Stock
Date Fair Value
Nonvested at January 1 670,552 $ 41.11
Granted 10,540 $ 42.97
Vested (189,976) $ 41.70
Forfeited (15,236) $ 42.52
Nonvested at December 31 475,880 $ 40.87
As of December 31, 2010, there was less than $1 million of total unrecognized compensation cost relating to restricted stock.
Restricted Stock Units
Beginning January 1, 2009, PG&E Corporation primarily awarded restricted stock units (“RSU”) instead of restricted stock as
permitted by the 2006 LTIP. RSUs are hypothetical shares of stock that will generally vest in 20% increments on the first business day
of March in year one, two, and three, with the remaining 40% vesting on the first business day of March in year four. Each vested
RSU is settled for one share of PG&E Corporation common stock. Additionally, upon settlement, RSU recipients receive payment for
FERC FORM NO. 1 (ED. 12-88) Page 123.20

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
the amount of dividend equivalents associated with the vested RSUs that have accrued since the date of grant.
The weighted average grant-date fair value per RSU granted during 2010 and 2009 was $42.97 and $35.53, respectively. The
total fair value of RSUs that vested during 2010 and 2009 was $5 million and less than $1 million, respectively. As of December 31,
2010, $21 million of total unrecognized compensation costs related to nonvested RSUs are expected to be recognized over the
remaining weighted average period of 2.70 years.
The following table summarizes RSU activity for 2010:
Number of
Weighted Average Grant-
Restricted Stock Units
Date Fair Value
Nonvested at January 1 664,992 $ 35.78
Granted 640,060 $ 42.97
Vested (125,651) $ 35.60
Forfeited (25,005) $ 37.61
Nonvested at December 31 1,154,396 $ 39.74
Performance Shares
On March 10, 2010, PG&E Corporation granted 605,275 contingent performance shares to eligible employees under the 2006
LTIP. Unlike performance shares awarded in prior periods (see below), which settle in cash, 2010 grants will be settled in PG&E
Corporation common stock and are classified as share-based equity awards. Performance shares granted and outstanding prior to 2010
will not be modified and will continue to be paid and settled in cash. The vesting of the performance shares granted in 2010 is
dependent upon three years of continuous service. Additionally the amount of common stock that recipients are entitled to receive, if
any, will be determined based on PG&E Corporation’s TSR relative to the performance of a specified group of peer companies for the
applicable three year performance period. Total compensation expense for these shares is based on the grant-date fair value, which is
determined using a Monte Carlo simulation valuation model. Performance share expense is recognized ratably over the requisite
service period based on the fair values determined, except for the expense attributable to awards granted to retirement-eligible
participants, which is recognized on the date of grant. Dividend equivalents on equity-classified awards, if any, will be paid in cash
upon vesting date based on the amount of common stock awarded.
For performance shares classified as equity awards, the following table summarizes activity for 2010:
Number of
Weighted Average Grant-
Performance Shares
Date Fair Value
Nonvested at January 1 -
Granted 616,990 $ 35.60
Vested -
Forfeited (7,020) $ 35.60
Nonvested at December 31 609,970 $ 35.60
As of December 31, 2010, $10 million of total unrecognized compensation costs related to nonvested performance shares are
expected to be recognized over the remaining weighted-average period of 1.22 years.
Prior to 2010, PG&E Corporation awarded performance shares to eligible participants under the 2006 LTIP as hypothetical
shares of common stock that vest at the end of a three-year period and are settled in cash based on the performance of PG&E
Corporation’s TSR. Upon vesting, the amount of cash that recipients are entitled to receive, if any, is determined by multiplying the
number of vested performance shares by the average closing price of PG&E Corporation common stock for the last 30 calendar days in
the three-year performance period. This result is then adjusted based on PG&E Corporation’s TSR relative to the performance of a
specified group of peer companies for the applicable three-year performance period. These outstanding performance shares are
classified as a liability because the performance shares can only be settled in cash. During each reporting period compensation
FERC FORM NO. 1 (ED. 12-88) Page 123.21

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
expense recognized for performance shares will fluctuate based on PG&E Corporation’s common stock price and its TSR relative to its
comparator group. As of December 31, 2010 and 2009, $68 million and $63 million, respectively, had been accrued as the
performance share liability for PG&E Corporation.
For performance shares classified as liability awards, the following table summarizes activity for 2010:
Number of
Weighted Average Fair
Performance Shares
Value
Nonvested at January 1 1,547,598 $ 55.98
Granted -
Vested (387,019) $ 43.06
Forfeited (23,089) $ 56.18
Nonvested at December 31 1,137,490 $ 60.37
For performance shares classified as liability awards, the total intrinsic value of amounts settled during 2010, 2009, and 2008
was $17 million, $21 million, and $7 million, respectively.
NOTE 7: PREFERRED STOCK
PG&E Corporation
PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value
preferred stock, which may be issued as redeemable or nonredeemable preferred stock. No preferred stock of PG&E Corporation has
been issued to date.
Utility
The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value
preferred stock. The Utility specifies that 5,784,825 shares of the $25 par value preferred stock authorized are designated as
nonredeemable preferred stock without mandatory redemption provisions. All remaining shares of preferred stock may be issued as
redeemable or nonredeemable preferred stock.
The following table summarizes the Utility’s outstanding preferred stock without mandatory redemption provisions at
December 31, 2010 and 2009:
(in millions, except share amounts, redemption
price, and par value) Shares Outstanding Redemption Price Balance
Nonredeemable $25 par value preferred stock
5.00% Series 400,000 N/A $ 10
5.50% Series 1,173,163 N/A 30
6.00% Series 4,211,662 N/A 105
Total nonredeemable preferred stock 5,784,825 $ 145
Redeemable $25 par value preferred stock
4.36% Series 418,291 $ 25.75 $ 11
4.50% Series 611,142 26.00 15
4.80% Series 793,031 27.25 20
5.00% Series 1,778,172 26.75 44
5.00% Series A 934,322 26.75 23
Total redeemable preferred stock 4,534,958 $ 113
FERC FORM NO. 1 (ED. 12-88) Page 123.22

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Preferred stock $ 258
Holders of the Utility’s nonredeemable preferred stock have rights to annual dividends ranging from $1.25 to $1.50 per share.
The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the
specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2010, annual
dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.
Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal
preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be
entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. During each of
2010, 2009, and 2008, the Utility paid $14 million of dividends on preferred stock. On December 15, 2010, the Board of Directors of
the Utility declared a cash dividend on its outstanding series of preferred stock totaling $4 million that was paid on February 15, 2011
to preferred shareholders of record on January 31, 2011. On February 16, 2011, the Board of Directors of the Utility declared a cash
dividend on its outstanding series of preferred stock, payable on May 15, 2011, to shareholders of record on April 29, 2011.
NOTE 8: EARNINGS PER SHARE
PG&E Corporation’s earnings per common share (“EPS”) is calculated utilizing the “two-class” method by dividing the sum
of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders by the weighted average
number of common shares outstanding during the period. In applying the two-class method, undistributed earnings are allocated to
both common shares and participating securities. PG&E Corporation’s Convertible Subordinated Notes met the criteria of
participating securities as the holders were entitled to receive dividends similar to holders of common stock.
As of June 29, 2010, all of PG&E Corporation’s Convertible Subordinated Notes had been converted into common stock.
Therefore, there were no participating securities outstanding at December 31, 2010. (See Note 4 above.)
The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average
shares of common stock outstanding for calculating basic EPS:
Year Ended December 31,
(in millions, except per share amounts) 2010 2009 2008
Basic
Income available for common shareholders $ 1,099 $ 1,220 $ 1,338
Less: distributed earnings to common shareholders 706 621 560
Undistributed earnings 393 599 778
Less: undistributed earnings from discontinued operations - - 154
Undistributed earnings from continuing operations $ 393 $ 599 $ 624
Allocation of undistributed earnings to common
shareholders
Distributed earnings to common shareholders $ 706 $ 621 $ 560
Undistributed earnings allocated to common shareholders –
continuing operations 385 573 592
Undistributed earnings allocated to common shareholders –
discontinued operations - - 146
Total common shareholders earnings $ 1,091 $ 1,194 $ 1,298
Weighted average common shares outstanding, basic 382 368 357
Convertible subordinated notes 8 17 19
Weighted average common shares outstanding and
participating securities 390 385 376
Net earnings per common share, basic
FERC FORM NO. 1 (ED. 12-88) Page 123.23

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Distributed earnings, basic (1) $ 1.85 $ 1.69 $ 1.57
Undistributed earnings – continuing operations, basic 1.01 1.56 1.66
Undistributed earnings – discontinued operations, basic - - 0.41
Total $ 2.86 $ 3.25 $ 3.64
(1) Distributed earnings, basic may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted
average, rather than the actual, number of shares outstanding.
In calculating diluted EPS during the period PG&E Corporation’s Convertible Subordinated Notes were outstanding, PG&E
Corporation applied the “if-converted” method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the
impact is dilutive when compared to basic EPS. In addition, PG&E Corporation applies the treasury stock method of reflecting the
dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.
The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average
shares of common stock outstanding for calculating diluted EPS:
Year ended
December 31,
(in millions, except per share amounts) 2010 2009
Diluted
Income available for common shareholders $ 1,099 $ 1,220
Add earnings impact of assumed conversion of participating securities:
Interest expense on convertible subordinated notes, net of tax 8 15
Unrealized loss on embedded derivative, net of tax - 2
Income available for common shareholders and assumed conversion $ 1,107 $ 1,237
Weighted average common shares outstanding, basic 382 368
Add incremental shares from assumed conversions:
Convertible subordinated notes 8 17
Employee share-based compensation 2 1
Weighted average common shares outstanding, diluted 392 386
Total earnings per common share, diluted $ 2.82 $ 3.20
The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average
shares of common stock outstanding for calculating diluted EPS:
Year ended
December 31,
(in millions, except per share amounts) 2008
Diluted
Income available for common shareholders $ 1,338
Less: distributed earnings to common shareholders 560
Undistributed earnings 778
Less: undistributed earnings from discontinued operations 154
Undistributed earnings from continuing operations $ 624
Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders $ 560
Undistributed earnings allocated to common shareholders –
continuing operations 593
FERC FORM NO. 1 (ED. 12-88) Page 123.24

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Undistributed earnings allocated to common shareholders –
discontinued operations 146
Total common shareholders earnings $ 1,299
Weighted average common shares outstanding, basic 357
Convertible subordinated notes 19
Weighted average common shares outstanding and participating
securities, basic 376
Weighted average common shares outstanding, basic 357
Employee share-based compensation 1
Weighted average common shares outstanding, diluted 358
Convertible subordinated notes 19
Weighted average common shares outstanding and participating
securities, diluted 377
Net earnings per common share, diluted
Distributed earnings, diluted $ 1.56
Undistributed earnings – continuing operations, diluted 1.66
Undistributed earnings – discontinued operations, diluted 0.41
Total earnings per common share, diluted $ 3.63
For each of the periods presented above, the calculation of outstanding shares on a diluted basis excluded an insignificant
amount of options and securities that were antidilutive.
NOTE 9: INCOME TAXES
The significant components of income tax provision (benefit) for continuing operations were as follows:
PG&E Corporation
Utility
Year Ended December 31,
2010 2009 2008 2010 2009 2008
(in millions)
Current:
Federal $ (12) $ (747) $ (268) $ (54) $ (696) $ (188)
State 130 (41) 33 134 (45) 24
Deferred:
Federal 525 1,161 604 589 1,139 596
State (91) 92 62 (90) 89 62
Tax credits (5) (5) (6) (5) (5) (6)
Income tax provision $ 547 $ 460 $ 425 $ 574 $ 482 $ 488
The following describes net deferred income tax liabilities:
PG&E Corporation
Utility
Year Ended December 31,
2010 2009 2010 2009
(in millions)
Deferred income tax assets:
Reserve for damages $ 222 $ 138 $ 222 $ 138
Environmental reserve 242 227 242 227
Compensation 345 338 305 304
FERC FORM NO. 1 (ED. 12-88) Page 123.25

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Net operating loss carry forward 327 - 270 -
Other 207 184 178 180
Total deferred income tax assets $ 1,343 $ 887 $ 1,217 $ 849
Deferred income tax liabilities:
Regulatory balancing accounts $ 1,116 $ 1,340 $ 1,116 $ 1,340
Property related basis differences 5,236 4,036 5,234 4,032
Income tax regulatory asset 509 418 509 418
Other 142 157 135 157
Total deferred income tax liabilities $ 7,003 $ 5,951 $ 6,994 $ 5,947
Total net deferred income tax liabilities $ 5,660 $ 5,064 $ 5,777 $ 5,098
Classification of net deferred income tax liabilities:
Included in current liabilities $ 113 $ 332 $ 118 $ 334
Included in noncurrent liabilities 5,547 4,732 5,659 4,764
Total net deferred income tax liabilities $ 5,660 $ 5,064 $ 5,777 $ 5,098
The differences between income taxes and amounts calculated by applying the federal statutory rate to income before income
tax expense for continuing operations were as follows:
PG&E Corporation
Utility
Year Ended December 31,
2010 2009 2008 2010 2009 2008
Federal statutory income tax rate 35.0 % 35.0 % 35.0 % 35.0 % 35.0 % 35.0 %
Increase (decrease) in income
tax rate resulting from:
State income tax (net of
federal benefit) 0.7 1.6 3.1 1.0 1.4 3.3
Effect of regulatory treatment
of fixed asset differences (3.1) (2.7) (3.2) (3.0) (2.6) (3.1)
Tax credits (0.4) (0.5) (0.5) (0.4) (0.5) (0.5)
IRS audit settlements 0.1 (4.5) (7.1) (0.2) (4.2) (4.1)
Other, net 0.9 (1.5) (0.9) 1.5 (1.3) (1.7)
Effective tax rate 33.2 % 27.4 % 26.4 % 33.9 % 27.8 % 28.9 %
Unrecognized tax benefits
The following table reconciles the changes in unrecognized tax benefits:
PG&E Corporation
Utility
2010 2009 2008 2010 2009 2008
(in millions)
Balance at beginning of year $ 673 $ 75 $ 209 $ 652 $ 37 $ 94
Additions for tax position
taken during a prior year 27 4 - 27 4 -
Additions for tax position
taken during the current year 89 624 43 87 623 20
Settlements (55) (27) (177) (54) (12) (77)
Reductions for tax position
taken during a prior year (20) (3) - - - -
FERC FORM NO. 1 (ED. 12-88) Page 123.26

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Balance at end of year $ 714 $ 673 $ 75 $ 712 $ 652 $ 37
The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2010 for
PG&E Corporation and the Utility is $39 million, with the remaining balance representing the probable deferral of taxes to later years.
PG&E Corporation and the Utility do not expect that the total unrecognized tax benefits would significantly change within the next 12
months.
PG&E Corporation and the Utility recognize accrued interest and penalties related to unrecognized tax benefits as income tax
expense in the Consolidated Statements of Income. Interest income net of penalties recognized in income tax expense by PG&E
Corporation in 2010, 2009, and 2008 was $3 million, $19 million, and $24 million, respectively. Interest income net of penalties
recognized in income tax expense by the Utility in 2010, 2009, and 2008 was $3 million, $14 million, and $11 million, respectively.
As of December 31, 2010, PG&E Corporation and the Utility had accrued interest income of $8 million. As of December 31,
2009, PG&E Corporation and the Utility had accrued interest expense and penalties of $11 million and $12 million, respectively.
Federal subsidy for Medicare Part D
PG&E Corporation and the Utility receive a federal subsidy for maintaining a retiree medical benefit plan with prescription
drug benefits that is actuarially equivalent to Medicare Part D. For federal income tax purposes, the subsidy was deductible when
contributed to the benefit plan maintained for these benefits. On March 30, 2010, federal healthcare legislation was signed eliminating
the deduction for subsidy contributions after 2012. As a result, PG&E Corporation and the Utility recognized an expense of $19
million in 2010 to reverse previously recognized federal tax benefits (recorded as an increase to income tax provision and a reduction
to deferred income tax assets for subsidy amounts included in the calculation of accrued retiree medical benefit obligation).
Tax settlements and years that remain subject to examination
On September 29, 2010, PG&E Corporation received the Internal Revenue Service (“IRS”) examination report for the 2005
to 2007 audit years and resolved all matters except for a few items that will be discussed with the IRS Appeals office. Included in the
2005 to 2007 audit was the resolution of the change in accounting method related to the capitalization of indirect service costs for
those years. As a result, PG&E Corporation recorded a $25 million reduction to income tax expense during 2010.
In tax year 2008, PG&E Corporation began participating in the Compliance Assurance Process (“CAP”), a real-time IRS
audit intended to expedite resolution of tax matters. The CAP audit culminates with a letter from the IRS indicating their acceptance of
the return. The IRS partially accepted the 2008 return, withholding two issues for further review. The most significant of these relates
to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. While the IRS
approved PG&E Corporation’s request for a change in method, the IRS will audit the methodology to determine the proper deduction.
This audit has not progressed significantly because the IRS is working with the utility industry to resolve this matter in a consistent
manner for all utilities before auditing individual companies. On December 14, 2010 the IRS accepted PG&E Corporation’s 2009 tax
return without change.
In 2009, PG&E Corporation recognized an income tax benefit of $56 million from settling a claim with the IRS related to
1998 and 1999. Additionally during 2009, PG&E Corporation recognized $12 million in California benefits, of which $10 million was
attributable to this settlement and $2 million was attributable to the 2001–2004 IRS settlement. (The 2001–2004 IRS settlement
resulted in a $154 million tax benefit related to National Energy & Gas Transmission, Inc. (“NEGT”) and was recorded as
discontinued operations in 2008.) PG&E Corporation received total cash refunds of $605 million in 2009 related to these settlements.
The California Franchise Tax Board is auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns,
as well as the 1997-2007 amended income tax returns reflecting IRS settlements for these years and claim filings that apply only to
California. It is uncertain when the California Franchise Tax Board will complete the audits.
PG&E Corporation believes that the final resolution of the federal and California audits will not have a material adverse
impact on its financial condition or results of operations. PG&E Corporation is neither under audit nor subject to any material risk in
FERC FORM NO. 1 (ED. 12-88) Page 123.27

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
any other jurisdiction.
Loss carry forwards
As of December 31, 2010 and 2009, PG&E Corporation has $24 million and $25 million, respectively, of federal and
California capital loss carry forwards based on filed tax returns, of which approximately $9 million will expire if not used by
December 31, 2011. For all periods presented, PG&E Corporation has provided a full valuation allowance against its deferred income
tax assets for capital loss carry forwards.
The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (the “Tax Relief Act”) Federal
legislation that was signed into law on December 17, 2010, provides for full expensing of qualified property, plant, and equipment
placed in service from September 9, 2010 to December 31, 2011 for tax purposes. The Tax Relief Act increased PG&E Corporation’s
federal net operating loss carry forwards. As of December 31, 2010, PG&E Corporation has approximately $540 million of federal net
operating loss carry forwards and $45 million of tax credit carry forwards, which will expire between 2029 and 2030. In addition,
PG&E Corporation has approximately $46 million of loss carry forwards related to charitable contributions, which will expire between
2014 and 2015. PG&E Corporation believes it is more likely than not the tax benefits associated with the federal operating loss and
tax credit can be realized within the carry forward periods, therefore no valuation allowance was recognized as of December 31, 2010.
The amount of federal net operating loss carry forwards for which a tax benefit from employee stock plans would be recorded in
additional paid-in capital was approximately $9 million as of December 31, 2010.
NOTE 10: DERIVATIVES AND HEDGING ACTIVITIES
Use of Derivative Instruments
The Utility faces market risk primarily related to electricity and natural gas commodity prices. All of the Utility’s risk
management activities involving derivatives reduce the volatility of commodity costs on behalf of its customers. The CPUC allows the
Utility to charge customer rates designed to recover the Utility’s reasonable costs of providing services, including the cost to obtain
and deliver electricity and natural gas.
The Utility uses both derivative and non-derivative contracts in managing its customers’ exposure to commodity-related price
risk, including:
• forward ? contracts that commit the Utility to purchase a commodity in the future;
• swap agreements that require payments to or from counterparties based upon the difference between two prices for a
predetermined contractual quantity;
• option ? contracts that provide the Utility with the right to buy a commodity at a predetermined price; and
• futures ? contracts that are exchange-traded contracts committing the Utility to make a cash settlement at a specified price and
future date.
These instruments are not held for speculative purposes and are subject to certain regulatory requirements.
Commodity-Related Price Risk
Commodity-related price risk management activities that meet the definition of a derivative are recorded at fair value on the
Consolidated Balance Sheets. As long as the ratemaking mechanisms discussed above remain in place and the Utility’s risk
management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover from customers, in rates,
all costs related to commodity-related price risk-related derivative instruments. Therefore, all unrealized gains and losses associated
with the change in fair value of these derivative instruments are deferred and recorded within the Utility’s regulatory assets and
liabilities on the Consolidated Balance Sheets. (See Note 3 above.) Net realized gains or losses on derivative instruments related to
FERC FORM NO. 1 (ED. 12-88) Page 123.28

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
price risk for commodities are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to
regulatory balancing accounts for recovery from customers.
The Utility elects the normal purchase and sale exception for qualifying commodity-related derivative instruments.
Derivative instruments that require physical delivery, are probable of physical delivery in quantities that are expected to be used by the
Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity
delivered are eligible for the normal purchase and sale exception. The fair value of instruments that are eligible for the normal
purchase and sales exception are not reflected in the Consolidated Balance Sheets.
The following is a discussion of the Utility’s use of derivative instruments intended to mitigate commodity-related price risk
for its customers.
Electricity Procurement
The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts
allocated under DWR contracts, and its own electricity generation facilities. The amount of electricity the Utility needs to meet the
demands of customers and that is not satisfied from the Utility’s own generation facilities, existing purchase contracts, or DWR
contracts allocated to the Utility’s customers is subject to change for a number of reasons, including:
• periodic ? expirations or terminations of existing electricity purchase contracts, including the DWR’s contracts;
• the execution of new electricity purchase contracts;
• fluctuation ? in the output of hydroelectric and other renewable power facilities owned or under contract;
• changes ? in the Utility’s customers’ electricity demands due to customer and economic growth or decline, weather, implementation
of new energy efficiency and demand response programs, direct access, and community choice aggregation;
• the ? acquisition, retirement, or closure of generation facilities; and
• changes ? in market prices that make it more economical to purchase power in the market rather than use the Utility’s existing or
contracted resources to generate power.
The Utility enters into third-party power purchase agreements to ensure sufficient electricity to meet customer needs. The
Utility’s third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase
agreements are considered derivative instruments. The Utility elects to use the normal purchase and sale exception for eligible
derivative instruments.
A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce the
volatility in customer rates, the Utility has entered into financial swap contracts to effectively fix the price of future purchases and
reduce the cash flow variability associated with fluctuating electricity prices under some of those power purchase agreements. These
financial swaps are considered derivative instruments.
Electric Transmission Congestion Revenue Rights
The California Independent System Operator (“CAISO”) controlled electricity transmission grid used by the Utility to
transmit power is subject to transmission constraints. As a result, the Utility is subject to financial risk associated with the cost of
transmission congestion. The congestion revenue rights (“CRRs”) allow market participants, including load-serving entities, to hedge
the financial risk of CAISO-imposed congestion charges in the new day-ahead market. The CAISO releases CRRs through an annual
and monthly process, each of which includes an allocation phase (in which load-serving entities are allocated CRRs at no cost based on
the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market
FERC FORM NO. 1 (ED. 12-88) Page 123.29

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
participants). The CRRs held by the Utility are considered derivative instruments.
Natural Gas Procurement (Electric Fuels Portfolio)
The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through the Utility-owned natural
gas generating facilities, tolling agreements, and natural gas-indexed electricity procurement contracts. In order to reduce the volatility
in customer rates, the Utility purchases financial instruments such as futures, swaps, and options to reduce future cash flow variability
associated with fluctuating natural gas prices. These financial instruments are considered derivative instruments.
Natural Gas Procurement (Core Gas Supply Portfolio)
The Utility enters into physical natural gas commodity contracts to fulfill the needs of its residential and smaller commercial
customers known as “core” customers. (The Utility does not procure natural gas for industrial and large commercial, or “non-core,”
customers.) Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes
of gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot market to balance such seasonal supply
and demand. The Utility purchases financial instruments such as swaps and options as part of its core winter hedging program in order
to manage customer exposure to high gas prices during peak winter months. These financial instruments are considered derivative
instruments.
Volume of Derivative Activity
At December 31, 2010, the volumes of PG&E Corporation’s and the Utility’s outstanding derivative contracts were as
follows:
Contract Volumes (1)
Greater Than Greater Than
1 Year But 3 Years But
Underlying Less Than 1 Less Than 3 Less Than 5 Greater Than
Product Instruments Year Years Years 5 Years (2)
Natural Gas (3)
(MMBtus (4))
Electricity
(Megawatt-hou
rs)
Forwards,
Futures, and
Swaps
427,176,587 308,712,558 - -
Options 270,509,308 176,150,000 - -
Forwards,
Futures, and 5,690,441 6,969,024 3,673,512 4,826,640
Swaps
Options 415,450 - 264,096 396,396
Congestion
Revenue Rights 74,313,524 72,070,789 71,997,921 96,986,809
(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each time period.
(2) Derivatives in this category expire between 2016 and 2022.
(3) Amounts shown are for the combined positions of the electric and core gas portfolios.
(4) Million British Thermal Units.
Presentation of Derivative Instruments in the Financial Statements
In PG&E Corporation’s and the Utility’s Consolidated Balance Sheets, derivative instruments are presented on a net basis by
counterparty where the right of offset exists under a master netting agreement. The net balances include outstanding cash collateral
associated with derivative positions.
FERC FORM NO. 1 (ED. 12-88) Page 123.30

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
At December 31, 2010, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:
Gross
Total
Derivative Cash Derivative
(in millions) Balance (1) Netting (2) Collateral (2) Balances
Commodity Risk (PG&E Corporation and the Utility)
Current assets –other $ 56 $ (45) $ 79 $ 90
Other noncurrent assets –
other 77 (62) 96 111
Current liabilities – other (388) 45 119 (224)
Noncurrent liabilities –
other (486) 62 130 (294)
Total commodity risk $ (741) $ - $ 424 $ (317)
(1) See Note 11 of the Notes to the Consolidated Financial Statements for a discussion of the valuation techniques
used to calculate the fair value of these instruments.
(2) Positions, by counterparty, are netted where the intent and legal right to offset exist in accordance with master
netting agreements.
At December 31, 2009, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:
Gross
Total
Derivative Cash Derivative
(in millions) Balance (1) Netting (2) Collateral (2) Balances
Commodity Risk (PG&E Corporation and the Utility)
Current assets –other $ 76 $ (12) $ 77 $ 141
Other noncurrent assets –
other 64 (44) 13 33
Current liabilities – other (231) 12 54 (165)
Noncurrent liabilities –
other (390) 44 44 (302)
Total commodity risk $ (481) $ - $ 188 $ (293)
Other Risk Instruments (3) (PG&E Corporation Only)
Current liabilities – other $ (13) $ - $ - $ (13)
Total derivatives $ (494) $ - $ 188 $ (306)
(1) See Note 11 of the Notes to the Consolidated Financial Statements for a discussion of the valuation techniques
used to calculate the fair value of these instruments.
(2) Positions, by counterparty, are netted where the intent and legal right to offset exist in accordance with master
netting agreements.
(3) This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated
Notes, which were converted to PG&E Corporation common stock in 2010.
For the years ended December 31, 2010 and 2009, the gains and losses recorded on PG&E Corporation’s and the Utility’s
derivative instruments were as follows:
Commodity Risk
(PG&E Corporation and the
Utility)
(in millions) 2010 2009
FERC FORM NO. 1 (ED. 12-88) Page 123.31

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Unrealized gain/(loss) – Regulatory assets and
liabilities (1)
$ (260) $ 15
Realized gain/(loss) – Cost of electricity (2) (573) (701)
Realized gain/(loss) – Cost of natural gas (2) (79) (54)
Total commodity risk instruments $ (912) $ (740)
(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory
assets or liabilities rather than being recorded to the Consolidated Statements of Income. These amounts
exclude the impact of cash collateral postings.
(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted
by realized amounts on these instruments.
Cash inflows and outflows associated with the settlement of all derivative instruments are included in operating cash flows on
PG&E Corporation’s and the Utility’s Consolidated Statements of Cash Flows.
The majority of the Utility’s commodity risk-related derivative instruments contain collateral posting provisions tied to the
Utility’s credit rating from each of the major credit rating agencies. If the Utility’s credit rating were to fall below investment grade,
the Utility would be required to immediately post additional cash to fully collateralize its net liability derivative positions.
At December 31, 2010, the additional cash collateral that the Utility would be required to post if its credit risk-related
contingency features were triggered was as follows:
(in millions)
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized $ (518)
Related derivatives in an asset position -
Collateral posting in the normal course of business related
to these derivatives 7
Net position of derivative contracts/additional collateral
posting requirements (1) $ (511)
(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is
not impacted by any of the Utility’s credit risk-related contingencies.
NOTE 11: FAIR VALUE MEASUREMENTS
PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair
value. Fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based
on assumptions that market participants would use in pricing an asset or a liability. A three-tier fair value hierarchy is established as a
basis for considering such assumptions and for inputs used in the valuation methodologies in measuring fair value:
Level 1—Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2—Include other inputs that are directly or indirectly observable in the marketplace.
Level 3—Unobservable inputs which are supported by little or no market activities.
The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable
inputs when measuring fair value.
Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below
(money market investments and assets held in rabbi trusts are held by PG&E Corporation and not the Utility):
FERC FORM NO. 1 (ED. 12-88) Page 123.32

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Fair Value Measurements at December 31, 2010
(in millions) Level 1 Level 2 Level 3 Total
Assets:
Money market investments $ 138 $ - $ - $ 138
Nuclear decommissioning trusts
U.S. equity securities (1) 1,029 7 - 1,036
Non-U.S. equity securities 349 - - 349
U.S. government and agency securities 584 40 - 624
Municipal securities - 119 - 119
Other fixed income securities - 66 - 66
Total nuclear decommissioning trusts (2) 1,962 232 - 2,194
Price risk management instruments (Note 10)
Electric (3) 130 - - 130
Gas (4) 3 - - 3
Total price risk management instruments 133 - - 133
Rabbi trusts
Fixed Income securities - 24 - 24
Life insurance contracts - 65 - 65
Total rabbi trusts - 89 - 89
Long-term disability trust
U.S. equity securities (1) 11 24 - 35
Corporate debt securities (1) - 150 - 150
Total long-term disability trust 11 174 - 185
Total assets $ 2,244 $ 495 $ - $ 2,739
Liabilities:
Price risk management instruments (Note 10)
Electric (5) $ - $ 5 $ 403 $ 408
Gas (6) - 1 41 42
Total price risk management instruments
- 6 444 450
Total liabilities $ - $ 6 $ 444 $ 450
(1) Level 2 balances include commingled funds, which are comprised primarily of securities traded publicly on exchanges. Price quotes for the assets held by
the funds are readily observable and available.
(2) Excludes $185 million primarily related to deferred taxes on appreciation of investment value.
(3) Balances include the impact of netting adjustments of $359 million to Level 1. Includes natural gas for electric portfolio.
(4) Balances include the impact of netting adjustments of $44 million to Level 1. Includes natural gas for core customers.
(5) Balances include the impact of netting adjustments of $66 million to Level 2 and $(48) million to Level 3. Includes natural gas for electric portfolio.
(6) Balances include the impact of netting adjustments of $3 million to Level 3. Includes natural gas for core customers.
Fair Value Measurements at December 31, 2009
(in millions) Level 1 Level 2 Level 3 Total
Assets:
Money market investments $ 189 $ - $ 4 $ 193
Nuclear decommissioning trusts
FERC FORM NO. 1 (ED. 12-88) Page 123.33

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
U.S. equity securities (1) 762 6 - 768
Non-U.S. equity securities 344 - - 344
U.S. government and agency securities 653 51 - 704
Municipal securities 1 89 - 90
Other fixed income securities - 108 - 108
Total nuclear decommissioning trusts (2) 1,760 254 - 2,014
Rabbi trusts
Equity securities 21 - - 21
Life insurance contracts 60 - - 60
Total rabbi trusts 81 - - 81
Long-term disability trust
U.S. equity securities (1) 52 23 - 75
Corporate debt securities (1) - 113 - 113
Total long-term disability trust 52 136 - 188
Total assets $ 2,082 $ 390 $ 4 $ 2,476
Liabilities:
Dividend participation rights (3) $ - $ - $ 12 $ 12
Price risk management instruments (Note 10)
Electric (4) 2 73 157 232
Gas (5) 1 - 60 61
Total price risk management instruments 3 73 217 293
Other liabilities - - 3 3
Total liabilities $ 3 $ 73 $ 232 $ 308
(1) Level 2 balances include commingled funds, which are comprised primarily of securities traded publicly on exchanges. Price quotes for the assets held by
the funds are readily observable and available.
(2) Excludes deferred taxes on appreciation of investment value.
(3) The dividend participation rights were associated with PG&E Corporation’s Convertible Subordinated Notes which were no longer outstanding as of
December 31, 2010.
(4) Balances include the impact of netting adjustments of $108 million to Level 1, $48 million to Level 2, and $19 million to Level 3. Includes natural gas for
electric portfolio.
(5) Balances include the impact of netting adjustments of $13 million to Level 3. Includes natural gas for core customers.
Money Market Investments
PG&E Corporation invests in money market funds that seek to maintain a stable net asset value. These funds invest in
high-quality, short-term, diversified money market instruments, such as treasury bills, federal agency securities, certificates of deposit,
and commercial paper with a maximum weighted average maturity of 60 days or less. PG&E Corporation’s investments in these
money market funds are generally valued using unadjusted quotes in an active market for identical assets and are thus classified as
Level 1 instruments. Money market funds are recorded as cash and cash equivalents in PG&E Corporation’s Consolidated Balance
Sheets.
Trust Assets
The assets held by the nuclear decommissioning trusts, the rabbi trusts related to the non-qualified deferred compensation
plans, and the long-term disability trust are comprised primarily of equity securities and debt securities. In general, investments held in
the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. It is reasonably possible that changes in
the market values of investment securities could occur in the near term, and such changes could materially affect the trusts’ fair value.
Equity securities primarily include investments in common stock and commingled funds comprised of equity across multiple
FERC FORM NO. 1 (ED. 12-88) Page 123.34

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
industry sectors in the U.S. and other regions of the world. Equity securities are generally valued based on unadjusted prices in active
markets for identical transactions and are classified as Level 1.
Debt securities are comprised primarily of fixed income securities that include U.S. government and agency securities,
municipal securities, and corporate debt securities. A market based valuation approach is generally used to estimate the fair value of
debt securities classified as Level 2 instruments in the tables above. Under a market approach, fair values are determined based on
evaluated pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the
valuation model generally include benchmark yield curves and issuer spreads. The external credit rating, coupon rate, and maturity of
each security are considered in the valuation, as applicable.
The Consolidated Balance Sheets of PG&E Corporation and the Utility contain assets held in trust for the PG&E Retirement
Plan Master Trust, the Postretirement Life Insurance Trust, and the Postretirement Medical Trusts presented on a net basis. (See Note
12 below.) The pension assets are presented net of pension obligations as noncurrent liabilities – other in PG&E Corporation’s and the
Utility’s Consolidated Balance Sheets.
Price Risk Management Instruments
Price risk management instruments include physical and financial derivative contracts, such as futures, forwards, swaps,
options, and CRRs that are either exchange-traded or over-the-counter traded. (See Note 10 above.)
Futures, forwards, and swaps are valued using observable market prices for the underlying commodity or an identical
instrument and are classified as Level 1 or Level 2 instruments. For periods where market data is not available, the Utility extrapolates
forward prices. Other futures, forwards, and swaps are considered Level 3 instruments as the determination of their fair value includes
the use of unobservable forward prices.
All energy-related options are classified as Level 3 and are valued using a standard option pricing model with various
assumptions, including forward prices for the underlying commodity, time value at a risk free rate, and volatility. For periods when
market data is not available, the Utility extrapolates these assumptions using internal models.
The Utility holds CRRs to hedge financial risk of CAISO-imposed congestion charges in the day-ahead markets. CRRs are
valued based on the forecasted settlement price at the delivery points underlying the CRR using internal models. The Utility also uses
the most current annual auction prices published by the CAISO to calibrate internal models. Limited market data is available between
auction dates; therefore, CRRs are classified as Level 3 measurements.
The Utility enters into power purchase agreements for the purchase of electricity to meet the demand of its customers. (See
Note 10 above.) The Utility uses internal models to determine the fair value of these power purchase agreements. These power
purchase agreements include contract terms that extend beyond a period for which an active market exists. The Utility utilizes market
data for the underlying commodity to the extent that it is available in determining the fair value. For periods where market data is not
available, the Utility extrapolates forward prices. These power purchase agreements are considered Level 3 instruments as the
determination of their fair value includes the use of unobservable forward prices.
Transfers between Levels
PG&E Corporation and the Utility recognize any transfers between levels in the fair value hierarchy as of the end of the
reporting period. There were no significant transfers between levels for the year ended December 31, 2010.
Level 3 Reconciliation
The following tables present reconciliations for assets and liabilities measured and recorded at fair value on a recurring basis,
using significant unobservable inputs (Level 3), for the years ended December 31, 2010 and 2009:
PG&E Corporation Only
PG&E Corporation and the Utility
FERC FORM NO. 1 (ED. 12-88) Page 123.35

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Nuclear
Decommission- Long-term Long-term
Dividend Price Risk ing Trusts Disability Disability
Money Participation Management Equity Equity Corp. Debt Other
(in millions) Market Rights Instruments Securities (1) Securities Securities Liabilities Total
Asset (liability) balance
as of December 31, 2008 $ 12 $ (42) $ (156) $ 5 $ 54 $ 24 $ (2) $ (105)
Realized and unrealized
gains (losses):
Included in earnings - 2 - - 12 3 - 17
Included in regulatory
assets and liabilities or
balancing accounts - - (61) 1 - - (1) (61)
Purchases, issuances, and
settlements (8) 28 - - (43) 86 - 63
Transfers into Level 3 - - - - - - - -
Transfers out of Level 3 - - - (6) (23) (113) - (142)
Asset (liability) balance
as of December 31, 2009 $ 4 $ (12) $ (217) $ - $ - $ - $ (3) $ (228)
Realized and unrealized
gains (losses):
Included in earnings - - - - - - - -
Included in regulatory
assets and liabilities or
balancing accounts - - (227) - - - 3 (224)
Purchases, issuances, and
settlements (4) 12 - - - - - 8
Transfers into Level 3 - - - - - - - -
Transfers out of Level 3 - - - - - - - -
Asset (liability) balance
as of December 31, 2010 $ - $ - $ (444) $ - $ - $ - $ - $ (444)
(1) Excludes deferred taxes on appreciation of investment value.
Financial Instruments
PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial
instruments:
• ?The fair values of cash, restricted cash and deposits, net accounts receivable, short-term borrowings,
accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan
agreements approximate their carrying values at December 31, 2010 and 2009.
• ?The fair values of the Utility’s fixed rate senior notes and fixed rate pollution control bond loan
agreements, PG&E Corporation’s Convertible Subordinated Notes, PG&E Corporation’s fixed rate
senior notes, and the ERBs issued by PERF were based on quoted market prices at December 31, 2010
and 2009.
The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table
below excludes financial instruments with carrying values that approximate their fair values):
FERC FORM NO. 1 (ED. 12-88) Page 123.36

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
At December 31,
2010 2009
Carrying Fair Carrying Fair
(in millions) Amount Value (2) Amount Value (2)
Debt (Note 4):
PG&E Corporation (1) $ 349 $ 383 $ 597 $ 1,096
Utility 10,444 11,314 9,240 9,824
Energy recovery bonds (Note 5) 827 862 1,213 1,269
(1) PG&E Corporation Convertible Subordinated Notes were no longer outstanding as of December 31, 2010.
(2) Fair values are determined using readily available quoted market prices.
Nuclear Decommissioning Trust Investments
The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and
dismantling the Utility’s nuclear facilities. At December 31, 2010 and 2009, the Utility had accumulated nuclear decommissioning
trust funds with an estimated fair value of $2.0 billion and $1.9 billion, respectively, net of deferred taxes on unrealized gains. In 2010
and 2009, the trusts earned $62 million and $63 million in interest and dividends, respectively. All earnings on the assets held in the
trusts, net of authorized disbursements from the trusts and investment management and administrative fees, are reinvested. Amounts
may not be released from the decommissioning trusts until authorized by the CPUC.
At December 31, 2010 and 2009, total unrealized losses on the investments held in the trusts were $6 million and $8 million,
respectively. The Utility concluded that the unrealized losses were other-than-temporary impairments and recorded a reduction to the
nuclear decommissioning trusts assets and the corresponding regulatory liability for asset retirement costs. There were no individually
material unrealized losses.
The following table provides a summary of available-for-sale investments held in the Utility’s nuclear decommissioning
trusts:
Total Total
Amortized Unrealized Unrealized Estimated (1)
Cost Gains Losses Fair Value
(in millions)
As of December 31, 2010
Equity securities
U.S. $ 509 $ 529 $ (2) $ 1,036
Non-U.S. 180 170 (1) 349
Debt securities
U.S. government and agency
securities 571 55 (2) 624
Municipal securities 119 1 (1) 119
Other fixed income securities 65 1 - 66
Total $ 1,444 $ 756 $ (6) $ 2,194
As of December 31, 2009
Equity securities
U.S. $ 344 $ 425 $ (1) $ 768
Non-U.S. 182 163 (1) 344
Debt securities
U.S. government and agency
securities 656 52 (4) 704
FERC FORM NO. 1 (ED. 12-88) Page 123.37

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Municipal securities 89 1 - 90
Other fixed income securities 108 2 (2) 108
Total $ 1,379 $ 643 $ (8) $ 2,014
(1) Excludes taxes on appreciation of investment value.
The debt securities mature on the following schedule:
As of December 31, 2010
(in millions)
Less than 1 year $ 37
1–5 years 349
5–10 years 215
More than 10 years 208
Total maturities of debt securities $ 809
The following table provides a summary of the activity for the debt and equity securities:
Year Ended December 31,
2010 2009 2008
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments $ 1,405 $ 1,351 $ 1,635
Gross realized gains on sales of securities held as available-for-sale 42 27 30
Gross realized losses on sales of securities held as available-for-sale (11) (55) (142)
NOTE 12: EMPLOYEE BENEFIT PLANS
PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees and retirees
(referred to collectively as “pension benefits”), contributory postretirement medical plans for eligible employees and retirees and their
eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees (referred to
collectively as “other benefits”). PG&E Corporation and the Utility have elected that certain of the trusts underlying these plans be
treated under the Code as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made
to the qualified trusts, subject to certain Code limitations. PG&E Corporation and the Utility use a December 31 measurement date for
all plans.
PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable
regulatory decisions and federal minimum funding requirements. Based upon current assumptions and available information, the
Utility has not identified any minimum funding requirements related to its pension plans.
Change in Plan Assets, Benefit Obligations, and Funded Status
The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded
status for pension benefits and other benefits for PG&E Corporation during 2010 and 2009:
Pension Benefits
(in millions) 2010 2009
Change in plan assets:
Fair value of plan assets at January 1 $ 9,330 $ 8,066
Actual return on plan assets 1,235 1,523
FERC FORM NO. 1 (ED. 12-88) Page 123.38

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Company contributions 162 187
Benefits and expenses paid (477) (446)
Fair value of plan assets at December 31 $ 10,250 $ 9,330
Change in benefit obligation:
Projected benefit obligation at January 1 $ 10,766 $ 9,767
Service cost for benefits earned 253 227
Interest cost 645 624
Actuarial loss 856 494
Plan amendments (1) 71
Transitional costs 4 3
Benefits paid (452) (420)
Projected benefit obligation at December 31 (1) $
12,071
$
10,766
Funded status:
Current liability $ (5) $ (5)
Noncurrent liability (1,816) (1,431)
Accrued benefit cost at December 31 $ (1,821) $ (1,436)
(1) PG&E Corporation’s accumulated benefit obligation was $10,653 million and $9,527 million at December 31, 2010 and 2009, respectively.
Other Benefits
(in millions) 2010 2009
Change in plan assets:
Fair value of plan assets at January 1 $ 1,169 $ 990
Actual return on plan assets 147 166
Company contributions 94 87
Plan participant contribution 49 42
Benefits and expenses paid (122) (116)
Fair value of plan assets at December 31 $ 1,337 $ 1,169
Change in benefit obligation:
Benefit obligation at January 1 $ 1,511 $ 1,382
Service cost for benefits earned 36 30
Interest cost 88 87
Actuarial loss 52 72
Plan amendments 128 -
Transitional costs 1 1
Benefits paid (113) (106)
Federal subsidy on benefits paid 3 4
Plan participant contributions 49 41
Benefit obligation at December 31 $ 1,755 $ 1,511
Funded status:
Noncurrent liability $ (418) $ (342)
Accrued benefit cost at December 31 $ (418) $ (342)
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
FERC FORM NO. 1 (ED. 12-88) Page 123.39

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
On February 16, 2010, the Utility amended its contributory postretirement medical plans for retirees to provide for additional
employer contributions towards retiree premiums. The plan amendment was accounted for as a plan modification that required
re-measurement of the accumulated benefit obligation, plan assets, and periodic benefit costs. The inputs and assumptions used in
re-measurement did not change significantly from December 31, 2009 and did not have a material impact on the funded status of the
plans. The re-measurement of the accumulated benefit obligation and plan assets resulted in an increase to other postretirement
benefits and a decrease to other comprehensive income of $148 million. The impact to net periodic benefit cost was not material.
Components of Net Periodic Benefit Cost
Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income for 2010, 2009, and 2008 is
as follows:
Pension Benefits
December 31,
(in millions) 2010 2009 2008
Service cost for benefits earned $ 279 $ 259 $ 236
Interest cost 645 624 581
Expected return on plan assets (624) (579) (696)
Amortization of prior service cost 53 53 47
Amortization of unrecognized loss 44 101 1
Net periodic benefit cost 397 458 169
Less: transfer to regulatory account (1) (233) (294) (4)
Total $ 164 $ 164 $ 165
(1) The Utility recorded $233 million, $295 million, and $4 million for the years ended December 31, 2010, 2009, and 2008, respectively, to a regulatory account as
the amounts are probable of recovery from customers in future rates.
December 31,
(in millions) 2010 2009 2008
Service cost for benefits earned $ 279 $ 259 $ 236
Interest cost 645 624 581
Expected return on plan assets (624) (579) (696)
Amortization of prior service cost 53 53 47
Amortization of unrecognized loss 44 101 1
Net periodic benefit cost 397 458 169
Less: transfer to regulatory account (1) (233) (294) (4)
Total $ 164 $ 164 $ 165
(1) The Utility recorded $233 million, $295 million, and $4 million for the years ended December 31, 2010, 2009, and 2008, respectively, to a regulatory account as
the amounts are probable of recovery from customers in future rates.
Other Benefits
December 31,
(in millions) 2010 2009 2008
Service cost for benefits earned $ 36 $ 30 $ 29
Interest cost 88 87 81
Expected return on plan assets (74) (68) (93)
Amortization of transition obligation 26 26 26
Amortization of prior service cost 25 16 16
FERC FORM NO. 1 (ED. 12-88) Page 123.40

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Amortization of unrecognized loss (gain) 3 3 (15)
Net periodic benefit cost $ 104 $ 94 $ 44
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Components of Accumulated Other Comprehensive Income (Loss)
PG&E Corporation and the Utility record the net periodic benefit cost for pension benefits and other benefits as a component
of accumulated other comprehensive income (loss), net of tax. Net periodic benefit cost is composed of unrecognized prior service
costs, unrecognized gains and losses, and unrecognized net transition obligations as components of accumulated other comprehensive
income, net of tax. (See Note 2 above.)
Regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the
difference between pension expense or income for accounting purposes and pension expense or income for ratemaking, which is based
on a funding approach. A regulatory adjustment is also recorded for the amounts that would otherwise be charged to accumulated
other comprehensive income for the pension benefits related to the Utility’s defined benefit pension plan. The Utility would record a
regulatory liability for a portion of the credit balance in accumulated other comprehensive income, should the other benefits be in an
overfunded position. However, this recovery mechanism does not allow the Utility to record a regulatory asset for an underfunded
position related to other benefits. Therefore, the charge remains in accumulated other comprehensive income (loss) for other benefits.
Pension Benefits
The estimated amounts that will be amortized into net periodic benefit cost for PG&E Corporation in 2011 are as follows:
(in millions)
Unrecognized prior service cost $ 35
Unrecognized net loss 48
Total $ 83
Other Benefits
(in millions)
Unrecognized prior service cost $ 26
Unrecognized net loss 4
Unrecognized net transition obligation 26
Total $ 56
There were no material differences between the estimated amounts that will be amortized into net period benefit costs for
PG&E Corporation and the Utility.
Medicare Prescription Drug, Improvement and Modernization Act of 2003
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 establishes a prescription drug benefit under
Medicare (“Medicare Part D”) and a tax-exempt federal subsidy to sponsors of retiree health care benefit plans that provide a benefit
that actuarially is at least equivalent to Medicare Part D. PG&E Corporation and the Utility determined that benefits provided to
certain participants actuarially will be at least equivalent to Medicare Part D. Therefore, PG&E Corporation and the Utility are
entitled to a tax-exempt subsidy that reduced the accumulated postretirement benefit obligation under the defined benefit medical plan
at December 31, 2010 and 2009 and reduced the net periodic cost for 2010 and 2009 by the following amounts:
(in millions) 2010 2009
Accumulated postretirement benefit obligation reduction $ 72 $ 71
FERC FORM NO. 1 (ED. 12-88) Page 123.41

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Net periodic benefit cost reduction 1 7
On March 30, 2010, federal healthcare legislation was signed eliminating the deduction for subsidy contributions after 2012.
(See Note 9 above.)
There was no material difference between PG&E Corporation’s and the Utility’s Medicare Part D subsidy during 2010.
Valuation Assumptions
The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic cost. The
following weighted average year-end assumptions were used in determining the plans’ projected benefit obligations and net benefit
cost.
Pension Benefits
Other Benefits
December 31, December 31,
2010 2009 2008 2010 2009 2008
Discount rate 5.42% 5.97% 6.31% 5.11–5.56% 5.66–6.09% 5.85–6.33%
Average rate of future compensation
increases 5.00% 5.00% 5.00% - - -
Expected return on plan assets 6.60% 6.80% 7.30% 5.20–6.60% 5.80–6.90% 7.00–7.30%
The assumed health care cost trend rate as of December 31, 2010 is 8%, decreasing gradually to an ultimate trend rate in 2018
and beyond of approximately 5%. A one-percentage-point change in assumed health care cost trend rate would have the following
effects:
One-
Percentage-
Point
Increase
One-
Percentage-
Point
Decrease
(in millions)
Effect on postretirement benefit obligation $ 83 $ (86)
Effect on service and interest cost 7 (7)
Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying
these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan
assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term
inflation rate. Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a
long-term inflation rate. For the pension plan, the assumed return of 6.6% compares to a ten-year actual return of 6.2%. The rate used
to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 600
Aa-grade non-callable bonds at December 31, 2010. This yield curve has discount rates that vary based on the duration of the
obligations. The estimated future cash flows for the pension and other benefit obligations were matched to the corresponding rates on
the yield curve to derive a weighted average discount rate.
The difference between actual and expected return on plan assets is included in unrecognized gain (loss), and is considered in
the determination of future net periodic benefit income (cost). The actual return on plan assets for 2009 was lower than the expected
return due to the significant decline in equity market values that occurred in 2009. The actual return on plan assets in 2010 was in line
with the expectations.
Investment Policies and Strategies
The financial position of PG&E Corporation’s and the Utility’s funded employee benefit plans is driven by the relationship
between plan assets and liabilities. As noted above, the funded status is the difference between the fair value of plan assets and
projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and can
result in fluctuations in costs for financial reporting as well as the amount of minimum contributions required under the Employee
FERC FORM NO. 1 (ED. 12-88) Page 123.42

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Retirement Income Security Act of 1974, as amended (“ERISA”). PG&E Corporation’s and the Utility’s investment policies and
strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility.
Interest rate risk and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In
addition to affecting the trust’s fixed income portfolio market values, interest rate changes also influence liability valuations as
discount rates move with current bond yields. To manage this risk, PG&E Corporation’s and the Utility’s trusts hold significant
allocations to fixed income investments that include U.S. government securities, corporate securities, interest rate swaps, and other
fixed income securities. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding
costs due to their higher expected return. The equity investment allocation is implemented through diversified U.S., non-U.S., and
global portfolios that include common stock and commingled funds across multiple industry sectors. Absolute return investments
include hedge fund portfolios that diversify the plan’s holdings in equity and fixed income investments by exhibiting returns with low
correlation to the direction of these markets. Over the last three years, target allocations to equity investments have generally declined
in favor of longer-maturity fixed income investments as a means of dampening future funded status volatility.
PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee
benefit plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and
responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and
investment manager guidelines include provisions to ensure prudent diversification, manage risk through appropriate use of physical
direct asset holdings and derivative securities, and identify permitted and prohibited investments.
The target asset allocation percentages for major categories of trust assets for pension and other benefit plans at December 31,
2011, 2010, and 2009 are as follows:
Pension Benefits
Other Benefits
2011 2010 2009 2011 2010 2009
U.S. Equity 26% 26% 32% 28% 26% 37%
Non-U.S. Equity 14% 14% 18% 15% 13% 18%
Global Equity 5% 5% 5% 3% 3% 3%
Absolute Return 5% 5% 5% 4% 3% 3%
Fixed Income 50% 50% 40% 50% 54% 34%
Cash Equivalents -% -% -% -% 1% 5%
Total 100% 100% 100% 100% 100% 100%
Fair Value Measurements
The following tables present the fair value of plan assets for pension and other benefit plans by major asset category at
December 31, 2010 and 2009.
Fair Value Measurements as of December 31, 2010
(in millions) Level 1 Level 2 Level 3 Total
Pension Benefits:
U.S. Equity $ 328 $ 2,482 $ - $ 2,810
Non-U.S. Equity 356 1,111 - 1,467
Global Equity 177 360 - 537
Absolute Return - - 494 494
Fixed Income:
U.S. Government 790 233 - 1,023
Corporate 6 2,724 549 3,279
Other 52 393 120 565
Cash Equivalents 20 - - 20
Total $ 1,729 $ 7,303 $ 1,163 $ 10,195
FERC FORM NO. 1 (ED. 12-88) Page 123.43

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Other Benefits:
U.S. Equity $ 104 $ 230 $ - $ 334
Non-U.S. Equity 118 80 - 198
Global Equity 18 29 - 47
Absolute Return - - 47 47
Fixed Income:
U.S. Government 73 14 - 87
Corporate 8 457 129 594
Other 3 21 10 34
Cash Equivalents 13 - - 13
Total $ 337 $ 831 $ 186 $ 1,354
Other Assets 38
Total Plan Assets at Fair Value $ 11,587
Fair Value Measurements as of December 31, 2009
(in millions) Level 1 Level 2 Level 3 Total
Pension Benefits:
U.S. Equity $ 411 $ 2,065 $ - $ 2,476
Non-U.S. Equity 316 1,018 - 1,334
Global Equity 162 317 - 479
Absolute Return - - 340 340
Fixed Income:
U.S. Government 585 262 - 847
Corporate 25 2,455 531 3,011
Other (8) 233 190 415
Cash Equivalents 378 31 - 409
Total $ 1,869 $ 6,381 $ 1,061 $ 9,311
Other Benefits:
U.S. Equity $ 88 $ 218 $ - $ 306
Non-U.S. Equity 81 68 - 149
Global Equity - 8 - 8
Absolute Return - - 32 32
Fixed Income:
U.S. Government 40 15 - 55
Corporate 82 275 124 481
Other (1) 13 17 29
Cash Equivalents 111 - - 111
Total $ 401 $ 597 $ 173 $ 1,171
Other Assets 17
Total Plan Assets at Fair Value $ 10,499
Equity Securities
The U.S., Non-U.S., and combined Global Equity categories include equity investments in common stock and commingled
funds comprised of equity across multiple industries and regions of the world. Equity investments in common stock are actively traded
on a public exchange and are therefore considered Level 1 assets. These equity investments are generally valued based on unadjusted
prices in active markets for identical securities. Commingled funds are maintained by investment companies for large institutional
investors and are not publicly traded. Commingled funds are comprised primarily of underlying equity securities that are publicly
traded on exchanges, and price quotes for the assets held by these funds are readily observable and available. Commingled funds are
categorized as Level 2 assets.
FERC FORM NO. 1 (ED. 12-88) Page 123.44

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Absolute Return
The Absolute Return category includes portfolios of hedge funds that are valued based on a variety of proprietary and
non-proprietary valuation methods, including unadjusted prices for publicly-traded securities in active markets. Hedge funds are
considered Level 3 assets.
Fixed Income
The Fixed Income category includes U.S. government securities, corporate securities, and other fixed income securities.
U.S. government fixed income primarily consists of U.S. Treasury notes and U.S. government bonds that are valued based on
quoted market prices or evaluated pricing data for similar securities adjusted for observable differences. These securities are
categorized as Level 1 or Level 2 assets.
Corporate fixed income primarily includes investment grade bonds of U.S. issuers across multiple industries that are valued
based on a compilation of primarily observable information or broker quotes in non-active markets. The fair value of corporate bonds
is determined using recently executed transactions, market price quotations (where observable), bond spreads or credit default swap
spreads obtained from independent external parties such as vendors and brokers adjusted for any basis difference between cash and
derivative instruments. These securities are classified as Level 2 assets. Corporate fixed income also includes one commingled fund
comprised of private corporate debt instruments. The fund is valued using pricing models and valuation inputs that are unobservable
and is considered a Level 3 asset.
Other fixed income primarily includes pass-through and asset-backed securities. Pass-through securities are valued based on
benchmark yields created using observable market inputs and are Level 2 assets. Asset-backed securities are primarily valued based
on broker quotes in non-active markets and are considered Level 3 assets. Other fixed income also includes municipal bonds and
futures. Municipal bonds are valued based on a compilation of primarily observable information or broker quotes in non-active
markets and are considered Level 2 assets. Futures are valued based on unadjusted prices in active markets and are Level 1 assets.
Cash Equivalents
Cash equivalents consist primarily of money markets and commingled funds of short-term securities that are considered Level
1 assets and valued at the net asset value of $1 per unit. The number of units held by the plan fluctuates based on the unadjusted price
changes in active markets for the funds’ underlying assets.
Transfers between Levels
PG&E Corporation and the Utility recognize any transfers between levels in the fair value hierarchy as of the end of the
reporting period. There were no significant transfers between levels for the year ended December 31, 2010.
Level 3 Reconciliation
The following table is a reconciliation of changes in the fair value of instruments for pension and other benefit plans that have been
classified as Level 3 for the years ended December 31, 2010 and 2009:
Absolute
Return
Corporate Fixed
Income
Other Fixed
Income
(in millions)
Total
Pension Benefits:
Balance as of December 31, 2009 $ 340 $ 531 $ 190 $ 1,061
Actual return on plan assets:
Relating to assets still held at the
reporting date 44 52 5 101
FERC FORM NO. 1 (ED. 12-88) Page 123.45

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Relating to assets sold during the
period 5 5 5 15
Purchases, sales, and settlements 105 (39) (80) (14)
Transfers into (out of) Level 3 - - - -
Balance as of December 31, 2010 $ 494 $ 549 $ 120 $ 1,163
Other Benefits:
Balance as of December 31, 2009 $ 32 $ 124 $ 17 $ 173
Actual return on plan assets:
Relating to assets still held at the
reporting date 4 15 - 19
Relating to assets sold during the
period 1 (2) - (1)
Purchases, sales, and settlements 10 (8) (7) (5)
Transfers into (out of) Level 3 - - - -
Balance as of December 31, 2010 $ 47 $ 129 $ 10 $ 186
Absolute
Return
Corporate Fixed
Income
Other Fixed
Income
(in millions)
Total
Pension Benefits:
Balance as of December 31, 2008 $ 263 $ 457 $ 291 $ 1,011
Actual return on plan assets:
Relating to assets still held at the
reporting date 15 82 14 111
Relating to assets sold during the
period 4 4 12 20
Purchases, sales, and settlements 58 (11) (127) (80)
Transfers into (out of) Level 3 - (1) - (1)
Balance as of December 31, 2009 $ 340 $ 531 $ 190 $ 1,061
Other Benefits:
Balance as of December 31, 2008 $ 25 $ 116 $ 25 $ 166
Actual return on plan assets:
Relating to assets still held at the
reporting date 2 15 1 18
Relating to assets sold during the
period - 1 1 2
Purchases, sales, and settlements 5 (8) (10) (13)
Transfers into (out of) Level 3 - - - -
Balance as of December 31, 2009 $ 32 $ 124 $ 17 $ 173
Cash Flow Information
Employer Contributions
PG&E Corporation and the Utility contributed $162 million to the pension benefit plans and $94 million to the other benefit
plans in 2010. These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute
amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. None
of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2010. The Utility’s
pension benefits met all the funding requirements under ERISA. PG&E Corporation and the Utility expect to make total contributions
of approximately $245 million and $58 million to the pension plan and other postretirement benefit plans, respectively, for 2011.
Benefits Payments
FERC FORM NO. 1 (ED. 12-88) Page 123.46

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 31, 2010, the estimated benefits expected to be paid in each of the next five fiscal years, and in aggregate for
the five fiscal years thereafter for PG&E Corporation, are as follows:
Pension
Other
(in millions)
2011 $ 509 $ 114
2012 547 117
2013 586 122
2014 624 128
2015 663 133
2016–2020 3,869 725
There were no material differences between the estimated benefits expected to be paid for PG&E Corporation and the Utility
for the years presented above.
Defined Contribution Benefit Plans
PG&E Corporation sponsors employee retirement savings plans, including a 401(k) defined contribution savings plan. These
plans are qualified under applicable sections of the Code and provide for tax-deferred salary deductions, after-tax employee
contributions, and employer contributions. Employer contribution expense reflected in PG&E Corporation’s Consolidated Statements
of Income was as follows:
(in millions)
Year ended December 31,
2010 $ 56
2009 52
2008 53
There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the
years presented above.
NOTE 13: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS
Various electricity suppliers filed claims in the Utility’s proceeding under Chapter 11 seeking payment for energy supplied to
the Utility’s customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange (“PX”)
between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial
proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers,
including municipal and governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets
between May 2000 and June 2001. At December 31, 2010 and December 31, 2009, the Utility held $512 million and $515 million in
escrow, respectively, including interest earned, for payment of the remaining net disputed claims. These amounts are included within
restricted cash on the Consolidated Balance Sheets.
While the FERC and judicial proceedings have been pending, the Utility entered into a number of settlements with various
electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity
suppliers. These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment
based on the outcome of the various refund offset and interest issues being considered by the FERC. The proceeds from these
settlements, after deductions for contingencies based on the outcome of the various refund offset and interest issues being considered
by the FERC, will continue to be refunded to customers in rates. Additional settlement discussions with other electricity suppliers are
ongoing. Any net refunds, claim offsets, or other credits that the Utility receives from energy suppliers through resolution of the
remaining disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be
refunded to customers.
FERC FORM NO. 1 (ED. 12-88) Page 123.47

