PG&E CORP, 10-Q filed on 10/30/2013
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2013
Oct. 22, 2013
Entity Information [Line Items]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Sep. 30, 2013 
 
Document Fiscal Year Focus
2013 
 
Document Fiscal Period Focus
Q3 
 
Trading Symbol
PCG 
 
Entity Registrant Name
PG&E CORP 
 
Entity Central Index Key
0001004980 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
449,295,292 
Pacific Gas And Electric Company [Member]
 
 
Entity Information [Line Items]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Sep. 30, 2013 
 
Document Fiscal Year Focus
2013 
 
Document Fiscal Period Focus
Q3 
 
Trading Symbol
PCG 
 
Entity Registrant Name
PACIFIC GAS & ELECTRIC CO 
 
Entity Central Index Key
0000075488 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
264,374,809 
Condensed Consolidated Statements Of Income (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Operating Revenues
 
 
 
 
Electric
$ 3,517 
$ 3,323 
$ 9,375 
$ 9,026 
Natural gas
658 
653 
2,248 
2,184 
Total operating revenues
4,175 
3,976 
11,623 
11,210 
Operating Expenses
 
 
 
 
Cost of electricity
1,645 
1,283 
3,817 
3,104 
Cost of natural gas
131 
118 
656 
593 
Operating and maintenance
1,585 
1,344 
4,179 
4,138 
Depreciation, amortization, and decommissioning
523 
617 
1,542 
1,807 
Total operating expenses
3,884 
3,362 
10,194 
9,642 
Operating Income
291 
614 
1,429 
1,568 
Interest income
2 
2 
6 
6 
Interest expense
(179)
(178)
(532)
(528)
Other income, net
26 
26 
78 
84 
Income Before Income Taxes
140 
464 
981 
1,130 
Income tax (benefit) provision
(24)
100 
243 
291 
Net Income
164 
364 
738 
839 
Preferred stock dividend requirement of subsidiary
3 
3 
10 
10 
Income Available for Common Shareholders
161 
361 
728 
829 
Weighted average common shares outstanding, basic
446 
428 
441 
422 
Weighted Average Common Shares Outstanding, Diluted
447 
429 
442 
423 
Net Earnings Per Common Share, Basic
$ 0.36 
$ 0.84 
$ 1.65 
$ 1.96 
Net Earnings Per Common Share, Diluted
$ 0.36 
$ 0.84 
$ 1.65 
$ 1.96 
Dividends Declared Per Common Share
$ 0.46 
$ 0.46 
$ 1.37 
$ 1.37 
Pacific Gas And Electric Company [Member]
 
 
 
 
Operating Revenues
 
 
 
 
Electric
3,517 
3,321 
9,372 
9,022 
Natural gas
657 
653 
2,248 
2,184 
Total operating revenues
4,174 
3,974 
11,620 
11,206 
Operating Expenses
 
 
 
 
Cost of electricity
1,645 
1,283 
3,817 
3,104 
Cost of natural gas
131 
118 
656 
593 
Operating and maintenance
1,583 
1,343 
4,175 
4,134 
Depreciation, amortization, and decommissioning
523 
617 
1,542 
1,807 
Total operating expenses
3,882 
3,361 
10,190 
9,638 
Operating Income
292 
613 
1,430 
1,568 
Interest income
2 
2 
6 
5 
Interest expense
(172)
(172)
(513)
(511)
Other income, net
20 
19 
66 
64 
Income Before Income Taxes
142 
462 
989 
1,126 
Income tax (benefit) provision
(20)
122 
261 
328 
Net Income
162 
340 
728 
798 
Preferred stock dividend requirement
3 
3 
10 
10 
Income Available for Common Shareholders
$ 159 
$ 337 
$ 718 
$ 788 
Condensed Consolidated Statements Of Comprehensive Income (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Net income
$ 164 
$ 364 
$ 738 
$ 839 
Other Comprehensive Income
 
 
 
 
Amortization of prior service cost (net of taxes of $5, $5, $14, and $15, at respective dates)
6 
7 
18 
19 
Amortization of actuarial loss (net of taxes of $11, $12, $35, and $38 for PG&E Corporation, at respective dates, and net of taxes of $11, $12, $34, and $38 for the Utility, at respective dates)
18 
18 
52 
58 
Amortization of transition obligation (net of taxes of $0, $2, $0, and $6, at respective dates)
0 
4 
0 
12 
Transfer to regulatory account (net of taxes of $13, $14, $39, and $44, at repsective dates)
(20)
(21)
(58)
(63)
Gain (loss) on investments (net of taxes of $2, $0, $13, and $0, at respective dates)
(3)
0 
19 
0 
Total other comprehensive income
1 
8 
31 
26 
Comprehensive Income
165 
372 
769 
865 
Preferred stock dividend requirement of subsidiary
3 
3 
10 
10 
Comprehensive Income Attributable to Common Shareholders
162 
369 
759 
855 
Pacific Gas And Electric Company [Member]
 
 
 
 
Net income
162 
340 
728 
798 
Other Comprehensive Income
 
 
 
 
Amortization of prior service cost (net of taxes of $5, $5, $14, and $15, at respective dates)
6 
7 
18 
19 
Amortization of actuarial loss (net of taxes of $11, $12, $35, and $38 for PG&E Corporation, at respective dates, and net of taxes of $11, $12, $34, and $38 for the Utility, at respective dates)
18 
18 
53 
58 
Amortization of transition obligation (net of taxes of $0, $2, $0, and $6, at respective dates)
0 
4 
0 
12 
Transfer to regulatory account (net of taxes of $13, $14, $39, and $44, at repsective dates)
(20)
(21)
(58)
(63)
Total other comprehensive income
4 
8 
13 
26 
Comprehensive Income
$ 166 
$ 348 
$ 741 
$ 824 
Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Amortization of prior service cost, tax
$ 5 
$ 5 
$ 14 
$ 15 
Amortization of actuarial loss, tax
11 
12 
35 
38 
Amortizaiton of transition obligation, tax
0 
2 
0 
6 
Transfer to regulatory account, tax
13 
14 
39 
44 
Gain (loss) on investments, tax
2 
0 
13 
0 
Pacific Gas And Electric Company [Member]
 
 
 
 
Amortization of prior service cost, tax
5 
5 
14 
15 
Amortization of actuarial loss, tax
11 
12 
34 
38 
Amortizaiton of transition obligation, tax
0 
2 
0 
6 
Transfer to regulatory account, tax
$ 13 
$ 14 
$ 39 
$ 44 
Condensed Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Current Assets
 
 
Cash and cash equivalents
$ 281 
$ 401 
Restricted cash
301 
330 
Accounts receivable
 
 
Customers (net of allowance for doubtful accounts of $81 and $87 at respective dates)
1,099 
937 
Accrued unbilled revenue
809 
761 
Regulatory balancing accounts
1,004 
936 
Other
286 
365 
Regulatory assets
483 
564 
Inventories
 
 
Gas stored underground and fuel oil
184 
135 
Materials and supplies
316 
309 
Income taxes receivable
377 
211 
Other
382 
172 
Total current assets
5,522 
5,121 
Property, Plant, and Equipment
 
 
Electric
41,939 
39,701 
Gas
13,381 
12,571 
Construction work in progress
1,996 
1,894 
Other
1 
1 
Total property, plant, and equipment
57,317 
54,167 
Accumulated depreciation
(17,560)
(16,644)
Net property, plant, and equipment
39,757 
37,523 
Other Noncurrent Assets
 
 
Regulatory assets
6,827 
6,809 
Nuclear decommissioning trusts
2,272 
2,161 
Income taxes receivable
163 
176 
Other
673 
659 
Total other noncurrent assets
9,935 
9,805 
TOTAL ASSETS
55,214 
52,449 
Current Liabilities
 
 
Short-term borrowings
953 
492 
Long-term debt, classified as current
1,288 
400 
Accounts payable
 
 
Trade creditors
1,303 
1,241 
Disputed claims and customer refunds
156 
157 
Regulatory balancing accounts
1,002 
634 
Other
388 
444 
Interest payable
852 
870 
Income taxes payable
39 
6 
Deferred income taxes
1,663 
2,012 
Other
7,644 
6,256 
Total current liabilities
   
   
Noncurrent Liabilities
 
 
Long-term debt
11,918 
12,517 
Regulatory liabilities
5,343 
5,088 
Pension and other postretirement benefits
3,711 
3,575 
Asset retirement obligations
2,946 
2,919 
Deferred income taxes
7,275 
6,748 
Other
2,117 
2,020 
Total noncurrent liabilities
33,310 
32,867 
Commitments and Contingencies (Note 10)
   
   
Shareholders' Equity
 
 
Preferred stock
0 
0 
Common stock
9,212 
8,428 
Reinvested earnings
4,866 
4,747 
Accumulated other comprehensive loss
(70)
(101)
Total shareholders' equity
14,008 
13,074 
Noncontrolling Interest - Preferred Stock of Subsidiary
252 
252 
Total equity
14,260 
13,326 
TOTAL LIABILITIES AND EQUITY
55,214 
52,449 
Pacific Gas And Electric Company [Member]
 
 
Current Assets
 
 
Cash and cash equivalents
60 
194 
Restricted cash
301 
330 
Accounts receivable
 
 
Customers (net of allowance for doubtful accounts of $81 and $87 at respective dates)
1,099 
937 
Accrued unbilled revenue
809 
761 
Regulatory balancing accounts
1,004 
936 
Other
289 
366 
Regulatory assets
483 
564 
Inventories
 
 
Gas stored underground and fuel oil
184 
135 
Materials and supplies
316 
309 
Income taxes receivable
377 
186 
Other
344 
160 
Total current assets
5,266 
4,878 
Property, Plant, and Equipment
 
 
Electric
41,939 
39,701 
Gas
13,381 
12,571 
Construction work in progress
1,996 
1,894 
Total property, plant, and equipment
57,316 
54,166 
Accumulated depreciation
(17,559)
(16,643)
Net property, plant, and equipment
39,757 
37,523 
Other Noncurrent Assets
 
 
Regulatory assets
6,827 
6,809 
Nuclear decommissioning trusts
2,272 
2,161 
Income taxes receivable
158 
171 
Other
411 
381 
Total other noncurrent assets
9,668 
9,522 
TOTAL ASSETS
54,691 
51,923 
Current Liabilities
 
 
Short-term borrowings
693 
372 
Long-term debt, classified as current
938 
400 
Accounts payable
 
 
Trade creditors
1,303 
1,241 
Disputed claims and customer refunds
156 
157 
Regulatory balancing accounts
1,002 
634 
Other
404 
419 
Interest payable
841 
865 
Income taxes payable
49 
12 
Deferred income taxes
1,443 
1,794 
Other
6,829 
5,894 
Total current liabilities
   
   
Noncurrent Liabilities
 
 
Long-term debt
11,918 
12,167 
Regulatory liabilities
5,343 
5,088 
Pension and other postretirement benefits
3,628 
3,497 
Asset retirement obligations
2,946 
2,919 
Deferred income taxes
7,484 
6,939 
Other
2,055 
1,959 
Total noncurrent liabilities
33,374 
32,569 
Commitments and Contingencies (Note 10)
   
   
Shareholders' Equity
 
 
Preferred stock
258 
258 
Common stock
1,322 
1,322 
Additional paid-in capital
5,516 
4,682 
Reinvested earnings
7,472 
7,291 
Accumulated other comprehensive loss
(80)
(93)
Total shareholders' equity
14,488 
13,460 
TOTAL LIABILITIES AND EQUITY
$ 54,691 
$ 51,923 
Condensed Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Allowance for doubtful accounts
$ 81 
$ 87 
Common stock, par value
$ 0 
$ 0 
Common stock, shares authorized
800,000,000 
800,000,000 
Common stock, shares outstanding
448,590,070 
430,718,293 
Pacific Gas And Electric Company [Member]
 
 
Allowance for doubtful accounts
$ 81 
$ 87 
Common stock, par value
$ 5 
$ 5 
Common stock, shares authorized
800,000,000 
800,000,000 
Common stock, shares outstanding
264,374,809 
264,374,809 
Condensed Consolidated Statements Of Cash Flows (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Cash Flows from Operating Activities
 
 
Net income
$ 738 
$ 839 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation, amortization, and decommissioning
1,542 
1,807 
Allowance for equity funds used during construction
(78)
(79)
Deferred income taxes and tax credits, net
527 
624 
Disallowed capital expenditures
196 
0 
Other
274 
230 
Effect of changes in operating assets and liabilities:
 
 
Accounts receivable
(160)
(326)
Inventories
(56)
(34)
Accounts payable
84 
(55)
Income taxes receivable/payable
(133)
69 
Other current assets and liabilities
(269)
16 
Regulatory assets, liabilities, and balancing accounts, net
12 
66 
Other noncurrent assets and liabilities
156 
295 
Net cash provided by operating activities
2,833 
3,452 
Cash Flows from Investing Activities
 
 
Capital expenditures
(3,881)
(3,361)
Decrease (Increase) in restricted cash
29 
(38)
Proceeds from sales and maturities of nuclear decommissioning trust investments
1,152 
903 
Purchases of nuclear decommissioning trust investments
(1,150)
(964)
Other
37 
101 
Net cash used in investing activities
(3,813)
(3,359)
Cash Flows from Financing Activities
 
 
Borrowings under revolving credit facilities
140 
0 
Net issuances (repayments) of commercial paper, net of discount of $1 and $3 at respective dates
322 
(1,247)
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $9 and $10 at respective dates
741 
1,140 
Long-term debt matured or repurchased
(461)
(50)
Energy recovery bonds matured
0 
(313)
Common stock issued
724 
702 
Common stock dividends paid
(583)
(556)
Other
(23)
14 
Net cash provided by (used in) financing activities
860 
(310)
Net change in cash and cash equivalents
(120)
(217)
Cash and cash equivalents at January 1
401 
513 
Cash and cash equivalents at September 30
281 
296 
Cash received (paid) for:
 
 
Interest, net of amounts capitalized
(499)
(486)
Income taxes, net
(65)
114 
Supplemental disclosures of noncash investing and financing activities
 
 
Common stock dividends declared but not yet paid
204 
195 
Capital expenditures financed through accounts payable
277 
228 
Noncash common stock issuances
17 
18 
Terminated capital leases
0 
136 
Pacific Gas And Electric Company [Member]
 
 
Cash Flows from Operating Activities
 
 
Net income
728 
798 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation, amortization, and decommissioning
1,542 
1,807 
Allowance for equity funds used during construction
(78)
(79)
Deferred income taxes and tax credits, net
545 
633 
Disallowed capital expenditures
196 
0 
Other
231 
189 
Effect of changes in operating assets and liabilities:
 
 
Accounts receivable
(162)
(327)
Inventories
(56)
(34)
Accounts payable
125 
(31)
Income taxes receivable/payable
(154)
153 
Other current assets and liabilities
(250)
15 
Regulatory assets, liabilities, and balancing accounts, net
12 
66 
Other noncurrent assets and liabilities
147 
315 
Net cash provided by operating activities
2,826 
3,505 
Cash Flows from Investing Activities
 
 
Capital expenditures
(3,881)
(3,361)
Decrease (Increase) in restricted cash
29 
(38)
Proceeds from sales and maturities of nuclear decommissioning trust investments
1,152 
903 
Purchases of nuclear decommissioning trust investments
(1,150)
(964)
Other
14 
14 
Net cash used in investing activities
(3,836)
(3,446)
Cash Flows from Financing Activities
 
 
Net issuances (repayments) of commercial paper, net of discount of $1 and $3 at respective dates
322 
(1,247)
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $9 and $10 at respective dates
741 
1,140 
Long-term debt matured or repurchased
(461)
(50)
Energy recovery bonds matured
0 
(313)
Preferred stock dividends paid
(10)
(10)
Common stock dividends paid
(537)
(537)
Equity contribution
835 
715 
Other
(14)
25 
Net cash provided by (used in) financing activities
876 
(277)
Net change in cash and cash equivalents
(134)
(218)
Cash and cash equivalents at January 1
194 
304 
Cash and cash equivalents at September 30
60 
86 
Cash received (paid) for:
 
 
Interest, net of amounts capitalized
(487)
(476)
Income taxes, net
(86)
174 
Supplemental disclosures of noncash investing and financing activities
 
 
Capital expenditures financed through accounts payable
277 
228 
Terminated capital leases
$ 0 
$ 136 
Condensed Consolidated Statements Of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Net issuances of commercial paper, discount
$ 1 
$ 3 
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs
9 
10 
Pacific Gas And Electric Company [Member]
 
 
Net issuances of commercial paper, discount
1 
3 
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs
$ 9 
$ 10 
Organization And Basis Of Presentation
Organization And Basis Of Presentation
 
NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
 
PG&E Corporation is a holding company that conducts its business through Pacific Gas and Electric Company, 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 primarily regulated by the CPUC and the FERC.  In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility's nuclear generation facilities.  The Utility's accounts for electric and gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.
 
