PG&E CORP, 10-K filed on 2/11/2014
Annual Report
Document And Entity Information (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended 12 Months Ended
Dec. 31, 2013
Jun. 30, 2013
Feb. 3, 2014
PG&E Corporation [Member]
Dec. 31, 2013
Pacific Gas And Electric Company [Member]
Feb. 3, 2014
Pacific Gas And Electric Company [Member]
Document Type
10-K 
 
 
10-K 
 
Document Period End Date
Dec. 31, 2013 
 
 
Dec. 31, 2013 
 
Amendment Flag
false 
 
 
false 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Non-accelerated Filer 
 
Entity Registrant Name
PG&E CORP 
 
 
PACIFIC GAS & ELECTRIC CO 
 
Entity Central Index Key
0001004980 
 
 
0000075488 
 
Current Fiscal Year End Date
--12-31 
 
 
--12-31 
 
Document Fiscal Year Focus
2013 
 
 
2013 
 
Entity Current Reporting Status
Yes 
 
 
Yes 
 
Document Fiscal Period Focus
FY 
 
 
FY 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Yes 
 
Entity Voluntary Filers
No 
 
 
No 
 
Entity Public Float
 
$ 20,326 
 
 
 
Entity Common Stock, Shares Outstanding
 
 
457,663,407 
 
264,374,809 
Consolidated Statements Of Income (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Operating Revenues
 
 
 
Electric
$ 12,494 
$ 12,019 
$ 11,606 
Natural gas
3,104 
3,021 
3,350 
Total operating revenues
15,598 
15,040 
14,956 
Operating Expenses
 
 
 
Cost of electricity
5,016 
4,162 
4,016 
Cost of natural gas
968 
861 
1,317 
Operating and maintenance
5,775 
6,052 
5,466 
Depreciation, amortization, and decommissioning
2,077 
2,272 
2,215 
Total operating expenses
13,836 
13,347 
13,014 
Operating Income
1,762 
1,693 
1,942 
Interest income
9 
7 
7 
Interest expense
(715)
(703)
(700)
Other income, net
40 
70 
49 
Income Before Income Taxes
1,096 
1,067 
1,298 
Income tax provision
268 
237 
440 
Net Income
828 
830 
858 
Preferred stock dividend requirement of subsidiary
14 
14 
14 
Preferred stock dividend requirement
14 
14 
14 
Income Available for Common Shareholders
814 
816 
 
Weighted Average Common Shares Outstanding, Basic
444 
424 
401 
Weighted Average Common Shares Outstanding, Diluted
445 
425 
402 
Net earnings per common share, basic
$ 1.83 
$ 1.92 
$ 2.1 
Net Earnings Per Common Share, Diluted
$ 1.83 
$ 1.92 
$ 2.1 
Pacific Gas And Electric Company [Member]
 
 
 
Operating Revenues
 
 
 
Electric
12,489 
12,014 
11,601 
Natural gas
3,104 
3,021 
3,350 
Total operating revenues
15,593 
15,035 
14,951 
Operating Expenses
 
 
 
Cost of electricity
5,016 
4,162 
4,016 
Cost of natural gas
968 
861 
1,317 
Operating and maintenance
5,742 
6,045 
5,459 
Depreciation, amortization, and decommissioning
2,077 
2,272 
2,215 
Total operating expenses
13,803 
13,340 
13,007 
Operating Income
1,790 
1,695 
1,944 
Interest income
8 
6 
5 
Interest expense
(690)
(680)
(677)
Other income, net
84 
88 
53 
Income Before Income Taxes
1,192 
1,109 
1,325 
Income tax provision
326 
298 
480 
Net Income
866 
811 
845 
Preferred stock dividend requirement
14 
14 
14 
Income Available for Common Shareholders
$ 852 
$ 797 
$ 831 
Condensed Consolidated Statements Of Comprehensive Income (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Net income
$ 828 
$ 830 
$ 858 
Other Comprehensive Income
 
 
 
Pension and other postretirement benefit plans obligations (related to corporation net of income tax of $80, $72 and $9, at respective dates and related to utility of $75, $73, and $4, at respective dates)
 
108 
(11)
Gain on investments (net of taxes $26, $3, and $0, at respective dates)
38 
4 
0 
Total other comprehensive income (loss)
151 
112 
(11)
Comprehensive Income
979 
942 
847 
Preferred stock dividend requirement of subsidiary
14 
14 
14 
Comprehensive Income
965 
928 
833 
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Other Comprehensive Income
 
 
 
Gain on investments (net of taxes $26, $3, and $0, at respective dates)
38 
 
 
Other Postretirement Benefit Plans Defined Benefit [Member]
 
 
 
Other Comprehensive Income
 
 
 
Total other comprehensive income (loss)
92 
 
 
Other Postretirement Benefit Plans Defined Benefit [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Other Comprehensive Income
 
 
 
Gain on investments (net of taxes $26, $3, and $0, at respective dates)
0 
 
 
Other Pension Plans Defined Benefit [Member]
 
 
 
Other Comprehensive Income
 
 
 
Total other comprehensive income (loss)
38 
 
 
Other Pension Plans Defined Benefit [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Other Comprehensive Income
 
 
 
Gain on investments (net of taxes $26, $3, and $0, at respective dates)
38 
 
 
Defined Benefits Plan Pension [Member]
 
 
 
Other Comprehensive Income
 
 
 
Total other comprehensive income (loss)
21 
 
 
Defined Benefits Plan Pension [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Other Comprehensive Income
 
 
 
Gain on investments (net of taxes $26, $3, and $0, at respective dates)
0 
 
 
Pacific Gas And Electric Company [Member]
 
 
 
Net income
866 
811 
845 
Other Comprehensive Income
 
 
 
Pension and other postretirement benefit plans obligations (related to corporation net of income tax of $80, $72 and $9, at respective dates and related to utility of $75, $73, and $4, at respective dates)
106 
109 
(7)
Total other comprehensive income (loss)
106 
109 
(7)
Comprehensive Income
$ 972 
$ 920 
$ 838 
Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Pension and other postretirement benefit plans obligations tax
$ 80 
$ 72 
$ 9 
Gain on investments tax
26 
3 
0 
Other Postretirement Benefit Plans Defined Benefit [Member] |
Amounts Reclassified From Other Comprehensive Income [Member]
 
 
 
Pension and other postretirement benefit plans obligations tax
3 
 
 
Unrecognized net gain, income tax benefit (expense)
10 
 
 
Transfer to regulatory account of income
0 
 
 
Other Postretirement Benefit Plans Defined Benefit [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Pension and other postretirement benefit plans obligations tax
35 
 
 
Gain on investments tax
0 
 
 
Transfer to regulatory account of income
22 
 
 
Other Pension Plans Defined Benefit [Member] |
Amounts Reclassified From Other Comprehensive Income [Member]
 
 
 
Pension and other postretirement benefit plans obligations tax
0 
 
 
Unrecognized net gain, income tax benefit (expense)
0 
 
 
Transfer to regulatory account of income
0 
 
 
Other Pension Plans Defined Benefit [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Pension and other postretirement benefit plans obligations tax
0 
 
 
Gain on investments tax
26 
 
 
Transfer to regulatory account of income
0 
 
 
Defined Benefits Plan Pension [Member] |
Amounts Reclassified From Other Comprehensive Income [Member]
 
 
 
Pension and other postretirement benefit plans obligations tax
45 
 
 
Unrecognized net gain, income tax benefit (expense)
8 
 
 
Transfer to regulatory account of income
54 
 
 
Defined Benefits Plan Pension [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Pension and other postretirement benefit plans obligations tax
804 
 
 
Gain on investments tax
0 
 
 
Transfer to regulatory account of income
790 
 
 
Pacific Gas And Electric Company [Member]
 
 
 
Pension and other postretirement benefit plans obligations tax
$ 75 
$ 73 
$ 4 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Current Assets
 
 
Cash and cash equivalents
$ 296 
$ 401 
Restricted cash
301 
330 
Accounts receivable
 
 
Customers (net of allowance for doubtful accounts of $80 and $87 at December 31, 2013 and 2012)
1,091 
937 
Accrued unbilled revenue
766 
761 
Regulatory balancing accounts
1,124 
936 
Other
312 
365 
Regulatory assets
448 
564 
Inventories
 
 
Gas stored underground and fuel oil
137 
135 
Materials and supplies
317 
309 
Income taxes receivable
574 
211 
Other
611 
172 
Total current assets
5,977 
5,121 
Property, Plant, and Equipment
 
 
Electric
42,881 
39,701 
Gas
14,379 
12,571 
Construction work in progress
1,834 
1,894 
Other
2 
1 
Total property, plant, and equipment
59,096 
54,167 
Accumulated depreciation
(17,844)
(16,644)
Net property, plant, and equipment
41,252 
37,523 
Other Noncurrent Assets
 
 
Regulatory assets
4,913 1
6,809 1
Nuclear decommissioning trusts
2,342 
2,161 
Income taxes receivable
85 
176 
Other
1,036 
659 
Total other noncurrent assets
8,376 
9,805 
TOTAL ASSETS
55,605 
52,449 
Current Liabilities
 
 
Short-term borrowings
1,174 
492 
Long-term debt, classified as current
889 
400 
Accounts payable
 
 
Trade creditors
1,293 
1,241 
Disputed claims and customer refunds
154 
157 
Regulatory balancing accounts
1,008 
634 
Other
471 
444 
Interest payable
892 
870 
Other
1,612 
2,018 
Total current liabilities
7,493 
6,256 
Noncurrent Liabilities
 
 
Long-term debt
12,717 
12,517 
Regulatory liabilities
5,660 
5,088 
Pension and other postretirement benefits
1,601 
3,575 
Asset retirement obligations
3,539 
2,919 
Deferred income taxes
7,823 
6,748 
Other
2,178 
2,020 
Total noncurrent liabilities
33,518 
32,867 
Commitments and Contingencies (Note 14)
   
   
Shareholders' Equity
 
 
Preferred stock
0 
0 
Common stock
9,550 
8,428 
Reinvested earnings
4,742 
4,747 
Accumulated other comprehensive income (loss)
50 
(101)
Total shareholders' equity
14,342 
13,074 
Noncontrolling Interest - Preferred Stock of Subsidiary
252 
252 
Total equity
14,594 
13,326 
TOTAL LIABILITIES AND EQUITY
55,605 
52,449 
Other Postretirement Benefit Plans Defined Benefit [Member]
 
 
Noncurrent Liabilities
 
 
Pension and other postretirement benefits
57 2
181 2
Shareholders' Equity
 
 
Accumulated other comprehensive income (loss)
15 
(77)
Other Pension Plans Defined Benefit [Member]
 
 
Shareholders' Equity
 
 
Accumulated other comprehensive income (loss)
42 
4 
Defined Benefits Plan Pension [Member]
 
 
Shareholders' Equity
 
 
Accumulated other comprehensive income (loss)
(7)
(28)
Pacific Gas And Electric Company [Member]
 
 
Current Assets
 
 
Cash and cash equivalents
65 
194 
Restricted cash
301 
330 
Accounts receivable
 
 
Customers (net of allowance for doubtful accounts of $80 and $87 at December 31, 2013 and 2012)
1,091 
937 
Accrued unbilled revenue
766 
761 
Regulatory balancing accounts
1,124 
936 
Other
313 
366 
Regulatory assets
448 
564 
Inventories
 
 
Gas stored underground and fuel oil
137 
135 
Materials and supplies
317 
309 
Income taxes receivable
563 
186 
Other
523 
160 
Total current assets
5,648 
4,878 
Property, Plant, and Equipment
 
 
Electric
42,881 
39,701 
Gas
14,379 
12,571 
Construction work in progress
1,834 
1,894 
Total property, plant, and equipment
59,094 
54,166 
Accumulated depreciation
(17,843)
(16,643)
Net property, plant, and equipment
41,251 
37,523 
Other Noncurrent Assets
 
 
Regulatory assets
4,913 
6,809 
Nuclear decommissioning trusts
2,342 
2,161 
Income taxes receivable
81 
171 
Other
814 
381 
Total other noncurrent assets
8,150 
9,522 
TOTAL ASSETS
55,049 
51,923 
Current Liabilities
 
 
Short-term borrowings
914 
372 
Long-term debt, classified as current
539 
400 
Accounts payable
 
 
Trade creditors
1,293 
1,241 
Disputed claims and customer refunds
154 
157 
Regulatory balancing accounts
1,008 
634 
Other
432 
419 
Interest payable
887 
865 
Other
1,382 
1,806 
Total current liabilities
6,609 
5,894 
Noncurrent Liabilities
 
 
Regulatory liabilities
5,660 
5,088 
Pension and other postretirement benefits
1,530 
3,497 
Asset retirement obligations
3,539 
2,919 
Deferred income taxes
8,042 
6,939 
Other
2,111 
1,959 
Total noncurrent liabilities
33,599 
32,569 
Commitments and Contingencies (Note 14)
   
   
Shareholders' Equity
 
 
Preferred stock
258 
258 
Common stock
1,322 
1,322 
Additional paid-in capital
5,821 
4,682 
Reinvested earnings
7,427 
7,291 
Accumulated other comprehensive income (loss)
13 
(93)
Total shareholders' equity
14,841 
13,460 
TOTAL LIABILITIES AND EQUITY
$ 55,049 
$ 51,923 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Restricted cash
$ 301 
$ 330 
Allowance for doubtful accounts
80 
87 
Regulatory assets current
448 
564 
Common stock, shares authorized
800,000,000 
800,000,000 
Common stock, shares outstanding
456,670,424 
430,718,293 
Pacific Gas And Electric Company [Member]
 
 
Restricted cash
301 
330 
Allowance for doubtful accounts
80 
87 
Regulatory assets current
$ 448 
$ 564 
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 
Consolidated Statements Of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Cash Flows from Operating Activities
 
 
 