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents the changes in the remaining net disputed claims liability and interest accrued from December
31, 2009 to December 31, 2010:
(in millions)
Balance at December 31, 2009 $ 946
Interest accrued 30
Less: supplier settlements (42)
Balance at December 31, 2010 $ 934
At December 31, 2010, the Utility’s net disputed claims liability was $934 million, consisting of $745 million of remaining
disputed claims (classified on the Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and
interest accrued at the FERC-ordered rate of $683 million (classified on the Consolidated Balance Sheets within interest payable)
partially offset by accounts receivable from the CAISO and the PX of $494 million (classified on the Consolidated Balance Sheets
within accounts receivable – other).
Interest accrues on the net liability for disputed claims at the FERC-ordered rate, which is higher than the rate earned by the
Utility on the escrow balance. Although the Utility has been collecting the difference between the accrued interest and the earned
interest from customers, this amount is not held in escrow. If the amount of interest accrued at the FERC-ordered rate is greater than
the amount of interest ultimately determined to be owed with respect to disputed claims, the Utility would refund to customers any
excess net interest collected from customers. The amount of any interest that the Utility may be required to pay will depend on the
final amounts to be paid by the Utility with respect to the disputed claims and when such interest is paid.
PG&E Corporation and the Utility are unable to predict when the FERC or judicial proceedings that are still pending will be
resolved, and the amount of any potential refunds that the Utility may receive or the amount of disputed claims, including interest that
the Utility will be required to pay.
NOTE 14: RELATED PARTY AGREEMENTS AND TRANSACTIONS
The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and
among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations.
Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or
service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to
the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature
and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other
subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total
assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and
meet the reporting and accounting requirements of its regulatory agencies.
The Utility’s significant related party transactions were as follows:
Year Ended December 31,
2010 2009 2008
(in millions)
Utility revenues from:
Administrative services provided to PG&E Corporation $ 7 $ 5 $ 4
Utility expenses from:
Administrative services received from PG&E
Corporation $ 55 $ 62 $ 122
Utility employee benefit due to PG&E Corporation 27 3 2
FERC FORM NO. 1 (ED. 12-88) Page 123.48

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
At December 31, 2010 and December 31, 2009, the Utility had a receivable of $89 million and $26 million, respectively,
from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Consolidated
Balance Sheets, and a payable of $16 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s
Consolidated Balance Sheets.
NOTE 15: COMMITMENTS AND CONTINGENCIES
PG&E Corporation and the Utility have substantial financial commitments in connection with agreements entered into to
support the Utility’s operating activities. PG&E Corporation and the Utility also have significant contingencies arising from their
operations, including contingencies related to guarantees, regulatory proceedings, nuclear operations, environmental compliance and
remediation, tax matters, and legal matters.
Commitments
Utility
Third-Party Power Purchase Agreements
As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity.
The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or
electricity at the date of purchase.
The table below shows the costs incurred for each type of third-party power purchase agreement at December 31, 2010:
Payments
(in millions) 2010 2009 2008
Qualifying facilities(1) (2) $ 1,164 $ 1,210 $ 1,724
Renewable energy
contracts(1) 573 362 302
Other power purchase
agreements(1) 598 643 2,036
Irrigation district and
water agencies(1) 59 58 69
(1) The amounts above do not include payments related to DWR purchases
for the benefit of the Utility’s customers, as the Utility only acts as an agent for
the DWR.
(2) Payments include $321, $344, and $412 attributable to renewable energy
contracts with qualifying facilities at December 31, 2010, 2009 and 2008,
respectively.
Qualifying Facility Power Purchase Agreements – Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”),
electric utilities are required to purchase energy and capacity from independent power producers with generation facilities that meet the
statutory definition of a qualifying facility (“QF”). QFs include small power production facilities whose primary energy sources are
co-generation facilities that produce combined heat and power (“CHP”) and renewable generation facilities. To implement the
purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power
purchase agreements with QFs and approved the applicable terms and conditions, prices, and eligibility requirements. These
agreements require the Utility to pay for energy and capacity. Energy payments are based on the QF’s actual electrical output and
CPUC-approved energy prices, while capacity payments are based on the QF’s total available capacity and contractual capacity
commitment. Capacity payments may be adjusted if the QF exceeds or fails to meet performance requirements specified in the
FERC FORM NO. 1 (ED. 12-88) Page 123.49

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
applicable power purchase agreement.
As of December 31, 2010, the Utility had agreements with 226 QFs for approximately 3,700 megawatts (“MW”) that are in
operation. Agreements for approximately 3,400 MW expire at various dates between 2011 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 75 inoperative QFs. The total of approximately 3,700 MW
consists of approximately 2,500 MW from cogeneration projects and approximately 1,200 MW from renewable sources. No single QF
accounted for more than 5% of the Utility’s 2010, 2009, or 2008 electricity sources.
Renewable Energy Power Purchase Agreements – The Utility has entered into various contracts to purchase renewable
energy to help the Utility meet the current renewable portfolio standard (“RPS”) requirement. In general, renewable contract payments
consist primarily of per megawatt hour (“MWh”) payments and either a small or no fixed capacity payment, as opposed to contracts
with non-renewable sources, which generally include both a per MWh payment and a fixed capacity payment. As shown in the table
below, the Utility’s commitments for energy payments under these renewable energy agreements are expected to grow significantly,
assuming that the facilities are developed timely. No single supplier accounted for more than 5% of the Utility’s 2010, 2009, or 2008
electricity sources.
Other Power Purchase Agreements – In accordance with the Utility’s CPUC-approved long-term procurement plans, the
Utility has entered into several power purchase agreements with third parties. The Utility’s obligations under a portion of these
agreements are contingent on the third party’s development of a new generation facility to provide the power to be purchased by the
Utility under the agreements.
Irrigation District and Water Agency Power Purchase Agreements – The Utility has contracts with various irrigation districts
and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum
payments based on the irrigation districts’ and water agencies’ debt service requirements, whether or not any hydroelectric power is
supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various
dates from 2011 to 2031. Irrigation districts and water agencies consist of small and large hydro plants. No single irrigation district or
water agency accounted for more than 5% of the Utility’s 2010, 2009, or 2008 electricity sources.
At December 31, 2010, the undiscounted future expected power purchase agreement payments were as follows:
Renewable
Irrigation District &
Qualifying Facility (Other than QF) Water Agency Other
Operations & Debt Total
(in millions) Energy Capacity Energy Capacity Maintenance Service Energy Capacity Payments
2011 $ 720 $ 366 $ 796 $ 8 $ 59 $ 21 $ 3 $ 691 $ 2,664
2012 545 321 944 9 45 21 3 684 2,572
2013 542 312 1,261 9 28 15 3 822 2,992
2014 548 301 1,647 - 13 12 1 605 3,127
2015 509 259 1,942 - 11 11 - 583 3,315
Thereafter 3,129 1,263 40,882 5 27 16 - 4,227 49,549
Total $ 5,993 $ 2,822 $ 47,472 $ 31 $ 183 $ 96 $ 10 $ 7,612 $64,219
Some of the power purchase agreements that the Utility entered into with independent power producers that are QFs are
treated as capital leases. The following table shows the future fixed capacity payments due under the QF contracts that are treated as
capital leases. (These amounts are also included in the table above.) The fixed capacity payments are discounted to their present value
in the table below using the Utility’s incremental borrowing rate at the inception of the leases. The amount of this discount is shown in
the table below as the amount representing interest.
(in millions)
2011 $ 50
FERC FORM NO. 1 (ED. 12-88) Page 123.50

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2012 50
2013 50
2014 42
2015 38
Thereafter 124
Total fixed capacity payments 354
Less: amount representing interest 72
Present value of fixed capacity payments $ 282
Minimum lease payments associated with the lease obligation are included in cost of electricity on PG&E Corporation’s and
the Utility’s Consolidated Statements of Income. The timing of the recognition of the lease expense conforms to the ratemaking
treatment for the Utility’s recovery of the cost of electricity. The QF contracts that are treated as capital leases expire between April
2014 and September 2021.
The present value of the fixed capacity payments due under these contracts is recorded on PG&E Corporation’s and the
Utility's Consolidated Balance Sheets. At December 31, 2010 and December 31, 2009, current liabilities – other included $34 million
and $32 million, respectively, and noncurrent liabilities – other included $248 million and $282 million, respectively. The
corresponding assets at December 31, 2010 and December 31, 2009 of $282 million and $314 million including accumulated
amortization of $126 million and $94 million, respectively are included in property, plant, and equipment on PG&E Corporation’s and
the Utility’s Consolidated Balance Sheets.
Natural Gas Supply, Transportation, and Storage Commitments
The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core
customers. The contract lengths and quantities of the Utility’s portfolio of natural gas procurement contracts can fluctuate based on
market conditions. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically
in Canada and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. In addition,
the Utility has contracted for gas storage services in northern California in order to better meet core customers’ winter peak loads. At
December 31, 2010, the Utility’s undiscounted obligations for natural gas purchases, natural gas transportation services, and natural
gas storage were as follows:
(in millions)
2011 $ 710
2012 273
2013 191
2014 170
2015 161
Thereafter 1,128
Total (1) $ 2,633
(1) Amounts above include firm transportation contracts for the Ruby Pipeline (a 1.5 billion cubic
feet per day (“bcf/d”) pipeline which is currently under construction and expected to become
operational in the summer of 2011, and the Utility has contracted for a capacity of approximately
0.4 bcf/d).
Payments for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $1.6 billion in
2010, $1.4 billion in 2009, and $2.7 billion in 2008.
Nuclear Fuel Agreements
The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from 1 to 14
years and are intended to ensure long-term fuel supply. The contracts for uranium and for conversion and enrichment services provide
FERC FORM NO. 1 (ED. 12-88) Page 123.51

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
for 100% coverage of reactor requirements through 2016, while contracts for fuel fabrication services provide for 100% coverage of
reactor requirements through 2017. The Utility relies on a number of international producers of nuclear fuel in order to diversify its
sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are
escalated using published indices. New agreements are primarily based on forward market pricing. Price increases in the uranium and
enrichment service markets are providing upward pressure on nuclear fuel costs starting in 2011.
At December 31, 2010, the undiscounted obligations under nuclear fuel agreements were as follows:
(in millions)
2011 $ 84
2012 69
2013 105
2014 132
2015 191
Thereafter 1,057
Total $ 1,638
Payments for nuclear fuel amounted to $144 million in 2010, $141 million in 2009, and $157 million in 2008.
Other Commitments and Operating Leases
The Utility has other commitments relating to operating leases. At December 31, 2010, the future minimum payments related
to other commitments were as follows:
(in millions)
2011 $ 25
2012 22
2013 19
2014 14
2015 11
Thereafter 73
Total $ 164
Payments for other commitments and operating leases amounted to $25 million in 2010, $22 million in 2009, and $41 million
in 2008. PG&E Corporation and the Utility had operating leases on office facilities expiring at various dates from 2011 to 2020.
Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 1% to 4%. The rentals
payable under these leases may increase by a fixed amount each year, a percentage of a base year, or the consumer price index. Most
leases contain extension options ranging between one and five years.
Underground Electric Facilities
At December 31, 2010, the Utility was committed to spending approximately $236 million for the conversion of existing
overhead electric facilities to underground electric facilities. These funds are conditionally committed depending on the timing of the
work, including the schedules of the respective cities, counties, and communications utilities involved. The Utility expects to spend
approximately $42 million to $60 million each year in connection with these projects. Consistent with past practice, the Utility expects
that these capital expenditures will be included in rate base as each individual project is completed and recoverable in rates charged to
customers.
Contingencies
PG&E Corporation
FERC FORM NO. 1 (ED. 12-88) Page 123.52

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
PG&E Corporation retains a guarantee related to certain obligations of its former subsidiary, NEGT, that were issued to the
purchaser of an NEGT subsidiary company in 2000. PG&E Corporation’s primary remaining exposure relates to any potential
environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser, and is limited to $150
million. PG&E Corporation has not received any claims nor does it consider it probable that any claims will be made under the
guarantee. PG&E Corporation believes that its potential exposure under this guarantee would not have a material impact on its
financial condition or results of operations.
Utility
Energy Efficiency Programs and Incentive Ratemaking
The CPUC has established a ratemaking mechanism to provide incentives to the California investor-owned utilities to meet
the CPUC’s energy savings goals through implementation of the utilities’ 2006 through 2008 energy efficiency programs. On
December 16, 2010, the CPUC awarded the Utility a final true-up payment award of $29.1 million for the 2006 through 2008 energy
efficiency program cycle. Including this award, the Utility has earned incentive revenues totaling $104 million through December 31,
2010 based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006
through 2008 program cycle. The CPUC has directed the utilities to file their applications for incentive awards for 2009 energy
efficiency program performance by June 30, 2011 to enable the CPUC to issue a final decision by the end of 2011.
On November 15, 2010, a proposed decision was issued that if, adopted by the CPUC, would modify the incentive
mechanism that would apply to the 2010 through 2012 program cycle. Among other changes, the proposed modification would limit
the total amount of the incentive award or penalty that could be awarded to, or imposed on, all the investor-owned utilities to $189
million. If the proposed decision is adopted, the Utility’s opportunity to earn incentive revenues would be limited compared to the
mechanism that was in place for the 2006-2008 program cycle.
Spent Nuclear Fuel Storage Proceedings
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 Power Plant (“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 at Diablo Canyon 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. The Ninth Circuit heard
oral arguments on November 4, 2010. The Utility expects a decision from the Ninth Circuit in 2011.
As a result of the DOE’s failure to build a repository for nuclear waste, the Utility and other nuclear power plant owners sued
the DOE to recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility sought to recover $92
million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims
awarded the Utility $89 million. The DOE filed an appeal of this decision on May 28, 2010. On August 3, 2010, the Utility filed two
complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred since 2005 to build on-site
storage facilities. The Utility estimates that it has incurred costs of at least $205 million since 2005. Amounts recovered from the
DOE will be credited to customers.
Nuclear Insurance
The Utility has several types of nuclear insurance for the two nuclear operating units at Diablo Canyon and for its retired
FERC FORM NO. 1 (ED. 12-88) Page 123.53

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
nuclear generation facility at Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption
losses as a member of Nuclear Electric Insurance Limited (“NEIL”). NEIL is a mutual insurer owned by utilities with nuclear
facilities. NEIL provides property damage and business interruption coverage of up to $3.2 billion per incident for Diablo Canyon. In
addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear
generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an
additional premium of up to $42 million per one-year policy term.
NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of
terrorism cause damages covered under any of the nuclear insurance policies issued by NEIL to any NEIL member, the maximum
recovery under all those nuclear insurance policies may not exceed NEIL’s policy limit of $3.2 billion within a 12-month period plus
any additional amounts recovered by NEIL for these losses from reinsurance. Certain acts of terrorism may be “certified” by the
Secretary of the Treasury. For damages caused by certified acts of terrorism, NEIL can obtain compensation from the federal
government and will provide up to its full policy limit of $3.2 billion for each insured loss caused by these certified acts of terrorism.
The $3.2 billion amount would not be shared as is described above for damages caused by acts of terrorism that have not been
certified.
Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that
occur during the transportation of material to and from Diablo Canyon are limited to $12.6 billion. As required by the Price-Anderson
Act, the Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance of the
$12.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may
be assessed up to $235 million per nuclear incident under this program, with payments in each year limited to a maximum of $35
million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five
years. The next scheduled adjustment is due on or before October 29, 2013.
The Price-Anderson Act does not apply to public liability claims that arise from nuclear incidents that occur during shipping
of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. Such claims are
covered by nuclear liability policies purchased by the enricher and the fuel fabricator as well as by separate supplier’s and transporter’s
(“S&T”) insurance policies. The Utility has an S&T policy that provides coverage for claims arising from some of these incidents up
to a maximum of $375 million per incident. The Utility could incur losses that are either not covered by insurance or exceed the
amount of insurance available.
In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification
from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the $53 million of liability insurance.
Legal Matters
PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E
Corporation and the Utility are named as parties in a number of claims and lawsuits. In addition, the Utility can incur penalties for
failure to comply with federal, state, or local laws and regulations.
PG&E Corporation and the Utility record a provision for a liability when it is both probable that a liability has been incurred
and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated
costs and record a liability based on the lower end of the range, unless an amount within the range is a better estimate than any other
amount. These accruals, and the estimates of any additional reasonably possible losses, are reviewed quarterly and are adjusted to
reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and
events pertaining to a particular matter. In assessing such contingencies, PG&E Corporation’s and the Utility’s policy is to exclude
anticipated legal costs.
The accrued liability for legal matters (other than third-party liability claims related to the San Bruno accident as discussed
below) totaled $55 million at December 31, 2010 and $57 million at December 31, 2009 and is included in PG&E Corporation’s and
the Utility’s current liabilities – other in the Consolidated Balance Sheets. Except as discussed below, PG&E Corporation and the
Utility do not believe that losses associated with legal matters would have a material adverse impact on their financial condition,
FERC FORM NO. 1 (ED. 12-88) Page 123.54

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
results of operations, or cash flows after consideration of the accrued liability at December 31, 2010.
Explosion and Fires in San Bruno, California
On September 9, 2010, an underground 30-inch natural gas transmission pipeline (line 132) owned and operated by the Utility
ruptured in a residential area located in the City of San Bruno, California (“San Bruno accident”). The ensuing explosion and fire
resulted in the deaths of eight people, injuries to numerous individuals, and extensive property damage. Both the NTSB and the CPUC
have begun investigations of the San Bruno accident but they have not yet determined the cause of the pipeline rupture. The NTSB has
issued several public statements regarding the investigation and a metallurgy report, all of which are available on the NTSB’s website.
The NTSB will hold fact-finding hearings in Washington, D.C. on March 1, 2011 through March 3, 2011 and has stated that it intends
to release a total of six factual reports about the San Bruno accident before the hearings begin based on the following topics:
metallurgy, operations, human performance, survival factors, fire scene, and meteorology. It is expected that these reports will be
made publicly available on the NTSB’s website as each report is released.
As part of the CPUC’s investigation, the CPUC’s staff will examine the safety of the Utility’s natural gas transmission
pipelines in its northern and central California service territory. The CPUC staff reviewed information about the Utility’s planned and
unplanned pressurization events where the pressure has risen above the maximum available operating pressure (“MAOP”) in several of
the Utility’s gas transmission lines. On February 2, 2011, the CPUC ordered the Utility to reduce operating pressure twenty percent
below the MAOP on certain of its gas transmission pipelines, and also ordered the Utility to reduce operating pressure on other
transmission lines that meet certain criteria. The Utility has complied with the CPUC’s order and also has reported to the CPUC that
the Utility has identified a number of instances where it had either exceeded MAOP by more than ten percent or had raised the pressure
to maintain operational flexibility, including several instances in which the highest pressure reading exceeded MAOP by a few pounds,
but not more than ten percent. The CPUC also has appointed an independent review panel to gather and review facts, make a technical
assessment of the San Bruno accident and its root cause, and make recommendations for action by the CPUC to ensure such an
accident is not repeated. The report of the independent review panel is expected in the second quarter of 2011.
Several parties have requested that the CPUC institute a formal CPUC investigation into the San Bruno accident. The Utility
has filed a response stating that it welcomes the CPUC’s investigation. The CPUC may consider this request at its meeting to be held
on February 24, 2011. If the CPUC institutes a formal investigation, the CPUC may impose penalties if it determines that the Utility
violated any laws, rules, regulations or orders pertaining to the operations and maintenance of its natural gas system. The CPUC is
authorized to assess penalties of up to $20,000, per day, per violation. PG&E Corporation and the Utility anticipate that the CPUC
will institute one or more formal investigations regarding these matters. PG&E Corporation and the Utility are unable to estimate a
potential loss or range of loss associated with penalties that may be imposed by the CPUC in connection with the San Bruno accident.
In addition to these investigations, as of February 8, 2011, 59 lawsuits on behalf of approximately 177 plaintiffs, including
two class action lawsuits, have been filed against PG&E Corporation and the Utility in San Mateo County Superior Courts. In
addition, five lawsuits on behalf of 11 plaintiffs have been filed by residents of San Bruno in the San Francisco County Superior Court
against PG&E Corporation and the Utility. These lawsuits seek compensation for personal injury and property damage and seek other
relief. The class action lawsuits allege causes of action for strict liability, negligence, public nuisance, private nuisance, and
declaratory relief. Several other residents also have submitted damage claims to the Utility. The Utility has filed a petition on behalf
of PG&E Corporation and the Utility to coordinate these lawsuits in San Mateo County Superior Court. In its statement in support of
coordination, the Utility has stated that it is prepared to enter into early mediation in an effort to resolve claims with those plaintiffs
willing to do so. A hearing is scheduled for February 24, 2011.
The Utility recorded a provision of $220 million in 2010 for estimated third-party claims related to the San Bruno accident,
including personal injury and property damage claims, damage to infrastructure, and other damage claims. The Utility currently
estimates that it may incur as much as $400 million for third-party claims. This estimate may change depending on the final
determination of the causes for the pipeline rupture and responsibility for the personal injuries and property damages and the number
and nature of third-party claims. As more information becomes known, including information resulting from the NTSB and CPUC
investigations, management’s estimates and assumptions regarding the amount of third-party liability incurred in connection with the
San Bruno accident may change. It is possible that a change in estimate could have a material adverse impact on PG&E Corporation’s
and the Utility’s financial condition, results of operations, or cash flows.
FERC FORM NO. 1 (ED. 12-88) Page 123.55

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The Utility maintains liability insurance for damages in the approximate amount of $992 million in excess of a $10 million
deductible. Although PG&E Corporation and the Utility currently consider it likely that most of the costs the Utility incurs for
third-party claims relating to the San Bruno accident will ultimately be recovered through this insurance, no amounts for insurance
recoveries have been recorded as of December 31, 2010. PG&E Corporation and the Utility are unable to predict the amount and
timing of insurance recoveries.
CPUC Investigation of the December 24, 2008 Natural Gas Explosion in Rancho Cordova, California
On November 19, 2010, the CPUC began an investigation of the natural gas explosion and fire that occurred on December 24,
2008 in a house in Rancho Cordova, California (“Rancho Cordova accident”). The explosion resulted in one death, injuries to several
people, and property damage. The CPUC’s Consumer Protection and Safety Division (“CPSD”) and the NTSB investigated the
accident. The NTSB issued its investigative report in May 2010, and the CPSD submitted its report to the CPUC in November 2010.
The NTSB determined that the probable cause of the release, ignition, and explosion of natural gas was use of a section of unmarked
and out-of-specification polyethylene pipe with inadequate wall thickness that allowed gas to leak from the mechanical coupling that
had been installed on September 21, 2006. The NTSB stated that the delayed response by the Utility’s employees was a contributing
factor. Based on the CPSD’s and the NTSB’s investigative findings, the CPSD requested the CPUC to open a formal investigation and
recommended that the CPUC impose unspecified fines and penalties on the Utility.
In its order instituting the investigation, the CPUC stated that it will determine whether the Utility violated any law,
regulation, CPUC general orders or decisions, or other rules or requirement applicable to the Utility’s natural gas service and facilities,
and/or engaged in unreasonable and/or imprudent practices in connection with the Rancho Cordova accident. The CPUC also stated
that it intends to ascertain whether any management policies and practices contributed to violations of law and the Rancho Cordova
accident.
The CPUC ordered the Utility to provide extensive information, from as far back as January 1, 2000, about its practices and
procedures at issue. The Utility’s report, due on February 17, 2011, agrees with the NTSB’s conclusions about the probable cause of
the accident and explains what process improvements the Utility has made to prevent a similar accident in the future. The CPUC has
scheduled a pre-hearing conference for March 1, 2011 to establish a schedule for the proceeding, including the date of an evidentiary
hearing. PG&E Corporation and the Utility believe that the CPUC is likely to impose penalties on the Utility in connection with the
Rancho Cordova accident.
PG&E Corporation and the Utility are unable to predict the ultimate outcome of the investigations of the San Bruno and
Rancho Cordova accidents. The CPUC is authorized to impose penalties of up to $20,000 per day, per violation. If the CPUC
imposed a material amount of penalties on the Utility, there would be a material adverse impact on PG&E Corporation’s and the
Utility’s financial condition, results of operations, and cash flows.
Environmental Matters
The Utility has been, and may be required to pay for environmental remediation at sites where it has been, or may be, a
potentially responsible party under federal and state environmental laws. These sites include former manufactured gas plant (“MGP”)
sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the
storage, recycling, or disposal of potentially hazardous substances. Under federal and California laws, the Utility may be responsible
for remediation of hazardous substances even if it did not deposit those substances on the site.
Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a
remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. The Utility
records an environmental remediation liability when site assessments indicate that remediation is probable and it can reasonably
estimate the loss within a range of possible amounts.
The Utility records an environmental remediation liability based on the lower end of the range of estimated costs, unless an
amount within the range is a better estimate than any other amount. Amounts recorded are not discounted to their present value.
FERC FORM NO. 1 (ED. 12-88) Page 123.56

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The Utility had an undiscounted and gross environmental remediation liability of $612 million at December 31, 2010 and
$586 million at December 31, 2009. The following table presents the changes in the environmental remediation liability from
December 31, 2009:
(in millions)
Balance at December 31, 2009 $ 586
Additional remediation costs accrued:
Transfer to regulatory account for recovery 112
Amounts not recoverable from customers 29
Less: Payments (115)
Balance at December 31, 2010 $ 612
The $612 million accrued at December 31, 2010 consists of the following:
• $45 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;
• $171 for remediation at the Utility’s natural gas compressor site located on the California border, near Topock, Arizona;
• $85 million related to remediation at divested generation facilities;
• $110 million related to remediation costs for the Utility’s generation and other facilities and for third-party disposal sites;
• $139 million related to investigation and/or remediation costs at former MGP sites owned by the Utility or third parties
(including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of
the former MGP sites); and
• $62 million related to remediation costs for fossil decommissioning sites.
The Utility has a program, in cooperation with the California Environmental Protection Agency, to evaluate and take
appropriate action to mitigate any potential environmental concerns posed by certain former MGPs located throughout the Utility’s
service territory. Of the forty one MGP sites owned or operated by the Utility, forty have been or are in the process of being
investigated and/or remediated, and the Utility is developing a strategy to investigate and remediate the last site.
Of the $612 million environmental remediation liability, the Utility expects to recover $316 million through the
CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs without a
reasonableness review (excluding any remediation associated with the Hinkley natural gas compressor site) and $131 million through
the ratemaking mechanism that authorizes the Utility to recover 100% of remediation costs for decommissioning fossil-fueled sites and
certain of the Utility’s transmission stations (excluding any remediation associated with divested generation facilities). The Utility also
recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the
Utility’s ultimate obligations may be subject to refund to customers.
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. The Utility’s undiscounted future costs could increase to as much as $1.2 billion if the extent of
contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able
to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements.
FERC FORM NO. 1 (ED. 12-88) Page 123.57

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Line
No.
Item
(a)
Unrealized Gains and
Losses on Availablefor-Sale
Securities
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Currency
Hedges
(d)
Other
Adjustments
(e)
1
2
3
4
5
6
7
8
9
10
Balance of Account 219 at Beginning of
Preceding Year
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
Preceding Quarter/Year to Date Changes in
Fair Value
Total (lines 2 and 3)
Balance of Account 219 at End of
Preceding Quarter/Year
Balance of Account 219 at Beginning of
Current Year
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
Current Quarter/Year to Date Changes in
Fair Value
Total (lines 7 and 8)
Balance of Account 219 at End of Current
Quarter/Year
( 216,471,801)
27,102,447
35,859,497
62,961,944
( 153,509,857)
( 153,509,857)
32,459,612
( 73,939,380)
( 41,479,768)
( 194,989,625)
FERC FORM NO. 1 (NEW 06-02)
Page 122a

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
1
2
3
4
5
6
7
8
9
10
Other Cash Flow
Hedges
Interest Rate Swaps
(f)
Other Cash Flow
Hedges
[Specify]
(g)
Totals for each
category of items
recorded in
Account 219
(h)
( 216,471,801)
27,102,447
35,859,497
62,961,944
( 153,509,857)
( 153,509,857)
32,459,612
( 73,939,380)
( 41,479,768)
( 194,989,625)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
Total
Comprehensive
Income
(j)
1,250,003,668 1,312,965,612
1,120,973,704 1,079,493,936
FERC FORM NO. 1 (NEW 06-02)
Page 122b

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Year/Period of Report
End of 2010/Q4
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
Line
No.
1
Utility Plant
Classification
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
2
In Service
3
Plant in Service (Classified)
47,904,554,907
34,552,454,380
4
Property Under Capital Leases
411,990,775
410,655,935
5
Plant Purchased or Sold
-1,758,039
-1,758,039
6
Completed Construction not Classified
3,234,162,018
2,488,623,688
7
Experimental Plant Unclassified
8
Total (3 thru 7)
51,548,949,661
37,449,975,964
9
Leased to Others
10
Held for Future Use
11
Construction Work in Progress
1,377,023,361
1,016,902,985
12
Acquisition Adjustments
2,711,908
2,711,908
13
Total Utility Plant (8 thru 12)
52,928,684,930
38,469,590,857
14
Accum Prov for Depr, Amort, & Depl
25,060,388,172
18,068,897,603
15
Net Utility Plant (13 less 14)
27,868,296,758
20,400,693,254
16
Detail of Accum Prov for Depr, Amort & Depl
17
In Service:
18
Depreciation
24,623,869,935
18,016,805,331
19
Amort & Depl of Producing Nat Gas Land/Land Right
20
Amort of Underground Storage Land/Land Rights
6,911,832
21
Amort of Other Utility Plant
429,606,405
52,092,272
22
Total In Service (18 thru 21)
25,060,388,172
18,068,897,603
23
Leased to Others
24
Depreciation
25
Amortization and Depletion
26
Total Leased to Others (24 & 25)
27
Held for Future Use
28
Depreciation
29
Amortization
30
Total Held for Future Use (28 & 29)
31
Abandonment of Leases (Natural Gas)
32
Amort of Plant Acquisition Adj
33
Total Accum Prov (equals 14) (22,26,30,31,32)
25,060,388,172
18,068,897,603
FERC FORM NO. 1 (ED. 12-89) Page 200

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas
Other (Specify)
Other (Specify)
Other (Specify)
(d) (e) (f)
(g)
Year/Period of Report
End of 2010/Q4
Common
9,210,199,638 4,141,900,889 3
1,334,840 4
460,460,281 285,078,049 6
9,671,994,759 4,426,978,938 8
67,296,319 292,824,057 11
9,739,291,078 4,719,802,995 13
5,290,554,470 1,700,936,099 14
4,448,736,608 3,018,866,896 15
5,281,723,677 1,325,340,927 18
6,911,832 20
1,918,961 375,595,172 21
5,290,554,470 1,700,936,099 22
5,290,554,470 1,700,936,099 33
(h)
Line
No.
1
2
5
7
9
10
12
16
17
19
23
24
25
26
27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-89) Page 201

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Year/Period of Report
End of 2010/Q4
1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the
respondent.
2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the
quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Description of item
Balance
Beginning of Year
(a)
(b)
Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
Fabrication
Changes during Year
Additions
(c)
Nuclear Materials 213,404,552 156,733,721
Allowance for Funds Used during Construction
(Other Overhead Construction Costs, provide details in footnote)
SUBTOTAL (Total 2 thru 5) 213,404,552
Nuclear Fuel Materials and Assemblies
In Stock (120.2)
In Reactor (120.3) 282,637,283 89,563,543
SUBTOTAL (Total 8 & 9) 282,637,283
Spent Nuclear Fuel (120.4) 1,499,757,195 70,386,399
Nuclear Fuel Under Capital Leases (120.6)
(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 1,612,579,237
TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 383,219,793
Estimated net Salvage Value of Nuclear Materials in line 9
Estimated net Salvage Value of Nuclear Materials in line 11
Est Net Salvage Value of Nuclear Materials in Chemical Processing
Nuclear Materials held for Sale (157)
Uranium
Plutonium
Other (provide details in footnote):
TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)
FERC FORM NO. 1 (ED. 12-89) Page 202

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Year/Period of Report
End of 2010/Q4
Amortization
(d)
-85,379,213
Changes during Year
Other Reductions (Explain in a footnote)
(e)
Balance
End of Year
(f)
88,790,917 281,347,356
281,347,356
70,386,399 301,814,427
301,814,427
1,570,143,594
1,697,958,450
455,346,927
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
FERC FORM NO. 1 (ED. 12-89) Page 203

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 202 Line No.: 3 Column: e
Allocated reload inserted into Unit 1 reactor during 2010 refueling outage.
Schedule Page: 202 Line No.: 9 Column: e
Transfer of fuel to spent fuel pool during 2010.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Year/Period of Report
End of 2010/Q4
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
Line
Account Balance Additions
No.
Beginning of Year
(a)
(b)
(c)
1 1. INTANGIBLE PLANT
2 (301) Organization
3 (302) Franchises and Consents 105,037,374 1,847,097
4 (303) Miscellaneous Intangible Plant 9,655,373
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 114,692,747 1,847,097
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights 3,938,242 3,107,249
9 (311) Structures and Improvements 62,127,871 55,631,478
10 (312) Boiler Plant Equipment 88,871,962 188,612,183
11 (313) Engines and Engine-Driven Generators 892,346
12 (314) Turbogenerator Units 119,751,277 132,980,638
13 (315) Accessory Electric Equipment 24,285,138 24,216,985
14 (316) Misc. Power Plant Equipment 15,912,890 15,272,310
15 (317) Asset Retirement Costs for Steam Production 49,536,829
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 365,316,555 419,820,843
17 B. Nuclear Production Plant
18 (320) Land and Land Rights 21,588,467 4,697,124
19 (321) Structures and Improvements 972,842,626 6,606,756
20 (322) Reactor Plant Equipment 3,215,542,734 121,599,246
21 (323) Turbogenerator Units 1,121,318,888 2,998,979
22 (324) Accessory Electric Equipment 829,170,810 5,771,471
23 (325) Misc. Power Plant Equipment 592,047,325 4,466,815
24 (326) Asset Retirement Costs for Nuclear Production 96,806,164
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 6,849,317,014 146,140,391
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights 44,235,612 5,080,365
28 (331) Structures and Improvements 307,555,065 3,927,440
29 (332) Reservoirs, Dams, and Waterways 1,441,664,558 94,262,619
30 (333) Water Wheels, Turbines, and Generators 491,148,276 14,743,267
31 (334) Accessory Electric Equipment 164,179,365 9,991,020
32 (335) Misc. Power PLant Equipment 54,671,311 5,016,067
33 (336) Roads, Railroads, and Bridges 46,599,804 2,296,472
34 (337) Asset Retirement Costs for Hydraulic Production 9,271,738
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 2,559,325,729 135,317,250
36 D. Other Production Plant
37 (340) Land and Land Rights 1,721,299 6,350,688
38 (341) Structures and Improvements 18,269,094 116,190,875
39 (342) Fuel Holders, Products, and Accessories 1,713,866 10,903,742
40 (343) Prime Movers 55,588,497 158,955,195
41 (344) Generators 38,528,059 24,092,371
42 (345) Accessory Electric Equipment 39,002,205 64,074,683
43 (346) Misc. Power Plant Equipment 28,528,986 39,608,821
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 183,352,006 420,176,375
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 9,957,311,304 1,121,454,859
FERC FORM NO. 1 (REV. 12-05)
Page 204

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Line
Account Balance Additions
No.
Beginning of Year
(a)
(b)
(c)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights 212,228,241 5,288,378
49 (352) Structures and Improvements 205,132,923 18,743,919
50 (353) Station Equipment 2,964,361,694 340,711,511
51 (354) Towers and Fixtures 464,692,148 45,591,804
52 (355) Poles and Fixtures 471,834,751 51,096,001
53 (356) Overhead Conductors and Devices 811,707,165 80,307,577
54 (357) Underground Conduit 310,415,814 40,975,039
55 (358) Underground Conductors and Devices 158,694,720 95,381,774
56 (359) Roads and Trails 46,660,955 1,383,097
57 (359.1) Asset Retirement Costs for Transmission Plant 967,129
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 5,646,695,540 679,479,100
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights 163,632,498 5,866,045
61 (361) Structures and Improvements 199,271,018 18,046,464
62 (362) Station Equipment 1,906,092,795 152,845,404
63 (363) Storage Battery Equipment 334,866
64 (364) Poles, Towers, and Fixtures 2,454,181,768 147,818,118
65 (365) Overhead Conductors and Devices 2,877,247,836 199,154,652
66 (366) Underground Conduit 2,126,134,186 62,736,607
67 (367) Underground Conductors and Devices 2,978,537,423 135,859,026
68 (368) Line Transformers 1,738,434,331 150,431,392
69 (369) Services 2,527,889,315 61,194,545
70 (370) Meters 835,250,527 308,899,071
71 (371) Installations on Customer Premises 27,313,912
72 (372) Leased Property on Customer Premises 895,448
73 (373) Street Lighting and Signal Systems 157,261,564 2,778,714
74 (374) Asset Retirement Costs for Distribution Plant 24,150,693
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 18,016,628,180 1,245,630,038
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Rights
78 (381) Structures and Improvements
79 (382) Computer Hardware
80 (383) Computer Software
81 (384) Communication Equipment
82 (385) Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights 424,632
87 (390) Structures and Improvements 7,675,000 15,840
88 (391) Office Furniture and Equipment 17,167,485 360,645
89 (392) Transportation Equipment
90 (393) Stores Equipment
91 (394) Tools, Shop and Garage Equipment 51,362,152 5,940,613
92 (395) Laboratory Equipment 12,457,019 115,282
93 (396) Power Operated Equipment 328,162
94 (397) Communication Equipment 7,050,735 2,239,454
95 (398) Miscellaneous Equipment -2,480,123 51,439
96 SUBTOTAL (Enter Total of lines 86 thru 95) 93,985,062 8,723,273
97 (399) Other Tangible Property 468,499,422
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 562,484,484 8,723,273
100 TOTAL (Accounts 101 and 106) 34,297,812,255 3,057,134,367
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8) 435,000
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 34,297,377,255 3,057,134,367
FERC FORM NO. 1 (REV. 12-05)
Page 206

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Year/Period of Report
End of 2010/Q4
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent’s plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
Retirements
Adjustments
Transfers
Balance at
Line
(d)
(e)
(f)
End of Year
(g)
No.
1
2
106,884,471 3
9,655,373 4
116,539,844 5
6
7
7,045,491 8
117,759,349 9
277,484,145 10
892,346 11
252,731,915 12
48,502,123 13
-5,140,000 26,045,200
14
12,988,529 62,525,358
15
7,848,529 792,985,927
16
17
26,285,591 18
1,753,977 977,695,405
19
26,177,296 -410,019
3,310,554,665
20
1,876,345 -176,965
1,122,264,557
21
2,785,844 832,156,437
22
3,578,456 144,000
593,079,684
23
96,806,164 24
36,171,918 -442,984
6,958,842,503
25
26
49,315,977 27
91,945 311,390,560
28
87,028 -165,617
1,535,674,532
29
1,182,527 504,709,016
30
275,804 173,894,581
31
182,885 59,504,493
32
616 48,895,660
33
-1,630,268 7,641,470
34
1,820,805 -1,795,885
2,691,026,289
35
36
8,071,987 37
134,459,969 38
12,617,608 39
214,543,692 40
62,620,430 41
103,076,888 42
128,274 68,266,081
43
44
128,274 603,656,655
45
37,992,723 5,737,934
11,046,511,374
46
FERC FORM NO. 1 (REV. 12-05)
Page 205

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Retirements
Adjustments
Transfers
Balance at
Line
(d)
(e)
(f)
End of Year
(g)
No.
47
13,987 -723,364
216,779,268
48
112,796 -2,605,038
221,159,008
49
13,590,014 -744,469
3,290,738,722
50
2,083,871 508,200,081
51
3,514,995 -122,587
519,293,170
52
5,049,260 -135,202
886,830,280
53
351,390,853 54
594,088 253,482,406
55
5,044,077 -41,315
42,958,660
56
2,435,247 3,402,376
57
30,003,088 -1,936,728
6,294,234,824
58
59
-430,555 169,067,988
60
11,711 -1,790,716
215,515,055
61
10,374,654 -250,855
2,048,312,690
62
334,866 63
9,769,284 -762,839
2,591,467,763
64
13,461,911 -724,184
3,062,216,393
65
93,690 -2,199,909
2,186,577,194
66
3,310,283 -1,548,508
3,109,537,658
67
17,538,142 -390,428
1,870,937,153
68
538,378 -297,527
2,588,247,955
69
203,711,568 -25,319,767
915,118,263
70
27,313,912 71
895,448 72
59,926 -6,777
159,973,575
73
-8,678,782 15,471,911
74
258,869,547 -42,400,847
18,960,987,824
75
76
77
78
79
80
81
82
83
84
85
424,632 86
7,690,840 87
7,240 17,520,890
88
89
90
4,140,830 53,161,935
91
12,572,301 92
6,894 321,268
93
27,053 9,263,136
94
55,778,463 53,349,779
95
4,182,017 55,778,463
154,304,781
96
468,499,422 97
98
4,182,017 55,778,463
622,804,203
99
331,047,375 17,178,822
37,041,078,069
100
101
1,323,040 1,758,040
102
103
331,047,375 15,855,782
37,039,320,029
104
FERC FORM NO. 1 (REV. 12-05)
Page 207

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Year/Period of Report
End of 2010/Q4
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Description of Project Construction work in progress -
Electric (Account 107)
(a)
(b)
5721054 SFR-SF H Sub: 115kV BAAH Conversion
27,236,312
5704039 Upper North Fork Feather River FERC 2105 Relicense
25,323,568
5724979 Crane Valley Dam - Seismic Upgrade
23,685,177
5720296 sfr-48-Mission Sub: Rebuild
21,289,750
5719039 McCloud-Pit FERC 2106 Relicense
20,833,836
5719538 Drum Spaulding Relicensing
18,961,043
5721919 Atlantic Lincoln Transmission Project
17,641,376
5726013 Mission Rebuild 115Kv Bus
17,625,620
5717079 Palermo-Rio Oso 115kV Line Capacity
16,865,255
5735278 COM:License Renewal Application Review
15,825,916
5716718 DeSabla Centerville Relicensing
15,470,952
5737558 Photovoltaic 250MW Program, (Construct and Design)
14,448,816
5735925 NaS Battery Installation
12,789,464
5701979 Poe Hydroelectric FERC 2107 Relicense
11,900,581
5715260 ESO Disaster Recovery Project
11,247,873
5727460 Humboldt Bay Generation Station
11,070,373
5718947 Rock Creek Upgrade Units
10,545,669
5723300 Gregg Reactor Project
10,518,802
5727011 Arco Bank 1 Replace 115/70kV
9,855,699
5740318 Implement New Security Force on Force Requirements
8,908,171
5726998 Oakland C: Replace 115/12kV, 60 MVA Bank 2
8,387,689
5724300 Central Coast Reinforcement Project
8,189,358
5736118 Modify PA Boundary (IDS)
8,133,698
5721918 Hollister 115kV Line Reconductoring
8,099,082
5731638 Canada/Pac NW-Northern CA Transmission Project
7,678,149
5732298 Humboldt 115/60 kV Transformer Replacement
7,640,918
5738578 Fuel Cell Generators
7,341,892
5737398 Construct Manzana Wind Generating Station
7,338,252
5716260 Sacramento - Rio Oso-Colgate Raise Towers
7,272,786
5721879 Atlantic Lincoln Transmission Project
7,166,138
5733403 Unit 1:Replace Process Control (7100) Racks
7,017,200
5717285 Work Requested by Others Rule 20A - Mission
6,980,952
5728119 Geographic Information System Network Upgrades
6,581,655
5736540 Helms - Unit 1 Replace Wicket Gate Bushings
6,303,169
5736142 COM: Transition NFPA 805 License Basis
6,286,804
5715550 Pease-Marysville 60kV Line Conversion
5,842,309
5505341 Transmission Emergency Response
5,433,489
5726638 Panoche Sub: Install 230 kV MPAC
5,212,237
5739806 Eastshore 230/115 kV TX No. 2 Replacement
5,183,264
5717284 Work at the Request of Others Rule 20A - Los Padres
5,131,300
5735519 SmartMeter - November 2009 (Release H)
5,034,552
5725603 Glenn #2 60kV Reconductor
4,822,538
43 TOTAL 1,016,902,985
FERC FORM NO. 1 (ED. 12-87) Page 216

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Year/Period of Report
End of 2010/Q4
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Description of Project Construction work in progress -
Electric (Account 107)
(a)
(b)
5506561 System Breaker Replacement:230/115/60kV
4,804,174
5738002 Security Camera Infrastructure
4,690,481
5717038 Pease-Marysville 60kV Line Conversion
4,623,417
5721442 Mesa Substation: Install Distribution Bank
4,548,156
5720704 Pit 3 Dam Britton Powerhouse
4,547,469
5735302 Garberville SVC Installation
4,445,213
5735620 SmartMeter - June 2010 (Release I)
4,433,750
5732791 San Mateo sub-convert 115kV bus to BAAH
4,426,278
5738903 Henrietta-McCall 230 kV Reconductor
4,396,629
5730181 Sanger-Reedley Reconductoring
4,384,275
5706038 Chili Bar Relicense FERC 2155
4,377,256
5729886 Carolands: Replace Bank #2
4,173,662
5704040 Poe U2 Replace Runner
4,156,701
5737279 Smart Meter - BP (Read2Bill Except Hndlng Assess)
4,134,451
5733378 Big River SVC Installation
4,106,485
5738897 Helm-McCall 230 kV Reconductoring
4,059,462
5717292 Work Requested by Others Rule 20A - San Jose
4,051,996
5729893 San Leandro “U”: Replace Bank #1
4,045,398
5738895 Panoche-Helm 230 kV Reconductoring
4,012,765
5720667 Pit 3 Unit 1 Rewind
4,005,388
5731106 Cooley Landing 115/60kv Transformers Bank 1
3,927,794
5733720 COM:Install Intake Bar Rack Raking System
3,920,183
5720787 Kilarc-Cow License Surr Relicensing
3,902,640
5729890 Daly City: Replace Bank #1
3,806,639
5726798 Madera Sub: Convert 70 kV to Ring Bus
3,763,304
5727000 Belmont Sub:Replace 115/12kV, 45 MVA Bank1
3,741,998
5700287 RCC LC- Water Temperature Control
3,733,843
5713559 East Grand Sub: Replace Bank1 115/12-2x45MVA
3,675,690
5733784 San Mateo 230 kV ECC Auto
3,674,063
5725599 Cabrillo-Santa Ynez 115kV Reconductor
3,656,951
5732660 Daly City 115KV Bus Reconfiguration
3,618,779
5717278 Work at the Request of Others Rule 20A - Central Coast
3,563,790
5725600 Atascadero-San Luis Obispo 70kV Reconductoring
3,550,606
5728039 Access and Badging
3,451,279
5726860 Relief Dam L.L. Draft Valves
3,416,067
5738899 Panoche-McMullin 230 kV Reconductor
3,402,357
5509699 08D Cornerstone Reclosers
3,342,888
5505597 Work at the Request of Others Non-Reimb.-Mission
3,341,729
5724098 SmartMeter-System Integration & Test
3,316,004
5506315 Yard Improvements
3,251,893
5735439 SA-Synchronized-phasor technology demo
3,238,812
5726502 Purchase 115-17kV 45 MVA +/- 15% LTC
3,199,496
43 TOTAL 1,016,902,985
FERC FORM NO. 1 (ED. 12-87) Page 216.1

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Year/Period of Report
End of 2010/Q4
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Description of Project Construction work in progress -
Electric (Account 107)
(a)
(b)
5721839 Woodside Sub: Replace Bank 1
3,169,391
5729177 Sierra Lincoln: Replace Bank #2
3,120,406
5732653 Marysville - Plumas Re-conductor
3,114,881
5737999 NRC Force on Force Items
3,070,841
5717295 Work at the Request of Others Rule 20A - Yosemite
3,038,744
5736438 SmartMeter - Peak Time Rebate (PTR)
3,021,972
5733680 COM:FWST 0-1 Internal Refurbishing & Pipe Repladement
3,000,253
5733750 Replace Auxiliary Board Phase 4A
2,956,133
5734859 Condition Based Maintenance implementation, Transmission Substation
2,941,967
5738905 Chowchilla-Le Grand 115 kV Reconductor
2,844,779
5705779 Relicense Transmission Lines
2,840,176
5507682 Replace Deteriorated Boardwalks
2,834,776
5729887 Cassidy: Replace Bank #1
2,789,344
5721938 Holdover Permit Project
2,777,821
5731721 South Coast - Burns Sub Reliability
2,770,181
5732690 Sobrante MPAC
2,676,015
5717280 Work at the Request of Others Rule 20A - Diablo
2,673,162
5728078 Helms - Replace Relays
2,534,756
5737463 Smart Meter - Restoration Validation (Release G)
2,518,854
5732697 Sanger 115 kV MPAC
2,515,856
5738458 Los Banos 230 kV MPAC
2,501,132
5737919 Midway Sub: Bank 1 Replacement Upgrades
2,497,921
5734604 Valley Springs 230/60 kV MPAC
2,477,577
5733785 Ignacio - 230kV MPAC
2,471,463
5740698 Bellota 230 kV MPAC
2,432,125
5506659 Permit Project
2,397,024
5731264 Midway - Replace Circuit Switchers W/ 500kV Circuit Breakers
2,327,319
5733058 Tri-Valley Voltage Control
2,309,979
5732778 Purch 1ph 40MVA230-115x70x60 Mobile
2,266,664
5735119 South Valley - Henrietta 70 kV Bus
2,180,416
5732721 East Bay - Elk Creek 60kV Tap
2,174,684
5740338 San Leandro U: Emergency Replace Bank
2,139,126
5726301 U2:Replace SPDS System
2,083,100
5721854 Napa Sub: Install Bnk # 3 and Feeder
2,082,571
5734022 Replace Vaca-Dixon Bank #6
2,077,621
5728905 Sacramento - Hartley Sub: Install 6
2,053,435
5717289 Work at the Request of Others Rule 20A - Peninsula
1,994,680
5733412 U1:Replace SPDS System
1,987,442
5737141 Transbay Transit Center Electric Relocation
1,965,350
5506639 Distribution Mobile Replacement Program
1,956,772
5738573 Replace failed Mobile T-45.0-8, purch 45MVA
1,949,446
5733408 DCPP Unit 1:Upgrade Polar Crane Control Systems
1,932,521
43 TOTAL 1,016,902,985
FERC FORM NO. 1 (ED. 12-87) Page 216.2

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Year/Period of Report
End of 2010/Q4
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Description of Project Construction work in progress -
Electric (Account 107)
(a)
(b)
5738901 McMullin-Kearney 230 kV Reconductor
1,925,226
5733245 Trans Rep Wood Poles_EPC Contract
1,913,611
5737998 COM:Unattended Pathway
1,855,248
5722499 Fort Ord Substation, Bus Regulator
1,852,422
5726809 Atwater Bank 1 115kv-12kv, 45 MVA LTC
1,843,819
5735945 Madera MPAC
1,833,353
5734001 Henrietta Sub: Install New Bank
1,825,225
5736134 Tulare Lake Sub: Inst new Bank
1,797,171
5506253 JIT Replace Transformers
1,796,299
5733990 Glenn Sub: Install Bank 3
1,789,743
5731018 Tesla - Salado - Manteca 115 kV Reconductor
1,771,507
5722558 DeSabla Philbrook Refurb. Spill Channel
1,768,838
5727142 Belmont Sub:Repl 115-12kV Bank2
1,748,951
5506282 JIT Replace Miscellaneous Equipment
1,743,488
5733504 Divide 115 kV MPAC
1,741,198
5733513 Bellota 115 kV MPAC
1,736,693
5505580 Work at the Request of Others Partially Reimb.-CC
1,684,865
5732691 Brighton 115 kV MPAC
1,670,426
5724539 Helm - Replace Exciters
1,663,941
5503191 Mission-City Reliability
1,610,092
5717279 Work at the Request of Others Rule 20A - De Anza
1,579,302
5724399 Drum 1&2 Penstock Tunnel Replacement
1,568,726
5733929 Replace Clayton Bank #1 and new feeder
1,550,034
5732978 Sacramento-Caribou#1 60kVBusRecon&SCADAIns
1,543,407
5732986 Moss Landing: convert 230 kV bus to BAAH
1,542,536
5729171 Yosemite Madera: Install Bank/Feeder
1,538,937
5733803 Pease Sub: Repl Failed Reg #2
1,530,445
5738220 Wheeler Ridge 70 kV MPAC
1,503,886
5738000 COM:Last Access Control
1,499,144
5733933 Instll Nortch Bnk#2 for Cisco Sys Exp
1,493,031
5707549 Windsor Sub: Land (Fulton DPA)
1,489,917
5727860 U1:Replace Eagle-21 System (I&COM)
1,438,277
5720874 Balch 2 U3 Replace Exciter
1,431,518
5720780 Pit 345 LC Recreation
1,428,387
5726838 U1:Mod Control Room Ventilation
1,428,291
5724538 Helms - Replace Governors
1,414,391
5739631 BURNS 60/24 KV, 10 MVA, BK 1 Emerge
1,410,711
5738728 Cottle MPAC 230kv
1,407,339
5732985 Moss Landing: convert 115 kV bus to BAAH
1,395,097
5730184 Wheeler Ridge 230/70 kV Transfor Install
1,363,754
5731362 Hydro SCADA - Life Cycle Replacement
1,363,482
5726618 Newark-Ravenswood 230kV Reconductor
1,361,372
43 TOTAL 1,016,902,985
FERC FORM NO. 1 (ED. 12-87) Page 216.3

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Year/Period of Report
End of 2010/Q4
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Description of Project Construction work in progress -
Electric (Account 107)
(a)
(b)
5723320 ED-EOO-Fresno Control Center Rel.-Fac
1,321,119
5736541 Helms - U2 Repl. Wicket Gate Bushings
1,317,589
5738592 Ripon 115kV MPAC
1,316,679
5733925 46-Replace Konocti Bank #1
1,313,559
5736401 Centerville Rebuild TSV & Wickets
1,302,032
5728898 Pittsburg-Tesla 230 kV Reconductoring
1,285,228
5738301 Gill Ranch Transmission
1,249,400
5507181 SA-60-230 KV Protection Relays Replacements
1,246,909
5738059 09-2010 MRTU projects
1,236,539
5735941 Cooley Landing MPAC
1,222,032
5509219 Pole Replacement - North Region
1,220,557
5508934 Cable Replacement - ERR - Diablo
1,210,273
5503196 Diablo-City Reliability
1,198,450
5732728 Humboldt Sub: 60 kV BAAH in GIS
1,198,118
5733840 Livingston 115 kV MPAC
1,193,549
5738574 Wheeler Ridge 230/115 kV MPAC
1,189,682
5726604 Humboldt Sub - 60 kV MPAC
1,169,372
5732722 Sacramento - Nicolaus-Wilkins Slough 60kV
1,142,356
5738593 Sneath Lane 60 kV MPAC
1,113,900
5737462 Reclamation District 2047: Replace Bank 1
1,107,642
5733783 San Mateo 115 kV ECC Auto
1,104,245
5719003 Spring Gap St LC-SandBar Dam Fish Scrns
1,103,202
5734791 COM:Upgrade EP Dose Assessment-MIDA
1,095,804
5738362 Fort Ord 60 kV MPAC
1,090,805
5507179 SA-Install SCADA/RTUs
1,078,065
5721863 San Benito Sub: Install Bank 1
1,052,465
5507683 Replace UG Pumping Stations
1,050,212
5507699 Rebuild Transmission Line
1,047,400
5720779 Battle Cr Salmon/Steelhead Phase 1
1,040,599
5737658 East Grand - Bank 1 115kV Bus Upgrade
1,040,405
5729482 06-2008 Lockheed New 12kV Feeder Net App
1,026,765
5730478 McCloud Dam LLO Improvements
1,021,956
Aggregate total of projects with less than $1,000,000 in actual costs in CWIP
172,231,406
43 TOTAL 1,016,902,985
FERC FORM NO. 1 (ED. 12-87) Page 216.4

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line
No.
Item
(a)
Section A. Balances and Changes During Year
Total
Electric Plant in
(c+d+e)
Service
(b)
(c)
Electric Plant Held
for Future Use
(d)
Electric Plant
Leased to Others
(e)
1 Balance Beginning of Year
17,533,279,224 17,533,279,224
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense
1,003,132,970 1,003,132,970
4 (403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. Plt. Leas. to Others
6 Transportation Expenses-Clearing
7 Other Clearing Accounts
8 Other Accounts (Specify, details in footnote):
9 Reverse Common Allocation
-109,080,147 -109,080,147
10 TOTAL Deprec. Prov for Year (Enter Total of
894,052,823 894,052,823
lines 3 thru 9)
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired
331,047,376 331,047,376
13 Cost of Removal
156,136,900 156,136,900
14 Salvage (Credit)
16,747,378 16,747,378
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
470,436,898 470,436,898
of lines 12 thru 14)
16 Other Debit or Cr. Items (Describe, details in
59,910,182 59,910,182
footnote):
17
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1,
18,016,805,331 18,016,805,331
10, 15, 16, and 18)
Section B. Balances at End of Year According to Functional Classification
20 Steam Production
244,221,285 244,221,285
21 Nuclear Production
5,531,425,530 5,531,425,530
22 Hydraulic Production-Conventional
1,154,107,951 1,154,107,951
23 Hydraulic Production-Pumped Storage
794,066,870 794,066,870
24 Other Production
19,245,748 19,245,748
25 Transmission
1,980,212,002 1,980,212,002
26 Distribution
7,779,678,286 7,779,678,286
27 Regional Transmission and Market Operation
28 General
513,847,659 513,847,659
29 TOTAL (Enter Total of lines 20 thru 28)
18,016,805,331 18,016,805,331
FERC FORM NO. 1 (REV. 12-05)
Page 219

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 219 Line No.: 12 Column: c
This reconciles with the cost of plant retired shown on pages 204-207, column d, as
follows:
Book cost of depreciable plant
retired
331,047,376
Rounding (1)
Total 331,047,375
Schedule Page: 219 Line No.: 16 Column: c
This consists of the following:
Decommissioning reclass to Regulatory Liability
(Nuclear & Fossil)
10,942,439
FAS 143 Assets Depreciation (Nuclear & Fossil) 17,809,043
FIN 47 Asset Depreciation (EDP, EHP, ETP) (853,676)
Capital Lease Obligations 31,976,896
Fleet A/D Reclass from Common (85,640)
Mirant Reclass 2,059,472
Gain or Loss (3,466,454)
Adjustment to prior year's amount 1,528,102
Total 59,910,182
Schedule Page: 219 Line No.: 28 Column: c
FAS 109 gross-up on Diablo Canyon Power Plant Utility Asset I is included in General
Plant.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Description of Investment
(a)
Date Acquired
(b)
Date Of
Maturity
(c)
Year/Period of Report
End of 2010/Q4
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
Calaska Energy Company
Common Stock
Additional Paid in Capital
Undistributed Earnings
SUBTOTAL
Eureka Energy Company
Common Stock
Additional Paid in Capital
Undistributed Earnings
SUBTOTAL
Natural Gas Corporation of California
Common Stock
Additional Paid in Capital
Undistributed Earnings
SUBTOTAL
Pacific Conservation Services Company
Common Stock
Undistributed Earnings
SUBTOTAL
Pacific Gas Properties Company
Common Stock
Additional Paid in Capital
Undistributed Earnings
SUBTOTAL
Pacific Energy Fuels Company
Common Stock
Undistributed Earnings
SUBTOTAL
1978
1978
1954
1982
1988
1989
Amount of Investment at
Beginning of Year
(d)
1,000
17,240,668
-18,448,826
-1,207,158
1,000
4,000,000
397,901
4,398,901
100,000
10,618,000
-3,148,217
7,569,783
10,000
150,057
160,057
10,000
10,000
-10,698,496
-10,678,496
10,000
-1,282,110
-1,272,110
42 Total Cost of Account 123.1 $ 38
TOTAL 133,708,094
FERC FORM NO. 1 (ED. 12-89) Page 224

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Description of Investment
(a)
Date Acquired
(b)
Date Of
Maturity
(c)
Year/Period of Report
End of 2010/Q4
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
Standard Pacific Gas Line Incorporated
Common Stock
Additional Paid in Capital
Undistributed Earnings
Advances: Note
Note
Note
Note
Note
Note
Note
Less: Accumulated Gas Line Depreciation
SUBTOTAL
PG&E Energy Recovery Funding LLC
Additional Paid in Capital
Undistributed Earnings
SUBTOTAL
PG&E Housing Fund
Additional Paid in Capital
Undistributed Earnings
SUBTOTAL
Midway Power LLC
Additional Paid in Capital
Undistributed Earnings
SUBTOTAL
1930-32
1954
05-09-88
09-06-88
12-30-88
08-22-89
10-09-90
02-25-92
12-01-93
2004
2004
2008
Demand
Demand
Demand
Demand
Demand
Demand
Amount of Investment at
Beginning of Year
(d)
1,200
16,157,021
5,962,799
1,127,868
2,580,000
8,712,308
2,880,000
4,200,000
3,300,000
1,518,000
-26,659,988
19,779,208
28,629,378
47,652,526
76,281,904
45,206,278
-27,075,809
18,130,469
25,144,364
-4,598,828
20,545,536
42 Total Cost of Account 123.1 $ 38
TOTAL 133,708,094
FERC FORM NO. 1 (ED. 12-89) Page 224.1

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
Year/Period of Report
End of 2010/Q4
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
Equity in Subsidiary
Revenues for Year
Amount of Investment at Gain or Loss from Investment
Earnings of Year
(e) (f)
End of Year
(g)
Disposed of
(h)
Line
No.
1,000 2
17,240,668 3
-2,290 -18,451,116
4
-2,290 -1,209,448
6
1,000 9
4,000,000 10
175,898 573,799
11
175,898 4,574,799
13
100,000 16
10,618,000 17
7,087 -3,141,130
18
7,087 7,576,870
20
10,000 23
-829 149,228
24
-829 159,228
26
10,000 29
10,000 30
-12,405 -10,710,901
31
-12,405 -10,690,901
33
10,000 36
273,926 -1,635,005
37
273,926 -1,625,005
39
1
5
7
8
12
14
15
19
21
22
25
27
28
32
34
35
38
40
41
-17,426,049 115,151,066
42
FERC FORM NO. 1 (ED. 12-89) Page 225