This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility that includes separate Condensed Consolidated Financial Statements for each company.  The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  PG&E Corporation's Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.  The Utility's Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries.  All intercompany transactions have been eliminated.  PG&E Corporation and the Utility operate in one segment.
 
The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with GAAP for interim financial statements and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the U.S. Securities and Exchange Commission and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements.  PG&E Corporation's and the Utility's Condensed Consolidated Financial Statements reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of their financial condition, results of operations, and cash flows for the periods presented.  The information at December 31, 2012 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2012 Annual Report.  This quarterly report should be read in conjunction with the 2012 Annual Report.  
 
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, legal and regulatory contingencies, environmental remediation liabilities, asset retirement obligations, and pension and other postretirement benefit plans obligations.  Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable.  Actual results could differ materially from those estimates.
 
 
New And Significant Accounting Policies
New And Significant Accounting Policies
 
NOTE 2: SIGNIFICANT ACCOUNTING POLICIES
 
The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2012 Annual Report.
 
Variable Interest Entities
 
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 that has a controlling financial interest in a VIE is known as the VIE's primary beneficiary and is required to consolidate the VIE.  In determining whether consolidation of a particular entity is required, PG&E Corporation and the Utility first evaluate whether the entity is a VIE.  If the entity is a VIE, PG&E Corporation and the Utility use a qualitative approach to determine if either is the primary beneficiary of the VIE.
 
Some of the counterparties to the Utility's power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs at September 30, 2013, it assessed whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE's gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE's performance, such as dispatch rights and operating and maintenance activities.  The Utility's financial exposure is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 2013, it did not consolidate any of them.
 
PG&E Corporation affiliates have entered into four tax equity agreements to fund residential and commercial retail solar energy installations with four separate privately held funds that are considered VIEs.  Under these agreements, PG&E Corporation has made cumulative lease payments and investment contributions of $363 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies.  At September 30, 2013 and December 31, 2012, the carrying amount of PG&E Corporation's investment in these agreements was $138 million and $166 million, respectively.  PG&E Corporation determined that it does not have control over the companies' significant economic activities, such as the design of the companies, vendor selection, construction, and the ongoing operations of the companies.  PG&E Corporation has no material remaining commitment to fund these agreements.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs at September 30, 2013, it did not consolidate any of them.  
 
Pension and Other Postretirement Benefits
 
PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees, as well as contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.
 
The net periodic benefit costs reflected in PG&E Corporation's Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2013 and 2012 were as follows:
 
 
Pension Benefits
 
Other Benefits
 
Three Months Ended September 30,
(in millions)
2013
 
2012
 
2013
 
2012
Service cost for benefits earned
$
121
 
$
100
 
$
14
 
$
14
Interest cost
 
158
 
 
165
 
 
19
 
 
21
Expected return on plan assets
 
(162
 ) 
 
(150
 ) 
 
(20
 ) 
 
(19
)
Amortization of transition obligation
 
-
 
 
-
 
 
-
 
 
6
Amortization of prior service cost
 
5
 
 
5
 
 
6
 
 
7
Amortization of net actuarial loss
 
28
 
 
29
 
 
1
 
 
1
Net periodic benefit cost
 
150
 
 
149
 
 
20
 
 
30
Less: transfer to regulatory account (1)
 
(66
 ) 
 
(75
 ) 
 
-
 
 
-
Total
$
84
 
$
74
 
$
20
 
$
30
 
 
 
 
 
 
 
 
 
 
 
 
 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from customers in futures rates.
 
 
Pension Benefits
 
Other Benefits
 
Nine Months Ended September 30,
(in millions)
2013
 
2012
 
2013
 
2012
Service cost for benefits earned
$
351
 
$
297
 
$
40
 
$
37
Interest cost
 
470
 
 
494
 
 
56
 
 
63
Expected return on plan assets
 
(487
 ) 
 
(449
 ) 
 
(60
 ) 
 
(58
)
Amortization of transition obligation
 
-
 
 
-
 
 
-
 
 
18
Amortization of prior service cost
 
15
 
 
15
 
 
17
 
 
19
Amortization of net actuarial loss
 
83
 
 
92
 
 
4
 
 
4
Net periodic benefit cost
 
432
 
 
449
 
 
57
 
 
83
Less: transfer to regulatory account (1)
 
(179
 ) 
 
(225
 ) 
 
-
 
 
-
Total
$
253
 
$
224
 
$
57
 
$
83
 
 
 
 
 
 
 
 
 
 
 
 
 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from customers in future rates.
 
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
 
Adoption of New Accounting Pronouncements
 
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
 
In February 2013, the Financial Accounting Standards Board issued an ASU that requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income.  The ASU became effective for PG&E Corporation and the Utility on January 1, 2013. 
 
The changes, net of income tax, in PG&E Corporation's accumulated other comprehensive income (loss) for the three and nine months ended September 30, 2013 consist of the following:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension
 
Other
 
Other
 
 
 
 
Benefits
 
Benefits
 
Investments
 
Total
(in millions, net of income tax)
Three Months Ended September 30, 2013
Beginning balance
$
(28
 ) 
$
(69
 ) 
$
26
 
$
(71
)
Other comprehensive income before reclassifications
 
(20
 ) 
 
-
 
 
(3
 ) 
 
(23
)
Amounts reclassified from other comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
      Amortization of prior service cost (1)
 
3
 
 
3
 
 
-
 
 
6
      Amortization of net actuarial loss (1)
 
17
 
 
1
 
 
-
 
 
18
Net current period other comprehensive income (loss)
 
-
 
 
4
 
 
(3)
 
 
1
Ending balance
$
(28)
 
$
(65)
 
$
23
 
$
(70)
 
 
 
 
 
 
 
 
 
 
 
 
 (1) These components are included in the computation of net periodic pension and other postretirement costs.  (See the “Pension and Other Postretirement Benefits” table above for additional details.)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension
 
Other
 
Other
 
 
 
 
Benefits
 
Benefits
 
Investments
 
Total
(in millions, net of income tax)
Nine Months Ended September 30, 2013
Beginning balance
$
(28
 ) 
$
(77
 ) 
$
4
 
$
(101
)
Other comprehensive income before reclassifications
 
(58
 ) 
 
-
 
 
19
 
 
(39
)
Amounts reclassified from other comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
      Amortization of prior service cost (1)
 
9
 
 
9
 
 
-
 
 
18
      Amortization of net actuarial loss (1)
 
49
 
 
3
 
 
-
 
 
52
Net current period other comprehensive income (loss)
 
-
 
 
12
 
 
19
 
 
31
Ending balance
$
(28)
 
$
(65)
 
$
23
 
$
(70)
 
 
 
 
 
 
 
 
 
 
 
 
 (1) These components are included in the computation of net periodic pension and other postretirement costs.  (See the “Pension and Other Postretirement Benefits” table above for additional details.)
 
There was no material difference between PG&E Corporation and the Utility for the information disclosed above, with the exception of other investments which are held by PG&E Corporation.
 
Disclosures about Offsetting Assets and Liabilities
 
In January 2013, the Financial Accounting Standards Board issued an ASU that clarifies the scope of disclosures about offsetting assets and liabilities.  The guidance requires an entity to disclose gross and net information about derivatives that are offset in the balance sheet or subject to an enforceable master-netting arrangement or similar agreement.  The ASU became effective for PG&E Corporation and the Utility on January 1, 2013.  (See Note 7 below.)
 
Regulatory Assets, Liabilities, And Balancing Accounts
Regulatory Assets, Liabilities, And Balancing Accounts
 
NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
 
Regulatory Assets
 
Long-Term Regulatory Assets
 
Long-term regulatory assets are composed of the following:
 
 
 
Balance at
 
September 30,
 
December 31,
(in millions)
2013
 
2012
Pension benefits
$
3,356
 
$
3,275
Deferred income taxes
 
1,772
 
 
1,627
Utility retained generation
 
515
 
 
552
Environmental compliance costs
 
609
 
 
604
Price risk management
 
144
 
 
210
Electromechanical meters
 
150
 
 
194
Unamortized loss, net of gain, on reacquired debt
 
140
 
 
141
Other
 
141
 
 
206
Total long-term regulatory assets
$
6,827
 
$
6,809
 
 
Regulatory Liabilities
 
Long-Term Regulatory Liabilities
 
Long-term regulatory liabilities are composed of the following:
 
 
 
Balance at
 
September 30,
 
December 31,
(in millions)
2013
 
2012
Cost of removal obligations
$
3,805
 
$
3,625
Recoveries in excess of asset retirement obligations
 
674
 
 
620
Public purpose programs
 
594
 
 
590
Other
 
270
 
 
253
Total long-term regulatory liabilities
$
5,343
 
$
5,088
 
Regulatory Balancing Accounts
 
                                                The Utility's recovery of a significant portion of revenue requirements and costs is decoupled from the volume of sales.  The Utility records (1) differences between actual customer billings and the Utility's authorized revenue requirement, and (2) differences between incurred costs and customer billings.  To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account receivable or payable.  Regulatory balancing accounts receivable and payable will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.
Current Regulatory Balancing Accounts, Net
 
 
Receivable (Payable)
 
Balance at
 
September 30,
 
December 31,
(in millions)
2013
 
2012
Distribution revenue adjustment mechanism
$
(3
 ) 
$
219
Utility generation
 
(22
 ) 
 
117
Hazardous substance
 
75
 
 
56
Public purpose programs
 
(100
 ) 
 
(83
)
Gas fixed cost
 
179
 
 
44
Energy recovery bonds
 
(170
 ) 
 
(43
)
Energy procurement
 
281
 
 
77
U.S. Department of Energy Settlement
 
(279
 ) 
 
(250
)
GHG allowance auction proceeds (1)
 
(250
 ) 
 
-
Other
 
291
 
 
165
Total regulatory balancing accounts, net
$
2
 
$
302
 
 
 
 
 
 
 
      (1) The CARB has adopted regulations that established a state-wide, “cap-and-trade” program (effective January 1, 2013) that sets a
      gradually declining limit on the amount of GHGs that may be emitted each year. This balancing account is used to record proceeds
      collected by the Utility for GHG emission allowances associated with the cap-and-trade program.  These amounts will be refunded
      to customers in future periods.  
 
 
 
Debt
Debt
NOTE 4: DEBT
 
Senior Notes
 
In June 2013, the Utility issued $375 million principal amount of 3.25% Senior Notes due June 15, 2023 and $375 million principal amount of 4.60% Senior Notes due June 15, 2043.  The proceeds were used to repurchase $461 million principal amount, net of $15 million of premiums and $6 million of accrued interest, of the Utility's $1.0 billion outstanding 4.80% Senior Notes due March 1, 2014, to repay a portion of outstanding commercial paper, and for general corporate purposes.
 
Revolving Credit Facilities
 
                                    In April 2013, PG&E Corporation and the Utility amended and restated their revolving credit facilities to extend their termination dates from May 31, 2016 to April 1, 2018.  These agreements contain substantially similar terms as their original 2011 credit agreements.  
 
At September 30,  2013, PG&E Corporation had $260 million of cash borrowings and no letters of credit outstanding under its $300 million revolving credit facility.
 
At September 30,  2013, the Utility had no cash borrowings and $91 million of letters of credit outstanding under its $3.0 billion revolving credit facility.
 
Pollution Control Bonds
 
At September 30, 2013, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.05% to 0.07%.  At September 30, 2013, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.01% to 0.04%.
      
Commercial Paper Program
 
At September 30, 2013, the Utility had $693 million of commercial paper outstanding supported by available capacity under its revolving credit facility.
Equity
Equity
NOTE 5: EQUITY
 
PG&E Corporation's and the Utility's changes in equity for the nine months ended September 30, 2013 were as follows:
 
 
 
 
 
 
PG&E Corporation
 
Utility
 
Total
 
Total
(in millions)
Equity
 
Shareholders' Equity
Balance at December 31, 2012
$
13,326
 
$
13,460
Comprehensive income
 
769
 
 
741
Equity contributions
 
-
 
 
835
Common stock issued
 
741
 
 
-
Share-based compensation expense
 
43
 
 
(1
)
Common stock dividends declared
 
(609
 ) 
 
(537
)
Preferred stock dividend requirement
 
-
 
 
(10
)
Preferred stock dividend requirement of subsidiary
 
(10
 ) 
 
-
Balance at September 30, 2013
$
14,260
 
$
14,488
 
 
 
 
 
 
In May 2013, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $400 million.  As of September 30, 2013, PG&E Corporation sold common stock having an aggregate gross sales price of $150 million under this agreement.  During the three and nine months ended September 30, 2013, PG&E Corporation paid commissions of $1 million, respectively, under this agreement.
 
During the nine months ended September 30, 2013, PG&E Corporation issued 18 million shares of its common stock for aggregate net cash proceeds of $724 million in the following transactions:
  • 7 million shares were sold in an underwritten public offering for cash proceeds of $300 million, net of fees and commissions;
  • 6 million shares were issued for cash proceeds of $212 million under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans; and
  • 5 million shares were sold for cash proceeds of $212 million, net of commissions paid of $2 million, under equity distribution agreements.    
Earnings Per Share
Earnings Per Share
NOTE 6: EARNINGS PER SHARE
 
PG&E Corporation's basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-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 common shares outstanding for calculating diluted EPS:
 
 
Three Months Ended
 
Nine Months Ended
 
 September 30,
 
 September 30,
(in millions, except per share amounts)
2013
 
2012
 
2013
 
2012
Income available for common shareholders
$
161
 
$
361
 
$
728
 
$
829
Weighted average common shares outstanding, basic
 
446
 
 
428
 
 
441
 
 
422
Add incremental shares from assumed conversions:
 
 
 
 
 
 
 
 
 
 
 
Employee share-based compensation
 
1
 
 
1
 
 
1
 
 
1
Weighted average common share outstanding, diluted
 
447
 
 
429
 
 
442
 
 
423
Total earnings per common share, diluted
$
0.36
 
$
0.84
 
$
1.65
 
$
1.96
 
For each of the periods presented above, the calculation of weighted average common shares outstanding on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.
Derivatives
Derivatives
 
NOTE 7: DERIVATIVES
 
                                                The Utility uses both derivative and non-derivative contracts in managing its exposure to commodity-related price risk, including forward contracts, swap agreements, futures contracts, and option contracts.
 
These instruments are not held for speculative purposes and are subject to certain regulatory requirements.  Customer rates are designed to recover the Utility's reasonable costs of providing services, including the costs related to price risk management activities.
 
Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets.  As long as the current ratemaking mechanism remains in place and the Utility's price risk management activities are carried out in accordance with CPUC directives, the Utility expects to recover fully, in rates, all costs related to derivatives.  Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility's regulatory assets and liabilities.  (See Note 3 above.)  Net realized gains or losses on commodity derivatives 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 or refund to customers.
 