Net income
$ 828 
$ 830 
$ 858 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, amortization, and decommissioning
2,077 
2,272 
2,215 
Allowance for equity funds used during construction
(101)
(107)
(87)
Deferred income taxes and tax credits, net
1,075 
648 
544 
Disallowed capital expenditures
196 
353 
0 
Other
355 
290 
326 
Effect of changes in operating assets and liabilities:
 
 
 
Accounts receivable
(152)
(40)
(288)
Inventories
(10)
(24)
(63)
Accounts payable
113 
4 
65 
Income taxes receivable/payable
(363)
(132)
(103)
Other current assets and liabilities
(469)
262 
23 
Regulatory assets, liabilities, and balancing accounts, net
(202)
291 
(100)
Other noncurrent assets and liabilities
80 
243 
349 
Net cash provided by operating activities
3,427 
4,882 
3,739 
Cash Flows from Investing Activities
 
 
 
Capital expenditures
(5,207)
(4,624)
(4,038)
Decrease in restricted cash
29 
50 
200 
Proceeds from sales and maturities of nuclear decommissioning trust investments
1,619 
1,133 
1,928 
Purchases of nuclear decommissioning trust investments
(1,604)
(1,189)
(1,963)
Other
56 
104 
(113)
Net cash provided by (used in) investing activities
(5,107)
(4,526)
(3,986)
Cash Flows from Financing Activities
 
 
 
Borrowings under revolving credit facilities
140 
120 
358 
Repayments under revolving credit facilities
0 
0 
(358)
Net issuances (repayments) of commercial paper, net of discount of $2, $3, and $4 at respective dates
542 
(1,021)
782 
Proceeds from issuance of short-term debt
0 
0 
250 
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $18, $13, and $8 at respective dates
1,532 
1,137 
792 
Short-term debt matured
0 
(250)
(250)
Long-term debt matured or repurchased
(861)
(50)
(700)
Energy recovery bonds matured
0 
(423)
(404)
Common stock issued
1,045 
751 
662 
Common stock dividends paid
(782)
(746)
(704)
Other
(41)
14 
41 
Net cash provided by (used in) financing activities
1,575 
(468)
469 
Net change in cash and cash equivalents
(105)
(112)
222 
Cash and cash equivalents at January 1
401 
513 
291 
Cash and cash equivalents at December 31
296 
401 
513 
Cash received (paid) for:
 
 
 
Interest, net of amounts capitalized
(623)
(594)
(647)
Income taxes, net
(41)
114 
(42)
Supplemental disclosures of noncash investing and financing activities
 
 
 
Common stock dividends declared but not yet paid
208 
196 
188 
Capital expenditures financed through accounts payable
322 
362 
308 
Noncash common stock issuances
22 
22 
24 
Terminated Capital Leases
0 
136 
0 
Pacific Gas And Electric Company [Member]
 
 
 
Cash Flows from Operating Activities
 
 
 
Net income
866 
811 
845 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, amortization, and decommissioning
2,077 
2,272 
2,215 
Allowance for equity funds used during construction
(101)
(107)
(87)
Deferred income taxes and tax credits, net
1,103 
684 
582 
Disallowed capital expenditures
196 
353 
0 
Other
299 
236 
289 
Effect of changes in operating assets and liabilities:
 
 
 
Accounts receivable
(152)
(40)
(227)
Inventories
(10)
(24)
(63)
Accounts payable
99 
(26)
51 
Income taxes receivable/payable
(377)
(50)
(192)
Other current assets and liabilities
(404)
272 
36 
Regulatory assets, liabilities, and balancing accounts, net
(202)
291 
(100)
Other noncurrent assets and liabilities
22 
256 
414 
Net cash provided by operating activities
3,416 
4,928 
3,763 
Cash Flows from Investing Activities
 
 
 
Capital expenditures
(5,207)
(4,624)
(4,038)
Decrease in restricted cash
29 
50 
200 
Proceeds from sales and maturities of nuclear decommissioning trust investments
1,619 
1,133 
1,928 
Purchases of nuclear decommissioning trust investments
(1,604)
(1,189)
(1,963)
Other
21 
16 
14 
Net cash provided by (used in) investing activities
(5,142)
(4,614)
(3,859)
Cash Flows from Financing Activities
 
 
 
Borrowings under revolving credit facilities
0 
0 
208 
Repayments under revolving credit facilities
0 
0 
(208)
Net issuances (repayments) of commercial paper, net of discount of $2, $3, and $4 at respective dates
542 
(1,021)
782 
Proceeds from issuance of short-term debt
0 
0 
250 
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $18, $13, and $8 at respective dates
1,532 
1,137 
792 
Short-term debt matured
0 
(250)
(250)
Long-term debt matured or repurchased
(861)
(50)
(700)
Energy recovery bonds matured
0 
(423)
(404)
Preferred stock dividends paid
(14)
(14)
(14)
Common stock dividends paid
(716)
(716)
(716)
Equity contribution
1,140 
885 
 
Other
(26)
28 
54 
Net cash provided by (used in) financing activities
1,597 
(424)
349 
Net change in cash and cash equivalents
(129)
(110)
253 
Cash and cash equivalents at January 1
194 
304 
51 
Cash and cash equivalents at December 31
65 
194 
304 
Cash received (paid) for:
 
 
 
Interest, net of amounts capitalized
(600)
(574)
(627)
Income taxes, net
(62)
174 
(50)
Supplemental disclosures of noncash investing and financing activities
 
 
 
Capital expenditures financed through accounts payable
322 
362 
308 
Terminated Capital Leases
$ 0 
$ 136 
$ 0 
Consolidated Statements Of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Cash Flows from Financing Activities
 
 
 
Net issuances of commercial paper, discount
$ 2 
$ 3 
$ 4 
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs
18 
13 
8 
Pacific Gas And Electric Company [Member]
 
 
 
Cash Flows from Financing Activities
 
 
 
Net issuances of commercial paper, discount
2 
3 
4 
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs
$ 18 
$ 13 
$ 8 
Consolidated Statements Of Equity (USD $)
In Millions, except Share data
Total
USD ($)
Other Postretirement Benefit Plans Defined Benefit [Member]
USD ($)
Other Pension Plans Defined Benefit [Member]
USD ($)
Defined Benefits Plan Pension [Member]
USD ($)
Pacific Gas And Electric Company [Member]
USD ($)
Common Stock Shares [Member]
Common Stock Shares [Member]
Pacific Gas And Electric Company [Member]
USD ($)
Preferred Stock [Member]
Pacific Gas And Electric Company [Member]
USD ($)
Common Stock Amount [Member]
USD ($)
Additional Paid-In Capital [Member]
Pacific Gas And Electric Company [Member]
USD ($)
Reinvested Earnings [Member]
USD ($)
Reinvested Earnings [Member]
Pacific Gas And Electric Company [Member]
USD ($)
Accumulated Other Comprehensive Income (Loss) [Member]
USD ($)
Accumulated Other Comprehensive Income (Loss) [Member]
Pacific Gas And Electric Company [Member]
USD ($)
Total Shareholders' Equity [Member]
USD ($)
Total Shareholders' Equity [Member]
Pacific Gas And Electric Company [Member]
USD ($)
Noncontrolling Interest - Preferred Stock Of Subsidiary [Member]
USD ($)
Balance at Dec. 31, 2010
$ 11,534 
 
 
 
 
 
$ 1,322 
$ 258 
$ 6,878 
$ 3,241 
$ 4,606 
$ 7,095 
$ (202)
$ (195)
$ 11,282 
$ 11,721 
$ 252 
Balance, in shares at Dec. 31, 2010
 
 
 
 
 
395,227,205 
 
 
 
 
 
 
 
 
 
 
 
Net income
858 
 
 
 
845 
 
 
 
 
 
858 
845 
 
 
858 
845 
 
Other comprehensive income (loss)
(11)
 
 
 
(7)
 
 
 
 
 
 
 
(11)
(7)
(11)
(7)
 
Equity contribution
 
 
 
 
 
 
 
 
 
555 
 
 
 
 
 
555 
 
Common stock issued, net
 
 
 
 
 
 
 
 
686 
 
 
 
 
 
686 
 
 
Common stock issued, net, shares
 
 
 
 
 
17,029,877 
 
 
 
 
 
 
 
 
 
 
 
Stock-based compensation amortization
37 
 
 
 
 
 
 
 
37 
 
 
 
 
 
37 
 
 
Common stock dividends declared
(738)
 
 
 
 
 
 
 
 
 
(738)
(716)
 
 
(738)
(716)
 
Tax benefit (expense) from employee stock plans
1 
 
 
 
 
 
 
 
1 
 
 
 
 
 
1 
 
 
Preferred stock dividend
 
 
 
 
 
 
 
 
 
 
 
(14)
 
 
 
(14)
 
Preferred stock dividend requirement of subsidiary
(14)
 
 
 
 
 
 
 
 
 
(14)
 
 
 
(14)
 
 
Balance at Dec. 31, 2011
12,353 
 
 
 
 
 
1,322 
258 
7,602 
3,796 
4,712 
7,210 
(213)
(202)
12,101 
12,384 
252 
Balance, in shares at Dec. 31, 2011
 
 
 
 
 
412,257,082 
 
 
 
 
 
 
 
 
 
 
 
Net income
830 
 
 
 
811 
 
 
 
 
 
830 
811 
 
 
830 
811 
 
Other comprehensive income (loss)
112 
 
 
 
109 
 
 
 
 
 
 
 
112 
109 
112 
109 
 
Equity contribution
 
 
 
 
885 
 
 
 
 
885 
 
 
 
 
 
885 
 
Common stock issued, net
773 
 
 
 
 
 
 
 
773 
 
 
 
 
 
773 
 
 
Common stock issued, net, shares
 
 
 
 
 
18,461,211 
 
 
 
 
 
 
 
 
 
 
 
Stock-based compensation amortization
52 
 
 
 
 
 
 
 
52 
 
 
 
 
 
52 
 
 
Common stock dividends declared
(781)
 
 
 
 
 
 
 
 
 
(781)
(716)
 
 
(781)
(716)
 
Tax benefit (expense) from employee stock plans
1 
 
 
 
 
 
 
 
1 
1 
 
 
 
 
1 
1 
 
Preferred stock dividend
 
 
 
 
 
 
 
 
 
 
 
(14)
 
 
 
(14)
 
Preferred stock dividend requirement of subsidiary
(14)
 
 
 
 
 
 
 
 
 
(14)
 
 
 
(14)
 
 
Balance at Dec. 31, 2012
13,326 
 
 
 
 
 
1,322 
258 
8,428 
4,682 
4,747 
7,291 
(101)
(93)
13,074 
13,460 
252 
Balance, in shares at Dec. 31, 2012
430,718,293 
 
 
 
264,374,809 
430,718,293 
 
 
 
 
 
 
 
 
 
 
 
Net income
828 
 
 
 
866 
 
 
 
 
 
828 
866 
 
 
828 
866 
 
Other comprehensive income (loss)
151 
92 
38 
21 
106 
 
 
 
 
 
 
 
151 
106 
151 
106 
 
Equity contribution
 
 
 
 
1,140 
 
 
 
 
1,140 
 
 
 
 
 
1,140 
 
Common stock issued, net
1,067 
 
 
 
 
 
 
 
1,067 
 
 
 
 
 
1,067 
 
 
Common stock issued, net, shares
 
 
 
 
 
25,952,131 
 
 
 
 
 
 
 
 
 
 
 
Stock-based compensation amortization
56 
 
 
 
 
 
 
 
56 
 
 
 
 
 
56 
 
 
Common stock dividends declared
(819)
 
 
 
 
 
 
 
 
 
(819)
(716)
 
 
(819)
(716)
 
Tax benefit (expense) from employee stock plans
(1)
 
 
 
 
 
 
 
(1)
(1)
 
 
 
 
(1)
(1)
 
Preferred stock dividend
 
 
 
 
 
 
 
 
 
 
 
(14)
 
 
 
(14)
 
Preferred stock dividend requirement of subsidiary
(14)
 
 
 
 
 
 
 
 
 
(14)
 
 
 
(14)
 
 
Balance at Dec. 31, 2013
$ 14,594 
 
 
 
 
 
$ 1,322 
$ 258 
$ 9,550 
$ 5,821 
$ 4,742 
$ 7,427 
$ 50 
$ 13 
$ 14,342 
$ 14,841 
$ 252 
Balance, in shares at Dec. 31, 2013
456,670,424 
 
 
 
264,374,809 
456,670,424 
 
 
 
 
 
 
 
 
 
 
 
Organization And Basis Of Presentation
Organization And Basis Of Presentation
NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
 
PG&E Corporation is a holding company whose primary operating subsidiary is 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.  
 
This is a combined annual report of PG&E Corporation and the Utility.  PG&E Corporation's Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.  The Utility's Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries.  All intercompany transactions have been eliminated from the Consolidated Financial Statements.  The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  PG&E Corporation and the Utility operate in one segment.
 
The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X promulgated by the SEC.  The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future regulatory decisions and economic conditions, that are difficult to predict.  Some of the more critical estimates and assumptions relate to the Utility's regulatory assets and liabilities, 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 Consolidated Financial Statements are appropriate and reasonable.  Actual results could differ materially from those estimates.
Summary Of Significant Accounting Policies
Summary Of Significant Accounting Policies
 
NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Regulation and Regulated Operations
 
As a regulated entity, the Utility collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility's costs of service.  The Utility's ability to recover a significant portion of its authorized revenue requirements through rates is independent, or “decoupled,” from the volume of the Utility's electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.  Regulatory assets are amortized over the future periods in which the costs are recovered.  If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.
 
The Utility also records a regulatory balancing account asset or liability for differences between actual customer billings and authorized revenue requirements that are probable of recovery or refund.  These differences do not have an impact on net income.  The Utility also records differences between incurred costs and customer billings or authorized revenue meant to recover those costs.  To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively, and the differences do not have an impact on net income.  See “Revenue Recognition” below.
 