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
Year/Period of Report
End of 2010/Q4
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
Equity in Subsidiary
Revenues for Year
Amount of Investment at Gain or Loss from Investment
Earnings of Year
(e) (f)
End of Year
(g)
Disposed of
(h)
Line
No.
1,200 2
16,157,021 3
-112,424 5,850,375
4
1,127,868 5
2,580,000 6
8,712,308 7
2,880,000 8
4,200,000 9
3,300,000 10
1,518,000 11
-27,304,974 12
-112,424 19,021,798
14
28,629,378 17
-6,616,434 41,036,092
18
-6,616,434 69,665,470
20
45,259,041 23
-1,107,424 -28,183,233
24
-1,107,424 17,075,808
26
25,232,429 29
-10,031,154 -14,629,982
30
-10,031,154 10,602,447
32
1
13
15
16
19
21
22
25
27
28
31
33
34
35
36
37
38
39
40
41
-17,426,049 115,151,066
42
FERC FORM NO. 1 (ED. 12-89) Page 225.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
This Report Is:
(1) X An Original
(2) A Resubmission
MATERIALS AND SUPPLIES
Date of Report
(Mo, Da, Yr)
04/08/2011
Account Balance Balance
Beginning of Year
End of Year
(a)
(b)
(c)
Year/Period of Report
End of
2010/Q4
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
1 Fuel Stock (Account 151)
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)
8 Transmission Plant (Estimated)
9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)
403,420 1,143,343 ELECTRIC
52,187,387 53,670,031 ALL
62,003,539 62,734,627 ALL
8,973,421 8,622,223 ALL
76,369,854 80,176,065 ALL
199,534,201 205,202,946
199,937,621 206,346,289
Department or
Departments which
Use Material
(d)
FERC FORM NO. 1 (REV. 12-05)
Page 227

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
Transmission Service and Generation Interconnection Study Costs
7. In column (e) report the account credited with the reimbursement received for performing the study.
Line
Costs Incurred During
No.
Description
Period
Account Charged
(a)
(b)
(c)
Reimbursements
Received During
the Period
(d)
Year/Period of Report
End of 2010/Q4
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
Transmission Studies
TOTAL TRANSMISSION STUDIES
(See details in the footnotes) 97,078 186 100,000 186
Generation Studies
TOTAL GENERATION STUDIES
(See details in the footnotes) 2,255,086 186 2,491,895 186
GRAND TOTAL 2,352,164
2,591,895
Account Credited
With Reimbursement
(e)
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 231 Line No.: 25 Column: a
The FERC format for page 231 requires the reporting of costs incurred and reimbursements received during the
period. The additional information below summarizes the balances and activities of each study cost from
December 31, 2008 through December 31, 2009
Cost Reimburse- Net
Incurred ments Activity
Balance in Period Received Period Balance in
Acct 186 Ended Period Ended Ended Acct 186
Description at 12/31/09 12/31/10 12/31/10 12/31/10 12/31/10
TRANSMISSION STUDIES
9710341 WL-City of Roseville System Impact Study (19,928) 0 0 0 (19,928)
9712247 WL-Red Bluff 6-MW Reclamation Pump Plant 3,505 12,606 0 12,606 16,111
9712380 WL-Kirkwd Meadows PUD Interconnect-SIS 3,118 33,228 30,000 3,228 6,346
9712460 WL-Hercules Muni Utl Inter-SIS 1,038 24,179 0 24,180 25,218
9712982 WL - Tesla Tracy 230kV Line 1 Reloc-SIS 0 3,703 40,000 (36,297) (36,297)
9713185 WG - LMUD Susanville Biomass Project-SIS 0 13,280 30,000 (16,720) (16,720)
9713260 WL - Hercules Muni Utilities Inter-FAS 0 571 0 571 571
9713955 WL - Tesla Tracy 230kV Line 1 Reloc-FAS 0 8,072 0 8,072 8,072
9714755 WL - KMPUD-IFAS 0 1,439 0 1,439 1,439
Total Transmission Studies (12,267) 97,078 100,000 (2,921) (15,188)
GENERATION STUDIES
9710020 WG-JG Boswell (Rule 21) DI Study (11,453) 0 0 0 (11,453)
9710302 WG-Inergy Propane (Rule 21) DI Study (27,609) 0 0 0 (27,609)
9710360 WG-USE Powerflow, Base Cases & Conting. 50,400 0 0 0 50,400
9710361 WG-Viasyn Stability Study (ISIS) 12,400 0 0 0 12,400
9710382 WG-Western GeoPower Unit 1 - IFAS 54,901 0 0 0 54,901
9710481 WG-Cal Poly - DIS (Rule 21) (17,545) 0 0 0 (17,545)
9710603 WG-Bear River Ridge - IFAS 27,951 0 27,951 (27,951) 0
9710641 WG- Jacob Canal Project- Sys. Imp. Study 21,649 0 21,649 (21,649) 0
9710683 Atwell Island PV Solar IFS 42,600 0 42,600 (42,600) 0
9710687 WG - Stockton Generation IFAS 19,358 0 19,358 (19,358) 0
9710688 WG - Stockton Generation Expansion IFAS 8,190 0 8,190 (8,190) 0
9710741 WG-Navigant Third Party Study Support 1,962 0 0 0 1,962
9710764 WG-Laurel East ISIS 9,783 0 9,783 (9,783) 0
9710766 WG-Laurel West - ISIS 9,731 0 9,731 (9,731) 0
9710780 WG-California PV IFAS 44,124 0 44,124 (44,124) 0
9710861 WG-Alpaugh North - ISIS 110,767 91,760 0 91,760 202,527
9710862 WG-Carrizo Plain - IFAS 14,917 0 14,917 (14,917) 0
9710980 WG-Transition Cluster Projects-Phase 1 584,529 100,493 708,684 (608,191) (23,662)
9711082 WG-Redwood Landfill Project ISI Study 12,640 9,030 12,640 (3,610) 9,030
9711360 WG-Ameresco Butte Landfill Prj.Scope Mtg 11,490 0 0 0 11,490
9711361 WG-KRCD - 2nd ISIS Re-study 12,107 0 0 0 12,107
9711402 Santa Cruz Landfill (10,000) 0 0 0 (10,000)
9711404 WG-Rio Bravo Status Eval.Prj. CLAP Calc. (1,777) 0 0 0 (1,777)
9711450 Recurrent Energy - PV - Sunset Reservoir (5,000) 0 (5,000) 5,000 0
9711461 WG-Corcoran PV ISIS Study 15,512 2,410 17,922 (15,512) 0
9711480 Antelope Sub PV (81) 0 (81) 81 0
9711481 Blackwell Sub PV 2,799 0 2,799 (2,799) 0
9711500 WG-White River PV Project - Scoping Mtg. 268 0 268 (268) 0
9711501 WG-White River PV Project - ISIS Study 21,217 1,416 22,634 (21,218) (1)
9711563 WG-Ameresco Butte County project - IFAS 6,128 0 0 0 6,128
9711580 Bena Landfill (698) 0 (698) 698 0
9711620 WG-EE Support-Contra Costa Gen.Station 12,603 2,683 30,000 (27,317) (14,714)
9711621 G2 Energy, Ostrom Rd - Addt'l Gen 1,432 0 0 0 1,432
9711622 City of Santa Cruz - Newell Creek Dam (2,500) 0 (2,500) 2,500 0
9711660 Delfern Project 2,754 0 2,754 (2,754) 0
9711680 Recurrent Energy - PV - Sunset Reservoir (2,500) 0 (2,500) 2,500 0
9711681 J&A - Santa Maria II, LLC (3,391) 0 (3,391) 3,391 0
9711682 Cymric Project 1,547 0 1,547 (1,547) 0
9711720 WG-Alpaugh North Project - IFAS 8,079 0 8,079 (8,079) 0
9711820 WG-Buena Vista Re-Powering Prj.Scop.Mtg. 3,455 0 3,455 (3,455) 0
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
9711821 WG-Buena Vista Re-Powering Project ISIS 10,887 2,730 10,887 (8,157) 2,730
9711840 Salinas Valley Solid Waste Authority (6,116) 778 0 778 (5,338)
9711860 Avenal Land LLC (10mW PV Project) 2,544 0 0 0 2,544
9711861 Facility Study (213) 0 (213) 213 0
9711880 WG-20MW Solar Project#3-ISIS (11,293) 6,070 0 6,070 (5,223)
9711920 WG-Hatchel Ridge Wind Farm Project -SAIS 3,133 0 0 0 3,133
9711922 WG-Montezuma (High Winds III) - AIS 3,096 0 0 0 3,096
9711960 WG-Lost Hills Solar project -SM 14,914 0 14,914 (14,914) 0
9711980 WG-Atwell Island PV Solar Gen Stn -IFAS 9,291 0 9,291 (9,291) 0
9712000 G2 Energy LLC (Hay Road) (5,000) 1,891 0 1,891 (3,109)
9712020 enXco - Merced Falls (SIS) (5,000) 5,678 678 5,000 0
9712021 enXco - Madera (SIS) (5,000) 8,464 3,464 5,000 0
9712022 enXco - Goose Lake 17,347 6,611 23,958 (17,347) 0
9712023 enXco - Smyrna 12,333 6,892 20,225 (13,333) (1,000)
9712024 Kirby Canyon (5,866) 899 0 899 (4,967)
9712025 Tri Cities (6,000) 0 0 0 (6,000)
9712040 enXco - Smyrna - T 9,896 9,032 19,928 (10,896) (1,000)
9712061 Atwell West PV Solar Gen Facility-ISIS 1,504 8,326 0 8,326 9,830
9712062 Twisselman - SIS (1,000) 14,965 5,000 9,965 8,965
9712064 WG-20MW Solar Project#6-ISIS (21,996) 5,020 0 5,020 (16,976)
9712065 WG-Arco I Solar Project - ISIS 1,755 7,717 0 7,717 9,472
9712080 WG-Arco Solar I Project - Scoping Mtg 2,049 0 2,049 (2,049) 0
9712100 Placer County Water Agency (301) 0 (301) 301 0
9712101 BADGER CREEK DEVELOPMENT 9,542 0 0 0 9,542
9712120 J&A - SANTA MARIA II, LLC (500) 500 0 500 0
9712140 BLACKWELL - Facility Impact Study (5,000) 0 0 0 (5,000)
9712141 LOST HILLS SOLAR PROJECT - ISIS 15,601 9,026 17,697 (8,671) 6,930
9712160 KRCD Community Power Plant - IFAS Re-Stu 5,924 0 0 0 5,924
9712180 BiDart Diary - SIS (1,778) 2,556 778 1,778 0
9712220 SOLAR POWER PARTNERS INC - System Impact (3,357) 6,161 2,805 3,356 (1)
9712240 WG-Buena Vista Biomass Project-IFAS 22,326 2,786 25,113 (22,327) (1)
9712241 WG-Corcoran PV 20 MVA Gen Facility-IFAS 0 5,552 5,552 0 0
9712242 WG-Jacob Canal Solar Farm-IFAS 13,291 1,454 14,648 (13,194) 97
9712243 WG-Laurel West Solar Farm-IFAS 5,046 0 5,046 (5,046) 0
9712244 WG-Laurel East Solar Farm-IFAS 5,623 0 5,623 (5,623) 0
9712245 WG-Cluster 1 Projects-Phase I 21,870 120,914 0 120,914 142,784
9712246 WG-Transition Cluster Project-Phase II 22,068 335,982 0 335,982 358,050
9712248 Rio Bravo WDT - Feasibility 1,819 770 2,589 (1,819) 0
9712272 enXco - ELK HILLS - EVANS (Feasibility) (1,000) 0 0 0 (1,000)
9712273 enXco - SAN BERNARD (Feasibility) (1,000) 0 (1,000) 1,000 0
9712274 ORO LOMA T (SIS) (8,500) 11,570 3,070 8,500 0
9712275 ORO LOMA (SIS) (8,500) 10,534 2,034 8,500 0
9712276 FIREBAUGH (SIS) (8,500) 6,959 (1,541) 8,500 0
9712321 WG-Redwood Landfill-IFAS 2,466 21,206 23,673 (2,467) (1)
9712340 White River PV 20MVA Solar Gen-IFAS 0 5,311 5,311 0 0
9712341 Atwell West PV Solar Gen-IFAS 649 6,947 7,596 (649) 0
9712342 EE Avenal 20MW Solar #3-IFAS 1,168 23,233 25,000 (1,767) (599)
9712343 EE Avenal 20MW Solar #6-IFAS 779 14,192 25,000 (10,808) (10,029)
9712400 BioVerde BVE Rosina 1 279 (279) 0 (279) 0
9712401 BioVerde BVE Rosina 2 (1,000) 1,000 0 1,000 0
9712402 BioVerde Corcoran (1,000) 1,000 0 1,000 0
9712403 BioVerde San Joaquin Bycad (824) 824 0 824 0
9712404 BioVerde Kettleman City 1 (West) [SIS] (1,000) 1,000 0 1,000 0
9712405 BioVerde Kettleman City 2 (East) (824) 824 0 824 0
9712406 BioVerde Cloverdale Dairy (379) 379 0 379 0
9712407 BioVerde Lansing Dairy (119) 119 0 119 0
9712408 BioVerde Red Top [SIS] (736) 0 9,961 (9,961) (10,697)
9712409 BioVerde BMY Tranquility (161) 161 0 161 0
9712420 Tri Cities (SIS) (5,000) 0 0 0 (5,000)
9712421 BiDart (Feasibility) (5,000) 0 0 0 (5,000)
9712540 enXco Schindler B (Feasibility) (606) 606 0 606 0
9712541 enXco Blackwell (Feasibility) (1,000) 0 0 0 (1,000)
9712560 Solarpack Le Grand (SIS) (329) 6,680 6,351 329 0
9712562 WG-Acacia Solar Gen Fac-SIS 389 8,629 9,019 (390) (1)
9712563 WG-Blkwell Solar 1 Gen Fac-SM 519 0 519 (519) 0
9712564 WG-Blkwell Solar 1 Gen Fac-SIS 1,912 24,585 0 24,585 26,497
FERC FORM NO. 1 (ED. 12-87) Page 450.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
9712566 WG-Old River 1 Gen Fac-SIS 1,688 7,724 9,413 (1,689) (1)
9712568 WG-Old River 2 Gen Fac-SIS 1,688 7,280 8,968 (1,688) 0
9712570 WG-Wagon Wheel Mt Solar 1 Gen Fac-SIS 2,450 12,698 15,148 (2,450) 0
9712571 WG-Westside Solar 20MW Gen Fac-SM 1,558 0 1,558 (1,558) 0
9712572 WG-Westside Solar 20MW Gen Fac-SIS 1,428 10,007 11,435 (1,428) 0
9712573 WG-Quay Valley 20MW Solar PV Gen Fac-SM 3,115 0 3,115 (3,115) 0
9712574 WG-Quay Valley 20MW Solar PV Gen Fac-SIS 0 9,005 0 9,005 9,005
9712576 WG-Whitney Point Solar-SIS 909 16,526 17,435 (909) 0
9712577 WG-Wellhead Renewables Frsno Gen Fac-SM 0 2,612 2,612 0 0
9712578 WG-Wellhead Renewables Frsno Gen Fac-SIS 0 3,996 0 3,996 3,996
9712579 WG-White Ranch Solar-SM 1,039 267 1,306 (1,039) 0
9712580 WG-White Ranch Solar-SIS 0 1,874 1,874 0 0
9712581 WG-Angiola Water District Solar-SM 1,039 401 1,440 (1,039) 0
9712582 WG-Angiola Water District Solar-SIS 0 13,521 13,521 0 0
9712601 BioVerde Vander Woude Dairy [SIS] (870) 0 9,961 (9,961) (10,831)
9712681 WG-Carizzo Plain Solar-AIS 0 15,042 0 15,042 15,042
9712700 WG-Buttonwood Solar - Scoping Meeting 909 0 909 (909) 0
9712701 WG-Buttonwood Solar - SIS 519 1,071 1,590 (519) 0
9712702 WG-Panoche Valley Solar Farm-SM 260 0 0 0 260
9712703 WG-Panoche Valley Solar Farm-SIS 0 19,309 0 19,309 19,309
9712704 WG-Avenal 9 MW Solar SIS 1,038 9,995 40,000 (30,005) (28,967)
9712710 WG-FRV Vega Solar - SIS 0 17,749 0 17,749 17,749
9712720 Guadalupe Landfill (SIS) 0 1,156 3,000 (1,844) (1,844)
9712761 WG-Hudson Solar Project - Scoping Mtg 0 566 566 0 0
9712762 WG-Hudson Solar Project - SIS 0 14,234 0 14,234 14,234
9712920 WG-Lompoc Wind Power Project - ISIS 0 9,863 0 9,863 9,863
9712922 WG-Sweetwater PV 20 MVA Slr Gen Stn-SIS 0 9,762 9,762 0 0
9712924 WG-Premier Power Russell Solar-SIS 0 8,374 0 8,374 8,374
9712925 WG-CAL SP V - Scoping Meeting 0 1,120 543 577 577
9712926 WG-CAL SP V - SIS 0 16,676 16,676 0 0
9712928 WG-Stanislaus PV (Phase1) - SIS 0 16,537 16,537 0 0
9712931 WG-Lost Hills Solar Generation - FAS 0 5,597 0 5,597 5,597
9713021 WG - FRV Centuri Solar - SIS 0 9,646 0 9,646 9,646
9713022 WG - Excelsior Solar-Scoping Meeting 0 700 700 0 0
9713023 WG - Excelsior Solar-SIS 0 15,520 0 15,520 15,520
9713024 WG - Schindler South Project-Scoping Mtg 0 134 134 0 0
9713025 WG - Schindler South Project-SIS 0 13,696 0 13,696 13,696
9713026 WG - Brannon Solar - Scoping Mtg 0 1,086 1,086 0 0
9713105 WG - Sun Harvester Solar - Scoping Mtg 0 803 803 0 0
9713106 WG - Sun Harvester Solar - SIS 0 9,698 0 9,698 9,698
9713107 WG - FRV Cygnus Solar - Scoping Meeting 0 577 577 0 0
9713111 WG - Fairfax Solar - Scoping Meeting 0 1,354 1,354 0 0
9713112 WG - Fairfax Solar - SIS 0 874 0 874 874
9713113 WG - Placer Solar - Scoping Meeting 0 1,658 1,658 0 0
9713114 WG - Placer Solar - SIS 0 10,017 0 10,017 10,017
9713115 WG - Three Rocks Solar - Scoping Meeting 0 1,086 1,086 0 0
9713116 WG - Three Rocks Solar - SIS 0 4,086 0 4,086 4,086
9713117 WG - Cluster 2 Phase 1 0 178,814 0 178,814 178,814
9713140 WG - Wellhead Renewables-Feasibility 0 5,136 536 4,600 4,600
9713182 WG - El Peco Solar Farm-Scoping Mtg 0 576 0 576 576
9713183 WG - El Peco Solar Farm-SIS 0 23,138 0 23,138 23,138
9713340 AEJ Trust (SIS) 0 353 0 353 353
9713364 WG - Crocker Solar Power-SM 0 2,122 2,122 0 0
9713365 WG - Crocker Solar Power-SIS 0 3,159 0 3,159 3,159
9713366 WG - Great Valley Solar-SM 0 1,364 1,364 0 0
9713367 WG - Great Valley Solar-SIS 0 15,033 0 15,033 15,033
9713368 WG - PV Rosina 1-SM 0 2,197 0 2,197 2,197
9713369 WG - PV Rosina 1-SIS 0 9,464 0 9,464 9,464
9713370 WG - Skunk Hollow-SM 0 1,479 1,479 0 0
9713371 WG - Skunk Hollow-SIS 0 8,240 0 8,240 8,240
9713372 WG - Jefferson Solar-SM 0 1,653 1,653 0 0
9713373 WG - Jefferson Solar-SIS 0 438 0 438 438
9713374 WG - Five Points Solar-SM 0 2,244 2,244 0 0
9713375 WG - Five Points Solar-SIS 0 303 0 303 303
9713423 Shiloh (SIS) 0 9,530 11,000 (1,470) (1,470)
9713480 WG - Copus Solar One Gen Fac-SM 0 455 455 0 0
FERC FORM NO. 1 (ED. 12-87) Page 450.3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
9713481 WG - Copus Solar One Gen Fac-SIS 0 9,869 0 9,869 9,869
9713482 WG - Lakeview Solar One Gen Fac-SM 0 152 152 0 0
9713483 WG - Lakeview Solar One Gen Fac-SIS 0 10,869 0 10,869 10,869
9713502 WG - FRV Orion Kern Solar Gen Fac-SM 0 877 877 0 0
9713503 WG - FRV Orion Kern Solar Gen Fac-SIS 0 13,555 0 13,555 13,555
9713504 WG - FRV Adobe Solar Gen Fac-SM 0 893 893 0 0
9713505 WG - FRV Adobe Solar Gen Fac-SIS 0 2,960 0 2,960 2,960
9713506 WG - Arco Solar 1 Project - IFAS 0 13,617 0 13,617 13,617
9713507 WG - Old River 1 Gen Fac-IFAS 0 10,554 0 10,554 10,554
9713511 WG - Quay Valley Solar PV Project-IFAS 0 11,078 0 11,078 11,078
9713512 WG - Westside Solar Project-IFAS 0 876 0 876 876
9713513 WG - Sweetwater PV Solar Gen Stn-IFAS 0 8,861 0 8,861 8,861
9713514 WG - Whitney Point Solar Project-IFAS 0 455 0 455 455
9713515 WG - Stanislaus PV Phase 1 Gen Fac-IFAS 0 15,807 0 15,807 15,807
9713580 Carrizo Plains (SIS) 0 20,597 0 20,597 20,597
9713581 Old River II WDT (SIS) 0 4,288 11,000 (6,712) (6,712)
9713582 Cuyama - Diamond PV-08 (SIS) 0 23,987 15,000 8,987 8,987
9713583 Stockdale - Diamond PV 07 (SIS) 0 5,100 15,000 (9,900) (9,900)
9713585 WG - Avenal Park-Facilities Study 0 2,591 35,000 (32,409) (32,409)
9713600 REP ENERGY - HOROWITZ PV (SIS) 0 546 4,000 (3,454) (3,454)
9713601 WG - Kettleman Solar Farm Gen-SM 0 758 758 0 0
9713602 WG - Kettleman Solar Farm Gen-SIS 0 6,716 0 6,716 6,716
9713603 WG - Sun Seeker Solar Enrgy Ctr-SM 0 303 303 0 0
9713604 WG - Sun Seeker Solar Enrgy Ctr-SIS 0 540 0 540 540
9713606 WG - Stratford Solar Farm Gen-SIS 0 6,666 0 6,666 6,666
9713607 WG - Salado Solar Generation Facility-SM 0 303 303 0 0
9713608 WG - Salado Solar Gen Facility-SIS 0 9,060 0 9,060 9,060
9713609 WG - Kamm Generation Facility-SM 0 725 725 0 0
9713610 WG - Kamm Generation Facility-SIS 0 6,267 0 6,267 6,267
9713611 WG - Adams East Gen Fac-SM 0 590 590 0 0
9713612 WG - Adams East Gen Fac-SIS 0 15,357 0 15,357 15,357
9713613 WG - San Joaquin 1-A Gen Fac-SM 0 405 0 405 405
9713615 WG - San Joaquin 2-A Gen Fac-SM 0 798 0 798 798
9713617 WG - Westlands Solar Farm PV1 Gen-SM 0 675 675 0 0
9713618 WG - Westlands Solar Farm PV1 Gen-SIS 0 11,115 0 11,115 11,115
9713619 E&B Resources (DIS) 0 3,018 6,000 (2,982) (2,982)
9713621 Kirby Canyon (Facility) 0 121 5,000 (4,879) (4,879)
9713622 BIG CREEK HYDRO (Protection/reliability) 0 24,586 31,825 (7,239) (7,239)
9713623 Rhodia (Relay Upgrade, Eng Review) 0 24,035 24,035 0 0
9713624 BIOVERDE - VLOT (SIS) 0 0 1,000 (1,000) (1,000)
9713625 BIOVERDE VANDER WOUDE II (Feasibility) 0 1,000 1,000 0 0
9713626 BIOVERDE - LAKESIDE DAIRY (Feasibility) 0 1,215 1,000 215 215
9713627 BIOVERDE - HOOGENDAM (Feasibility) 0 1,000 1,000 0 0
9713628 Solar Power Inc - Aerojet3 (Feasibility) 0 1,000 1,000 0 0
9713629 Solar Power Inc - Aerojet4 (Feasibility) 0 1,000 1,000 0 0
9713630 Solar Power Inc - Colusa (System Impact) 0 15,500 20,000 (4,500) (4,500)
9713631 Solar Power - Susanville (Feasibility) 0 1,000 1,000 0 0
9713632 Ortigalita Power Company (SIS) 0 3,392 5,000 (1,608) (1,608)
9713634 enXco - Santa Nella (SIS) 0 5,983 10,000 (4,017) (4,017)
9713635 enXco - Stone Corral (SIS) 0 6,744 7,500 (756) (756)
9713636 enXco - Giffen (SIS) 0 11,181 15,000 (3,819) (3,819)
9713637 enXco - Corcoran City (SIS) 0 5,705 16,000 (10,295) (10,295)
9713638 enXco - Corcoran Irrigation (SIS) 0 6,909 15,000 (8,091) (8,091)
9713639 enXco - Chowchilla Muller (SIS) 0 1,000 1,000 0 0
9713640 CENERGY POWER - BAXTER 1 (SIS) 0 6,598 7,500 (902) (902)
9713641 CENERGY POWER - ECK 2 (SIS) 0 5,158 7,500 (2,342) (2,342)
9713642 CENERGY POWER - NICKEL 1 (SIS) 0 7,168 7,500 (332) (332)
9713643 EID - TANK 7 HYDRO (SIS) 0 1,869 5,000 (3,131) (3,131)
9713644 enXco -Chowchilla Ora Muller (SIS) 0 1,164 1,000 164 164
9713645 Bakersfield Fuel and Oil (SIS) 0 7,241 11,000 (3,759) (3,759)
9713647 Kiara Solar (SIS) 0 8,314 11,000 (2,686) (2,686)
9713648 CITY AND CTY OF SF- SF SHORE PWR (DIS) 0 5,273 6,000 (727) (727)
9713649 Potrero Hills Egy Landfill (SIS) 0 4,345 15,000 (10,655) (10,655)
9713650 AEJ Trust (SIS) 0 9,926 11,000 (1,074) (1,074)
9713651 CENERGY POWER - ECK 1 (SIS) 0 1,000 1,000 0 0
9713652 CENERGY POWER - BAXTER 2 (SIS) 0 1,000 1,000 0 0
FERC FORM NO. 1 (ED. 12-87) Page 450.4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
9713653 Solar Power Inc - Red Bluff (SIS) 0 8,251 20,000 (11,749) (11,749)
9713654 enXco - Stone Corral R7 (SIS) 0 3,198 10,000 (6,802) (6,802)
9713655 enXco - Goose Lake Memo (SIS) 0 0 1,000 (1,000) (1,000)
9713656 enXco - San Bernard Delis (SIS) 0 1,020 10,000 (8,980) (8,980)
9713657 enXco - El Peco (SIS) 0 2,610 8,500 (5,890) (5,890)
9713658 enXco - Chowchilla LR Montgomery (SIS) 0 8,345 7,500 845 845
9713659 SR Solis - ROCKET SOLAR (SIS) 0 3,153 15,000 (11,847) (11,847)
9713660 Bakersfield Fuel and Oil 2 (SIS) 0 3,004 11,000 (7,996) (7,996)
9713741 CAL SP X (SIS) 0 0 11,000 (11,000) (11,000)
9713742 FRV CYGNUS (SIS) 0 5,750 11,000 (5,250) (5,250)
9713743 CAL SP XI (SIS) 0 96 11,000 (10,904) (10,904)
9713780 GSNA 6 (SIS) 0 0 1,000 (1,000) (1,000)
9713781 GSNA 7 (SIS) 0 0 1,000 (1,000) (1,000)
9713783 SR Solis Huron (SIS) 0 0 15,000 (15,000) (15,000)
9713820 FRV ORION II (SIS) 0 5,460 11,000 (5,540) (5,540)
9713903 BAP POWER - NICKEL 1 (Facility Study) 0 0 500 (500) (500)
9713941 WG - Grangeville Solar Farm Gen Fac-SIS 0 3,628 0 3,628 3,628
9713942 WG - CAL SP XII Gen Fac-SM 0 675 0 675 675
9713943 WG - CAL SP XII Gen Fac-SIS 0 1,423 0 1,423 1,423
9713944 WG - Kansas Gen Fac-SM 0 946 0 946 946
9713945 WG - Kansas Gen Fac-SIS 0 2,447 0 2,447 2,447
9713946 WG - Kansas South Gen Fac-SM 0 2,817 0 2,817 2,817
9713947 WG - Kansas South Gen Fac-SIS 0 936 0 936 936
9713948 WG - Jayne East Gen Fac-SM 0 1,764 0 1,764 1,764
9713949 WG - Jayne East Gen Fac-SIS 0 11,631 0 11,631 11,631
9713952 WG - Angiola Water Dist Solar-FAS 0 30,397 0 30,397 30,397
9713953 WG - Panoche Valley Solar Farm-FAS 0 18,099 0 18,099 18,099
9713954 WG - FRV Vega Solar-FAS 0 11,239 0 11,239 11,239
9713963 Putah Creek Solar Farm (SIS) 0 6,963 6,000 963 963
9713981 Green Point (SIS) 0 4,520 4,000 520 520
9714000 WG - Angiola Valley Solar Ranch C3-SM 0 675 0 675 675
9714001 WG - Arco Solar Station C3-SM 0 270 0 270 270
9714002 WG - Laguna Solar Farm C3-SM 0 540 0 540 540
9714005 WG - RE Mustang C3-SM 0 392 0 392 392
9714006 WG - RE Tranquility C3-SM 0 262 0 262 262
9714011 WG - WRE Coalinga C3-SM 0 270 0 270 270
9714012 WG - WRE Mendota C3-SM 0 270 0 270 270
9714013 WG - WRE Panoche C3-SM 0 270 0 270 270
9714014 WG - WRE Schindler C3-SM 0 270 0 270 270
9714015 WG - WRE Stroud C3-SM 0 135 0 135 135
9714017 WG - Cluster 3 Projects Phase 1 0 2,382 0 2,382 2,382
9714041 GASNA 10P, LLC- OL1 (SIS) 0 164 11,000 (10,836) (10,836)
9714042 GASNA 14P, LLC - OL5 (SIS) 0 164 1,000 (836) (836)
9714081 SunEdison - Le Grand (SIS) 0 164 11,000 (10,836) (10,836)
9714082 Hansen Ranch (SIS) 0 0 1,000 (1,000) (1,000)
9714102 WG - Montezuma II Wind-TCPII Results Mtg 0 262 0 262 262
9714103 WG - Carrizo Slr Farm-TCPII Results Mtg 0 9,495 0 9,495 9,495
9714104 WG - Desert Topaz 2-TCPII Results Mtg 0 5,052 0 5,052 5,052
9714105 WG - Walker Rdg Wind-TCPII Results Mtg 0 1,582 0 1,582 1,582
9714106 WG - Avenal Energy -TCPII Results Mtg 0 532 0 532 532
9714107 WG - Contra Costa Gen -TCPII Results Mtg 0 540 0 540 540
9714108 WG - GWF Henrietta -TCPII Results Mtg 0 667 0 667 667
9714109 WG - Hydro Enrgy CA -TCPII Results Mtg 0 2,018 0 2,018 2,018
9714110 WG - Madera Power -TCPII Results Mtg 0 262 0 262 262
9714111 WG - GWF Hanford -TCPII Results Mtg 0 405 0 405 405
9714112 WG - Alpaugh PV Slr-TCPII Results Mtg 0 536 0 536 536
9714113 WG - Marsh Landing Gen-TCPII Results Mtg 0 1,068 0 1,068 1,068
9714114 WG - DGC Kelso CT-TCPII Results Mtg 0 540 0 540 540
9714115 WG - PV-42 -TCPII Results Mtg 0 36,413 0 36,413 36,413
9714116 WG - Los Esteros Crit -TCPII Results Mtg 0 270 0 270 270
9714117 WG - Tres Vaqueros Wi -TCPII Results Mtg 0 270 0 270 270
9714120 AXIO POWER - JOLON (SIS) 0 0 11,000 (11,000) (11,000)
9714121 AXIO POWER - SAN MIGUEL (SIS) 0 0 11,000 (11,000) (11,000)
9714140 WG - World Sun PV-SM 0 135 0 135 135
9714146 WG - Repowered McKittrick Cogen-SM 0 270 0 270 270
9714149 WG - Thunderhill Solar Pwr Gen-SIS 0 3,667 0 3,667 3,667
FERC FORM NO. 1 (ED. 12-87) Page 450.5

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
9714150 WG - Chowchilla Solar Gen-SM 0 785 0 785 785
9714152 WG - BFO PV 09 Gen-SM 0 532 0 532 532
9714155 BFO-PV-12 (SIS) 0 0 1,000 (1,000) (1,000)
9714156 BFO-PV-13 (SIS) 0 0 1,000 (1,000) (1,000)
9714160 IRD McFarland (SIS) 0 4,822 11,000 (6,178) (6,178)
9714162 CAL SP IX (SIS) 0 251 11,000 (10,749) (10,749)
9714180 COOL EARTH SOLAR (SIS) 0 823 5,000 (4,177) (4,177)
9714200 WG - LMUD OPDE High Rock Solar-SIS 0 0 30,000 (30,000) (30,000)
9714220 SEPV-18 (SIS) 0 0 10,000 (10,000) (10,000)
9714243 AMERESCO VASCO RD (SIS) 0 3,828 7,500 (3,672) (3,672)
9714244 STOCKTON ENERGY CNT -R & R (SIS) 0 0 1,000 (1,000) (1,000)
9714261 CAL SP VI (SIS) 0 914 0 914 914
9714360 AMERESCO SJ - FOOTHILL (SIS) 0 2,053 1,000 1,053 1,053
9714361 Acciona - Copus Interconnection (SIS) 0 2,470 21,500 (19,030) (19,030)
9714362 Acciona - Lakeview Interconnection (SIS) 0 0 15,000 (15,000) (15,000)
9714364 Bakersfield Fuel and Oil (FAS) 0 2,360 10,000 (7,640) (7,640)
9714366 WGD - Salinas Valley Solid Waste (FAS) 0 0 30,000 (30,000) (30,000)
9714440 IEC ORD RANCH SOLAR PROJECT (SIS) 0 0 10,000 (10,000) (10,000)
9714448 11 MW SR SolisGooseLakeLLC SolEner (SIS) 0 0 10,000 (10,000) (10,000)
9714449 20 MW SR SolisYanceyLLC SolEner (SIS) 0 0 10,000 (10,000) (10,000)
9714450 20 MW SR Solis Gustine LLC SolEner (SIS) 0 0 10,000 (10,000) (10,000)
9714451 9 MW SR Solis Ikemiya LLC SolEner (SIS) 0 0 10,000 (10,000) (10,000)
9714540 Cenergy # MA1 (SIS) 0 0 1,000 (1,000) (1,000)
9714541 Cenergy - MA2 (SIS) 0 0 1,000 (1,000) (1,000)
9714542 WG - DES Gen Facility-SM 0 785 0 785 785
9714544 WG - BRJ Gen Facility-SM 0 785 0 785 785
9714546 WG - Enrico Matson 2 Gen Fac-SM 0 785 0 785 785
9714548 WG - Enrico Matson 4 Gen Fac-SM 0 785 0 785 785
9714550 WG - Sirius Solar Gen Fac-SM 0 392 0 392 392
9714551 WG - Sirius Solar Gen Fac-SIS 0 785 0 785 785
9714552 WG - Trinity Gen Fac-SM 0 785 0 785 785
9714554 WG - Graham-Westlands Proj Gen Fac-SM 0 131 0 131 131
9714556 WG - Kent South Gen Fac-SM 0 785 0 785 785
9714558 WG - Orion Gen Fac-SM 0 785 0 785 785
9714560 WG - JAC Gen Fac-SM 0 916 0 916 916
9714562 WG - Indeck Yuba Energy CTR Gen Fac-SM 0 392 0 392 392
9714680 Axio Maricopa (SIS) 0 0 11,000 (11,000) (11,000)
9714701 Solar Power Inc - Colusa (Feasibility) 0 0 5,000 (5,000) (5,000)
9714722 WG - Shiloh III-AIS 0 1,841 0 1,841 1,841
9714740 WG - Panoche Valley Slr Farm C2 P-RM 0 523 0 523 523
9714742 WG - White River West PV Gen C2P1-RM 0 262 0 262 262
9714743 WG - Corcoran West PV Gen C2P1-RM 0 131 0 131 131
9714745 WG - FRV Leo Slr C2P1-RM 0 1,187 0 1,187 1,187
9714746 WG - Russell City Enrgy Ctr Exp2 C2P1-RM 0 523 0 523 523
9714747 WG - Sutter Energy Ctr #2 C2P1-RM 0 1,329 0 1,329 1,329
9714748 WG - Solar Star CA XIII C2P1-RM 0 523 0 523 523
9714749 WG - Madera Slr PV1 C2P1-RM 0 523 0 523 523
9714750 WG - CPN Wild Horse Geothermal C2P1-RM 0 261 0 261 261
9714751 WG - King Solar II C2P1-RM 0 915 0 915 915
9714752 WG - BioVerde PV Vander Woude C2P1-RM 0 522 0 522 522
9714753 WG - GWF Tracy Add Capacity C2P1-RM 0 261 0 261 261
9714754 WG - North Star Slr 1 C2P1-RM 0 784 0 784 784
9714804 WG - Pioneer Solar I Gen Fac-SM 0 785 0 785 785
9714810 WG - Las Lomas Solar Gen Fac-SM 0 785 0 785 785
9714825 WG - Annedale Solar Gen Fac-SM 0 785 0 785 785
9714853 WG - Goose Lake Slr I Gen Fac-SM 0 785 0 785 785
9714860 WG - Rio Bravo Slr I Gen Fac-SM 0 785 0 785 785
9714878 CCSF TRANS CRYSTAL SPRINGS RD HWY 35 0 121,147 220,000 (98,853) (98,853)
Total Generation Studies 1,155,631 2,255,086 2,491,895 (236,809) 918,822
Grand Total 1,143,364 2,352,164 2,591,895 (239,730) 903,634
Definition of acronyms used above:
AIS Amended Interconnection Study
DIS Detailed Interconnection Study
FERC FORM NO. 1 (ED. 12-87) Page 450.6

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
IFS
IFAS
ISIS
OIS
SAIS
SIS
FSS
Interconnection Feasibility Study
Interconnection Facility Study
Interconnection System Impact Re-Study
Optional Interconnection Study
Second Amended Interconnection Study
System Impact Study
Feasibility Study Scoping
FERC FORM NO. 1 (ED. 12-87) Page 450.7

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
OTHER REGULATORY ASSETS (Account 182.3)
Year/Period of Report
End of 2010/Q4
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be
grouped by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
Core Brokerage Fee
Description and Purpose of
Other Regulatory Assets
Balance at
Debits CREDITS
Written off During
the Quarter/Year
Account Charged
(a)
Net Energy Metering Memo - Electric
Purchased Gas Balancing Account
Electric Baseline Shortfall Balancing Account
Self-Generation Program Memo Account-Electric
Self-Generation Program Memo Account-Gas
BCA Charge Account
CA Alternate Rates for Energy Program-Electric
CA Alternate Rates for Energy Program-Gas
Electric Hazardous Substance Balancing Account
Gas Hazardous Substance Balancing Account
Core Fixed Cost Gas Balancing Account
Transition Cost - Noncore Balancing Account
Enhanced Oil Recovery Balancing Account
Core Pipeline Demand Charge Account
CEE Incentive Electric Balancing Account
CEE Incentive Gas Balancing Account
Gas Core Firm Storage Account
Energy Resource Recovery Account
Common-Area Balancing Account
Renewables Balancing Account
Research, Dev. and Demo. Balancing Account
Bond Charge Balancing Account
Noncore Distribution Fixed Cost Balancing Acct
Environmental Compliance Regulatory Asset
Natural Gas Vehicle Balancing Account
Distribution Revenue Adjustment Mechanism
Transmission Revenue Balancing Account
Reliability Services Balancing Account
Electric Price Risk Management - Current
Electric Price Risk Management - NonCurrent
Gas Price Risk Management - Current
Gas Price Risk Management - NonCurrent
Vegetation Management Deferred Expense
Transmission Access Charge Balancing Account
DWR Power Charge Collection Balancing Account
DWR Power Charge Regulatory Asset
Public Purpose Programs Revenue Adjustment Mech.
Distribution Bypass Deferral Rate Memo Account
End-Use Customer Refund Adjustment
Gas Public Purpose Program Surcharge Memo Acct
SmartMeter Project Balancing Account-Electric
SmartMeter Project Balancing Account-Gas
Beginning of
Current
Quarter/Year
(b)
(c)
(d)
Written off During
the Period
Amount
(e)
Balance at end of
Current Quarter/Year
1,382,395 Various
356,789
1,025,606
( 1,711,081) Various
3,839
-1,714,920
( 26,635,377) 40,278,141
13,642,764
210,124,688 471,511
210,596,199
( 89,613,020) Various
17,366,020
-106,979,040
( 15,205,992) 182.3
3,801,866
-19,007,858
( 632,320) Various
274,394
-906,714
64,845,660 84,721,125
149,566,785
( 17,020,997) 3,411,598
-13,609,399
8,895,367 22,293,162
31,188,529
20,771,776 52,001,432
72,773,208
93,433,436 Various
37,009,322
56,424,114
( 811,638) 1,131,816
320,178
( 2) 2
( 11,612,199) 12,196,922
584,723
30,416,852 431
6,886,109
23,530,743
4,874,421 785,076
5,659,497
( 2,551,767) 2,672,437
120,670
71,834,153 Various
188,537,974
-116,703,821
8,354,283 18,746
8,373,029
( 1,290,086) 1,290,087
1
( 637,378) 637,387
9
( 49,686,491) Various
111,434
-49,797,925
875,971 Various
2,526,342
-1,650,371
407,562,937 400
257,670,315
149,892,622
( 134,474) 134,161
-313
151,889,685 Various
7,001,551
144,888,134
46,304,579 400
83,903,897
-37,599,318
15,536,328 400
22,905,030
-7,368,702
178,495,205 131,794,235
310,289,440
362,804,228 93,596,682
456,400,910
53,070,132 12,251,577
65,321,709
28,136,664 4,293,307
32,429,971
10,648,014 Various
7,374,531
3,273,483
52,811,529 Various
3,644,095
49,167,434
20,386,320 34,350,558
54,736,878
28,078,464 400
20,323,019
7,755,445
( 5,342,537) 6,295,619
953,082
2,017,714 9,566
2,027,280
( 893,625) 254
2,463,009
-3,356,634
5,025,592 Various
19,812
5,005,780
49,497,661 7,759,448
57,257,109
31,839,851 23,397,728
55,237,579
(f)
44 TOTAL 6,500,673,291 1,925,627,307
1,528,054,977 6,898,245,621
FERC FORM NO. 1/3-Q (REV. 02-04) Page 232

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
OTHER REGULATORY ASSETS (Account 182.3)
Year/Period of Report
End of 2010/Q4
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be
grouped by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
Description and Purpose of
Other Regulatory Assets
Balance at
Debits CREDITS
Written off During
the Quarter/Year
Account Charged
(a)
Renewables Portfolio Standard Cost Memo Acct
Climate Smart Balancing Acccount-Gas
Climate Smart Balancing Acccount-Electric
Procurement Energy Efficiency Rev. Adj. Mechanism
Family Electric Rate Assistance Balancing Acct
Negative Ongoing Competition Transition Chrg BA
Dynamic Pricing Memorandum Account
Bristish Columbia Renewable Study Bal Account-Elec
Market Redesign & Technology Memo Account
Gateway Settlement Balancing Account
Land Conserv. Plan Env. Remediation Memo Acct.
Energy Efficiency 2009-2011 Memo Acct-Electric
Energy Efficiency 2009-2011 Memo Acct-Gas
Fire Hazard Prevention Memo Acct
FASB 109 Regulatory Asset
QF Buyout
Advanced Metering and Demand Response Account
Distributed Energy Resources Memo Account
Nuclear Decommissioning Adjustment Mechanism
Dept of Energy Litigation Balancing Acct
Demand Response Expenditures Balancing Account
Demand Response Revenue Balancing Account
Miscellaneous Gas Reg Asset - Current
Miscellaneous Gas Reg Asset - NonCurrent
Miscellaneous Electric Reg Asset - Current
Miscellaneous Electric Reg Asset - NonCurrent
Energy Recovery Bonds Regulatory Asset
EEC Funding Payment Recovery Account
Financing Costs Regulatory Asset
Utility Retained Generation Regulatory Assets
Financial Hedging Costs
Pension Regulatory Asset
FIN 47 - Regulatory Asset
Fossil Decommissioning Reg Asset
Electric/Gas Reserve Accounts
Community Choice Aggr. Implem. Costs Balan. Acct.
Gas Hazardous Substance Regulatory Asset
Gas Non-Hazardous Substance Regulatory Asset
Gas AB32 Administration Fee Memo Account
Electric AB32 Administration Fee Memo Account
San Bruno Independent Review Panel Memo Account
CA Solar Initiative Thermal Program Memo Account
Electric Disconnection Memo Account
Beginning of
Current
Quarter/Year
(b)
(c)
(d)
Written off During
the Period
Amount
(e)
Balance at end of
Current Quarter/Year
385,772 311,869
697,641
( 3,808,344) Various
798,324
-4,606,668
( 5,117,989) 511,483
-4,606,506
4,069,110 Varioius
6,421,939
-2,352,829
4,643,803 2,027,913
6,671,716
1,267,272,840 404,487,090
1,671,759,930
2,425,621 182.3
2,199,891
225,730
( 884,156) 1,298,507
414,351
1,322,521 20,225,662
21,548,183
416,006 1,022,218
1,438,224
566,535 1,342,529
1,909,064
192,492,955 Various
192,492,955
39,024,877 Various
39,024,877
23,331 14,303
37,634
1,042,684,540 207,170,136
1,249,854,676
67,212,714 67,212,714
6,473,355 14,526
6,487,881
8,509,063 1,509,097
10,018,160
292,134 16,762,011
17,054,145
13,730,639 1,119,428
14,850,067
( 26,417,793) Various
13,560,916
-39,978,709
222,859 1,832,781
2,055,640
253,062 234,563
487,625
14,624,897 Various
15,866,814
-1,241,917
59,855,815 48,052,602
107,908,417
7,434,556 Various
6,131,658
1,302,898
998,422,308 Various
296,619,193
701,803,115
37,707,000 228.4
8,670,000
29,037,000
38,718,919 428
3,411,394
35,307,525
1,161,443,237 Various
120,052,052 1,041,391,185
24,792,670 428
2,530,211
22,262,459
1,386,300,699 372,680,540
1,758,981,239
14,851,094 3,620,361
18,471,455
56,274,462 55,674,906
111,949,368
(1,651,680,742) Various
158,095,405
*,***,***,***
3,833,238
221,135,693
13,179,292
4,664,786
157,915
500,242
844,963
2,260,440
(f)
3,833,238
221,135,693
13,179,292
4,664,786
157,915
500,242
844,963
2,260,440
44 TOTAL 6,500,673,291 1,925,627,307
1,528,054,977 6,898,245,621
FERC FORM NO. 1/3-Q (REV. 02-04) Page 232.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
OTHER REGULATORY ASSETS (Account 182.3)
Year/Period of Report
End of 2010/Q4
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be
grouped by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
Description and Purpose of
Other Regulatory Assets
Balance at
Debits CREDITS
Written off During
the Quarter/Year
Account Charged
(a)
Gas Disconnection Memo Account
SmartMeter Memorandum Account Electric
SmartMeter Memorandum Account Gas
Beginning of
Current
Quarter/Year
(b)
(c)
1,705,244
893,470
747,176
(d)
Written off During
the Period
Amount
(e)
Balance at end of
Current Quarter/Year
(f)
1,705,244
893,470
747,176
44 TOTAL 6,500,673,291 1,925,627,307
1,528,054,977 6,898,245,621
FERC FORM NO. 1/3-Q (REV. 02-04) Page 232.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 232 Line No.: 25 Column: a
The Utility expects to recover these costs over periods ranging from 1 to 32 years.
Schedule Page: 232 Line No.: 40 Column: a
Amortization period - one year.
Schedule Page: 232.1 Line No.: 15 Column: a
Based on current regulatory ratemaking and income tax laws, the Utility expects to recover
deferred income taxes related to regulatory assets over periods ranging from 1 to 45
years.
Schedule Page: 232.1 Line No.: 16 Column: a
Amortization period - 2003-2014.
Schedule Page: 232.1 Line No.: 27 Column: a
Amortization period is 8 years, the term of the Energy Recovery Bonds.
Schedule Page: 232.1 Line No.: 28 Column: a
Amortization period - 2004-2013.
EEC stands for Environmental Enhancement Corporation.
Schedule Page: 232.1 Line No.: 29 Column: a
The interest rate hedge portion of this regulatory asset is being amortized over periods
of 5, 7, 10, and 30 years.
This regulatory asset is recoverable through the cost of capital mechanism. Costs, net of
premiums or discounts for outstanding debt which are also recoverable through this
mechanism, are shown on pages 256-257 of the annual report on Form 1.
Schedule Page: 232.1 Line No.: 30 Column: a
The individual components of these regulatory assets are amortized over their respective
lives, with a weighted average life of approximately 13 years.
Schedule Page: 232.1 Line No.: 31 Column: a
This regulatory asset is recoverable through the cost of capital mechanism. Costs, net of
premiums or discounts for outstanding debt which are also recoverable through this
mechanism, are shown on pages 256-257 of the annual report on Form 1.
Schedule Page: 232.1 Line No.: 35 Column: f
This is a combination of various accounts as follows:
Electric and Gas Reserve Accounts
Modified Transition Cost Balancing Account
Deferred Divestiture Transaction Cost
The ending balance of these regulatory assets should show ($1,809,776,147), but the FERC
software is unable to show negative numbers of over a billion dollars.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
MISCELLANEOUS DEFFERED DEBITS (Account 186)
Year/Period of Report
End of 2010/Q4
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
Description of Miscellaneous Balance at
Debits CREDITS
Deferred Debits
Beginning of Year
Account
Charged
Amount
(a)
(b)
(c)
(d)
(e)
Customer Advance for
Construction - Refundable
Deferred Development Costs
Payments for Main Line
Extension (MLX) and
Non-energy Invoices
Payments for MLX
Reimburseable Transmission
Service & Generation
Interconnection Study Costs
Miscellaneous Minor Items
Balance at
End of Year
(f)
13,596,973 162,433
13,759,406
15,924,763 11,648,750
27,573,513
223,176 893,142
1,116,318
-3,026,184 Various
4,774,518
-7,800,702
1,143,364 186
239,730
903,634
-2,849,436 3,905,209
1,055,773
47 Misc. Work in Progress
48
Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL
25,012,656 36,607,942
FERC FORM NO. 1 (ED. 12-94) Page 233

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
Year/Period of Report
End of 2010/Q4
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Description and Location
(a)
Electric
Environmental
Compensation
CIAC
Injuries and Damages
California Corporation Franchise Tax
Other
TOTAL Electric (Enter Total of lines 2 thru 7)
Gas
Environmental
Compensation
CIAC
Injuries and Damages
California Corporation Franchise Tax
Other
TOTAL Gas (Enter Total of lines 10 thru 15
Other (Specify)
TOTAL (Acct 190) (Total of lines 8, 16 and 17)
Line 17 consists of the following:
Balance of Begining
of Year
(b)
154,841,472
227,092,208
-10,983,266
98,089,009
-20,488,238
16,110,853
464,662,038
72,426,218
95,259,642
110,940,462
31,890,619
-32,808,999
39,849,440
317,557,382
16,302,135
798,521,555
Notes
Balance
Balance
at Beginning
at End
of Year
of Year
------------ -------------
Balance at End
of Year
(c)
164,915,112
227,775,252
-18,620,173
94,109,871
-29,425,091
189,728,213
628,483,184
76,743,375
95,552,206
108,473,731
117,323,676
-5,147,418
139,909,417
532,854,987
43,365,614
1,204,703,785
California Corporation Franchise Tax $(18,128,714) $(17,332,321)
Compensation (140,138) 2,382,404
Other 34,570,987 58,305,531
------------ ------------
Total $ 16,302,135 $ 43,365,614
============ ============
FERC FORM NO. 1 (ED. 12-88) Page 234

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
CAPITAL STOCKS (Account 201 and 204)
Year/Period of Report
End of 2010/Q4
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line
No.
Class and Series of Stock and
Name of Stock Series
Number of shares
Authorized by Charter
Par or Stated
Value per share
Call Price at
End of Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
(a)
Pacific Gas and Electric Company's stock
is wholly owned by PG&E Corporation
Common
TOTAL COMMON
Registered with the American Stock Exchange
Preferred, Cumulative:
Redeemable: Without Mandatory Redemption
4.36%
4.50%
4.80%
5.00%
5.00% - Series A
7.04%
Undesignated in Class
SubTotal Redeemable Without
Mandatory Redemption
Registered with the American Stock Exchange
Non-Redeemable
5.00%
5.50%
6.00%
SubTotal Non-Redeemable
Redeemable: With Mandatory Redemption
6.30%
6.57%
Undesignated in Class
SubTotal Redeemable With
Mandatory Redemption
TOTAL PREFERRED
(b)
800,000,000
800,000,000
418,291
611,142
793,031
1,778,172
934,322
3,000,000
56,180,217
63,715,175
400,000
1,173,163
4,211,662
5,784,825
2,500,000
3,000,000
10,000,000
15,500,000
85,000,000
(c)
5.00
5.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
100.00
(d)
25.75
26.00
27.25
26.75
26.75
FERC FORM NO. 1 (ED. 12-91) Page 250

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
CAPITAL STOCKS (Account 201 and 204) (Continued)
Year/Period of Report
End of 2010/Q4
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET
HELD BY RESPONDENT
Line
(Total amount outstanding without reduction
AS REACQUIRED STOCK (Account 217)
IN SINKING AND OTHER FUNDS No.
for amounts held by respondent)
Shares
(e)
Amount
(f)
Shares
(g)
Cost
(h)
Shares
(i)
Amount
(j)
1
2
264,374,809 1,321,874,045
3
4
264,374,809 1,321,874,045
5
6
7
8
9
418,291 10,457,275
10
611,142 15,278,550
11
793,031 19,825,775
12
1,778,172 44,454,300
13
934,322 23,358,050
14
15
16
17
4,534,958 113,373,950
18
19
20
21
22
400,000 10,000,000
23
1,173,163 29,329,075
24
4,211,662 105,291,550
25
26
5,784,825 144,620,625
27
28
29
30
31
32
33
34
35
36
10,319,783 257,994,575
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-88) Page 251

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 250 Line No.: 15 Column: a
Redeemed on August 31, 2005.
Schedule Page: 250 Line No.: 30 Column: a
This was reclassifed to Other Long-Term Debt in accordance with FASB 150 in September
2003. It was shown here since it is still part of the total number of preferred shares
authorized. They were fully redeemed on May 31, 2005.
Schedule Page: 250 Line No.: 31 Column: a
This was reclassifed to Other Long-Term Debt in accordance with FASB 150 in September
2003. It was shown here since it is still part of the total number of preferred shares
authorized. They were fully redeemed on May 31, 2005.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
Line Item Amount
No.
(a)
(b)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Account 211 - Miscellaneous Paid-in Capital
1,471,315,126
40 TOTAL 1,471,315,126
FERC FORM NO. 1 (ED. 12-87) Page 253

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
CAPITAL STOCK EXPENSE (Account 214)
Year/Period of Report
End of 2010/Q4
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Class and Series of Stock
(a)
COMMON
PREFERRED, CUMULATIVE:
Redeemable - $25 par value per share:
4.36%
4.50%
4.80%
5.00%
5.00% - Series A
Non-Redeemable - $25 par value per share:
5.00%
5.50%
6.00%
Balance at End of Year
(b)
25,143,083
29,509
387,663
777,999
1,758,375
158,204
73,717
173,730
449,606
22 TOTAL 28,951,886
FERC FORM NO. 1 (ED. 12-87) Page 254b

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Year/Period of Report
End of 2010/Q4
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
1 ACCOUNT 221:
2 SENIOR NOTES & POLLUTION CONTROL BONDS:
3 Series
Rate
4 Series 4.20% Senior Notes due 2011 4.200%
Principal Amount
Of Debt issued
(b)
500,000,000
Total expense,
Premium or Discount
(c)
3,869,586
5 1,300,000 D
6 Series 4.80% Senior Notes due 2014 4.800%
1,000,000,000
7,989,172
7 1,530,000 D
8 Series 6.05% Senior Notes due 2034 6.050%
3,000,000,000
30,717,515
9 14,640,000 D
10 Series 5.80% Senior Notes due 2037 5.800%
700,000,000
6,807,234
11 3,822,000 D
12 Series 5.625% Senior Notes due 2017 5.625%
500,000,000
3,857,481
13 2,710,000 D
14 Series 5.625% Senior Notes due 2017 5.625%
200,000,000
1,486,541
15 -3,100,000 P
16 Series 6.35% Senior Notes due 2038 6.350%
400,000,000
3,943,976
17 568,000 D
18 Series 8.25% Senior Notes due 2018 8.250%
600,000,000
4,572,075
19 9,942,000 D
20 Series 8.25% Senior Notes due 2018 8.250%
200,000,000
1,511,598
21 -8,950,000 P
22 Series 6.25% Senior Notes due 2013 6.250%
400,000,000
2,788,005
23 2,968,000 D
24 Series 6.25% Senior Notes due 2039 6.250%
550,000,000
5,145,853
25 6,814,500 D
26 Series 5.4% Senior Notes due 2040 5.400%
550,000,000
5,464,539
27 7,815,500 D
28 Series 5.8% Senior Notes due 2037 5.800%
250,000,000
2,568,157
29 3,862,500 D
30 Series 3.5% Senior Notes due 2020 3.500%
550,000,000
4,311,853
31 2,728,000 D
32 Series 3.5% Senior Notes due 2020 3.500%
250,000,000
2,006,306
33 TOTAL 14,143,075,908 173,019,023
FERC FORM NO. 1 (ED. 12-96) Page 256

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Year/Period of Report
End of 2010/Q4
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 6,840,000 D
2 Series 5.4% Senior Notes due 2040 5.400%
250,000,000
2,568,806
3 6,252,500 D
4 Pollution Control Bonds
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
1996 Series 96A/C/E/F/G
1997 Series 97B
2004 Series A-D
2008 Series F-G
2009 Series A-D
2010 Series E
SUBTOTAL ACCOUNT 221
ACCOUNT 222:
Various
Various
4.750%
3.750%
Various
2.250%
727,870,000
148,550,000
345,000,000
95,000,000
308,550,000
50,000,000
11,574,970,000
10,607,457
2,129,592
7,897,424
538,745
1,986,577
507,531
173,019,023
20 REACQUIRED BONDS
21 Pollution Control Bonds
22
23
24
25
26
27
28
1996 Series 96G
2008 Series F-G
SUBTOTAL ACCOUNT 222
ACCOUNT 223:
Variable
Variable
-62,870,000
-95,000,000
-157,870,000
29 ADVANCES FROM ASSOCIATED COMPANIES
30
31
32
PG&E Energy Recovery Funding LLC
SUBTOTAL ACCOUNT 223
Various
2,725,975,908
2,725,975,908
33 TOTAL 14,143,075,908 173,019,023
FERC FORM NO. 1 (ED. 12-96) Page 256.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
Year/Period of Report
End of 2010/Q4
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD
Outstanding
Line
Nominal Date Date of
(Total amount outstanding without Interest for Year
No.
of Issue Maturity Date From Date To
reduction for amounts held by
respondent)
Amount
(d) (e) (f) (g) (h) (i)
1
2
3
3/23/04 3/1/11
3/23/04
3/1/11
500,000,000 21,000,000 4
5
3/23/04 3/1/14
3/23/04
3/1/14
1,000,000,000 48,000,000 6
7
3/23/04 3/1/34
3/23/04
3/1/34
3,000,000,000 181,500,000 8
9
3/13/07 3/1/37
3/13/07
3/1/37
700,000,000 40,600,000 10
11
12/4/07 11/30/17 12/4/07
11/30/17
500,000,000 28,125,000 12
13
3/3/08 11/30/17 3/3/08
11/30/17
200,000,000 11,250,000 14
15
3/3/08 2/15/38 3/3/08
2/15/38
400,000,000 25,400,000 16
17
10/21/08 10/15/18 10/21/08 10/15/18
600,000,000 49,500,000 18
19
11/18/08 10/15/18 11/18/08 10/15/18
200,000,000 16,500,000 20
21
11/18/08 12/1/13 11/18/08 12/1/13
400,000,000 25,000,000 22
23
3/6/09 3/1/39
3/6/09
3/1/39
550,000,000 34,375,000 24
25
11/18/09 1/15/40 11/18/09 1/15/40
550,000,000 29,700,000 26
27
4/1/10 3/1/37
4/1/10
3/1/37
250,000,000 10,875,000 28
29
9/15/10 10/1/20 9/15/10
10/1/20
550,000,000 5,668,056 30
31
11/18/10 10/1/20 11/18/10 10/1/20
250,000,000 1,045,139 32
12,252,523,939 607,199,526
33
FERC FORM NO. 1 (ED. 12-96) Page 257