The Utility elects the normal purchase and sale exception for eligible derivatives.  Derivatives that require 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 derivatives that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.
 
Presentation of Derivative Instruments in the Financial Statements
 
In the Condensed Consolidated Balance Sheets, derivatives are presented on a net basis by counterparty where the right and the intention to offset exists under a master netting agreement.  All derivatives that are subject to a master netting arrangement have been netted.  The net balances include outstanding cash collateral associated with derivative positions.
 
At September 30, 2013, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:
 
 
 
Commodity Risk
 
Gross Derivative
 
 
 
 
 
Total Derivative
(in millions)
Balance
 
Netting
 
Cash Collateral
 
Balance
Current assets - other
$
31
 
$
(12
 ) 
$
19
 
$
38
Other noncurrent assets - other
 
66
 
 
(5
 ) 
 
-
 
 
61
Current liabilities - other
 
(162
 ) 
 
12
 
 
106
 
 
(44
)
Noncurrent liabilities - other
 
(149
 ) 
 
5
 
 
23
 
 
(121
)
Total commodity risk
$
(214)
 
$
-
 
$
148
 
$
(66)
 
 
At December 31, 2012, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:
 
 
 
Commodity Risk
 
Gross Derivative
 
 
 
 
 
Total Derivative
(in millions)
Balance
 
Netting
 
Cash Collateral
 
Balance
Current assets - other
$
48
 
$
(25
 ) 
$
36
 
$
59
Other noncurrent assets - other
 
99
 
 
(11
 ) 
 
-
 
 
88
Current liabilities - other
 
(255
 ) 
 
25
 
 
115
 
 
(115
)
Noncurrent liabilities - other
 
(221
 ) 
 
11
 
 
14
 
 
(196
)
Total commodity risk
$
(329)
 
$
-
 
$
165
 
$
(164)
 
 
                        Gains and losses associated with price risk management activities were recorded as follows:
 
 
Commodity Risk
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
(in millions)
2013
 
2012
 
2013
 
2012
Unrealized gain - regulatory assets and liabilities (1)
$
40
 
$
162
 
$
115
 
$
327
Realized loss - cost of electricity (2)
 
(57
 ) 
 
(108
 ) 
 
(136
 ) 
 
(383
)
Realized loss - cost of natural gas (2)
 
(2
 ) 
 
(5
 ) 
 
(14
 ) 
 
(32
)
Total commodity risk
$
(19)
 
$
49
 
$
(35)
 
$
(88)
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the  Condensed 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.
 
 
Volume of Derivative Activity
 
At September 30, 2013, the volumes of PG&E Corporation's and the Utility's outstanding derivatives were as follows:
 
 
 
 
 
Contract Volume (1)
 
 
 
 
 
 
1 Year or
 
3 Years or
 
 
 
 
 
 
 
 
Greater but
 
Greater but
 
 
 
 
 
 
Less Than 1
 
Less Than 3
 
Less Than 5
 
5 Years or
Underlying Product
 
Instruments
 
Year
 
Years
 
 Years
 
Greater (2)
Natural Gas (3)
 
Forwards and
 
 
 
 
 
 
 
 
(MMBtus (4))
 
Swaps
 
282,212,809
 
84,938,674
 
4,907,500
 
-
 
 
Options
 
206,604,635
 
115,753,835
 
1,500,000
 
-
Electricity
 
Forwards and
 
 
 
 
 
 
 
 
(Megawatt-hours)
 
Swaps
 
2,537,023
 
2,396,080
 
2,008,046
 
1,685,781
 
 
Options
 
95,158
 
239,233
 
239,015
 
24,350
 
 
Congestion
 
 
 
 
 
 
 
 
 
 
Revenue Rights
 
57,166,228
 
78,318,934
 
60,465,135
 
11,609,557
 
 
 
 
 
 
 
 
 
 
 
 
(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period.
      (2) Derivatives in this category expire between 2018 and 2022.
      (3) Amounts shown are for the combined positions of the electric fuels and core gas portfolios.
(4) Million British Thermal Units.
 
At December 31, 2012, the volumes of PG&E Corporation's and the Utility's outstanding derivatives were as follows:
 
 
 
 
 
Contract Volume (1)
 
 
 
 
 
 
1 Year or
 
3 Years or
 
 
 
 
 
 
 
 
Greater but
 
Greater but
 
 
 
 
 
 
Less Than 1
 
Less Than 3
 
Less Than 5
 
5 Years or
Underlying Product
 
Instruments
 
Year
 
Years
 
 Years
 
Greater (2)
Natural Gas (3)
 
Forwards and
 
 
 
 
 
 
 
 
(MMBtus (4))
 
Swaps
 
329,466,510
 
98,628,398
 
5,490,000
 
-
 
 
Options
 
221,587,431
 
216,279,767
 
10,050,000
 
-
Electricity
 
Forwards and
 
 
 
 
 
 
 
 
(Megawatt-hours)
 
Swaps
 
2,537,023
 
3,541,046
 
2,009,505
 
2,538,718
 
 
Options
 
-
 
239,015
 
239,233
 
119,508
 
 
Congestion
 
 
 
 
 
 
 
 
 
 
Revenue Rights
 
74,198,690
 
74,187,803
 
74,240,147
 
25,699,804
 
 
 
 
 
 
 
 
 
 
 
 
(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period.
(2) Derivatives in this category expire between 2018 and 2022.
(3) Amounts shown are for the combined positions of the electric fuels and core gas portfolios.
(4) Million British Thermal Units.
 
The majority of the Utility's derivatives 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 was to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions.  At September 30, 2013, the Utility's credit rating was investment grade.  
 
The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:
 
 
 
Balance at
 
September 30,
 
December 31,
(in millions)
2013
 
2012
Derivatives in a liability position with credit risk-related
 
 
 
 
 
 contingencies that are not fully collateralized
$
(133
 ) 
$
(266
)
Related derivatives in an asset position
 
29
 
 
59
Collateral posting in the normal course of business related to
 
 
 
 
 
these derivatives
 
112
 
 
103
Net position of derivative contracts/additional collateral
 
 
 
 
 
posting requirements (1)
$
8
 
$
(104)
 
 
 
 
 
 
 (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.
 
Fair Value Measurements
Fair Value Measurements
 
NOTE 8: FAIR VALUE MEASUREMENTS
 
PG&E Corporation and the Utility measure their cash equivalents, trust assets, price risk management instruments, and other investments 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 - 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 (assets held in rabbi trusts and other investments are held by PG&E Corporation and not the Utility):
 
 
Fair Value Measurements
 
At  September 30, 2013
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting (1)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
214
 
$
-
 
$
-
 
$
-
 
$
214
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
26
 
 
-
 
 
-
 
 
-
 
 
26
  U.S. equity securities
 
1,009
 
 
10
 
 
-
 
 
-
 
 
1,019
  Non-U.S. equity securities
 
435
 
 
-
 
 
-
 
 
-
 
 
435
  U.S. government and agency securities
 
782
 
 
148
 
 
-
 
 
-
 
 
930
  Municipal securities
 
-
 
 
26
 
 
-
 
 
-
 
 
26
  Other fixed-income securities
 
-
 
 
128
 
 
-
 
 
-
 
 
128
Total nuclear decommissioning trusts (2)
 
2,252
 
 
312
 
 
-
 
 
-
 
 
2,564
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
 
1
 
 
27
 
 
65
 
 
2
 
 
95
  Gas
 
-
 
 
4
 
 
-
 
 
-
 
 
4
Total price risk management instruments
 
1
 
 
31
 
 
65
 
 
2
 
 
99
Rabbi trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Fixed-income securities
 
-
 
 
30
 
 
-
 
 
-
 
 
30
  Life insurance contracts
 
-
 
 
70
 
 
-
 
 
-
 
 
70
Total rabbi trusts
 
-
 
 
100
 
 
-
 
 
-
 
 
100
Long-term disability trust
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
5
 
 
-
 
 
-
 
 
-
 
 
5
  U.S. equity securities
 
-
 
 
11
 
 
-
 
 
-
 
 
11
  Non-U.S. equity securities
 
-
 
 
10
 
 
-
 
 
-
 
 
10
  Fixed-income securities
 
-
 
 
116
 
 
-
 
 
-
 
 
116
Total long-term disability trust
 
5
 
 
137
 
 
-
 
 
-
 
 
142
Other investments
 
51
 
 
-
 
 
-
 
 
-
 
 
51
Total assets
$
2,523
 
$
580
 
$
65
 
$
2
 
$
3,170
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
$
53
 
$
100
 
$
147
 
$
(140
 ) 
$
160
  Gas
 
6
 
 
5
 
 
-
 
 
(6
 ) 
 
5
Total liabilities
$
59
 
$
105
 
$
147
 
$
(146)
 
$
165
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $292 million of deferred taxes primarily related to appreciation of investment value.
 
 
 
Fair Value Measurements
 
At December 31, 2012
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting (1)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
209
 
$
-
 
$
-
 
$
-
 
$
209
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
21
 
 
-
 
 
-
 
 
-
 
 
21
  U.S. equity securities
 
940
 
 
9
 
 
-
 
 
-
 
 
949
  Non-U.S. equity securities
 
379
 
 
-
 
 
-
 
 
-
 
 
379
  U.S. government and agency securities
 
681
 
 
139
 
 
-
 
 
-
 
 
820
  Municipal securities
 
-
 
 
59
 
 
-
 
 
-
 
 
59
  Other fixed-income securities
 
-
 
 
173
 
 
-
 
 
-
 
 
173
Total nuclear decommissioning trusts (2)
 
2,021
 
 
380
 
 
-
 
 
-
 
 
2,401
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
 
1
 
 
60
 
 
80
 
 
6
 
 
147
  Gas
 
-
 
 
5
 
 
1
 
 
(6
 ) 
 
-
Total price risk management instruments
 
1
 
 
65
 
 
81
 
 
-
 
 
147
Rabbi trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Fixed-income securities
 
-
 
 
30
 
 
-
 
 
-
 
 
30
  Life insurance contracts
 
-
 
 
72
 
 
-
 
 
-
 
 
72
Total rabbi trusts
 
-
 
 
102
 
 
-
 
 
-
 
 
102
Long-term disability trust
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
10
 
 
-
 
 
-
 
 
-
 
 
10
  U.S. equity securities
 
-
 
 
14
 
 
-
 
 
-
 
 
14
  Non-U.S. equity securities
 
-
 
 
11
 
 
-
 
 
-
 
 
11
  Fixed-income securities
 
-
 
 
136
 
 
-
 
 
-
 
 
136
Total long-term disability trust
 
10
 
 
161
 
 
-
 
 
-
 
 
171
Total assets
$
2,241
 
$
708
 
$
81
 
$
-
 
$
3,030
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
$
155
 
$
144
 
$
160
 
$
(156
 ) 
$
303
  Gas
 
8
 
 
9
 
 
-
 
 
(9
 ) 
 
8
Total liabilities
$
163
 
$
153
 
$
160
 
$
(165)
 
$
311
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $240 million of deferred taxes primarily related to appreciation of investment value.
 
Valuation Techniques
 
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.  All investments that are valued using a net asset value per share can be redeemed quarterly with notice not to exceed 90 days.
 
Money Market Investments
 
PG&E Corporation and the Utility invest 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 U.S. Treasury bills, U.S. agency securities, certificates of deposit, and commercial paper with a maximum weighted average maturity of 60 days or less.  PG&E Corporation's and the Utility's investments in these money market funds are valued using unadjusted prices for identical assets in an active market and are thus classified as Level 1.  Money market funds are recorded as cash and cash equivalents in the Condensed 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 composed primarily of equity securities, debt securities, and life insurance policies.  In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.
 
Equity securities primarily include investments in common stock, which are valued based on unadjusted prices for identical securities in active markets and are classified as Level 1.  Equity securities also include commingled funds, that are valued using a net asset value per share and are composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world and are classified as Level 2.  Price quotes for the assets held by these funds are readily observable and available.
 
Debt securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of debt securities classified as Level 2.  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 ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.
 
Price Risk Management Instruments
 
Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.  
 
Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model.  Exchange-traded forwards and swaps that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded forwards and swaps or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.  Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3.  These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.    
 
The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  CRRs are valued based on prices observed in the CAISO auction, which are discounted at the risk-free rate.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions.  CRRs are classified as Level 3.
 
Other Investments
 
Other investments in common stock are valued based on unadjusted prices for the investments and are actively traded on public exchanges.  These investments are therefore considered Level 1 assets.
 
Transfers between Levels
 
PG&E Corporation and the Utility recognize transfers between levels in the fair value hierarchy as of the end of the reporting period. There were no transfers between levels for the three and nine months ended September 30, 2013.
 
 
 
 
Level 3 Measurements and Sensitivity Analysis
 
The Utility's market and credit risk management function is responsible for determining the fair value of the Utility's price risk management derivatives.  Market and credit risk management reports to the Chief Risk Officer of the Utility.  Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility's Level 3 instruments.  These models use pricing inputs from brokers and historical data.  The market and credit risk management function and the Utility's finance function collaborate to determine the appropriate fair value methodologies and classification for each derivative.  Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.  Valuation models and techniques are reviewed periodically.
 
CRRs and power purchase agreements are valued using historical prices or significant unobservable inputs derived from internally developed models.  Historical prices include CRR auction prices.  Unobservable inputs include forward electricity prices.  Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  (See Note 7 above.)
 
 
 
 
Fair Value at
 
 
 
 
 
 
 
(in millions)
 
September 30, 2013
 
 
 
 
 
 
 
Fair Value Measurement
 
Assets
 
Liabilities
 
Valuation Technique
 
Unobservable Input
 
Range (1)
Congestion revenue rights
 
$
65
 
$
13
 
Market approach
 
CRR auction prices
 
$
(7.58) - 7.93
Power purchase agreements
 
$
-
 
$
134
 
Discounted cash flow
 
Forward prices
 
$
10.36 - 54.86
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (1) Represents price per megawatt-hour
 
 
 
Fair Value at
 
 
 
 
 
 
 
(in millions)
 
December 31, 2012
 
 
 
 
 
 
 
Fair Value Measurement
 
Assets
 
Liabilities
 
Valuation Technique
 
Unobservable Input
 
Range (1)
Congestion revenue rights
 
$
80
 
$
16
 
Market approach
 
CRR auction prices
 
$
(9.04) - 55.15
Power purchase agreements
 
$
-
 
$
145
 
Discounted cash flow
 
Forward prices
 
$
8.59 - 62.90
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (1) Represents price per megawatt-hour
 
Level 3 Reconciliation
 
The following tables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2013 and 2012:
 
 
Price Risk Management Instruments
(in millions)
2013
 
2012
Liability balance as of July 1
$
(76)
 
$
(80)
Realized and unrealized gains (losses):
 
 
 
 
 
Included in regulatory assets and liabilities or balancing accounts (1)
 
(6
 ) 
 
(4
)
Liability balance as of September 30
$
(82)
 
$
(84)
 
 
 
 
 
 
 (1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.
 
 
Price Risk Management Instruments
(in millions)
2013
 
2012
Liability balance as of January 1
$
(79)
 
$
(74)
Realized and unrealized gains (losses):
 
 
 
 
 
Included in regulatory assets and liabilities or balancing accounts (1)
 
(3
 ) 
 
(10
)
Liability balance as of September 30
$
(82)
 
$
(84)
 
 
 
 
 
 
                   (1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.
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, 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 September 30, 2013 and December 31, 2012, as they are short-term in nature or have interest rates that reset daily.  
  • The fair values of the Utility's fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation's fixed-rate senior notes were based on quoted market prices at September 30, 2013 and December 31, 2012.  
 