To the extent that portions of the Utility's operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.  
 
Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.
 
Cash and Cash Equivalents
 
Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.  
 
Restricted Cash
 
Restricted cash consists primarily of the Utility's cash held in escrow pending the resolution of the remaining disputed claims made by electricity suppliers in the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code.  (See Note 12 below.)  
 
Allowance for Doubtful Accounts Receivable
 
Accounts receivable are primarily composed of trade receivables and unbilled revenue.  PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record accounts receivable at estimated net realizable value.  The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.
 
Inventories
 
Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground represents gas that is recorded to inventory when purchased and then expensed as the gas is withdrawn for distribution  to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed.
 
 
      The Utility also purchases greenhouse gas emission allowances that are recorded as inventory. They are carried at weighted average cost and included in Other Noncurrent Assets - Other in the Consolidated Balance Sheets.  The costs of the greenhouse gas emissions are expensed and recoverable through rates.
 
Property, Plant, and Equipment
 
Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.) The Utility's total estimated useful lives and balances of its property, plant, and equipment were as follows:
 
 
 
Estimated Useful
 
Balance at December 31,
(in millions, except estimated useful lives)
Lives (years)
 
2013
 
2012
Electricity generating facilities (1)
20 to 100
 
$
9,116
 
$
8,253
Electricity distribution facilities
10 to 55
 
 
25,333
 
 
23,767
Electricity transmission
10 to 70
 
 
8,429
 
 
7,681
Natural gas distribution facilities
20 to 53
 
 
9,117
 
 
8,257
Natural gas transportation and storage
5 to 65
 
 
5,265
 
 
4,314
Construction work in progress
 
 
 
1,834
 
 
1,894
Total property, plant, and equipment
 
 
 
59,094
 
 
54,166
Accumulated depreciation
 
 
 
(17,843
 ) 
 
(16,643
)
Net property, plant, and equipment
 
 
$
41,251
 
$
37,523
 
 
 
 
 
 
 
 
 (1) Balance includes nuclear fuel inventories.  Stored nuclear fuel inventory is stated at weighted average cost.  Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output.  (See Note 14 below.)
 
 
The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property.  This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment.  The Utility's composite depreciation rates were 3.51% in 2013, 3.63% in 2012, and 3.67% in 2011.  The useful lives of the Utility's property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.  
 
AFUDC
 
AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions and is capitalized as part of the cost of construction.  AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.  The Utility recorded AFUDC related to debt and equity, respectively, of $47 million and $101 million during 2013, $49 million and $107 million during 2012, and $40 million and $87 million during 2011.
 
Asset Retirement Obligations
 
PG&E Corporation and the Utility record an ARO at discounted fair value in the period in which the obligation is incurred if the discounted fair value can be reasonably estimated.  In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset.  In each subsequent period, the ARO is accreted to its present value.  PG&E Corporation and the Utility also record an ARO if a legal obligation to perform an asset removal exists and can be reasonably estimated, but performance is conditional upon a future event.  The Utility recognizes timing differences between the recognition of costs and the costs recovered through the ratemaking process as regulatory assets or liabilities.  (See Note 3 below.)  The Utility has an ARO primarily for its nuclear generation facilities, certain fossil fuel-fired generation facilities, and gas transmission system assets.  
 
For the year ended December 31, 2013, the Utility recorded an increase of $596 million to its ARO. The increase primarily reflects a higher expected cost per unit of transmission pipeline replacements.
 
Detailed studies of the cost to decommission the Utility's nuclear generation facilities are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC.  In December 2012, the Utility submitted its updated decommissioning cost estimate with the CPUC.  The estimated undiscounted cost to decommission the Utility's nuclear power plants increased by $1.4 billion in 2012 due to higher spent nuclear fuel disposal costs and an increase in the scope of work.  A significant portion of the increase in decommissioning cost estimates is due to the need to develop on-site storage for spent nuclear fuel because the federal government has failed to meet its obligation to develop a permanent repository for the disposal of nuclear waste from nuclear facilities in the United States.  The Utility expects that it will recover its future on-site storage costs from the federal government. Recovered amounts will be refunded to customers through rates.
 
The estimated undiscounted nuclear decommissioning cost for the Utility's nuclear generation facilities was approximately $3.5 billion at December 31, 2013 and 2012, as filed in the 2012 triennial proceeding.  In future dollars, the estimated nuclear decommissioning cost is approximately $6.1 billion at December 31, 2013 and 2012.  These estimates are based on the 2012 decommissioning cost studies and are prepared in accordance with CPUC requirements.  The estimated nuclear decommissioning cost in future dollars is discounted for GAAP purposes and recognized as an ARO on the Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued in accordance with GAAP was $2.5 billion at December 31, 2013 and 2012.  
 
A reconciliation of the changes in the ARO liability is as follows:
(in millions)
 
 
ARO liability at December 31, 2011
$
1,609
Revision in estimated cash flows
 
1,301
Accretion
 
101
Liabilities settled
 
(92
)
ARO liability at December 31, 2012
 
2,919
Revision in estimated cash flows
 
596
Accretion
 
130
Liabilities settled
 
(107
)
ARO liability at December 31, 2013
$
3,538
 
 
The Utility has identified the following AROs for which a reasonable estimate of fair value could not be made.  As a result, the Utility has not recorded a liability related to these AROs:  
∙      Restoration of land to its pre-use condition under the terms of certain land rights agreements.  Land rights will be maintained for the foreseeable future, and therefore, the Utility cannot reasonably estimate the settlement date(s) or range of settlement dates for the obligations associated with these assets;  
 
Removal and proper disposal of lead-based paint contained in some Utility facilities.  The Utility does not have information available that specifies which facilities contain lead-based paint and, therefore, cannot reasonably estimate the settlement date(s) associated with the obligations; and
 
Removal of certain communications equipment from leased property, and retirement activities associated with substation and certain hydroelectric facilities.  The Utility will maintain and continue to operate its hydroelectric facilities until the operation of a facility becomes uneconomical.  The operation of the majority of the Utility's hydroelectric facilities is currently, and for the foreseeable future, expected to be economically beneficial.  Therefore, the settlement date(s) cannot be reasonably estimated at this time.
 
 
Disallowance of Plant Costs
 
PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.  During 2013 and 2012, the Utility recorded charges of $196 million and $353 million, respectively, for PSEP capital costs that are expected to exceed the CPUC's authorized levels or that are specifically disallowed.  (See “Natural Gas Matters” in Note 14 below).  No material disallowance losses were recorded in 2011.
 
Gains and Losses on Debt Extinguishments
 
Deferred gains and losses on debt extinguishments are recorded to current assets - regulatory assets and other noncurrent assets - regulatory assets in the Consolidated Balance Sheets. Gains and losses on debt extinguishments associated with regulated operations are deferred and amortized over a period consistent with the recovery of costs through regulated rates.  PG&E Corporation and the Utility recorded unamortized loss on debt extinguishments, net of gain, of $157 million, $163 million, and $186 million at December 31, 2013, 2012, and 2011, respectively.  The amortization expense related to this loss was $23 million in both 2013 and 2012, and $18 million in 2011.  
 
Revenue Recognition
 
The Utility recognizes revenues as electricity and natural gas services are delivered, and includes amounts for services rendered but not yet billed at the end of the period. 
 
The CPUC authorizes most of the Utility's revenues in the Utility's GRC and its GT&S rate cases, which generally occur every three years.  In general, the Utility's ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility's sales of electricity and natural gas services.  The Utility recognizes revenues once they have been authorized for rate recovery, amounts are objectively determinable and probable of recovery, and amounts are expected to be collected within 24 months.  Generally, the revenue is recognized ratably over the year. 
 
The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs.  Generally, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred.
 
The FERC authorizes the Utility's revenue requirements in periodic (often annual) TO rate cases.  The Utility's ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility's electricity sales, and revenue is recognized only for amounts billed and unbilled.
 
The Utility's revenues and net income can be affected by incentive ratemaking mechanisms that adjust rates depending on the extent to which the Utility meets certain performance criteria. 
 
Income Taxes
 
PG&E Corporation and the Utility use the liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year.  PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.  (See Note 8 below.)
 
PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position.  The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.  
 
Investment tax credits are deferred and amortized to income over time. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.  PG&E Corporation amortizes its investment tax credits over the projected investment recovery period.
 
PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  PG&E Corporation files a combined state income tax return in California.  PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.
 
Nuclear Decommissioning Trusts
 
The Utility's nuclear generation facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.  
 
The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.”  Since the Utility's nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion.  Therefore, all unrealized losses are considered other-than-temporary impairments.  Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates.  Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility's earnings or accumulated other comprehensive income.  The cost of debt and equity securities sold by the trust is determined by specific identification.
 
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 December 31, 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 December 31, 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 $362 million from 2010 to 2013 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 December 31, 2013 and 2012, the carrying amount of PG&E Corporation's investment in these agreements was $98 million and $166 million, respectively.  PG&E Corporation has no material remaining commitment to fund these agreements.  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.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs at December 31, 2013, it did not consolidate any of them.
 
Other Accounting Policies
 
For other accounting policies impacting PG&E Corporation's and the Utility's consolidated financial statements, see “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies” in Note 14 of the Notes to the Consolidated Financial Statements.
 
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 for the year ended December 31, 2013 consisted of the following:
 
 
Pension
 
Other
 
Other
 
 
 
(in millions)
Benefits
 
Benefits
 
Investments
 
Total
Beginning balance
$
(28
 ) 
$
(77
 ) 
$
4
 
$
(101
)
Other comprehensive income before reclassifications:
 
 
 
 
 
 
 
 
 
 
 
      Unrecognized net actuarial loss (net of taxes of $804,
 
 
 
 
 
 
 
 
 
 
 
      $35, and $0, respectively)
 
1,169
 
 
45
 
 
-
 
 
1,214
     Transfer to regulatory account (net of taxes of
 
 
 
 
 
 
 
 
 
 
 
     $790, $22, and $0, respectively)
 
(1,150
 ) 
 
31
 
 
-
 
 
(1,119
)
      Gain on investments (net of taxes of $0, $0, and $26,
 
 
 
 
 
 
 
 
 
 
 
      respectively)
 
-
 
 
-
 
 
38
 
 
38
Amounts reclassified from other comprehensive income: (1)
 
 
 
 
 
 
 
 
 
 
 
      Amortization of prior service cost (net of taxes of
 
 
 
 
 
 
 
 
 
 
 
      $8, $10, and $0, respectively)
 
12
 
 
13
 
 
-
 
 
25
      Amortization of net actuarial loss (net of taxes of
 
 
 
 
 
 
 
 
 
 
 
      $45, $3, and $0, respectively)
 
66
 
 
3
 
 
-
 
 
69
     Transfer to regulatory account (net of taxes of
 
 
 
 
 
 
 
 
 
 
 
     $54, $0, and $0, respectively)
 
(76
 ) 
 
-
 
 
-
 
 
(76
)
Net current period other comprehensive income
 
21
 
 
92
 
 
38
 
 
151
Ending balance
$
(7)
 
$
15
 
$
42
 
$
50
 
 
 
 
 
 
 
 
 
 
 
 
 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)
 
With the exception of other investments, there was no material difference between PG&E Corporation and the Utility for the information disclosed above.
 
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 9 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 are composed of the following:
 
 
 
Balance at December 31,
 
Recovery
(in millions)
2013
 
2012
 
Period
Pension benefits (1)
$
1,444
 
$
3,275
 
N/A (4)
Deferred income taxes (1)
 
1,835
 
 
1,627
 
1 - 45 years
Utility retained generation (2)
 
503
 
 
552
 
11 years
Environmental compliance costs (1)
 
628
 
 
604
 
32 years
Price risk management (1)
 
106
 
 
210
 
9 years
Electromechanical meters (3)
 
135
 
 
194
 
4 years
Unamortized loss, net of gain, on reacquired debt (1)
 
135
 
 
141
 
13 years
Other
 
127
 
 
206
 
Various
Total long-term regulatory assets
$
4,913
 
$
6,809
 
 
 
 
 
 
 
 
 
 
 
(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP and also includes amounts that otherwise would be recorded to accumulated other comprehensive loss in the Consolidated Balance Sheets.  (See Note 11 below.)
 
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility's proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility's retained generation assets.  The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.  
 
(3) Represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices.
 
(4) The Utility expects to continuously recover pension benefits.
 
In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest.  Accordingly, the Utility earns a return only on its regulatory assets for retained generation, regulatory assets for electromechanical meters, and regulatory assets for unamortized loss, net of gain, on reacquired debt.
 
 
 
Regulatory Liabilities
 
Long-term regulatory liabilities are composed of the following:
 
 
 
Balance at December 31,
(in millions)
2013
 
2012
Cost of removal obligations (1)
$
3,844
 
$
3,625
Recoveries in excess of AROs (2)
 
748
 
 
620
Public purpose programs (3)
 
587
 
 
590
Other
 
481
 
 
253
Total long-term regulatory liabilities
$
5,660
 
$
5,088
 
 
 
 
 
 
 
(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.
 
(2) Represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility's nuclear generation facilities.  Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments.  (See Note 10 below.)
 
(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
 
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 the Utility's authorized revenue requirement and actual customer billings, and (2) differences between incurred costs and customer billings.  To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable.  Regulatory balancing accounts that the Utility does not expect to collect or refund over the next 12 months are included in other noncurrent assets - regulatory assets or noncurrent liabilities - regulatory liabilities, respectively, in the Consolidated Balance Sheets.  
 