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
Year/Period of Report
End of 2010/Q4
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD
Outstanding
Line
Nominal Date Date of
(Total amount outstanding without Interest for Year
No.
of Issue Maturity Date From Date To
reduction for amounts held by
respondent)
Amount
(d) (e) (f) (g) (h) (i)
1
11/18/10 1/15/40 11/18/10 1/15/40
250,000,000 1,612,500 2
3
4
5/23/96 Various 5/23/96
Various
727,870,000 11,618,337 5
6
9/16/97 Various 9/16/97
Various
148,550,000 342,723 7
8
6/29/04 12/1/23 6/29/04
12/1/23
345,000,000 16,387,500 9
10
9/22/08 Various 9/22/08
Various
95,000,000 2,563,021 11
12
9/1/09 Various 9/1/09
Various
308,550,000 588,373 13
14
4/8/10 11/1/26 4/8/10
11/1/26
50,000,000 821,875 15
16
11,574,970,000 562,472,524 17
18
19
20
21
-62,870,000 22
23
-95,000,000 24
25
-157,870,000 26
27
28
29
835,423,939 44,727,002 30
31
835,423,939 44,727,002 32
12,252,523,939 607,199,526
33
FERC FORM NO. 1 (ED. 12-96) Page 257.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 256 Line No.: 1 Column: c
Items included under column (c) represent original issuance expense, premium or discount
on issuance related to outstanding debt which are recoverable through the cost of capital
mechanism. Other financing related costs which are also recoverable are reflected on page
232, Other Regulatory Assets (Account 182.3).
Schedule Page: 256.1 Line No.: 17 Column: i
This amount reconciles to Account 427, Interest on Long-Term Debt, per Line 62, Column c
of Form 1 page 117, Statement of Income for the Year, as follows:
Interest expense per this page 562,472,524
Remarketing costs not included on this page 986,727
Total Interest expense per page 117 563,459,250
Schedule Page: 256.1 Line No.: 26 Column: c
Original debt expense amortization costs on reacquired bonds are reported in Account 189
on Form 2 page 260.
Schedule Page: 256.1 Line No.: 26 Column: i
No interest costs or income is recorded for bonds outstanding and held in FERC Account
222.
Schedule Page: 256.1 Line No.: 32 Column: i
This amount reconciles to Account 430, Interest on Debt to Associated Companies per Line
67, Column c of Form 1 page 117, Statement of Income for the Year, as follows:
Interest expense per this page 44,727,002
Subsidiary interest not included on this page 13,929
Total Interest expense per page 117 44,740,932
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line
No.
1 Net Income for the Year (Page 117)
2
3
4 Taxable Income Not Reported on Books
5 Contributions in Aid of Construction
6
7
8
Particulars (Details)
(a)
9 Deductions Recorded on Books Not Deducted for Return
10 Provision for Federal Income Taxes
11 Provision for State Income Taxes
12 Others (See footnotes for details)
13
14 Income Recorded on Books Not Included in Return
15 AFUDC - Equity and debt
16 Balancing Accounts
17
18
19 Deductions on Return Not Charged Against Book Income
20 Others (See footnotes for details)
21
22
23
24
25
26
27 Federal Tax Net Income
28 Show Computation of Tax:
29 Tax at 35% for Electric, Water, Non-Utility, and Gas
30 Les: Return to accrual
31 Add: Tax on FIN 48 Interest
32 Less: Low Income Housing Credits
33 Audit Adjustments
34 FIN 48 Adjustment (IRS Settlement - Acctg Method Change & R&E Credit)
35 Reclass Acctg Method Change Adjustment to Deferred Expense Since NOL
36
37 TOTAL TAX
38
39 FEDERAL INCOME TAX ACCRUAL (Lines 15, 53, and 76 of Pages 114-117)
40
41
42
43
44
Amount
(b)
1,120,973,704
82,288,749
506,630,630
67,418,494
1,123,764,981
160,103,895
72,309,704
2,878,296,686
-209,633,727
-73,371,701
-57,281,340
8,913,634
-1,176,000
25,413,930
-72,290,955
136,505,000
-33,287,432
-33,287,432
FERC FORM NO. 1 (ED. 12-96) Page 261

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 261 Line No.: 12 Column: b
This consists of the following:
Total
ERB Regulatory Asset Amortization $390,727,013
Supplier Settlements 127,346,882
Executive Compensation 151,968
Pretax income LLC Funding 17,426,048
Loss on Reacquired Debt 22,345,000
Meals & Entertainment & Lobbying 51,000,000
Capitalized Interest 108,640,866
Nuclear Fuel expense 85,379,213
Gas Hedge Amortization 71,098,128
Penalties 8,233,850
Bad Debts 13,304,000
Injuries & Damages 203,859,326
Other 24,252,687
Total $1,123,764,981
Schedule Page: 261 Line No.: 20 Column: b
This consists of the following:
Computer Software $91,714,000
Cost of removal 189,819,835
Depreciation adjustment 2,325,004,011
Earnings of Subsidiaries 17,755,011
Franchise Tax 100,506,000
Tax Exempt Bond Interest 1,000,000
Repair allowance 41,207,850
Fossil Decommissioning 25,640,646
Bankruptcy 17,324,362
Humboldt Decommissioning 45,876,543
Dividends Paid Deduction 3,540,000
Stock Options/Restricted Stock 7,218,722
Medicare Part D 1,494,464
Compensation Related Adjustments 10,195,242
Total 2,878,296,686
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Year/Period of Report
End of 2010/Q4
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
BALANCE AT BEGINNING OF YEAR
Taxes
Taxes
Charged
Paid
Taxes Accrued Prepaid Taxes
During
During
(Account 236) (Include in Account 165) Year
Year
(a) (b) (c) (d) (e) (f)
Kind of Tax
(See instruction 5)
FEDERAL
FICA
Taxes on Income
Unemployment
Decommissioning Inc.
SUBTOTAL FEDERAL
STATE
State Training Tax Fund
Taxes on Income
Unemployment
SUBTOTAL STATE TAXES
OTHER STATE AND LOCAL
Timber Yield Tax
Ad Valorem Property
Payroll Tax
Business Tax
Other
SUBTOTAL OTHER STATE
& LOCAL TAXES
14,612,301
222,998,166
19,609
237,630,076
102,974
102,974
1,887,458
1,887,458
81,128,907
-33,287,432
1,295,160
14,462,254
63,598,889
158,761
133,884,933
8,685,121
142,728,815
48,448
248,699,973
8,575,432
982,046
1,128,989
259,434,888
85,874,534
Adjustments
-48,211,961 -119,032,366
1,263,034
14,462,254
53,387,861 -119,032,366
158,761
318,024,535 193,353,749
8,433,273
326,616,569 193,353,749
48,448
248,699,973
9,031,978
982,046
1,128,989
259,891,434
TOTAL
41 465,762,592 639,895,864 74,321,383
239,620,508
FERC FORM NO. 1 (ED. 12-96) Page 262

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
Year/Period of Report
End of 2010/Q4
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED
(Taxes accrued Prepaid Taxes
Electric Extraordinary Items Adjustments to Ret.
Other
Account 236) (Incl. in Account 165) (Account 408.1, 409.1) (Account 409.3) Earnings (Account 439)
(g) (h) (i) (j) (k) (l)
1
9,866,674 61,103,347
20,025,560 2
118,890,329 -17,814,651
-15,472,781 3
51,735 929,148
366,012 4
14,462,254 5
6
128,808,738 58,680,098
4,918,791 7
8
9
113,895 44,866 10
9,214,147 40,969,983
92,914,950 11
354,822 6,230,706
2,454,415 12
13
9,568,969 47,314,584
95,414,231 14
15
16
34,756 13,692 17
195,683,548 53,016,425 18
1,430,912 6,152,015
2,423,417 19
704,520 277,526 20
842,190 286,799 21
22
1,430,912 203,417,029
56,017,859 23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
Line
No.
139,808,619
309,411,711 156,350,881
41
FERC FORM NO. 1 (ED. 12-96) Page 263

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 262 Line No.: 1 Column: l
Gas
Non-utility
(Account 408.1 (Account 408.2 Total
409.1) 409.2) Other
(a) (b) (c)
FEDERAL
FICA 20,025,560 0 20,025,560
Taxes on Income (10,692,195) (4,780,586) (15,472,781)
Unemployment 366,012 0 366,012
Total Federal Taxes 9,699,377 (4,780,586) 4,918,791
STATE
State Training Tax Fund 44,866 0 44,866
Taxes on Income 97,212,748 (4,297,798) 92,914,950
Unemployment 2,454,415 0 2,454,415
Total State Taxes 99,712,029 (4,297,798) 95,414,231
STATE AND LOCAL
Timber Yield Tax 13,692 0 13,692
Ad Valorem Property 52,709,010 307,415 53,016,425
Payroll Tax 2,423,417 0 2,423,417
Business Tax 277,526 0 277,526
Other 286,799 0 286,799
Total Local Taxes 55,710,444 307,415 56,017,859
Schedule Page: 262 Line No.: 3 Column: f
This consists of the following:
165,121,850 (8,770,969) 156,350,881
FIN 48 gross interest $-21,874,634
Activity booked to Account 143 due
to debit balance 140,907,000
Total $119,032,366
Schedule Page: 262 Line No.: 11 Column: f
This consists of the following:
Reclass debit balance of Account 236
to Account 143 $-47,908,668
Activity booked to Account 143 due to
debit balance -145,445,081
Total $-193,353,749
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
the average period over which the tax credits are amortized.
Line Account Balance at Beginning
No. Subdivisions
of Year
(a)
(b)
Year/Period of Report
End of 2010/Q4
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i)
Allocations to
Deferred for Year
Current Year's Income
Adjustments
Account No. Amount Account No. Amount
(c)
(d) (e) (f) (g)
1 Electric Utility
2 3%
3 4%
4 7%
5 10% 58,217,000 411.5 271,362
6
7
8 TOTAL 58,217,000 271,362
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10
11 10% 30,514,266 411.5 1,558,000
12
13 TOTAL GAS 30,514,266 1,558,000
14
15 ELECTRIC AND GAS 88,731,266 1,829,362
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89) Page 266

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued)
Year/Period of Report
End of 2010/Q4
Balance at End
of Year
(h)
Average Period
of Allocation
to Income
(i)
ADJUSTMENT EXPLANATION
57,945,638 16 5
57,945,638 8
Line
No.
1
2
3
4
6
7
9
22 10
28,956,266 11
12
28,956,266 13
14
86,901,904 15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89) Page 267

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
Description and Other
Deferred Credits
(a)
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
OTHER DEFFERED CREDITS (Account 253)
Balance at
Beginning of Year
(b)
Contra
Account
(c)
DEBITS
Amount
(d)
Credits
(e)
Year/Period of Report
End of 2010/Q4
1. Report below the particulars (details) called for concerning other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
Balance at
End of Year
CIAC Deferred Revenue 213,799,398 Various
7,211,388
206,588,010
Deferred Credits - Electric 49,184,799 Various
1,047,543
48,137,256
Reserves
Deferred Credits - Hazardous 38,027,079 Various
38,027,079
Substance Insurance Recoveries
Performance Shares Liability 30,817,488 Various
-19,305,705
11,511,783
Other 18,655,209 Various
6,332,089
24,987,298
(f)
47 TOTAL 350,483,973
46,286,010 -12,973,616
291,224,347
FERC FORM NO. 1 (ED. 12-94) Page 269

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable
property.
2. For other (Specify),include deferrals relating to other income and deductions.
Line
No.
CHANGES DURING YEAR
Account
Balance at
Beginning of Year
Amounts Debited
Amounts Credited
to Account 410.1 to Account 411.1
(a) (b) (c) (d)
1 Accelerated Amortization (Account 281)
2 Electric
3 Defense Facilities
4 Pollution Control Facilities
5 Other (provide details in footnote):
6 Settlement Regulatory Asset
7
8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
13
14
15 TOTAL Gas (Enter Total of lines 10 thru 14)
16
17 TOTAL (Acct 281) (Total of 8, 15 and 16)
18 Classification of TOTAL
19 Federal Income Tax
20 State Income Tax
21 Local Income Tax
1,105,025,558
1,105,025,558
1,105,025,558
870,627,356
234,398,202
-9,004,908
-9,004,908
-9,004,908
-7,051,259
-1,953,649
NOTES
FERC FORM NO. 1 (ED. 12-96) Page 272

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
ADJUSTMENTS
Amounts Debited Amounts Credited
Debits
Credits
Balance at
to Account 410.2 to Account 411.2 Account
Amount
Account
Amount
End of Year
Credited
Debited
(e) (f) (g)
(h) (j)
(i)
(k)
Line
No.
1
2
3
4
5
1,114,030,466 6
7
1,114,030,466 8
9
10
11
12
13
14
15
16
1,114,030,466 17
18
877,678,615 19
236,351,851 20
21
NOTES (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 273

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
Account
Balance at
No.
Beginning of Year
Amounts Debited
Amounts Credited
to Account 410.1 to Account 411.1
(a) (b) (c) (d)
1 Account 282
2 Electric 3,646,688,960 -482,269,725 -1,343,799,904
3 Gas 809,334,691 -204,238,970 -356,877,021
4 Non-Utility 2,553,719
5 TOTAL (Enter Total of lines 2 thru 4) 4,458,577,370 -686,508,695 -1,700,676,925
6
7
8
9 TOTAL Account 282 (Enter Total of lines 5 thru 4,458,577,370 -686,508,695 -1,700,676,925
10 Classification of TOTAL
11 Federal Income Tax 3,857,107,872 -537,568,017 -1,331,708,584
12 State Income Tax 601,469,498 -148,940,678 -368,968,341
13 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96) Page 274

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
Year/Period of Report
End of 2010/Q4
CHANGES DURING YEAR
ADJUSTMENTS
Amounts Debited Amounts Credited
Debits
Credits
Balance at
to Account 410.2 to Account 411.2 Account
Amount
Account
Amount
End of Year
Credited
Debited
(e) (f) (g)
(h) (j)
(i)
(k)
Line
No.
192,529,786 4,700,748,925 2
82,512,766 1,044,485,508 3
2,553,719 4
275,042,552 5,747,788,152 5
6
7
8
275,042,552 5,747,788,152 9
10
215,371,022 4,866,619,461 11
59,671,530 881,168,691 12
13
1
NOTES (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 275

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 274 Line No.: 2 Column: j
This consists of the following:
SFAS 109 adjustment - account 182.3 (117,975,593
)
NDT Tax Settlement 9,293,162
Other adjustment and reclassification (return-to-accrual (55,634,319)
true-up)
Other adjustment and reclassification (FIN48) (78,953,133)
Current - Noncurrent Reclass (4,894,223)
(248,164,106
)
Schedule Page: 274 Line No.: 3 Column: j
This consists of the following:
SFAS 109 adjustment - account 182.3 (50,560,968)
NDT Tax Settlement 3,982,784
Other adjustment and reclassification
(33,837,057)
(FIN48)
Current - Noncurrent Reclass (2,097,524)
(82,512,766)
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
Account
Balance at
Amounts Debited Amounts Credited
No.
Beginning of Year
to Account 410.1 to Account 411.1
(a) (b) (c) (d)
1 Account 283
2 Electric
3 Loss on Reacquired Debt
73,338,592
-7,239,955
-419,020
4 Balancing Accounts
388,094,238
-244,658,393
1,444,824
5
6
7
8
Other
-121,206,986
-63,464,327
-72,769,954
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
340,225,844
-315,362,675
-71,744,150
11 Loss on Reacquired Debt
18,973,032
-3,102,838
-187,206
12 Balancing Accounts
25,327,129
-57,194,342
-60,862,980
13 Hedging
14
15
16
Other
-51,448,521
-30,238,587
-32,093,835
17 TOTAL Gas (Total of lines 11 thru 16)
-7,148,360
-90,535,767
-93,144,021
18 Other
715,742
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
333,793,226
303,915,805
-405,898,442
-317,837,228
-164,888,171
-129,115,054
22 State Income Tax
23 Local Income Tax
29,877,421
-88,061,214
-35,773,117
NOTES
FERC FORM NO. 1 (ED. 12-96) Page 276

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
CHANGES DURING YEAR
ADJUSTMENTS
Amounts Debited Amounts Credited
Debits
Credits
Balance at Line
to Account 410.2 to Account 411.2 Account
Amount
Account
Amount
End of Year No.
Credited
Debited
(e) (f) (g)
(h) (i)
(j) (k)
1
2
66,517,657 3
141,991,021 4
19,612,533 -92,288,826 5
19,612,533 116,219,852 9
6
7
8
10
16,057,400 11
28,995,767 12
13
8,405,372 -41,187,901 14
15
16
8,405,372 3,865,266 17
-61,189 358,535
296,018 18
-61,189 358,535
28,017,905
120,381,136 19
-47,914 280,749
21,939,314
136,804,282 21
-13,275 77,786
6,078,591
-16,423,146 22
20
23
NOTES (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 277

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 276 Line No.: 5 Column: j
This represents other adjustment and reclassification (between deferred accounts).
Schedule Page: 276 Line No.: 14 Column: j
This represents other adjustment and reclassification (between deferred accounts).
Schedule Page: 276 Line No.: 18 Column: a
This relates significantly to gain or loss on reacquired debt (non-utility).
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
Description and Purpose of
Other Regulatory Liabilities
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
OTHER REGULATORY LIABILITIES (Account 254)
DEBITS
Account
Credited
Amount
(c)
(d)
Credits
(e)
Year/Period of Report
End of 2010/Q4
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
(a)
1 Electric Procurement Collateral Payment
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
Balance at Begining
of Current
Quarter/Year
(b)
Balance at End
of Current
Quarter/Year
(f)
Miscellaneous Gas Reg Liab - Current 3,878,394 182.3
480,284 3,398,110
Miscellaneous Gas Reg Liab - NonCurrent
Miscellaneous Electric Reg Liab - Current
( 204,540) 204,540
155,149,395 Various
88,716,461 66,432,934
Miscellaneous Electric Reg Liab - NonCurrent 70,297,858 254
50,292,910 20,004,948
Sempra & Price Indexing Gas
1,154,355 -1,154,355
Non Current Reg Liab-CC8 Settlement 64,843,137 107
2,059,472 62,783,665
Direct Access Discretionary Cost/Revenue ( 6,729,794) 182.3
1,745,783 -8,475,577
Humboldt Bay Power Plant Memo Account
Affiliate Transaction Fee Memo Account
3,010,509 2,264,497
5,275,006
252,345 136,606
388,951
Gas Price Risk Management - Current 2,221,700 176
1,579,688 642,012
Gas Price Risk Management - NonCurrent 4,767,170 176
3,377,108 1,390,062
Electric Price Risk Management - Curren 73,966,343 175
31,668,835 42,297,508
Electric Price Risk Management - NonCurrent
Headroom Account
FAS 143 Regulatory Liability
FIN 47 Regulatory Liability
Customer Credit Holding Account
California Solar Initiative
Air Conditioning Expenditure
Energy Efficiency - Electric
PPP Energy Efficiency - Gas
PPP Surcharge Energy Efficiency - Gas
PPP Low Income - Electric
PPP Low Income - Gas
PPP Surcharge Low Income - Gas
PPP Surcharge RDD - Gas
Affiliate Transfer Fees Account
Non-Tariffed Products and Svcs BA-Electric
Non-Tariffed Products and Svcs BA-Gas
Procurement Energy Effiency
On Bill Financing Balancing Electric
On Bill Financing Balancing Gas
Hazardous Insurance Recoveries
59,405,376 7,653,877
67,059,253
164,285 Various
2 164,283
715,573,013 125,137,795 840,710,808
( 227,286,219) Various
13,209,122 -240,495,341
131,611 295
131,906
208,624,631 Various
58,840,364 149,784,267
45,248,238 31,138,558
76,386,796
43,383,959 9,085,948
52,469,907
16,812,567 6,881,420
23,693,987
( 7,998,044) Various
8,039,556 -16,037,600
18,875,655 10,182,161
29,057,816
5,931,025 Various
3,190,641 2,740,384
( 8,111,186) 4,424,240
-3,686,946
( 520,564) 262,098
-258,466
99,404 53,813
153,217
( 43,004) 317,191
274,187
( 35,185) 259,521
224,336
57,352,175 21,706,205
79,058,380
15,189,552
3,334,202
24,450,543
15,189,552
3,334,202
24,450,543
41 TOTAL 1,299,060,254
264,354,581 262,683,062 1,297,388,735
FERC FORM NO. 1/3-Q (REV 02-04) Page 278

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 278 Line No.: 7 Column: a
The designations for the type of supporting structure in this column are defined as
follows:
SSP - Single Steel Poles
SWP - Single Wood Poles
WH - Wood "H" Structures
T - Steel Towers
UG - Underground
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
ELECTRIC OPERATING REVENUES (Account 400)
Year/Period of Report
End of 2010/Q4
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added
for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of
each month.
4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
Title of Account
Operating Revenues Year
to Date Quarterly/Annual
(a)
(b)
Sales of Electricity
(440) Residential Sales 4,795,501,768
(442) Commercial and Industrial Sales
Small (or Comm.) (See Instr. 4) 5,559,550,382
Large (or Ind.) (See Instr. 4) 1,423,531,071
(444) Public Street and Highway Lighting 71,456,772
(445) Other Sales to Public Authorities 2,465,159
(446) Sales to Railroads and Railways 4,362,151
(448) Interdepartmental Sales 22,540,420
TOTAL Sales to Ultimate Consumers 11,879,407,723
(447) Sales for Resale 63,271,138
TOTAL Sales of Electricity 11,942,678,861
(Less) (449.1) Provision for Rate Refunds -21,673,968
TOTAL Revenues Net of Prov. for Refunds 11,964,352,829
Other Operating Revenues
(450) Forfeited Discounts 4,305,310
(451) Miscellaneous Service Revenues 10,738,741
(453) Sales of Water and Water Power 372,864
(454) Rent from Electric Property 56,516,278
(455) Interdepartmental Rents
(456) Other Electric Revenues -1,306,972,894
(456.1) Revenues from Transmission of Electricity of Others 11,856,022
(457.1) Regional Control Service Revenues
(457.2) Miscellaneous Revenues
(400) Balancing Accounts -35,004,349
TOTAL Other Operating Revenues -1,258,188,028
TOTAL Electric Operating Revenues 10,706,164,801
Operating Revenues
Previous year (no Quarterly)
(c)
4,759,286,389
5,307,906,424
1,391,727,726
68,305,535
2,320,306
3,180,894
18,740,759
11,551,468,033
66,368,799
11,617,836,832
-16,184,278
11,634,021,110
5,417,340
12,801,301
394,065
51,267,749
-1,895,642,980
11,727,726
487,540,636
-1,326,494,163
10,307,526,947
FERC FORM NO. 1/3-Q (REV. 12-05)
Page 300

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
ELECTRIC OPERATING REVENUES (Account 400)
Year/Period of Report
End of 2010/Q4
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification
in a footnote.)
7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD
AVG.NO. CUSTOMERS PER MONTH
Year to Date Quarterly/Annual
Amount Previous year (no Quarterly)
Current Year (no Quarterly) Previous Year (no Quarterly)
(d) (e) (f) (g)
30,744,336 31,234,681 4,565,637
4,578,151 2
37,932,845 38,761,410 613,773
613,472 4
14,414,954 14,805,543 1,293
1,335 5
448,325 445,730 31,850
31,252 6
19,761 19,957 16
16 7
345,718 360,383 27
29 8
158,542 135,583
9
84,064,481 85,763,287 5,212,596
5,224,255 10
1,607,595 1,865,338 3
3 11
85,672,076 87,628,625 5,212,599
5,224,258 12
85,672,076 87,628,625 5,212,599
5,224,258 14
Line
No.
1
3
13
Line 12, column (b) includes $
Line 12, column (d) includes
0
0
of unbilled revenues.
MWH relating to unbilled revenues
FERC FORM NO. 1/3-Q (REV. 12-05)
Page 301

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 300 Line No.: 4 Column: b
Line 4 includes all other commercial and industrial customers including irrigation
pumping.
Schedule Page: 300 Line No.: 5 Column: b
Line 5 includes commercial and industrial customers with demands of 1,000 Kw or greater.
Schedule Page: 300 Line No.: 10 Column: b
This includes California Department of Water Resources ("DWR") revenues of $1,455,848,989,
which was deducted from Line 21 below.
Schedule Page: 300 Line No.: 10 Column: d
This includes Direct Access MWh of 4,192,541 and DWR MWh of 9,799,434
Schedule Page: 300 Line No.: 17 Column: b
This consists of :
NSF fees and rent charges to customers' refundable deposits 4,540,811
Funds received from customers for damages to Utility property (144,691)
MLX billings to electric residential customers 3,132,311
MLX billings to electric non-residential customers 1,844,965
Miscellaneous (items under $250,000) 234,764
Misc. Service Revenues 1,130,581
Total 10,738,741
Schedule Page: 300 Line No.: 21 Column: b
This consists of :
California Department of Water Resources ("DWR") (1,382,937,262)
Unbilled revenues (19,086,906)
Other electric revenues not classified elsewhere 71,007,541
Reimbursement to the Utility for costs spent on customer
43,530,065
projects
Reimbursement fees paid to the CPUC based on sales (19,932,988)
Transition Cost Revenue Account for non-bypassable charges 18,184,726
Revenue assigned - base (19,070,114)
Other revenue-damage claim 1,207,330
MCI rights of way 864,577
Timber sales 1,324,862
Miscellaneous (items under $400,000) (2,064,724)
Total (1,306,972,894)
The DWR revenues of ($1,382,937,262) above represents amount passed through to the DWR.
The Utility acts as a pass-through entity for electricity purchased by the DWR that is
sold to the Utility's customers. Although charges for electricity provided by the DWR are
included in the amounts the Utility bills its customers, the Utility deducts from
electricity revenues amounts passed through to the DWR. The pass-through amounts are based
on the quantities of electricity provided by the DWR that are consumed by customers,
priced at the related CPUC-approved remittance rate. These pass-through amounts are
excluded from the Utility's electricity revenues in its Statement of Income.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
Year/Period of Report
End of 2010/Q4
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Number and Title of Rate schedule MWh Sold
Revenue Average Number KWh of Sales Revenue Per
No.
of Customers Per Customer KWh Sold
(a)
(b)
(c)
(d)
(e)
(f)
1 440 Residential Sales:
2 E1 - Individually Metered
3 E1 - California Alternate Rates
4 for Energy (CARE) for
5 low income
28,195,058 4,376,274,502
4,400,351 6,407 0.1552
6 E6
7 E6 - CARE for Low Income
8 E7 - Time-of-Use (TOU)
9 E7 - CARE for Low Income
10 E8 -Seasonal Service Option
11 E8 - CARE for Low Income
64,563
787,049
898,112
12,363,876
133,916,764
177,774,117
9,845
76,241
57,178
6,558
10,323
15,707
0.1915
0.1702
0.1979
12 EA7 -Experimental Alternate
13 Peak TOU Service
14 EA7 - CARE for Low Income
15 EA9
503
1,622
80,939
314,082
39
166
12,897
9,771
0.1609
0.1936
16 EB9
29 3,967
15 1,933 0.1368
17 ECLSD
-2,108
18 EM -Master-Metered Multi- family
286,850 50,466,014
18,622 15,404 0.1759
19 ENET - New Energy Metering Servic
-54
20 EML -Multifamily CARE Program
27,497 2,359,162
181 151,917 0.0858
21 EMTOU
189 23,178
5 37,800 0.1226
22 ES -Multi-family Service
27,091 3,184,338
263 103,008 0.1175
23 ESL -Multifamily CARE
29,633 2,981,294
261 113,536 0.1006
24 ESR -RV Park and Residential Mari
1,381 175,815
31 44,548 0.1273
25 ESRL -RV Park and Residential Ma
6,069 680,142
60 101,150 0.1121
26 ET -Mobilehome Park Service
17,724 1,707,336
278 63,755 0.0963
27 ETL -Low-Income Mobile Home
397,906 32,775,291
2,079 191,393 0.0824
28 MIS-RS
29 MULTI-RS
30 NEMS
-2,341
-651
31 SE1 -Standby - Individually Meter
7 789
1 7,000 0.1127
32 SEM1 -Standby - Master-Metered
2,993 408,315
10 299,300 0.1364
33 STOUS -Standby - TOU
58
1
34 STOUS -Standby - TOU Secondary -
35 UNCLASSIFIED
36
61
16,942
10
37 SUBTOTAL RESIDENTIAL
38
39 442 Commercial and Industrial
40 Sales:
30,744,337 4,795,501,767
4,565,637 6,734 0.1560
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
FERC FORM NO. 1 (ED. 12-95) Page 304
0 0 0 0 0.0000
0 0 0 0 0.0000
0 0 0 0 0.0000

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
Year/Period of Report
End of 2010/Q4
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Number and Title of Rate schedule MWh Sold
Revenue Average Number KWh of Sales Revenue Per
No.
of Customers Per Customer KWh Sold
(a)
(b)
(c)
(d)
(e)
(f)
1 A1 -Small General Service
6,851,680 1,242,760,084
399,858 17,135 0.1814
2 A1F -Small General Service
75,985 15,168,547
18,346 4,142 0.1996
3
1,157 212,520
53 21,830 0.1837
4 A15 -Small General Service
5 A1NC
6 A1NR
649 292,682
533 1,218 0.4510
7 A6 -TOU
1,747,178 296,985,614
27,659 63,169 0.1700
8 A10 -Medium General Demand-
9 Metered Service
10 E1
11 E19 -500 to 999 Kw Demand
9,852,725
12,358,129
1,536,838,975
1,533,575,609
48,398
17,137
203,577
721,137
0.1560
0.1241
12 E20 -1000 Kw Demand or More
13,070,374 1,272,331,981
1,047 12,483,643 0.0973
13 E37 - 1000 Kw Demand or More
1,129,638 107,814,772
608 1,857,957 0.0954
14 ECLSD
15 ENET
16 MIS-RS
17 NEMS
4,460
18 AG1 -Agricultural Power
452,819 114,589,284
38,072 11,894 0.2531
19 AG4 -TOU Agricultural Power
583,573 109,322,099
20,607 28,319 0.1873
20 AG5 -Large TOU
21 Agricultural Power
22 AGICE
3,635,956
303,607
466,189,632
26,897,904
17,751
1,967
204,831
154,350
0.1282
0.0886
23 AGR -Split-Wk TOU
24 Agricultural Power
25 AGV -Short-Pk TOU
26 Agricultural Power
57,905
36,607
11,501,212
7,238,811
3,129
2,208
18,506
16,579
0.1986
0.1977
27 OL1 -Outdoor Area Lighting Serv
11,756 3,163,233
17,069 689 0.2691
28 SA1 -Standby & General
29 Service
30 SA6 -Standby & Small TOU
437
8,617
78,111
1,605,460
8
16
54,625
538,563
0.1787
0.1863
31 SA10 -Standby & Alt. Rate for
32 Med-Use
33 SAG1B
34 SAG4E
35 SAG5B
31,721
5
4,793,673
1,174
43 737,698 0.1511
0.2348
36 SE19 -Standby & 500 to 999 Kw
37 Demand or More
38 SE20 -Standby & 1000 Kw
39 1001430
160,320
966,059
21,490,602
103,468,282
81
80
1,979,259
12,075,738
0.1340
0.1071
40 SE37 -Standby - Med Gen
610,010 53,525,101
5 122,002,000 0.0877
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
FERC FORM NO. 1 (ED. 12-95) Page 304.1
0 0 0 0 0.0000
0 0 0 0 0.0000
0 0 0 0 0.0000

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
Year/Period of Report
End of 2010/Q4
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Number and Title of Rate schedule MWh Sold
Revenue Average Number KWh of Sales Revenue Per
No.
of Customers Per Customer KWh Sold
(a)
(b)
(c)
(d)
(e)
(f)
1 Demand-Mtrd TOU Svc
2 STOUP -Standby - TOU Primary
21,070 5,822,863
126 167,222 0.2764
3 STOUS -Standby - TOU
4 Secondary
5 STOUT -Standby - TOU
6 Transformer
7 E31
8 UNCLASSIFIED
9
5,980
373,825
18
1,487,540
44,368,098
1,553,130
116
149
51,552
2,508,893
0.2488
0.1187
86.2850
10 SUBTOTAL COMMERCIAL
11 AND INDUSTRIAL
12
13 444 Public Street and
14 Highway Lighting
52,347,800 6,983,081,453
615,066 85,109 0.1334
15 LS1-A -Utility-Owned Street
16 & Highway Lighting
31,415 9,108,908
3,922 8,010 0.2900
17 LS1-B -Utility-Owned Street
18 & Highway Lighting
30 6,336
8 3,750 0.2112
19 LS1-C -Utility-Owned Street
20 & Highway Lighting
21 LS1-D -Utility-Owned Street
22 & Highway Lighting
23 LS1-E -Utility-Owned Street
24 & Highway Lighting
25 LS1-F -Utility-Owned Street
26 & Highway Lighting
10,080
6,351
17,451
8,178
2,451,154
2,286,446
5,466,628
2,607,881
565
793
1,277
1,403
17,841
8,009
13,666
5,829
0.2432
0.3600
0.3133
0.3189
27 LS1-F1 -Utility-Owned Street
28 & Highway Lighting
3 1,023
7 429 0.3410
29 LS2-A -Customer-Owned Street
30 & Highway Lighting
310,990 39,117,582
8,462 36,751 0.1258
31 LS2-B
17 2,425
2 8,500 0.1426
32 LS2-C -Customer-Owned Street
33 & Highway Lighting
34 LS3 -Cust-Owned Street
35 & Highway Lighting
36 LS3-F -Cust-Owned Street
37 & Highway Lighting
38 TC1 -Traffic Control Service
11,136
8,873
4,080
38,489
1,899,650
1,167,764
660,952
6,447,585
657
1,047
2,198
10,914
16,950
8,475
1,856
3,527
0.1706
0.1316
0.1620
0.1675
39 TC1F -Traffic Control Service
1,228 232,436
595 2,064 0.1893
40 UNCLASSIFIED
3
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
FERC FORM NO. 1 (ED. 12-95) Page 304.2
0 0 0 0 0.0000
0 0 0 0 0.0000
0 0 0 0 0.0000

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
Year/Period of Report
End of 2010/Q4
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Number and Title of Rate schedule MWh Sold
Revenue Average Number KWh of Sales Revenue Per
No.
of Customers Per Customer KWh Sold
(a)
(b)
(c)
(d)
(e)
(f)
1
2 SUBTOTAL PUBLIC STREET
3 & HIGHWAY LIGHTING
4
5 445 Other Sales to Public Au-
6 thorities - Special Contracts
7
8 SUBTOTAL OTHER SALES
9 TO PUBLIC AUTHORITIES
10
11 446 Sales to Railroads and
12 Railways Special Contracts
13
14 SUBTOTAL SALES TO
15 RAILROADS AND RAILWAYS
16
17 448 Interdepartmental Sales
18
19 SUBTOTAL INTERDEPART-
20 MENTAL SALES
21
22 TOTAL SALES TO ULTIMATE
23 CONSUMERS
24
25 447 Sales for Resale
26 Special Contracts
27
28 TOTAL SALES FOR RESALE
29
30 RECAP:
31 Sales to Ultimate Consumer
32 Sale for Resale
33
34 TOTAL BILLED
35
36
37
38
39
40
448,324 71,456,770
31,850 14,076 0.1594
19,761 2,465,160
16 1,235,063 0.1247
19,761 2,465,160
16 1,235,063 0.1247
345,718 4,632,151
27 12,804,370 0.0134
345,718 4,632,151
27 12,804,370 0.0134
158,542 22,540,420
0.1422
158,542 22,540,420
0.1422
84,064,482 11,879,677,721
5,212,596 16,127 0.1413
1,607,595 63,271,138
3 535,865,000 0.0394
1,607,595 63,271,138
3 535,865,000 0.0394
84,064,482 11,879,677,721
5,212,596 16,127 0.1413
1,607,595 63,271,138
3 535,865,000 0.0394
85,672,077 11,942,948,859
5,212,599 16,436 0.1394
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
FERC FORM NO. 1 (ED. 12-95) Page 304.3
0 0 0 0 0.0000
0 0 0 0 0.0000
0 0 0 0 0.0000

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 304.2 Line No.: 10 Column: a
(1) Mr. Mistry became VP and Controller on March 8, 2010.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
SALES FOR RESALE (Account 447)
Year/Period of Report
End of 2010/Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Name of Company or Public Authority Statistical FERC Rate
Average
Actual Demand (MW)
Classifi- Schedule or Monthly Billing Average
(Footnote Affiliations)
Average
cation Tariff Number Demand (MW) Monthly NCP Demand Monthly CP Demand
(a)
(b)
(c)
(d)
(e)
(f)
Silicon Valley Power RQ
85
0.1
17.6
17.6
Hetch Hetchy RQ
114
18.6
18.6
18.6
California Independent
System Operator (ISO)
RQ
6
n/a
n/a
n/a
Subtotal RQ
0
0 0
Subtotal non-RQ
0
0
0
Total
0
0
0
FERC FORM NO. 1 (ED. 12-90) Page 310

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
SALES FOR RESALE (Account 447) (Continued)
Year/Period of Report
End of 2010/Q4
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(g)
REVENUE
Total ($) Line
Demand Charges Energy Charges Other Charges
(h+i+j)
No.
($) ($) ($)
(h)
(i)
(j)
(k)
188 77 24,002
-24,079
1
1,118,000 26,825 1,144,825 2
1,607,407 62,126,313 62,126,313 4
3
5
6
7
8
9
10
11
12
13
14
1,607,595
1,118,077
62,150,315
2,746 63,271,138
0
0
0
0
0
1,607,595
1,118,077
62,150,315
2,746
63,271,138
FERC FORM NO. 1 (ED. 12-90) Page 311

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 310 Line No.: 1 Column: a
Sales represent the Grizzly Power Sale.
Schedule Page: 310 Line No.: 1 Column: j
Other charges represent booking estimate adjustments.
Schedule Page: 310 Line No.: 2 Column: a
Represents Supplemental Demand A-1, Supplemental Demand A-2, and energy sales, if
applicable.
Schedule Page: 310 Line No.: 2 Column: j
Other charges represent booking estimate adjustments.
Schedule Page: 310 Line No.: 4 Column: a
Represents amounts included in ISO Settlement Statement on page 397.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
Account
Amount for
Current Year
No.
(a)
(b)
Year/Period of Report
End of 2010/Q4
Amount for
Previous Year
(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering
5 (501) Fuel
148,272,824
107,910,039
6 (502) Steam Expenses
29,309
8,616
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses
10 (506) Miscellaneous Steam Power Expenses
9,486,442
10,006,307
11 (507) Rents
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)
157,788,575
117,924,962
14 Maintenance
15 (510) Maintenance Supervision and Engineering
16 (511) Maintenance of Structures
44,569
3,898
17 (512) Maintenance of Boiler Plant
1,575,759
1,070,676
18 (513) Maintenance of Electric Plant
9,956,103
17,227,162
19 (514) Maintenance of Miscellaneous Steam Plant
5,283,867
6,255,935
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)
16,860,298
24,557,671
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)
174,648,873
142,482,633
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering
25 (518) Fuel
105,267,617
89,842,086
26 (519) Coolants and Water
29,049,330
30,657,140
27 (520) Steam Expenses
49,020,065
45,078,190
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Expenses
1,620,980
4,566,404
31 (524) Miscellaneous Nuclear Power Expenses
84,464,062
86,775,275
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
269,422,054
256,919,095
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
8,515,850
13,318,977
37 (530) Maintenance of Reactor Plant Equipment
33,840,917
50,251,342
38 (531) Maintenance of Electric Plant
40,039,351
44,809,825
39 (532) Maintenance of Miscellaneous Nuclear Plant
18,668,000
22,075,462
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
101,064,118
130,455,606
41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
370,486,172
387,374,701
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering
45 (536) Water for Power
5,275,893
5,847,524
46 (537) Hydraulic Expenses
3,678,661
3,192,674
47 (538) Electric Expenses
20,301,242
20,099,111
48 (539) Miscellaneous Hydraulic Power Generation Expenses
29,573,615
27,471,536
49 (540) Rents
2,577,246
2,220,193
50 TOTAL Operation (Enter Total of Lines 44 thru 49)
61,406,657
58,831,038
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering
54 (542) Maintenance of Structures
3,798,130
3,340,833
55 (543) Maintenance of Reservoirs, Dams, and Waterways
21,150,049
17,608,490
56 (544) Maintenance of Electric Plant
20,546,485
24,126,127
57 (545) Maintenance of Miscellaneous Hydraulic Plant
8,873,663
8,747,748
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
54,368,327
53,823,198
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)
115,774,984
112,654,236
FERC FORM NO. 1 (ED. 12-93) Page 320

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
Account
Amount for
Current Year
No.
(a)
(b)
Year/Period of Report
End of 2010/Q4
Amount for
Previous Year
(c)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering
63 (547) Fuel
1,017,375
4,638,032
64 (548) Generation Expenses
319,182
3,330
65 (549) Miscellaneous Other Power Generation Expenses
-12,988,223
2,313,177
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)
-11,651,666
6,954,539
68 Maintenance
69 (551) Maintenance Supervision and Engineering
70 (552) Maintenance of Structures
641,374
424,002
71 (553) Maintenance of Generating and Electric Plant
579,550
624,590
72 (554) Maintenance of Miscellaneous Other Power Generation Plant
624,695
963,269
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)
1,845,619
2,011,861
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)
-9,806,047
8,966,400
75 E. Other Power Supply Expenses
76 (555) Purchased Power
3,633,537,677
3,490,737,323
77 (556) System Control and Load Dispatching
78 (557) Other Expenses
64,639,548
69,828,126
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)
3,698,177,225
3,560,565,449
80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79)
4,349,281,207
4,212,043,419
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering
84 (561) Load Dispatching
1,332
85 (561.1) Load Dispatch-Reliability
86 (561.2) Load Dispatch-Monitor and Operate Transmission System
19,551,973
14,484,818
87 (561.3) Load Dispatch-Transmission Service and Scheduling
88 (561.4) Scheduling, System Control and Dispatch Services
44,725,102
36,171,609
89 (561.5) Reliability, Planning and Standards Development
262
91,027
90 (561.6) Transmission Service Studies
372
91 (561.7) Generation Interconnection Studies
92 (561.8) Reliability, Planning and Standards Development Services
7,632,274
8,128,841
93 (562) Station Expenses
4,746,698
7,411,362
94 (563) Overhead Lines Expenses
16,515,771
19,794,891
95 (564) Underground Lines Expenses
1,452,941
1,488,018
96 (565) Transmission of Electricity by Others
21,572,412
21,591,178
97 (566) Miscellaneous Transmission Expenses
29,355,517
33,749,859
98 (567) Rents
99 TOTAL Operation (Enter Total of lines 83 thru 98)
145,553,322
142,912,935
100 Maintenance
101 (568) Maintenance Supervision and Engineering
102 (569) Maintenance of Structures
2,808,862
1,600,622
103 (569.1) Maintenance of Computer Hardware
1,667,864
1,499,612
104 (569.2) Maintenance of Computer Software
871,770
697,771
105 (569.3) Maintenance of Communication Equipment
1,356,282
1,582,419
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment
19,314,152
17,050,315
108 (571) Maintenance of Overhead Lines
35,560,058
35,010,107
109 (572) Maintenance of Underground Lines
653,004
816,340
110 (573) Maintenance of Miscellaneous Transmission Plant
349,685
281,000
111 TOTAL Maintenance (Total of lines 101 thru 110)
62,581,677
58,538,186
112 TOTAL Transmission Expenses (Total of lines 99 and 111)
208,134,999
201,451,121
FERC FORM NO. 1 (ED. 12-93) Page 321

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
Account
Amount for
Current Year
No.
(a)
(b)
Year/Period of Report
End of 2010/Q4
Amount for
Previous Year
(c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Rights Market Facilitation
118 (575.4) Capacity Market Facilitation
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services
9,039,432
11,662,949
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
9,039,432
11,662,949
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)
9,039,432
11,662,949
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering
135 (581) Load Dispatching
136 (582) Station Expenses
3,071,381
6,482,773
137 (583) Overhead Line Expenses
17,837,032
14,949,299
138 (584) Underground Line Expenses
28,698,062
25,038,219
139 (585) Street Lighting and Signal System Expenses
52,545
140 (586) Meter Expenses
-1,678,114
-1,641,962
141 (587) Customer Installations Expenses
23,609,207
25,694,010
142 (588) Miscellaneous Expenses
82,264,736
88,624,137
143 (589) Rents
144 TOTAL Operation (Enter Total of lines 134 thru 143)
153,802,304
159,199,021
145 Maintenance
146 (590) Maintenance Supervision and Engineering
147 (591) Maintenance of Structures
9,103,204
7,759,024
148 (592) Maintenance of Station Equipment
25,858,790
24,106,586
149 (593) Maintenance of Overhead Lines
277,298,657
259,994,803
150 (594) Maintenance of Underground Lines
28,742,412
27,110,565
151 (595) Maintenance of Line Transformers
3,118,453
83,343
152 (596) Maintenance of Street Lighting and Signal Systems
4,307,590
4,390,200
153 (597) Maintenance of Meters
3,869,621
2,556,284
154 (598) Maintenance of Miscellaneous Distribution Plant
118,254
103,826
155 TOTAL Maintenance (Total of lines 146 thru 154)
352,416,981
326,104,631
156 TOTAL Distribution Expenses (Total of lines 144 and 155)
506,219,285
485,303,652
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision
160 (902) Meter Reading Expenses
37,333,416
44,102,420
161 (903) Customer Records and Collection Expenses
137,891,659
142,677,335
162 (904) Uncollectible Accounts
44,381,617
55,796,063
163 (905) Miscellaneous Customer Accounts Expenses
85,852
95,048
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163)
219,692,544
242,670,866
FERC FORM NO. 1 (ED. 12-93) Page 322

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
Account
Amount for
Current Year
No.
(a)
(b)
Year/Period of Report
End of 2010/Q4
Amount for
Previous Year
(c)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Assistance Expenses
685,131,746
692,449,590
169 (909) Informational and Instructional Expenses
1,800,964
37,052
170 (910) Miscellaneous Customer Service and Informational Expenses
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170)
686,932,710
692,486,642
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision
175 (912) Demonstrating and Selling Expenses
8,649,009
5,540,811
176 (913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)
8,649,009
5,540,811
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries
204,020,880
324,001,999
182 (921) Office Supplies and Expenses
17,987,790
15,322,873
183 (Less) (922) Administrative Expenses Transferred-Credit
27,384,595
44,907,723
184 (923) Outside Services Employed
135,128,569
135,568,475
185 (924) Property Insurance
14,344,568
9,393,615
186 (925) Injuries and Damages
66,259,243
57,567,250
187 (926) Employee Pensions and Benefits
277,048,419
274,650,832
188 (927) Franchise Requirements
90,224,140
89,140,441
189 (928) Regulatory Commission Expenses
190 (929) (Less) Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses
2,074,773
387,169
192 (930.2) Miscellaneous General Expenses
4,628,192
4,238,648
193 (931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)
784,331,979
865,363,579
195 Maintenance
196 (935) Maintenance of General Plant
11,056,083
15,937,376
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)
795,388,062
881,300,955
198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197)
6,783,337,248
6,732,460,415
FERC FORM NO. 1 (ED. 12-93) Page 323

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
QUALIFYING FACILITIES (QF's)
2
THERMAL: BIOMASS
3
BIG VALLEY POWER LLC
LU
N/A
0.3665
N/A
4
BURNEY FOREST PRODUCTS
LU
24
31.42916667
N/A
5
COLLINS PINE
LU
5.5
8.805
N/A
6
COVANTA MENDOTA L. P.
LU
22
25.1971545
N/A
7
DG FAIRHAVEN POWER, LLC
LU
16
14.95258333
N/A
8
HL POWER
LU
20
27.213184
N/A
9
OGDEN POWER PACIFIC, INC. (BURNEY)
LU
9.75
9.629
N/A
10
OGDEN POWER PACIFIC, INC. (MT.
LU
10.5
9.7575
N/A
11
OGDEN POWER PACIFIC, INC. (OROVILLE) LU
16.5
11.772
N/A
12
PACIFIC-ULTRAPOWER CHINESE
LU
19.8
19.53725
N/A
13
RIO BRAVO FRESNO
LU
23.5
24.75358333
N/A
14
RIO BRAVO ROCKLIN
LU
22
24.733
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
SIERRA PACIFIC IND. (BURNEY)
LU
9.5
14.63316667
N/A
2
SIERRA PACIFIC IND. (LINCOLN)
LU
4.98
13.11833333
N/A
3
SIERRA PACIFIC IND. (QUINCY)
LU
12.5
20.468
N/A
4
SIERRA PACIFIC IND.(SUSANVILLE)
LU
9.842
0
N/A
5
SONOMA COUNTY WATER AGENCY
LU
0
0
N/A
6
THERMAL ENERGY DEV. CORP.
LU
13
19.2975
N/A
7
TOWN OF SCOTIA COMPANY, LLC
LU
N/A
22.492
N/A
8
WHEELABRATOR SHASTA
LU
49.68
48.978
N/A
9
WOODLAND BIOMASS
LU
22
18.972
N/A
10
THERMAL: ENHANCED OIL RECOVERY
11
AERA ENERGY LLC. (COALINGA)
LU
N/A
3.064833333
N/A
12
AERA ENERGY LLC. (N. MIDWAY SUNSET) LU
N/A
0
N/A
13
AERA ENERGY LLC. (OXFORD)
LU
N/A
0
N/A
14
AERA ENERGY LLC. (S. BELRIDGE)
LU
N/A
5.811583333
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
BADGER CREEK LIMITED
LU
42
47.891801
N/A
2
BEAR MOUNTAIN LIMITED
LU
42
49.31991667
N/A
3
BERRY PETROLEUM COMPANY
LU
N/A
11.95741667
N/A
4
CHALK CLIFF LIMITED
LU
42
47.49125
N/A
5
CHEVRON USA (COALINGA)
LU
N/A
11.17808333
N/A
6
CHEVRON USA (CYMRIC)
LU
N/A
7.37575
N/A
7
CHEVRON USA (EASTRIDGE)
LU
N/A
18.93616667
N/A
8
CHEVRON USA (TAFT/CADET)
LU
N/A
5.547166667
N/A
9
CHEVRON U.S.A. INC. (FEE A)
LU
N/A
3.759
N/A
10
CHEVRON U.S.A INC. (FEE C)
LU
N/A
1.82725
N/A
11
CHEVRON U.S.A. INC. (SE KERN RIVER)
LU
N/A
17.16483333
N/A
12
CHEVRON U.S.A. INC. (MCKITTRICK)
LU
N/A
5.465568333
N/A
13
COALINGA COGENERATION COMPANY
LU
33
40.81541667
N/A
14
DAI / OILDALE , INC.
LU
29
30.04558333
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
DOUBLE C
LU
47
36.47575817
N/A
2
GRAPHIC PACKAGING INT'L (BLUE
LU
N/A
17.88333358
N/A
3
HIGH SIERRA LIMITED
LU
47
18.55919875
N/A
4
JACKSON VALLEY IRRIGATION DIST
LU
N/A
0.079166667
N/A
5
KERN FRONT LIMITED
LU
47
23.19930825
N/A
6
LIVE OAK LIMITED
LU
42
48.84483333
N/A
7
MCKITTRICK LIMITED
LU
42
47.142
N/A
8
MIDSET COGEN. CO.
LU
N/A
0
N/A
9
MIDWAY-SUNSET COGEN. CO.
LU
N/A
26.70181818
N/A
10
PLAINS EXPLORATION AND PRODUCTION LU
N/A
1.510333333
N/A
11
PLAINS EXPLORATION AND PRODUCTION LU
N/A
1.379166667
N/A
12
SALINAS RIVER COGEN CO
LU
N/A
38.818
N/A
13
SARGENT CANYON COGERATION
LU
N/A
36.502
N/A
14
THERMAL: COGENERATION
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
ALTAMONT COGENERATION CORP.
LU
5.7
0
N/A
2
CALPINE KING CITY COGEN.
LU
111
121.856
3
CALPINE GILROY COGEN, L.P.
LU
N/A
N/A
N/A
4
CALPINE KING CITY COGEN.
LU
111
121.856
N/A
5
CALPINE MONTEREY COGEN INC.
LU
20.9
14.9545
N/A
6
CALPINE PITTSBURG POWER PLANT
LU
N/A
3.132
N/A
7
CARDINAL COGEN
LU
N/A
29.49114492
N/A
8
CHEVRON USA (CONCORD)
LU
N/A
0.867583333
N/A
9
GATX/CALPINE COGEN-AGNEWS INC.
LU
24
28.94383333
N/A
10
GRAPHIC PACKAGING INT'L (BLUE
LU
N/A
17.88333358
N/A
11
CROCKETT COGEN
LU
240
222.92099
N/A
12
GREENLEAF UNIT #1
LU
49.2
49.79508333
N/A
13
GREENLEAF UNIT #2
LU
49.2
49.608
N/A
14
MARTINEZ COGEN LIMITED
LU
10
40.76116667
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
OROVILLE COGEN
LU
7.5
4.479583333
N/A
2
PE - KES KINGSBURG,LLC
LU
34.5
32.434
N/A
3
SAN JOAQUIN POWER COMPANY
LU
0
0
N/A
4
SAN JOSE COGEN
LU
N/A
0.455
N/A
5
SRI INTERNATIONAL
LU
N/A
2.28
N/A
6
UNITED AIRLINES (COGEN)
LU
25.65
26.2305
N/A
7
WHEELABRATOR LASSEN INC.
LU
42
6.930168
N/A
8
YUBA CITY COGEN
LU
46
48.3625
N/A
9
NAPA STATE HOSPITAL
LU
N/A
0.40325
N/A
10
OCCIDENTAL OF ELK HILLS
LU
N/A
0
N/A
11
OILDALE ENERGY LLC
LU
29
40.21216667
N/A
12
PE - BERKELEY, INC.
LU
22.47
26.054
N/A
13
RHODIA INC. (RHONE- POULENC)
LU
N/A
0.529083333
N/A
14
RIPON COGENERATION, LLC
LU
42
47.98752508
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.5

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
SAINT AGNES MED. CTR
LU
N/A
1.1355
N/A
2
CONOCOPHILLIPS COMPANY
LU
N/A
8.4675
N/A
3
SANGER POWER, L.L.C.
LU
38
41.6675
N/A
4
FRESNO COGENERATION CORPORATION LU
33
19.25
N/A
5
FRITO LAY COGEN
LU
N/A
0.83425
N/A
6
THERMAL: WASTE TO ENERGY
7
WASTE MANAGEMENT RENEWABLE
LU
N/A
15.84074842
N/A
8
EBMUD (OAKLAND)
LU
N/A
1.620756667
N/A
9
GAS RECOVERY SYS. (AMERICAN CYN)
LU
0.836
1.367083333
N/A
10
GAS RECOVERY SYS. (GUADALUPE)
LU
1.443
2.302833333
N/A
11
GAS RECOVERY SYS. (MENLO PARK)
LU
0.95
1.134083333
N/A
12
GAS RECOVERY SYS. (NEWBY ISLAND 1)
LU
1.73
1.855
N/A
13
GAS RECOVERY SYS. (NEWBY ISLAND 2)
LU
3.76
3.19
N/A
14
GWF POWER SYSTEMS INC. #1
LU
16
19.71108333
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.6

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
GWF POWER SYSTEMS INC. #2
LU
16
19.218
N/A
2
GWF POWER SYSTEMS INC. #3
LU
16
18.772
N/A
3
GWF POWER SYSTEMS INC. #4
LU
16
19.30916667
N/A
4
GWF POWER SYSTEMS INC. #5
LU
16
19.5045
N/A
5
HANFORD L.P.
LU
22
23.99448
N/A
6
MONTEREY REGIONAL WASTE MGMT
LU
1.15
1.953061667
N/A
7
MONTEREY REGIONAL WATER
LU
N/A
0.212583333
N/A
8
COVANTA POWER PACIFIC (SALINAS)
LU
N/A
0
N/A
9
COVANTA POWER PACIFIC, STOCKTON
LU
N/A
0.766916667
N/A
10
PALO ALTO LANDFILL
LU
N/A
0
N/A
11
STANISLAUS WASTE ENERGY CO.
LU
16.5
17.96108333
N/A
12
THERMAL: COAL
13
AIR PRODUCTS MANUFACTURING
LU
N/A
51.14341667
N/A
14
MT.POSO COGENERATION CO.
LU
N/A
50.79233333
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.7

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
POSDEF (COGEN NATIONAL)
LU
44
0
N/A
2
RIO BRAVO POSO
LU
30
36.0215
N/A
3
RENEWABLE: GEOTHERMAL
4
AMEDEE GEOTHERMAL VENTURE 1
0.369
0.112166667
N/A
5
RENEWABLE: HYDRO
6
BAKER STATION ASSOCIATES L.P.
LU
N/A
1.141083333
N/A
7
CALAVERAS CTY WD
LU
N/A
0.592916667
N/A
8
EL DORADO (MONTGOMERY CK)
LU
N/A
2.166715917
N/A
9
FRIANT POWER AUTHORITY
LU
N/A
14.38266667
N/A
10
EIF HAYPRESS, LLC (LWR)
LU
N/A
1.682666667
N/A
11
EIF HAYPRESS LLC (MDL)
LU
N/A
1.780833333
N/A
12
HUMBOLDT BAY MWD
LU
N/A
0.868583333
N/A
13
HYPOWER, INC.
LU
N/A
9.41677775
N/A
14
INDIAN VALLEY HYDRO
LU
N/A
0.5635
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.8

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
KERN HYDRO (OLCESE)
LU
N/A
6.00075
N/A
2
MADERA-CHOWCHILLA WATER AND
LU
N/A
1.032624333
N/A
3
MALACHA HYDRO L.P.
LU
N/A
20.92
N/A
4
MEGA RENEWABLES (BIDWELL DITCH)
LU
N/A
1.488048667
N/A
5
MEGA RENEWABLES (HATCHET CRK)
LU
N/A
4.19206275
N/A
6
MEGA RENEWABLES (ROARING CRK)
LU
N/A
1.35558725
N/A
7
MERCED ID (PARKER)
LU
N/A
0.904666667
N/A
8
MONTEREY CTY WATER RES AGENCY
LU
N/A
1.923333333
N/A
9
NELSON CREEK POWER INC.
LU
N/A
0.731083333
N/A
10
NEVADA IRRIGATION DISTRICT/BOWMAN LU
N/A
1.781995833
N/A
11
NID/COMBIE SOUTH
LU
N/A
0.802666667
N/A
12
NID/SCOTTS FLAT
LU
N/A
0.600416667
N/A
13
NORMAN ROSS BURGESS
LU
N/A
1.547833333
N/A
14
OLSEN POWER PARTNERS
LU
N/A
2.26325
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.9

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
ORANGE COVE IRRIGATION DIST.
LU
N/A
0.416916667
N/A
2
ROCK CREEK L.P.
LU
N/A
1.48925
N/A
3
SNOW MOUNTAIN HYDRO LLC (LOST
LU
N/A
0.399128167
N/A
4
SNOW MOUNTAIN HYDRO LLC
LU
N/A
0.3805
N/A
5
SNOW MOUNTAIN HYDRO LLC (COVE)
LU
N/A
3.196017167
N/A
6
SNOW MOUNTAIN HYDRO LLC (BURNEY
LU
N/A
1.4105
N/A
7
SOUTH SAN JOAQUIN ID
LU
N/A
2.1385
N/A
8
SOUTH SAN JOAQUIN ID (WOODWARD)
LU
N/A
0.95775
N/A
9
STS HYDROPOWER LTD. (KANAKA)
LU
N/A
0.75875
N/A
10
STS HYDROPOWER LTD. (KEKAWAKA)
LU
N/A
3.5995
N/A
11
TKO POWER (SOUTH BEAR CREEK)
LU
N/A
0.262408167
N/A
12
TRI-DAM AUTHORITY
LU
15
11.829
N/A
13
YOLO COUNTY FLOOD & WCD
LU
N/A
0
N/A
14
YUBA COUNTY WATER (DEADWOOD
LU
N/A
0.789304167
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.10

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
MISC. CHARGES FOR VARIOUS
2
DISTRICTS
3
RENEWABLE: WIND
4
ALTAMONT ENERGY CORP
LU
N/A
0
N/A
5
ALTAMONT MIDWAY LTD.
LU
N/A
4.482
N/A
6
ALTAMONT POWER LLC (PARTNERS 1)
LU
N/A
0
N/A
7
ALTAMONT POWER LLC (PARTNERS 2)
LU
N/A
0
N/A
8
ALTAMONT POWER LLC (3-4 )
LU
N/A
1.5549925
N/A
9
ALTAMONT POWER LLC (4-4)
LU
N/A
7.9486435
N/A
10
ALTAMONT POWER LLC (6-4)
LU
N/A
6.588399333
N/A
11
GREEN RIDGE POWER LLC (10 MW)
LU
N/A
9.865651417
N/A
12
GREEN RIDGE POWER LLC (100 MW - A)
LU
N/A
24.92677375
N/A
13
GREEN RIDGE POWER LLC (100 MW - C)
LU
N/A
2.918652333
N/A
14
GREEN RIDGE POWER LLC (100 MW - D)
LU
N/A
5.666597667
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.11

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
GREEN RIDGE POWER LLC (110 MW)
LU
N/A
89.7254155
N/A
2
GREEN RIDGE POWER LLC (23.8 MW)
LU
N/A
4.997657833
N/A
3
GREEN RIDGE POWER LLC (5.9 MW)
LU
N/A
3.314973
N/A
4
GREEN RIDGE POWER LLC (70 MW - B)
LU
N/A
8.65554125
N/A
5
GREEN RIDGE POWER LLC (70 MW - C)
LU
N/A
13.95541517
N/A
6
GREEN RIDGE POWER LLC (70 MW - D)
LU
N/A
0.701941917
N/A
7
GREEN RIDGE POWER LLC (70 MW)
LU
N/A
26.55072567
N/A
8
INTERNATIONAL TURBINE RESEARCH
LU
N/A
13.83466667
N/A
9
J.V.ENTERPRISE
LU
N/A
0
N/A
10
NORTHWIND ENERGY
LU
N/A
6.435666667
N/A
11
PATTERSON PASS WIND FARM LLC
LU
N/A
13.0735
N/A
12
SEA WEST ENERGY GROUP (TOTALS)
LU
N/A
4.428083333
N/A
13
TOWN OF SCOTIA COMPANY, LLC
LU
N/A
22.492
N/A
14
TRES VAQUEROS WIND FARMS, LLC
LU
N/A
0
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.12

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
THERMAL: BIOMASS
2010
2
SIERRA PACIFIC IND. (ANDERSON)
LU
N/A
2.512833333
N/A
3
SIERRA PACIFIC IND. (SONORA)
LU
N/A
0
N/A
4
THERMAL: ENHANCED OIL RECOVERY
2010
5
BERRY PETROLEUM COGEN
LU
N/A
37.10875
N/A
6
CHEVRON U.S.A. INC. (NORTH MIDWAY)
LU
N/A
0.172833333
N/A
7
THERMAL: COGENERATION
2010
8
CHEVRON RICHMOND REFINERY
LU
N/A
13.92
N/A
9
UCSF
LU
N/A
2.422166667
N/A
10
SMALL POWER PRODUCERS -
11
AMERICAN ENERGY, INC. (SAN LUIS
LU
N/A
0
N/A
12
AMERICAN ENERGY, INC. ( WOLFSEN
LU
N/A
0.213416667
N/A
13
ARBUCKLE MOUNTAIN HYDRO
LU
N/A
0.152916667
N/A
14
BAILEY CREEK RANCH
LU
N/A
0.232916667
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.13