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):
 
 
September 30, 2013
 
December 31, 2012
(in millions)
Carrying Amount
 
Level 2 Fair Value
 
Carrying Amount
 
Level 2 Fair Value
Debt (Note 4)
 
 
 
 
 
 
 
 
 
 
 
PG&E Corporation
$
350
 
$
359
 
$
349
 
$
371
Utility
 
11,934
 
 
12,750
 
 
11,645
 
 
13,946
 
 
Available for Sale Investments
 
The following table provides a summary of available-for-sale investments:
 
 
 
 
 
Total
 
 
Total
 
 
 
 
Amortized
 
 
Unrealized
 
 
Unrealized
 
 
Total Fair
(in millions)
Cost
 
 
Gains
 
 
Losses
 
 
Value
As of September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
$
26
 
$
-
 
$
-
 
$
26
  Equity securities
 
 
 
 
 
 
 
 
 
 
 
    U.S.
 
267
 
 
753
 
 
(1
 ) 
 
1,019
    Non-U.S.
 
205
 
 
230
 
 
-
 
 
435
  Debt securities
 
 
 
 
 
 
 
 
 
 
 
    U.S. government and agency securities
 
870
 
 
63
 
 
(3
 ) 
 
930
    Municipal securities
 
24
 
 
2
 
 
-
 
 
26
    Other fixed-income securities
 
128
 
 
1
 
 
(1
 ) 
 
128
Total nuclear decommissioning trusts (1)
 
1,520
 
 
1,049
 
 
(5
 ) 
 
2,564
Other investments
 
13
 
 
38
 
 
-
 
 
51
Total
$
1,533
 
$
1,087
 
$
(5)
 
$
2,615
As of December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
21
 
$
-
 
$
-
 
$
21
Equity securities
 
 
 
 
 
 
 
 
 
 
 
  U.S.
 
331
 
 
618
 
 
-
 
 
949
  Non-U.S.
 
199
 
 
181
 
 
(1
 ) 
 
379
Debt securities
 
 
 
 
 
 
 
 
 
 
 
  U.S. government and agency securities
 
723
 
 
97
 
 
-
 
 
820
  Municipal securities
 
56
 
 
4
 
 
(1
 ) 
 
59
  Other fixed-income securities
 
168
 
 
5
 
 
-
 
 
173
Total (1)
$
1,498
 
$
905
 
$
(2)
 
$
2,401
 
 
 
 
 
 
 
 
 
 
 
 
(1) Represents amounts before deducting $292 million and $240 million at September 30, 2013 and December 31, 2012, respectively, of deferred taxes primarily related to appreciation of investment value.
 
 
 
The fair value of debt securities by contractual maturity is as follows:
 
 
 
As of
(in millions)
September 30, 2013
Less than 1 year
$
17
1-5 years
 
512
5-10 years
 
241
More than 10 years
 
314
Total maturities of debt securities
$
1,084
 
The following table provides a summary of activity for the debt and equity securities:
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2013
 
2012
 
 
2013
 
2012
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Proceeds from sales and maturities of nuclear decommissioning  
 
 
 
 
 
 
 
 
 
 
 
trust investments
$
357
 
$
237
 
$
1,152
 
$
903
Gross realized gains on sales of securities held as available-for-sale
 
7
 
 
3
 
 
44
 
 
17
Gross realized losses on sales of securities held as available-for-sale
 
(4
 ) 
 
(6
 ) 
 
(10
 ) 
 
(13
)
 
 
 
Resolution Of Remaining Chapter 11 Disputed Claims
Resolution Of Remaining Chapter 11 Disputed Claims
NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS
 
Various electricity suppliers filed claims in the Utility's proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility's customers 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 governmental entities, for overcharges incurred in the CAISO and the California Power Exchange wholesale electricity markets during this period.
 
While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers.  The Utility entered into a number of settlement agreements 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 Utility is uncertain when and how the remaining disputed claims will be resolved.
  
Any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers through resolution of the remaining disputed claims, either through settlement or through the conclusion of the various FERC and judicial proceedings, are refunded to customers through rates in future periods.
 
At September 30, 2013 and December 31, 2012, the remaining net disputed claims liability consisted of $156 million and $157 million, respectively, of remaining net disputed claims (classified on the Condensed Consolidated Balance Sheets within accounts payable - disputed claims and customer refunds) and $704 million and $685 million, respectively, of accrued interest (classified on the Condensed Consolidated Balance Sheets within interest payable).
 
At September 30, 2013 and December 31, 2012 the Utility held $291 million, respectively, in escrow, including earned interest, for payment of the remaining net disputed claims liability.  These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.
Commitments And Contingencies
Commitments And Contingencies
 
NOTE 10: 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 regulatory proceedings, investigations, nuclear liability, legal matters and environmental remediation.
 
Commitments
 
            In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments.  The Utility disclosed its commitments at December 31, 2012 in Note 15 of the Notes to the Consolidated Financial Statements in the 2012 Annual Report.  During the nine months ended September 30, 2013, the Utility entered into several renewable energy and other power purchase agreements, resulting in a total commitment of $1.9 billion over the next one to twenty-five years.  These agreements have been approved by the CPUC and have completed major milestones with respect to construction.
 
Contingencies
 
PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits.  In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations.  PG&E Corporation and the Utility record a provision for a loss contingency when it is both probable that a loss 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 losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.  The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation's and the Utility's policy is to exclude anticipated legal costs from the provision for loss.
 
 
 
Natural Gas Matters
 
On September 9, 2010, a natural gas transmission pipeline owned and operated by the Utility ruptured in San Bruno, California.  The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage.  Following the San Bruno accident, various regulatory proceedings, investigations, and lawsuits were commenced.  The National Transportation Safety Board, an independent review panel appointed by the CPUC, and the SED completed investigations with respect to the San Bruno accident, placing the blame primarily on the Utility.  As part of a rulemaking proceeding to consider the adoption of new natural gas safety regulations, the CPUC ordered all natural gas operators in California to submit proposed plans to modernize and upgrade their natural gas transmission systems as well as associated cost forecast and ratemaking proposals.  
 
      Pipeline Safety Enhancement Plan
 
The Utility's pipeline safety enhancement plan is a multi-year program to modernize and upgrade its natural gas transmission system.  In December 2012, the CPUC approved most of the projects proposed in the PSEP but disallowed the Utility's request for rate recovery of a significant portion of costs the Utility forecasted it would incur through 2014.  The CPUC authorized the Utility to recover costs, subject to the adopted capital and expense amounts, for activities including pipeline strength testing, pipeline replacement, in-line inspection, and the installation of automated valves.  The CPUC prohibited the Utility from recovering the costs of pressure testing pipeline placed into service after January 1, 1956 for which the Utility is unable to produce pressure test records.  The CPUC ordered the Utility to file an update PSEP application after the Utility completes its search and review of records relating to pipeline pressure validation for all 6,750 miles of the Utility's natural gas transmission pipelines.  
 
On October 29, 2013, the Utility submitted its update application to present the results of its completed records search and review and to request approval of adjusted revenue requirements.  Based on the information obtained through the records search and review, the Utility has proposed to change the scope and prioritization of PSEP work, including deferring some projects to after 2014 and accelerating other projects.  The Utility has proposed net reductions to authorized costs for both its strength testing program (to test 658 miles rather than 783 miles) and its pipeline replacement program (to replace 143 miles rather than 186 miles).  In August 2013, in anticipation of the Utility's update application, TURN and the CPUC's DRA requested the assigned ALJ for an order limiting the scope of the revenue requirement changes that the Utility could request in the update application to only those changes resulting from the records search and subsequent pressure validation based on those records, which could result in a disallowance of costs associated with the acceleration of projects.  The ALJ has not yet addressed their request and it is uncertain how the information presented in the Utility's update application about accelerating or changing the scope of PSEP projects will be considered.  The Utility has requested that the CPUC issue a final decision by August 2014 to approve the revised scope of PSEP projects and the net reduction in authorized costs.
 
 
Based on the proposed changes in the scope of PSEP projects through 2014, the Utility forecasts that total unrecoverable costs to complete this work will significantly exceed the amount previously forecasted primarily due to higher anticipated unit costs to replace pipeline segments.  As a result, for the three months ended September 30, 2013, the Utility recorded a charge of $196 million, reflecting the increase in forecasted capital expenditures through 2014 that are expected to exceed the amount to be recovered.  At September 30, 2013, the Utility has recorded cumulative charges of $549 million for disallowed PSEP-related capital expenditures, including $353 million recorded at December 31, 2012.  
 
      At September 30, 2013, capitalized PSEP costs of approximately $170 million are included in Property, Plant, and Equipment on the Condensed Consolidated Balance Sheets.  The Utility could record additional charges if the CPUC does not approve the adjusted revenue requirements requested in the Utility's PSEP update application or if cost forecasts increase in the future.  The CPUC also could make ratemaking adjustments to recovery of PSEP costs in connection with the pending CPUC investigations discussed below. 
 
Pending CPUC Investigations  
 
There are three CPUC investigative enforcement proceedings pending against the Utility that relate to (1) the Utility's safety recordkeeping for its natural gas transmission system, (2) the Utility's operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility's pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the San Bruno accident.  Evidentiary hearings and briefing have been completed in each of these investigations.  
 
 The SED has recommended that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, allocated as follows:  (1) $300 million as a fine to the State General Fund, (2) $435 million for a portion of PSEP costs that were previously disallowed by the CPUC and funded by shareholders, and (3) $1.515 billion to perform PSEP work that was previously approved by the CPUC, implement operational remedies, and for future PSEP costs.  Other parties, including the City of San Bruno, TURN, the CPUC's DRA, and the City and County of San Francisco, have recommended total penalties of at least $2.25 billion, including fines payable to the State General Fund of differing amounts.  The City of San Bruno also recommended that the Utility provide $150 million for a Peninsula Emergency Response Consortium, spend $100 million ($5 million per year for 20 years) to fund an independent advocacy trust (the California Pipeline Safety Trust), and provide funding for an independent monitor to oversee the implementation of the recommended remedial operational measures.  TURN also recommended that the Utility bear expenses of $50 million to implement remedial measures and to pay for an independent monitor.  
 
The record for the proceedings was closed on October 15, 2013.  The CPUC's rules call for the CPUC ALJs to issue one or more presiding officers' decisions within 60 days of this date.  The decisions will become the final decisions of the CPUC 30 days after issuance unless the Utility or another party files an appeal with the CPUC, or a CPUC commissioner requests that the CPUC review the decision, within such time.  If an appeal or review request is filed, other parties have 15 days to provide comments but the CPUC could act before considering any comments.  
 
At September 30, 2013 and December 31, 2012, PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets included an accrual of $200 million in other current liabilities for the minimum amount of fines deemed probable that the Utility will pay to the State General Fund.  The Utility is unable to make a better estimate due to the many variables that could affect the final outcome, including how the total number and duration of violations will be determined; how the various penalty recommendations made by the SED and other parties will be considered; how the financial and tax impact of unrecoverable costs the Utility has incurred, and will continue to incur, to improve the safety and reliability of its pipeline system, will be considered; whether the Utility's costs to perform any required remedial actions will be considered; and how the CPUC responds to public pressure.  Future changes in these estimates or the assumptions on which they are based could have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.  The CPUC may impose fines on the Utility that are materially higher than the amount accrued and may disallow PSEP costs that were previously authorized for recovery or other future costs.  Disallowed costs would be charged to net income in the period incurred.  
 
Other CPUC Enforcement Matters
 
      In addition to the investigations that are pending against the Utility related to its natural gas operations and the San Bruno accident, the CPUC and/or SED are also considering the following matters.  PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses that may be incurred in connection with these matters.  
 
Gas Safety Citation Program
 
California gas corporations are required to provide notice to the SED of any self-identified or self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and the corporations' natural gas operating practices.  The SED is authorized to issue citations and impose fines for violations of certain state and federal regulations.  In September 2013, the SED published a document explaining the internal procedures the SED staff intends to follow in assessing gas safety violations and determining appropriate enforcement action.  The SED can consider several factors in exercising its discretion to impose fines or take other enforcement action based on the totality of the circumstances. Such factors include how the SED assesses the severity of the safety risk associated with each violation; how the SED determines the number of violations; how the SED determines the duration of the violations; how the SED considers other factors such as whether the violation was self-reported, and whether any corrective actions were taken.  The SED's internal procedures also include a schedule of potential fine amounts that vary based on the severity of the safety risk posed by the violation. 
 
In October 2013, the SED issued a citation related to one of the Utility's self-reports and imposed a fine of $140,000.  The Utility has filed 58 self-reports with the SED, plus additional follow-up reports, that the SED has not yet addressed.  The SED could issue additional citations and impose fines associated with these self-reports.    
 
Orders to Show Cause
 
On August 19, 2013, the CPUC issued two OSCs related to a document submitted by the Utility on July 3, 2013 as “errata” to correct information about some segments in Lines 101 and 147 (two of the Utility's natural gas transmission pipelines that serve the San Francisco peninsula) that had been previously provided to the CPUC in October 2011 to allow the Utility to restore operating pressure on these pipelines.  The first OSC directed the Utility to show why all orders issued by the CPUC to authorize increased operating pressure on the Utility's gas transmission pipelines should not be immediately suspended pending competent demonstration that the Utility's natural gas system records are reliable.  It is uncertain when the CPUC will issue a decision on the first OSC.  The second OSC ordered the Utility to show why it should not be penalized for violating CPUC rules that prohibit any person from misleading the CPUC, in connection with the errata submission.  Among other recommendations submitted by intervening parties related to the second OSC, the DRA and TURN have recommended that the CPUC impose penalties of $12.7 million on the Utility.  The CPUC is expected to issue a decision on the second OSC before the end of 2013.  The CPUC could impose penalties on the Utility or take other enforcement action in connection with the OSCs.  
 
Natural Gas Transmission Pipeline Rights-of-Way
 
In 2012, the Utility also notified the CPUC and the SED that the Utility is undertaking a system-wide effort to survey its transmission pipelines and identify and remove encroachments (such as building structures and vegetation overgrowth) from pipeline rights-of-way over a multi-year period.  The SED could impose penalties on the Utility or take other enforcement action in connection with this matter.
 
Criminal Investigation
 
In June 2011, the U.S. Department of Justice, the California Attorney General's Office, and the San Mateo County District Attorney's Office began an investigation of the San Bruno accident and indicated that the Utility is a target of the investigation.  Although the San Mateo County District Attorney's Office has publicly indicated that they will not pursue state criminal charges, the U.S. Department of Justice may still bring criminal charges, including charges based on claims that the Utility violated the federal Pipeline Safety Act, against PG&E Corporation or the Utility.  It is uncertain whether any criminal charges will be brought against any of PG&E Corporation's or the Utility's current or former employees.  The Utility is continuing to cooperate with federal investigators.  PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses associated with any civil or criminal penalties that could be imposed and such penalties could have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.  In addition, the Utility's business or operations could be negatively affected by any remedial measures that the Utility may undertake, such as operating its natural gas transmission business subject to the supervision and oversight of an independent monitor.
 
 
Third-Party Claims
 
In September 2013, the Utility agreed to settle the claims of substantially all of the remaining plaintiffs who sought compensation for personal injury and property damage, and other relief, including punitive damages, following the San Bruno accident.  Approximately 165 lawsuits on behalf of approximately 525 plaintiffs have been filed against the Utility.  For the three and nine months ended September 30, 2013, the Utility recorded a charge of $110 million to reflect its best estimate of probable loss for settlements reached in September 2013 and remaining third-party claims for personal injury, property damage, and damage to infrastructure, including claims by government entities.  At September 30, 2013, the Utility has recorded cumulative charges of $565 million for third-party claims related to the San Bruno accident and has made cumulative payments of $389 million for settlements.
 