The Utility sells and delivers electricity and natural gas, which includes procuring and generating electricity.  The Utility also administers public purpose programs, primarily related to customer energy efficiency programs.  The balancing accounts associated with these items 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 receivable and payable are composed of the following:
 
 
 
Receivable
 
Balance at December 31,
(in millions)
2013
 
2012
Electric distribution
$
102
 
$
219
Utility generation
 
57
 
 
117
Gas distribution
 
70
 
 
44
Energy procurement
 
410
 
 
193
Public purpose programs
 
56
 
 
48
Other
 
429
 
 
315
Total regulatory balancing accounts receivable
$
1,124
 
$
936
 
 
 
 
 
 
 
 
 
Payable
 
Balance at December 31,
(in millions)
2013
 
2012
Energy procurement
$
298
 
$
116
Public purpose programs
 
171
 
 
131
Other
 
539
 
 
387
Total regulatory balancing accounts payable
$
1,008
 
$
634
 
 
 
 
 
 
 
Debt
Debt
 
NOTE 4: DEBT
 
Long-Term Debt
 
The following table summarizes PG&E Corporation's and the Utility's long-term debt:
 
 
December 31,
(in millions)
2013
 
2012
PG&E Corporation
 
 
 
Senior notes, 5.75%, due 2014
 
350
 
 
350
Less: current portion
 
(350
 ) 
 
-
Total senior notes
 
-
 
 
350
Total PG&E Corporation long-term debt
 
-
 
 
350
Utility
 
 
 
 
 
Senior notes:
 
 
 
 
 
6.25% due 2013
 
-
 
 
400
4.80% due 2014
 
539
 
 
1,000
5.625% due 2017
 
700
 
 
700
8.25% due 2018
 
800
 
 
800
3.50% due 2020
 
800
 
 
800
4.25% due 2021
 
300
 
 
300
3.25% due 2021
 
250
 
 
250
2.45% due 2022
 
400
 
 
400
3.25% due 2023
 
375
 
 
-
3.85% due 2023
 
300
 
 
-
6.05% due 2034
 
3,000
 
 
3,000
5.80% due 2037
 
950
 
 
950
6.35% due 2038
 
400
 
 
400
6.25% due 2039
 
550
 
 
550
5.40% due 2040
 
800
 
 
800
4.50% due 2041
 
250
 
 
250
4.45% due 2042
 
400
 
 
400
3.75% due 2042
 
350
 
 
350
4.60% due 2043
 
375
 
 
-
5.125% due 2043
 
500
 
 
-
Less: current portion
 
(539
 ) 
 
(400
)
Unamortized discount, net of premium
 
(51
 ) 
 
(51
)
Total senior notes, net of current portion
 
11,449
 
 
10,899
Pollution control bonds:
 
 
 
 
 
Series 1996 C, E, F, 1997 B, variable rates (1), due 2026 (2)
 
614
 
 
614
Series 2004 A-D, 4.75%, due 2023 (3)
 
345
 
 
345
Series 2009 A-D, variable rates (4), due 2016 and 2026 (5)
 
309
 
 
309
Total pollution control bonds
 
1,268
 
 
1,268
Total Utility long-term debt, net of current portion
 
12,717
 
 
12,167
Total consolidated long-term debt, net of current portion
$
12,717
 
$
12,517
 
 
 
 
 
 
(1)  At December 31, 2013, interest rates on these bonds and the related loans ranged from 0.01% to 0.04%.
(2)  Each series of these bonds is supported by a separate letter of credit.  In April 2013, the letters of credit were extended to April 1, 2018.  Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.
(3) The Utility has obtained credit support from an insurance company for these bonds.
(4) At December 31, 2013, interest rates on these bonds and the related loans ranged from 0.01% to 0.02%.
(5) Each series of these bonds is supported by a separate direct-pay letter of credit.  Series A and B letters of credit expire on May 31, 2016.  In October 2013, Series C and D letters of credit were extended to December 3, 2016 to coincide with the maturity of the underlying bonds.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.
 
 
Pollution Control Bonds
 
The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility.  Substantially all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility's Diablo Canyon nuclear power plant.  In 1999, the Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sale agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding.  The Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.
 
Repayment Schedule
 
PG&E Corporation's and the Utility's combined short-term and long-term debt principal repayment amounts at December 31, 2013 are reflected in the table below:
 
(in millions,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 except interest rates)
2014
 
2015
 
2016
 
2017
 
 
2018
 
Thereafter
 
Total
PG&E Corporation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average fixed interest rate
 
5.75
%
 
 
              -
 
 
 
              -
 
 
 
              -
 
 
 
              -
 
 
 
              -
 
 
 
5.75
%
Fixed rate obligations
$
       350
 
 
$
              -
 
 
$
              -
 
 
$
              -
 
 
$
              -
 
 
$
              -
 
 
$
           350
 
Utility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average fixed interest rate
 
4.80
%
 
 
              -
 
 
 
              -
 
 
 
5.63
%
 
 
8.25
%
 
 
5.06
%
 
 
5.29
%
Fixed rate obligations
$
          539
 
 
$
              -
 
 
$
              -
 
 
$
          700
 
 
$
          800
 
 
$
      10,345
 
 
$
      12,384
 
Variable interest rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    as of December 31, 2013
 
              -
 
 
 
              -
 
 
 
0.02
%
 
 
              -
 
 
 
0.02
%
 
 
              -
 
 
 
0.02
%
Variable rate obligations (1)
$
              -
 
 
$
              -
 
 
$
          309
 
 
$
              -
 
 
$
          614
 
 
$
              -
 
 
$
          923
 
Total consolidated debt
$
          889
 
 
$
              -
 
 
$
       309
 
 
$
         700
 
 
$
       1,414
 
 
$
     10,345
 
 
$
     13,657
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (1) These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on May 31, 2016, December 3, 2016, or April 1, 2018.
 
Short-term Borrowings
 
The following table summarizes PG&E Corporation's and the Utility's outstanding borrowings under their revolving credit facilities and the Utility's commercial paper program at December 31, 2013:
 
 
 
 
 
 
Letters of
 
 
 
 
 
 
 
Termination
 
Facility
 
 Credit
 
 
 
Commercial
 
Facility
(in millions)
Date
 
Limit
 
Outstanding
 
Borrowings
 
Paper
 
Availability
PG&E Corporation
April 2018
 
$
300
(1)
 
$
 
 
$
260
 
$
-
 
 
$
40
 
Utility
April 2018
 
 
3,000
(2)
 
 
79
 
 
-
 
 
914
(3)
 
 
2,007
(3)
Total revolving credit facilities
 
 
$
3,300
 
 
$
79
 
$
260
 
$
914
 
 
$
2,047
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
(2) Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
(3) The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.
 
For 2013, the average outstanding borrowings on PG&E Corporation's revolving credit facility was $214 million and the maximum outstanding balance during the year was $260 million.  For 2013, the Utility's average outstanding commercial paper balance was $542 million and the maximum outstanding balance during the year was $1.1 billion.  The Utility did not borrow under its credit facility in 2013.  
 
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.  PG&E Corporation's and the Utility's revolving credit facilities may be used for working capital, the repayment of commercial paper, and other corporate purposes.  At PG&E Corporation's and the Utility's request and at the sole discretion of each lender, the facilities may be extended for additional periods.  Provided certain conditions are met, PG&E Corporation and the Utility have the right to increase, in one or more requests, given not more frequently than once a year, the aggregate lenders' commitments under the revolving credit facilities by up to $100 million and $500 million, respectively, in the aggregate for all such increases.
 
Borrowings under the revolving credit facilities (other than swingline loans) bear interest based, at PG&E Corporation's and the Utility's election, on (1) a London Interbank Offered Rate plus an applicable margin or (2) the base rate plus an applicable margin.  The base rate will equal the higher of the following: the administrative agent's announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin.  Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods.  PG&E Corporation and the Utility also will pay a facility fee on the total commitments of the lenders under the revolving credit facilities.  The applicable margins and the facility fees will be based on PG&E Corporation's and the Utility's senior unsecured debt ratings issued by Standard & Poor's Rating Services and Moody's Investor Service.  Facility fees are payable quarterly in arrears.
 
PG&E Corporation's and the Utility's revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes.  In addition, the revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter.  PG&E Corporation's revolving credit facility agreement also requires that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility.  
      
Commercial Paper Programs
 
                  At December 31, 2013, the average yield on outstanding Utility commercial paper was 0.26%.
 
In January 2014, PG&E Corporation established a commercial paper program.  PG&E Corporation will treat the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.
 
The borrowings from PG&E Corporation and the Utility's commercial paper programs are used primarily to fund temporary financing needs.  Liquidity support for these borrowings is provided by available capacity under their respective revolving credit facilities, as described above.  The commercial paper may have maturities up to 365 days and ranks equally with PG&E Corporation's and the Utility's other unsubordinated and unsecured indebtedness.  Commercial paper notes are sold at an interest rate dictated by the market at the time of issuance.  
 
Common Stock And Share-Based Compensation
Common Stock And Share-Based Compensation
 
NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION
 
PG&E Corporation had 456,670,424 shares of common stock outstanding at December 31, 2013.  PG&E Corporation held all of the Utility's outstanding common stock at December 31, 2013.  
 
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 December 31, 2013, PG&E Corporation had       sold common stock having an aggregate gross sales price of $395 million and had the ability to issue an additional $5 million of its common stock under this agreement.  During 2013, PG&E Corporation paid commissions of $3 million under this agreement.
 
            During 2013, PG&E Corporation issued 26 million shares of its common stock for aggregate net cash proceeds of $1,045 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;
 8 million shares were issued for cash proceeds of $290 million under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans; and
 11 million shares were sold for cash proceeds of $455 million, net of commissions paid of $4 million, under equity       distribution agreements.
 
Dividends
 
The Board of Directors of PG&E Corporation and the Utility declare dividends quarterly.  Under the Utility's Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility's preferred stock have been paid.  For 2013, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.455 per share.
 
Under their respective credit agreements, PG&E Corporation and the Utility are each required to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%.  Based on the calculation of this ratio, $493 million of the Utility's reinvested earnings was restricted at December 31, 2013.  In addition, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average.  At December 31, 2013, the Utility was required to maintain reinvested earnings of $7.4 billion as equity to meet this requirement.
 
In addition, to comply with the revolving credit facility's 65% ratio requirement and the CPUC's requirement to maintain a 52% equity component, $7.7 billion and $14.6 billion of the Utility's net assets were restricted at December 31, 2013 to comply with these requirements, respectively, and could not be transferred to PG&E Corporation in the form of cash dividends.  As a holding company, PG&E Corporation depends on cash distributions from the Utility to meet its debt service and other financial obligations and to pay dividends on its common stock.
 
Long-Term Incentive Plan
 
The PG&E Corporation LTIP permits various forms of share-based incentive awards, including stock options, stock appreciation rights, restricted stock awards, RSUs, performance shares, deferred compensation awards, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards.  A maximum of 12 million shares of PG&E Corporation common stock (subject to adjustment for changes in capital structure, stock dividends, or other similar events) has been reserved for issuance under the 2006 LTIP, of which 3,310,474 shares were available for future awards at December 31, 2013.  
 
The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2013, 2012, and 2011:
 
(in millions)
2013
 
2012
 
2011
Restricted stock units
$
36
 
$
31
 
$
23
Performance shares:
 
 
 
 
 
 
 
 
Equity awards
 
28
 
 
26
 
 
16
Liability awards
 
-
 
 
-
 
 
(13
)
Total compensation expense (pre-tax)
$
64
 
$
57
 
$
26
Total compensation expense (after-tax)
$
38
 
$
34
 
$
16
 
Share-based compensation costs capitalized during 2013, 2012, and 2011 was immaterial.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
 
 
 
Restricted Stock Units
 
RSU awards issued and outstanding under the LTIP generally vest over three year periods.  RSUs generally vest in 20% increments on the first business day of March in year one, two, and three, with the remaining 40% vesting on the first business day of March in year four.  Vested RSUs are settled in shares of PG&E Corporation common stock.  Additionally, upon settlement, RSU recipients receive payment for the amount of dividend equivalents associated with the vested RSUs that have accrued since the date of grant.  RSU expense is generally recognized ratably over the vesting period based on the fair values determined.  The weighted average grant-date fair value for RSUs granted during 2013, 2012, and 2011 was $42.92, $42.17, and $45.10, respectively.  The total fair value of RSUs that vested during 2013, 2012, and 2011 was $30 million, $18 million, and $11 million, respectively.  The tax benefit from RSUs that vested during each period was not material.  As of December 31, 2013, $50 million of total unrecognized compensation costs related to nonvested RSUs was expected to be recognized over the remaining weighted average period of 2.17 years.
 
The following table summarizes RSU activity for 2013:
 
 
 
Number of
 
Weighted Average Grant-
 
Restricted Stock Units
 
Date Fair Value
Nonvested at January 1
2,069,291
 
$
42.52
Granted
993,115
 
$
42.92
Vested
(719,071
 ) 
$
41.03
Forfeited
(43,314
 ) 
$
42.68
Nonvested at December 31
2,300,021
 
$
43.16
 
 
Performance Shares
 
Performance shares awarded to recipients under the LTIP are for a specified number of shares of common stock (or cash with respect to grants before 2010) based on PG&E Corporation's total shareholder return relative to a specified group of industry peer companies over a three-year performance period.  Performance shares vest after three years of service.  Performance share expense is generally recognized ratably over the applicable three-year period based on the fair values determined.  Dividend equivalents on performance shares, if any, will be paid in cash upon the vesting date based on the amount of common stock to which the recipients are entitled.  
 
Total compensation expense for performance shares is based on the grant-date fair value, which is determined using a Monte Carlo simulation valuation model.  The weighted average grant-date fair value for performance shares granted during 2013, 2012, and 2011 was $33.45, $41.93, and $33.91 respectively.  There was no tax benefit associated with performance shares that vested during each of these periods.  As of December 31, 2013, $29 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted average period of 1.25 years.
 