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
BROWNS VALLEY IRRIGATION DISTRICT
LU
N/A
0.4395
N/A
2
CALAVERAS YUBA HYDRO #1
LU
N/A
0.051003083
N/A
3
CALAVERAS YUBA HYDRO #2
LU
N/A
0.047900167
N/A
4
CALAVERAS YUBA HYDRO #3
LU
N/A
0.02676675
N/A
5
CANAL CREEK POWER PLANT (RETA)
LU
N/A
0.30625
N/A
6
CHARCOAL RAVINE
LU
N/A
0.00512025
N/A
7
CITY OF WATSONVILLE
LU
N/A
0.09575
N/A
8
COVANTA POWER PACIFIC, STOCKTON
LU
N/A
0.766916667
N/A
9
DAVID O. HARDE
LU
N/A
0.0011655
N/A
10
DIGGER CREEK RANCH
LU
N/A
0.4535
N/A
11
DONALD R. CHENOWETH
LU
N/A
0.000188417
N/A
12
E J M MCFADDEN
LU
N/A
0.0895
N/A
13
EAGLE HYDRO
LU
N/A
0.446166667
N/A
14
ERIC AND DEBBIE WATTENBURG
LU
N/A
0.060166667
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.14

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
FAIRFIELD POWER PLANT (PAPAZIAN)
LU
N/A
0.425666667
N/A
2
FAR WEST POWER CORPORATION
LU
N/A
0.058636667
N/A
3
FIVE BEARS HYDROELECTRIC
LU
N/A
0.14525
N/A
4
GAS RECOVERY SYSTEMS, INC [SANTA
LU
0.632
0
N/A
5
HAT CREEK HEREFORD RANCH
LU
N/A
0.038101333
N/A
6
HENWOOD ASSOCIATES
LU
N/A
0.386083333
N/A
7
JACKSON VALLEY IRRIGATION DIST
LU
N/A
0.079166667
N/A
8
JAMES B. PETER
LU
N/A
0.016568333
N/A
9
JAMES CRANE HYDRO
LU
N/A
0.00111225
N/A
10
JOHN NEERHOUT JR.
LU
N/A
0.015545
N/A
11
KAREN RIPPEY
LU
N/A
0
N/A
12
KINGS RIVER HYDRO CO.
LU
N/A
0.298666667
N/A
13
L.P. REINHARD
LU
N/A
0
N/A
14
LANGERWERF DAIRY
LU
N/A
0.043416667
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.15

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
LASSEN STATION HYDRO
LU
N/A
0.785083333
N/A
2
LOFTON RANCH
LU
N/A
0.085
N/A
3
MADERA CANAL (1174 + 84)
LU
N/A
0.291305
N/A
4
MADERA CANAL (1923)
LU
N/A
0.412743333
N/A
5
MADERA CANAL STATION 1302
LU
N/A
0.14553
N/A
6
MEGA HYDRO #1 (CLOVER CREEK)
LU
N/A
0.69825
N/A
7
MEGA HYDRO (GOOSE VALLEY RANCH)
LU
N/A
0.06825
N/A
8
MEGA RENEWABLES (SILVER SPRINGS)
LU
N/A
0.2485
N/A
9
MICHAEL W. STEPHENS
LU
N/A
0
N/A
10
MILL & SULPHUR CREEK
LU
N/A
0.701666667
N/A
11
NID/SCOTTS FLAT
LU
N/A
0.600416667
N/A
12
ORANGE COVE IRRIGATION DIST.
LU
N/A
0.416916667
N/A
13
PAN PACIFIC (WEBER FLAT)
LU
N/A
0
N/A
14
PLACER COUNTY WATER AGENCY
LU
N/A
0.329959667
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.16

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
REAL GOODS TRADING CORP.
LU
N/A
0
N/A
2
ROBERT AND JOYCE VIEUX
LU
N/A
0
N/A
3
ROBERT W. LEE
LU
N/A
0
N/A
4
ROBIN WILLIAMS SOLAR POWER GEN
LU
N/A
0.000249833
N/A
5
ROCK CREEK WATER DISTRICT
LU
N/A
0.1845
N/A
6
SANTA CLARA VALLEY WATER DIST.
LU
0.8
0.054166667
N/A
7
SCHAADS HYDRO
LU
N/A
0.155916667
N/A
8
SHAMROCK UTILITIES (CEDAR FLAT)
LU
N/A
0.263333333
N/A
9
SHAMROCK UTILITIES (CLOVER LEAF)
LU
N/A
0.131916667
N/A
10
SHEILA ST. GERMAIN
LU
N/A
0
N/A
11
SIERRA ENERGY
LU
N/A
0.077333333
N/A
12
SNOW MOUNTAIN HYDRO LLC (LOST
LU
N/A
0.399128167
N/A
13
SOUTH SUTTER WATER
LU
N/A
0.093166667
N/A
14
STEVE & BONNIE TETRICK
LU
N/A
0.0000075
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.17

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
STEVEN SPELLENBERG HYDRO
LU
N/A
0
N/A
2
SUTTER'S MILL
LU
N/A
0.096448333
N/A
3
SWISS AMERICA
LU
N/A
0.0261555
N/A
4
TOM BENNINGHOVEN
LU
N/A
0.01383525
N/A
5
VECINO VINEYARDS LLC
LU
N/A
0.036416667
N/A
6
WATER WHEEL RANCH
LU
N/A
0.615916667
N/A
7
WENDEL ENERGY OPERATIONS 1,LLC
LU
0.213
0.71575
N/A
8
WRIGHT RANCH HYDROELECTRIC
LU
N/A
0.005282333
N/A
9
YOUTH WITH A MISSION/SPRINGS OF
LU
N/A
0.079666667
N/A
10
YUBA COUNTY WATER AGENCY
0.13
0.135485
N/A
11
SMALL POWER PRODUCERS - THERMAL
12
1080 CHESTNUT CORP. LU
N/A
0.00036325
N/A
13
AIRPORT CLUB
LU
N/A
0
N/A
14
ARDEN WOOD BENEVOLENT ASSOC.
LU
N/A
0.000240917
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.18

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
CITY OF FAIRFIELD
LU
N/A
0.050916667
N/A
2
CITY OF MILPITAS
LU
N/A
0.02207925
N/A
3
GREATER VALLEJO RECREATION
LU
N/A
0.005450417
N/A
4
COUNTY OF SANTA CRUZ ( WATER ST.
LU
N/A
0.005833333
N/A
5
DOLE ENTERPRISES, INC
LU
N/A
0.029831083
N/A
6
HAYWARD AREA REC & PARK DIST.
LU
N/A
0.038901417
N/A
7
NIHONMACHI TERRACE
LU
N/A
0
N/A
8
OCCIDENTAL OF ELK HILLS
LU
N/A
0
N/A
9
ORINDA SENIOR VILLAGE
LU
N/A
0.001901667
N/A
10
RED BLUFF UNION HIGH SCHOOL
LU
N/A
0
N/A
11
SATELLITE SENIOR HOMES
LU
N/A
0.000583333
N/A
12
STANFORD ENERGY GROUP
LU
N/A
0
N/A
13
UCSC PHYSICAL PLANT
LU
N/A
0
N/A
14
YOUNG RADIO INC.
LU
N/A
0
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.19

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
YUBA CITY RACQUET CLUB
LU
N/A
0.010976
N/A
2
BILATERAL CONTRACTS:
3
- RENEWABLE CONTRACTS
4
NEVADA IRRIGATION DISTRICT NORTH OS 6
N/A
N/A
N/A
5
SEMPRA EL DORADO SOLAR IMPORT OS 6
N/A
N/A
N/A
6
NEVADA IRRIGATION DISTRICT SOUTH OS 6
N/A
N/A
N/A
7
ETIWANDA POWER PLANT OS 6
N/A
N/A
N/A
8
WOODLAND BIOMASS OS 6
N/A
N/A
N/A
9
BIG CREEK WATER WORKS, LTD. OS 6
N/A
N/A
N/A
10
BONNEVILLE POWER ADMINSTRATION OS 6
N/A
N/A
N/A
11
NEVADA IRRIGATION DISTRICT SCOTTS OS 6
N/A
N/A
N/A
12
EL DORADO IRRIGATION OS 6
N/A
N/A
N/A
13
SOUTH FEATHER WATER AND POWER OS 6
N/A
N/A
N/A
14
SHELL ENERGY OS 6
N/A
N/A
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.20

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
LOST CREEK OS 6
N/A
N/A
N/A
2
WADHAM ENERGY LTD. PART. OS 6
N/A
N/A
N/A
3
IBERDROLA RENEWABLES (AKA PPM OS 6
N/A
N/A
N/A
4
PACIFICORP OS 6
N/A
N/A
N/A
5
VANTAGE WIND (POWEREX S&F) OS 6
N/A
N/A
N/A
6
COMMUNITY RENEWABLE ENERGY OS 6
N/A
N/A
N/A
7
SIERRA POWER CORPORATION OS 6
N/A
N/A
N/A
8
MADERA RENEWABLE OS 6
N/A
N/A
N/A
9
FPLE DIABLO WINDS OS 6
N/A
N/A
N/A
10
BARCLAYS-NINE CANYON CONFIRM OS 6
N/A
N/A
N/A
11
BIG VALLEY POWER, LLC OS 6
N/A
N/A
N/A
12
CASTELANELLI BROS. BIOGAS OS 6
N/A
N/A
N/A
13
BUENA VISTA ENERGY, LLC OS 6
N/A
N/A
N/A
14
BOTTLE ROCK OS 6
N/A
N/A
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.21

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
CALPINE GEYSERS OS 6
N/A
N/A
N/A
2
GLOBAL AMPERSAND OS 6
N/A
N/A
N/A
3
IBERDROLA KLONDIKE (AKA PPM OS 6
N/A
N/A
N/A
4
SHILOH I WIND PROJECT LLC OS 6
N/A
N/A
N/A
5
TUNNEL HILL HYDROELECTRIC PROJECT OS 6
N/A
N/A
N/A
6
SHILOH II WIND (AKA ENXCO) OS 6
N/A
N/A
N/A
7
ARLINGTON WIND POWER PROJECT OS 6
N/A
N/A
N/A
8
SEMPRA COPPER MOUNTAIN SOLAR OS 6
N/A
N/A
N/A
9
IBERDROLA RENEWABLES (AKA PPM OS 6
N/A
N/A
N/A
10
VANTAGE WIND ENERGY LLC OS 6
N/A
N/A
N/A
11
SIERRA GREEN ENERGY LLC OS 6
N/A
N/A
N/A
12
CAL RENEW (AKA CLEAN TECH) - COD: OS 6
N/A
N/A
N/A
13
HATCHET RIDGE WIND LLC OS 6
N/A
N/A
N/A
14
SANTA MARIA II LFG POWER PLANT OS 6
N/A
N/A
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.22

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
NEXTERA MONTEZUMA WIND OS 6
N/A
N/A
N/A
2
BLAKE'S LANDING FARMS, INC OS 6
N/A
N/A
N/A
3
BILATERAL CONTRACTS: OS 6
N/A
N/A
N/A
4
-WSPP/EEI OS 6
N/A
N/A
N/A
5
SEMPRA ENERGY TRADING CORP. OS 6
N/A
N/A
N/A
6
BP ENERGY COMPANY OS 6
N/A
N/A
N/A
7
BONNEVILLE POWER ADMINISTRATION OS 6
N/A
N/A
N/A
8
PORTLAND GENERAL OS 6
N/A
N/A
N/A
9
CITY OF SANTA CLARA (SVP MUNI) OS 6
N/A
N/A
N/A
10
SEATTLE CITY LIGHT OS 6
N/A
N/A
N/A
11
CORAL POWER LLC (SHELL ENERGY LLC) OS 6
N/A
N/A
N/A
12
SOUTHERN CALIFORNIA EDISON OS 6
N/A
N/A
N/A
13
DYNEGY, INC. OS 6
N/A
N/A
N/A
14
CALPINE ENERGY SERVICES L.P. OS 6
N/A
N/A
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.23

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
IBERDROLA RENEWABLES (PPM OS 6
N/A
N/A
N/A
2
PACIFICORP OS 6
N/A
N/A
N/A
3
POWEREX CORP OS 6
N/A
N/A
N/A
4
CONSTELLATION ENERGY OS 6
N/A
N/A
N/A
5
PACIFIC SUMMIT ENERGY LLC OS 6
N/A
N/A
N/A
6
BARCLAYS BANK PLC OS 6
N/A
N/A
N/A
7
MORGAN STANLEY CAPITAL GROUP OS 6
N/A
N/A
N/A
8
JP MORGAN VENTURES ENERGY CORP OS 6
N/A
N/A
N/A
9
SACRAMENTO MUNICIPAL UTILITY OS 6
N/A
N/A
N/A
10
CITIGROUP ENERGY INC OS 6
N/A
N/A
N/A
11
IBERDROLA RENEWABLES (PPM OS 6
N/A
N/A
N/A
12
TRANSALTA ENERGY MARKETING US OS 6
N/A
N/A
N/A
13
BILATERAL CONTRACTS:
14
- SUPPLEMENTAL ENERGY:
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.24

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
POTRERO 3 - RMR MIRANT OS 6
N/A
N/A
N/A
2
CALPINE PEAKERS OS 6
N/A
N/A
N/A
3
BILATERAL CONTRACTS:
4
- RESOURCE ADEQUACY:
5
RRI ENERGY SERVICES JUL-SEP 2010 RA OS 6
N/A
N/A
N/A
6
SOUTH FEATHER WATER AND POWER OS 6
N/A
N/A
N/A
7
LA PALOMA GENERATING COMPANY OS 6
N/A
N/A
N/A
8
MIRANT DELTA TOLLING 2008 - 2012 OS 6
N/A
N/A
N/A
9
CALPINE LOS MEDANOS RA 2008-2012 OS 6
N/A
N/A
N/A
10
LA PALOMA GENERATING COMPANY OS 6
N/A
N/A
N/A
11
ELK HILLS POWER LLC JUL-SEP 2010 RA OS 6
N/A
N/A
N/A
12
MORGAN STANLEY CAPITAL GROUP OS 6
N/A
N/A
N/A
13
DYNEGY POWER MARKETING JUL-AUG OS 6
N/A
N/A
N/A
14
CALPINE GEYSERS (200/425 MW) OS 6
N/A
N/A
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.25

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
CALPINE LOS MEDANOS RA 2008-2012 OS 6
N/A
N/A
N/A
2
CALPINE METCALF RA 2008-2012 OS 6
N/A
N/A
N/A
3
BILATERAL CONTRACTS:
4
- LONG-TERM WHOLESALE
5
MIDWAY SUNSET PPA OS 6
N/A
N/A
N/A
6
MIRANT DELTA TOLLING 2008 - 2012 OS 6
N/A
N/A
N/A
7
CALPINE PEAKERS OS 6
N/A
N/A
N/A
8
GWF OS 6
N/A
N/A
N/A
9
DYNEGY MOSS LANDING UNITS 6&8 OS 6
N/A
N/A
N/A
10
JR SIMPLOT OS 6
N/A
N/A
N/A
11
EIF PANOCHE OS 6
N/A
N/A
N/A
12
STARWOOD POWER MIDWAY, LLC OS 6
N/A
N/A
N/A
13
SOUTH FEATHER WATER AND POWER OS 6
N/A
N/A
N/A
14
BILATERAL CONTRACTS:
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.26

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
- DEMAND RESPONSE AGREEMENTS:
2
C Powered OS 6
N/A
N/A
N/A
3
Alternative Energy Resources OS 6
N/A
N/A
N/A
4
Energy Connect OS 6
N/A
N/A
N/A
5
EnerNoc OS 6
N/A
N/A
N/A
6
Energy Curtailment OS 6
N/A
N/A
N/A
7
BILATERAL CONTRACTS:
8
- OTHERS:
9
Hedging Activity OS 6
N/A
N/A
N/A
10
Non-UEG Costs OS 6
N/A
N/A
N/A
11
Non-CTC Costs OS 6
N/A
N/A
N/A
12
Interstate gas pipeline charges OS 6
N/A
N/A
N/A
13
Broker/Management and Other OS 6
N/A
N/A
N/A
14
UFE OS 6
N/A
N/A
N/A
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.27

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER (Account 555)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Average
Monthly NCP Demand Monthly CP Demand
(e)
(f)
1
California Independent System Operator OS 6
N/A
N/A
N/A
2
Day Ahead Market Purchases OS 6
N/A
N/A
N/A
3
Miscellaneous Items
4
5
6
7
8
9
10
11
12
13
14
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.28

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
220,843
42,384
174,485
92,684
161,936
63,203
61,648
68,881
113,169
180,705
173,845
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
1
2
3
5,753,537 14,536,038 20,289,575 4
839,605 2,829,706 3,669,311 5
4,895,130 11,797,324 16,692,454 6
2,402,052 5,304,859 7,706,911 7
3,619,498 7,387,632 11,007,130 8
-98,045 7,525,150 7,427,105 9
-103,810 7,345,860 7,242,050 10
1,783,960 4,375,367 6,159,327 11
2,779,794 7,357,364 10,137,158 12
4,824,994 12,150,581 16,975,575 13
4,858,435 11,689,014 16,547,449 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
93,963
78,669
106,533
146,162
93,321
397,686
30,103
17,955
9,692
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
1,932,525 6,214,533 8,147,058 1
1,571,410 5,169,859 6,741,269 2
2,450,804 6,805,275 9,256,079 3
4
9 9 5
3,077,016 9,730,763 12,807,779 6
8,624,043 8,624,043 7
8,996,049 26,440,623 35,436,672 8
324,492 1,766,149 2,090,641 9
10
73,759 819,251 893,010 11
12
13
40,815 425,692 466,507 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
370,709
391,204
87,463
348,196
70,568
31,802
58,986
25,246
24,314
11,205
119,696
30,773
333,424
230,679
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
9,733,184 16,822,779 26,555,963 1
10,123,088 17,795,750 -87,416 27,831,422 2
398,043 3,932,412 4,330,455 3
5,238,368 15,870,940 21,109,308 4
295,721 3,256,776 3,552,497 5
160,980 1,434,434 1,595,414 6
204,718 2,591,201 2,795,919 7
133,189 1,073,666 1,206,855 8
84,526 1,218,225 1,302,751 9
39,864 551,804 591,668 10
577,635 5,395,760 5,973,395 11
133,248 1,473,587 1,606,835 12
1,444,129 15,123,628 16,567,757 13
2,857,796 10,461,823 13,319,619 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
181,856
139,241
43,392
48,952
379,669
362,510
289,387
38,586
5,717
5,275
285,781
271,494
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
4,275,042 8,670,776 12,945,818 1
573,887 6,253,690 6,827,577 2
4,275,042 2,026,275 6,301,317 3
4
4,275,042 2,242,080 6,517,122 5
9,842,263 17,257,009 27,099,272 6
9,814,294 16,559,037 26,373,331 7
1,339,760 13,110,583 14,450,343 8
375,045 1,981,097 2,356,142 9
33,395 250,514 283,909 10
18,751 242,813 261,564 11
1,275,860 12,989,989 14,265,849 12
1,231,002 12,345,548 13,576,550 13
14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
32,580
552,540
67,421
18,054
170,763
2,228
10,167
214,147
1,449,711
246,956
261,927
192,928
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
1
56,287 1,210,681 1,266,968 2
20,700,000 -570,561 20,129,439 3
24,244,868 26,427,035 50,671,903 4
1,484,238 3,478,827 4,963,065 5
97,429 925,352 1,022,781 6
866,617 7,667,248 8,533,865 7
5,562 108,768 114,330 8
7,308,797 335,723 7,644,520 9
5,787,598 9,688,654 15,476,252 10
52,979,480 66,150,759 119,130,239 11
9,807,406 11,470,145 21,277,551 12
10,109,554 11,914,056 22,023,610 13
4,970,606 8,583,814 13,554,420 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
10,911
107,589
96
8,466
189,286
16,241
132,636
1,190
309,754
198,975
150
139,059
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
1,355,199 526,079 1,881,278 1
8,422,546 5,232,132 13,654,678 2
3
68 4,440 4,508 4
41,745 385,950 427,695 5
4,768,210 8,206,056 12,974,266 6
4,955,500 655,635 5,611,135 7
10,629,862 6,887,638 17,517,500 8
625 54,161 54,786 9
10
6,348,369 14,105,126 20,453,495 11
4,689,994 9,036,514 13,726,508 12
600 7,671 8,271 13
7,949,734 6,596,172 14,545,906 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.5

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
116
12,683
130,629
863
39,651
2,374
6,149
18,349
8,184
23,195
143,975
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
434 5,354 5,788 1
39,995 532,275 572,270 2
8,356,525 6,861,055 15,217,580 3
4
3,500 39,799 43,299 5
6
201,507 2,652,408 2,853,915 7
8,427 112,911 121,338 8
96,993 409,819 506,812 9
300,712 1,227,488 1,528,200 10
63,436 545,115 608,551 11
12
370,882 1,572,614 1,943,496 13
3,801,482 9,674,806 13,476,288 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.6

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
156,905
143,749
150,767
156,655
165,707
37,474
380
5,420
131,921
343,742
289,444
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
3,926,834 10,322,250 14,249,084 1
3,799,463 9,668,848 13,468,311 2
3,660,236 9,917,062 13,577,298 3
3,950,017 10,335,924 14,285,941 4
4,439,684 10,986,379 15,426,063 5
152,816 3,289,716 3,442,532 6
1,034 18,215 19,249 7
8
22,973 243,007 265,980 9
10
556,166 6,034,591 6,590,757 11
12
3,168,897 25,358,932 28,527,829 13
27,276,984 27,276,984 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.7

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
-37,439
274,234
1,038
4,831
612
11,948
78,111
8,525
8,689
6,970
62,855
2,503
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
-91,770 -2,796,136 -2,887,906 1
7,663,505 18,464,267 26,127,772 2
3
1,711 44,453 46,164 4
5
61,558 233,593 295,151 6
3,778 27,761 31,539 7
168,379 840,145 1,008,524 8
1,932,941 4,803,132 6,736,073 9
230,702 513,255 743,957 10
217,318 534,769 752,087 11
33,314 457,218 490,532 12
710,441 2,712,271 3,422,712 13
20,458 146,632 167,090 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.8

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
34,112
6,488
30,134
10,178
25,474
8,367
5,444
11,761
4,024
15,639
2,547
1,325
8,491
9,012
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
284,042 2,060,663 2,344,705 1
167,678 393,049 560,727 2
1,251,392 2,214,911 3,466,303 3
188,778 463,482 652,260 4
386,416 1,216,711 1,603,127 5
114,510 406,175 520,685 6
36,271 225,630 261,901 7
80,781 502,470 583,251 8
59,576 279,971 339,547 9
327,190 988,861 1,316,051 10
5,613 190,158 195,771 11
6,678 89,191 95,869 12
45,770 404,888 450,658 13
161,476 412,772 574,248 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.9

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
3,382
3,917
1,986
19,361
4,665
13,902
5,245
1,606
14,282
1,695
76,566
3,202
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
69,343 226,471 295,814 1
47,887 281,673 329,560 2
3
48,436 116,652 165,088 4
274,845 1,327,631 1,602,476 5
92,881 303,686 396,567 6
80,877 606,290 687,167 7
32,670 227,228 259,898 8
17,790 116,507 134,297 9
37,023 692,608 729,631 10
18,108 121,827 139,935 11
2,594,008 3,341,958 5,935,966 12
13
42,537 227,299 269,836 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.10

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
9,915
6,132
30,014
24,684
21,293
72,853
9,177
15,823
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
1
2
3
4
214,198 424,361 638,559 5
109,293 366,300 475,593 6
534,204 1,799,413 2,333,617 7
467,559 1,484,155 1,951,714 8
9
10
378,487 1,313,421 1,691,908 11
1,590,651 4,393,965 5,984,616 12
212,202 551,549 763,751 13
333,629 962,125 1,295,754 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.11

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
251,182
15,895
10,291
23,872
38,471
1,937
71,091
23,068
13,272
31,497
10,149
177
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
5,015,507 14,379,099 19,394,606 1
279,712 931,280 1,210,992 2
229,581 619,233 848,814 3
557,870 1,448,967 2,006,837 4
913,530 2,332,043 3,245,573 5
45,243 117,587 162,830 6
1,670,578 4,287,213 5,957,791 7
592,592 1,436,269 2,028,861 8
9
288,460 802,758 1,091,218 10
635,331 1,910,479 2,545,810 11
189,249 435,324 624,573 12
11,887 11,887 13
14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.12

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
5,862
295,923
1
29,265
5,611
951
704
1,444
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
1
22,211 308,673 330,884 2
3
4
1,323,158 13,457,687 14,780,845 5
38 38 6
7
1,219,976 1,219,976 8
6,879 248,342 255,221 9
10
11
6,826 41,655 48,481 12
7,628 35,324 42,952 13
7,620 64,340 71,960 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.13

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
2,540
352
330
168
1,681
35
114
10
3,165
457
2,659
164
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
15,586 109,126 124,712 1
2,086 15,620 17,706 2
1,944 14,646 16,590 3
855 7,396 8,251 4
11,837 72,450 84,287 5
103 1,514 1,617 6
107 5,612 5,719 7
8
24 465 489 9
18,413 208,364 226,777 10
20 20 11
1,827 31,866 33,693 12
12,296 183,606 195,902 13
1,032 10,534 11,566 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.14

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
2,680
254
156
272
2,372
448
118
7
108
1,089
170
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
18,955 114,304 133,259 1
3,523 12,868 16,391 2
1,989 11,133 13,122 3
4
577 12,668 13,245 5
37,750 160,177 197,927 6
2,291 19,225 21,516 7
166 5,127 5,293 8
16 602 618 9
245 7,429 7,674 10
11
23,161 72,057 95,218 12
13
1,109 10,715 11,824 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.15

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
3,009
584
1,848
2,849
895
4,404
328
2,010
2,805
1,911
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
58,695 139,844 198,539 1
2,308 25,176 27,484 2
49,160 112,900 162,060 3
78,406 172,915 251,321 4
27,164 53,118 80,282 5
72,144 207,905 280,049 6
2,001 14,602 16,603 7
43,245 91,320 134,565 8
9
33,752 137,931 171,683 10
11
12
13
6,728 90,820 97,548 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.16

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
1
636
271
898
1,603
855
184
509
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
1
2
3
2 57 59 4
4,096 27,529 31,625 5
11,154 11,154 6
3,269 41,625 44,894 7
22,822 110,809 133,631 8
13,721 57,977 71,698 9
10
506 9,290 9,796 11
12
3,570 22,012 25,582 13
1 1 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.17

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
725
246
91
241
3,611
3,920
31
453
1,109
1
2
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
1
4,089 48,363 52,452 2
1,312 10,531 11,843 3
525 4,438 4,963 4
1,147 10,060 11,207 5
63,000 168,389 231,389 6
64,714 263,907 328,621 7
66 1,453 1,519 8
1,087 23,206 24,293 9
19,267 73,697 92,964 10
11
3 50 53 12
13
5 82 87 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.18

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
123
171
42
6
239
316
12
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
545 5,552 6,097 1
312 8,120 8,432 2
75 2,025 2,100 3
2 226 228 4
564 11,216 11,780 5
697 15,164 15,861 6
7
8
22 589 611 9
10
3 3 11
12
13
14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.19

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
88
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
171 3,948 4,119 1
2
3
207,191 207,191 4
167,217 167,217 5
378,659 378,659 6
1,463,527 1,463,527 7
15,248,417 15,248,417 8
216,327 216,327 9
516,173 516,173 10
287,683 287,683 11
3,906,080 3,906,080 12
320,835 1,868,860 2,189,695 13
76,148,850 76,148,850 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.20

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt Hours
Received
(h)
Delivered
(i)
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
694,329 694,329 1
14,886,584 14,886,584 2
416,727 416,727 3
54,459,475 54,459,475 4
1,540,498 1,540,498 5
1,668,910 3,666,937 5,335,847 6
1,024,784 2,079,785 3,104,569 7
2,211,140 5,699,916 7,911,056 8
2,686,460 2,686,460 9
9,201,355 9,201,355 10
280,783 280,783 11
131,279 131,279 12
4,997,835 4,997,835 13
6,206,824 6,206,824 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.21

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt Hours
Received
(h)
Delivered
(i)
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
239,573,078 239,573,078 1
2,080,852 2,080,852 2
28,838,202 28,838,202 3
11,335,637 11,335,637 4
361,539 361,539 5
37,162,298 37,162,298 6
20,793,318 20,793,318 7
8,335,312 8,335,312 8
4,704,024 4,704,024 9
4,305,490 4,305,490 10
4,759 4,759 11
57,725 57,725 12
2,931,387 2,931,387 13
71,319 71,319 14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.22

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt Hours
Received
(h)
Delivered
(i)
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
107,521 107,521 1
1,952 1,952 2
16,973,414 16,973,414 5
10,458,777 10,458,777 6
161,969 161,969 7
158,004 158,004 8
-6,000 -6,000 9
45,194 45,194 10
6,229,424 6,229,424 11
196,250 196,250 12
1,109,200 1,109,200 13
155,501 155,501 14
3
4
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.23

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt Hours
Received
(h)
Delivered
(i)
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
5,354,997 5,354,997 1
74,499 74,499 2
7,994,011 7,994,011 3
599,174 599,174 4
47,484,385 47,484,385 5
52,011,965 52,011,965 7
-8,197 -8,197 8
27,600 27,600 9
20,925,770 20,925,770 10
2,427,736 2,427,736 11
-10,900 -10,900 12
6
13
14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.24

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt Hours
Received
(h)
Delivered
(i)
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
13,594,889 461,197 14,056,086 1
-1,344,627 -1,344,627 2
3,787,379 3,787,379 5
1,450,000 1,450,000 6
409,966 409,966 7
34,740,800 34,740,800 8
1,657,600 1,657,600 9
95,550 95,550 10
760,000 760,000 11
138,999 138,999 12
359,750 359,750 13
15,308,940 15,308,940 14
3
4
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.25

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt Hours
Received
(h)
Delivered
(i)
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
19,062,400 19,062,400 1
21,941,000 21,941,000 2
2,778,300 7,367,452 10,145,752 5
56,027,529 -4,870,374 51,157,155 6
25,399,654 986,812 26,386,466 7
13,126,030 -149,738 12,976,292 8
83,379,721 3,185,114 86,564,835 9
71,782 71,782 10
51,672,158 1,893,844 53,566,002 11
13,002,816 349,442 13,352,258 12
290,000 7,465,219 7,755,219 13
3
4
14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.26

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours
MegaWatt Hours MegaWatt Hours
Purchased
Received
Delivered
(g)
(h)
(i)
24,945,160
4,410,945
932,409
-80,053
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
1
97,310 10,299 107,609 2
4,304,869 54,895 4,359,764 3
1,668,493 16,438 1,684,931 4
3,577,902 49,664 3,627,566 5
2,895,200 21,810 2,917,010 6
469,309,542 469,309,542 9
39,740,350 39,740,350 10
69,503,871 69,503,871 11
2,015,239 2,015,239 12
1,304,413 1,304,413 13
7
8
14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.27

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASED POWER(Account 555) (Continued)
(Including power exchanges)
Year/Period of Report
End of 2010/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt Hours
Received
(h)
Delivered
(i)
COST/SETTLEMENT OF POWER
Line
Demand Charges Energy Charges Other Charges Total (j+k+l) No.
($) ($) ($)
of Settlement ($)
(j)
(k)
(l)
(m)
741,949,363 741,949,363 1
13,378,758 13,378,758 3
2
4
5
6
7
8
9
10
11
12
13
14
44,837,023 754,305,279 2,879,319,814 -87,416 3,633,537,677
FERC FORM NO. 1 (ED. 12-90) Page 327.28

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 326 Line No.: 1 Column: c
No FERC rate schedules are provided in column (c) for QF's and Independent Power Producers
because these companies are non-FERC jurisdictional sellers.
Schedule Page: 326.13 Line No.: 1 Column: a
The following is a list of QF's under 1 MW:
AMERICAN ENERGY, INC. (SAN LUIS
BYPASS)
AMERICAN ENERGY, INC. ( WOLFSEN
BYPASS )
ARBUCKLE MOUNTAIN HYDRO
BAILEY CREEK RANCH
BROWNS VALLEY IRRIGATION DISTRICT
CALAVERAS YUBA HYDRO #1
CALAVERAS YUBA HYDRO #2
CALAVERAS YUBA HYDRO #3
CANAL CREEK POWER PLANT (RETA)
CHARCOAL RAVINE
CITY OF WATSONVILLE
COVANTA POWER PACIFIC, STOCKTON
DAVID O. HARDE
DIGGER CREEK RANCH
DONALD R. CHENOWETH
E J M MCFADDEN
EAGLE HYDRO
ERIC AND DEBBIE WATTENBURG
FAIRFIELD POWER PLANT (PAPAZIAN)
FAR WEST POWER CORPORATION
FIVE BEARS HYDROELECTRIC
GAS RECOVERY SYSTEMS, INC [SANTA
CRUZ]
HAT CREEK HEREFORD RANCH
HENWOOD ASSOCIATES
JACKSON VALLEY IRRIGATION DIST
JAMES B. PETER
JAMES CRANE HYDRO
JOHN NEERHOUT JR.
KAREN RIPPEY
KINGS RIVER HYDRO CO.
L.P. REINHARD
LANGERWERF DAIRY
LASSEN STATION HYDRO
LOFTON RANCH
MADERA CANAL (1174 + 84)
MADERA CANAL (1923)
MADERA CANAL STATION 1302
MEGA HYDRO #1 (CLOVER CREEK)
MEGA HYDRO (GOOSE VALLEY RANCH)
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
MEGA RENEWABLES (SILVER SPRINGS)
MICHAEL W. STEPHENS
MILL & SULPHUR CREEK
NID/SCOTTS FLAT
ORANGE COVE IRRIGATION DIST.
PAN PACIFIC (WEBER FLAT)
PLACER COUNTY WATER AGENCY
REAL GOODS TRADING CORP.
ROBERT AND JOYCE VIEUX
ROBERT W. LEE
ROBIN WILLIAMS SOLAR POWER GEN
ROCK CREEK WATER DISTRICT
SANTA CLARA VALLEY WATER DIST.
SCHAADS HYDRO
SHAMROCK UTILITIES (CEDAR FLAT)
SHAMROCK UTILITIES (CLOVER LEAF)
SHEILA ST. GERMAIN
SIERRA ENERGY
SNOW MOUNTAIN HYDRO LLC (LOST
CREEK 2)
SOUTH SUTTER WATER
STEVE & BONNIE TETRICK
STEVEN SPELLENBERG HYDRO
SUTTER'S MILL
SWISS AMERICA
TOM BENNINGHOVEN
VECINO VINEYARDS LLC
WATER WHEEL RANCH
WENDEL ENERGY OPERATIONS 1,LLC
WRIGHT RANCH HYDROELECTRIC
YOUTH WITH A MISSION/SPRINGS OF
LIVING WATERS
YUBA COUNTY WATER AGENCY
1080 CHESTNUT CORP.
AIRPORT CLUB
ARDEN WOOD BENEVOLENT ASSOC.
CITY OF FAIRFIELD
CITY OF MILPITAS
GREATER VALLEJO RECREATION
DISTRICT
COUNTY OF SANTA CRUZ ( WATER ST.
JAIL)
DOLE ENTERPRISES, INC
HAYWARD AREA REC & PARK DIST.
NIHONMACHI TERRACE
OCCIDENTAL OF ELK HILLS
ORINDA SENIOR VILLAGE
RED BLUFF UNION HIGH SCHOOL
FERC FORM NO. 1 (ED. 12-87) Page 450.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
SATELLITE SENIOR HOMES
STANFORD ENERGY GROUP
UCSC PHYSICAL PLANT
YOUNG RADIO INC.
YUBA CITY RACQUET CLUB
Schedule Page: 326.27 Line No.: 10 Column: a
The Non-UEG fuel costs is gas purchased for the bilateral contracts (tolling agreements)
with LSP Morro Bay, LSP Moss Landing, and Mirant Pittsburg and Contra Costa.
Schedule Page: 326.28 Line No.: 3 Column: a
These expenses consist of Transmission Service Costs related to power losses, PX Admin
Fees, Circuit Leases, Other Consulting Services (Independent Evaluator costs), and
miscellaneous expenses.
FERC FORM NO. 1 (ED. 12-87) Page 450.3

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
(Including transactions referred to as 'wheeling')
Year/Period of Report
End of 2010/Q4
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
Payment By
(Company of Public Authority)
Energy Received From
(Company of Public Authority)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(Footnote Affiliation)
(Footnote Affiliation)
(a)
(b)
(c)
WESTERN AREA POWER
ADMINISTRATION (WAPA)
CONTRACT 2207A WAPA Various LFP
WHOLESALE DISTRIBUTION TARIFF,
SERVICE AGREEMENT NO. 17 WAPA Various LFP
CITY & COUNTY OF SAN
FRANCISCO (CCSF)
TRANSMISSION CCSF CCSF LFP
INTERRUPTIBLE TRANSMISSION Various CCSF NF
CALIFORNIA DEPARTMENT OF WATER
RESOURCES (DWR)
HIGH VOLTAGE
LOW VOLTAGE
TO WAMP DWR Various LFP
WAPA DWR Various LFP
TO/FROM N/W DWR Various LFP
TO LMUD DWR LMUD LFP
TO MID DWR MID LFP
TO NCPA DWR NCPA LFP
TO CCSF DWR CCSF LFP
TO TID DWR TID LFP
TO ETAWANDA DWR ETAWANDA LFP
TO SVP DWR SVP LFP
SF BAY AREA RAPID TRANSIT (BART) NCPA/WAPA SF BART LFP
TRANSMISSION AGENCY OF
NORTHERN CALIFORNIA (TANC) Various Various LFP
Statistical
Classification
(d)
TOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
(Including transactions reffered to as 'wheeling')
Year/Period of Report
End of 2010/Q4
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt
Point of Delivery
Billing
TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other
Demand
MegaWatt Hours MegaWatt Hours No.
Tariff Number Designation)
Designation)
(MW)
Received
Delivered
(e)
(f)
(g)
(h)
(i)
(j)
1
2
3
227 Various
Various 41 136,465 130,716 4
5
SA17 Various
Various 6
7
8
9
114 Newark
Various 175 905,746 888,980 10
114 Newark
Various 11
12
13
14
1,300 578,483 562,453 15
53,747 52,257 16
77 Various
Various 17
77 Various
Various 18
77 Various
Malin 19
77 Various
Various 20
77 Various
Tracy 21
77 Various
Various 22
77 Various
Various 23
77 Various
Tracy 24
77 Various
Various 25
77 Various
Various 26
27
SA 30 COTP Terminus/-
Various 62 358,086 348,163 28
Tracy Substation 29
30
143 Midway
Various 233 409,341 401,512 31
32
33
34
1,811 2,441,868 2,384,081
FERC FORM NO. 1 (ED. 12-90) Page 329

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
(Including transactions reffered to as 'wheeling')
Year/Period of Report
End of 2010/Q4
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges
($)
(Other Charges)
($)
Total Revenues ($)
(k+l+m)
Line
No.
(l)
(m)
(n)
1
2
3
61,900 43,569 19,986
125,455 4
5
6
7
8
9
4,668,670 172,141
4,840,811 10
11
12
13
14
2,169,929 186,768
2,356,697 15
202,758 202,758 16
17
18
19
20
21
22
23
24
25
26
27
2,869,271 -4,893 2,864,378 28
29
30
1,477,564 -11,641
1,465,923 31
32
33
34
2,931,171 8,562,490
362,361
11,856,022
FERC FORM NO. 1 (ED. 12-90) Page 330

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 328 Line No.: 1 Column: a
Company or Public Authority
Termination
Date
WESTERN AREA POWER ADMINISTRATION
CONTRACT 2207A 03/31/2016
CITY & COUNTY OF SAN FRANCISCO
TRANSMISSION 07/01/2015
INTERRUPTIBLE TRANSMISSION 07/01/2015
CALIFORNIA DEPARTMENT OF WATER RESOURCES
TO WAMP 12/31/2014
WAPA 12/31/2014
TO/FROM N/W 12/31/2014
TO LMUD 12/31/2014
TO MID 12/31/2014
TO NCPA 12/31/2014
TO CCSF 12/31/2014
TO TID 12/31/2014
TO ETAWANDA 12/31/2014
TO SVP 12/31/2014
SF BAY AREA RAPID TRANSIT 10/01/2016
TRANSMISSION AGENCY OF NORTHERN CALIFORNIA *
*(This contract is effective until a successor transmission
service agreement is executed by the Utility and TANC.)
Schedule Page: 328 Line No.: 4 Column: m
Other charges ($11,986) represent booking estimate adjustments. Other Charges also include
$8,000 in revenue erroneously booked to the WAPA account. This amount should have been
excluded as it goes through the Transmission Revenue Balancing Account not this account.
Schedule Page: 328 Line No.: 10 Column: m
Other Charges represent booking estimate adjustments. In September 2003 the Utility
changed billing methodology using energy as billing determinants rather than contract
demand. The change was pursuant to the TO6 Settlement Agreement under FERC Docket No.
ER03-666-000.
Schedule Page: 328 Line No.: 10 Column: n
Revenue data represent transmission only.
Schedule Page: 328 Line No.: 13 Column: a
The DWR acts as its own Scheduling Coordinator and, as such, is charged losses by the
California Independent System Operator ("CAISO"). The Utility does not have access to DWR
loss data under the CAISO. The losses shown here are estimates based on the Utility's
system average losses of 2.85%.
Further, the DWR acting as its own Scheduling Coordinator is not obligated to provide the
Utility with individual schedules. Without these schedules, the Utility cannot determine
the revenue or energy attributable to each delivery point.
Schedule Page: 328 Line No.: 15 Column: m
Other Charges represent booking estimate adjustments. In September 2003 the Utility
changed billing methodology using energy as billing determinants rather than contract
demand. The change was pursuant to the TO6 Settlement Agreement under FERC Docket No.
ER03-666-000.
Schedule Page: 328 Line No.: 28 Column: e
Transmission is provided under the Open Access Tariff, Docket No. OA96-28-000 (FERC
Electric Tariff Original Volume No. 3). Service Agreement (SA) No. 30, Docket
ER97-4393-000.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 328 Line No.: 28 Column: h
BART's Network Transmission demand is an average of twelve monthly demands.
Schedule Page: 328 Line No.: 28 Column: m
Other charges represent booking estimate adjustments.
Schedule Page: 328 Line No.: 30 Column: a
Transmission is provided under the Midway Transmission Service.
Recorded here are the Midway Transmission Service data for TANC members which include
Modesto Irrigation District, Sacramento Municipal Utility District, City of Redding, and
the Turlock Irrigation District.
Schedule Page: 328 Line No.: 31 Column: m
Other Charges represent booking estimate adjustments. In September 2003 the Utility
changed billing methodology using energy as billing determinants rather than contract
demand. The change was pursuant to the TO6 Settlement Agreement under FERC Docket No.
ER03-666-000.
FERC FORM NO. 1 (ED. 12-87) Page 450.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling")
Year/Period of Report
End of 2010/Q4
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Name of Company or Public
Authority (Footnote Affiliations)
(a)
California - Oregon
Transmission Project
Pacificorp
Sacramento Municipal
Utility District
Western Area Power
Administration
California-Oregon
Intertie
Other
Statistical
Classification
(b)
TRANSFER OF ENERGY
Magawatthours
hours
Magawatt-
Received Delivered
(c)
(d)
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Demand Energy
Other Total Cost of
Charges Charges Charges
($)
($)
($)
Transmission
($)
(e)
(f)
(g)
(h)
OS 223,601
223,601
OS 20,000,000
372,135
20,372,135
OS 100,992
100,992
OS 1,222
192,000
193,222
OS 680,417
680,417
OS 2,045
2,045
TOTAL
20,102,214 1,470,198 21,572,412
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 332 Line No.: 2 Column: g
Represents operation and maintenance costs.
Schedule Page: 332 Line No.: 3 Column: e
Represents payments for lease of transmission capacity.
Schedule Page: 332 Line No.: 3 Column: g
Represents operation and maintenance costs.
Schedule Page: 332 Line No.: 5 Column: e
Represents payments for lease of transmission capacity.
Schedule Page: 332 Line No.: 7 Column: e
Represents payments for lease of transmission capacity.
Schedule Page: 332 Line No.: 7 Column: g
Represents operation and maintenance costs.
Schedule Page: 332 Line No.: 9 Column: g
Represents payments for administrative costs for scheduling services provided by the
California Independent System Operator.
Schedule Page: 332 Line No.: 10 Column: g
Represents other administrative costs
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
X
End of 2010/Q4
(2) A Resubmission
04/08/2011
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line Description Amount
No.
(a)
(b)
1 Industry Association Dues
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities
5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000
6
7 Bank Service Fees
3,089,316
8 Intervenor Compensation
1,648,797
9 MCI-PG&E Exchange Rights
864,577
10 Consulting Services, Outside Attorney Fees, and Cs
279,056
11 Write off from miscellaneous reconciliations
113,756
12 Intercompany Billings Timing Difference
86,013
13 Clearing Account Adjustments
-1,266,320
14 Cash bonus from procurement card usage
-89,675
15 Cost adjustments
-85,649
16 Miscellaneous cash receipt (recovery of unclaimed)
-10,503
17 Restituition Cash Receipts from Employees
-6,825
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
5,649
46 TOTAL
4,628,192
FERC FORM NO. 1 (ED. 12-94) Page 335

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Line
Depreciation Expense for Asset Limited Term Amortization of
Functional Classification
Expense Retirement Costs Electric Plant Other Electric
No.
(Account 403) (Account 403.1) (Account 404) Plant (Acc 405)
(a)
(b)
(c)
(d)
(e)
1 Intangible Plant
4,186,300
2 Steam Production Plant
-17,140,033 7,952,886
3 Nuclear Production Plant
58,804,251 38,730,540
4 Hydraulic Production Plant-Conventional
40,772,871 13,229,406
5 Hydraulic Production Plant-Pumped Storage
1,395,497 7,789,695
6 Other Production Plant
8,315,682 2,549,350
7 Transmission Plant
156,059,818
8 Distribution Plant
640,614,067
9 Regional Transmission and Market Operation
10 General Plant
5,230,670
11 Common Plant-Electric
109,080,147 60,626,565
12 TOTAL
1,003,132,970 64,812,865 70,251,877
Total
(f)
4,186,300
-9,187,147
97,534,791
54,002,277
9,185,192
10,865,032
156,059,818
640,614,067
5,230,670
169,706,712
1,138,197,712
B. Basis for Amortization Charges
FERC FORM NO. 1 (REV. 12-03) Page 336

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Year/Period of Report
End of 2010/Q4
C. Factors Used in Estimating Depreciation Charges
Line
Depreciable
Estimated Net Applied
Mortality
Average
No. Account No.
Plant Base Avg. Service Salvage Depr. rates
Curve
Remaining
(In Thousands)
Life
(Percent) (Percent)
Type
Life
(a) (b)
(c)
(d) (e)
(f)
(g)
12
13 Intangible Plant
14 302 105,037
3.97 16.70
15 303 9,655
10.00 13.13
16 SUBTOTAL 114,692
17 Steam Prdction -Fossil
18 Steam Production
19 311 11,381
30.00 3.33 R5
29.50
20 312 12,137
30.00 3.33 R5
29.50
21 313 892
30.00 3.33 R5
29.50
22 314 7,123
30.00 3.33 R5
29.50
23 315 2,613
30.00 3.33 R5
29.50
24 316 4,706
30.00 3.33 R5
29.50
25 SUBTOTAL 38,852
26 Hydraulic Production
27 Hydraulic Production
28 331 300,862
-12.00 1.78 19.00
29 332 1,416,934
-12.00 1.78 19.00
30 333 470,459
-12.00 1.78 19.00
31 334 157,156
-12.00 1.78 19.00
32 335 53,904
-12.00 1.78 19.00
33 336 45,775
-12.00 1.78 19.00
34 SUBTOTAL 2,445,090
35
36 Nuclear Production -
37 Diablo Canyon
38 321 973,297
0.67 16.00
39 322 3,096,889
0.67 16.00
40 323 1,123,290
0.67 16.00
41 324 827,796
0.67 16.00
42 325 596,769
0.67 16.00
43 SUBTOTAL 6,618,041
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Year/Period of Report
End of 2010/Q4
C. Factors Used in Estimating Depreciation Charges
Line
Depreciable
Estimated Net Applied
No. Account No.
Plant Base Avg. Service Salvage Depr. rates
(In Thousands)
Life
(Percent) (Percent)
(a) (b)
(c)
(d) (e)
12 Other Production
13 341 266
14 342 19
15.00 R2
15 343 485
15.00 2.77 R2
16 344 7,826
17 345 1,453
18 346 28,529
19 SUBTOTAL 38,578
20
21 Transmission
22 352 200,280
23 353 2,893,773
24 354 464,692
25 355 471,835
26 356 811,707
27 357 310,416
28 358 158,695
29 359 46,661
30 SUBTOTAL 5,358,059
31
32 Transmission -
33 Diablo Canyon
34 352 4,853
2.31
35 353 70,589
2.00
36 SUBTOTAL 75,442
37
38
39
40
41
42
43
44
45
46
47
48
49
50
Mortality
Curve
Type
(f)
Average
Remaining
Life
(g)
25.00 4.63 R2
7.60
25.00 1.89 R2
10.34
15.00 0.24 R2
11.40
19.00 3.58 R2
18.90
60.00 -20.00 2.10 R3
47.52
40.00 -21.00 3.07 S1.5,S0
29.15
69.00 -45.00 1.82 S4,R5
42.56
46.00 -67.00 3.01 R2.5
33.90
54.00 -49.00 2.35 S6,R5
34.49
60.00 1.23 R5
52.77
50.00 1.34 R3
41.14
60.00 1.36 R5
51.80
FERC FORM NO. 1 (REV. 12-03) Page 337.1

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Year/Period of Report
End of 2010/Q4
C. Factors Used in Estimating Depreciation Charges
Line
Depreciable
Estimated Net Applied
Mortality
Average
No. Account No.
Plant Base Avg. Service Salvage Depr. rates
Curve
Remaining
(In Thousands)
Life
(Percent) (Percent)
Type
Life
(a) (b)
(c)
(d) (e)
(f)
(g)
12 Distribution
13 361 199,271
55.00 -20.00 2.31 L5
38.05
14 362 1,906,093
41.00 -15.00 2.88 S1
27.67
15 363 335
10.00
16 364 2,454,182
40.00 -80.00 4.42 R1
25.47
17 365 2,877,248
40.00 -77.00 4.45 R1.5
25.39
18 366 2,126,134
58.00 -20.00 2.21 L3
43.31
19 367 2,978,537
36.00 -30.00 3.50 R4
21.40
20 368 1,738,434
31.00 3.41 R2.5, S1.5
17.97
21 369 2,527,889
48.00 -54.00 3.06 R2.5, R4
30.71
22 370 835,327
30.00 -7.00 3.27 R1.5, S3
19.42
23 371 27,314
40.00 S1
13.70
24 372 895
16.00 83.29 S1
25 373 157,262
24.00 2.00 1.57 R0.5, L2, L0, S3
6.77
26 SUBTOTAL 17,828,921
27
28 General Plant
29 390 7,675
31.00 -5.00 2.74 S2
12.37
30 391 17,167
30.00 20.00 2.67 17.78
31 394 51,362
15.00 10.00 6.00 7.64
32 395 12,457
30.00 3.33 11.17
33 396 328
20.00 10.00 4.50 7.60
34 397 7,051
15.00 -4.00 6.93 7.77
35 398 10,086
15.00 20.00 5.33 4.91
36 SUBTOTAL 106,126
37
38 General Plant -
39 Diablo Canyon
40 389 4
41 391
2.67
42 398
5.33
43 399 468,499
44 SUBTOTAL 468,503
45
46 TOTAL 33,092,304
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 336 Line No.: 12 Column: a
Section C excludes SFAS 143 Asset Retirement Cost depreciation and Utility Retained
Generation plant regulatory asset amortization.
Schedule Page: 336 Line No.: 12 Column: e
Plant depreciation parameters and rates (other than for fossil, hydro, and Diablo Canyon)
are based on mortality characteristics adopted in CPUC Decisions 07-03-044 and 04-12-050.
Depreciation rates for fossil, hydro, and Diablo Canyon are based on the estimated
remaining useful life of the power plants, as required by CPUC Decisions 07-03-044 and
04-12-050.
This column reflects accrual rates based on CPUC jurisdictional Transmisssion Plant and
CPUC authorized depreciation parameters in CPUC Decision 07-03-044 and does not include
any FERC authorized transmission rates.
Schedule Page: 336.2 Line No.: 46 Column: b
Amounts in column (b) were obtained from depreciable and amortizable plant account
balances as of December 31, 2010.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
REGULATORY COMMISSION EXPENSES
Line
Description
Assessed by
Expenses
Total
No. (Furnish name of regulatory commission or body the Regulatory
of
Expense for
docket or case number and a description of the case) Commission Current Year
Utility
(b) + (c)
(a)
(b)
(c)
(d)
1 Annual licensing fee to the U.S. Nuclear Reg 9,649,731 9,649,731
2 Commission (NRC) for Diablo Canyon Nuclear
3 Power Plant (DCPP) in accordance with 10 CFR .
4
5
6
7
8 'Fees for review of Part 50 Application for 3,472,976 3,472,976
9 Reactor License, Inspections and Operator exam
10 from the NRC for DCPP in accordance with
11 10 CFR 170.21.
12
13
14
15 Fees for review of Part 55 Application for 141,838 141,838
16 Reactor Operator exams from the NRC for DCPP
17 in accordance with 10 CFR 170.21.
18
19 Fees for review of Part 50 Application for 3,237,832 3,237,832
20 Reactor License, Inspections and Operator
21 exams from the NRC for DCPP in accordance
22 with 10 CFR 170.21.
23
24 Other miscellaneous 3,727 3,727
25
26 Annual fee to the NRC for Humboldt Bay Nuclear -132,500 -132,500
27 Power Plant (HBPP) in accordance with 10 CFR .
28
29 Fees for review of Part 50 Application for 192,010 192,010
30 Reactor License, Inspections and Operator
31 exams from the NRC for HBPP in accordance
32 with 10 CFR 170.21.
33
34
35
36
37
38
39
40
41
42
43
44
45
Year/Period of Report
End of 2010/Q4
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Deferred
in Account
182.3 at
Beginning of Year
(e)
46 TOTAL 16,565,614 16,565,614
FERC FORM NO. 1 (ED. 12-96) Page 350

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
REGULATORY COMMISSION EXPENSES (Continued)
Year/Period of Report
End of 2010/Q4
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR
AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Deferred to Contra
Amount
Deferred in
Department Account
Amount
No.
Account 182.3 Account
Account 182.3
End of Year
(f) (g)
(h)
(i)
(j)
(k) (l)
Electric 524
9,649,731
1
2
3
4
5
6
7
Electric 524
3,472,976
8
9
10
11
12
13
14
Electric 524
141,838
15
16
17
18
Electric 930
3,237,832
19
20
21
22
23
Electric 930
3,727
24
25
Electric 524
-132,500
26
27
28
Electric 524
192,010
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
Line
No.
16,565,614
46
FERC FORM NO. 1 (ED. 12-96) Page 351

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
Classification
(a)
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Description
(b)
Year/Period of Report
End of 2010/Q4
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed Internally: a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distribution
i. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.)
c. Internal combustion or gas turbine (7) Total Cost Incurred
d. Nuclear B. Electric, R, D & D Performed Externally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f. Siting and heat rejection Power Research Institute
(2) Transmission
1 NONE
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 352

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
Year/Period of Report
End of 2010/Q4
(2) Research Support to Edison Electric Institute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost Incurred
3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $50,000 or more,
briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).
Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D &
D activity.
4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year,
listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by
"Est."
7. Report separately research and related testing facilities operated by the respondent.
Costs Incurred Internally
Current Year
(c)
Costs Incurred Externally
Current Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR
Account
(e)
Amount
(f)
Unamortized
Accumulation
(g)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 353

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
DISTRIBUTION OF SALARIES AND WAGES
Year/Period of Report
End of 2010/Q4
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
Classification
(a)
Electric
Operation
Production
Transmission
Regional Market
Distribution
Customer Accounts
Customer Service and Informational
Sales
Administrative and General
TOTAL Operation (Enter Total of lines 3 thru 10)
Maintenance
Production
Transmission
Regional Market
Distribution
Administrative and General
TOTAL Maintenance (Total of lines 13 thru 17)
Total Operation and Maintenance
Production (Enter Total of lines 3 and 13)
Transmission (Enter Total of lines 4 and 14)
Regional Market (Enter Total of Lines 5 and 15)
Distribution (Enter Total of lines 6 and 16)
Customer Accounts (Transcribe from line 7)
Customer Service and Informational (Transcribe from line 8)
Sales (Transcribe from line 9)
Administrative and General (Enter Total of lines 10 and 17)
TOTAL Oper. and Maint. (Total of lines 20 thru 27)
Gas
Operation
Production-Manufactured Gas
Production-Nat. Gas (Including Expl. and Dev.)
Other Gas Supply
Storage, LNG Terminaling and Processing
Transmission
Distribution
Customer Accounts
Customer Service and Informational
Sales
Administrative and General
TOTAL Operation (Enter Total of lines 31 thru 40)
Maintenance
Production-Manufactured Gas
Production-Natural Gas (Including Exploration and Development)
Other Gas Supply
Storage, LNG Terminaling and Processing
Transmission
Direct Payroll
Distribution
(b)
166,228,686
47,061,630
122,082,443
121,095,703
92,453,305
1,963,232
201,894,362
752,779,361
90,769,180
24,681,118
133,374,155
248,824,453
256,997,866
71,742,748
255,456,598
121,095,703
92,453,305
1,963,232
201,894,362
1,001,603,814
4,109,263
3,902,814
24,872,292
93,104,181
87,248,664
15,640,463
5,790,295
79,182,429
313,850,401
556,660
2,423,133
12,038,673
Allocation of
Payroll charged for
Clearing Accounts
(c)
Total
(d)
1,001,603,814
FERC FORM NO. 1 (ED. 12-88) Page 354

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Year/Period of Report
End of 2010/Q4
Line
No.
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
Classification
(a)
Distribution
Administrative and General
TOTAL Maint. (Enter Total of lines 43 thru 49)
Total Operation and Maintenance
Production-Manufactured Gas (Enter Total of lines 31 and 43)
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
Other Gas Supply (Enter Total of lines 33 and 45)
Storage, LNG Terminaling and Processing (Total of lines 31 thru
Transmission (Lines 35 and 47)
Distribution (Lines 36 and 48)
Customer Accounts (Line 37)
Customer Service and Informational (Line 38)
Sales (Line 39)
Administrative and General (Lines 40 and 49)
TOTAL Operation and Maint. (Total of lines 52 thru 61)
Other Utility Departments
Operation and Maintenance
TOTAL All Utility Dept. (Total of lines 28, 62, and 64)
Utility Plant
Construction (By Utility Departments)
Electric Plant
Gas Plant
Other (provide details in footnote):
TOTAL Construction (Total of lines 68 thru 70)
Plant Removal (By Utility Departments)
Electric Plant
Gas Plant
Other (provide details in footnote):
TOTAL Plant Removal (Total of lines 73 thru 75)
Other Accounts (Specify, provide details in footnote):
TOTAL Other Accounts
TOTAL SALARIES AND WAGES
Direct Payroll
Distribution
(b)
46,673,621
61,692,087
4,665,923
6,325,947
36,910,965
139,777,802
87,248,664
15,640,463
5,790,295
79,182,429
375,542,488
1,377,146,302
367,907,023
73,720,782
56,149,252
497,777,057
212,430,741
175,222,279
1,556,839
389,209,859
4,806,896
4,806,896
2,268,940,114
Allocation of
Payroll charged for
Clearing Accounts
(c)
Total
(d)
375,542,488
1,377,146,302
367,907,023
73,720,782
56,149,252
497,777,057
212,430,741
175,222,279
1,556,839
389,209,859
4,806,896
4,806,896
2,268,940,114
FERC FORM NO. 1 (ED. 12-88) Page 355

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of
2010/Q4
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
COMMON UTILITY PLANT IN SERVICE
-------------------------------
Balance Transfers Balance
Acct Beginning and End
No. Description of Year Additions Retirements Adjustments of Year
---- -------------------------- ------------- ----------- ----------- ------------ -------------
301 Organization 132,410 18,753 0 0 151,163
302 Franchises/Consents 0 102,806 0 0 102,806
303 Intangible Plant 853,390,259 111,071,209 -9,037,023 -417,866 955,006,579
------------- ----------- ----------- ------------ -------------
Total Intangible Plant 853,522,669 111,192,768 -9,037,023 -417,866 955,260,548
------------- ----------- ----------- ------------ -------------
389 Land and Land Rights 79,357,259 135,449 0 -3,493 79,489,215
------------- ----------- ----------- ------------ -------------
390 Structures and Improvements 1,090,144,145 32,158,508 -2,692,893 -467,621 1,119,142,139
391 Personal Computer Hardware 55,745,825 24,686,864 -7,501,357 -103,983 72,827,349
391 Office Machines 307,219,522 28,377,895 -26,891,985 0 308,705,432
391 Office Furniture & Equipment 218,121,035 7,244,509 -1,141,081 0 224,224,463
392 Transportation Equipment 600,920,065 53,038,207 -30,894,922 -13,250 623,050,100
393 Stores Equipment 9,916,894 485,879 -241,356 0 10,161,417
394 Tools, Shop, & Garage Equipment 53,321,321 3,425,425 -2,390,237 -14,821 54,341,688
395 Laboratory Equipment 24,375,072 3,014,838 -466,703 0 26,923,207
397 Communication Equipment 682,269,744 192,413,734 -43,781,046 -2,043,517 828,858,915
398 Miscellaneous Equipment 20,394,752 2,226,385 -126,241 0 22,494,896
399 Other Tangible Property 495,750 0 -406,091 0 89,659
396 Power Operated Equipment 95,498,973 10,496,340 -4,585,403 0 101,409,910
------------- ----------- ----------- ------------ -------------
Total Non-Landed 3,158,423,098 357,568,584 -143,383,639 -2,643,192 3,392,229,174
------------- ----------- ----------- ------------ -------------
Total 4,091,303,026 468,896,801 -189,216,338 -3,064,551 4,426,978,938
------------- ----------- ----------- ------------ -------------
101.1 Property Under Capital Leases 0 0 0 0 0
------------- ----------- ----------- ------------ -------------
Total Common Utility Plant in Service 4,091,303,026 468,896,801 -195,763,108 -3,064,551 4,426,978,938
107 Construction Work in Progress-
Common Utility Plant 160,786,201 132,037,856 0 0 292,824,057
------------- ----------- ----------- ------------ -------------
Total Common Utility Plant 4,252,089,227 600,934,657 -195,763,108 -3,064,551 4,719,802,995
============= =========== =========== =========== =============
FERC FORM NO. 1 (ED. 12-87) Page 356