The following table presents changes in the third-party claims liability since the San Bruno accident in September 2010; the balance is included in other current liabilities in the Condensed Consolidated Balance Sheets:
 
(in millions)
 
 
Balance at January 1, 2010
$
-
Loss accrued
 
220
Less: Payments
 
(6
)
Balance at December 31, 2010
 
214
Additional loss accrued
 
155
Less: Payments
 
(92
)
Balance at December 31, 2011
 
277
Additional loss accrued
 
80
Less: Payments
 
(211
)
Balance at December 31, 2012
 
146
Additional loss accrued
 
110
Less: Payments
 
(80
)
Balance at September 30, 2013
$
176
 
 
The Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or “layers.”  Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available.  The aggregate amount of insurance coverage for third-party liability attributable to the San Bruno accident is approximately $992 million in excess of a $10 million deductible.  Through September 30, 2013, the Utility has recognized cumulative insurance recoveries of $354 million for third-party claims and related legal expenses.  (The Utility has incurred cumulative legal expenses of $84 million in addition to the $565 million charges above).  Insurance recoveries for the three and nine months ended September 30, 2013 were $25 million and $70 million, respectively.  These amounts were recorded as a reduction to operating and maintenance expense in the Condensed Consolidated Statements of Income.  Although the Utility believes that a significant portion of costs incurred for third-party claims (and associated legal expenses) relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries.
 
Class Action Complaint
 
On August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions.  The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses.  The plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of California state law.  The plaintiffs seek restitution and disgorgement, as well as compensatory and punitive damages.  
 
PG&E Corporation and the Utility contest the plaintiffs' allegations.  On May 23, 2013, the court granted PG&E Corporation's and the Utility's request to dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs' allegations.  The plaintiffs have appealed the court's ruling to the California Court of Appeal.  PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses, if any, that may be incurred in connection with this matter.
 
Legal and Regulatory Contingencies
 
Accruals for other legal and regulatory contingencies (excluding amounts related to natural gas matters above) totaled $36 million at September 30, 2013 and $34 million at December 31, 2012.  These amounts are included in other current liabilities in the Condensed Consolidated Balance Sheets.  The resolution of these matters is not expected to have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, or cash flows.  
 
 
Nuclear Insurance
 
The Utility is a member of NEIL, which is a mutual insurer owned by utilities with nuclear facilities.  NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear event were to occur at the Utility's two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2 billion per non-nuclear incident for Diablo Canyon.  Humboldt Bay Unit 3 has up to $131 million of coverage for nuclear and non-nuclear property damages.  NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants.  
 
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 $13.6 billion.  The Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon.  The balance is provided under a loss-sharing program among utilities owning nuclear reactors.  The Price-Anderson Act does not apply to 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.  The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident. 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 liability insurance.  (See Note 15 of the Notes to the Consolidated Financial Statements of the 2012 Annual Report for additional information on the Utility's insurance coverage and premiums.)  
 
 
Environmental Remediation Contingencies
 
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 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 the Utility can reasonably estimate the loss or a range of probable amounts.  The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount.  Amounts recorded are not discounted to their present value.
 
The environmental remediation liability is composed of the following:
 
 
 
Balance at
(in millions)
September 30, 2013
 
December 31, 2012
Utility-owned natural gas compressor site near Topock, Arizona (1)
$
268
 
$
239
Utility-owned natural gas compressor site near Hinkley, California (1)
 
197
 
 
226
Former manufactured gas plant sites owned by the Utility or third parties
 
179
 
 
181
Utility-owned generation facilities (other than for fossil fuel-fired),
  other facilities, and third-party disposal sites
 
165
 
 
158
Fossil fuel-fired generation facilities formerly owned by the Utility
 
85
 
 
87
Decommissioning fossil fuel-fired generation facilities and sites
 
20
 
 
19
Total environmental remediation liability
$
914
 
$
910
 
 
 
 
 
 
      (1) See “Natural Gas Compressor Sites” below.
 
 
At September 30, 2013, the Utility expected to recover $581 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC.  One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites (including the Topock site) without a reasonableness review.  The Utility may incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site.
 
Natural Gas Compressor Sites
 
The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility's natural gas compressor sites near Hinkley, California and Topock, Arizona.  The Utility is also required to take measures to abate the effects of the contamination on the environment.  
 
Hinkley Site
 
The Utility's remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region.  On July 17, 2013, the Regional Board certified a final environmental report evaluating the Utility's proposed remedial methods to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts.  The Regional Board is expected to issue waste discharge permits in 2014 to allow for continued treatment of hexavalent chromium and issue a final clean-up order in 2015.
 
The Utility has implemented interim remediation measures to reduce the mass of the chromium plume, monitor and control movement of the plume, and provided replacement water to affected residents.  As of September 30, 2013, approximately 350 residential households located near the plume boundary were covered by the Utility's whole house water replacement program and the majority have opted to accept the Utility's offer to purchase their properties.  The Utility is required to maintain and operate the program for five years or until the State of California has adopted a drinking water standard specifically for hexavalent chromium at which time the program will be evaluated.   The State of California recently proposed draft regulations for hexavalent chromium and is expected to issue a final standard in 2014.
   
The Utility's environmental remediation liability at September 30, 2013 reflects the Utility's best estimate of probable future costs associated with its final remediation plan and whole house water program.  Future costs will depend on many factors, including the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the required time period by which those standards must be met, the extent of the chromium plume boundary, and adoption of a final drinking water standard by the State of California.  As more information becomes known regarding these factors, the Utility's cost estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes.  Future changes in estimates or assumptions may have a material impact on PG&E Corporation's and the Utility's future financial condition, results of operations, and cash flows. 
 
Topock Site
 
The Utility's remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior.  The California Department of Toxic Substances Control has approved the Utility's final remediation plan to contain and remediate the underground plume of hexavalent chromium, under which the Utility will implement an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The Utility expects to submit its final remedial design plan in 2014 for approval to begin construction of the groundwater treatment system.  The Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of the chromium plume toward the Colorado River.  
 
The Utility's environmental remediation liability at September 30, 2013 reflects its best estimate of probable future costs associated with its final remediation plan.  Future costs will depend on many factors, including the extent of work to be performed to implement the final groundwater remedy and the Utility's required time frame for remediation.  As more information becomes known regarding these factors, the Utility's cost estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes.  Future changes in estimates or assumptions could have a material impact on PG&E Corporation's and the Utility's future financial condition and cash flows.
 
 
Reasonably Possible Environmental Contingencies
 
Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility's undiscounted future costs could increase to as much as $1.7 billion (including amounts related to the Hinkley and Topock sites described above) 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.  The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on PG&E Corporation's and the Utility's results of operations during the period in which they are recorded.
 
Tax Matters
 
The IRS is currently reviewing several matters pertaining to the 2008, 2010, 2011, and 2012 tax returns.  The most significant of these matters relates to the repairs accounting method changes for the 2008, 2011, and 2012 tax returns. 
 
The IRS has been working with the utility industry to provide guidance concerning the deductibility of repairs.  PG&E Corporation and the Utility expect the IRS to issue guidance with respect to repairs made in the natural gas transmission and distribution businesses within the next six months.  PG&E Corporation's and the Utility's unrecognized tax benefits may change significantly within the next 12 months depending on the guidance to be issued by the IRS and the resolution of the IRS audits related to the 2008, 2010, 2011, and 2012 tax returns.  As of September 30, 2013, PG&E Corporation and the Utility believe that it is reasonably possible that unrecognized tax benefits will decrease by approximately $350 million within the next 12 months as a result of audit settlements. 
 
There were no other significant developments to tax matters during the nine months ended September 30, 2013.  (Refer to Note 9 of the Notes to the Consolidated Financial Statements in the 2012 Annual Report.)
 
New And Significant Accounting Policies (Policies)
Pension And Other Postretirement Benefits 
Pension and Other Postretirement Benefits
 
PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees, as well as contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.
 
The net periodic benefit costs reflected in PG&E Corporation's Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2013 and 2012 were as follows:
 
 
Pension Benefits
 
Other Benefits
 
Three Months Ended September 30,
(in millions)
2013
 
2012
 
2013
 
2012
Service cost for benefits earned
$
121
 
$
100
 
$
14
 
$
14
Interest cost
 
158
 
 
165
 
 
19
 
 
21
Expected return on plan assets
 
(162
 ) 
 
(150
 ) 
 
(20
 ) 
 
(19
)
Amortization of transition obligation
 
-
 
 
-
 
 
-
 
 
6
Amortization of prior service cost
 
5
 
 
5
 
 
6
 
 
7
Amortization of net actuarial loss
 
28
 
 
29
 
 
1
 
 
1
Net periodic benefit cost
 
150
 
 
149
 
 
20
 
 
30
Less: transfer to regulatory account (1)
 
(66
 ) 
 
(75
 ) 
 
-
 
 
-
Total
$
84
 
$
74
 
$
20
 
$
30
 
 
 
 
 
 
 
 
 
 
 
 
 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from customers in futures rates.
 
 
Pension Benefits
 
Other Benefits
 
Nine Months Ended September 30,
(in millions)
2013
 
2012
 
2013
 
2012
Service cost for benefits earned
$
351
 
$
297
 
$
40
 
$
37
Interest cost
 
470
 
 
494
 
 
56
 
 
63
Expected return on plan assets
 
(487
 ) 
 
(449
 ) 
 
(60
 ) 
 
(58
)
Amortization of transition obligation
 
-
 
 
-
 
 
-
 
 
18
Amortization of prior service cost
 
15
 
 
15
 
 
17
 
 
19
Amortization of net actuarial loss
 
83
 
 
92
 
 
4
 
 
4
Net periodic benefit cost
 
432
 
 
449
 
 
57
 
 
83
Less: transfer to regulatory account (1)
 
(179
 ) 
 
(225
 ) 
 
-
 
 
-
Total
$
253
 
$
224
 
$
57
 
$
83
 
 
 
 
 
 
 
 
 
 
 
 
 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from customers in future rates.
 
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
 
 
Variable Interest Entities 
Variable Interest Entities
 
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 that has a controlling financial interest in a VIE is known as the VIE's primary beneficiary and is required to consolidate the VIE.  In determining whether consolidation of a particular entity is required, PG&E Corporation and the Utility first evaluate whether the entity is a VIE.  If the entity is a VIE, PG&E Corporation and the Utility use a qualitative approach to determine if either is the primary beneficiary of the VIE.
 
Some of the counterparties to the Utility's power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs at September 30, 2013, it assessed whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE's gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE's performance, such as dispatch rights and operating and maintenance activities.  The Utility's financial exposure is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 2013, it did not consolidate any of them.
 
PG&E Corporation affiliates have entered into four tax equity agreements to fund residential and commercial retail solar energy installations with four separate privately held funds that are considered VIEs.  Under these agreements, PG&E Corporation has made cumulative lease payments and investment contributions of $363 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies.  At September 30, 2013 and December 31, 2012, the carrying amount of PG&E Corporation's investment in these agreements was $138 million and $166 million, respectively.  PG&E Corporation determined that it does not have control over the companies' significant economic activities, such as the design of the companies, vendor selection, construction, and the ongoing operations of the companies.  PG&E Corporation has no material remaining commitment to fund these agreements.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs at September 30, 2013, it did not consolidate any of them.  
 
New And Significant Accounting Policies (Tables)
Components Of Net Periodic Benefit Cost 
Pension and Other Postretirement Benefits
 
 
 
Pension Benefits
 
Other Benefits
 
Three Months Ended September 30,
(in millions)
2013
 
2012
 
2013
 
2012
Service cost for benefits earned
$
121
 
$
100
 
$
14
 
$
14
Interest cost
 
158
 
 
165
 
 
19
 
 
21
Expected return on plan assets
 
(162
 ) 
 
(150
 ) 
 
(20
 ) 
 
(19
)
Amortization of transition obligation
 
-
 
 
-
 
 
-
 
 
6
Amortization of prior service cost
 
5
 
 
5
 
 
6
 
 
7
Amortization of net actuarial loss
 
28
 
 
29
 
 
1
 
 
1
Net periodic benefit cost
 
150
 
 
149
 
 
20
 
 
30
Less: transfer to regulatory account (1)
 
(66
 ) 
 
(75
 ) 
 
-
 
 
-
Total
$
84
 
$
74
 
$
20
 
$
30
 
 
 
 
 
 
 
 
 
 
 
 
(1)      The Utility recorded these amounts to a regulatory account since they are probable of recovery from customers in futures rates.
 
 
 
Pension Benefits
 
Other Benefits
 
Nine Months Ended September 30,
(in millions)
2013
 
2012
 
2013
 
2012
Service cost for benefits earned
$
351
 
$
297
 
$
40
 
$
37
Interest cost
 
470
 
 
494
 
 
56
 
 
63
Expected return on plan assets
 
(487
 ) 
 
(449
 ) 
 
(60
 ) 
 
(58
)
Amortization of transition obligation
 
-
 
 
-
 
 
-
 
 
18
Amortization of prior service cost
 
15
 
 
15
 
 
17
 
 
19
Amortization of net actuarial loss
 
83
 
 
92
 
 
4
 
 
4
Net periodic benefit cost
 
432
 
 
449
 
 
57
 
 
83
Less: transfer to regulatory account (1)
 
(179
 ) 
 
(225
 ) 
 
-
 
 
-
Total
$
253
 
$
224
 
$
57
 
$
83
 
 
 
 
 
 
 
 
 
 
 
 
 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from customers in future rates.
Reclassification Out Of Accumulated Other Comprehensive Income 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension
 
Other
 
Other
 
 
 
 
Benefits
 
Benefits
 
Investments
 
Total
(in millions, net of income tax)
Three Months Ended September 30, 2013
Beginning balance
$
(28
 ) 
$
(69
 ) 
$
26
 
$
(71
)
Other comprehensive income before reclassifications
 
(20
 ) 
 
-
 
 
(3
 ) 
 
(23
)
Amounts reclassified from other comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
      Amortization of prior service cost (1)
 
3
 
 
3
 
 
-
 
 
6
      Amortization of net actuarial loss (1)
 
17
 
 
1
 
 
-
 
 
18
Net current period other comprehensive income (loss)
 
-
 
 
4
 
 
(3)
 
 
1
Ending balance
$
(28)
 
$
(65)
 
$
23
 
$
(70)
 
 
 
 
 
 
 
 
 
 
 
 
 (1) These components are included in the computation of net periodic pension and other postretirement costs.  (See the “Pension and Other Postretirement Benefits” table above for additional details.)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension
 
Other
 
Other
 
 
 
 
Benefits
 
Benefits
 
Investments
 
Total
(in millions, net of income tax)
Nine Months Ended September 30, 2013
Beginning balance
$
(28
 ) 
$
(77
 ) 
$
4
 
$
(101
)
Other comprehensive income before reclassifications
 
(58
 ) 
 
-
 
 
19
 
 
(39
)
Amounts reclassified from other comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
      Amortization of prior service cost (1)
 
9
 
 
9
 
 
-
 
 
18
      Amortization of net actuarial loss (1)
 
49
 
 
3
 
 
-
 
 
52
Net current period other comprehensive income (loss)
 
-
 
 
12
 
 
19
 
 
31
Ending balance
$
(28)
 
$
(65)
 
$
23
 
$
(70)
 
 
 
 
 
 
 
 
 
 
 
 
 (1) These components are included in the computation of net periodic pension and other postretirement costs.  (See the “Pension and Other Postretirement Benefits” table above for additional details.)
Regulatory Assets, Liabilities, And Balancing Accounts (Tables)
Long-Term Regulatory Assets 
 
Balance at
 
September 30,
 
December 31,
(in millions)
2013
 
2012
Pension benefits
$
3,356
 
$
3,275
Deferred income taxes
 
1,772
 
 
1,627
Utility retained generation
 
515
 
 
552
Environmental compliance costs
 
609
 
 
604
Price risk management
 
144
 
 
210
Electromechanical meters
 
150
 
 
194
Unamortized loss, net of gain, on reacquired debt
 
140
 
 
141
Other
 
141
 
 
206
Total long-term regulatory assets
$
6,827
 
$
6,809
Long-Term Regulatory Liabilities 
 
Balance at
 
September 30,
 
December 31,
(in millions)
2013
 
2012
Cost of removal obligations
$
3,805
 
$
3,625
Recoveries in excess of asset retirement obligations
 
674
 
 
620
Public purpose programs
 
594
 
 
590
Other
 
270
 
 
253
Total long-term regulatory liabilities
$
5,343
 
$
5,088
Current Regulatory Balancing Accounts, Net 
 
Receivable (Payable)
 
Balance at
 
September 30,
 
December 31,
(in millions)
2013
 
2012
Distribution revenue adjustment mechanism
$
(3
 ) 
$
219
Utility generation
 
(22
 ) 
 
117
Hazardous substance
 
75
 
 
56
Public purpose programs
 
(100
 ) 
 
(83
)
Gas fixed cost
 
179
 
 
44
Energy recovery bonds
 
(170
 ) 
 
(43
)
Energy procurement
 
281
 
 
77
U.S. Department of Energy Settlement
 
(279
 ) 
 
(250
)
GHG allowance auction proceeds (1)
 
(250
 ) 
 
-
Other
 
291
 
 
165
Total regulatory balancing accounts, net
$
2
 
$
302
 
 
 
 
 
 
 
      (1) The CARB has adopted regulations that established a state-wide, “cap-and-trade” program (effective January 1, 2013) that sets a
      gradually declining limit on the amount of GHGs that may be emitted each year. This balancing account is used to record proceeds
      collected by the Utility for GHG emission allowances associated with the cap-and-trade program.  These amounts will be refunded
      to customers in future periods.  
 