The following table summarizes performance shares classified as equity awards activity for 2013:
 
 
 
Number of
 
Weighted Average Grant-
 
Performance Shares
 
Date Fair Value
Nonvested at January 1
1,497,473
 
$
38.15
Granted
911,620
 
$
33.45
Vested
-
 
$
-
Forfeited (1)
(617,773
 ) 
$
34.22
Nonvested at December 31
1,791,320
 
$
37.85
 
 
 
 
 
(1) Includes performance shares that expired with zero value as performance targets were not met.
 
Preferred Stock
Preferred Stock
NOTE 6: PREFERRED STOCK
 
PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value preferred stock, which may be issued as redeemable or nonredeemable preferred stock.  PG&E Corporation does not have any preferred stock outstanding.
 
The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock.  The Utility specifies that 5,784,825 shares of the $25 par value preferred stock authorized are designated as nonredeemable preferred stock without mandatory redemption provisions.  The following table summarizes the Utility's outstanding preferred stock, none of which had mandatory redemption provisions at December 31, 2013 and 2012:
 
(in millions, except share amounts, redemption
 
 
 
 
 
 
 
price, and par value)
Shares Outstanding
 
Redemption Price
 
Balance
Nonredeemable $25 par value preferred stock
 
 
 
 
 
 
 
5.00% Series
400,000
 
 
N/A
 
$
10
5.50% Series
1,173,163
 
 
N/A
 
 
30
6.00% Series
4,211,662
 
 
N/A
 
 
105
Total nonredeemable preferred stock
5,784,825
 
 
 
 
$
145
 
 
 
 
 
 
 
 
Redeemable $25 par value preferred stock
 
 
 
 
 
 
 
4.36% Series
418,291
 
$
25.75
 
$
11
4.50% Series
611,142
 
 
26.00
 
 
15
4.80% Series
793,031
 
 
27.25
 
 
20
5.00% Series
1,778,172
 
 
26.75
 
 
44
5.00% Series A
934,322
 
 
26.75
 
 
23
Total redeemable preferred stock
4,534,958
 
 
 
 
$
113
Preferred stock
 
 
 
 
 
$
258
 
At December 31, 2013, annual dividends on the Utility's nonredeemable preferred stock ranged from $1.25 to $1.50 per share.  The Utility's redeemable preferred stock is subject to redemption at the Utility's option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date.  At December 31, 2013, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.
 
Dividends on all Utility preferred stock are cumulative.  All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights.  Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.  During each of 2013, 2012, and 2011 the Utility paid $14 million of dividends on preferred stock.
Earnings Per Share
Earnings Per Share
NOTE 7: 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 for 2013, 2012 and 2011.
 
 
Year Ended December 31,
(in millions, except per share amounts)
2013
 
2012
 
2011
Income available for common shareholders
$
814
 
$
816
 
$
844
Weighted average common shares outstanding, basic
 
444
 
 
424
 
 
401
Add incremental shares from assumed conversions:
 
 
 
 
 
 
 
 
Employee share-based compensation
 
1
 
 
1
 
 
1
Weighted average common share outstanding, diluted
 
445
 
 
425
 
 
402
Total earnings per common share, diluted
$
1.83
 
$
1.92
 
$
2.10
 
For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.
Income Taxes
Income Taxes
NOTE 8: INCOME TAXES
 
The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:
 
 
PG&E Corporation
 
Utility
 
Year Ended December 31,
(in millions)
2013
 
2012
 
2011
 
2013
 
2012
 
2011
Current:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Federal
$
(218
 ) 
$
(74
 ) 
$
(77
 ) 
$
(222
 ) 
$
(52
 ) 
$
(83
)
State
 
(26
 ) 
 
33
 
 
152
 
 
(23
 ) 
 
41
 
 
161
Deferred:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Federal
 
552
 
 
374
 
 
504
 
 
604
 
 
404
 
 
534
State
 
(35
 ) 
 
(92
 ) 
 
(135
 ) 
 
(28
 ) 
 
(91
 ) 
 
(128
)
Tax credits
 
(5
 ) 
 
(4
 ) 
 
(4
 ) 
 
(5
 ) 
 
(4
 ) 
 
(4
)
Income tax provision
$
268
 
$
237
 
$
440
 
$
326
 
$
298
 
$
480
 
The following table describes net deferred income tax liabilities:
 
 
PG&E Corporation
 
Utility
 
Year Ended December 31,
(in millions)
2013
 
2012
 
2013
 
2012
Deferred income tax assets:
 
 
 
 
 
 
 
 
 
 
 
Customer advances for construction
$
90
 
$
101
 
$
90
 
$
101
Reserve for damages
 
161
 
 
175
 
 
161
 
 
175
Environmental reserve
 
152
 
 
97
 
 
152
 
 
97
Compensation
 
167
 
 
229
 
 
102
 
 
179
Net operating loss carryforward
 
890
 
 
938
 
 
670
 
 
736
GHG allowances
 
108
 
 
34
 
 
108
 
 
34
Other
 
135
 
 
230
 
 
128
 
 
221
Total deferred income tax assets
$
1,703
 
$
1,804
 
$
1,411
 
$
1,543
Deferred income tax liabilities:
 
 
 
 
 
 
 
 
 
 
 
Regulatory balancing accounts
$
261
 
$
256
 
$
261
 
$
256
Property related basis differences
 
8,048
 
 
7,449
 
 
8,038
 
 
7,447
Income tax regulatory asset
 
748
 
 
663
 
 
748
 
 
663
Other
 
151
 
 
173
 
 
86
 
 
99
Total deferred income tax liabilities
$
9,208
 
$
8,541
 
$
9,133
 
$
8,465
Total net deferred income tax liabilities
$
7,505
 
$
6,737
 
$
7,722
 
$
6,922
Classification of net deferred income tax liabilities:
 
 
 
 
 
 
 
 
 
 
 
Included in current liabilities (assets)
$
(318
 ) 
$
(11
 ) 
$
(320
 ) 
$
(17
)
Included in noncurrent liabilities
 
7,823
 
 
6,748
 
 
8,042
 
 
6,939
Total net deferred income tax liabilities
$
7,505
 
$
6,737
 
$
7,722
 
$
6,922
 
 
The following table reconciles income tax expense at the federal statutory rate to the income tax provision:
 
 
PG&E Corporation
 
Utility
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
Federal statutory income tax rate
35.0
%
 
35.0
%
 
35.0
%
 
35.0
%
 
35.0
%
 
35.0
%
Increase (decrease) in income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
tax rate resulting from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
State income tax (net of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
federal benefit)
(3.1
 ) 
 
(3.9
 ) 
 
1.1
 
 
(2.2
 ) 
 
(3.0
 ) 
 
1.6
 
Effect of regulatory treatment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
of fixed asset differences
(4.2
 ) 
 
(4.1
 ) 
 
(4.4
 ) 
 
(3.8
 ) 
 
(3.9
 ) 
 
(4.2
 ) 
Tax credits
(0.4
 ) 
 
(0.6
 ) 
 
(0.5
 ) 
 
(0.4
 ) 
 
(0.6
 ) 
 
(0.5
 ) 
Benefit of loss carryback
(1.1
 ) 
 
(0.7
 ) 
 
(1.9
 ) 
 
(1.0
 ) 
 
(0.4
 ) 
 
(2.1
 ) 
Non deductible penalties
0.8
 
 
0.6
 
 
6.5
 
 
0.7
 
 
0.5
 
 
6.3
 
Other, net
(2.2
 ) 
 
(3.8
 ) 
 
(1.5
 ) 
 
(0.9
 ) 
 
(0.8
 ) 
 
0.1
 
Effective tax rate
24.8
%
 
22.5
%
 
34.3
%
 
27.4
%
 
26.8
%
 
36.2
%
 
Unrecognized tax benefits
 
The following table reconciles the changes in unrecognized tax benefits:
      
 
PG&E Corporation
 
Utility
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of year
$
581
 
$
506
 
$
714
 
$
575
 
$
503
 
$
712
Additions for tax position taken
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
during a prior year
 
12
 
 
32
 
 
2
 
 
12
 
 
26
 
 
2
Reductions for tax position
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
taken during a prior year
 
(6
 ) 
 
(13
 ) 
 
(198
 ) 
 
(6
 ) 
 
(10
 ) 
 
(196
)
Additions for tax position
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
taken during the current year
 
79
 
 
67
 
 
3
 
 
79
 
 
67
 
 
-
Settlements
 
-
 
 
(11
 ) 
 
(15
 ) 
 
-
 
 
(11
 ) 
 
(15
)
Balance at end of year
$
666
 
$
581
 
$
506
 
$
660
 
$
575
 
$
503
 
The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2013 for PG&E Corporation and the Utility was $29 million, with the remaining balance representing the potential deferral of taxes to later years.
 
Tax settlements and years that remain subject to examination
 
PG&E Corporation participates in the Compliance Assurance Process, a real-time IRS audit intended to expedite resolution of tax matters.  The Compliance Assurance Process audit culminates with a letter from the IRS indicating its acceptance of the return.
 
In January 2014, PG&E Corporation received the IRS closing agreements for the 2008 and 2010 audit years, subject to the approval by the Joint Committee on Taxation of the U.S. Congress.  The IRS has previously accepted the 2009 tax return without adjustments.  The IRS is currently reviewing several matters pertaining to the 2011 and 2012 tax returns.  The most significant of these matters relates to the repairs accounting method changes.
 
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 during 2014.  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 2010, 2011, and 2012 tax returns.  As of December 31, 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.  
 
Carryforwards
 
As of December 31, 2013, PG&E Corporation had approximately $3.3 billion of federal net operating loss carryforwards and $68 million of tax credit carryforwards, which will expire between 2029 and 2033.  In addition, PG&E Corporation had approximately $121 million of loss carryforwards related to charitable contributions, which will expire between 2014 and 2018.  PG&E Corporation believes it is more likely than not the tax benefits associated with the federal operating loss, charitable contributions, and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of December 31, 2013.  As of December 31, 2013, PG&E Corporation had approximately $15 million of federal net operating loss carryforwards related to the tax benefit on employee stock plans that would be recorded in additional paid-in capital when used.
Derivatives And Hedging Activities
Derivatives And Hedging Activities
 
NOTE 9: DERIVATIVES
 
Use of Derivative Instruments
 
The Utility uses both derivative and non-derivative contracts in managing its customers' 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 Consolidated Balance Sheets.  As long as the current ratemaking mechanism discussed above 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 on the Consolidated Balance Sheets.  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.
 
PG&E Corporation and the Utility offset cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement where the right of offset and the intention to offset exist.
 
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 Consolidated Balance Sheets at fair value, but are accounted for under the accrual method of accounting.  Therefore, expenses are recognized as incurred.
 
Electricity Procurement
 
The Utility enters into third-party power purchase agreements for electricity to meet customer needs.  The Utility's third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivatives.  The Utility elects the normal purchase and sale exception for eligible derivatives.
 
A portion of the Utility's third-party power purchase agreements contain market-based pricing terms.  In order to reduce volatility in customer rates, the Utility may enter into financial instruments, such as futures, options, or swaps, to effectively fix and/or cap the price of future purchases and reduce cash flow variability associated with fluctuating electricity prices.  These financial contracts are considered derivatives.
 
 
Electric Transmission Congestion Revenue Rights
 
The California electric transmission grid, controlled by the CAISO, is subject to transmission constraints when there is insufficient transmission capacity to supply the market.  The CAISO imposes congestion charges on market participants to manage transmission congestion.  The revenue generated from congestion charges is allocated to holders of CRRs.  CRRs allow market participants to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities, such as the Utility, are allocated CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market participants).  The Utility can participate in the allocation and auction phases of the annual and monthly CRR processes.  CRRs are considered derivatives.
 
Natural Gas Procurement (Electric Fuels Portfolio)
 
The Utility's electric procurement portfolio is exposed to natural gas price risk primarily through physical natural gas commodity purchases to fuel natural gas generating facilities, and electricity procurement contracts indexed to natural gas prices.  To reduce the volatility in customer rates, the Utility may enter into financial instruments, such as futures, options, or swaps.  The Utility also enters into fixed-price forward contracts for natural gas to reduce future cash flow variability from fluctuating natural gas prices.  These instruments are considered derivatives.
 
Natural Gas Procurement (Core Gas Supply Portfolio)
 
The Utility enters into physical natural gas commodity contracts to fulfill the needs of its residential and smaller commercial customers known as “core” customers.  The Utility does not procure natural gas for industrial and large commercial, or “non-core,” customers.  Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally.  Consequently, varying volumes of natural gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot market to balance such seasonal supply and demand.  The Utility purchases financial instruments, such as futures, swaps and options, as part of its core winter hedging program in order to manage customer exposure to high natural gas prices during peak winter months.  These financial instruments are considered derivatives.
 
 
 
Volume of Derivative Activity
 
At December 31, 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
 
243,213,288
 
79,735,000
 
8,892,500
 
-
 
 
Options
 
169,123,208
 
87,689,708
 
3,450,000
 
-
Electricity
 
Forwards and
 
 
 
 
 
 
 
 
(Megawatt-hours)
 
Swaps
 
2,537,023
 
2,009,505
 
2,008,046
 
1,534,695
 
 
Congestion
 
 
 
 
 
 
 
 
 
 
Revenue Rights
 
73,510,440
 
83,747,782
 
63,718,517
 
29,945,852
 
 
 
 
 
 
 
 
 
 
 
 (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 2019 and 2022.
(3) Amounts shown are for the combined positions of the electric fuels and core gas supply 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 2023.
(3) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(4) Million British Thermal Units.
 
 
Presentation of Derivative Instruments in the Financial Statements
 
In PG&E Corporation's and the Utility's Consolidated Balance Sheets, derivatives are presented on a net basis by counterparty where the right and the intention to offset exists under a master netting agreement.  The net balances include outstanding cash collateral associated with derivative positions.
 