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of
2010/Q4
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
ALLOCATION OF COMMON UTILITY PLANT AND
ACCUMULATED PROVISION FOR DEPRECIATION BASED
ON THE COST SEPARATION ADOPTED BY THE CPUC
--------------------------------------------
Description Total Electric Gas
----------- ------------- ------------- -------------
Common Utility Plant in Service (a) 4,426,978,938 2,801,392,271 1,625,586,666
Accumulated Provision for Depreciation (a) 1,700,936,099 1,125,849,603 575,086,495
ALLOCATION OF AD VALOREM TAXES APPLICABLE TO COMMON UTILITY PLANT
BASED ON THE COST SEPARATION ADOPTED BY THE CPUC
------------------------------------------------
Amount Account 408
Charged -----------------------------
Description During Year Electric Gas
----------- ------------- ------------- -------------
Taxes
Operative Property (b) 248,392,558 195,683,548 52,709,010
(from page 262-263)
Common Utility Plant (a) 16,314,001 10,323,500 5,990,501
included in above amount
NOTES:
(a) 2009 allocations are based on the methodology of unbundling Common Plant as approved
in the cost separation filing and adopted in the 2003 General Rate Case (GRC).
Electric
Gas
------------- -------------
Common Plant in Service Allocation Factors 63.28% 36.72%
Common Plant Accumulated Depreciation Allocation Factors 66.19% 33.81%
(b) Amounts are based on direct charges. Not included in the total was $307,415 charged to others.
ALLOCATION OF DEPRECIATION EXPENSE APPLICABLE TO COMMON
FERC FORM NO. 1 (ED. 12-87) Page 356.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of
2010/Q4
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
UTILITY PLANT BASED ON THE COST SEPARATION ADOPTED BY THE CPUC
--------------------------------------------------------------
Amount Account 403
Charged -----------------------------
Description Account During Year Electric Gas
----------- ------- ------------- ------------- -------------
Depreciation 403 160,500,054 109,080,147 51,419,907
Amortization 404 93,805,609 60,626,565 33,179,044
------------- ------------ -------------
Total 254,305,663 169,706,712 84,598,951
============= ============ =============
ALLOCATION OF MAINTENANCE EXPENSES OF COMMON UTILITY
PLANT BASED ON THE COST SEPARATION ADOPTED BY THE CPUC
------------------------------------------------------
Amount Account 935
Charged -----------------------------
Description During Year Electric Gas
----------- ------------- ------------- -------------
Maintenance of General Plant 15,411,323 11,056,083 4,355,240
Note:
Operation expense data was not available.
CONSTRUCTION WORK IN PROGRESS - COMMON (ACCOUNT 107)
----------------------------------------------------
Description of Project
Amount
FERC FORM NO. 1 (ED. 12-87) Page 356.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of
2010/Q4
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
----------------------------------------------------------------------------- -------------
Dynamic Pricing Phase 1-Peak Day Pricing IT Multiple Counties 49,438,791
Radio Network Refresh/Consolidation Multiple Counties 18,513,356
Web Improvement Project (WIP) Multiple Counties 17,480,748
Mapping & Facility Management Automation San Francisco County 11,518,628
Enterprise Security Risk Management Project San Francisco County 10,708,900
ADAPT Program San Francisco County 7,471,224
Condition Based Maintenance San Francisco County 7,432,809
Enterprise Information Protection (EIP) Release 1.0,1.1,3.2 Multiple Counties 7,345,076
Warehous & Meter Mgmnt Sys Repl&Ntw San Francisco County 6,597,062
Veg Management Application Replacem Multiple Counties 6,453,901
Market Redesign and Technology Upgrade MAP San Francisco County 5,874,210
ETC Pay Statement Opt-out & Enhance San Francisco County 5,772,333
LAN/WAN Lifecycle Multiple Counties 5,665,554
Common Facilities Lifecycle Multiple Counties 5,006,388
SAP Learning Mgmt Solution (Capital) San Francisco County 4,792,559
ISO Real Time Settlements San Francisco County 4,601,129
Lifecycle Program Management (cap) Multiple Counties 4,139,129
Santa Rosa SC - Remodel Bldgs 7549, Sonoma County 3,948,864
Smart Meter - O&M Process Improvement (Release O) San Francisco County 3,880,864
MobileConnect Release 3 San Francisco County 3,683,543
Stockton SC - Remodel Bldg 2 #6350 San Joaquin County 3,613,972
San Francisco SC Garage-Seismic Upgrade San Francisco County 3,440,776
San Francisco SC MEP Replacement San Francisco County 3,371,312
SM - Performance Engineering (Release X) San Francisco County 3,349,447
Dynamic Pricing Phase 1-Peak Day Pricing IT San Francisco County 3,229,245
Enterprise Information Protection (EIP) Release 1.0,1.1,3.2 San Francisco County 3,203,185
FA IT ENT: Enterprise Content Mngmn Multiple Counties 3,158,030
Wintel Server Lifecycle Multiple Counties 2,904,840
Smart Meter - Operations Center Capital Phase 2 Contra Costa County 2,762,060
Capital Asset Expense Planning Phase San Francisco County 2,744,728
Wireless Lifecycle Multiple Counties 2,699,286
PowerPlant Asset Accounting System Multiple Counties 2,633,963
General Office - GENSET San Francisco County 2,514,359
Operational Reporting Initiative San Francisco County 2,432,435
SAP Upgrade - HR Enterprise Structure San Francisco County 2,154,442
Capital Asset Expense Planning Phase Multiple Counties 2,038,245
Business Intelligence Program/Platform Enhancements San Francisco County 1,767,481
Warehous & Meter Mgmnt Sys Repl&Ntw Multiple Counties 1,660,635
Fleet Capital Tools & Equipment Yolo County 1,658,462
LAN/WAN Lifecycle San Francisco County 1,618,196
Business Intelligence Program-HR BW Enhancements San Francisco County 1,581,792
ADAPT Program Multiple Counties 1,565,930
Workforce Time and Attendance Module San Francisco County 1,531,896
Storage Refresh/Capacity Solano County 1,469,751
Smart Meter - Business Process Release I San Francisco County 1,419,775
FERC FORM NO. 1 (ED. 12-87) Page 356.3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of
2010/Q4
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
Call Efficiency Improvements Phase San Francisco County 1,381,684
EPI Renewable Energy Trading Settle San Francisco County 1,363,884
MobileConnect Release 3 Multiple Counties 1,307,799
Invest in Buildings-VP Div Ops Facilities Tuolumne County 1,262,625
63-SCADA Electric Trans - SCADA Com Alameda County 1,236,437
SAP Upgrade - SAP Automation San Francisco County 1,234,911
Mapping & Facility Management Automation Multiple Counties 1,152,235
Smart Meter - Business Process (Release O) San Francisco County 1,079,700
Fleet Mgmt System Implementation R1 Multiple Counties 997,449
Corporate Real Estate - Interiors San Francisco County 996,316
Smart Meter - Release X Phase 2 San Francisco County 987,491
Bakersfield SC - Remodel Bldgs Kern County 986,315
Unix Server Refresh/Capacity Multiple Counties 972,569
SAP Upgrade - Capital Multiple Counties 949,826
63-SCADA Electric Trans - SCADA MS Multiple Counties 836,887
Transmission Lifecycle Multiple Counties 769,110
Smart Meter - Business Process (Replan) San Francisco County 762,316
BI Program - BPC/IPS Phase 1 San Francisco County 742,053
SM - Outage Restoration Replan (Rel J) San Francisco County 683,707
Cinnabar SC - Replace HVAC Units Santa Clara County 676,139
Technical School Infrastructure Upgrade Alameda County 658,267
Smart Meter - MDMS 2.7.3 San Francisco County 647,954
General Office - Replace Strobes System San Francisco County 598,222
Transmission Lifecycle Butte County 596,422
Risk Control Infrastructure Improvements Multiple Counties 546,300
Smart Meter - Restoration Validation (Release J) San Francisco County 527,387
SCADA Electric Dist - Comm Sonoma County 509,798
Smart Meter - IT Core Team Activity San Francisco County 505,231
IT Facility Refresh (CAP) Kern County 503,343
63-SCADA Electric Trans - SCADA MS San Francisco County 495,916
Risk Control Infrastructure Improvements San Francisco County 488,652
Repl Security Server & Oprtng Platform San Luis Obispo County 471,527
SCADA Electric Dist - Comm Multiple Counties 436,292
IT Facility Refresh (CAP) Calaveras County 421,843
Invest in Buildings-VP Div Ops Facilities Contra Costa County 410,536
Smart Meter - Operations Center Capital (Phase 2) San Francisco County 407,622
IT Facility Refresh (CAP) San Joaquin County 403,452
Habitat Conservation Portal Enhance San Francisco County 396,542
Invest in Buildings-VP Div Ops Facilities Multiple Counties 377,306
Invest in Buildings-VP Div Ops Facilities Shasta County 374,858
Condition Based Maintenance Multiple Counties 372,051
Data Center Facilities Lifecycle Solano County 371,825
Smart Meter - Release X Hardware (Phase 2) Multiple Counties 336,003
DP2_IT Real Time Pricing Multiple Counties 322,368
Transmission Lifecycle Kern County 319,243
GSM, Terminal Reliability Multiple Counties 315,276
FERC FORM NO. 1 (ED. 12-87) Page 356.4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of
2010/Q4
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
Corporate Real Estate - Roofing San Francisco County 308,135
2010 ED Control Ctr Consolidation Contra Costa County 287,634
Smart Meter - System Integration & Test San Francisco County 284,690
DCPP Reporting Enhancements San Luis Obispo County 281,807
CGT-Systemwide SCADA RTU Replacement -WK Tehama County 272,849
63-SCADA Electric Trans - SCADA Com Tehama County 259,942
Capital Conservation Multiple Counties 256,962
Invest in Buildings-VP Div Ops Facilities Mendocino County 251,698
-----------
Subtotal- Projects with more than $250,000
in actual costs in CWIP, excluding Research,
Development, & Demonstration jobs 285,246,717
Projects with less than $250,000 in actual
costs in CWIP, including credits representing
preliminary billings 7,577,340
-----------
TOTAL CWIP - COMMON 292,824,057
===========
FERC FORM NO. 1 (ED. 12-87) Page 356.5

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for
Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market
for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining
whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and
separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line
Description of Item(s)
No.
(a)
1 Energy
2 Net Purchases (Account 555)
3 Net Sales (Account 447)
4 Transmission Rights
Balance at End of Balance at End of
Quarter 1 Quarter 2
(b)
(c)
Balance at End of
Quarter 3
(d)
Balance at End of
Year
(e)
5 Ancillary Services
1,218,265 1,113,463 697,690
4,414,846
6 Other Items (list separately)
7 Grid Management
13,000,110 13,106,328 19,768,771 61,396,810
8 FERC Fees
1,073,299 1,048,634 2,548,280
5,891,935
9 ISO Congestion
10 Unaccounted for Energy
( 5,797,804) 26,359,941 ( 3,760,029)
3,627,241
11 Congestion Revenue Rights -Hedge
( 23,958) ( 7,449,477) ( 8,288,902) ( 21,287,336)
12 Congestion Revenue Rights -Auction
767,881 ( 276,333) 351,721
1,132,180
13 Other ISO related charges:
14 Neutrality
1,167,865 12,405,364 12,614,241 40,655,988
15 Voltage Support
16 Other
( 14,615,504) ( 14,813,691) ( 6,664,672) ( 47,177,583)
17 Cost Recovery
6,044,027 11,902,094 2,262,582 33,476,811
18 Inter Day Ahead SC Trade
( 125,370,100) ( 90,512,206) ( 86,017,953) ( 418,347,633)
19 Inter Real Time SC Trade
( 3,276,217) ( 10,037,969) ( 10,958,125) ( 28,464,724)
20 Interest
( 9,905) ( 11,048) ( 27,162) ( 106,835)
21 Energy
22 ISO Spot Market Purchases
17,577,792 10,515,224 24,230,354 81,105,763
23 ISO Spot Market Sales
( 8,952,754) ( 25,968,529) ( 6,356,084) ( 55,366,979)
24 Day Ahead Market Purchases
323,447,809 190,659,072 268,000,728 1,087,590,858
25 Day Ahead Market Sales
392,436 ( 128,215) ( 4,699,569) ( 6,759,334)
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL
206,643,242 117,912,652 203,701,871
741,782,008
FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
PURCHASES AND SALES OF ANCILLARY SERVICES
Year/Period of Report
End of 2010/Q4
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during
the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Line
No.
Type of Ancillary Service
(a)
1 Scheduling, System Control and Dispatch
2 Reactive Supply and Voltage
3 Regulation and Frequency Response
4 Energy Imbalance
5 Operating Reserve - Spinning
6 Operating Reserve - Supplement
7 Other
8 Total (Lines 1 thru 7)
Amount Purchased for the Year
Usage - Related Billing Determinant
Unit of
Number of Units Measure Dollars
(b) (c) (d)
Various
4,651,062
4,651,062
Amount Sold for the Year
Usage - Related Billing Determinant
Unit of
Number of Units Measure Dollars
(e) (f) (g)
859,303
835,017
1,129,123
835,017
835,017
4,493,477
NA
kW-Month
kW-Month
kWh
kW-Month
kW-Month
Various
FERC FORM NO. 1 (New 2-04) Page 398

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 398 Line No.: 1 Column: b
With the exception of the Utility's contracts with BART and Minnesota Methane (OAT
Tarriff) that are reported In Lines 1 - 6, all Ancillary Services (AS) purchases and sales
are covered under the FERC approved ISO Tariff. Definitions of AS under Order No. 888 and
the ISO Tariff are not consistent with one another. In order to avoid confusion as to
meanings and terminologies, ISO AS amounts are not included on these lines but are
reported on Line 7.
Schedule Page: 398 Line No.: 7 Column: b
This line includes Ancillary Services as follows:
AS under grandfathered existing
contracts
Regulation Service
Charge
- -
-
Flat
Charge
0
ISO related AS activities
Retail ISO Purchases and Sales and
Existing Transmission Contracts (ETC) (a)
- Various 4,651,062 - Various 236,216
Total 4,651,062 236,216
(a) This comprised of various billing determinants which the ISO uses to calculate the amounts of AS sold or
purchased.
This item also includes ISO AS purchases/sales by the Utility in its role as Scheduling Coordinator for
ETCs.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Year/Period of Report
End of 2010/Q4
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for
the definition of each statistical classification.
NAME OF SYSTEM:
Line
No.
1 January
Month
(a)
2 February
3 March
4 Total for Quarter 1
5 April
6 May
7 June
8 Total for Quarter 2
9 July
10 August
11 September
12 Total for Quarter 3
13 October
14 November
15 December
16 Total for Quarter 4
Monthly Peak
MW - Total
(b)
14,226
14,008
13,683
41,917
12,659
12,290
18,902
43,851
19,308
20,975
19,286
59,569
15,975
14,790
14,492
45,257
Day of
Monthly
Peak
(c)
21
23
9
19
3
28
15
25
2
14
29
16
Hour of
Monthly
Peak
(d)
1800
1900
1900
2000
1400
1700
1700
1700
1600
1600
1800
1800
Firm Network
Service for Self
(e)
11,416
11,576
11,144
34,136
10,410
10,785
15,940
37,135
15,901
17,538
16,125
49,564
13,246
11,650
11,541
36,437
Firm Network
Service for
Others
(f)
70
68
62
200
62
47
43
152
66
68
68
202
60
60
71
191
Long-Term Firm
Point-to-point
Reservations
(g)
Other Long-
Term Firm
Short-Term Firm
Point-to-point
Other
Service
Service
(h)
Reservation
(i)
(j)
1,710 1,030
1,711 653
1,711 766
5,132 2,449
1,702 486
960 498
1,712 1,207
4,374 2,191
435 2,905
426 2,943
632 2,461
1,493 8,309
550 2,119
482 2,598
522 2,358
1,554 7,075
17 Total Year to
Date/Year
190,594
157,272
745
12,553 20,024
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 400 Line No.: 1 Column: b
The source of the entries in this column are the metered data from Pacific Gas and
Electric Company's (the "Utility") Daily Service Report, Line 9.
Schedule Page: 400 Line No.: 1 Column: f
Entries here represent Open Access Transmission Tariff Network Service to the Bay Area
Rapid Transit District.
Schedule Page: 400 Line No.: 1 Column: h
Entries here represent transmission service to the following Existing Transmission
Contract customers:
California Department of Water Resources
City and County of San Francisco ("CCSF")
Transmission Agency of Northern California ("TANC")
Western Area Power Administration ("WAPA")
Contract demand is used as a proxy for coincident peaks for CCSF and TANC. WAPA coincident
peaks are estimated.
Schedule Page: 400 Line No.: 1 Column: j
Transmission services utilizing the Utility's transmission system are also sold by the
California Independent System Operator ("ISO") to other wholesale entities. The ISO tracks
this data and reports it sepearately to the FERC. The Utility does not have access to this
data. The ISO numbers reported in this column were derived by subtracting columns (e)-(i)
from column (b).
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line
No.
Item
(a)
1 SOURCES OF ENERGY
2 Generation (Excluding Station Use):
3 Steam
4 Nuclear
5 Hydro-Conventional
6 Hydro-Pumped Storage
7 Other
8 Less Energy for Pumping
9 Net Generation (Enter Total of lines 3
through 8)
10 Purchases
11 Power Exchanges:
12 Received
13 Delivered
14 Net Exchanges (Line 12 minus line 13)
15 Transmission For Other (Wheeling)
16 Received
17 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
MegaWatt Hours
Line
Item MegaWatt Hours
No.
(b)
(a)
(b)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
84,064,481
3,546,966 Interdepartmental Sales)
18,430,538 23 Requirements Sales for Resale (See
1,607,595
10,376,222 instruction 4, page 311.)
583,878 24 Non-Requirements Sales for Resale (See
138,282 instruction 4, page 311.)
899,141 25 Energy Furnished Without Charge
32,176,745 26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
58,828,998
2,441,868
2,384,081
57,787
91,063,530
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
5,391,454
91,063,530
FERC FORM NO. 1 (ED. 12-90) Page 401a

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
MONTHLY PEAKS AND OUTPUT
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
2. Report in column (b) by month the system’s output in Megawatt hours for each month.
3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system.
5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM: Pacific Gas and Electric Company
Monthly Non-Requirments
Line
MONTHLY PEAK
Sales for Resale &
No. Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4) Day of Month
Hour
(a)
(b)
(c)
(d)
(e)
(f)
29 January
7,514,915
13,181 21
1800
30 February
6,645,928
12,868 23
1900
31 March
7,384,859
12,725 9
1900
32 April
7,038,424
11,753 19
2000
33 May
7,350,355
11,851 3
2100
34 June
8,081,128
17,641 28
1700
35 July
8,968,964
17,767 15
1700
36 August
8,755,624
19,286 25
1700
37 September
8,201,029
17,677 2
1600
38 October
7,654,567
14,755 14
1600
39 November
7,372,216
13,383 29
1800
40 December
7,681,834
13,207 16
1800
41 TOTAL 92,649,843
FERC FORM NO. 1 (ED. 12-90) Page 401b

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 401 Line No.: 3 Column: b
This includes conventional plants only. It does not include combustion turbines, which is
shown separately on Line 7.
Schedule Page: 401 Line No.: 7 Column: b
This includes combustion turbines and photo voltaic generation of 133,677 MWH and 4,605
MWH, respectively.
Schedule Page: 401 Line No.: 10 Column: b
Actual purchases from pages 326-327 were 44,837,023 MWH. For purposes only of accounting
for the total energy that went through the Utility's electric system, the MWH for Direct
Access ("DA") of 4,192,541 MWH and California Department of Water Resources ("DWR")
deliveries of 9,799,434 MWH were added to this line item. It should be noted that DA and
DWR megawatts are not Utility purchases and were reported here only because page 401 of
the Form 1 does not have any other available line where DA and DWR deliveries can be shown
more appropriately.
The Utility acts as a pass-through entity for electricity purchased by the DWR that is
sold to the Utility's customers. Although charges for electricity provided by the DWR are
included in the amounts the Utility bills its customers, the Utility deducts from
electricity revenues amounts passed through to the DWR. The pass-through amounts are based
on the quantities of electricity provided by the DWR that are consumed by customers,
priced at the related CPUC-approved remittance rate. These pass-through amounts are
excluded from the Utility's electricity revenues in its Statement of Income.
Schedule Page: 401 Line No.: 22 Column: b
This includes MWH sales for DWR and DA as discussed in the footnote to Line 10, column b.
Schedule Page: 401 Line No.: 26 Column: b
Data for energy used by the electric department is not separately available but is
included on Line 22.
Schedule Page: 401 Line No.: 29 Column: b
The values shown in Lines 29-40, column b, include correction of data previously reported
in Form 3-Q for the first three quarters of 2010.
Schedule Page: 401 Line No.: 29 Column: c
The values shown in Lines 29-40, column c, include correction of data previously reported
in Form 3-Q for the first three quarters of 2010.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of
2010/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name: DIABLO CANYON 1 & 2
(b)
Plant
Name: HUMBOLDT BAY 1 & 2
(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
2 Type of Constr (Conventional, Outdoor, Boiler, etc)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
6 Net Peak Demand on Plant - MW (60 minutes)
7 Plant Hours Connected to Load
8 Net Continuous Plant Capability (Megawatts)
9 When Not Limited by Condenser Water
10 When Limited by Condenser Water
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - KWh
13 Cost of Plant: Land and Land Rights
14 Structures and Improvements
15 Equipment Costs
16 Asset Retirement Costs
17 Total Cost
18 Cost per KW of Installed Capacity (line 17/5) Including
19 Production Expenses: Oper, Supv, & Engr
20 Fuel
21 Coolants and Water (Nuclear Plants Only)
22 Steam Expenses
23 Steam From Other Sources
24 Steam Transferred (Cr)
25 Electric Expenses
26 Misc Steam (or Nuclear) Power Expenses
27 Rents
28 Allowances
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Boiler (or reactor) Plant
32 Maintenance of Electric Plant
33 Maintenance of Misc Steam (or Nuclear) Plant
34 Total Production Expenses
35 Expenses per Net KWh
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
38 Quantity (Units) of Fuel Burned
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
41 Average Cost of Fuel per Unit Burned
42 Average Cost of Fuel Burned per Million BTU
43 Average Cost of Fuel Burned per KWh Net Gen
44 Average BTU per KWh Net Generation
Nuclear
Steam
Conventional
Semi-Outdoor
1968
1956
1986
1958
2323.00
102.40
2240
105
8760
6544
0
0
2240
105
2240
0
1439
45
18430537775
379721293
26285591
218631
977695407
11748462
6326554765
29088315
0
23866669
7330535763
64922077
3155.6331
634.0047
0
0
105267617
28132140
29049330
0
49020065
27550
0
0
0
0
1620980
21730
80412389
2358076
0
0
0
0
0
0
8515850
300
33840917
1128
40039351
1332886
18618116
2454685
366384615
34328495
0.0199
0.0904
Nuclear
Gas
MWD
Mcf
0 2306350 0 0 4872508 0
0 0 0 0 1019889 0
0.000 0.000 0.000 0.000 4.940 0.000
0.000 45.647 0.000 0.000 5.440 0.000
0.000 0.557 0.000 0.000 5.330 0.000
0.000 0.006 0.000 0.000 0.070 0.000
0.000 10247.676 0.000 0.000 13218.000 0.000
FERC FORM NO. 1 (REV. 12-03) Page 402

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of
2010/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name: Colusa Gen Station
(b)
Plant
Name: Humboldt Gen Station
(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
2 Type of Constr (Conventional, Outdoor, Boiler, etc)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
6 Net Peak Demand on Plant - MW (60 minutes)
7 Plant Hours Connected to Load
8 Net Continuous Plant Capability (Megawatts)
9 When Not Limited by Condenser Water
10 When Limited by Condenser Water
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - KWh
13 Cost of Plant: Land and Land Rights
14 Structures and Improvements
15 Equipment Costs
16 Asset Retirement Costs
17 Total Cost
18 Cost per KW of Installed Capacity (line 17/5) Including
19 Production Expenses: Oper, Supv, & Engr
20 Fuel
21 Coolants and Water (Nuclear Plants Only)
22 Steam Expenses
23 Steam From Other Sources
24 Steam Transferred (Cr)
25 Electric Expenses
26 Misc Steam (or Nuclear) Power Expenses
27 Rents
28 Allowances
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Boiler (or reactor) Plant
32 Maintenance of Electric Plant
33 Maintenance of Misc Steam (or Nuclear) Plant
34 Total Production Expenses
35 Expenses per Net KWh
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
38 Quantity (Units) of Fuel Burned
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
41 Average Cost of Fuel per Unit Burned
42 Average Cost of Fuel Burned per Million BTU
43 Average Cost of Fuel Burned per KWh Net Gen
44 Average BTU per KWh Net Generation
Combined Cycle
Internal Comb Recip
Outdoor
Indoor
2010
2010
2010
2011
711.45
146.43
659
146
157
2239
0
0
0
0
0
0
23
18
67868256
129784500
6214498
0
110713282
60184243
521199372
130214429
6893077
2957716
645020229
193356388
906.6276
1320.4698
0
0
1906662
4040723
0
0
0
0
0
0
0
0
10306
8450
-560139
656939
0
0
0
0
0
0
143
43980
535
439
632129
614035
3428
2811
1993064
5367377
0.0294
0.0414
Gas
Gas
Mcf
Mcf
0 459541 0 0 1128157 0
0 1018000 0 0 1023500 0
0.000 4.360 0.000 0.000 4.350 0.000
0.000 4.340 0.000 0.000 4.590 0.000
0.000 4.350 0.000 0.000 4.430 0.000
0.000 0.030 0.000 0.000 0.040 0.000
0.000 6893.000 0.000 0.000 8945.000 0.000
FERC FORM NO. 1 (REV. 12-03) Page 402.1

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name:
Mobile Unit 2
(d)
Plant
Name:
Mobile Unit 3
(e)
Plant
Name:
Gateway Gen Station
(f)
Year/Period of Report
End of
2010/Q4
Line
No.
Oil
Bbl
Gas Turbine Gas Turbine Combined Cycle 1
Mobile Mobile Outdoor 2
1976 1976 2009 3
1976 1976 2009 4
13.30 13.30 613.00 5
15 15 580 6
121 204 6922 7
0 0 0 8
15 15 0 9
0 0 0 10
0 0 21 11
2631563 1260789 3099376275 12
0 0 5040000 13
0 1399 69543039 14
3189457 4354025 365773242 15
0 0 5198961 16
3189457 4355424 445555242 17
239.8088 327.4755 726.8438 18
0 0 0 19
1611518 1201526 112397632 20
0 0 0 21
879 880 0 22
0 0 0 23
0 0 0 24
694 693 121340 25
73555 73555 -6530590 26
0 0 0 27
0 0 0 28
0 0 0 29
10 9 641499 30
36 36 1573580 31
42539 42538 9340121 32
56465 306602 1836759 33
1785696 1625839 119380341 34
0.6786 1.2895 0.0385 35
Oil Gas
36
Bbl Mcf
37
0 7871 0 0 3349 0 0 22952623 0
38
0 5809455 0 0 5809455 0 0 1027500 0
39
0.000 105.840 0.000 0.000 105.840 0.000 0.000 4.840 0.000
40
0.000 104.990 0.000 0.000 104.990 0.000 0.000 4.910 0.000
41
0.000 18.070 0.000 0.000 18.070 0.000 0.000 4.640 0.000
42
0.000 0.314 0.000 0.000 0.279 0.000 0.000 0.035 0.000
43
0.000 17376.000 0.000 0.000 15433.000 0.000 0.000 7609.000 0.000
44
FERC FORM NO. 1 (REV. 12-03) Page 403

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name:
(d)
Plant
Name:
(e)
Plant
Name:
(f)
End of
2010/Q4
Line
No.
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7
0 0 0 8
0 0 0 9
0 0 0 10
0 0 0 11
0 0 0 12
0 0 0 13
0 0 0 14
0 0 0 15
0 0 0 16
0 0 0 17
0.0000 0.0000 0.0000 18
0 0 0 19
0 0 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0 0 0 34
0.0000 0.0000 0.0000 35
0 0 0 0 0 0 0 0 0
38
0 0 0 0 0 0 0 0 0
39
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
40
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
41
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
42
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
43
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
44
1
2
3
4
36
37
FERC FORM NO. 1 (REV. 12-03) Page 403.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 402 Line No.: -1 Column: c
Humboldt Bay Units 1 & 2 were retired September 30, 2010.
Schedule Page: 402 Line No.: -1 Column: d
Mobile Unit 1 was salvaged and scrapped out in 2008.
Schedule Page: 402 Line No.: -1 Column: e
Mobile Unit 2 and Mobile Unit 3 were retired September 24, 2010.
Schedule Page: 402 Line No.: 11 Column: d
Operated and maintained by employees stationed at Humboldt Bay Power Plant.
Schedule Page: 402 Line No.: 11 Column: e
Operated and maintained by employees stationed at Humboldt Bay Power Plant.
Schedule Page: 402 Line No.: 17 Column: c
Total costs for all steam power plants exclude primarily those relating to asset
retirement costs for the non-operational Humboldt Bay Unit 3 plant and other miscellaneous
costs not tied to any existing generating plants.
Schedule Page: 402 Line No.: 34 Column: c
Total production expenses for all steam power plants exclude certain expenses for the
non-operational Humboldt Bay Unit 3 plant and other miscellaneous costs not tied to any
existing generating plant
FERC FORM NO. 1 (ED. 12-87) Page 450.1

FERC FORM NO. 1 (REV. 12-03) Page 406
Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Year/Period of Report
End of
2010/Q4
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No.
Plant Name: BALCH NO. 1
(b)
175
FERC Licensed Project No.
Plant Name: BALCH NO. 2
(c)
175
1 Kind of Plant (Run-of-River or Storage)
R of R/Storage R of R/Storage
2 Plant Construction type (Conventional or Outdoor)
Conventional Outdoor
3 Year Originally Constructed
1927 1958
4 Year Last Unit was Installed
1927 1958
5 Total installed cap (Gen name plate Rating in MW)
31.00 97.20
6 Net Peak Demand on Plant-Megawatts (60 minutes)
34 105
7 Plant Hours Connect to Load
7,250 8,754
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions
34 105
10 (b) Under the Most Adverse Oper Conditions
34 104
11 Average Number of Employees
0 0
12 Net Generation, Exclusive of Plant Use - Kwh
144,643,669 559,392,475
13 Cost of Plant
14 Land and Land Rights
7,714 1,112
15 Structures and Improvements
0 2,897,151
16 Reservoirs, Dams, and Waterways
9,683,062 5,321,106
17 Equipment Costs
6,956,037 13,747,748
18 Roads, Railroads, and Bridges
623,794 0
19 Asset Retirement Costs
0 0
20 TOTAL cost (Total of 14 thru 19)
17,270,607 21,967,117
21 Cost per KW of Installed Capacity (line 20 / 5)
557.1164 225.9991
22 Production Expenses
23 Operation Supervision and Engineering
0 0
24 Water for Power
13,819 78,255
25 Hydraulic Expenses
21,841 68,021
26 Electric Expenses
123,546 265,060
27 Misc Hydraulic Power Generation Expenses
172,597 533,023
28 Rents
19,274 59,523
29 Maintenance Supervision and Engineering
0 0
30 Maintenance of Structures
150,428 467,077
31 Maintenance of Reservoirs, Dams, and Waterways
119,311 248,295
32 Maintenance of Electric Plant
797,545 614,602
33 Maintenance of Misc Hydraulic Plant
158,259 141,700
34 Total Production Expenses (total 23 thru 33)
1,576,620 2,475,556
35 Expenses per net KWh
0.0109 0.0044

FERC FORM NO. 1 (REV. 12-03) Page 406.1
Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Year/Period of Report
End of
2010/Q4
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No.
Plant Name: BUTT VALLEY
(b)
2105
FERC Licensed Project No. 2105
Plant Name: CARIBOU NO. 1
(c)
1 Kind of Plant (Run-of-River or Storage)
R of R/Storage R of R/Storage
2 Plant Construction type (Conventional or Outdoor)
Outdoor Conventional
3 Year Originally Constructed
1958 1921
4 Year Last Unit was Installed
1958 1924
5 Total installed cap (Gen name plate Rating in MW)
40.00 73.85
6 Net Peak Demand on Plant-Megawatts (60 minutes)
41 75
7 Plant Hours Connect to Load
6,530 7,901
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions
41 75
10 (b) Under the Most Adverse Oper Conditions
38 74
11 Average Number of Employees
0 6
12 Net Generation, Exclusive of Plant Use - Kwh
116,480,191 99,181,363
13 Cost of Plant
14 Land and Land Rights
502,332 346,421
15 Structures and Improvements
1,274,550 3,787,151
16 Reservoirs, Dams, and Waterways
37,442,234 27,109,412
17 Equipment Costs
15,179,906 14,679,294
18 Roads, Railroads, and Bridges
601,748 346,067
19 Asset Retirement Costs
0 0
20 TOTAL cost (Total of 14 thru 19)
55,000,770 46,268,345
21 Cost per KW of Installed Capacity (line 20 / 5)
1,375.0193 626.5179
22 Production Expenses
23 Operation Supervision and Engineering
0 0
24 Water for Power
36,244 66,436
25 Hydraulic Expenses
11,408 19,509
26 Electric Expenses
131,247 1,047,458
27 Misc Hydraulic Power Generation Expenses
224,949 409,385
28 Rents
8,168 15,307
29 Maintenance Supervision and Engineering
0 0
30 Maintenance of Structures
22,894 97,348
31 Maintenance of Reservoirs, Dams, and Waterways
193,686 208,539
32 Maintenance of Electric Plant
169,641 704,960
33 Maintenance of Misc Hydraulic Plant
134,012 223,657
34 Total Production Expenses (total 23 thru 33)
932,249 2,792,599
35 Expenses per net KWh
0.0080 0.0282

FERC FORM NO. 1 (REV. 12-03) Page 406.2
Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Year/Period of Report
End of
2010/Q4
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No.
Plant Name: DE SABLA
(b)
803
FERC Licensed Project No.
Plant Name: DRUM NO. 1
(c)
2310
1 Kind of Plant (Run-of-River or Storage)
R of R/Storage R of R/Storage
2 Plant Construction type (Conventional or Outdoor)
Outdoor Conventional
3 Year Originally Constructed
1963 1913
4 Year Last Unit was Installed
1963 1928
5 Total installed cap (Gen name plate Rating in MW)
18.45 49.20
6 Net Peak Demand on Plant-Megawatts (60 minutes)
19 54
7 Plant Hours Connect to Load
7,604 4,050
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions
19 54
10 (b) Under the Most Adverse Oper Conditions
19 54
11 Average Number of Employees
0 6
12 Net Generation, Exclusive of Plant Use - Kwh
79,357,287 87,703,003
13 Cost of Plant
14 Land and Land Rights
145,157 1,610,547
15 Structures and Improvements
2,267,852 2,507,598
16 Reservoirs, Dams, and Waterways
30,955,103 13,390,359
17 Equipment Costs
3,993,854 16,071,705
18 Roads, Railroads, and Bridges
2,271,774 1,022,736
19 Asset Retirement Costs
0 0
20 TOTAL cost (Total of 14 thru 19)
39,633,740 34,602,945
21 Cost per KW of Installed Capacity (line 20 / 5)
2,148.1702 703.3119
22 Production Expenses
23 Operation Supervision and Engineering
0 0
24 Water for Power
15,368 81,387
25 Hydraulic Expenses
68,336 370,927
26 Electric Expenses
246,845 862,478
27 Misc Hydraulic Power Generation Expenses
222,769 569,964
28 Rents
13,872 70,205
29 Maintenance Supervision and Engineering
0 0
30 Maintenance of Structures
16,261 55,755
31 Maintenance of Reservoirs, Dams, and Waterways
744,590 676,369
32 Maintenance of Electric Plant
137,789 360,017
33 Maintenance of Misc Hydraulic Plant
155,644 165,393
34 Total Production Expenses (total 23 thru 33)
1,621,474 3,212,495
35 Expenses per net KWh
0.0204 0.0366

FERC FORM NO. 1 (REV. 12-03) Page 406.3
Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Year/Period of Report
End of
2010/Q4
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No.
Plant Name: HAAS
(b)
1988
FERC Licensed Project No.
Plant Name: HALSEY
(c)
2130
1 Kind of Plant (Run-of-River or Storage)
R of R/Storage R of R/Storage
2 Plant Construction type (Conventional or Outdoor)
Conventional Conventional
3 Year Originally Constructed
1958 1916
4 Year Last Unit was Installed
1958 1916
5 Total installed cap (Gen name plate Rating in MW)
135.00 13.60
6 Net Peak Demand on Plant-Megawatts (60 minutes)
144 11
7 Plant Hours Connect to Load
8,659 7,879
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions
144 11
10 (b) Under the Most Adverse Oper Conditions
138 11
11 Average Number of Employees
0 0
12 Net Generation, Exclusive of Plant Use - Kwh
624,935,810 56,480,683
13 Cost of Plant
14 Land and Land Rights
29,498 885,301
15 Structures and Improvements
6,619,522 480,241
16 Reservoirs, Dams, and Waterways
28,440,696 12,308,042
17 Equipment Costs
17,319,835 4,355,434
18 Roads, Railroads, and Bridges
152,179 12,048
19 Asset Retirement Costs
0 0
20 TOTAL cost (Total of 14 thru 19)
52,561,730 18,041,066
21 Cost per KW of Installed Capacity (line 20 / 5)
389.3461 1,326.5490
22 Production Expenses
23 Operation Supervision and Engineering
0 0
24 Water for Power
58,529 16,574
25 Hydraulic Expenses
96,845 206,157
26 Electric Expenses
348,973 223,888
27 Misc Hydraulic Power Generation Expenses
709,445 124,067
28 Rents
428,314 14,298
29 Maintenance Supervision and Engineering
0 0
30 Maintenance of Structures
142,073 64,531
31 Maintenance of Reservoirs, Dams, and Waterways
237,698 541,275
32 Maintenance of Electric Plant
527,641 155,724
33 Maintenance of Misc Hydraulic Plant
200,902 41,195
34 Total Production Expenses (total 23 thru 33)
2,750,420 1,387,709
35 Expenses per net KWh
0.0044 0.0246

FERC FORM NO. 1 (REV. 12-03) Page 406.4
Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Year/Period of Report
End of
2010/Q4
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 96
Plant Name: KERCKHOFF NO. 2
(b)
FERC Licensed Project No. 1988
Plant Name: KINGS RIVER
(c)
1 Kind of Plant (Run-of-River or Storage)
R of R/Storage R of R/Storage
2 Plant Construction type (Conventional or Outdoor)
Underground Semi-Outdoor
3 Year Originally Constructed
1983 1962
4 Year Last Unit was Installed
1983 1962
5 Total installed cap (Gen name plate Rating in MW)
139.50 48.60
6 Net Peak Demand on Plant-Megawatts (60 minutes)
155 52
7 Plant Hours Connect to Load
6,971 7,029
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions
155 52
10 (b) Under the Most Adverse Oper Conditions
151 52
11 Average Number of Employees
0 0
12 Net Generation, Exclusive of Plant Use - Kwh
551,886,124 222,499,802
13 Cost of Plant
14 Land and Land Rights
578,362 14,097
15 Structures and Improvements
37,879,761 1,957,755
16 Reservoirs, Dams, and Waterways
76,084,473 13,614,121
17 Equipment Costs
37,107,248 7,966,816
18 Roads, Railroads, and Bridges
7,535,859 40,813
19 Asset Retirement Costs
0 0
20 TOTAL cost (Total of 14 thru 19)
159,185,703 23,593,602
21 Cost per KW of Installed Capacity (line 20 / 5)
1,141.1162 485.4651
22 Production Expenses
23 Operation Supervision and Engineering
0 0
24 Water for Power
388,328 56,713
25 Hydraulic Expenses
93,687 33,404
26 Electric Expenses
339,497 147,254
27 Misc Hydraulic Power Generation Expenses
749,171 256,184
28 Rents
57,980 154,665
29 Maintenance Supervision and Engineering
0 0
30 Maintenance of Structures
82,356 27,564
31 Maintenance of Reservoirs, Dams, and Waterways
358,683 698,076
32 Maintenance of Electric Plant
836,148 278,061
33 Maintenance of Misc Hydraulic Plant
120,747 59,849
34 Total Production Expenses (total 23 thru 33)
3,026,597 1,711,770
35 Expenses per net KWh
0.0055 0.0077

FERC FORM NO. 1 (REV. 12-03) Page 406.5
Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Year/Period of Report
End of
2010/Q4
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No.
Plant Name: PIT NO. 3
(b)
233
FERC Licensed Project No.
Plant Name: PIT NO. 4
(c)
233
1 Kind of Plant (Run-of-River or Storage)
R of R/Storage R of R/Storage
2 Plant Construction type (Conventional or Outdoor)
Conventional Conventional
3 Year Originally Constructed
1925 1955
4 Year Last Unit was Installed
1925 1955
5 Total installed cap (Gen name plate Rating in MW)
80.19 103.50
6 Net Peak Demand on Plant-Megawatts (60 minutes)
70 95
7 Plant Hours Connect to Load
8,689 8,757
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions
70 95
10 (b) Under the Most Adverse Oper Conditions
70 95
11 Average Number of Employees
6 0
12 Net Generation, Exclusive of Plant Use - Kwh
283,586,734 407,561,527
13 Cost of Plant
14 Land and Land Rights
3,625,208 291,717
15 Structures and Improvements
494,004 1,461,956
16 Reservoirs, Dams, and Waterways
50,024,273 40,501,467
17 Equipment Costs
9,169,331 16,320,270
18 Roads, Railroads, and Bridges
1,303,689 219,591
19 Asset Retirement Costs
0 0
20 TOTAL cost (Total of 14 thru 19)
64,616,505 58,795,001
21 Cost per KW of Installed Capacity (line 20 / 5)
805.7926 568.0676
22 Production Expenses
23 Operation Supervision and Engineering
0 0
24 Water for Power
45,076 57,483
25 Hydraulic Expenses
9,190 12,477
26 Electric Expenses
1,201,216 156,067
27 Misc Hydraulic Power Generation Expenses
1,437,063 2,084,029
28 Rents
15,667 21,260
29 Maintenance Supervision and Engineering
0 0
30 Maintenance of Structures
39,015 131,283
31 Maintenance of Reservoirs, Dams, and Waterways
774,878 129,998
32 Maintenance of Electric Plant
478,380 528,179
33 Maintenance of Misc Hydraulic Plant
171,008 127,151
34 Total Production Expenses (total 23 thru 33)
4,171,493 3,247,927
35 Expenses per net KWh
0.0147 0.0080

FERC FORM NO. 1 (REV. 12-03) Page 406.6
Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Year/Period of Report
End of
2010/Q4
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No.
Plant Name: POE
(b)
2107
FERC Licensed Project No. 1962
Plant Name: ROCK CREEK
(c)
1 Kind of Plant (Run-of-River or Storage)
R of R/Storage R of R/Storage
2 Plant Construction type (Conventional or Outdoor)
Outdoor Conventional
3 Year Originally Constructed
1958 1950
4 Year Last Unit was Installed
1958 1950
5 Total installed cap (Gen name plate Rating in MW)
142.83 124.74
6 Net Peak Demand on Plant-Megawatts (60 minutes)
120 112
7 Plant Hours Connect to Load
7,255 8,747
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions
120 112
10 (b) Under the Most Adverse Oper Conditions
125 114
11 Average Number of Employees
0 6
12 Net Generation, Exclusive of Plant Use - Kwh
531,552,676 424,874,953
13 Cost of Plant
14 Land and Land Rights
817,824 1,770,950
15 Structures and Improvements
2,138,275 3,668,080
16 Reservoirs, Dams, and Waterways
32,944,749 41,369,289
17 Equipment Costs
12,773,740 7,668,388
18 Roads, Railroads, and Bridges
1,146,684 353,339
19 Asset Retirement Costs
0 0
20 TOTAL cost (Total of 14 thru 19)
49,821,272 54,830,046
21 Cost per KW of Installed Capacity (line 20 / 5)
348.8152 439.5546
22 Production Expenses
23 Operation Supervision and Engineering
0 0
24 Water for Power
106,290 99,212
25 Hydraulic Expenses
21,701 20,867
26 Electric Expenses
315,157 1,240,791
27 Misc Hydraulic Power Generation Expenses
665,528 1,314,824
28 Rents
45,364 31,520
29 Maintenance Supervision and Engineering
0 0
30 Maintenance of Structures
73,080 93,133
31 Maintenance of Reservoirs, Dams, and Waterways
832,048 382,779
32 Maintenance of Electric Plant
520,611 279,602
33 Maintenance of Misc Hydraulic Plant
115,918 67,819
34 Total Production Expenses (total 23 thru 33)
2,695,697 3,530,547
35 Expenses per net KWh
0.0051 0.0083

FERC FORM NO. 1 (REV. 12-03) Page 406.7
Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Year/Period of Report
End of
2010/Q4
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No.
Plant Name: WEST POINT
(b)
137
FERC Licensed Project No.
Plant Name: WISE NO. 1
(c)
2310
1 Kind of Plant (Run-of-River or Storage)
R of R/Storage R of R/Storage
2 Plant Construction type (Conventional or Outdoor)
Conventional Conventional
3 Year Originally Constructed
1948 1917
4 Year Last Unit was Installed
1948 1917
5 Total installed cap (Gen name plate Rating in MW)
13.60 13.60
6 Net Peak Demand on Plant-Megawatts (60 minutes)
15 14
7 Plant Hours Connect to Load
7,665 7,925
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions
15 14
10 (b) Under the Most Adverse Oper Conditions
13 14
11 Average Number of Employees
0 6
12 Net Generation, Exclusive of Plant Use - Kwh
84,258,665 80,878,173
13 Cost of Plant
14 Land and Land Rights
225,845 790,751
15 Structures and Improvements
644,927 560,125
16 Reservoirs, Dams, and Waterways
5,337,959 7,262,509
17 Equipment Costs
6,048,085 7,486,462
18 Roads, Railroads, and Bridges
142,056 32,563
19 Asset Retirement Costs
0 0
20 TOTAL cost (Total of 14 thru 19)
12,398,872 16,132,410
21 Cost per KW of Installed Capacity (line 20 / 5)
911.6818 1,186.2066
22 Production Expenses
23 Operation Supervision and Engineering
0 0
24 Water for Power
10,206 21,107
25 Hydraulic Expenses
29,520 262,023
26 Electric Expenses
164,360 720,175
27 Misc Hydraulic Power Generation Expenses
169,111 157,999
28 Rents
25,902 18,199
29 Maintenance Supervision and Engineering
0 0
30 Maintenance of Structures
23,089 14,812
31 Maintenance of Reservoirs, Dams, and Waterways
116,006 682,971
32 Maintenance of Electric Plant
167,581 161,418
33 Maintenance of Misc Hydraulic Plant
36,334 49,929
34 Total Production Expenses (total 23 thru 33)
742,109 2,088,633
35 Expenses per net KWh
0.0088 0.0258

FERC FORM NO. 1 (REV. 12-03) Page 406.8
Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Year/Period of Report
End of
2010/Q4
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No.
Plant Name:
(b)
0
FERC Licensed Project No.
Plant Name:
(c)
0
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
0.00 0.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)
0 0
7 Plant Hours Connect to Load
0 0
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions
0 0
10 (b) Under the Most Adverse Oper Conditions
0 0
11 Average Number of Employees
0 0
12 Net Generation, Exclusive of Plant Use - Kwh
0 0
13 Cost of Plant
14 Land and Land Rights
0 0
15 Structures and Improvements
0 0
16 Reservoirs, Dams, and Waterways
0 0
17 Equipment Costs
0 0
18 Roads, Railroads, and Bridges
0 0
19 Asset Retirement Costs
0 0
20 TOTAL cost (Total of 14 thru 19)
0 0
21 Cost per KW of Installed Capacity (line 20 / 5)
0.0000 0.0000
22 Production Expenses
23 Operation Supervision and Engineering
0 0
24 Water for Power
0 0
25 Hydraulic Expenses
0 0
26 Electric Expenses
0 0
27 Misc Hydraulic Power Generation Expenses
0 0
28 Rents
0 0
29 Maintenance Supervision and Engineering
0 0
30 Maintenance of Structures
0 0
31 Maintenance of Reservoirs, Dams, and Waterways
0 0
32 Maintenance of Electric Plant
0 0
33 Maintenance of Misc Hydraulic Plant
0 0
34 Total Production Expenses (total 23 thru 33)
0 0
35 Expenses per net KWh
0.0000 0.0000

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of
2010/Q4
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name: BELDEN
(d)
2105
FERC Licensed Project No. 2106
Plant Name: JAMES B. BLACK
(e)
FERC Licensed Project No.
Plant Name: BUCKS CREEK
(f)
619
Line
No.
R of R/Storage R of R/Storage
R of R/Storage 1
Outdoor Outdoor
Conventional 2
1969 1965 1928 3
1969 1966 1928 4
117.90 168.66 66.00 5
125 172 65 6
5,304 8,737 8,726 7
125 172 65 9
125 172 53 10
0 0 0 11
250,131,428 714,469,248 213,295,615 12
505,304 696,134 808,723 14
1,041,275 496,741 540,730 15
56,463,742 59,799,986 12,688,450 16
8,125,567 17,302,669 17,937,927 17
293,264 1,202,704 3,085,588 18
0 0 0 19
66,429,152 79,498,234 35,061,418 20
563.4364 471.3520 531.2336 21
0 0 0 23
110,727 99,060 58,871 24
29,205 26,229 16,685 25
187,579 280,093 190,170 26
681,484 826,421 477,930 27
25,512 64,345 89,721 28
0 0 0 29
69,987 87,510 77,161 30
366,130 432,556 366,226 31
378,284 418,193 198,337 32
85,886 133,419 60,263 33
1,934,794 2,367,826 1,535,364 34
0.0077 0.0033 0.0072 35
8
13
22
FERC FORM NO. 1 (REV. 12-03) Page 407

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of
2010/Q4
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2105
Plant Name: CARIBOU NO. 2
(d)
FERC Licensed Project No.
Plant Name: COLEMAN
(e)
1121
FERC Licensed Project No.
Plant Name: CRESTA
(f)
1962
Line
No.
R of R/Storage R of R/Storage
R of R/Storage 1
Outdoor Conventional
Conventional 2
1958 1979 1949 3
1958 1979 1950 4
117.90 12.15 73.80 5
120 13 70 6
8,746 6,037 8,752 7
120 13 70 9
119 5 72 10
0 0 0 11
357,167,432 33,013,629 290,319,746 12
361,471 95,300 1,363,491 14
2,860,788 783,922 1,745,519 15
30,516,398 20,617,259 20,977,121 16
16,228,530 7,973,325 10,459,151 17
859 39,392 135,058 18
0 0 0 19
49,968,046 29,509,198 34,680,340 20
423.8172 2,428.7406 469.9233 21
0 0 0 23
106,296 5,091 62,005 24
25,277 65,446 15,129 25
68,579 231,486 218,984 26
654,165 89,744 823,268 27
24,487 2,944 19,698 28
0 0 0 29
88,923 26,571 39,034 30
286,144 409,619 398,499 31
336,761 145,073 153,606 32
76,330 81,673 43,234 33
1,666,962 1,057,647 1,773,457 34
0.0047 0.0320 0.0061 35
8
13
22
FERC FORM NO. 1 (REV. 12-03) Page 407.1

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of
2010/Q4
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name: DRUM NO. 2
(d)
2310
FERC Licensed Project No.
Plant Name: DUTCH FLAT
(e)
2310
FERC Licensed Project No.
Plant Name: ELECTRA
(f)
137
Line
No.
R of R/Storage R of R/Storage
R of R/Storage 1
Outdoor Conventional
Conventional 2
1965 1943 1948 3
1965 1943 1948 4
53.10 22.00 102.50 5
50 22 98 6
7,859 7,186 8,684 7
50 22 98 9
49 23 98 10
0 0 2 11
301,210,656 89,882,103 462,305,028 12
211,194 646,357 1,087,570 14
177,574 600,113 1,210,947 15
2,371,783 8,420,278 23,758,342 16
950,946 8,707,362 14,769,808 17
356,754 184,068 955,709 18
0 0 0 19
4,068,251 18,558,178 41,782,376 20
76.6149 843.5535 407.6329 21
0 0 0 23
74,600 33,170 59,317 24
339,895 151,171 193,305 25
600,995 137,106 647,280 26
522,445 232,313 1,106,406 27
64,327 28,596 164,483 28
0 0 0 29
40,105 17,836 148,998 30
605,763 281,953 716,385 31
223,302 225,362 473,652 32
151,293 67,717 217,920 33
2,622,725 1,175,224 3,727,746 34
0.0087 0.0131 0.0081 35
8
13
22
FERC FORM NO. 1 (REV. 12-03) Page 407.2

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of
2010/Q4
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2661
FERC Licensed Project No. 2661 FERC Licensed Project No. 96
Plant Name: HAT CREEK NO. 1 Plant Name: HAT CREEK NO. 2
Plant Name: KERCKHOFF NO. 1
(d)
(e)
(f)
Line
No.
R of R/Storage R of R/Storage
R of R/Storage 1
Conventional Conventional
Conventional 2
1921 1921 1920 3
1921 1921 1920 4
10.00 10.00 34.08 5
9 9 38 6
8,663 8,059 2,742 7
9 9 38 9
4 9 0 10
0 0 0 11
29,339,370 37,604,662 39,111,072 12
574,530 917,321 5,889 14
230,364 294,998 563,583 15
1,055,959 937,936 3,191,256 16
1,610,621 2,707,706 4,720,970 17
810,393 319,411 5,491 18
0 0 0 19
4,281,867 5,177,372 8,487,189 20
428.1867 517.7372 249.0372 21
0 0 0 23
3,099 3,099 59,142 24
19,088 2,135 22,770 25
99,054 98,822 160,941 26
181,541 181,541 184,696 27
349 348 14,215 28
0 0 0 29
8,871 4,179 21,863 30
30,930 45,690 124,553 31
74,982 159,122 245,766 32
24,696 27,302 73,279 33
442,610 522,238 907,225 34
0.0151 0.0139 0.0232 35
8
13
22
FERC FORM NO. 1 (REV. 12-03) Page 407.3

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of
2010/Q4
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name: NARROWS
(d)
1403
FERC Licensed Project No.
Plant Name: NEWCASTLE
(e)
2310
FERC Licensed Project No.
Plant Name: PIT NO.1
(f)
2687
Line
No.
R of R/Storage R of R/Storage
R of R/Storage 1
Conventional Conventional
Conventional 2
1942 1986 1922 3
1942 1986 1922 4
10.20 12.70 69.30 5
12 12 61 6
5,803 5,885 8,632 7
12 12 61 9
12 0 61 10
0 0 0 11
55,947,199 32,339,948 218,921,215 12
274,030 3,872,962 1,574,231 14
517,867 4,035,049 2,237,360 15
543,619 43,805,028 9,124,090 16
3,783,915 6,743,087 19,599,250 17
506,629 2,622,426 1,512,115 18
0 0 0 19
5,626,060 61,078,552 34,047,046 20
551.5745 4,809.3348 491.2994 21
0 0 0 23
128,623 17,327 131,391 24
16,515 215,750 8,009 25
201,841 246,340 290,370 26
282,985 129,721 982,331 27
172 14,941 305 28
0 0 0 29
4,568 9,321 34,207 30
275,815 598,116 726,069 31
177,664 160,337 238,230 32
26,361 53,316 87,812 33
1,114,544 1,445,169 2,498,724 34
0.0199 0.0447 0.0114 35
8
13
22
FERC FORM NO. 1 (REV. 12-03) Page 407.4

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of
2010/Q4
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 233
FERC Licensed Project No. 2106 FERC Licensed Project No.
Plant Name: PIT NO. 5 Plant Name: PIT NO. 6
Plant Name: PIT NO. 7
(d)
(e)
(f)
2106
Line
No.
R of R/Storage R of R/Storage
R of R/Storage 1
Conventional Outdoor
Outdoor 2
1944 1965 1965 3
1944 1965 1965 4
141.84 79.20 109.80 5
160 80 112 6
8,758 8,751 8,755 7
160 80 112 9
160 80 112 10
6 0 0 11
713,132,508 344,962,398 483,570,511 12
484,269 274,798 315,356 14
3,833,398 2,899,716 2,207,649 15
43,641,746 17,313,851 22,334,105 16
34,484,315 7,758,927 7,876,849 17
1,382,508 690,250 409,930 18
0 0 0 19
83,826,236 28,937,542 33,143,889 20
590.9915 365.3730 301.8569 21
0 0 0 23
58,316 46,080 64,503 24
33,428 11,083 14,711 25
1,215,476 239,339 211,065 26
3,154,785 391,725 614,412 27
35,808 29,932 41,903 28
0 0 0 29
85,315 40,692 61,254 30
249,890 253,403 249,566 31
516,010 359,065 420,531 32
260,142 99,523 110,589 33
5,609,170 1,470,842 1,788,534 34
0.0079 0.0043 0.0037 35
8
13
22
FERC FORM NO. 1 (REV. 12-03) Page 407.5

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of
2010/Q4
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 137
Plant Name: SALT SPRINGS
(d)
FERC Licensed Project No.
Plant Name: STANISLAUS
(e)
2130
FERC Licensed Project No.
Plant Name: TIGER CREEK
(f)
137
Line
No.
R of R/Storage R of R/Storage
R of R/Storage 1
Conventional Outdoor
Conventional 2
1931 1963 1931 3
1953 1963 1931 4
42.03 81.90 52.28 5
44 91 58 6
7,318 8,088 7,508 7
44 91 58 9
34 91 58 10
2 0 6 11
160,340,105 376,422,703 253,410,424 12
380,765 324,009 3,995,759 14
1,043,319 1,124,864 4,785,743 15
29,507,616 16,552,984 39,485,461 16
7,830,727 12,117,585 14,118,865 17
1,033,091 916,372 2,730,509 18
0 0 0 19
39,795,518 31,035,814 65,116,337 20
946.8360 378.9477 1,245.5305 21
0 0 0 23
30,973 391,165 40,826 24
91,612 145,473 263,557 25
405,333 588,346 575,787 26
517,877 1,778,457 680,996 27
78,676 94,862 103,684 28
0 0 0 29
41,052 98,689 154,282 30
313,543 597,293 571,993 31
489,413 652,569 312,428 32
117,109 345,598 164,077 33
2,085,588 4,692,452 2,867,630 34
0.0130 0.0125 0.0113 35
8
13
22
FERC FORM NO. 1 (REV. 12-03) Page 407.6

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of
2010/Q4
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name: A.G. WISHON
(d)
1354
FERC Licensed Project No.
Plant Name:
(e)
0
FERC Licensed Project No.
Plant Name:
(f)
0
Line
No.
R of R/Storage 1
Conventional 2
1910 3
1910 4
12.80 0.00 0.00 5
20 0 0 6
7,445 0 0 7
20 0 0 9
12 0 0 10
0 0 0 11
89,862,517 0 0 12
938,599 0 0 14
77,869 0 0 15
6,488,242 0 0 16
3,086,424 0 0 17
29,364 0 0 18
0 0 0 19
10,620,498 0 0 20
829.7264 0.0000 0.0000 21
0 0 0 23
30,538 0 0 24
11,984 0 0 25
146,353 0 0 26
419,262 0 0 27
97,260 0 0 28
0 0 0 29
14,053 0 0 30
180,630 0 0 31
363,865 0 0 32
18,385 0 0 33
1,282,330 0 0 34
0.0143 0.0000 0.0000 35
8
13
22
FERC FORM NO. 1 (REV. 12-03) Page 407.7

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of
2010/Q4
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name:
(d)
0 FERC Licensed Project No. 0
FERC Licensed Project No. 0
Plant Name:
Plant Name:
(e)
(f)
Line
No.
1
2
3
4
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7
0 0 0 9
0 0 0 10
0 0 0 11
0 0 0 12
0 0 0 14
0 0 0 15
0 0 0 16
0 0 0 17
0 0 0 18
0 0 0 19
0 0 0 20
0.0000 0.0000 0.0000 21
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0 0 0 34
0.0000 0.0000 0.0000 35
8
13
22
FERC FORM NO. 1 (REV. 12-03) Page 407.8

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 406 Line No.: 11 Column: b
Operated remotely from Fresno. Attended by 4 roving operators headquartered at Balch
Camp.
Schedule Page: 406 Line No.: 11 Column: c
Operated remotely from Fresno. Attended by 4 roving operators headquartered at Balch
Camp.
Schedule Page: 406 Line No.: 11 Column: d
Operated remotely from Caribou No. 1. Attended by 2 roving operators headquartered at
Caribou No. 1.
Schedule Page: 406 Line No.: 11 Column: e
Operated remotely from Pit No. 5. Attended by 3 roving operators headquartered at Pit
No. 5.
Schedule Page: 406 Line No.: 11 Column: f
Operated remotely from Rock Creek. Attended by 3 roving operators headquartered at Rock
Creek.
Schedule Page: 406.1 Line No.: 11 Column: b
Operated remotely from Caribou No. 1. Attended by 2 roving operators headquartered at
Caribou No. 1.
Schedule Page: 406.1 Line No.: 11 Column: d
Operated remotely from Caribou No. 1. Attended by 2 roving operators headquartered at
Caribou No. 1.
Schedule Page: 406.1 Line No.: 11 Column: e
Attended by 4 roving operators headquartered at Manton.
Schedule Page: 406.1 Line No.: 11 Column: f
Operated remotely from Rock Creek. Attended by 3 roving operators headquartered at Rock
Creek.
Schedule Page: 406.2 Line No.: 3 Column: c
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 406.2 Line No.: 3 Column: d
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 406.2 Line No.: 3 Column: e
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 406.2 Line No.: 3 Column: f
Salt Springs includes large storage facilities used also for Tiger Creek, West Point, and
Electra plants.
Schedule Page: 406.2 Line No.: 11 Column: b
Attended by 2 roving operators headquartered at Camp 1.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 406.2 Line No.: 11 Column: d
Operated remotely from Drum No. 1. Attended by 3 relief operators headquartered at Drum
No. 1.
Schedule Page: 406.2 Line No.: 11 Column: e
Operated remotely from Drum No. 1. Attended by 3 relief operators headquartered at Drum
No. 1.
Schedule Page: 406.3 Line No.: 3 Column: c
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 406.3 Line No.: 3 Column: f
Crane Valley includes storage facilities used also for Kerchoff No. 1 and No. 2, San
Joaquin Nos. 1-A, 2, 3 and A.G. Wishon plants (Projects 1354 and 96).
Schedule Page: 406.3 Line No.: 11 Column: b
Operated remotely from Fresno. Attended by 4 roving operators headquartered at Balch
Camp.
Schedule Page: 406.3 Line No.: 11 Column: c
Attended by 3 relief operators headquartered at Wise.
Schedule Page: 406.3 Line No.: 11 Column: d
Attended by 4 roving operators headquartered at Burney.
Schedule Page: 406.3 Line No.: 11 Column: e
Attended by 4 roving operators headquartered at Burney.
Schedule Page: 406.3 Line No.: 11 Column: f
Attended by 5 roving operators headquartered at A. G. Wishon.
Schedule Page: 406.4 Line No.: 3 Column: b
Crane Valley includes storage facilities used also for Kerchoff No. 1 and No. 2, San
Joaquin Nos. 1-A, 2, 3, and A. G. Wishon plants (Projects 1354 and 96).
Schedule Page: 406.4 Line No.: 3 Column: e
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 406.4 Line No.: 11 Column: b
Attended by 5 roving operators headquartered at A. G. Wishon.
Schedule Page: 406.4 Line No.: 11 Column: c
Operated remotely from Fresno. Attended by 4 roving operators headquartered at Balch Camp.
Schedule Page: 406.4 Line No.: 11 Column: f
Operated remotely from Pit No. 3. Attended by 4 roving operators headquartered at Burney.
Schedule Page: 406.5 Line No.: 11 Column: c
Operated remotely from Pit No. 3. Attended by 4 roving operators headquartered at Burney.
Schedule Page: 406.5 Line No.: 11 Column: e
Operated remotely from Pit No. 5. Attended by 3 roving operators headquartered at Pit No.
5.
Schedule Page: 406.5 Line No.: 11 Column: f
Operated remotely from Pit No. 5. Attended by 3 roving operators headquartered at Pit No.
5.
Schedule Page: 406.6 Line No.: 3 Column: d
Salt Springs includes large storage facilities used also for Tiger Creek, West Point, and
Electra plants.
Schedule Page: 406.6 Line No.: 3 Column: e
FERC FORM NO. 1 (ED. 12-87) Page 450.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Stanislaus Common includes hydraulic facilities common to Stanislaus and Spring Gap
plants. Stanislaus-Spring Gap common is not a hydroelectric generating plant.
Schedule Page: 406.6 Line No.: 3 Column: f
Salt Springs includes large storage facilities used also for Tiger Creek, West Point, and
Electra plants.
Schedule Page: 406.6 Line No.: 11 Column: b
Operated remotely from Rock Creek. Attended by 3 roving operators headquartered at Rock
Creek.
Schedule Page: 406.6 Line No.: 11 Column: e
Operated remotely from Tiger Creek Operating Center. Attended by 3 roving operators
headquartered at Tiger Creek.
Schedule Page: 406.7 Line No.: 3 Column: b
Salt Springs includes large storage facilities used also for Tiger Creek, West Point, and
Electra plants.
Schedule Page: 406.7 Line No.: 3 Column: c
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 406.7 Line No.: 3 Column: d
Crane Valley includes storage facilities used also for Kerchoff No. 1 and No. 2, San
Joaquin Nos. 1-A, 2, 3, and A. G. Wishon plants (Projects 1354 and 96).
Schedule Page: 406.7 Line No.: 11 Column: b
Operated remotely from Tiger Creek Operating Center. Attended by 1 roving operator
headquartered at Tiger Creek.
Schedule Page: 406.7 Line No.: 11 Column: d
Attended by 4 roving operators headquartered at Auberry.
Schedule Page: 406.7 Line No.: 11 Column: e
The average number of employees for each plant does not include headworks tenders,
maintenance force, or headquarters support personnel.
Schedule Page: 406.7 Line No.: 20 Column: e
Investments in recreation and fish and wildlife facilities and FIN 47 were not included in
the cost of plant reported in these pages.
Schedule Page: 406.7 Line No.: 34 Column: e
Total production expenses exclude those expenses for irrigation districts and other
expenses that are not tied to any specific plants.
FERC FORM NO. 1 (ED. 12-87) Page 450.3