Equity (Tables)
Changes In Equity
 
PG&E Corporation
 
Utility
 
Total
 
Total
(in millions)
Equity
 
Shareholders' Equity
Balance at December 31, 2012
$
13,326
 
$
13,460
Comprehensive income
 
769
 
 
741
Equity contributions
 
-
 
 
835
Common stock issued
 
741
 
 
-
Share-based compensation expense
 
43
 
 
(1
)
Common stock dividends declared
 
(609
 ) 
 
(537
)
Preferred stock dividend requirement
 
-
 
 
(10
)
Preferred stock dividend requirement of subsidiary
 
(10
 ) 
 
-
Balance at September 30, 2013
$
14,260
 
$
14,488
 
 
 
 
 
 
Earnings Per Share (Tables)
Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted
 
Three Months Ended
 
Nine Months Ended
 
 September 30,
 
 September 30,
(in millions, except per share amounts)
2013
 
2012
 
2013
 
2012
Income available for common shareholders
$
161
 
$
361
 
$
728
 
$
829
Weighted average common shares outstanding, basic
 
446
 
 
428
 
 
441
 
 
422
Add incremental shares from assumed conversions:
 
 
 
 
 
 
 
 
 
 
 
Employee share-based compensation
 
1
 
 
1
 
 
1
 
 
1
Weighted average common share outstanding, diluted
 
447
 
 
429
 
 
442
 
 
423
Total earnings per common share, diluted
$
0.36
 
$
0.84
 
$
1.65
 
$
1.96
Derivatives (Tables)
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value 
 
At September 30, 2013, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:
 
 
 
Commodity Risk
 
Gross Derivative
 
 
 
 
 
Total Derivative
(in millions)
Balance
 
Netting
 
Cash Collateral
 
Balance
Current assets - other
$
31
 
$
(12
 ) 
$
19
 
$
38
Other noncurrent assets - other
 
66
 
 
(5
 ) 
 
-
 
 
61
Current liabilities - other
 
(162
 ) 
 
12
 
 
106
 
 
(44
)
Noncurrent liabilities - other
 
(149
 ) 
 
5
 
 
23
 
 
(121
)
Total commodity risk
$
(214)
 
$
-
 
$
148
 
$
(66)
 
 
 
 
At December 31, 2012, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:
 
 
 
Commodity Risk
 
Gross Derivative
 
 
 
 
 
Total Derivative
(in millions)
Balance
 
Netting
 
Cash Collateral
 
Balance
Current assets - other
$
48
 
$
(25
 ) 
$
36
 
$
59
Other noncurrent assets - other
 
99
 
 
(11
 ) 
 
-
 
 
88
Current liabilities - other
 
(255
 ) 
 
25
 
 
115
 
 
(115
)
Noncurrent liabilities - other
 
(221
 ) 
 
11
 
 
14
 
 
(196
)
Total commodity risk
$
(329)
 
$
-
 
$
165
 
$
(164)
 
 
 
Gains And Losses On Derivative Instruments 
 
Commodity Risk
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
(in millions)
2013
 
2012
 
2013
 
2012
Unrealized gain - regulatory assets and liabilities (1)
$
40
 
$
162
 
$
115
 
$
327
Realized loss - cost of electricity (2)
 
(57
 ) 
 
(108
 ) 
 
(136
 ) 
 
(383
)
Realized loss - cost of natural gas (2)
 
(2
 ) 
 
(5
 ) 
 
(14
 ) 
 
(32
)
Total commodity risk
$
(19)
 
$
49
 
$
(35)
 
$
(88)
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the  Condensed 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.
 
Volumes Of Outstanding Derivative Contracts 
 
At September 30, 2013, the volumes of PG&E Corporation's and the Utility's outstanding derivatives were as follows:
 
 
 
 
 
Contract Volume (1)
 
 
 
 
 
 
1 Year or
 
3 Years or
 
 
 
 
 
 
 
 
Greater but
 
Greater but
 
 
 
 
 
 
Less Than 1
 
Less Than 3
 
Less Than 5
 
5 Years or
Underlying Product
 
Instruments
 
Year
 
Years
 
 Years
 
Greater (2)
Natural Gas (3)
 
Forwards and
 
 
 
 
 
 
 
 
(MMBtus (4))
 
Swaps
 
282,212,809
 
84,938,674
 
4,907,500
 
-
 
 
Options
 
206,604,635
 
115,753,835
 
1,500,000
 
-
Electricity
 
Forwards and
 
 
 
 
 
 
 
 
(Megawatt-hours)
 
Swaps
 
2,537,023
 
2,396,080
 
2,008,046
 
1,685,781
 
 
Options
 
95,158
 
239,233
 
239,015
 
24,350
 
 
Congestion
 
 
 
 
 
 
 
 
 
 
Revenue Rights
 
57,166,228
 
78,318,934
 
60,465,135
 
11,609,557
 
 
 
 
 
 
 
 
 
 
 
 
(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period.
      (2) Derivatives in this category expire between 2018 and 2022.
      (3) Amounts shown are for the combined positions of the electric fuels and core gas portfolios.
(4) Million British Thermal Units.
 
At December 31, 2012, the volumes of PG&E Corporation's and the Utility's outstanding derivatives were as follows:
 
 
 
 
 
Contract Volume (1)
 
 
 
 
 
 
1 Year or
 
3 Years or
 
 
 
 
 
 
 
 
Greater but
 
Greater but
 
 
 
 
 
 
Less Than 1
 
Less Than 3
 
Less Than 5
 
5 Years or
Underlying Product
 
Instruments
 
Year
 
Years
 
 Years
 
Greater (2)
Natural Gas (3)
 
Forwards and
 
 
 
 
 
 
 
 
(MMBtus (4))
 
Swaps
 
329,466,510
 
98,628,398
 
5,490,000
 
-
 
 
Options
 
221,587,431
 
216,279,767
 
10,050,000
 
-
Electricity
 
Forwards and
 
 
 
 
 
 
 
 
(Megawatt-hours)
 
Swaps
 
2,537,023
 
3,541,046
 
2,009,505
 
2,538,718
 
 
Options
 
-
 
239,015
 
239,233
 
119,508
 
 
Congestion
 
 
 
 
 
 
 
 
 
 
Revenue Rights
 
74,198,690
 
74,187,803
 
74,240,147
 
25,699,804
 
 
 
 
 
 
 
 
 
 
 
 
(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period.
(2) Derivatives in this category expire between 2018 and 2022.
(3) Amounts shown are for the combined positions of the electric fuels and core gas portfolios.
(4) Million British Thermal Units.
Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered 
 
Balance at
 
September 30,
 
December 31,
(in millions)
2013
 
2012
Derivatives in a liability position with credit risk-related
 
 
 
 
 
 contingencies that are not fully collateralized
$
(133
 ) 
$
(266
)
Related derivatives in an asset position
 
29
 
 
59
Collateral posting in the normal course of business related to
 
 
 
 
 
these derivatives
 
112
 
 
103
Net position of derivative contracts/additional collateral
 
 
 
 
 
posting requirements (1)
$
8
 
$
(104)
 
 
 
 
 
 
 (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.
Fair Value Measurements (Tables)
Assets And Liabilities Measured At Fair Value On A Recurring Basis 
 
Fair Value Measurements
 
At  September 30, 2013
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting (1)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
214
 
$
-
 
$
-
 
$
-
 
$
214
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
26
 
 
-
 
 
-
 
 
-
 
 
26
  U.S. equity securities
 
1,009
 
 
10
 
 
-
 
 
-
 
 
1,019
  Non-U.S. equity securities
 
435
 
 
-
 
 
-
 
 
-
 
 
435
  U.S. government and agency securities
 
782
 
 
148
 
 
-
 
 
-
 
 
930
  Municipal securities
 
-
 
 
26
 
 
-
 
 
-
 
 
26
  Other fixed-income securities
 
-
 
 
128
 
 
-
 
 
-
 
 
128
Total nuclear decommissioning trusts (2)
 
2,252
 
 
312
 
 
-
 
 
-
 
 
2,564
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
 
1
 
 
27
 
 
65
 
 
2
 
 
95
  Gas
 
-
 
 
4
 
 
-
 
 
-
 
 
4
Total price risk management instruments
 
1
 
 
31
 
 
65
 
 
2
 
 
99
Rabbi trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Fixed-income securities
 
-
 
 
30
 
 
-
 
 
-
 
 
30
  Life insurance contracts
 
-
 
 
70
 
 
-
 
 
-
 
 
70
Total rabbi trusts
 
-
 
 
100
 
 
-
 
 
-
 
 
100
Long-term disability trust
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
5
 
 
-
 
 
-
 
 
-
 
 
5
  U.S. equity securities
 
-
 
 
11
 
 
-
 
 
-
 
 
11
  Non-U.S. equity securities
 
-
 
 
10
 
 
-
 
 
-
 
 
10
  Fixed-income securities
 
-
 
 
116
 
 
-
 
 
-
 
 
116
Total long-term disability trust
 
5
 
 
137
 
 
-
 
 
-
 
 
142
Other investments
 
51
 
 
-
 
 
-
 
 
-
 
 
51
Total assets
$
2,523
 
$
580
 
$
65
 
$
2
 
$
3,170
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
$
53
 
$
100
 
$
147
 
$
(140
 ) 
$
160
  Gas
 
6
 
 
5
 
 
-
 
 
(6
 ) 
 
5
Total liabilities
$
59
 
$
105
 
$
147
 
$
(146)
 
$
165
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $292 million of deferred taxes primarily related to appreciation of investment value.
 
 
 
Fair Value Measurements
 
At December 31, 2012
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting (1)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
209
 
$
-
 
$
-
 
$
-
 
$
209
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
21
 
 
-
 
 
-
 
 
-
 
 
21
  U.S. equity securities
 
940
 
 
9
 
 
-
 
 
-
 
 
949
  Non-U.S. equity securities
 
379
 
 
-
 
 
-
 
 
-
 
 
379
  U.S. government and agency securities
 
681
 
 
139
 
 
-
 
 
-
 
 
820
  Municipal securities
 
-
 
 
59
 
 
-
 
 
-
 
 
59
  Other fixed-income securities
 
-
 
 
173
 
 
-
 
 
-
 
 
173
Total nuclear decommissioning trusts (2)
 
2,021
 
 
380
 
 
-
 
 
-
 
 
2,401
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
 
1
 
 
60
 
 
80
 
 
6
 
 
147
  Gas
 
-
 
 
5
 
 
1
 
 
(6
 ) 
 
-
Total price risk management instruments
 
1
 
 
65
 
 
81
 
 
-
 
 
147
Rabbi trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Fixed-income securities
 
-
 
 
30
 
 
-
 
 
-
 
 
30
  Life insurance contracts
 
-
 
 
72
 
 
-
 
 
-
 
 
72
Total rabbi trusts
 
-
 
 
102
 
 
-
 
 
-
 
 
102
Long-term disability trust
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
10
 
 
-
 
 
-
 
 
-
 
 
10
  U.S. equity securities
 
-
 
 
14
 
 
-
 
 
-
 
 
14
  Non-U.S. equity securities
 
-
 
 
11
 
 
-
 
 
-
 
 
11
  Fixed-income securities
 
-
 
 
136
 
 
-
 
 
-
 
 
136
Total long-term disability trust
 
10
 
 
161
 
 
-
 
 
-
 
 
171
Total assets
$
2,241
 
$
708
 
$
81
 
$
-
 
$
3,030
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
$
155
 
$
144
 
$
160
 
$
(156
 ) 
$
303
  Gas
 
8
 
 
9
 
 
-
 
 
(9
 ) 
 
8
Total liabilities
$
163
 
$
153
 
$
160
 
$
(165)
 
$
311
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $240 million of deferred taxes primarily related to appreciation of investment value.
 
Level 3 Measurements And Sensitivity Analysis 
 
 
Fair Value at
 
 
 
 
 
 
 
(in millions)
 
September 30, 2013
 
 
 
 
 
 
 
Fair Value Measurement
 
Assets
 
Liabilities
 
Valuation Technique
 
Unobservable Input
 
Range (1)
Congestion revenue rights
 
$
65
 
$
13
 
Market approach
 
CRR auction prices
 
$
(7.58) - 7.93
Power purchase agreements
 
$
-
 
$
134
 
Discounted cash flow
 
Forward prices
 
$
10.36 - 54.86
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (1) Represents price per megawatt-hour
 
 
 
Fair Value at
 
 
 
 
 
 
 
(in millions)
 
December 31, 2012
 
 
 
 
 
 
 
Fair Value Measurement
 
Assets
 
Liabilities
 
Valuation Technique
 
Unobservable Input
 
Range (1)
Congestion revenue rights
 
$
80
 
$
16
 
Market approach
 
CRR auction prices
 
$
(9.04) - 55.15
Power purchase agreements
 
$
-
 
$
145
 
Discounted cash flow
 
Forward prices
 
$
8.59 - 62.90
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (1) Represents price per megawatt-hour
Level 3 Reconciliation 
 
 
Price Risk Management Instruments
(in millions)
2013
 
2012
Liability balance as of July 1
$
(76)
 
$
(80)
Realized and unrealized gains (losses):
 
 
 
 
 
Included in regulatory assets and liabilities or balancing accounts (1)
 
(6
 ) 
 
(4
)
Liability balance as of September 30
$
(82)
 
$
(84)
 
 
 
 
 
 
 (1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.
 
 
Price Risk Management Instruments
(in millions)
2013
 
2012
Liability balance as of January 1
$
(79)
 
$
(74)
Realized and unrealized gains (losses):
 
 
 
 
 
Included in regulatory assets and liabilities or balancing accounts (1)
 
(3
 ) 
 
(10
)
Liability balance as of September 30
$
(82)
 
$
(84)
 
 
 
 
 
 
                   (1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.
 