 
 
At December 31, 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
$
42
 
$
(10
 ) 
$
16
 
$
48
Other noncurrent assets - other
 
99
 
 
(4
 ) 
 
-
 
 
95
Current liabilities - other
 
(122
 ) 
 
10
 
 
69
 
 
(43
)
Noncurrent liabilities - other
 
(110
 ) 
 
4
 
 
2
 
 
(104
)
Total commodity risk
$
(91)
 
$
-
 
$
87
 
$
(4)
 
 
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 recorded on PG&E Corporation's and the Utility's derivatives were as follows:
 
 
Commodity Risk
 
For the year ended December 31,
(in millions)
2013
 
2012
 
2011
Unrealized gain/(loss) - regulatory assets and liabilities (1)
$
238
 
$
391
 
$
21
Realized loss - cost of electricity (2)
 
(178
 ) 
 
(486
 ) 
 
(558
)
Realized loss - cost of natural gas (2)
 
(22
 ) 
 
(38
 ) 
 
(106
)
Total commodity risk
$
38
 
$
(133)
 
$
(643)
 
 
 
 
 
 
 
 
 
 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the  Consolidated Statements of Income.  These amounts exclude the impact of cash collateral postings.
(2) These amounts are fully passed through to customers in rates.  Accordingly, net income was not impacted by realized amounts on these instruments.
 
 
Cash inflows and outflows associated with derivatives are included in operating cash flows on PG&E Corporation's and the Utility's Consolidated Statements of Cash Flows.
 
The majority of the Utility's derivatives contain collateral posting provisions tied to the Utility's credit rating from each of the major credit rating agencies.  At December 31, 2013, the Utility's credit rating was investment grade.  If the Utility's credit rating were 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.
 
 
 
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 December 31,
(in millions)
2013
 
2012
Derivatives in a liability position with credit risk-related
 
 
 
 
 
 contingencies that are not fully collateralized
$
(79
 ) 
$
(266
)
Related derivatives in an asset position
 
4
 
 
59
Collateral posting in the normal course of business related to
 
 
 
 
 
these derivatives
 
65
 
 
103
Net position of derivative contracts/additional collateral
 
 
 
 
 
posting requirements (1)
$
(10)
 
$
(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 10: 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.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure 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  December 31, 2013
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting (1)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
226
 
$
-
 
$
-
 
$
-
 
$
226
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
38
 
 
-
 
 
-
 
 
-
 
 
38
  U.S. equity securities
 
1,046
 
 
11
 
 
 
 
 
-
 
 
1,057
  Non-U.S. equity securities
 
457
 
 
-
 
 
-
 
 
-
 
 
457
  U.S. government and agency securities
 
760
 
 
156
 
 
-
 
 
-
 
 
916
  Municipal securities
 
-
 
 
25
 
 
-
 
 
-
 
 
25
  Other fixed-income securities
 
-
 
 
162
 
 
-
 
 
-
 
 
162
Total nuclear decommissioning trusts (2)
 
2,301
 
 
354
 
 
-
 
 
-
 
 
2,655
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 9)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
 
2
 
 
27
 
 
107
 
 
3
 
 
139
  Gas
 
-
 
 
5
 
 
-
 
 
(1
 ) 
 
4
Total price risk management instruments
 
2
 
 
32
 
 
107
 
 
2
 
 
143
Rabbi trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Fixed-income securities
 
-
 
 
39
 
 
-
 
 
-
 
 
39
  Life insurance contracts
 
-
 
 
70
 
 
-
 
 
-
 
 
70
Total rabbi trusts
 
-
 
 
109
 
 
-
 
 
-
 
 
109
Long-term disability trust
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
9
 
 
-
 
 
-
 
 
-
 
 
9
  U.S. equity securities
 
-
 
 
14
 
 
-
 
 
-
 
 
14
  Non-U.S. equity securities
 
-
 
 
12
 
 
-
 
 
-
 
 
12
  Fixed-income securities
 
-
 
 
122
 
 
-
 
 
-
 
 
122
Total long-term disability trust
 
9
 
 
148
 
 
-
 
 
-
 
 
157
Other investments
 
84
 
 
-
 
 
-
 
 
-
 
 
84
Total assets
$
2,622
 
$
643
 
$
107
 
$
2
 
$
3,374
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 9)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
$
19
 
$
72
 
$
137
 
$
(84
 ) 
$
144
  Gas
 
1
 
 
3
 
 
-
 
 
(1
 ) 
 
3
Total liabilities
$
20
 
$
75
 
$
137
 
$
(85)
 
$
147
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $313 million, primarily related to deferred taxes on 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 9)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  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 9)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  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, primarily related to deferred taxes on 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 table 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 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 using 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 any transfers between levels in the fair value hierarchy as of the end of the reporting period. For the years ended December 31, 2013 and 2012, there were no significant transfers between levels.
 
 
Level 3 Measurements and Sensitivity Analysis
 
The Utility's market and credit risk management function, which reports to the Chief Risk Officer of the Utility, is responsible for determining the fair value of the Utility's price risk management derivatives.  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 fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.
 
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 9 above.)
 
 
 
Fair Value at
 
 
 
 
 
 
 
(in millions)
 
December 31, 2013
 
 
 
 
 
 
 
Fair Value Measurement
 
Assets
 
Liabilities
 
Valuation Technique
 
Unobservable Input
 
Range (1)
Congestion revenue rights
 
$
107
 
$
32
 
Market approach
 
CRR auction prices
 
$
(6.47) - 12.04
Power purchase agreements
 
$
-
 
$
105
 
Discounted cash flow
 
Forward prices
 
$
23.43 - 51.75
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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 table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2013 and 2012, respectively:
 
 
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)
 
49
 
 
(5
)
Liability balance as of December 31
$
(30)
 
$
(79)
 
 
 
 
 
 
    (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 December 31, 2013 and 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 December 31, 2013 and 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):
 
 
At December 31,
 
2013
 
2012
(in millions)
Carrying Amount
 
Level 2 Fair Value
 
Carrying Amount
 
Level 2 Fair Value
Debt (Note 4)
 
 
 
 
 
 
 
 
 
 
 
PG&E Corporation
$
350
 
$
354
 
$
349
 
$
371
Utility
 
12,334
 
 
13,444
 
 
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 December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
$
38
 
$
-
 
$
-
 
$
38
  Equity securities
 
 
 
 
 
 
 
 
 
 
 
  U.S.
 
246
 
 
811
 
 
-
 
 
1,057
  Non-U.S.
 
215
 
 
242
 
 
-
 
 
457
  Debt securities
 
 
 
 
 
 
 
 
 
 
 
    U.S. government and agency securities
 
870
 
 
51
 
 
(5
 ) 
 
916
    Municipal securities
 
24
 
 
2
 
 
(1
 ) 
 
25
    Other fixed-income securities
 
163
 
 
1
 
 
(2
 ) 
 
162
Total nuclear decommissioning trusts (1)
 
1,556
 
 
1,107
 
 
(8
 ) 
 
2,655
Other investments
 
13
 
 
71
 
 
-
 
 
84
Total
$
1,569
 
$
1,178
 
$
(8)
 
$
2,739
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 $313 million and $240 million at December 31, 2013 and 2012, respectively, primarily related to deferred taxes on appreciation of investment value.
 
 
 
The fair value of debt securities by contractual maturity is as follows:
 
(in millions)
As of December 31, 2013
Less than 1 year
$
22
1-5 years
 
519
5-10 years
 
230
More than 10 years
 
332
Total maturities of debt securities
$
1,103
 
The following table provides a summary of activity for the debt and equity securities:
 
 
2013
 
2012
 
2011
(in millions)
 
 
 
 
 
 
 
 
Proceeds from sales and maturities of nuclear decommissioning trust
 
 
 
 
 
 
 
 
investments
$
1,619
 
$
1,133
 
$
1,928
Gross realized gains on sales of securities held as available-for-sale
 
94
 
 
19
 
 
43
Gross realized losses on sales of securities held as available-for-sale
 
(13
 ) 
 
(17
 ) 
 
(30
)
 
Employee Benefit Plans
Employee Benefit Plans
 
NOTE 11: EMPLOYEE BENEFIT PLANS
 
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.  Additionally, eligible employees hired after December 31, 2012 participate in the cash balance plan that was added to the defined benefit pension plan in 2012.  Eligible employees hired before December 31, 2012 were given a one-time election to participate in the cash balance plan prospectively, or to continue participating in the existing defined benefit plan.  The trusts underlying certain of these plans are qualified trusts under the Internal Revenue Code of 1986, as amended.  If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations.  PG&E Corporation and the Utility use a December 31 measurement date for all plans.
 
PG&E Corporation's and the Utility's funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements.  Based upon current assumptions and available information, the Utility's minimum funding requirements related to its pension plans was zero.  
 
Change in Plan Assets, Benefit Obligations, and Funded Status
 
The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans' aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2013 and 2012:
 
Pension Benefits
 
(in millions)
2013
 
2012
Change in plan assets:
 
 
 
Fair value of plan assets at January 1
$
12,141
 
$
10,993
Actual return on plan assets
 
673
 
 
1,488
Company contributions
 
323
 
 
282
Benefits and expenses paid
 
(610
 ) 
 
(622
)
Fair value of plan assets at December 31
$
12,527
 
$
12,141
 
 
 
 
 
 
Change in benefit obligation:
 
 
 
 
 
Projected benefit obligation at January 1
$
15,541
 
$
14,000
Service cost for benefits earned
 
468
 
 
396
Interest cost
 
627
 
 
658
Actuarial (gain) loss
 
(1,950
 ) 
 
1,099
Plan amendments
 
-
 
 
9
Transitional costs
 
1
 
 
1
Benefits and expenses paid
 
(610
 ) 
 
(622
)
Projected benefit obligation at December 31 (1)
$
14,077
 
$
15,541
 
 
 
 
 
 
Funded status:
 
 
 
 
 
Current liability
$
(6
 ) 
$
(6
)
Noncurrent liability
 
(1,544
 ) 
 
(3,394
)
Accrued benefit cost at December 31
$
(1,550)
 
$
(3,400)
 
 
 
 
 
 
 (1) PG&E Corporation's accumulated benefit obligation was $12,659  million and $13,778 million at December 31, 2013 and 2012, respectively.
 
Other Benefits
 
(in millions)
2013
 
2012
Change in plan assets:
 
 
 
 
 
Fair value of plan assets at January 1
$
1,758
 
$
1,491
Actual return on plan assets
 
64
 
 
191
Company contributions
 
145
 
 
149
Plan participant contribution
 
64
 
 
55
Benefits and expenses paid
 
(139
 ) 
 
(128
)
Fair value of plan assets at December 31
$
1,892
 
$
1,758
 
 
 
 
 
 
Change in benefit obligation:
 
 
 
 
 
Benefit obligation at January 1
$
1,940
 
$
1,885
Service cost for benefits earned
 
53
 
 
49
Interest cost
 
74
 
 
83
Actuarial gain
 
(415
 ) 
 
(23
)
Plan amendments
 
-
 
 
5
Benefits paid
 
(123
 ) 
 
(119
)
Federal subsidy on benefits paid
 
4
 
 
5
Plan participant contributions
 
64
 
 
55
Benefit obligation at December 31
$
1,597
 
$
1,940
 
 
 
 
 
 
Funded status (1):
 
 
 
 
 
Noncurrent asset
$
352
 
$
-
Noncurrent liability
 
(57
 ) 
 
(181
)
Accrued benefit cost at December 31
$
295
 
$
(181)
 
 
 
 
 
 
 (1) At December 31, 2013, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.       At December 31, 2012, both the postretirement medical plan and the postretirement life insurance plan were in underfunded positions.
 
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
 
Components of Net Periodic Benefit Cost
 
Net periodic benefit cost as reflected in PG&E Corporation's Consolidated Statements of Income was as follows:
 
Pension Benefits
 
(in millions)
2013
 
2012
 
2011
Service cost for benefits earned
$
468
 
$
396
 
$
320
Interest cost
 
627
 
 
658
 
 
660
Expected return on plan assets
 
(650
 ) 
 
(598
 ) 
 
(669
)
Amortization of prior service cost
 
20
 
 
20
 
 
34
Amortization of net actuarial loss
 
111
 
 
123
 
 
50
Net periodic benefit cost
 
576
 
 
599
 
 
395
Less: transfer to regulatory account (1)
 
(238
 ) 
 
(301
 ) 
 
(139
)
Total
$
338
 
$
298
 
$
256
 
 
 
 
 
 
 
 
 
 (1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates
 
Other Benefits
 
(in millions)
2013
 
2012
 
2011
Service cost for benefits earned
$
53
 
$
49
 
$
42
Interest cost
 
74
 
 
83
 
 
91
Expected return on plan assets
 
(79
 ) 
 
(77
 ) 
 
(82
)
Amortization of transition obligation
 
-
 
 
24
 
 
26
Amortization of prior service cost
 
23
 
 
25
 
 
27
Amortization of net actuarial loss
 
6
 
 
6
 
 
4
Net periodic benefit cost
$
77
 
$
110
 
$
108
 
 
 
 
 
 
 
 
 
 
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.  
 
Components of Accumulated Other Comprehensive Income
 
PG&E Corporation and the Utility record the net periodic benefit cost for pension benefits and other benefits as a component of accumulated other comprehensive income, net of tax.  Net periodic benefit cost is composed of unrecognized prior service costs, unrecognized gains and losses, and unrecognized net transition obligations as components of accumulated other comprehensive income, net of tax.  
 
Regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between pension expense or income calculated in accordance with GAAP for accounting purposes and pension expense or income for ratemaking, which is based on a funding approach.  A regulatory adjustment is also recorded for the amounts that would otherwise be charged to accumulated other comprehensive income for the pension benefits related to the Utility's defined benefit pension plan.  To the extent the other benefits are in an overfunded position, the Utility records a regulatory liability related to its other benefits and long term disability costs, for the excess of cumulative income for ratemaking over cumulative other benefits expense calculated in accordance with GAAP, and a portion of the credit balance in accumulated other comprehensive income.  However, this recovery mechanism does not allow the Utility to record a regulatory asset for an underfunded position related to other benefits.  Therefore, the charge remains in accumulated other comprehensive income (loss) for other benefits.
 