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
End of 2010/Q4
04/08/2011
PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants)
1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. Give project number.
3. If net peak demand for 60 minutes is not available, give the which is available, specifying period.
4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each
plant.
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
Line
No.
Item
(a)
FERC Licensed Project No.
2735
Plant Name: HELMS PUMPED STORAGE
(b)
1 Type of Plant Construction (Conventional or Outdoor) Underground
2 Year Originally Constructed 1984
3 Year Last Unit was Installed 1984
4 Total installed cap (Gen name plate Rating in MW) 1,053
5 Net Peak Demaind on Plant-Megawatts (60 minutes) 1,050
6 Plant Hours Connect to Load While Generating 3,690
7 Net Plant Capability (in megawatts) 1,212
8 Average Number of Employees 8
9 Generation, Exclusive of Plant Use - Kwh 583,877,767
10 Energy Used for Pumping 899,141,292
11 Net Output for Load (line 9 - line 10) - Kwh -315,263,525
12 Cost of Plant
13 Land and Land Rights 706,889
14 Structures and Improvements 174,654,487
15 Reservoirs, Dams, and Waterways 427,234,441
16 Water Wheels, Turbines, and Generators 176,519,890
17 Accessory Electric Equipment 49,541,385
18 Miscellaneous Powerplant Equipment 16,374,377
19 Roads, Railroads, and Bridges 8,792,089
20 Asset Retirement Costs
21 Total cost (total 13 thru 20) 853,823,558
22 Cost per KW of installed cap (line 21 / 4) 810.8486
23 Production Expenses
24 Operation Supervision and Engineering
25 Water for Power 416,016
26 Pumped Storage Expenses 20,662
27 Electric Expenses 1,823,023
28 Misc Pumped Storage Power generation Expenses 2,613,210
29 Rents 81,095
30 Maintenance Supervision and Engineering
31 Maintenance of Structures 746,070
32 Maintenance of Reservoirs, Dams, and Waterways 594,026
33 Maintenance of Electric Plant 3,399,456
34 Maintenance of Misc Pumped Storage Plant 1,689,595
35 Production Exp Before Pumping Exp (24 thru 34) 11,383,153
36 Pumping Expenses
37 Total Production Exp (total 35 and 36) 11,383,153
38 Expenses per KWh (line 37 / 9) 0.0195
FERC FORM NO. 1 (REV. 12-03) Page 408

Name of Respondent
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
(2) A Resubmission
04/08/2011
PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of
2010/Q4
6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes.
7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37
and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each
station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as
reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping
energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
FERC Licensed Project No.
Plant Name:
(c)
0 FERC Licensed Project No.
0 FERC Licensed Project No.
0
Plant Name:
Plant Name:
(d)
(e)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (REV. 12-03) Page 409

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
GENERATING PLANT STATISTICS (Small Plants)
Year/Period of Report
End of 2010/Q4
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project,
give project number in footnote.
Year Installed Capacity Net Peak
Line
Net Generation
Name of Plant
Orig. Name Plate Rating Demand
Excluding Cost of Plant
No.
Const. (In MW)
MW
(60 min.)
Plant Use
(a)
(b) (c)
(d)
(e)
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
SMALL HYDROELECTRIC PLANTS:
Alta FERC No.2310
Centerville FERC No.803
Chili Bar FERC No.2155
Coal Canyon
Cow Creek FERC No.606
Crane Valley FERC No.1354
Deer Creek FERC No.2310
Hamilton Branch
Inskip FERC No.1121
Kern Canyon FERC No. 178
Kilarc FERC No.606
Lime Saddle
Merced Falls FERC No.2467
Oak Flat FERC No.2105
Phoenix FERC No.1061
Potter Valley FERC No.77
San Joaquin No. 1-A FERC No.1354
San Joaquin No. 2 FERC No.1354
San Joaquin No. 3 FERC No.1354
South FERC No.1121
Spaulding No. 1 FERC No.2310
Spaulding No. 2 FERC No.2310
Spaulding No. 3 FERC No.2310
Spring Gap FERC No.2130
Toadtown FERC No.803
Tule FERC No.1333
Volta No.1 FERC No.1121
Volta No.2 FERC No.1121
Wise II FERC No.2310
Miscellaneous items
PHOTO VOLTAIC GENERATING PLANTS:
AT&T Park Solar Arrays
SF Service Center Solar Arrays
Vaca Dixon Solar Station
INTERNAL COMBUSTION:
(EMERGENCY STANDBY UNITS)
Downieville Diesel Plant
Grass Valley Mobile Diesel Generator
Sierra City Mobile Diesel Generator
TOTAL
1902
1904
1965
1907
1907
1919
1908
1921
1979
1921
1904
1906
1930
1985
1940
1910
1919
1917
1923
1979
1928
1928
1929
1921
1986
1914
1980
1981
1986
2007
2007
2009
1966
1971
1972
2.00 1.2 3,594 7,442,123
6.40 6.4 8,809 13,999,804
7.02 7.0 31,785 7,989,938
1.00 0.9 -21 3,573,400
1.44 1.8 1,232 2,988,764
0.99 0.9 3,758 4,964,544
5.50 5.7 16,966 45,430,442
5.39 4.8 15,515 5,663,754
7.65 8.0 44,608 13,883,922
9.54 11.5 22,726 10,110,399
3.00 2.0 16,819 4,083,357
2.00 2.0 4,894 10,265,873
3.44 3.5 12,483 4,082,870
1.40 1.3 5,545 8,145,166
1.60 2.0 10,078 10,555,385
9.46 9.2 27,308 34,317,219
0.42 0.4 1,886 3,436,241
2.88 3.2 13,961 6,166,798
4.00 4.2 18,652 6,847,104
6.75 7.0 17,216 15,606,722
7.04 7.0 35,122 7,926,022
3.70 4.4 12,742 3,527,179
6.61 5.8 32,375 7,217,734
6.00 7.0 41,658 7,576,398
1.80 1.5 5,328 6,057,416
4.50 6.4 25,769 4,775,451
8.55 9.0 41,742 14,074,292
0.95 0.9 4,977 2,678,426
2.87 3.1 6,663 12,154,452
5,154,513
0.11 0.1 146 1,990,928
0.81 0.8 270 72,959
2.00 2.0 4,189 10,569,186
0.75 95,289
0.25 38,497
0.33 49,054
128.15 131.0 488,795 303,511,618
FERC FORM NO. 1 (REV. 12-03) Page 410

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation
Production Expenses
Fuel Costs (in cents
Line
Retire. Costs) Per MW Exc'l. Fuel
Fuel
Maintenance
Kind of Fuel (per Million Btu)
No.
(g) (h)
(i)
(j) (k) (l)
1
2,071 86,333
69,819
188,292 Water
2
1,589 367,331
5,317
452,466 Water
3
251 283,220
7,326
232,047 Water
4
-171,744 67,263
731
308,149 Water
5
2,426 128,993
620
254,708 Water
6
1,321 74,038
1,375
427,414 Water
7
2,678 110,858
8,597
752,064 Water
8
365 16,714
3,900
20,525 Water
9
311 260,105
2,922
151,385 Water
10
445 420,303
15,758
381,152 Water
11
243 128,734
1,180
215,988 Water
12
2,098 144,463
1,625
540,741 Water
13
327 116,215
13,588
198,858 Water
14
1,469 53,958
1,153
66,709 Water
15
1,047 263,639
1,268
488,933 Water
16
1,257 1,594,273
9,008
1,238,874 Water
17
1,822 85,553
609
160,421 Water
18
442 139,174
4,886
468,415 Water
19
367 171,752
6,411
271,975 Water
20
907 202,585
22,538
396,089 Water
21
226 207,688
10,549
336,995 Water
22
277 115,080
6,646
616,984 Water
23
223 138,824
8,751
374,548 Water
24
182 366,679
6,540
447,987 Water
25
1,137 150,698
1,246
164,397 Water
26
185 263,517
2,377
165,346 Water
27
337 281,720
3,276
387,093 Water
28
538 105,303
325
28,567 Water
29
1,824 108,104
4,664
213,714 Water
30
31
32
33
13,606 Solar
34
270 Solar
35
2,523 Solar
36
37
38
39
Diesel
40
Diesel
41
Diesel
42
43
621 6,453,117
223,005
9,950,836
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 411

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 410 Line No.: 2 Column: a
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 410 Line No.: 5 Column: a
Water expense included in Other Expenses for Coal Canyon is common to Coal Canyon and
Lime Saddle plants.
No federal license required.
Schedule Page: 410 Line No.: 7 Column: a
Crane Valley includes storage facilities used also for Kerchoff No. 1 and No. 2, San
Joaquin Nos. 1-A, 2, 3, and A. G. Wishon plants (Projects 1354 and 96).
Schedule Page: 410 Line No.: 8 Column: a
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 410 Line No.: 9 Column: a
No federal license required.
Schedule Page: 410 Line No.: 13 Column: a
Water expense included in Other Expenses for Coal Canyon is common to Coal Canyon and
Lime Saddle plants.
No federal license required.
Schedule Page: 410 Line No.: 16 Column: a
Lyons Reservoir services Phoenix plant.
Schedule Page: 410 Line No.: 18 Column: a
Crane Valley includes storage facilities used also for Kerchoff No. 1 and No. 2, San
Joaquin Nos. 1-A, 2, 3, and A. G. Wishon plants (Projects 1354 and 96).
Schedule Page: 410 Line No.: 19 Column: a
Crane Valley includes storage facilities used also for Kerchoff No. 1 and No. 2, San
Joaquin Nos. 1-A, 2, 3, and A. G. Wishon plants (Projects 1354 and 96).
Schedule Page: 410 Line No.: 20 Column: a
Crane Valley includes storage facilities used also for Kerchoff No. 1 and No. 2, San
Joaquin Nos. 1-A, 2, 3, and A. G. Wishon plants (Projects 1354 and 96).
Schedule Page: 410 Line No.: 22 Column: a
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 410 Line No.: 23 Column: a
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 410 Line No.: 24 Column: a
Drum/Spalding Common includes the South Yuba Water System facilities which are common to
Alta, Deer Creek, Drum No. 1, Drum No. 2, Dutch Flat, Halsey, Newcastle, Spaulding Nos. 1,
2, and 3, and Wise plants and the Bear River Canal which is common to Halsey and Wise
plants.
Schedule Page: 410 Line No.: 25 Column: a
Stanislaus Common includes hydraulic facilities common to Stanislaus and Spring Gap
plants. Stanislaus-Spring Gap common is not a hydroelectric generating plant.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 410 Line No.: 31 Column: a
No federal license required.
FERC FORM NO. 1 (ED. 12-87) Page 450.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
1
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
2 A.E.C. Windfarm Pittsburg-Tesla
3 (Ralph Tap) #2
4 American Canyon American Canyon-
5 Sobrante
6 American-Canyon American
7 Sobrante Carquinez
8 Straits
9 American-Canyon Sobrante
10 Sobrante Sub
11 Arco Midway
12 Balch PP McCall
13 Haas PP McCall
14
15 Belden PP Rock Crk. Jct.
16 #1
17 Belden PP Butte County
18 Table Mtn.
19 Bellota Gregg #1
20
21
22
23 #2
24
25
26 Bellota Tesla #1
27 #2
28
29
30 Black PP Pit #5 PP
31 Bottle Rock PP
32 Bucks Crk PP
33 Caribou PH #2 Table Mtn.
34
35
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 T
2
230.00 T
2
230.00 T
2
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 SSP
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
1 Castle Rock Jct. Fulton #1
2 Castle Rock Fulton #2
3 Junction
4
5 Castle Rock Lakeville Sub #1
6
7
8 Castle Rock Lakeville Sub #2
9
10
11 Center of American Canyon-
12 Carquinez Straits Sobrante
13
14 Contra Costa Contra Costa
15 PP Sub #1 & 2
16 Contra Costa Newark #1
17 PP and #2
18
19
20 Contra Costa Newark #3
21 PP Research Sub
22 Contra Costa Tesla #1
23 PP
24 Contra Costa Tesla #2
25 Contra Costa
26 PP
27 Contra Costa Tesla #2
28 PP Windmaster
29 Sub
30 Contra Costa Brentwood Sub
31 PP Tesla #1 & 2
32 Contra Costa San Mateo
33 PP #1 & #2
34
35
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 SSP
1
230.00
T
230.00 SSP
1
230.00 T
2
230.00 T
1
230.00 UG
1
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
1
230.00 T
2
230.00 T
2
230.00 T
2
230.00 SSP
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
2
230.00 T
2
230.00 T
2
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
1
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
2 Contra Costa San Mateo
3 PP #1 & #2
4 Cottonwood Vaca-Dixon #1
5 #2
6 Cottonwood Vac-Dixon #2
7 Diablo Cyn PP Gates
8 Diablo Cyn PP Mesa
9 Diablo Cyn PP Midway
10 Diablo Cyn PP Midway #3
11 Diablo Cyn PP #1 D.C. Smith Yard
12 Diablo Cyn PP #2 D.C. Switch Yard
13 Fulton Ignacio #1
14
15 Fulton Ignacio #2
16
17 Gates Gregg
18 Gates Arco
19 Gates McCall
20 Gates Panoche #1
21
22 #2
23 Geysers ll Castle Rock
24 Castle Rock Jct.- Fulton
25 Jct. Cir. Cir. #2
26 Geysers 20 Geysers 13
27 Tap
28 Geysers 16 NCPA Tap
29 Geysers 12 PP Geysers 14
30 Castle Rock
31 Geysers PP Castle Rock
32 (Unit #14) Lakeville
33 Geysers PP Castle Rock
34 (Unit #5 & 6) Jct.
35 Geysers PP Castle Rock
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 T
2
230.00 T
2
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
500.00 T
1
230.00 T
1
500.00 T
1
500.00 T
1
500.00 T
1
500.00 T
1
230.00 T
1
230.00 SSP
1
230.00 T
1
230.00 SSP
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 SWP
1
230.00 T
1
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
1
230.00 T
1
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
1 (Unit ll) Jct.
2 Geysers PP Castle Rock
3 (Unit 9 & 10) Jct.
4 Geysers PP Geysers PP
5 (Unit 13) (Unit (9)
6 Castle Rock
7 Jct.
8
9 Geysers PP Occidental
10 (Unit (9) Petroleum
11 Geysers PP Geothermal
12 (Unit 13) PP #1
13 Geysers PP Castle Rock
14 (Unit 14) Jct.
15 Geysers PP Geysers PP
16 (Unit 17) (Unit 11)
17 Castle Rock
18 Jct.
19 Geysers PP Geysers PP
20 (Unit 18) (Unit 14)
21 Castle Rock
22 Jct.
23 Gregg Ashlan Av.
24 Sub.
25 Gregg-Ashlan Figarden Sub #1
26 Av. Sub
27 Gregg Herndon #1
28 & #2
29 Helms Gregg #1
30
31 #2
32
33 Herndon-Ashlan Figarden Sub #2
34 Av.
35 Herndon Ashland Av.
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 T
1
230.00 T
1
230.00 UG
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 UG
1
230.00 T
1
230.00 1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 1
230.00 UG
1
230.00 T
1
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
1 Herndon Kearney
2 Ignacio American
3 Jct. Canyon Jct.
4 Ignacio Ignacio
5 Jct. Sub
6 Ignacio Ignacio
7 Loop Cir. Loop Cir.
8 1 & 2 1 & 2
9 Indian Springs Round Mt. Sub.
10 Lakeville Sub Ignacio Jct.
11 Lakeville Ignacio #2
12 Los Banos Sub Midway Sub
13 #1
14 #2
15 Los Banos Sub Panoche
16 Los Banos Sub San Luis
17 Pumps #1
18 #2
19 Martin Embarcadero
20 #1 (HZ)
21 Martin Embarcadero
22 #2 (HZ)
23 Melones Warnerville
24 Jct. #1 & 2
25 Metcalf Monta Vista
26 Metcalf Monta Vista
27 Metcalf Monta Vista
28 Metcalf Moss Landg#1&#2
29 Metcalf Newark #1&#2
30
31 Midddle Fork PP Gold Hill
32
33
34 Middle Fork PP Gold Hill
35
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
2
500.00 T
1
230.00 T
2
230.00 UG
2
500.00 T
1
500.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 UG
1
230.00 UG
1
230.00 T
2
230.00 T
2
230.00 SSP
1
230.00 T
1
230.00 T
2
230.00 T
2
230.00 T
2
230.00 T
1
230.00 H
1
230.00 T
1
230.00 WH
1
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
1 Middle Fork- Orangevale
2 Gold Hill Sub (SMUD)
3 Middle Fork - Pocket Sub
4 Gold Hill (SMUD)
5
6
7 Midway Kern PP #1
8 Midway Kern PP #2
9 Midway Kern PP #3
10 Midway Kern PP #4
11 Midway Vincent #3
12 Midway Wheeler Ridge
13 #1
14 #2
15 Midway-Kern #1 Stockdale Sub
16 #1
17
18
19 Midway -Kern #3 Stockdale Sub
20 #2
21 Midway-Wheeler Buena Vista
22 Ridge #1 & 2 Pump Plant
23 (State DWR)
24 Midway-Wheeler Wheeler Ridge
25 Ridge #1 & 2 Pump Plant
26 (State DWR)
27 Midway-Wheeler Wind Gap Pump
28 Ridge #1 & 2 (State DWR)
29 Monta Vista Jefferson
30 Moraga Newark
31
32
33
34
35
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 T
1
230.00 T
1
230.00 1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
500.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 SSP
1
230.00 T
1
230.00 T
2
230.00 T
2
230.00 T
2
230.00 T
2
230.00
T
230.00
T
230.00
230.00
230.00
230.00
T
T
T
T
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.5

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
1
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
2 Morro Bay PP Gates
3 Morro Bay PP Midway
4 Morro Bay PP Mesa
5 Morro Bay PP-MESA Diablo Cyn PP
6 Moss Landing PH Los Banos Sub
7 Moss Landing PH Panoche #1
8
9 Moss Landing PH Panoche #2
10 Moss Landing Moss Landing
11 230KV SW. 115KV SW.
12 Moss Landing Los Banos
13 Moss Landing Metcalf
14 Newark San Mateo
15
16 NCPA 1&2 Tap Line CR Collector Line
17 Panoche Kearney
18 Panoche-Kearney McMullin Sub
19 Panoche McCall
20 Panoche McCall
21 Pittsburg PP Moraga #1 & 2
22
23 Pittsburg PP Moraga #3
24
25
26 Pittsburg-Panoche Los Banos
27 Pittsburg PP Sobrante Sub
28 Pittsburg PP Tesla Sub
29 Pittsburg PP Newark
30
31
32
33
34
35
230.00
T
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 T
2
230.00 T
2
230.00 T
1
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
1
230.00
T
500.00 T
1
500.00 T
1
230.00 T
2
230.00 1
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
2
230.00 2
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.6

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
1 Pit # 1- Sierra Pacific
2 Cottonwood Industry
3 Pit # 1 PP Vac-Dixon
4
5
6 Pit # 1 PP Vac-Dixon
7
8 Pit # 1 PP Vac-Dixon
9
10
11
12
13
14
15
16
17
18
19 Pit # 4 PP Round Mtn.
20
21
22
23
24
25 Pit # 5 PP Mega Renewable-
26 able Sub
27 Pit # 5 PP Round Mtn.
28
29
30
31
32
33
34 Pit # 5 PP Round Mtn.
35
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 WH
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 SH
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 WH
1
230.00 T
1
230.00 WH
1
230.00 T
1
230.00 WH
1
230.00 WH
1
230.00 T
1
230.00 T
1
230.00 WH
1
230.00 T
1
230.00 T
1
230.00 WH
1
230.00 WH
1
230.00 WH
1
230.00 T
1
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.7

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
1 Pit # 5 PP Roaring Crk.
2 Round Mtn. Sub
3 Pit # 6 PP Pit # 6 Jct.
4
5 Pit # 7 PP Pit # 7 Jct.
6 Pit # 7 PP Pit # 7 Jct.
7 Pittsburg- Rossmoor Sub
8 Moraga #1
9 Pittsburg- Roosmoor Sub
10 Moraga #2
11 Pit-Vaca Dixon Sierra Pacific
12 Industry
13
14 Rancho Seco Bellota Sub
15 PP (SMUD)
16 Rancho Seco Stagg Sub
17 PP (SMUD) and
18 Tesla Sub
19 Rio Oso Bellota #1
20 and #2
21
22
23
24 Rio Oso Sub T. 10/44
25 (SMUD)
26 Rio Oso Sub Tesla Sub
27 Rio Oso-Tesla Eight Mile
28 T.77/323A Substation
29 Rock Creek PP Riso Oso #1
30 Rock Creek PP Riso Oso #2
31 Round Mountain Cottonwood
32
33 Round Mountain Table Mtn. #1
34
35 Round Mountain Table Mtn. #2
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 WH
1
230.00 T
1
230.00 WH
1
230.00 T
1
230.00 WH
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
2
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 LST
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 WH
1
500.00 T
1
500.00 T
1
500.00 T
1
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.8

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
1
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
2 San Mateo Sub Martin Sub
3 Stockdale Bakersfield
4 #1
5 Stockdale Bakersfield
6 #1
7 #2
8
9 Table Mtn. Rio Oso #1
10 Table Mtn. Rio Oso #2
11 Table Mtn. Tesla Sub
12 Tesla Sub
13 Table Mtn. Vaca-Dixon
14 Tesla Sub Lawrence Lab
15
16 Tesla Sub Los Banos Sub
17 #1
18 Los Banos Sub
19 #2
20 Tesla Sub Metcalf Sub
21 Tesla Midway #1
22
23 Tesla Midway #2
24
25
26 Tesla Parker (MID)
27
28
29
30 Tesla USBR Tracy
31 #1 & 2
32 Tesla Newark #1
33 Tesla Newark #2
34 Tiger Creek Bellota #1
35
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
500.00 T
1
230.00 UG
1
230.00 T
1
230.00 SSP
1
230.00 T
1
230.00 SSP
1
230.00 T
1
230.00 T
1
500.00 T
1
500.00 T
1
500.00 T
1
230.00 T
1
230.00 SSP
1
500.00 T
1
500.00 T
1
500.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
1
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.9

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
1
2
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
3 Tiger Creek Bellota #2
4
5 Tiger Creek Bellota #2
6
7 Tiger Creek Bellota #2
8 U.S. Windpower Contra Costa-
9 Sub Tesla #1
10 Vac Dixon Vac Dixon
11 Moraga Cir.#1 Moraga Cir. #1
12 Vac Dixon Moraga Sub
13 Moraga Cir.#2 Bus Structure
14 Vac Dixon Contra Costa
15 Sub #1
16
17
18
19
20 Vac Dixon Contra Costa
21 Power #2
22
23
24
25
26 Vac Dixon- Peabody Sub
27 Contra Costa
28 #1 and 2
29 Vac Dixon Lakeville
30
31 Vac Dixon Moraga #1
32
33
34
35 Vac Dixon Moraga #1
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
2
230.00 T
2
230.00 T
2
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
230.00 T
1
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.10

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
1
2
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
3 Vac Dixon Moraga #2
4
5
6
7 Vac Dixon Telsa
8
9 Walnut (TID) Los Banos
10
11
12
13 Newark Los Esteros
14 Los Esteros Metcalf
15 Newark Los Esteros
16 Los Esteros Metcalf
17 Cayetano Vineyard
18 Vineyard Newark
19 Contra Costa Cayetano
20 Cayetano Vineyard
21 North Dublin Substat North Dublin Trans
22 Jefferson Martin
23 Birds Landing Switch High Winds Sub
24 North Dublin Substation Cayetano
25 North Dublin Substation Vineyard
26 Shiloh II Birds Landing Sw Sta
27 Panoche Energy Center Panoche Sub
28
29
30
31
32
33
34
35
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
Number
Of
Circuits
230.00 T
2
230.00 T
1
230.00 T
1
230.00 T
1
500.00 T
1
500.00 T
1
230.00 T
2
230.00 T
2
230.00 T
1
230.00 T
1
230.00 P
2
230.00
P
230.00 UG Duct Bank
1
230.00 UG Duct Bank
1
230.00 UG Duct Bank
2
230.00 UG Duct Bank
2
230.00 UG Duct Bank
2
230.00 UG Duct Bank
2
230.00 T
2
230.00 P
2
230.00 P
1
230.00 UG Duct Bank
1
230.00 UG Duct Bank
1
230.00 P
1
230.00 P
1
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.11

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
(1) X An Original
Date of Report
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS
Year/Period of Report
End of 2010/Q4
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
1
2
3
4 Summary of Lines
5 listed individually
6
7 Other lines on tower
8
9
10
11 Other lines on poles
12
13
14
15
16 Other Underground
17 Transmission Lines
18
19
20
21 Transmission Roads
22 and Trails
23
24
25
26
27
28
29
30
31
32
33
34
35
DESIGNATION
VOLTAGE (KV)
(Indicate where
Type of
other than
60 cycle, 3 phase)
Supporting
From
To
Operating Designed Structure
(a) (b)
(c)
(d) (e)
LENGTH (Pole miles)
(In the case of
underground lines
report circuit miles)
On Structure On Structures
of Line of Another
Designated Line
(f)
(g)
500.00 1,327.63
230.00 3,187.80 2,226.68
115.00 1,956.13 1,162.58
70.00 37.88
20.81
60.00 162.29
72.91
230.00
115.00 2,982.30
28.62
70.00 1,534.79
15.04
60.00 3,723.93
54.96
230.00
115.00 83.69
60.00 4.40
70.00 0.44
Number
Of
Circuits
(h)
36 TOTAL 15,001.28 3,581.60 378
FERC FORM NO. 1 (ED. 12-87) Page 422.12

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
1
1113AAC 2
3
4
2300AL 5
2156SSAC 6
7
8
AL2300 9
10
795ACSR 11
954AL 12
795ACSR 13
954AL 14
795ACSR 15
16
17
795ACSR 18
500CU 19
650CU 20
795ACSR 21
1113AL 22
500CU 23
795ACSR 24
1113AL 25
954SSAC 26
954SSAC 27
954SSAC 28
954SSAC 29
795ACSR 30
1113AL 31
795ACSR 32
795ACSR 33
1113AL 34
954AL 35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
1113AL 1
1113AL 2
3
4
2300AL 5
1113AL 6
3500AL 7
2300AL 8
1113AL 9
10
2156SSAC 11
12
13
14
795ACSR 15
16
954ACSR 17
795ACSR 18
1113AL 19
20
1113AL 21
954ACSR 22
1113AL 23
1113AL 24
25
954ACSR 26
27
28
1113AL 29
1113AL 30
1113AL 31
954ACSR 32
2300AL 33
954ACSR 34
1113AL 35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
954ACSR 1
954ACSR 2
954ACSR 3
954ACSR 4
954ACSR 5
1113AL 6
2300AL 7
1113AL 8
2300AL 9
2300AL 10
2300AL 11
2300AL 12
1113AL 13
1113AL 14
1113AL 15
1113AL 16
1113AL 17
795ACSR 18
1113AL 19
795ACSR 20
795ACSR 21
795ACSR 22
1113AL 23
24
25
1431AL 26
27
1113AL 28
1113AL 29
30
1113AL 31
32
1113AL 33
34
1113AL 35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
1
1113AL 2
3
4
5
6
1431AL 7
3500AL 8
9
10
11
1113AL 12
1113AL 13
1113AL 14
15
16
17
1113AL 18
19
20
21
1113AL 22
794ACSR 23
1113AL 24
25
1250 OFPA 26
Pipe type 27
28
1113AL 29
1113AL 30
1271ACSR 31
32
33
1250 OFP 34
Pipe type 35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
795ACSR 1
1113AL 2
3
1113AL 4
5
1113AL 6
7
8
1113AL 9
1852ACSR 10
3500AL 11
2300AL 12
1113AL 13
1113AL 14
1113AL 15
16
2500HPCU 17
18
19
2500CU 20
21
2500CU 22
23
1113AL 24
1113AL 25
1113AL 26
2300AL 27
795ACSR 28
795ACSR 29
1113AL 30
795ACSR 31
795ACSR 32
1113AL 33
1113AL 34
35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
1
1113AL 2
3
1113AL 4
1113AL 5
6
795ACSR 7
795ACSR 8
1113AL 9
1113AL 10
2300AL 11
12
1113AL 13
1113AL 14
15
795ACSR 16
1113AL 17
1113AL 18
19
1113AL 20
21
22
1113AL 23
24
25
1113AL 26
27
1113AL 28
1113AL 29
954ACSR 30
954ACSR 31
1113AL 32
954ACSR 33
795ACSR 34
1113AL 35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.5

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
1113AL 1
1113AL 2
1113AL 3
1113AL 4
1113AL 5
2300AL 6
795ACSR 7
2300AL 8
795ACSR 9
10
2300AL 11
2300AL 12
2300AL 13
1113AL 14
1113AL 15
1113AL 16
1113AL 17
1113AL 18
795ACSR 19
1113AL 20
954ACSR 21
954AL 22
954AL 23
954ACSR 24
1113AL 25
1113AL 26
954AL 27
2300AL 28
954AL 29
1113AL 30
1113AL 31
954AL 32
795ACSR 33
1113AL 34
35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.6

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
1
795ACSR 2
1113AL 3
954ACSR 4
5
954AL 6
795ACSR 7
795ACSR 8
643.7CU 9
518ACSR 10
11
954ACSR 12
954AL 13
795ACSR 14
643.7CU 15
518ACSR 16
518ACSR 17
500CU 18
795ACSR 19
795ACSR 20
380.5CU 21
380.5CU 22
518ACSR 23
1113AL 24
25
518ACSR 26
795ACSR 27
795ACSR 28
380.5CU 29
380.5CU 30
380.5CU 31
380.5CU 32
1113AL 33
1113AL 34
1113AL 35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.7

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
1
1113AL 2
1113AL 3
1113AL 4
795ACSR 5
795ACSR 6
7
795ACSR 8
9
1113AL 10
11
715.5ACS 12
13
14
2300AL 15
954AL 16
1113AL 17
1113AL 18
795ACSR 19
1113AL 20
1113AL 21
1113AL 22
795ACSR 23
1113AL 24
1113AL 25
1113AL 26
1113 27
28
795ACSR 29
795ACSR 30
795ACSR 31
795ACSR 32
1825ACSR 33
2300AL 34
1825ACSR 35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.8

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
2300AL 1
2500HPCU 2
1113AL 4
5
1113AL 6
1113AL 7
1113AL 8
1113AL 9
1113AL 10
2300AL 11
1852ACSR 12
13
2300AL 14
1113AL 15
16
2300AL 17
18
2300AL 19
2300AL 20
1113AL 21
795ACSR 22
1113AL 23
795ACSR 24
795ACSR 25
795ACSR 26
795ACSR 27
954AL 28
954AL 29
30
954ACSR 31
2300AL 32
2300AL 33
518ACSR 34
795ACSR 35
Line
No.
3
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.9

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
500CU 1
643.7CU 2
518ACSR 3
518ACSR 4
1113AL 5
500CU 6
643.7CU 7
8
1113AC 9
10
1113AL 11
12
1113AL 13
14
500CU 15
643.7CU 16
795ACSR 17
954ACSR 18
1113SSAC 19
20
643.7CU 21
795ACSR 22
954ACSR 23
1113SSAC 24
25
26
27
1113AL 28
1113AL 29
954ACSR 30
1113AL 31
1113AL 32
954ACSR 33
954AL 34
Other 35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.10

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
1
2
1113AL 3
954ACSR 4
954AL 5
Other 6
1855ACSR 7
2300AL 8
795ACSR 9
1113AL 10
954AL 11
954AL 12
2-2300 A 13
2-2300 A 14
2-2500 k 15
2-2500 k 16
2000 kcm 17
2000 kcm 18
1000 sq. 19
1000 sq. 20
954ACSR 21
954ACSR 22
1113AL 23
2000 kcm 24
2000 kcm 25
1431 AAC 26
2-1113 AAC 27
28
29
30
31
32
33
34
35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.11

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINE STATISTICS (Continued)
Year/Period of Report
End of 2010/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material
Land Construction and Total Cost Operation Maintenance Rents Total
Other Costs
Expenses Expenses
Expenses
(i) (j) (k) (l) (m) (n) (o) (p)
1
2
3
22,102,656 298,423,003 320,525,659 3,310,995 2,994,074
6,305,069 4
58,008,773 973,768,102 1,031,776,875 8,812,300 7,968,808
16,781,108 5
6
28,522,335 262,987,182 291,509,517 7,629,295 6,899,037
14,528,332 7
1,279,591 7,346,180 8,625,771
343,034 310,200
653,234 8
4,177,337 28,233,702 32,411,039
467,025 422,322
889,347 9
10
11
32,722,892 219,989,473 252,712,365 5,804,915 5,249,282
11,054,197 12
7,891,105 81,074,861 88,965,966 3,554,507 3,214,278
6,768,785 13
22,009,259 293,431,748 315,441,007 9,401,992 8,502,056
17,904,048 14
15
16
93,205 332,455,810 332,549,015 3,291,607 621,322
3,912,929 17
13,689,518 13,689,518
167,846 31,682
199,528 18
19
20
42,958,660 42,958,660
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Line
No.
176,807,153 2,554,358,239 2,731,165,392 42,783,516 36,213,061 78,996,577 36
FERC FORM NO. 1 (ED. 12-87) Page 423.12

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 422 Line No.: 1 Column: e
The designations for the type of supporting structure in this column are defined as
follows:
SSP - Single Steel Poles
SWP - Single Wood Poles
WH - Wood "H" Structures
T - Steel Towers
UG - Underground
Schedule Page: 422 Line No.: 1 Column: f
The data for this column is not available on a circuit-by-circuit basis as the Utility's
Geographic Information System is in the process of compiling the necessary data at this
time.
Schedule Page: 422 Line No.: 1 Column: g
The data for this column is not available on a circuit-by-circuit basis as the Utility's
Geographic Information System is in the process of compiling the necessary data at this
time.
Schedule Page: 422 Line No.: 5 Column: i
Bundled.
Schedule Page: 422 Line No.: 9 Column: i
Bundled.
Schedule Page: 422 Line No.: 22 Column: i
Bundled.
Schedule Page: 422.1 Line No.: 5 Column: i
Bundled.
Schedule Page: 422.1 Line No.: 6 Column: i
Bundled.
Schedule Page: 422.1 Line No.: 7 Column: i
Bundled.
Schedule Page: 422.1 Line No.: 8 Column: i
Bundled.
Schedule Page: 422.1 Line No.: 9 Column: i
Bundled.
Schedule Page: 422.3 Line No.: 29 Column: i
Bundled.
Schedule Page: 422.3 Line No.: 30 Column: i
Bundled.
Schedule Page: 422.3 Line No.: 31 Column: i
Bundled.
Schedule Page: 422.3 Line No.: 34 Column: i
Oil Filled.
Schedule Page: 422.3 Line No.: 35 Column: i
AL cable.
Schedule Page: 422.4 Line No.: 6 Column: f
Idle.
Schedule Page: 422.4 Line No.: 20 Column: i
Bundled.
Schedule Page: 422.5 Line No.: 2 Column: f
For 6.53 miles, the #2 position on these towers is occupied by the Sacramento Municipal
Utilities District's ("SMUD") White Rock-Elverta 230 kV line. SMUD purchased a half
interest in these towers.
Schedule Page: 422.5 Line No.: 4 Column: g
Property of SMUD (excluded from total length on last page of 422).
Schedule Page: 422.6 Line No.: 1 Column: i
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Bundled.
Schedule Page: 422.6 Line No.: 34 Column: i
Bundled.
Schedule Page: 422.8 Line No.: 16 Column: g
Poles are jointly owned by Modesto Irrigation District ("MID") and Turlock Irrigation
District ("TID"), while the conductor is property of TID (excluded from total length on
last page of 422).
Schedule Page: 422.8 Line No.: 26 Column: g
For 15.84 miles, the #2 position of these towers is occupied by SMUD's White Rock-Pocket
230kV line. SMUD purchased a half interest in these towers.
Schedule Page: 422.9 Line No.: 2 Column: i
Gas filled.
Schedule Page: 422.9 Line No.: 4 Column: i
Pipe type cable.
Schedule Page: 422.9 Line No.: 28 Column: g
Poles are jointly owned by MID and TID, while the conductor is property of MID (excluded
from total length on last page of 422).
Schedule Page: 422.9 Line No.: 29 Column: g
Property of MID (excluded from total length on last page of 422).
Schedule Page: 422.9 Line No.: 32 Column: i
Bundled.
Schedule Page: 422.9 Line No.: 33 Column: i
Bundled.
Schedule Page: 422.11 Line No.: 12 Column: g
Poles are jointly owned by MID and TID while the conductor is property of TID (excluded
from total length on last page of 422).
Schedule Page: 422.12 Line No.: 11 Column: a
Mileage, plant cost, and expenses for these lines are included in Line 4 above.
Schedule Page: 422.12 Line No.: 16 Column: a
Mileage, plant cost, and expenses for these lines are included in Line 4 above.
Schedule Page: 422.12 Line No.: 19 Column: k
Cost and expenses are already included in above lines.
Schedule Page: 422.12 Line No.: 21 Column: a
Includes roads and trails for all poles and tower lines.
FERC FORM NO. 1 (ED. 12-87) Page 450.2

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
TRANSMISSION LINES ADDED DURING YEAR
1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
Line
LINE DESIGNATION
Line SUPPORTING STRUCTURE CIRCUITS PER STRUCTURE
Length
Average
No.
From
To
in
Type
Number per Present Ultimate
Miles
Miles
(a) (b)
(c)
(d) (e)
(f)
(g)
1 UNDERGROUND
2 "(CX-3)" Order No. 30604166
3 Oakland C" Oakland "X" 3.70 PVC Duct 1 1
4
5 OVERHEAD
6 Pit#3-Carberry (TWR Carberry Switching yard 0.04 H-FrameTSP 1.00
1 1
7 Job No. 30642981
8
9 Carberry Switching yard Pit#3-Carberry (TWR 16/128) 0.04 H-FrameTSP 1.00
1 1
10 Job No. 30642981
11
12 Lerdo-Kern Oil-7th Standard 7th Standard Substation 2.29 Hybrid Concre/ 9.60
2 2
13 pole 21/4
14
15 Cottonwood-Delevan #1 Cottonwood-Delevan #1
Steel Poles
0.60 Steel Tower 10.05
1 1
16 Tower 70/478A Delevan Sub
17 Job No. 30580298
18
19 Logan Creek-Delevan Logan Creek-Delevan 0.60 Steel Tower 11.17
1 1
20 Tower 70/478A Delevan Sub
21 Job No. 30580298
22
23 Cottonwood-Delevan #2 Cottonwood-Delevan #2 0.54 Steel Tower 11.17
1 1
24 Tower 130/1022A Delevan Sub
25 Job No. 30580298
26
27 Glenn-Delevan Glenn-Delevan 0.54 Steel Tower 11.17
1 1
28 Tower 130/1022A Delevan Sub
29 Job No. 30580298
30
31 Delevan-Cortina Delevan-Cortina 0.34 Steel Tower 11.90
1 1
32 Delevan Sub Tower 71/479
33 Job No. 30580298
34
35 Delevan-Vaca #1 Delevan-Vaca #1 0.34 Steel Tower 11.90
1 1
36 Delevan Sub Tower 71/479
37 Job No. 30580298
38
39 Delevan-Vaca #2 Delevan-Vaca #2 0.35 Steel Tower 11.32
1 1
40 Delevan Sub Tower 130/1023
41 Job No. 30580298
42
43
44 TOTAL
157.97 328.51 48 48
FERC FORM NO. 1 (REV. 12-03) Page 424

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINES ADDED DURING YEAR
LINE DESIGNATION
Line SUPPORTING STRUCTURE
Length
Average
From
To
in
Type
Number per
Miles
Miles
(a) (b)
(c)
(d) (e)
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
CIRCUITS PER STRUCTURE
Present Ultimate
1 Delevan-Vaca #3 Delevan-Vaca #3 0.35 Steel Tower 11.32
1 1
2 Delevan Sub Tower 130/1023
3 Job No. 30580298
4
5 Gill Ranch Tap 9.30 Wood 16.00
1 1
6 Job Number 30694383
7
8 Henrietta Tulare Lake 6.00 LDS 16.00
1 1
9 Job Number 30764872 Phase 1
10
11 Sanger California #2 9.30 LDS 17.00
1 1
12 Job Number 30731005 &
13
14 Border - Glass Biola 5.00 Wood 17.00
1 1
15 Job Number 30545566
16
17 Rio Bravo Kern Oil 0.50 Wood 16.00
1 1
18 Job Number 30578966
19
20 Plainfield Jct. Pole 26/362 Plainfield Substation 2.80 Wood poles/TSP 13.00
2 2
21 Job No. 30587270
22
23 RECONDUCTOR:
24 UNDERGROUND
25 AWH-1 Order No. 30604453
26 Potrero Substation Bayshore Substation 1.60 Pipe 1 1
27 Martin Substation Bayshore Substation
28
29 AWH-2 Order No. 30604454
30 Potrero Substation Bayshore Substation 1.59 Pipe 1 1
31 Martin Substation Bayshore Substation 3.46 Pipe 1 1
32
33 OVERHEAD
34 Horseshoe Substation Gold Hill Substation 8.50 Steel Towers 6.00
2 2
35 Job No. 30633190
36
37 Fairway Taps Fairway Substation 1.57 TSPs 10.00
2 2
38
39 Schulte Substation Lammers Substation 0.69 TSPs 7.27
1 1
40
41 Carbona #1 Tap Carbona #1 Tap 4.53 Steel Towers, 7.94
1 1
42 WP 0/1 Kasson Sub
Wood Poles,
43 Job No. 30755609
&TSP
(f)
(g)
44 TOTAL
157.97 328.51 48 48
FERC FORM NO. 1 (REV. 12-03) Page 424.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
Line
No.
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINES ADDED DURING YEAR
LINE DESIGNATION
Line SUPPORTING STRUCTURE
Length
Average
From
To
in
Type
Number per
Miles
Miles
(a) (b)
(c)
(d) (e)
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
CIRCUITS PER STRUCTURE
Present Ultimate
1 Moss Moss Landing-Salinas-Soledd 2.40 Steel Towers 4.60
2 2
2 Tower 7/40 Tower 10/51
3 Job No. 30603838
4
5 Vaca Dixon Substation Peabody Substation 9.90 Steel Towers 6.00
2 2
6 Job No. 30603884
7
8 Peabody Substation Birds Landing Switching Stn 19.80 Steel Towers 6.00
2 2
9 Job No. 30603884
10
11 Vaca Dixon Substation Lambie Switching Station 14.00 Steel Towers 6.10
2 2
12 Job No. 30603884
13
14 Lambie Switching Station Birds Landing Switching Stn 7.00 Steel Towers 6.60
2 2
15 Job No. 30603884
16
17 Gold Hill Substation Clarksville Substation 6.00 Towers / TSP / 8.20
2 2
18 Job No. 30604172
19
Light Duty St
20 West Sacramento Substation Brighton Substation 14.00 Towers / TSP / 7.20
2 2
21 Job No. 30604290
22
Lattice Steele
23 Burney Substation Bus Str Hat Creek #2 PH pole 0/0 9.00 Wood Pole 21.00
1 1
24 Job No. 30614499
25
26 Paradise-Butt pole 13/0 paradise Butt pole 15/0 2.00 LDS poles 12.00
1 1
27 Job No. 30704135
28
29 REMOVALS
30 Allison-Davis (Start at 50/44A End at Tower 63/111 6.50 Steel Towers 10.00
2 2
31 Job No. 30737897 (from tower
32 63/111 to tower 63/106)
33 Job No. 30761064 (from 63/106 to 62/97, tower 63/
34 105 and 62/100 to remain)
35 Job No. 30761065 (from tower 62/96 to 50/40B, tower
36 59/57, 60/71 and 61/89 to remain)
37
38 Plainfield Jct. Pole 26/362 Plainfield Substation 2.80 Wood poles 13.00
1 1
39 Job No. 30587270
40
41
42
43
(f)
(g)
44 TOTAL
157.97 328.51 48 48
FERC FORM NO. 1 (REV. 12-03) Page 424.2

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
CONDUCTORS
Voltage
LINE COST
Line
Size Specification Configuration KV Land and Poles, Towers Conductors Asset
Total No.
and Spacing (Operating) Land Rights and Fixtures and Devices Retire. Costs
(h) (i)
(j)
(k)
(l) (m)
(n)
(o)
(p)
1
2
2500 Cu XLPE
115 41,011,417 21,601,433 62,612,850 3
795 ACSR
230 578,680
578,680 6
795 ACSR
230 578,680
578,680 9
1113 AA
V-10
115 1,765,816 842,842 2,608,658 12
954 ACSR
V-15'
230 1,470,253 1,470,253 15
954 ACSR
V-15'
230 1,470,253 1,470,253 19
954 ACSR
V-15'
230 1,323,228 1,323,228 23
954 ACSR
V-15'
230 1,323,228 1,323,228 27
954 ACSR
V-15'
230 833,144 833,144 31
954 ACSR
V-15'
230 833,144 833,144 35
954 ACSR
V-15'
230 857,648 857,648 39
4
5
7
8
10
11
13
14
16
17
18
20
21
22
24
25
26
28
29
30
32
33
34
36
37
38
40
41
42
43
992,416 65,700,725 136,532,731 -2,335,586 200,890,286
44
FERC FORM NO. 1 (REV. 12-03) Page 425

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINES ADDED DURING YEAR (Continued)
Year/Period of Report
End of 2010/Q4
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
CONDUCTORS
Voltage
LINE COST
Line
Size Specification Configuration KV Land and Poles, Towers Conductors Asset
Total No.
and Spacing (Operating) Land Rights and Fixtures and Devices Retire. Costs
(h) (i)
(j)
(k)
(l) (m)
(n)
(o)
(p)
954 ACSR
V-15'
230 857,648 857,648 1
715 AAC
T-1
115 5
1113 AAC
T-1
70 765,675 1,673,434 2,439,109 8
11113 AAC
T-1
115 2,441,433 2,783,363 5,224,796 11
715 AAC
TH
70 1,791,694 1,536,580 3,328,274 14
397A AAC
T-1
115 132,681 241,797 374,478 17
715 Aluminm
DC Post
60 1,826,224 1,180,751 3,006,975 20
2000 kcmil HPGF LP
115 10,845,284 10,845,284 26
2000 kcmil HPGF LP
115 22,571,746 22,571,746 27
2000 kcmil HPGF LP
115 11,467,373 11,467,373 30
2000 kcmil HPGF LP
115 24,954,157 24,954,157 31
477 ACSS
V-10
115 5,233,069 5,233,069 34
715.5 AA
V-10
115 726,520 2,366,850 446,614 3,539,984 37
954 ACSS
Delta-12
115 119,769
359,306 598,843 1,077,918 39
715 AAC
V-9
60 1,420,257
1,420,257 41
2
3
4
6
7
9
10
12
13
15
16
18
19
21
22
23
24
25
28
29
32
33
35
36
38
40
42
43
992,416 65,700,725 136,532,731 -2,335,586 200,890,286
44
FERC FORM NO. 1 (REV. 12-03) Page 425.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report Is:
Date of Report
(1) X An Original
(Mo, Da, Yr)
(2) A Resubmission
04/08/2011
TRANSMISSION LINES ADDED DURING YEAR (Continued)
Year/Period of Report
End of 2010/Q4
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
CONDUCTORS
Voltage
LINE COST
Line
Size Specification Configuration KV Land and Poles, Towers Conductors Asset
Total No.
and Spacing (Operating) Land Rights and Fixtures and Devices Retire. Costs
(h) (i)
(j)
(k)
(l) (m)
(n)
(o)
(p)
477 ACSS
V-10'
115 146,127
699,634 1,054,283 1,900,044 1
1113 ACSS
V-15
230 1,284,012 2,996,027 4,280,039 5
1113 ACSS
V-15
230 2,568,023 5,992,054 8,560,077 8
1113 ACSS
V-15
230 1,815,774 4,236,806 6,052,580 11
1113 ACSS
V-15
230 907,887 2,118,403 3,026,290 14
477 ACSS
V-10
115 1,350,760 4,073,564 5,424,324 17
477 ACSS
V-10
115 1,158,389 149,909 1,308,298 20
397 Aluminm
T1
60 347,174 417,956 765,130 23
715 Aluminm
T1, 3PS
115 530,359 547,897 1,078,256 26
2/0 Copper
115 -2,250,469 -2,250,469 30
4/0 Aluminm
T1
60 -85,117
-85,117 38
2
3
4
6
7
9
10
12
13
15
16
18
19
21
22
24
25
27
28
29
31
32
33
34
35
36
37
39
40
41
42
43
992,416 65,700,725 136,532,731 -2,335,586 200,890,286
44
FERC FORM NO. 1 (REV. 12-03) Page 425.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
AIRWAYS SUB, Fresno, Ca. Distribution
115.00 12.00 7.20
ALHAMBRA SUB, Martinez Distribution
115.00 12.00 7.20
ALMADEN SUB, San Jose Distribution
60.00 12.00 7.20
ALPAUGH SUB, Tulare Distribution
115.00 12.00
ALTO SUB, Mill Valley Distribution
60.00 12.00 2.40
AMES DISTRIBUTION SUB, Mountain View Distribution
115.00 12.00 7.20
ANDERSON SUB, Anderson Distribution
60.00 12.00 2.40
ANGIOLA SUB, Kings Distribution
70.00 12.00 7.20
ANTELOPE SUB, Blackwell Corner Distribution
70.00 12.00 2.40
ANTLER SUB, Lakehead Distribution
60.00 12.00 2.40
APPLE HILL SUB, Camino Distribution
115.00 12.00 7.20
APPLE HILL SUB, Camino Distribution
115.00 21.00 7.20
ARBUCKLE SUB, ARBUCKLE Distribution
60.00 12.00 7.20
ARCATA SUB, Arcata Distribution
60.00 12.00 7.20
ARVIN SUB, Arvin Distribution
70.00 12.00 2.40
ASHLAN AVENUE SUB, Fresno Distribution
230.00 12.00 7.20
ATASCADERO SUB, Atascadero Distribution
115.00 12.00 7.20
ATWATER SUB, Atwater Distribution
115.00 12.00 7.20
AUBERRY SUB, Auberry Distribution
70.00 12.00 7.20
AVENA SUB, Escalon Distribution
115.00 12.00
AVENAL SUB, Avenal Distribution
70.00 12.00
BAHIA SUB, Benicia Distribution
230.00 12.00 7.20
BAIR SUB, Redwood City Transmission
115.00 12.00 7.20
BAKERSFIELD SUB, Bakersfield Distribution
230.00 21.00 7.20
BANGOR SUB, Bangor Distribution
60.00 12.00 7.20
BARTON SUB, Fresno Distribution
115.00 12.00 7.20
BASALT SUB, Napa Distribution
60.00 12.00
BAY MEADOWS SUB, San Mateo Distribution
115.00 21.00 7.20
BAY MEADOWS SUB, San Mateo Distribution
115.00 12.00 7.20
BEAR VALLEY SUB, Bear Valley Distribution
70.00 21.00 7.20
BELL SUB, Auburn Distribution
115.00 12.00 7.20
BELLE HAVEN SUB, Menlo Park Distribution
60.00 12.00
BELLE HAVEN SUB, Menlo Park Distribution
60.00 4.00 2.40
BELLEVUE SUB, Santa Rosa Distribution
115.00 12.00 7.20
BELMONT SUB, Belmont Distribution
115.00 12.00 7.20
BERESFORD SUB, San Mateo Distribution
60.00 4.00
BERRENDA A SUB, Distribution
70.00 12.00 2.40
BIG BASIN SUB, Santa Cruz Distribution
60.00 12.00
BIG MEADOWS SUB, Greenville Distribution
60.00 44.00 2.40
BIOLA SUB, Biola Distribution
70.00 12.00 2.40
FERC FORM NO. 1 (ED. 12-96) Page 426

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
BLACKWELL SUB, Blackwell Corner Distribution
70.00 12.00 2.40
BLUE LAKE SUB, Blue Lake Distribution
60.00 12.00 2.40
BOGUE SUB, Yuba City Distribution
115.00 12.00 7.20
BOLINAS SUB, Boninas Distribution
60.00 12.00 7.20
BONITA SUB, Madera Distribution
70.00 12.00 7.20
BORDEN SUB, Madera Transmission
230.00 12.00 7.20
BOWLES SUB, Bowles Distribution
70.00 12.00 2.40
BRENTWOOD SUB, Brentwood Distribution
230.00 21.00 7.20
BRITTON SUB, Sunnyvale Distribution
115.00 12.00 7.20
BRUNSWICK SUB, Grass Valley Distribution
115.00 12.00 7.20
BUELLTON SUB, Buellton /93427 Distribution
115.00 12.00 7.20
BUENA VISTA SUB, Salinas Distribution
60.00 12.00 7.20
BULLARD SUB, Fresno Distribution
115.00 12.00 7.20
BULLARD SUB, Fresno Distribution
115.00 21.00 7.20
BURLINGAME SUB, Burlingame Distribution
115.00 21.00 7.20
BUTTE SUB, Chico Transmission
115.00 12.00 7.20
CABRILLO SUB, LOMPOC Distribution
115.00 12.00 7.20
CADET SUB, Maricopa Distribution
70.00 12.00
CAL WATER SUB, Distribution
115.00 12.00 7.20
CALAVERAS CEMENT SUB, San Andreas Distribution
60.00 12.00 7.20
CALFLAX SUB, Huron Distribution
70.00 12.00 2.40
CALIFORNIA AVE SUB, Fresno Distribution
115.00 12.00 7.20
CALISTOGA SUB, Calistoga Distribution
60.00 12.00 7.20
CALPELLA SUB, Calpella Distribution
115.00 12.00 7.20
CAMDEN SUB, Riverdale Distribution
70.00 12.00
CAMP EVERS SUB, Santa Cruz Distribution
115.00 21.00 7.20
CAMPHORA SUB, Monterey Distribution
60.00 12.00 7.20
CAMPHORA SUB, Monterey Distribution
60.00 4.00
CANAL SUB, Los Banos Distribution
70.00 12.00 7.20
CANTUA SUB, Cantua Creek Distribution
115.00 12.00
CAPAY SUB, Orland Distribution
60.00 12.00 2.40
CARBONA SUB, Tracy Distribution
60.00 12.00 7.20
CARNATION SUB, Bakersfield Distribution
70.00 21.00 7.20
CARNERAS SUB, Blackwells Corner Distribution
70.00 12.00 7.20
CAROLANDS SUB, Hillsborough Distribution
60.00 4.00
CARQUINEZ SUB, Vallejo Distribution
115.00 12.00 2.40
CARUTHERS SUB, Fresno Distribution
70.00 12.00 2.40
CASSIDY SUB, Madera Distribution
70.00 12.00 2.40
CASTRO VALLEY SUB, Castro Valley Distribution
230.00 12.00
CASTROVILLE SUB, Castroville Distribution
115.00 21.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
CAWELO B SUB, Famosa Distribution
70.00 4.00
CAYETANO SUB, Danville Distribution
230.00 21.00 7.20
CAYUCOS SUB, Cayucos Distribution
70.00 12.00 7.20
CHANNEL SUB, Stockton Distribution
60.00 12.00
CHARCA SUB, Wasco Distribution
115.00 12.00 7.20
CHENEY SUB, Mendota Distribution
115.00 12.00 7.20
CHEROKEE SUB, Stockton Distribution
60.00 12.00 7.20
CHICO A SUB, Chico Distribution
60.00 12.00 7.20
CHICO B SUB, Chico Distribution
115.00 12.00 7.20
CHOLAME SUB, Cholame/93431 Distribution
70.00 12.00 2.40
CHOLAME SUB, Cholame/93431 Distribution
70.00 21.00 2.40
CHOWCHILLA SUB, Chowchilla Distribution
115.00 12.00 7.20
CLARK ROAD SUB, Paradise Distribution
60.00 12.00 2.40
CLARKSVILLE SUB, Clarksville Distribution
115.00 21.00 7.20
CLAY SUB, Ione Distribution
60.00 12.00
CLAYTON SUB, Concord Distribution
115.00 21.00 7.20
CLAYTON SUB, Concord Distribution
115.00 12.00 7.20
CLEAR LAKE SUB, Finley Distribution
60.00 12.00 2.40
CLOVERDALE SUB, Cloverdale Distribution
115.00 12.00 7.20
CLOVIS SUB, Clovis Distribution
115.00 12.00 7.20
CLOVIS SUB, Clovis Distribution
115.00 21.00 7.20
COALINGA #1 SUB, Coalinga Distribution
70.00 12.00 7.20
COALINGA #2 SUB, Coalinga Distribution
70.00 12.00 2.40
COARSEGOLD SUB, Coursegold Distribution
115.00 21.00 7.20
COLUMBUS SUB, Bakersfield Distribution
115.00 12.00 7.20
COLUSA JUNCT SUB, Colusa Distribution
60.00 12.00 7.20
COLUSA SUB, Colusa Distribution
60.00 12.00
CONTRA COSTA SUBSTATION, Antioch Transmission
230.00 21.00 7.20
CONTRA COSTA SUBSTATION, Antioch Transmission
115.00 21.00 6.60
COPPERMINE SUB, Clovis Distribution
70.00 12.00 2.40
COPUS SUB, Bakersfield Distribution
70.00 12.00
CORCORAN SUB, Corcoran Transmission
115.00 12.00 7.20
CORDELIA SUB, Cordelia Distribution
115.00 12.00 7.20
CORDELIA SUB, Cordelia Distribution
60.00 12.00 2.40
CORNING SUB, Corning Distribution
60.00 12.00 2.40
CORONA SUB, Distribution
115.00 12.00 7.20
CORRAL SUB, Bellota Distribution
60.00 12.00 7.20
CORTINA SUB, Williams Transmission
115.00 12.00 7.20
COTATI SUB, Cotati Distribution
60.00 12.00
COTTLE SUB, Oakdale Distribution
230.00 17.00
FERC FORM NO. 1 (ED. 12-96) Page 426.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
COTTONWOOD SUB, Cottonwood Transmission
115.00 12.00 7.20
COUNTRY CLUB SUB, Stockton Distribution
60.00 12.00
COUNTRY CLUB SUB, Stockton Distribution
60.00 4.00
CRESSEY SUB, Merced Distribution
115.00 21.00
CURTIS SUB, Sonora Distribution
115.00 18.00
CUYAMA SUB, Cuyama Distribution
70.00 12.00
CUYAMA SUB, Cuyama Distribution
70.00 21.00 7.20
CYMRIC SUB, McKitrick Distribution
115.00 12.00 7.20
DAIRYLAND SUB, Chowchilla Distribution
115.00 12.00 7.20
DALY CITY SUB, Daly City Distribution
115.00 12.00
DAVIS SUB, Davis Distribution
115.00 12.00 7.20
DEEPWATER SUB, W. Sactramento Distribution
115.00 12.00 7.20
DEL MAR SUB, Rocklin Distribution
60.00 21.00 7.20
DEL MAR SUB, Rocklin Distribution
60.00 12.00 7.20
DEL MONTE SUB, Monterey Transmission
115.00 21.00 7.20
DERRICK SUB, Kettleman Distribution
70.00 12.00 2.40
DESCHUTES SUB, Palo Cedro Distribution
60.00 12.00 7.20
DIAMOND SPRINGS SUB, Placerville Distribution
115.00 12.00 7.20
DINUBA SUB, Dinuba Distribution
70.00 12.00
DIVIDE SUB, Orcutt Transmission
70.00 12.00 2.40
DIXON LANDING SUB, Distribution
115.00 21.00 7.20
DIXON SUB, Dixon Distribution
60.00 12.00
DOLAN ROAD SUB, Moss Landing Distribution
115.00 12.00
DOS PALOS SUB, Dos Palos Distribution
70.00 12.00 7.20
DUMBARTON SUB, Fremont Distribution
115.00 12.00
DUNBAR SUB, Glen Ellen Distribution
60.00 12.00
EAST GRAND SUB, So San Fran. Distribution
115.00 12.00 7.20
EAST MARYSVILLE SUB, Marysville, Distribution
115.00 12.00 7.20
EAST NICOLAUS SUB, E. Nicolaus Transmission
60.00 12.00
EAST STOCKTON SUB, Stockton Distribution
60.00 12.00 7.20
EAST STOCKTON SUB, Stockton Distribution
60.00 4.00
EDENVALE SUB, San Jose Distribution
115.00 21.00 7.20
EDENVALE SUB, San Jose Distribution
115.00 12.00 7.20
EDES SUB, Oakland Distribution
115.00 12.00 7.20
EIGHT MILE SUB, Stockton Distribution
230.00 21.00 7.20
EL CAPITAN SUB, Snelling Distribution
115.00 12.00
EL CAPITAN SUB, Snelling Distribution
115.00 21.00
EL CERRITO G SUB, El Cerrito Distribution
115.00 12.00 2.40
EL NIDO SUB, Merced Distribution
115.00 12.00 7.20
EL PATIO SUB, Campbell Distribution
115.00 12.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
EL PECO SUB, Madera Distribution
70.00 12.00
ELECTRA SUB, Distribution
60.00 12.00
ELK HILLS SUB, Valley Acres Distribution
70.00 12.00
ELK SUB, Elk Distribution
60.00 12.00 2.40
EUREKA A SUB, Eureka Distribution
60.00 12.00 7.20
EUREKA E SUB, Eureka Distribution
60.00 12.00 2.40
EVERGREEN SUB, San Jose Transmission
115.00 21.00 7.20
FAIRHAVEN SUB, Fairhaven Distribution
60.00 12.00 7.20
FAIRVIEW SUB, Martinez Distribution
115.00 21.00 12.00
FAIRWAY SUB, Santa Maria Distribution
115.00 12.00 7.20
FAMOSO SUB, Famosa Distribution
115.00 12.00
FELLOWS SUB, Fellows Distribution
115.00 21.00
FIGARDEN SUB, Fresno Distribution
230.00 21.00 7.20
FIREBAUGH SUB, Firebaugh Distribution
70.00 12.00 7.20
FITCH MOUNTAIN SUB, Healdsburg Distribution
60.00 12.00 7.20
FLINT SUB, Auburn Distribution
115.00 12.00 7.20
FMC SUB, San Jose Distribution
115.00 12.00 7.20
FOOTHILL SUB, SLO Distribution
115.00 12.00 2.40
FORESTHILL SUB, Foresthill, Distribution
60.00 12.00 7.20
FORT BRAGG A SUB, Fort Bragg Distribution
60.00 12.00 13.80
FORT ORD SUB, Fort Ord Distribution
60.00 12.00 2.40
FRANKLIN SUB, Hercules Distribution
60.00 12.00 7.20
FREMONT SUB, Fremont Distribution
115.00 12.00 7.20
FRENCH CAMP SUB, Stockton Distribution
60.00 12.00
FROGTOWN SUB, Angels Camp Distribution
115.00 17.00
FRUITVALE SUB, Bakersfield Distribution
70.00 12.00 2.40
FULTON SUB, Fulton Transmission
230.00 12.00 7.20
GABILAN SUB, Salinas Distribution
115.00 12.00 7.20
GALLO SUB, Livingston Distribution
115.00 12.00
GANSNER SUB, Quincy Distribution
60.00 12.00 7.20
GANSO SUB, Buttonwillow Distribution
115.00 12.00 7.20
GARBERVILLE SUB, Garberville Distribution
60.00 12.00 7.20
GATES SUB, Huron Transmission
230.00 12.00 7.20
GATES SUB, Huron Transmission
115.00 12.00
GEYSERVILLE SUB, Geyserville Distribution
60.00 12.00 2.40
GIFFEN SUB, San Joaquin Distribution
70.00 12.00 2.40
GIRVAN SUB, Redding Distribution
60.00 12.00 7.20
GLENWOOD SUB, Menlo Park Distribution
60.00 12.00 7.20
GLENWOOD SUB, Menlo Park Distribution
60.00 4.00
GOLDTREE SUB, SLO Distribution
115.00 12.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
GONZALES SUB, Gonzales Distribution
60.00 12.00
GOOSE LAKE SUB, Wasco Distribution
115.00 12.00 7.20
GRAND ISLAND SUB, Ryde Distribution
115.00 21.00 7.20
GRANT SUB, San Lorenzo Distribution
115.00 12.00 7.20
GRASS VALLEY SUB, Grass Valley Distribution
60.00 12.00
GREEN VALLEY SUB, Watsonville Transmission
115.00 21.00 7.20
GREENBRAE SUB, Larkspur Distribution
60.00 12.00 7.20
GUALALA SUB, Gualala Distribution
60.00 12.00 2.40
GUERNSEY SUB, Hanford Distribution
70.00 12.00 2.40
GUSTINE SUB, Gustine Distribution
60.00 12.00 7.20
HALF MOON BAY SUB, Half Moon Bay Distribution
60.00 12.00
HAMMER SUB, Stockton Distribution
60.00 12.00 7.20
HAMMONDS SUB, Fresno Distribution
115.00 12.00
HARDING SUB, Stockton Distribution
60.00 4.00
HARDWICK SUB, Layton Distribution
70.00 12.00 7.20
HARRIS SUB, Eureka Distribution
60.00 12.00 7.20
HARTER SUB, Yuba City Distribution
60.00 12.00 7.20
HARTLEY SUB, Lakeport Distribution
60.00 12.00 7.20
HATTON SUB, Carmel Valley Distribution
60.00 12.00 2.40
HENRIETTA SUB, Lamoore Transmission
70.00 12.00 2.40
HERDLYN SUB, Tracy Transmission
60.00 12.00 2.40
HICKS SUB, San Jose Distribution
230.00 21.00 7.20
HICKS SUB, San Jose Distribution
230.00 12.00 7.20
HIGGINS SUB, Higgins Corner Distribution
115.00 12.00 7.20
HIGHLANDS SUB, Clear Lake Distribution
115.00 12.00
HIGHWAY SUB, Petaluma Distribution
115.00 12.00 7.20
HOLLISTER SUB, Hollister Distribution
115.00 21.00 7.20
HOLLISTER SUB, Hollister Distribution
60.00 21.00
HONCUT SUB, Honcut Distribution
115.00 12.00 7.20
HOPLAND SUB, Hopland Transmission
60.00 12.00 2.40
HORSESHOE SUB, Granite Bay Distribution
115.00 12.00 7.20
HOWLAND ROAD SUB, Manteca Distribution
115.00 12.00 7.20
HUMBOLDT BAY PP SUB, Eureka Distribution
60.00 13.80
HUMBOLDT BAY PP SUB, Eureka Distribution
115.00 13.80
HUMBOLDT BAY PP SUB, Eureka Distribution
60.00 12.00 7.20
HUMBOLDT BAY PP SUB, Eureka Distribution
60.00 2.00
HUMBOLDT BAY PP SUB, Eureka Distribution
115.00 2.00
HURON SUB, Huron Distribution
70.00 12.00 2.40
IGNACIO SUB, Ignacio Transmission
115.00 12.00
IMHOFF SUB, Martinez Distribution
115.00 12.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.5