Carrying Amount And Fair Value Of Financial Instruments 
 
September 30, 2013
 
December 31, 2012
(in millions)
Carrying Amount
 
Level 2 Fair Value
 
Carrying Amount
 
Level 2 Fair Value
Debt (Note 4)
 
 
 
 
 
 
 
 
 
 
 
PG&E Corporation
$
350
 
$
359
 
$
349
 
$
371
Utility
 
11,934
 
 
12,750
 
 
11,645
 
 
13,946
Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments 
 
 
 
 
Total
 
 
Total
 
 
 
 
Amortized
 
 
Unrealized
 
 
Unrealized
 
 
Total Fair
(in millions)
Cost
 
 
Gains
 
 
Losses
 
 
Value
As of September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
$
26
 
$
-
 
$
-
 
$
26
  Equity securities
 
 
 
 
 
 
 
 
 
 
 
    U.S.
 
267
 
 
753
 
 
(1
 ) 
 
1,019
    Non-U.S.
 
205
 
 
230
 
 
-
 
 
435
  Debt securities
 
 
 
 
 
 
 
 
 
 
 
    U.S. government and agency securities
 
870
 
 
63
 
 
(3
 ) 
 
930
    Municipal securities
 
24
 
 
2
 
 
-
 
 
26
    Other fixed-income securities
 
128
 
 
1
 
 
(1
 ) 
 
128
Total nuclear decommissioning trusts (1)
 
1,520
 
 
1,049
 
 
(5
 ) 
 
2,564
Other investments
 
13
 
 
38
 
 
-
 
 
51
Total
$
1,533
 
$
1,087
 
$
(5)
 
$
2,615
As of December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
21
 
$
-
 
$
-
 
$
21
Equity securities
 
 
 
 
 
 
 
 
 
 
 
  U.S.
 
331
 
 
618
 
 
-
 
 
949
  Non-U.S.
 
199
 
 
181
 
 
(1
 ) 
 
379
Debt securities
 
 
 
 
 
 
 
 
 
 
 
  U.S. government and agency securities
 
723
 
 
97
 
 
-
 
 
820
  Municipal securities
 
56
 
 
4
 
 
(1
 ) 
 
59
  Other fixed-income securities
 
168
 
 
5
 
 
-
 
 
173
Total (1)
$
1,498
 
$
905
 
$
(2)
 
$
2,401
 
 
 
 
 
 
 
 
 
 
 
 
(1) Represents amounts before deducting $292 million and $240 million at September 30, 2013 and December 31, 2012, respectively, of deferred taxes primarily related to appreciation of investment value.
Schedule Of Maturities On Debt Instruments 
 
As of
(in millions)
September 30, 2013
Less than 1 year
$
17
1-5 years
 
512
5-10 years
 
241
More than 10 years
 
314
Total maturities of debt securities
$
1,084
Schedule Of Activity For Debt And Equity Securities 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2013
 
2012
 
 
2013
 
2012
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Proceeds from sales and maturities of nuclear decommissioning  
 
 
 
 
 
 
 
 
 
 
 
trust investments
$
357
 
$
237
 
$
1,152
 
$
903
Gross realized gains on sales of securities held as available-for-sale
 
7
 
 
3
 
 
44
 
 
17
Gross realized losses on sales of securities held as available-for-sale
 
(4
 ) 
 
(6
 ) 
 
(10
 ) 
 
(13
)
Commitments And Contingencies (Tables)
Change In Accruals Related To Third-Party Claims 
(in millions)
 
 
Balance at January 1, 2010
$
-
Loss accrued
 
220
Less: Payments
 
(6
)
Balance at December 31, 2010
 
214
Additional loss accrued
 
155
Less: Payments
 
(92
)
Balance at December 31, 2011
 
277
Additional loss accrued
 
80
Less: Payments
 
(211
)
Balance at December 31, 2012
 
146
Additional loss accrued
 
110
Less: Payments
 
(80
)
Balance at September 30, 2013
$
176
Schedule Of Environmental Remediation Liability 
 
Balance at
(in millions)
September 30, 2013
 
December 31, 2012
Utility-owned natural gas compressor site near Topock, Arizona (1)
$
268
 
$
239
Utility-owned natural gas compressor site near Hinkley, California (1)
 
197
 
 
226
Former manufactured gas plant sites owned by the Utility or third parties
 
179
 
 
181
Utility-owned generation facilities (other than for fossil fuel-fired),
  other facilities, and third-party disposal sites
 
165
 
 
158
Fossil fuel-fired generation facilities formerly owned by the Utility
 
85
 
 
87
Decommissioning fossil fuel-fired generation facilities and sites
 
20
 
 
19
Total environmental remediation liability
$
914
 
$
910
 
 
 
 
 
 
      (1) See “Natural Gas Compressor Sites” below.
New And Significant Accounting Policies (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Sep. 30, 2013
Dec. 31, 2012
Sep. 30, 2013
Lease Payments And Investment Contributions [Member]
Public Utility, Property, Plant and Equipment [Line Items]
 
 
 
Payments made under tax equity agreements
 
 
$ 363 
Carrying amount of investment in tax equity agreements
$ 138 
$ 166 
 
Number of tax equity agreements
4 
 
 
New And Significant Accounting Policies (Components Of Net Periodic Benefit Cost) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Pension [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Service cost for benefits earned
$ 121 
$ 100 
$ 351 
$ 297 
Interest cost
158 
165 
470 
494 
Expected return on plan assets
(162)
(150)
(487)
(449)
Amortization of transition obligation
0 
0 
0 
0 
Amortization of prior service cost
5 
5 
15 
15 
Amortization of net actuarial loss
28 
29 
83 
92 
Net periodic benefit cost
150 
149 
432 
449 
Less: transfer to regulatory account
(66)1
(75)1
(179)1
(225)1
Total
84 
74 
253 
224 
Other Benefits [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Service cost for benefits earned
14 
14 
40 
37 
Interest cost
19 
21 
56 
63 
Expected return on plan assets
(20)
(19)
(60)
(58)
Amortization of transition obligation
0 
6 
0 
18 
Amortization of prior service cost
6 
7 
17 
19 
Amortization of net actuarial loss
1 
1 
4 
4 
Net periodic benefit cost
20 
30 
57 
83 
Less: transfer to regulatory account
0 1
0 1
0 1
0 1
Total
$ 20 
$ 30 
$ 57 
$ 83 
New And Significant Accounting Policies (Reclassifications Out Of Accumulated Other Comprehensive Income) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2013
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
Beginning balance
$ (71)
$ (101)
Other comprehensive income before reclassifications
(23)
(39)
Amortization of prior service cost
6 1
18 1
Amortization of net actuarial loss
18 1
52 1
Net current period other comprehensive income (loss)
1 
31 
Ending balance
(70)
(70)
Other Investments [Member]
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
Beginning balance
26 
4 
Other comprehensive income before reclassifications
(3)
19 
Amortization of prior service cost
0 1
0 1
Amortization of net actuarial loss
0 1
0 1
Net current period other comprehensive income (loss)
(3)
19 
Ending balance
23 
23 
Pension [Member]
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
Beginning balance
(28)
(28)
Other comprehensive income before reclassifications
(20)
(58)
Amortization of prior service cost
3 1
9 1
Amortization of net actuarial loss
17 1
49 1
Net current period other comprehensive income (loss)
0 
0 
Ending balance
(28)
(28)
Other Benefits [Member]
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
Beginning balance
(69)
(77)
Other comprehensive income before reclassifications
0 
0 
Amortization of prior service cost
3 1
9 1
Amortization of net actuarial loss
1 1
3 1
Net current period other comprehensive income (loss)
4 
12 
Ending balance
$ (65)
$ (65)
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
$ 6,827 
$ 6,809 
Pension Benefits [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
3,356 
3,275 
Deferred Income Taxes [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
1,772 
1,627 
Utility Retained Generation [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
515 
552 
Environmental Compliance Costs [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
609 
604 
Price Risk Management [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
144 
210 
Electromechanical Meters [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
150 
194 
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
140 
141 
Other Long-Term Regulatory Assets [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
$ 141 
$ 206 
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Regulatory Liabilities [Line Items]
 
 
Total long-term regulatory liabilities
$ 5,343 
$ 5,088 
Cost Of Removal Obligations [Member]
 
 
Regulatory Liabilities [Line Items]
 
 
Total long-term regulatory liabilities
3,805 
3,625 
Recoveries In Excess Of Asset Retirement Obligaitons [Member]
 
 
Regulatory Liabilities [Line Items]
 
 
Total long-term regulatory liabilities
674 
620 
Public Purpose Programs [Member]
 
 
Regulatory Liabilities [Line Items]
 
 
Total long-term regulatory liabilities
594 
590 
Other Long-Term Regulatory Liabilities [Member]
 
 
Regulatory Liabilities [Line Items]
 
 
Total long-term regulatory liabilities
$ 270 
$ 253 
Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
$ 2 
$ 302 
Distribution Revenue Adjustment Mechanism [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
(3)
219 
Utility Generation [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
(22)
117 
Hazardous Substance [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
75 
56 
Public Purpose Program [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
(100)
(83)
Gas Fixed Cost [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
179 
44 
Energy Procurement [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
281 
77 
US Department of Energy Settlement [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
(279)
(250)
Greenhouse Gas Allowance Auction Proceeds [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
(250)1
0 1
Other Current Balancing Accounts [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
291 
165 
Energy Recovery Bonds [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts, net
$ (170)
$ (43)
Debt (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2013
Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member]
Sep. 30, 2013
Pollution Control Bonds Series 2009 A-D [Member]
Sep. 30, 2013
Minimum [Member]
Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member]
Sep. 30, 2013
Minimum [Member]
Pollution Control Bonds Series 2009 A-D [Member]
Sep. 30, 2013
Maximum [Member]
Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member]
Sep. 30, 2013
Maximum [Member]
Pollution Control Bonds Series 2009 A-D [Member]
Sep. 30, 2013
Utility [Member]
Jun. 14, 2013
Utility [Member]
Due June 15 2023 [Member]
Jun. 14, 2013
Utility [Member]
Due June 15 2043 [Member]
Sep. 30, 2013
Utility [Member]
Due March 1 2014 [Member]
Jun. 14, 2013
Utility [Member]
Due March 1 2014 [Member]
Debt [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit termination date
Apr. 01, 2018 
 
 
 
 
 
 
Apr. 01, 2018 
 
 
 
 
Line of credit facility, maximum borrowing capacity
$ 300 
 
 
 
 
 
 
$ 3,000 
 
 
 
 
Letters of credit outstanding
0 
 
 
 
 
 
 
91 
 
 
 
 
Debt instrument, interest rate
 
 
 
0.05% 
0.01% 
0.07% 
0.04% 
 
3.25% 
4.60% 
 
4.80% 
Debt instrument, face amount
 
614 
309 
 
 
 
 
 
 
 
 
 
Senior Notes
 
 
 
 
 
 
 
 
375 
375 
 
1,000 
Secured Debt Repurchase Agreements
 
 
 
 
 
 
 
 
 
 
 
461 
Commercial paper outstanding
 
 
 
 
 
 
 
693 
 
 
 
 
Short term borrowing outstanding
260 
 
 
 
 
 
 
0 
 
 
 
 
Premium
 
 
 
 
 
 
 
 
 
 
15 
 
Accrued interest
 
 
 
 
 
 
 
 
 
 
$ 6 
 
Equity (Changes In Equity) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Balance at December 31, 2012
 
 
$ 13,074 
 
Balance at December 31, 2012
 
 
13,326 
 
Comprehensive income
165 
372 
769 
865 
Common stock issued
 
 
741 
 
Share-based compensation expense
 
 
43 
 
Common stock dividends declared
 
 
(609)
 
Preferred stock dividend requirement of subsidiary
(3)
(3)
(10)
(10)
Balance at September 30, 2013
14,260 
 
14,260 
 
Balance at September 30, 2013
14,008 
 
14,008 
 
Pacific Gas And Electric Company [Member]
 
 
 
 
Balance at December 31, 2012
 
 
13,460 
 
Comprehensive income
166 
348 
741 
824 
Common stock issued
 
 
0 
 
Share-based compensation expense
 
 
(1)
 
Common stock dividends declared
 
 
(537)
 
Preferred stock dividend requirement
(3)
(3)
(10)
(10)
Equity contributions
 
 
835 
715 
Balance at September 30, 2013
$ 14,488 
 
$ 14,488 
 
Equity (Narrative) (Detail) (USD $)
In Millions, except Share data, unless otherwise specified
9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
May 2, 2013
Dec. 31, 2012
Common Stock Value
$ 9,212 
 
 
$ 8,428 
Proceeds From Issuance Of Common Stock
724 
702 
 
 
Equity distribution agreement amount
 
 
400 
 
Pacific Gas And Electric Company [Member]
 
 
 
 
Common Stock Value
1,322 
 
 
1,322 
Equity contribution
835 
715 
 
 
Equity Contract [Member]
 
 
 
 
Common Stock Shares Issued
5,000,000 
 
 
 
Common Stock Value
212 
 
150 
 
Net of fees and commissions
2 
 
 
 
Underwritten Public Offering [Member]
 
 
 
 
Common Stock Shares Issued
7,000,000 
 
 
 
Common Stock Value
300 
 
 
 
Four Zero One K Plan DRSPP and Share Based Compensation Plans [Member]
 
 
 
 
Common Stock Shares Issued
6,000,000 
 
 
 
Common Stock Value
212 
 
 
 
May 2 2013 Equity Contract [Member]
 
 
 
 
Net of fees and commissions
$ 1 
 
 
 
Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted EPS) (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Income available for common shareholders
$ 161 
$ 361 
$ 728 
$ 829 
Weighted average common shares outstanding, basic
446 
428 
441 
422 
Employee share-based compensation
1 
1 
1 
1 
Weighted average common shares outstanding, diluted
447 
429 
442 
423 
Total earnings per common share, diluted
$ 0.36 
$ 0.84 
$ 1.65 
$ 1.96 
Derivatives (Outstanding Derivative Balances) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Derivatives And Hedging Activities [Line Items]
 
 
Gross Derivative Balance
$ (214)
$ (329)
Netting
0 
0 
Cash Collateral
148 
165 
Total Derivative Balance
(66)
(164)
Other Current Assets [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Gross Derivative Balance
31 
48 
Netting
(12)
(25)
Cash Collateral
19 
36 
Total Derivative Balance
38 
59 
Other Noncurrent Assets [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Gross Derivative Balance
66 
99 
Netting
(5)
(11)
Cash Collateral
0 
0 
Total Derivative Balance
61 
88 
Other Current Liabilities [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Gross Derivative Balance
(162)
(255)
Netting
12 
25 
Cash Collateral
106 
115 
Total Derivative Balance
(44)
(115)
Other Noncurrent Liabilities [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Gross Derivative Balance
(149)
(221)
Netting
5 
11 
Cash Collateral
23 
14 
Total Derivative Balance
$ (121)
$ (196)
Derivatives (Gains And Losses On Derivative Instruments) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Unrealized gain/(loss) - regulatory assets and liabilities
$ 40 1
$ 162 1
$ 115 1
$ 327 1
Realized gain/(loss) - cost of electricity
(57)2
(108)2
(136)2
(383)2
Realized gain/(loss) - cost of natural gas
(2)2
(5)2
(14)2
(32)2
Total commodity risk
$ (19)
$ 49 
$ (35)
$ (88)
Derivatives (Volumes Of Outstanding Derivative Contracts, In Megawatt Hours Unless Otherwise Specified) (Detail)
3 Months Ended 12 Months Ended
Sep. 30, 2013
Dec. 31, 2012
Derivative [Line Items]
 
 
Derivatives expiration, lower (year)
2018 years 
2018 years 
Derivatives expiration, higher (year)
2022 years 
2022 years 
Forwards And Swaps [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Less Than 1 Year
282,212,809 1 2 3
329,466,510 1 2 3
Greater Than 1 Year but Less Than 3 Years
84,938,674 1 2 3
98,628,398 1 2 3
Greater Than 3 Years but Less Than 5 Years
4,907,500 1 2 3
5,490,000 1 2 3
Greater Than 5 Years
0 1 2 3 4
0 1 2 3 4
Forwards And Swaps [Member] |
Electricity [Member]
 