 
The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2014 are as follows:
 
Pension Benefit
(in millions)
 
Unrecognized prior service cost
$
20
Unrecognized net loss
 
2
Total
$
22
 
Other Benefits
(in millions)
 
 
Unrecognized prior service cost
$
23
Unrecognized net loss
 
2
Total
$
25
 
 
There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation and the Utility.
 
Valuation Assumptions
 
The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs.  The following weighted average year-end assumptions were used in determining the plans' projected benefit obligations and net benefit cost.
 
 
Pension Benefits
 
Other Benefits
 
December 31,
 
December 31,
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
Discount rate
4.89
%
 
3.98
%
 
4.66
%
 
4.70 - 5.00
%
 
3.75 - 4.08
%
 
4.41 - 4.77
%
Average rate of future
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
compensation increases
4.00
%
 
4.00
%
 
5.00
%
 
-
 
 
-
 
 
-
 
Expected return on plan assets
6.50
%
 
5.40
%
 
5.50
%
 
3.50 - 6.70
%
 
2.90 - 6.10
%
 
4.40 - 5.50
%
 
The assumed health care cost trend rate as of December 31, 2013 was 8%, decreasing gradually to an ultimate trend rate in 2020 and beyond of approximately 5%.  A one-percentage-point change in assumed health care cost trend rate would have the following effects:
 
 
 
One-
 
One-
 
Percentage-
 
Percentage-
 
Point
 
Point
(in millions)
Increase
 
Decrease
Effect on postretirement benefit obligation
$
86
 
$
(88
)
Effect on service and interest cost
 
9
 
 
(9
)
 
 
Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets.  Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate.  Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 6.5% compares to a ten-year actual return of 8.7%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 494 Aa-grade non-callable bonds at December 31, 2013.  This yield curve has discount rates that vary based on the duration of the obligations.  The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.
Investment Policies and Strategies
 
The financial position of PG&E Corporation's and the Utility's funded employee benefit plans is driven by the relationship between plan assets and liabilities.  As noted above, the funded status is the difference between the fair value of plan assets and projected benefit obligations.  Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs for financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation's and the Utility's investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility.  
 
Interest rate, credit, and equity risk are the key determinants of PG&E Corporation's and the Utility's funded status volatility.  In addition to affecting the trust's fixed-income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields.  To manage this risk, PG&E Corporation's and the Utility's trusts hold significant allocations to fixed-income investments that include U.S. government securities, corporate securities, and other fixed-income securities.  Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return.  The equity investment allocation is implemented through portfolios that include common stock and commingled funds across multiple industry sectors.  Real assets and absolute return investments are held to diversify the trust's holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets.  Real assets include commodities futures, REITS, global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios.
 
Target allocations for equity investments have generally declined in favor of longer-maturity fixed-income investments and real assets as a means of dampening future funded status volatility. Derivative instruments such as equity index futures contracts are used to maintain existing equity exposure while adding exposure to fixed-income securities.  In addition, derivative instruments such as equity index futures and fixed income futures are used to rebalance the fixed income/equity allocation of the pension's portfolio.  Foreign currency exchange contracts are also used to hedge a portion of the currency of the global equity investments.
 
PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets.  The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation.  Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.
 
The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:
 
 
Pension Benefits
 
Other Benefits
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Global equity securities
25
%
 
25
%
 
35
%
 
30
%
 
28
%
 
38
%
Absolute return
5
%
 
5
%
 
5
%
 
3
%
 
4
%
 
4
%
Real assets
10
%
 
10
%
 
10
%
 
8
%
 
8
%
 
8
%
Extended fixed-income securities
3
%
 
3
%
 
3
%
 
-
%
 
-
%
 
-
%
Fixed-income securities
57
%
 
57
%
 
47
%
 
59
%
 
60
%
 
50
%
Total
100
%
 
100
%
 
100
%
 
100
%
 
100
%
 
100
%
 
Fair Value Measurements
 
The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2013 and 2012.  
 
 
Fair Value Measurements
 
At December 31,
 
2013
 
2012
(in millions)
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Pension Benefits:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
70
 
$
-
 
$
-
 
$
70
 
$
112
 
$
-
 
$
-
 
$
112
Global equity securities
 
1,123
 
 
2,363
 
 
-
 
 
3,486
 
 
402
 
 
3,017
 
 
-
 
 
3,419
Absolute return
 
-
 
 
-
 
 
554
 
 
554
 
 
-
 
 
-
 
 
513
 
 
513
Real assets
 
562
 
 
-
 
 
544
 
 
1,106
 
 
525
 
 
-
 
 
285
 
 
810
Fixed-income securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. government
 
1,281
 
 
319
 
 
-
 
 
1,600
 
 
1,576
 
 
139
 
 
-
 
 
1,715
Corporate
 
1
 
 
4,230
 
 
625
 
 
4,856
 
 
3
 
 
4,275
 
 
611
 
 
4,889
Other
 
166
 
 
555
 
 
-
 
 
721
 
 
-
 
 
576
 
 
-
 
 
576
Total
$
3,203
 
$
7,467
 
$
1,723
 
$
12,393
 
$
2,618
 
$
8,007
 
$
1,409
 
$
12,034
Other Benefits:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
31
 
$
-
 
$
-
 
$
31
 
$
77
 
$
-
 
$
-
 
$
77
Global equity securities
 
127
 
 
504
 
 
-
 
 
631
 
 
118
 
 
397
 
 
-
 
 
515
Absolute return
 
-
 
 
-
 
 
53
 
 
53
 
 
-
 
 
-
 
 
49
 
 
49
Real assets
 
67
 
 
-
 
 
38
 
 
105
 
 
68
 
 
-
 
 
28
 
 
96
Fixed-income securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. government
 
119
 
 
5
 
 
-
 
 
124
 
 
148
 
 
5
 
 
-
 
 
153
Corporate
 
4
 
 
894
 
 
2
 
 
900
 
 
9
 
 
795
 
 
1
 
 
805
Other
 
14
 
 
37
 
 
-
 
 
51
 
 
-
 
 
38
 
 
-
 
 
38
Total
$
362
 
$
1,440
 
$
93
 
$
1,895
 
$
420
 
$
1,235
 
$
78
 
$
1,733
Total plan assets at fair value
 
 
 
 
 
 
 
 
 
$
14,288
 
 
 
 
 
 
 
 
 
 
$
13,767
 
In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $131 million and $132 million at December 31, 2013 and 2012, respectively.  These net assets and net liabilities were comprised primarily of cash, accounts receivable, accounts payable, and deferred taxes.
 
                                          Valuation Techniques
 
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.  All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days.
 
Money Market Investments
 
Money market investments consist primarily of commingled funds of U.S. government short-term securities that are considered Level 1 assets and valued at the net asset value of $1 per unit.  The number of units held by the plan fluctuates based on the unadjusted price changes in active markets for the funds' underlying assets.
 
 
 
Equity Securities
 
The global equity categories include equity investments in common stock and equity-index futures, and commingled funds comprised of equity across multiple industries and regions of the world.  Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets.  These equity investments are generally valued based on unadjusted prices in active markets for identical securities.  Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.  Collateral posted related to these futures consist of money market investments that are considered Level 1 assets.  Commingled funds are valued using a net asset value per share and are maintained by investment companies for large institutional investors and are not publicly traded.  Commingled funds are comprised primarily of underlying equity securities that are publicly traded on exchanges, and price quotes for the assets held by these funds are readily observable and available.  Commingled funds are categorized as Level 2 assets.
 
Absolute Return
 
The absolute return category includes portfolios of hedge funds that are valued using a net asset value per share based on a variety of proprietary and non-proprietary valuation methods, including unadjusted prices for publicly-traded securities in active markets.  Hedge funds are considered Level 3 assets.
 
Real Assets
 
The real asset category includes portfolios of commodities, commodities futures, global REITS, global listed infrastructure equities, and private real estate funds.  The commodities, commodities futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets.  Collateral posted related to the commodities futures consist of money market investments that are considered Level 1 assets.  Private real estate funds are valued using a net asset value per share derived using appraisals, pricing models, and valuation inputs that are unobservable and are considered Level 3 assets.  
 
Fixed-Income
 
The fixed-income category includes U.S. government securities, corporate securities, and other fixed-income securities.  
 
U.S. government fixed-income primarily consists of U.S. Treasury notes and U.S. government bonds that are valued based on quoted market prices or evaluated pricing data for similar securities adjusted for observable differences.  These securities are categorized as Level 1 or Level 2 assets.  
 
Corporate fixed-income primarily includes investment grade bonds of U.S. issuers across multiple industries that are valued based on a compilation of primarily observable information or broker quotes in non-active markets.  The fair value of corporate bonds is determined using recently executed transactions, market price quotations (where observable), bond spreads or credit default swap spreads obtained from independent external parties such as vendors and brokers adjusted for any basis difference between cash and derivative instruments.  These securities are classified as Level 2 assets.  Corporate fixed-income also includes commingled funds that are valued using a net asset value per share and are comprised of corporate debt instruments.  Commingled funds are considered Level 2 assets.  Corporate fixed-income also includes privately secured debt portfolios which are valued using a net asset value per share using pricing models and valuation inputs that are unobservable and are considered Level 3 assets. 
 
Other fixed-income primarily includes pass-through and asset-backed securities.  Pass-through securities are valued based on benchmark yields created using observable market inputs and are Level 2 assets.  Asset-backed securities are primarily valued based on broker quotes and are considered Level 2 assets.  Other fixed-income also includes municipal bonds and index futures.  Collateral posted related to the index futures consist of money market investments that are considered Level 1 assets.  Municipal bonds are valued based on a compilation of primarily observable information or broker quotes in non-active markets and are considered Level 2 assets.  Futures are valued based on unadjusted prices in active markets and are Level 1 assets.
 
Transfers Between Levels
 
Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  No significant transfers between levels occurred in the years ended December 31, 2013 and 2012.
 
Level 3 Reconciliation
 
The following table is a reconciliation of changes in the fair value of instruments for pension and other benefit plans that have been classified as Level 3 for the years ended December 31, 2013 and 2012:
 
 
Pension Benefits
 
Absolute
 
Corporate
 
 
 
 
(in millions)
Return
 
Fixed-Income
 
Real Assets
 
Total
Balance as of January 1, 2012
$
487
 
$
585
 
$
65
 
$
1,137
Actual return on plan assets:
 
 
 
 
 
 
 
 
 
 
 
Relating to assets still held at the reporting date
 
26
 
 
28
 
 
12
 
 
66
Relating to assets sold during the period
 
-
 
 
(1
 ) 
 
-
 
 
(1)
Purchases, issuances, sales, and settlements
 
 
 
 
 
 
 
 
 
 
 
Purchases
 
-
 
 
12
 
 
208
 
 
220
Settlements
 
-
 
 
(13
 ) 
 
-
 
 
(13)
Balance as of December 31, 2012
$
513
 
$
611
 
$
285
 
$
1,409
Actual return on plan  assets:
 
 
 
 
 
 
 
 
 
 
 
Relating to assets still held at the reporting date
 
37
 
 
1
 
 
49
 
 
87
Relating to assets sold during the period
 
4
 
 
-
 
 
(3
 ) 
 
1
Purchases, issuances, sales, and settlements
 
 
 
 
 
 
 
 
 
 
 
Purchases
 
-
 
 
20
 
 
352
 
 
372
Settlements
 
-
 
 
(7
 ) 
 
(139)
 
 
(146)
Balance as of December 31, 2013
$
554
 
$
625
 
$
544
 
$
1,723
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Benefits
 
Absolute
 
Corporate
 
 
 
 
(in millions)
Return
 
Fixed-Income
 
Real Assets
 
Total
Balance as of January 1, 2012
$
47
 
$
1
 
 
6
 
$
54
Actual return on plan assets:
 
 
 
 
 
 
 
 
 
 
 
Relating to assets still held at the reporting date
 
2
 
 
-
 
 
1
 
 
3
Relating to assets sold during the period
 
-
 
 
-
 
 
-
 
 
-
Purchases, issuances, sales, and settlements
 
 
 
 
 
 
 
 
 
 
 
Purchases
 
-
 
 
1
 
 
21
 
 
22
Settlements
 
-
 
 
(1
 ) 
 
-
 
 
(1)
Balance as of December 31, 2012
$
49
 
$
1
 
$
28
 
$
78
Actual return on plan  assets:
 
 
 
 
 
 
 
 
 
 
 
Relating to assets still held at the reporting date
 
4
 
 
-
 
 
3
 
 
7
Relating to assets sold during the period
 
-
 
 
-
 
 
-
 
 
-
Purchases, issuances, sales, and settlements
 
 
 
 
 
 
 
 
 
 
 
Purchases
 
12
 
 
1
 
 
21
 
 
34
Settlements
 
(12
 ) 
 
-
 
 
(14
 ) 
 
(26)
Balance as of December 31, 2013
$
53
 
$
2
 
$
38
 
$
93
 
 
                                          There were no transfers out of Level 3 in 2013 and 2012.
 
Cash Flow Information
 
Employer Contributions
 
PG&E Corporation and the Utility contributed $323 million to the pension benefit plans and $145 million to the other benefit plans in 2013.  These contributions are consistent with PG&E Corporation's and the Utility's funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements.  None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2013.  The Utility's pension benefits met all the funding requirements under ERISA.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $71 million to the pension plan and other postretirement benefit plans, respectively, for 2014.
 
Benefits Payments and Receipts
 
As of December 31, 2013, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
 
(in millions)
Pension
 
Other
 
Federal Subsidy
2014
$
613
 
$
90
 
$
(6
)
2015
 
652
 
 
95
 
 
(7
)
2016
 
692
 
 
100
 
 
(8
)
2017
 
730
 
 
107
 
 
(8
)
2018
 
766
 
 
113
 
 
(9
)
2019 - 2023
 
4,326
 
 
609
 
 
(35
)
 
There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above.  There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.
 