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
IONE SUB, Ione Distribution
60.00 12.00 7.20
JACINTO SUB, Willows Distribution
60.00 12.00 7.20
JACOBS CORNER SUB, Lemoore Distribution
70.00 12.00
JAMESON SUB, CORDELIA Distribution
115.00 12.00 7.20
JANES CREEK SUB, Arcata Distribution
60.00 12.00
JARVIS SUB, Union City Distribution
115.00 12.00 7.20
JESSUP SUB, Anderson Distribution
115.00 12.00
JOLON SUB, King City Distribution
60.00 12.00
KELSO SUB, Tracy Distribution
230.00 12.00
KERMAN SUB, Kerman Distribution
70.00 12.00 7.20
KERN OIL SUB, Bakersfield Distribution
115.00 12.00 7.20
KERN PP DIST SUB, Bakersfield Distribution
115.00 21.00 7.20
KESWICK SUB, Keswick Distribution
60.00 12.00 2.40
KETTLEMAN HILLS SUB, Kettleman Distribution
70.00 12.00 2.40
KING CITY SUB, King City Distribution
60.00 12.00
KINGSBURG SUB, Kingsburg Transmission
115.00 12.00 7.20
KIRKER SUB, Pittsburg Distribution
115.00 21.00 7.20
KONOCTI SUB, Clear Lake Distribution
60.00 12.00 2.40
LAKEVIEW SUB, Bakersfield Distribution
70.00 12.00 2.40
LAKEVILLE SUB, Petaluma Transmission
115.00 12.00
LAKEWOOD SUB, Walnut Creek Distribution
115.00 21.00 7.20
LAKEWOOD SUB, Walnut Creek Distribution
115.00 12.00 7.20
LAMMERS SUB, TRACY Distribution
115.00 12.00 7.20
LAMONT SUB, Bakersfield Distribution
115.00 12.00
LAS GALLINAS A SUB, Las Gallinas Distribution
115.00 12.00 2.40
LAS PALMAS SUB, Fresno Distribution
115.00 12.00 7.20
LAS POSITAS SUB, Livermore Transmission
230.00 21.00 7.20
LAS PULGAS SUB, Redwood City Distribution
60.00 4.00 2.40
LAWRENCE SUB, Sunnyvale Distribution
115.00 12.00
LE GRAND SUB, Le Grand Distribution
115.00 12.00 7.20
LEMOORE SUB, Armonia Distribution
70.00 12.00 2.40
LERDO SUB, Bakersfield Distribution
115.00 12.00 7.20
LINCOLN SUB, Lincoln Distribution
60.00 12.00 7.20
LINDEN SUB, Linden Distribution
60.00 12.00 2.40
LIVE OAK SUB, Live Oak Distribution
60.00 12.00
LIVERMORE SUB, Livermore Distribution
60.00 12.00 2.40
LIVINGSTON SUB, Livingston Distribution
115.00 12.00 7.20
LIVINGSTON SUB, Livingston Distribution
70.00 12.00
LLAGAS SUB, Gilroy Distribution
115.00 21.00 12.00
LOCKEFORD SUB, Lockeford Transmission
115.00 21.00
FERC FORM NO. 1 (ED. 12-96) Page 426.6

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
LOCKHEED #2 SUB, Sunnyvale Distribution
115.00 12.00
LODI SUB, Lodi Distribution
60.00 12.00 2.40
LODI SUB, Lodi Distribution
60.00 4.00
LOGAN CREEK SUB, Willows Distribution
230.00 21.00
LONETREE SUB, Antioch Distribution
230.00 21.00 7.20
LOS ALTOS SUB, Los Altos Distribution
60.00 12.00
LOS COCHES SUB, Greenfield Distribution
60.00 12.00
LOS GATOS SUB, Los Gatos Distribution
60.00 12.00 7.20
LOS MOLINOS SUB, Los Molinos Distribution
60.00 12.00 7.20
LOS OSITOS SUB, Monterey Distribution
60.00 21.00 7.20
LOYOLA SUB, Loyola Distribution
60.00 12.00 7.20
LOYOLA SUB, Loyola Distribution
60.00 4.00 2.40
LUCERNE SUB, Lucerne Distribution
115.00 12.00 7.20
MABURY SUB, San Jose Distribution
60.00 12.00 2.40
MABURY SUB, San Jose Distribution
115.00 12.00 7.20
MADERA SUB, Madera Distribution
70.00 12.00
MADISON SUB, Madison Distribution
60.00 12.00 7.20
MADISON SUB, Madison Distribution
115.00 12.00
MAGUNDEN SUB, Bakersfield Distribution
115.00 12.00 7.20
MAGUNDEN SUB, Bakersfield Distribution
115.00 21.00 7.20
MALAGA SUB, Fresno Distribution
115.00 12.00 7.20
MANCHESTER SUB, Fresno Distribution
115.00 12.00 7.20
MANTECA SUB, Manteca Transmission
115.00 17.00
MARICOPA SUB, Maricopa Distribution
70.00 12.00 2.40
MARIPOSA SUB, Mariposa Distribution
70.00 21.00
MARTELL SUB, Martell Distribution
60.00 12.00 2.40
MARYSVILLE SUB, Marysville Distribution
60.00 12.00
MAXWELL SUB, Maxwell Distribution
60.00 12.00
MCCALL SUB, Selma Transmission
115.00 12.00 7.20
MCDONALD-MCDONALDISLAND SUB, Stockton Distribution
60.00 4.00 2.40
MCFARLAND SUB, McFarland Distribution
70.00 12.00 2.40
MCKEE SUB, San Jose Distribution
115.00 12.00 7.20
MCMULLIN SUB, Fresno Distribution
230.00 12.00 7.20
MEADOW LANE SUB, Concord Distribution
115.00 21.00 7.20
MENDOCINO SUB, Redwood Valley Transmission
60.00 12.00 2.40
MENDOTA SUB, Mendota Transmission
115.00 12.00 7.20
MENLO SUB, Menlo Park Distribution
60.00 12.00 7.20
MENLO SUB, Menlo Park Distribution
60.00 4.00
MERCED SUB, Merced Transmission
115.00 12.00 7.20
MERCED SUB, Merced Transmission
115.00 21.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.7

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
METTLER SUB, Stockton Distribution
60.00 12.00
MIDDLETOWN SUB, Middletown Distribution
60.00 12.00 7.20
MIDWAY SUB, Buttonwillow Transmission
115.00 12.00 7.20
MILLBRAE SUB, Millbrae Transmission
115.00 12.00
MILLBRAE SUB, Millbrae Transmission
60.00 4.00
MILPITAS SUB, Milpitas Distribution
115.00 21.00 7.20
MILPITAS SUB, Milpitas Distribution
115.00 12.00 7.20
MIRABEL SUB, Forestville Distribution
60.00 12.00
MI-WUK SUB, Sugarpine Distribution
115.00 17.00
MOLINO SUB, Sebastopol Distribution
60.00 12.00 7.20
MONROE SUB, Santa Rosa Distribution
115.00 21.00 7.20
MONROE SUB, Santa Rosa Distribution
115.00 12.00 7.20
MONTAGUE SUB, San Jose Distribution
115.00 21.00 7.20
MONTE RIO SUB, Monte Rio Distribution
60.00 12.00 7.20
MONTEREY SUB, Monterey Distribution
60.00 4.00
MORAGA SUB, Orinda Transmission
115.00 12.00
MORGAN HILL SUB, Morgan Hill Distribution
115.00 21.00 7.20
MORMON SUB, Stockton Distribution
60.00 12.00 7.20
MORRO BAY SUB, Morro Bay Distribution
115.00 12.00 7.20
MOSHER SUB, Stockton Distribution
60.00 21.00 7.20
MOSHER SUB, Stockton Distribution
115.00 21.00 7.20
MOUNTAIN VIEW SUB, Mt. View Distribution
115.00 12.00 7.20
MT. EDEN SUB, Hayward Distribution
115.00 12.00 7.20
MT. QUARRIES SUB, Cool Distribution
60.00 12.00 7.20
NAPA SUB, Napa Distribution
60.00 12.00
NEWARK DIST SUB, Fremont Distribution
230.00 21.00 7.20
NEWARK SUB, Fremont Transmission
115.00 12.00 7.20
NEWBURG SUB, Fortuna Distribution
60.00 12.00 2.40
NEWHALL SUB, Firebaugh Distribution
115.00 12.00 7.20
NEWMAN SUB, Newman Distribution
60.00 12.00 7.20
NORCO SUB, Bakersfield Distribution
115.00 12.00 7.20
NORD SUB, Chico Distribution
115.00 12.00 7.20
NORTECH SUB, San Jose Distribution
115.00 21.00 7.20
NORTH DUBLIN SUB, Pleasanton Distribution
230.00 21.00 12.00
NORTH TOWER SUB, Vallejo Distribution
115.00 12.00 7.20
NORTH TOWER SUB, Vallejo Distribution
115.00 25.00 7.20
NOTRE DAME SUB, Chico Distribution
115.00 12.00 7.20
NOVATO SUB, Novato Distribution
60.00 12.00 7.20
OAKHURST SUB, Oakhurst Distribution
115.00 12.00 2.40
OAKLAND C (OAKLAND PP) SUB, Oakland Distribution
115.00 12.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.8

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
OAKLAND D SUB, Oakland Distribution
115.00 12.00 7.20
OAKLAND J SUB, Oakland Distribution
115.00 12.00 7.20
OAKLAND K (CLAREMONT) SUB, Oakland Distribution
115.00 12.00 6.60
OAKLAND L SUB, Oakland Distribution
115.00 12.00 7.20
OAKLAND X SUB, Oakland Distribution
115.00 12.00
OCEANO SUB, Oceano Distribution
115.00 12.00 7.20
OILFIELDS SUB, San Ardo Distribution
60.00 12.00
OLD KEARNEY SUB, Fresno Distribution
70.00 12.00 13.20
OLD RIVER SUB, Knob Hill Distribution
70.00 12.00 2.40
OLETA SUB, Plymouth Distribution
60.00 12.00 2.40
OLIVEHURST SUB, Olivehurst Distribution
115.00 12.00 7.20
OREGON TRAIL SUB, Redding Distribution
115.00 12.00 7.20
OREGON TRAIL SUB, Redding Distribution
60.00 12.00 2.40
ORLAND B SUB, Orland Distribution
60.00 12.00 2.40
ORO FINO SUB, Magalia Distribution
60.00 12.00 2.40
ORO LOMA SUB, Dos Palos Transmission
70.00 12.00 2.40
OROSI SUB, Orosi Distribution
70.00 12.00 7.20
OROVILLE SUB, Oroville Distribution
60.00 12.00 7.20
OROVILLE SUB, Oroville Distribution
60.00 4.00 2.40
ORTIGA SUB, Los Banos Distribution
70.00 12.00 2.40
PACIFICA SUB, Pacifica Distribution
60.00 12.00
PALMER SUB, Sisquat Distribution
115.00 12.00 7.20
PANAMA SUB, Bakersfield Distribution
70.00 21.00 7.20
PANORAMA SUB, Anderson Distribution
115.00 12.00
PARADISE SUB, Paradise Distribution
60.00 12.00 7.20
PARADISE SUB, Paradise Distribution
115.00 12.00
PARKWAY SUB, Vallejo Distribution
230.00 12.00 7.20
PARLIER SUB, Parlier Distribution
70.00 12.00 7.20
PASO ROBLES SUB, Paso Robles Distribution
70.00 12.00
PAUL SWEET SUB, Santa Cruz Distribution
115.00 21.00 7.20
PEABODY SUB, Fairfield Distribution
230.00 21.00 7.20
PEACHTON SUB, Gridley Distribution
60.00 12.00 2.40
PEASE SUB, Tierra Buena Transmission
115.00 12.00
PENNGROVE SUB, Penngrove Distribution
115.00 12.00
PENRYN SUB, Penryn Distribution
60.00 12.00 7.20
PEORIA SUB, Jamestown Distribution
115.00 18.00
PETALUMA C SUB, Petaluma Distribution
60.00 12.00
PIERCY SUB, San Jose Distribution
115.00 21.00 7.20
PINE GROVE SUB, Pine Grove Distribution
60.00 12.00 2.40
PINEDALE SUB, FRESNO Distribution
115.00 21.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.9

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
PLACER SUB, Auburn Transmission
115.00 12.00
PLACERVILLE SUB, Placerville Distribution
115.00 12.00 7.20
PLACERVILLE SUB, Placerville Distribution
115.00 21.00
PLAINFIELD SUB, Davis Distribution
60.00 12.00
PLEASANT GROVE SUB, Pleasant Grove Distribution
60.00 21.00 7.20
PLUMAS SUB, Wheatland Distribution
60.00 21.00 7.20
PLUMAS SUB, Wheatland Distribution
60.00 12.00 7.20
POINT MORETTI SUB, Davenport Distribution
60.00 12.00 2.40
POINT PINOLE SUB, Richmond Distribution
115.00 12.00 6.60
POSO MOUNTAIN SUB, Kern Distribution
115.00 21.00
PRUNEDALE SUB, Prunedale Distribution
115.00 12.00 7.20
PUEBLO SUB, Napa Distribution
115.00 12.00
PUEBLO SUB, Napa Distribution
115.00 21.00
PURISIMA SUB, Lompoc Distribution
115.00 12.00 7.20
PUTAH CREEK SUB, Winters Distribution
115.00 12.00
RACE TRACK SUB, Jamestown Distribution
115.00 17.00
RADUM SUB, Pleasanton Distribution
60.00 12.00
RAINBOW SUB, Sanger Distribution
115.00 12.00 7.20
RALSTON SUB, Belmont Distribution
60.00 12.00
RANCHERS COTTON SUB, Fresno Distribution
115.00 12.00 7.20
RAWSON SUB, Red Bluff Distribution
60.00 12.00 2.40
RED BLUFF SUB, Red Bluff Distribution
60.00 12.00 2.40
REDBUD SUB, Clearlake Oaks Distribution
115.00 12.00 7.20
REDWOOD CITY SUB, Redwood City Distribution
60.00 12.00 7.20
REDWOOD CITY SUB, Redwood City Distribution
60.00 4.00
REEDLEY SUB, Reedley Transmission
115.00 12.00 7.20
REEDLEY SUB, Reedley Transmission
70.00 12.00 2.40
RENFRO SUB, BAKERSFIELD Distribution
115.00 12.00 7.20
RESEARCH SUB, San Ramon Distribution
230.00 21.00 7.20
RESERVATION ROAD SUB, Salinas Distribution
60.00 12.00 2.40
RESERVE OIL SUB, Hanford Distribution
70.00 12.00 2.40
RESERVE OIL SUB, Hanford Distribution
70.00 4.00
RICE SUB, Princeton Distribution
60.00 12.00 4.16
RICHMOND R SUB, Richmond Distribution
115.00 12.00 6.60
RINCON SUB, Santa Rosa Distribution
115.00 12.00
RIO BRAVO SUB, Shafter Distribution
115.00 12.00 7.20
RIO DELL SUB, Rio Dell Distribution
60.00 12.00
RIPON SUB, Ripon Distribution
115.00 17.00
RISING RIVER SUB, Cassell, Distribution
60.00 12.00 2.40
RIVER OAKS SUB, San Jose Distribution
115.00 21.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.10

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
RIVERBANK SUB, Escalon Distribution
115.00 12.00
ROB ROY SUB, Watsonville Distribution
115.00 21.00 7.20
ROCKLIN SUB, Rocklin Distribution
60.00 12.00 7.20
ROSEDALE SUB, Bakersfield Distribution
115.00 12.00 7.20
ROSSMOOR SUB, Walnut Creek Distribution
230.00 12.00
ROUGH & READY ISLAND SUB, Stockton Distribution
60.00 12.00 7.20
SALINAS SUB, Salinas Transmission
115.00 12.00 7.20
SALMON CREEK SUB, Bodega Bay Distribution
60.00 12.00 2.40
SAN ARDO SUB, San Ardo Distribution
60.00 12.00
SAN BERNARD SUB, Lamont Distribution
70.00 12.00 2.40
SAN CARLOS SUB, San Carlos Distribution
60.00 12.00 7.20
SAN CARLOS SUB, San Carlos Distribution
60.00 4.00 2.40
SAN FRAN A (POTRERO PP) SUB, San Franc Distribution
115.00 12.00 7.20
SAN FRAN H (MARTIN) SUB, Daly City Transmission
115.00 12.00
SAN FRAN P-HUNTERS POINT SUB, San Fran Distribution
115.00 12.00
SAN FRAN X (MISSION) SUB, San Francisc Distribution
115.00 12.00
SAN FRAN Y (LARKIN) SUB, San Francisco Distribution
115.00 12.00
SAN JOAQUIN SUB, San Joaquin Distribution
70.00 12.00 7.20
SAN JOSE A SUB, San Jose Distribution
115.00 4.00 7.20
SAN JOSE A SUB, San Jose Distribution
115.00 12.00
SAN JOSE B SUB, San Jose Distribution
115.00 12.00 7.20
SAN LEANDRO U SUB, San Leandro Distribution
115.00 12.00
SAN LUIS OBISPO SUB, SLO Transmission
115.00 12.00 7.20
SAN MATEO SUB, San Mateo Transmission
115.00 21.00
SAN MATEO SUB, San Mateo Transmission
60.00 4.00
SAN MIGUEL SUB, San Miguel Distribution
70.00 12.00 7.20
SAN PABLO SUB, Richmond Distribution
115.00 12.00 7.20
SAN RAFAEL SUB, San Rafael Distribution
115.00 12.00 4.16
SAN RAMON SUB, San Ramon Transmission
230.00 21.00 12.00
SANGER SUB, Fresno Transmission
115.00 12.00 7.20
SANTA MARIA SUB, Santa Maria Distribution
115.00 12.00 7.20
SANTA NELLA SUB, Santa Nella Distribution
70.00 12.00 2.40
SANTA RITA SUB, Dos Palos Distribution
70.00 12.00 2.40
SANTA ROSA A SUB, Santa Rosa Distribution
115.00 12.00 7.20
SANTA YNEZ SUB, Santa Maria Distribution
115.00 12.00 7.20
SARATOGA SUB, Saratoga Distribution
230.00 12.00 7.20
SAUSALITO SUB, Sausalito Distribution
60.00 12.00 2.40
SAUSALITO SUB, Sausalito Distribution
60.00 4.00
SCHINDLER SUB, Five Points Transmission
115.00 12.00 7.20
SEMITROPIC SUB, Wasco Transmission
115.00 12.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.11

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
SERRAMONTE SUB, Daly City Distribution
115.00 12.00
SHAFTER SUB, Shafter Distribution
115.00 12.00 7.20
SHARON SUB, Chowchilla Distribution
115.00 12.00
SHINGLE SPRINGS SUB, Shingle Springs Distribution
115.00 21.00 7.20
SHINGLE SPRINGS SUB, Shingle Springs Distribution
115.00 12.00 7.20
SHREDDER SUB, Redwood City Distribution
115.00 4.00 6.60
SILVERADO SUB, St. Helena Distribution
115.00 21.00
SISQUOC SUB, Orcutt Distribution
115.00 12.00 7.20
SMYRNA SUB, Wasco Distribution
115.00 12.00 7.20
SNEATH LANE SUB, San Bruno Distribution
60.00 12.00 2.40
SOBRANTE SUB, Orinda Transmission
115.00 12.00 7.20
SOLEDAD SUB, Soledad Transmission
60.00 12.00
SONOMA A SUB, Sonoma Distribution
115.00 12.00
SOUTH BAY #1 & #2 SUB, Tracy Distribution
60.00 4.00
SPANISH CREEK SUB, Distribution
60.00 44.00
SPENCE SUB, Salinas Distribution
60.00 12.00
SRI SUB, Menlo Park Distribution
60.00 12.00
STAFFORD SUB, Novato Distribution
60.00 12.00
STAGG SUB, Stockton Transmission
230.00 21.00 7.20
STAGG SUB, Stockton Transmission
60.00 12.00 2.40
STALLION SUB, Bakersfield Distribution
70.00 4.00 7.20
STELLING SUB, Cupertino Distribution
115.00 12.00 7.20
STILLWATER STA SUB, Project City Distribution
60.00 12.00 2.40
STOCKDALE SUB, Bakersfield Distribution
230.00 21.00 7.20
STOCKDALE SUB, Bakersfield Distribution
115.00 12.00 7.20
STOCKTON A SUB, Stockton Transmission
115.00 12.00
STOCKTON A SUB, Stockton Transmission
60.00 4.00
STONE CORRAL SUB, Woodlake Distribution
70.00 12.00 7.20
STONE SUB, San Jose Distribution
115.00 12.00 7.20
STOREY SUB, Madera Distribution
230.00 12.00 7.20
STROUD SUB, Helm Distribution
70.00 12.00 2.40
SUISUN SUB, Fairfield Distribution
115.00 12.00 7.20
SUNOL SUB, Sunol Distribution
60.00 12.00 7.20
SWIFT SUB, San Jose Distribution
115.00 21.00 7.20
SYCAMORE CREEK SUB, Chico Distribution
115.00 12.00
TAFT SUB, Taft Transmission
115.00 12.00 7.20
TASSAJARA SUB, Danville Distribution
230.00 21.00 7.20
TEJON SUB, Leboc Distribution
70.00 12.00 2.40
TEMBLOR SUB, McKittrick Distribution
115.00 12.00 2.40
TEMPLETON SUB, TEMPLETON Transmission
230.00 21.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.12

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
TEVIS SUB, Oildale Distribution
115.00 21.00 7.20
TIDEWATER SUB, Martinez Distribution
230.00 21.00
TIVY VALLEY SUB, Fresno Distribution
70.00 12.00 7.20
TRACY SUB, Tracy Distribution
115.00 12.00 4.16
TRES VIAS SUB, Oroville Distribution
60.00 12.00 7.20
TRIMBLE SUB, San Jose Distribution
115.00 12.00 7.20
TRIMBLE SUB, San Jose Distribution
115.00 21.00 7.20
TULARE LAKE SUB, Kettleman Distribution
70.00 12.00 2.40
TULUCAY SUB, Napa Transmission
60.00 12.00
TUPMAN SUB, Tupman Distribution
115.00 12.00 7.20
TWISSELMAN SUB, Blackwell Corners Distribution
70.00 12.00 7.20
TYLER SUB, Red Bluff Distribution
60.00 12.00 2.40
UKIAH SUB, Ukiah Distribution
115.00 12.00 7.20
URICH SUB, Martinez Distribution
60.00 4.00
VACA DIXON SUB, Vacaville Transmission
115.00 12.00 7.20
VACAVILLE SUB, Vacaville Distribution
115.00 12.00 7.20
VALLEY VIEW SUB, El Sobrante Distribution
115.00 12.00
VASCO SUB, Livermore Distribution
60.00 12.00
VASONA SUB, Los Gatos Distribution
230.00 12.00 7.20
VICTOR SUB, Lodi Distribution
60.00 12.00 2.40
VICTOR SUB, Lodi Distribution
60.00 4.00
VIEJO SUB, Monterey Distribution
60.00 21.00 7.20
VIERRA SUB, Lathrop Distribution
115.00 17.00 7.20
VINEYARD SUB, Pleasanton Distribution
230.00 21.00 7.20
VOLTA #1PH SUB, Shingletown Distribution
60.00 12.00 2.40
WAHTOKE SUB, Reedley Distribution
115.00 12.00 7.20
WASCO SUB, Wasco Distribution
70.00 12.00 2.40
WATERLOO SUB, Stockton Distribution
60.00 12.00 2.40
WATSONVILLE SUB, Watsonville Distribution
60.00 12.00 7.20
WATSONVILLE SUB, Watsonville Distribution
60.00 4.00
WEBER SUB, Stockton Transmission
60.00 12.00 7.20
WEBER SUB, Stockton Transmission
230.00 12.00 7.20
WEEDPATCH SUB, Weedpatch Distribution
70.00 12.00 7.20
WELLFIELD SUB, Lamont Distribution
70.00 12.00 2.40
WEST FRESNO SUB, Fresno Distribution
115.00 12.00 7.20
WEST LANE SUB, Stockton Distribution
60.00 12.00 7.20
WEST SACRAMENTO SUB, WEST SACRAMENTO Distribution
115.00 12.00 7.20
WESTLEY SUB, Westley Distribution
60.00 12.00 2.40
WESTPARK SUB, Bakersfield Distribution
115.00 12.00 7.20
WHEATLAND SUB, Wheatland Distribution
60.00 12.00 7.20
FERC FORM NO. 1 (ED. 12-96) Page 426.13

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
WHEELER RIDGE SUB, Bakersfield Transmission
70.00 12.00 2.40
WHISMAN SUB, Mt. View Distribution
115.00 12.00 7.20
WILLIAMS SUB, Williams Distribution
60.00 12.00 7.20
WILLITS A SUB, Willits Distribution
60.00 12.00 2.40
WILLOW PASS SUB, Pittsburg Distribution
115.00 21.00 7.20
WILLOW PASS SUB, Pittsburg Distribution
60.00 12.00 2.40
WILLOWS A SUB, Willows Distribution
60.00 12.00
WILSON SUB, Merced Transmission
115.00 12.00
WOLFE SUB, Cupertino Distribution
115.00 12.00
WOODCHUCK SUB, Wilson Village Distribution
70.00 21.00
WOODLAND SUB, Woodland Distribution
115.00 12.00 7.20
WOODSIDE SUB, Woodside Distribution
60.00 12.00
WOODWARD SUB, Fresno Distribution
115.00 21.00 7.20
WRIGHT SUB, Los Banos Distribution
70.00 12.00 2.40
WYANDOTTE SUB, Oroville Distribution
115.00 12.00 7.20
ZACA SUB, Santa Maria Distribution
115.00 12.00 7.20
ZAMORA SUB, Zamora Distribution
115.00 12.00
Substations of < 10 MVA
Distribution
Rounding issues in column f
SUBTOTAL DISTRIBUTION SUBSTATIONS 56350.00 7574.60 2590.08
ARCO SUB, Lost Hills Transmission
230.00 70.00 13.20
ATLANTIC SUB, Roseville Transmission
230.00 60.00 13.20
BAIR SUB, Redwood City Transmission
115.00 60.00 13.20
BELLOTA SUB, Bellota Transmission
230.00 115.00 13.20
BORDEN SUB, Madera Transmission
230.00 70.00 13.20
BRIDGEVILLE SUB, Bridgeville Transmission
115.00 60.00 12.00
BRIGHTON SUB, Sacramento Transmission
230.00 115.00 13.20
BUTTE SUB, Chico Transmission
115.00 60.00 12.00
CASCADE SUB, Pine Grove Transmission
115.00 60.00 13.20
CHRISTIE SUB, Hercules Transmission
115.00 60.00 13.20
COBURN SUB, King City Transmission
230.00 60.00 13.20
CONTRA COSTA SUBSTATION, Antioch Transmission
115.00 60.00 6.60
CONTRA COSTA SUBSTATION, Antioch Transmission
230.00 115.00 13.20
COOLEY LANDING SUB, Palo Alto Transmission
115.00 60.00 13.80
CORCORAN SUB, Corcoran Transmission
115.00 70.00 6.60
CORTINA SUB, Williams Transmission
230.00 115.00 13.20
COTTONWOOD SUB, Cottonwood Transmission
230.00 60.00 13.20
COTTONWOOD SUB, Cottonwood Transmission
230.00 115.00 13.20
FERC FORM NO. 1 (ED. 12-96) Page 426.14

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
DEL MONTE SUB, Monterey Transmission
115.00 60.00 13.20
DIVIDE SUB, Orcutt Transmission
115.00 70.00 13.20
EAGLE ROCK SUB, Geysers Transmission
115.00 60.00
EAST NICOLAUS SUB, E. Nicolaus Transmission
115.00 60.00
EASTSHORE SUB, Hayward Transmission
230.00 115.00
EVERGREEN SUB, San Jose Transmission
115.00 60.00 13.20
FULTON SUB, Fulton Transmission
115.00 60.00 13.20
FULTON SUB, Fulton Transmission
230.00 115.00 13.20
GATES SUB, Huron Transmission
115.00 70.00 13.20
GATES SUB, Huron Transmission
230.00 115.00 13.20
GATES SUB, Huron Transmission
500.00 230.00 13.20
GLENN SUB, Orland Transmission
230.00 60.00 13.20
GOLD HILL SUB, Folsom Transmission
115.00 60.00 13.20
GOLD HILL SUB, Folsom Transmission
230.00 115.00 13.20
GREEN VALLEY SUB, Watsonville Transmission
115.00 60.00
HELM SUB, San Joaquin Transmission
230.00 70.00 13.20
HENRIETTA SUB, Lamoore Transmission
230.00 70.00 13.20
HENRIETTA SUB, Lamoore Transmission
230.00 115.00 2.40
HERDLYN SUB, Tracy Transmission
70.00 60.00 2.40
HERNDON SUB, Herndon Transmission
230.00 115.00 13.20
HOPLAND SUB, Hopland Transmission
115.00 60.00 13.20
HUMBOLDT SUB SUB, Eureka Transmission
115.00 60.00 12.00
IGNACIO SUB, Ignacio Transmission
115.00 60.00 13.20
IGNACIO SUB, Ignacio Transmission
230.00 115.00 13.20
JEFFERSON SUB, Redwood City Transmission
230.00 60.00 13.20
KASSON SUB, Tracy Transmission
115.00 60.00 13.20
KERN PP SUB, Bakersfield Transmission
115.00 70.00 13.20
KERN PP SUB, Bakersfield Transmission
230.00 115.00 13.20
KINGSBURG SUB, Kingsburg Transmission
115.00 70.00 13.80
LAKEVILLE SUB, Petaluma Transmission
230.00 60.00 13.20
LAKEVILLE SUB, Petaluma Transmission
230.00 115.00 13.20
LAS POSITAS SUB, Livermore Transmission
230.00 60.00 13.20
LOCKEFORD SUB, Lockeford Transmission
230.00 60.00 13.20
LOS BANOS SUB, Los Banos Transmission
230.00 70.00 13.20
LOS BANOS SUB, Los Banos Transmission
500.00 230.00 13.80
LOS ESTEROS SUB, Transmission
230.00 115.00 12.00
MANTECA SUB, Manteca Transmission
115.00 60.00 12.80
MCCALL SUB, Selma Transmission
230.00 115.00 13.20
MENDOCINO SUB, Redwood Valley Transmission
115.00 60.00 13.20
MENDOTA SUB, Mendota Transmission
115.00 70.00 13.80
FERC FORM NO. 1 (ED. 12-96) Page 426.15

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
MERCED SUB, Merced Transmission
115.00 70.00 6.60
MESA SUB, Nipomo Transmission
230.00 115.00 13.20
METCALF SUB, San Jose Transmission
230.00 115.00 13.20
METCALF SUB, San Jose Transmission
500.00 230.00 13.80
MIDWAY SUB, Buttonwillow Transmission
230.00 115.00 12.80
MIDWAY SUB, Buttonwillow Transmission
500.00 230.00 13.80
MILLBRAE SUB, Millbrae Transmission
115.00 60.00 13.80
MONTA VISTA SUB, Cupertino Transmission
115.00 60.00 13.20
MONTA VISTA SUB, Cupertino Transmission
230.00 60.00
MONTA VISTA SUB, Cupertino Transmission
230.00 115.00 13.20
MORAGA SUB, Orinda Transmission
230.00 115.00 13.20
MORRO BAY SW STA SUB, Morro Bay Transmission
230.00 115.00 13.20
MOSS LANDING PP SUB, Moss Landing Transmission
230.00 115.00 13.20
MOSS LANDING PP SUB, Moss Landing Transmission
500.00 230.00 13.80
NEW KEARNEY SUB, FRESNO Transmission
230.00 70.00 13.20
NEWARK SUB, Fremont Transmission
115.00 60.00 13.20
NEWARK SUB, Fremont Transmission
230.00 115.00 13.20
ORO LOMA SUB, Dos Palos Transmission
115.00 70.00 13.20
PALERMO SUB, Palermo Transmission
230.00 60.00
PALERMO SUB, Palermo Transmission
230.00 115.00 13.20
PANOCHE SUB, Mendota Transmission
230.00 115.00 13.20
PEASE SUB, Tierra Buena Transmission
115.00 60.00 13.20
PITTSBURG PP SUB, Transmission
230.00 115.00 13.20
PLACER SUB, Auburn Transmission
115.00 60.00
RAVENSWOOD SUB, Menlo Park Transmission
230.00 115.00 13.20
REEDLEY SUB, Reedley Transmission
115.00 70.00 13.20
RIO OSO SUB, Rio Oso Transmission
230.00 115.00 13.20
ROUND MOUNTAIN SUB, Rd Mtn Transmission
500.00 230.00 13.80
SALADO SUB, Patterson Transmission
115.00 70.00 12.00
SALINAS SUB, Salinas Transmission
115.00 60.00 13.20
SAN FRAN H (MARTIN) SUB, Daly City Transmission
115.00 60.00
SAN FRAN H (MARTIN) SUB, Daly City Transmission
230.00 115.00
SAN LUIS OBISPO SUB, SLO Transmission
115.00 70.00
SAN MATEO SUB, San Mateo Transmission
115.00 60.00
SAN MATEO SUB, San Mateo Transmission
230.00 115.00
SAN RAMON SUB, San Ramon Transmission
230.00 60.00 13.20
SANGER SUB, Fresno Transmission
115.00 70.00 6.60
SCHINDLER SUB, Five Points Transmission
115.00 70.00 13.20
SEMITROPIC SUB, Wasco Transmission
115.00 70.00 13.80
SOBRANTE SUB, Orinda Transmission
230.00 115.00
FERC FORM NO. 1 (ED. 12-96) Page 426.16

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
Primary Secondary Tertiary
(a)
(b)
(c)
(d)
(e)
SOLEDAD SUB, Soledad Transmission
115.00 60.00
STAGG SUB, Stockton Transmission
230.00 60.00 13.20
TABLE MOUNTAIN SUB, Oroville Transmission
230.00 115.00
TABLE MOUNTAIN SUB, Oroville Transmission
500.00 230.00 13.80
TAFT SUB, Taft Transmission
115.00 70.00 13.20
TEMPLETON SUB, TEMPLETON Transmission
230.00 70.00 13.20
TESLA SUB, Tracy Transmission
230.00 115.00 13.20
TESLA SUB, Tracy Transmission
500.00 230.00 13.20
TRINITY SUB, Weaverville Transmission
115.00 60.00 13.20
TULUCAY SUB, Napa Transmission
230.00 60.00 13.20
VACA DIXON SUB, Vacaville Transmission
115.00 60.00 13.20
VACA DIXON SUB, Vacaville Transmission
230.00 115.00 13.20
VACA DIXON SUB, Vacaville Transmission
500.00 230.00 13.80
VALLEY SPRINGS SUB, Valley Springs Transmission
230.00 60.00
WEBER SUB, Stockton Transmission
230.00 60.00 13.20
WHEELER RIDGE SUB, Bakersfield Transmission
115.00 70.00 13.20
WHEELER RIDGE SUB, Bakersfield Transmission
230.00 70.00 13.20
WILSON SUB, Merced Transmission
230.00 115.00 13.20
Rounding issues in column f
SUBTOTAL TRANSMISSION SUBSTATIONS 23545.00 10710.00 1272.40
TOTAL DISTRIBUTION & TRANSMISSION SUBSTATIONS 79895.00 18284.60 3862.48
FERC FORM NO. 1 (ED. 12-96) Page 426.17

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
90 2 1
27 2 2
60 2 3
11 1 4
38 6 1 5
30 1 6
19 3 1 7
16 1 8
11 1 9
11 3 1 10
16 1 11
16 1 12
27 4 1 13
54 2 14
11 3 15
210 3 16
30 1 17
90 2 18
25 2 19
16 3 1 20
16 1 21
112 2 22
45 2 23
150 2 24
13 1 25
120 3 26
39 4 27
90 2 28
75 2 29
13 1 30
57 2 31
57 3 32
16 6 1 33
70 3 34
125 3 35
10 2 36
11 2 37
11 3 1 38
15 3 39
20 3 40
FERC FORM NO. 1 (ED. 12-96) Page 427

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
13 1 1
13 3 1 2
75 2 3
12 1 4
16 1 5
30 1 6
20 3 7
195 3 8
120 3 9
90 3 10
21 2 11
76 3 12
90 2 13
45 1 14
30 1 15
46 2 16
11 1 17
20 3 18
30 1 19
15 3 20
19 3 21
135 3 22
21 3 1 23
16 1 24
41 2 25
90 2 26
11 1 27
6 3 1 28
60 2 29
24 1 30
11 6 31
37 3 32
16 1 33
16 1 34
11 2 35
25 2 36
30 1 37
13 1 38
85 2 39
30 3 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.1

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
11 1 1
45 1 2
25 2 3
13 1 4
41 2 5
19 3 1 6
16 1 7
21 3 1 8
32 2 9
13 1 10
13 1 11
61 2 12
11 3 1 13
135 3 14
29 2 15
120 3 16
16 1 17
20 6 1 18
19 3 1 19
90 2 20
45 1 21
27 2 22
19 3 23
61 2 24
59 3 25
12 1 26
21 6 1 27
150 2 28
42 3 1 29
20 3 1 30
28 4 31
46 2 32
16 1 33
13 3 2 34
58 10 3 35
30 1 36
43 2 37
7 1 38
29 6 1 39
80 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.2

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
30 1 1
35 3 2
7 1 3
25 3 1 4
90 2 1 5
19 3 1 6
16 3 7
16 1 8
30 1 9
95 4 1 10
135 3 11
61 2 12
75 2 13
16 1 14
75 2 15
14 1 16
43 2 17
61 2 18
49 5 19
11 3 1 20
135 3 1 21
49 4 1 22
11 1 23
13 1 24
105 3 25
32 6 1 26
150 5 1 27
25 2 1 28
9 3 29
16 1 30
8 1 31
140 3 32
30 1 33
90 2 34
90 2 35
63 2 36
45 1 37
127 5 1 38
32 2 1 39
135 3 40
FERC FORM NO. 1 (ED. 12-96) Page 427.3

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
23 2 1
11 1 2
13 1 3
11 3 1 4
13 1 5
13 3 1 6
90 2 1 7
13 1 8
50 3 9
60 2 10
30 1 11
60 2 12
225 3 13
30 1 14
22 2 15
25 3 16
50 2 17
11 1 18
21 3 1 19
19 6 20
19 3 1 21
60 2 22
90 3 23
32 2 24
25 4 25
49 4 1 26
60 2 27
16 1 28
25 1 29
13 1 30
16 1 31
21 3 1 32
45 1 33
19 3 34
22 4 35
19 3 36
16 1 37
32 2 38
7 1 39
16 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.4

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
22 2 1
27 2 2
81 3 3
90 2 4
19 3 1 5
60 2 6
32 2 7
12 7 1 8
31 4 9
21 3 10
32 5 11
70 7 12
16 1 13
13 2 14
12 1 15
29 2 16
60 2 17
19 2 18
16 3 19
12 3 20
13 1 21
150 2 22
90 2 23
77 3 24
60 2 25
64 4 1 26
70 2 27
25 1 28
16 1 29
13 3 1 30
72 2 31
16 1 32
133 6 SVC 4
50 33
77 3 34
11 1 35
4 1 36
4 1 37
20 3 38
46 2 39
16 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.5

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
13 1 1
16 1 2
29 2 3
45 1 4
20 2 5
105 3 6
22 1 7
11 1 8
30 1 9
41 2 10
90 2 11
90 2 12
11 3 1 13
11 3 14
23 3 15
90 2 16
135 3 17
16 4 18
19 3 19
30 1 20
180 6 1 21
25 3 1 22
90 2 23
52 2 24
39 3 25
16 1 26
165 3 27
14 2 28
145 5 1 29
19 3 30
56 4 1 31
60 2 32
55 3 33
19 3 34
27 2 35
25 6 36
30 1 37
11 3 38
100 3 39
98 4 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.6

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
46 2 1
21 3 1 2
5 3 1 3
45 1 4
45 1 5
51 3 6
13 3 1 7
32 2 8
13 3 1 9
43 2 10
21 3 1 11
5 3 1 12
29 2 13
19 3 14
16 1 15
41 6 16
30 1 17
21 2 18
45 1 19
45 1 20
105 3 21
135 3 22
135 8 1 23
11 3 24
32 2 25
13 3 1 26
49 4 1 27
17 3 1 28
90 2 29
21 2 30
19 3 31
105 3 32
45 1 33
145 3 34
5 3 1 35
30 1 36
32 2 37
13 2 38
45 1 39
45 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.7

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
11 1 1
34 4 1 2
23 2 3
60 2 4
6 3 1 5
90 2 6
75 2 7
11 1 8
14 3 1 9
43 2 10
90 2 11
45 1 12
135 3 13
29 2 14
11 3 1 15
45 1 16
120 3 17
30 1 18
16 1 19
30 1 20
30 1 21
115 3 22
135 3 23
16 1 24
68 7 1 25
150 2 26
57 6 1 27
20 4 1 28
29 2 29
41 4 30
16 1 31
32 2 32
45 1 33
45 1 34
45 1 35
30 6 36
45 1 37
23 2 38
43 3 39
180 5 40
FERC FORM NO. 1 (ED. 12-96) Page 427.8

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
130 3 1
146 6 1 2
38 3 1 3
135 3 4
140 3 5
60 2 6
42 6 1 7
31 4 8
40 7 9
18 4 10
41 2 11
16 1 12
6 3 13
25 7 14
11 1 15
22 3 16
17 2 17
25 2 18
5 3 1 19
11 1 20
23 2 21
11 1 22
45 1 23
30 1 24
45 1 25
45 1 26
30 1 27
30 1 28
90 3 1 29
140 3 30
135 3 31
14 6 1 32
34 3 33
13 1 34
61 2 35
58 4 36
57 5 1 37
45 1 38
22 4 39
135 3 40
FERC FORM NO. 1 (ED. 12-96) Page 427.9

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
41 4 1 1
30 1 2
30 1 3
39 2 4
135 3 5
45 1 6
13 1 7
11 1 8
16 1 9
20 1 10
32 2 11
45 1 StatCom 2
8 12
45 1 13
11 1 14
16 1 15
16 1 16
25 6 17
30 1 18
16 4 19
16 1 20
19 3 21
50 5 22
23 3 23
70 5 24
21 6 1 25
30 1 26
19 3 27
90 2 28
45 1 29
11 1 30
4 1 31
3 1 32
14 2 33
90 4 1 34
32 2 35
35 4 36
11 3 37
28 1 38
11 3 1 39
90 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.10

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
73 4 1 1
23 1 2
27 4 1 3
30 1 4
90 2 5
16 1 6
75 2 7
11 3 1 8
11 3 1 9
19 3 10
29 2 11
13 3 1 12
181 3 SVC 4
80 13
135 3 14
98 2 15
300 5 1 16
390 6 17
18 2 18
40 2 19
30 1 20
180 4 21
110 7 1 22
135 3 23
45 1 24
9 3 1 25
16 1 26
30 1 27
106 3 28
300 4 29
60 2 30
75 2 31
27 2 32
12 3 33
135 3 34
21 2 35
157 3 36
21 3 1 37
5 3 1 38
30 1 39
30 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.11

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
13 1 1
27 3 1 2
11 1 3
61 2 4
16 1 5
15 3 1 6
60 2 7
32 2 8
19 3 9
19 6 10
30 1 11
11 1 12
60 2 13
25 3 14
19 1 15
13 3 1 16
11 1 17
25 2 18
150 2 19
51 4 1 20
11 1 21
105 3 22
11 3 1 23
225 3 24
30 1 25
105 3 26
22 6 27
21 2 28
45 1 29
90 2 30
19 3 31
120 3 32
13 1 33
145 3 34
90 3 35
27 2 36
150 2 37
19 3 38
21 3 1 39
90 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.12

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
90 2 1
150 2 2
13 1 3
106 4 4
16 1 5
90 2 6
90 2 7
11 3 2 8
14 1 9
61 2 10
32 2 11
19 6 12
29 2 13
10 3 1 14
76 3 15
120 3 16
29 2 17
17 6 18
90 2 19
32 4 20
3 3 1 21
60 2 22
90 2 23
150 2 1 24
21 3 1 25
60 2 26
20 3 27
11 1 28
16 1 29
8 1 30
50 2 31
45 1 32
30 1 33
24 4 34
135 3 35
30 1 36
105 3 37
29 2 38
105 3 39
44 4 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.13

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
19 3 1
90 3 2
27 2 3
19 3 1 4
30 1 5
11 3 1 6
14 3 1 7
14 1 8
120 3 9
23 3 10
135 3 11
36 3 12
135 3 13
13 1 14
87 3 15
11 1 16
16 1 17
703 357 58 18
-59 19
28244 1751 167 10 138 21
134 3 23
334 4 1 24
80 3 25
400 2 Sync Cond 1
40 26
400 2 27
30 3 28
840 2 29
60 3 1 30
76 3 31
90 3 1 32
214 6 1 33
110 6 34
180 3 1 35
174 6 1 36
28 3 37
588 4 2 38
414 2 1 39
240 6 1 40
20
22
FERC FORM NO. 1 (ED. 12-96) Page 427.14

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
400 2 1
170 6 1 2
68 3 1 3
59 3 1 4
540 4 1 5
80 3 1 6
600 2 7
823 4 1 8
117 3 1 9
120 3 10
1122 3 1 11
255 4 1 12
80 3 13
840 2 14
38 3 15
134 3 16
308 4 17
180 3 1 18
50 3 1 19
840 2 Sync Cond 2
80 20
40 1 21
75 6 1 Sync Cond 1
20 22
400 2 23
823 4 1 24
400 2 25
76 3 26
400 2 27
1075 8 1 28
90 3 1 29
280 4 30
840 2 31
90 3 32
400 2 33
334 4 34
840 3 1 35
840 2 36
31 3 1 37
1243 5 1 Sync Cond 2
80 38
280 4 1 39
90 3 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.15

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
50 3 1
840 2 2
1630 10 1 3
3366 9 2 4
760 10 5
3364 9 2 6
90 3 7
200 1 8
134 3 1 9
1260 3 10
672 9 1 Sync Cond 3
144 11
269 3 1 12
1086 10 2 13
1122 3 1 14
108 3 1 15
80 3 16
1646 8 1 SVC 4
200 17
60 3 18
168 3 1 19
420 1 20
540 4 21
80 3 1 22
840 2 23
95 3 24
823 4 1 25
190 4 1 26
254 6 27
1122 3 1 28
48 3 29
400 2 30
40 1 31
823 4 1 32
90 3 1 33
156 4 34
1243 5 1 Sync Cond 3
123 35
90 3 1 36
30 3 1 37
90 3 1 38
90 3 1 39
806 6 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.16

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This
(1)
Report
X
Is:
An Original
(2) A Resubmission
SUBSTATIONS (Continued)
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
End of 2010/Q4
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
Number of Number of
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
Transformers
Spare
(In Service) (In MVa) In Service Transformers
Type of Equipment
Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)
(i)
(j)
(k)
75 6 1
600 2 2
1008 5 1 3
1122 3 1 4
162 4 5
175 1 6
806 6 1 7
3366 9 2 8
90 3 1 9
400 2 10
290 4 1 11
1094 8 12
2244 6 1 13
134 3 1 14
476 7 15
60 3 1 16
134 3 1 17
689 4 1 18
-10 19
57953 440 68 16 687 21
86197 2191 235 26 825 23
20
22
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.17

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 426.14 Line No.: 19 Column: a
The original entries in column f were in two decimal places, which the FERC software
rounds automatically to whole numbers. The entry here is an adjustment to present the
correct total.
Schedule Page: 426.14 Line No.: 21 Column: a
The Distribution Substation section includes substations that are characterized as
Transmission based on the methodology where any substation that has a
transmission-to-transmission transformation (Primary voltage >=60kV and secondary voltage
>= 60kV), is defined as a transmission station, regardless of the number of distribution
assets in the station. There are 600 Distribution Substations and 53 Transmission
Substations with distribution transformer banks. Of the Distribution Substations, there
are 462 substations with => 10 MVa capacity and 138 with < 10 MVa capacity.
Schedule Page: 426.17 Line No.: 19 Column: a
The original entries in column f were in two decimal places, which the FERC software
rounds automatically to whole numbers. The entry here is an adjustment to present the
correct total.
Schedule Page: 426.17 Line No.: 21 Column: a
Substation voltage classes are listed separately for each substation. Substations having
combined total capacity of =>10 MVa are listed individually above. All transmission
substations are =>10MVA. A number of substations contain several voltage classes on
multiple lines. All transmission and distribution substations are unattended.
There are 93 Transmission Substations and 600 Distribution Substations, representing a
total of 693 physical transmission and distribution substations. There are 53 Transmission
Substations with both transmission and distribution transformers.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

Name of Respondent
This Report Is:
Date of Report
Year/Period of Report
(1) X An Original
(Mo, Da, Yr)
PACIFIC GAS AND ELECTRIC COMPANY
End of 2010/Q4
(2) A Resubmission
04/08/2011
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as "general".
3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line
No. Description of the Non-Power Good or Service
(a)
1 Non-power Goods or Services Provided by Affiliated
Name of
Assiciated/Affiliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or Credited
(d)
2 Admin & General Expenses PG&E Corporation 401
55,468,994
3 A&G Direct Chars 2,351,331
4 A&G Allocation 53,117,663
5 Overcollateralization Fee Pacific Energy Recovery 421
1,830,546
6 Interest Expense Pacific Energy Recovery 430
44,727,002
7 Other Expense Standard Pacific Gas 401
861,848
8 Rent Expense Eureka Energy Company 401
265,846
9
10 TOTAL 103,154,236
11
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21 A&G Direct Charges PG&E Corporation 401
6,108,307
22 A&G Direct Charges FUELCO LLC 401
276,161
23 Admin & Service Fees PG&E Energy Recovery 417
2,559,093
24 Admin & General Charges Pacific Energy Fuels 401
518,768
25 A&G Direct Charges PCG Capital Inc 401
647,879
26
27 TOTAL 10,110,207
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (New) Page 429
FERC FORM NO. 1-F (New)

Name of Respondent
PACIFIC GAS AND ELECTRIC COMPANY
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/08/2011
Year/Period of Report
2010/Q4
FOOTNOTE DATA
Schedule Page: 429 Line No.: 4 Column:
The 3-Factor Allocation Method used here is an apportionment factor based on each
subsidiary's relative weighted average of assets, operating expenses excluding fuel, and
headcount.
FERC FORM NO. 1 (ED. 12-87) Page 450.1

SELECTED FINANCIAL DATA - CLASS A, B, C, AND D ELECTRIC UTILITIES
PACIFIC GAS AND ELECTRIC COMPANY
PERSON RESPONSIBLE FOR THIS REPORT: Dinyar Mistry, Vice President and Controller
(PREPARED FROM INFORMATION IN THE 2010 FERC ANNUAL REPORTS)
NET ELECTRIC PLANT INVESTMENT (a)
December 31
2009 2010 Annual Average
Electric Utility Plant (California Only)
1. Intangible Plant $ 653,039,599 $ 721,028,719 $ 687,034,159
2. Land and Land Rights 497,822,413 527,291,709 512,557,061
3. Depreciable Plant 35,727,479,364 38,594,149,912 37,160,814,638
4. Nuclear Fuel 1,995,799,030 2,153,305,377 2,074,552,204
5. Gross Electric Utility Plant 38,874,140,406 41,995,775,717 40,434,958,062
6. Electric Plant Held for Future Use - Net 0 0 0
7. Construction Work in Progress - Electric 1,647,820,850 1,202,202,048 1,425,011,449
8. Accumulated Deferred Income Taxes 464,662,038 628,483,184 546,572,611
9. Less: Reserves for Depreciation - Electric
Utility Plant 18,350,492,520 18,894,048,491 18,622,270,506
10. Less: Amortization and Depletion Reserves 1,852,590,968 1,998,657,166 1,925,624,067
11. Less: Customer Advances and Contribution
in Aid of Construction 118,256,777 110,480,707 114,368,742
12. Less: Accumulated Deferred Income and Investment
Tax Credits 5,150,157,362 5,988,944,882 5,569,551,122
13. Material and Supplies - Electric Only 126,256,678 130,995,767 128,626,223
14. Net Electric Plant Investment $ 15,641,382,345 $ 16,965,325,470 $ 16,303,353,908
CAPITALIZATION (Total Company)
15. Common Stock $ 1,321,874,045 $ 1,321,874,045 $ 1,321,874,045
16. Capital Stock (Premium, Discount and Expense)-Net 1,769,325,445 1,769,325,445 1,769,325,445
17. Other Paid in Capital 1,285,216,984 1,471,315,126 1,378,266,055
18. Retained Earnings 6,551,008,147 6,900,585,718 6,725,796,933
19. Other Miscellaneous Capital Accounts 0 0 0
20. Common Stock and Equity (Lines 15 through 19) 10,927,424,621 11,463,100,334 11,195,262,478
21. Preferred Stock 257,994,575 257,994,575 257,994,575
22. Long-Term Debt 11,356,922,217 12,201,402,470 11,779,162,344
23. Notes Payable and Current Portion of Long-Term Debt 833,000,000 853,033,000 843,016,500
24. Total Capitalization (Lines 20 through 23) $ 23,375,341,413 $ 24,775,530,379 $ 24,075,435,897
(a) Includes Common Plant Allocations.
-
Page 600

PACIFIC GAS AND ELECTRIC COMPANY
INCOME STATEMENT DATA
FOR CALIFORNIA INTRASTATE ELECTRIC OPERATIONS ONLY (b)
Annual Amount
25. Operating Revenues 10,631,037,641
26. Operating and Maintenance Expense 6,735,737,302
27. Depreciation 996,093,798
28. Depreciation for Asset Retirement Costs -
29. Amortization and Depletion Expenses and Property Losses 138,803,626
30. Regulatory Debits 387,947,799
31. Regulatory Credits 63
32. Property Taxes (Ad Valorem) 194,310,400
33. Taxes Other than Income and Property Taxes 89,937,265
34. Operating Revenue Deductions (Before Federal and
California Income Taxes) 8,542,830,253
35. Federal and California Income Taxes - Net 531,105,074
36. Gains and Losses from Disposition of Electric Plant - Net (1,199,581)
37. Accretion Expense -
38. Total Utility Operating Expenses 9,072,735,746
39. Net Operating Income (California Intrastate Electric Operations Only) 1,558,301,895
OTHER INCOME AND EXPENSE (Total Company)
40. Net Operating Income from Other Utility Operations (Total) 276,009,068
41. Net Other Income and Deductions (91,592,428)
42. Income Before Interest Charges 1,742,718,535
43. Interest Charges 621,744,831
44. Income Before Extraordinary Items 1,120,973,704
45. Extraordinary Items - Net of Income Tax -
46. Net Income 1,120,973,704
47. Preferred Stock Dividends and Redemption Premium 13,916,365
48. Income Available for Common Stock $ 1,107,057,339
49. Common Stock Dividends 716,000,000
OTHER DATA (CALIFORNIA INTRASTATE ELECTRIC OPERATIONS ONLY) (b) Items (48-50)
50. Payroll Charged to Operating and Maintenance Expense $ 994,575,373
51. Payroll Capitalized to Utility Plant - Electric 400,607,268
52.Total Payroll $ 1,395,182,641
53. Purchased Power $ 3,633,537,677
54. Allowance for Funds Used During Construction $ 139,777,700
55. Interdepartmental Revenues $ 22,540,420
56. Interdepartmental Expenses $ 123,351,684
57. Revenue from Sales to Residential Customers $ 4,795,501,768
58. Residential Sales in Kwhs 30,744,336,000
59. Total Revenue Sales to Ultimate Customers $ 11,879,407,723
60. Kwhs Sold to Ultimate Customers 84,064,481,000
61. Average Number of Residential Customers 4,565,637
62. Average Number of Ultimate Customers 5,212,596
(b) Assumes CPUC Jurisdictional Portion of Electric Operations.
Page 601