 
Derivative [Line Items]
 
 
Less Than 1 Year
2,537,023 1
2,537,023 1
Greater Than 1 Year but Less Than 3 Years
2,396,080 1
3,541,046 1
Greater Than 3 Years but Less Than 5 Years
2,008,046 1
2,009,505 1
Greater Than 5 Years
1,685,781 1 4
2,538,718 1 4
Options [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Less Than 1 Year
206,604,635 1 2 3
221,587,431 1 2 3
Greater Than 1 Year but Less Than 3 Years
115,753,835 1 2 3
216,279,767 1 2 3
Greater Than 3 Years but Less Than 5 Years
1,500,000 1 2 3
10,050,000 1 2 3
Greater Than 5 Years
0 1 2 3 4
0 1 2 3 4
Options [Member] |
Electricity [Member]
 
 
Derivative [Line Items]
 
 
Less Than 1 Year
95,158 1
0 1
Greater Than 1 Year but Less Than 3 Years
239,233 1
239,015 1
Greater Than 3 Years but Less Than 5 Years
239,015 1
239,233 1
Greater Than 5 Years
24,350 1 4
119,508 1 4
Congestion Revenue Rights [Member] |
Electricity [Member]
 
 
Derivative [Line Items]
 
 
Less Than 1 Year
57,166,228 1
74,198,690 1
Greater Than 1 Year but Less Than 3 Years
78,318,934 1
74,187,803 1
Greater Than 3 Years but Less Than 5 Years
60,465,135 1
74,240,147 1
Greater Than 5 Years
11,609,557 1 4
25,699,804 1 4
Derivatives (Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized
$ (133)
$ (266)
Related derivatives in an asset position
29 
59 
Collateral posting in the normal course of business related to these derivatives
112 
103 
Net position of derivative contracts/additional collateral posting requirements
$ 8 1
$ (104)1
Fair Value Measurements (Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Amount before deducting deferred taxes primariliy related to appreciation of investment value
$ 292 
$ 240 
Fair Value Measurements, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
214 
209 
Total assets
2,523 
2,241 
Total liabilities
59 
163 
Other investments
51 
 
Fair Value Measurements, Level 1 [Member] |
Nuclear Decommissioning Trusts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
26 
21 
U.S. equity securities
1,009 
940 
Non-U.S. equity securities
435 
379 
U.S. government and agency securities
782 
681 
Total assets
2,252 1
2,021 1
Fair Value Measurements, Level 1 [Member] |
Price Risk Management Instrument [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
1 
1 
Electricity
1 
1 
Electricity
53 
155 
Natural Gas
6 
8 
Fair Value Measurements, Level 1 [Member] |
Long-Term Disability Trust [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
5 
10 
Total assets
5 
10 
Fair Value Measurements, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
580 
708 
Total liabilities
105 
153 
Fair Value Measurements, Level 2 [Member] |
Nuclear Decommissioning Trusts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
U.S. equity securities
10 
9 
U.S. government and agency securities
148 
139 
Municipal securities
26 
59 
Other fixed-income securities
128 
173 
Total assets
312 1
380 1
Fair Value Measurements, Level 2 [Member] |
Price Risk Management Instrument [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
31 
65 
Electricity
27 
60 
Natural Gas
4 
5 
Electricity
100 
144 
Natural Gas
5 
9 
Fair Value Measurements, Level 2 [Member] |
Rabbi Trusts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
100 
102 
Fixed-income securities
30 
30 
Life insurance contracts
70 
72 
Fair Value Measurements, Level 2 [Member] |
Long-Term Disability Trust [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
U.S. equity securities
11 
14 
Non-U.S. equity securities
10 
11 
Total assets
137 
161 
Fixed-income securities
116 
136 
Fair Value Measurements, Level 3 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
65 
81 
Total liabilities
147 
160 
Fair Value Measurements, Level 3 [Member] |
Price Risk Management Instrument [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
65 
81 
Electricity
65 
80 
Natural Gas
0 
1 
Electricity
147 
160 
Netting [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
2 2
0 2
Total liabilities
(146)2
(165)2
Netting [Member] |
Price Risk Management Instrument [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
2 2
0 2
Electricity
2 2
6 2
Natural Gas
0 2
(6)2
Electricity
(140)2
(156)2
Natural Gas
(6)2
(9)2
Fair Value [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
214 
209 
Total assets
3,170 
3,030 
Total liabilities
165 
311 
Other investments
51 
 
Fair Value [Member] |
Nuclear Decommissioning Trusts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
26 
21 
U.S. equity securities
1,019 
949 
Non-U.S. equity securities
435 
379 
U.S. government and agency securities
930 
820 
Municipal securities
26 
59 
Other fixed-income securities
128 
173 
Total assets
2,564 1
2,401 1
Fair Value [Member] |
Price Risk Management Instrument [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
99 
147 
Electricity
95 
147 
Natural Gas
4 
0 
Electricity
160 
303 
Natural Gas
5 
8 
Fair Value [Member] |
Rabbi Trusts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
100 
102 
Fixed-income securities
30 
30 
Life insurance contracts
70 
72 
Fair Value [Member] |
Long-Term Disability Trust [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
5 
10 
U.S. equity securities
11 
14 
Non-U.S. equity securities
10 
11 
Total assets
142 
171 
Fixed-income securities
$ 116 
$ 136 
Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2013
Dec. 31, 2012
Congestion Revenue Rights [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Assets, Fair Value
$ 65 
$ 80 
Liabilities, Fair Value
13 
16 
Fair value measurement Valuation technique
Market approach 
Market approach 
Fair value measurement Unobservable Input
CRR auction prices 
CRR auction prices 
Power Purchase Agreements [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Liabilities, Fair Value
$ 134 
$ 145 
Fair value measurement Valuation technique
Discounted cash flow 
Discounted cash flow 
Fair value measurement Unobservable Input
Forward prices 
Forward prices 
Per Mega Watt Hour [Member] |
Minimum [Member] |
CRR Auction Prices [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Range
(7.58)1
(9.04)1
Per Mega Watt Hour [Member] |
Minimum [Member] |
Forward Prices [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Range
10.36 1
8.59 1
Per Mega Watt Hour [Member] |
Maximum [Member] |
CRR Auction Prices [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Range
7.93 1
55.15 1
Per Mega Watt Hour [Member] |
Maximum [Member] |
Forward Prices [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Range
54.86 1
62.9 1
Fair Value Measurements (Level 3 Reconciliation) (Detail) (Fair Value Measurements, Level 3 [Member], Price Risk Management Instruments [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Fair Value Measurements, Level 3 [Member] |
Price Risk Management Instruments [Member]
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
 
 
 
 
Liability balance
$ (76)
$ (80)
$ (79)
$ (74)
Included in regulatory assets and liabilities or balancing accounts
(6)1
(4)1
(3)1
(10)1
Liability balance
$ (82)
$ (84)
$ (82)
$ (84)
Fair Value Measurements (Carrying Amount And Fair Value Of Financial Instruments) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Carrying Amount [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Debt financial instrument
$ 350 
$ 349 
Fair Value [Member] |
Fair Value Measurements, Level 2 [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Debt financial instrument
359 
371 
Pacific Gas And Electric Company [Member] |
Carrying Amount [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Debt financial instrument
11,934 
11,645 
Pacific Gas And Electric Company [Member] |
Fair Value [Member] |
Fair Value Measurements, Level 2 [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Debt financial instrument
$ 12,750 
$ 13,946 
Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Less than 1 year
$ 17 
1-5 years
512 
5-10 years
241 
More than 10 years
314 
Total maturities of debt securities
$ 1,084 
Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Proceeds from sales and maturities of nuclear decommissioning trust investments
$ 357 
$ 237 
$ 1,152 
$ 903 
Gross realized gains on sales of securities held as available-for-sale
7 
3 
44 
17 
Gross realized losses on sales of securities held as available-for-sale
$ (4)
$ (6)
$ (10)
$ (13)
Resolution Of Remaining Chapter 11 Disputed Claims (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2013
Dec. 31, 2012
Pacific Gas And Electric Company [Member]
 
 
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
 
 
Interest accrued
$ 704 
$ 685 
Remaining disputed claims
156 
157 
CAISO And PX [Member]
 
 
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
 
 
Carrying amounts due from CAISO and PX as of the balance sheet date for disputed claims related to the Chapter 11 Filing
$ 291 
$ 291 
Commitments And Contingencies (Third-Party Power Purchases) (Detail) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2013
Long-term Purchase Commitment [Line Items]
 
Total
$ 1,900 
Minimum [Member]
 
Long-term Purchase Commitment [Line Items]
 
Long-term agreements range, years
1 
Maximum [Member]
 
Long-term Purchase Commitment [Line Items]
 
Long-term agreements range, years
25 
Commitments And Contingencies (Legal And Regulatory Contingencies) (Detail) (USD $)
In Millions, unless otherwise specified
9 Months Ended 3 Months Ended 12 Months Ended 9 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 12 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
San Bruno Explosion [Member]
Sep. 30, 2013
San Bruno Explosion [Member]
San Mateo County Superior Court [Member]
plaintiffs
Sep. 30, 2013
Tort Lawsuits [Member]
San Bruno Explosion [Member]
San Mateo County Superior Court [Member]
lawsuits
Sep. 30, 2013
Pipeline Safety Enhancement Plan Costs Approved, Implementation of Operational Remedies, Future Pipeline Safety Enhancement Plan Costs [Member]
Sep. 30, 2013
PGE Corporation And Utility [Member]
Dec. 31, 2012
PGE Corporation And Utility [Member]
Sep. 30, 2013
Pacific Gas And Electric Company [Member]
Sep. 30, 2012
Pacific Gas And Electric Company [Member]
Dec. 31, 2012
Pacific Gas And Electric Company [Member]
Dec. 31, 2011
Pacific Gas And Electric Company [Member]
Dec. 31, 2010
Pacific Gas And Electric Company [Member]
Sep. 30, 2013
Pacific Gas And Electric Company [Member]
San Bruno Explosion [Member]
Sep. 30, 2013
Utility [Member]
Sep. 30, 2013
Utility [Member]
mi
Dec. 31, 2012
Utility [Member]
Sep. 30, 2013
Utility [Member]
State General Fund [Member]
Sep. 30, 2013
Utility [Member]
Pipeline Safety Enhancement Plan Costs Previously Disallowed By CPUC [Member]
Sep. 30, 2013
Utility [Member]
Strength Testing Program [Member]
Original Application [Member]
mi
Sep. 30, 2013
Utility [Member]
Strength Testing Program [Member]
Updated Application [Member]
mi
Sep. 30, 2013
Utility [Member]
Pipeline Replacement Program [Member]
Original Application [Member]
mi
Sep. 30, 2013
Utility [Member]
Pipeline Replacement Program [Member]
Updated Application [Member]
mi
Loss Contingencies [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued legal liabilities
 
 
 
 
 
 
$ 36 
$ 34 
$ 176 
 
$ 146 
$ 277 
$ 214 
 
 
 
 
 
 
 
 
 
 
Number of self-reports filed with the CPUC
58 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Probable penalty amount
 
 
 
 
 
 
200 
200 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Disallowed capital expenditures
196 
0 
 
 
 
 
196 
353 
196 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of lawsuits
 
 
 
 
165 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of plaintiffs
 
 
 
525 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumulative charge
 
 
 
 
 
 
 
 
 
 
 
 
 
565 
 
 
 
 
 
 
 
 
 
Cumulative payments
 
 
 
 
 
 
 
 
 
 
 
 
 
389 
 
 
 
 
 
 
 
 
 
Estimated maximum amount for third party claims for San Bruno
 
 
110 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility liability insurance for damages
 
 
 
 
 
 
 
 
 
 
 
 
 
992 
 
 
 
 
 
 
 
 
 
Utility liability insurance deductible
 
 
 
 
 
 
 
 
 
 
 
 
 
10 
 
 
 
 
 
 
 
 
 
Cumulative insurance recoveries for cost incurred related to third-party claims
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25 
70 
284 
 
 
 
 
 
 
Legal expenses
 
 
 
 
 
 
 
 
 
 
 
 
 
84 
 
 
 
 
 
 
 
 
 
Number of CPUC investigative enforcement proceedings pending
3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SED issued citations
1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CPUC Issued OCS
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SED recommended penalty
 
 
 
 
 
1,515 
 
 
 
 
 
 
 
 
 
 
 
300 
435 
 
 
 
 
DRA and TURN Recommended Penalties
 
 
 
 
 
12,700 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total penalty recommended by various parties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,250 
2,250 
 
 
 
 
 
 
 
City of San Bruno recommended funding for a Peninsula Emergency Response Consortium
 
 
 
 
 
 
 
 
 
 
 
 
 
 
150 
150 
 
 
 
 
 
 
 
City of San Bruno recommended funding for the California Pipeline Safety Trust and an independent monitor to oversee the implementation of the recommended remedial operational measures
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100 
100 
 
 
 
 
 
 
 
TURN recommended funding to implement remedial measures and to pay for an independent monitor
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50 
50 
 
 
 
 
 
 
 
Capitalized PSEP Costs
 
 
 
 
 
 
170 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized tax benefits
350 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas Pipeline Transmission Miles
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,750 
 
 
 
783 
658 
186 
143 
SED imposed fine
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 140 
$ 140 
 
 
 
 
 
 
 
Commitments And Contingencies (Nuclear Insurance) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Long-term Purchase Commitment [Line Items]
 
Coverage for purchased public liability insurance, per incident
$ 375 
Diablo Canyon [Member]
 
Long-term Purchase Commitment [Line Items]
 
Maximum public liability per nuclear incident under Price-Anderson Act
13,600 
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act
375 
Diablo Canyon [Member] |
Nuclear Incident [Member]
 
Long-term Purchase Commitment [Line Items]
 
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon
3,200 
Diablo Canyon [Member] |
Non Nuclear Incident [Member]
 
Long-term Purchase Commitment [Line Items]
 
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon
2,000 
Humboldt Bay Unit [Member]
 
Long-term Purchase Commitment [Line Items]
 
Amount of property damage coverage provided by NEIL
131 
Amount of indemnification from the NRC for public liability arising from nuclear incidents
500 
Amount of liability insurance for Humboldt Bay Unit 3
$ 53 
Commitments And Contingencies (Environmental Remediation Liability Composed) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Utility-owned natural gas compressor site near Hinkley, California
$ 268 1
$ 239 1
Utility-owned natural gas compressor site near Topock, Arizona
197 1
226 1
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites
179 
181 
Former MGP sites owned by the Utility or third parties
165 
158 
Fossil fuel-fired generation facilities formerly owned by the Utility
85 
87 
Decommissioning fossil fuel-fired generation facilities and sites
20 
19 
Total environmental remediation liability
$ 914 
$ 910 
Commitments And Contingencies (Environmental Remediation Contingencies) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Long-term Purchase Commitment [Line Items]
 
Amount of environmental loss accrual expected to be recovered
$ 581 
Eligible resident households for voluntary program
350 
Topock Site [Member]
 
Long-term Purchase Commitment [Line Items]
 
Remediation cost recovery
90.00% 
Pacific Gas And Electric Company [Member]
 
Long-term Purchase Commitment [Line Items]
 
Increase in undiscounted future costs in the event other potentially responsible parties are not able to contribute
$ 1,700 
Commitments And Contingencies (Class Action Complaint) (Detail) (Pacific Gas And Electric Company [Member], USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2013
Pacific Gas And Electric Company [Member]
 
Long-term Purchase Commitment [Line Items]
 
Alleged utility collection 1997 to 2010
$ 100