Defined Contribution Benefit Plans
 
PG&E Corporation sponsors employee retirement savings plans, including a defined contribution savings plan that is qualified as a 401(k) plan under the Internal Revenue Code 1986, as amended.  These plans permit eligible employees to defer compensation, to make pre-tax and after-tax contributions, and provide for employer contributions to be made to eligible participants.  Employer contribution expense reflected in PG&E Corporation's Consolidated Statements of Income was as follows:
 
 
(in millions)
 
 
Year ended December 31,
 
 
2013
$
71
2012
 
67
2011
 
65
 
 
There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.
 
Resolution Of Remaining Chapter 11 Disputed Claims
Resolution Of Remaining Chapter 11 Disputed Claims
 
NOTE 12: 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.
 
The following table presents the changes in the remaining net disputed claims liability, which includes interest:
 
 
(in millions)
  
 
Balance at December 31, 2012
$
842
Interest accrued, net of settlement
  
25
Less: supplier settlements-principal amount
  
(3
)
Balance at December 31, 2013
$
864
 
 
At December 31, 2013 and 2012, the remaining net disputed claims liability consisted of $154 million and $157 million, respectively, of remaining net disputed claims (classified on the Consolidated Balance Sheets within accounts payable - disputed claims and customer refunds) and $710 million and $685 million, respectively, of accrued interest (classified on the Consolidated Balance Sheets within interest payable).
 
At December 31, 2013 and 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 Consolidated Balance Sheets.
 
Interest accrues on the remaining net disputed claims at the FERC-ordered rate, which is higher than the rate earned by the Utility on the escrow balance.  Although the Utility has been collecting the difference between the accrued interest and the earned interest from customers in rates, these collections are not held in escrow.  If the amount of accrued interest is greater than the amount of interest ultimately determined to be owed on the remaining net disputed claims, the Utility would refund to customers any excess interest collected.  The amount of any interest that the Utility may be required to pay will depend on the final determined amount of the remaining net disputed claims and when such interest is paid.
 
Related Party Agreements And Transactions
Related Party Agreements And Transactions
 
NOTE 13: RELATED PARTY AGREEMENTS AND TRANSACTIONS
 
The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves.  The Utility and PG&E Corporation exchange administrative and professional services in support of operations.  Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services.  Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services.  PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies.  Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.
 
 
The Utility's significant related party transactions were:
 
Year Ended December 31, 
(in millions)
2013
 
2012
 
2011
Utility revenues from:
 
 
 
 
 
Administrative services provided to PG&E Corporation
$
7
 
$
7
 
$
6
Utility expenses from:
 
 
 
 
 
 
 
 
Administrative services received from PG&E
 
 
 
 
 
 
 
 
Corporation
$
45
 
$
50
 
$
49
Utility employee benefit due to PG&E Corporation
 
57
 
 
51
 
 
33
 
 
At December 31, 2013 and 2012, the Utility had receivables of $22Error! Bookmark not defined. million and $19 million, respectively, from PG&E Corporation included in accounts receivable - other and other noncurrent assets - other on the Utility's Consolidated Balance Sheets, and payables of $17 million, each year respectively, to PG&E Corporation included in accounts payable - other on the Utility's Consolidated Balance Sheets.
 
Commitments And Contingencies
Commitments And Contingencies
 
NOTE 14: COMMITMENTS AND CONTINGENCIES
 
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to natural gas matters and environmental remediation.  The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities.  PG&E Corporation also has financial commitments described under “Other Commitments” below.  
 
 
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.  PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows have been materiality affected by the costs the Utility has incurred related to the ongoing regulatory proceedings, investigations, and civil lawsuits that commenced following the San Bruno accident.
 
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.  
 
The SED has issued investigative reports and briefs in each of these investigations alleging that the Utility committed numerous violations of applicable laws and regulations.  In July 2013, the SED 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 costs related to the Utility's PSEP 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 costs.  (See “Disallowed Capital Costs” below.)  Other parties, including the City of San Bruno, TURN, the CPUC's ORA, 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 ALJs who oversee the investigations are expected to issue one or more presiding officers' decisions to address the violations that they have determined the Utility committed and to impose penalties.  It is uncertain when the decisions will be issued.  Based on the CPUC's rules, the presiding officer's decisions would become the final decisions of the CPUC 30 days after issuance unless the Utility or another party filed an appeal with the CPUC, or a CPUC commissioner requested that the CPUC review the decision, within such time.  If an appeal or review request is filed, other parties would have 15 days to provide comments but the CPUC could act before considering any comments.
 
At December 31, 2013, the 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 will respond 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 capital investments would be charged to net income in the period in which the CPUC orders such a disallowance.  See “Disallowed Capital Costs” below.  Future disallowed expense and capital costs would be charged to net income in the period incurred.  
 
Other CPUC Enforcement 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 the following matters.                                                                                                                                            
 
Gas Safety Citation Program.  The Utility and other 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 that relate to the safety of their natural gas facilities and operating practices.  The SED is authorized to issue citations and impose fines for self-identified or self-corrected violations and for violations that the SED identifies through its periodic audits of the Utility's operations or otherwise.  The SED can exercise its discretion in determining whether to impose fines and the amount of such fines, or whether to take other enforcement action, based on the totality of the circumstances.  The SED can consider such factors as the severity of the safety risk associated with each violation; the number and duration of the violations; whether the violation was self-reported, and whether corrective actions were taken.  In January 2012, the SED imposed fines of $16.8 million on the Utility for self-reported failure to perform certain leak surveys and in 2013 the SED imposed fines ranging from $50,000 to $8.1 million for self-reported violations.  The Utility has filed over 50 self-reports with the SED, plus additional follow-up reports, that the SED has not yet addressed.  The SED is expected to impose fines or take enforcement action with respect to some of these self-reports.
                                                                              
Natural Gas Transmission Pipeline Rights-of-Way.  In 2012, the Utility notified the CPUC and the SED that it 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 fines on the Utility or take other enforcement action in connection with this matter.
 
Orders to Show Cause.  In August 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.  On December 19, 2013, the CPUC issued a decision to impose fines of approximately $14 million on the Utility in connection with the errata submission, finding that the Utility violated CPUC rules that prohibit any person from misleading the CPUC.  The Utility recorded this amount as an expense for 2013.  On January 23, 2014, the Utility filed an application for the rehearing of this decision, arguing that it is erroneous in several respects.  It is uncertain when the CPUC will issue a decision on the other OSC that directed the Utility to show cause 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.  Briefing on this OSC was completed on January 31, 2014.
 
Disallowed Capital Costs
 
In 2011, 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 forecasts and ratemaking proposals.  In December 2012, the CPUC approved most of the projects proposed in the Utility's PSEP application that was filed in August 2011, but disallowed the Utility's request for rate recovery of a significant portion of costs the Utility forecasted it would incur through 2014.  In October 2013, the Utility updated its PSEP application to present the results of its completed search and review of records relating to validation of operating pressure for all of the approximately 6,750 miles of the Utility's natural gas transmission pipelines.  The Utility requested that the CPUC approve changes to the scope and prioritization of PSEP work, including deferring some projects to after 2014 and accelerating other projects, and that the CPUC adjust authorized revenue requirements to reflect these changes.  The Utility has requested that the CPUC issue a final decision by August 2014.
 
At December 31, 2013, the Utility has recorded cumulative charges of $549 million for PSEP capital costs that are expected to exceed the amount to be recovered.  The Utility has requested that the CPUC authorize capital costs of $766 million under the PSEP, reflecting the proposed changes in the PSEP update application.  Of this amount, approximately $280 million is recorded in Property, Plant, and Equipment on the Consolidated Balance Sheets at December 31, 2013.  The Utility could record additional charges to the extent PSEP capital costs are higher than currently expected, or if additional capital costs are disallowed by the CPUC.  The Utility's ability to recover PSEP capital costs also could be affected by the final decisions to be issued in the CPUC's pending investigations discussed above. 
 
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 it 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 Liability Claims
 
The Utility has settled 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.)  At December 31, 2013, the Utility has recorded cumulative charges of $565 million as its best estimate of probable loss for third-party claims related to the San Bruno accident and has made cumulative payments of $520 million for settlements.  In addition, the Utility has incurred cumulative expenses of $86 million for associated legal costs.  The Utility's liability for third-party claims is included in other current liabilities in the Consolidated Balance Sheets and totaled $45 million at December 31, 2013 and $146 million at December 31, 2012.
 
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 December 31, 2013, the Utility has recognized cumulative insurance recoveries of $354 million for third-party claims and associated legal costs.  These amounts were recorded as a reduction to operating and maintenance expense in the Consolidated Statements of Income.  Although the Utility believes that a significant portion of costs incurred for third-party claims (and associated legal costs) 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 if the lower court's ruling is reversed.
 
 
Other Legal and Regulatory 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.  A provision for a loss contingency is recorded 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 and expense these costs as incurred.
 
Accruals for other legal and regulatory contingencies (excluding amounts related to natural gas matters above) totaled $43 million at December 31, 2013 and $34 million at December 31, 2012.  These amounts are included in other current liabilities in the Consolidated Balance Sheets.  The estimated reasonably possible range of loss for these matters in excess of the recorded accrual is not material.  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.  
 
 
Environmental Remediation Contingencies
 
The Utility is 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 the 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 following table presents the changes in the environmental remediation liability:
 
 
(in millions)
 
 
Balance at December 31, 2012
$
910
Additional remediation costs accrued:
 
 
Transfer to regulatory account for  recovery
 
116
Amounts not recoverable from customers
 
49
Less: Payments
 
(175
)
Balance at December 31, 2013
$
900
 
 
The environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is composed of the following:
 
 
 
Balance at December 31,
(in millions)
2013
 
2012
Utility-owned natural gas compressor site near Hinkley, California (1)
$
190
 
$
226
Utility-owned natural gas compressor site near Topock, Arizona (1)
 
264
 
 
239
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites
 
160
 
 
158
Former MGP sites owned by the Utility or third parties
 
184
 
 
181
Fossil fuel-fired generation facilities and sites
 
102
 
 
106
Total environmental remediation liability
$
900
 
$
910
 
 
 
 
 
 
      (1) See “Natural Gas Compressor Sites” below.
 
 
At December 31, 2013, the Utility expected to recover $579 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 the final project permits and a final clean-up order in phases through 2014 and into 2015.  As the permits and order are issued, the Utility will obtain additional clarity on the total costs associated with the final remedy and related activities. In January 2014, the Regional Board also approved an updated background study plan prepared in consultation with the U.S. Geological Survey, the results of which will define the final cleanup standards. The background study is not expected to be complete until 2018.
 
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 December 31, 2013, approximately 380 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 by June 2014.
   
The Utility's environmental remediation liability at December 31, 2013 reflects the Utility's best estimate of probable future costs associated with its final remediation plan, interim remediation measures, 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.  Future changes in cost estimates and the assumptions on which they are based may have a material impact on 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 December 31, 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.  Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition, results of operations, 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.  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 results of operations during the period in which they are recorded.
 
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.  Certain acts of terrorism may be “certified” by the Secretary of the Treasury.  If damages are caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy limit of $3.2 billion for each insured loss.  In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount.  
 
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 of the $13.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors.  The Utility may be assessed up to $255 million per nuclear incident under this program, with payments in each year limited to a maximum of $38 million per incident.  Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.  The next scheduled adjustment is due on or before September 10, 2018.
 
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.
Commitments
 
Third-Party Power Purchase Agreements
 
As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity.  The price of purchased power may be fixed or variable.  Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.  The costs incurred for all power purchases and electric capacity were as follows:
 
 
 
(in millions)
2013
 
2012
 
2011
Qualifying facilities (1)
$
813
 
$
779
 
$
1,069
Renewable energy contracts
 
1,281
 
 
815
 
 
622
Other power purchase agreements
 
902
 
 
661
 
 
690
 
(1) Costs incurred include $271, $286, and $297 attributable to renewable energy contracts with qualifying facilities at December 31, 2013, 2012, and 2011, respectively.
 
 
 
 
Qualifying Facility Power Purchase Agreement - The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law.  As of December 31, 2013, the Utility had agreements with 170 QFs that are in operation, which expire at various dates between 2014 and 2028.      
 
Renewable Energy Power Purchase Agreements - The Utility is required to gradually increase the amount of renewable energy that it delivers to its customers in order to comply with California's renewable portfolio standard requirement.  The Utility has entered into various contracts to purchase renewable energy to help meet the renewable portfolio standard requirement.  The Utility's obligations under a significant portion of these agreements are contingent on the third party's construction of new generation facilities.  The Utility's commitments for energy payments under these renewable energy agreements are expected to grow significantly.
 
Other Power Purchase Agreements - The Utility has entered into several power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements.  The Utility's obligation under a portion of these agreements is contingent on the third parties' development of new generation facilities to provide capacity and energy products to the Utility.  The Utility also has agreements with various irrigation districts and water agencies to purchase hydroelectric power.
 
At December 31, 2013, the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones were as follows:
 
 
 
 
Renewable
 
 
 
 
 
 
(in millions)
Qualifying Facility
 
(Other than QFs)
 
Other
 
Total Payments
2014
$
913
 
$
1,906
 
$
829
 
$
3,648
2015
 
707
 
 
2,102
 
 
770
 
 
3,579
2016
 
587
 
 
2,109
 
 
722
 
 
3,418
2017
 
450
 
 
2,104
 
 
684
 
 
3,238
2018
 
406
 
 
1,962
 
 
640
 
 
3,008
Thereafter
 
1,614
 
 
30,242
 
 
2,984
 
 
34,840
Total
$
4,677
 
$
40,425
 
$
6,629
 
$
51,731
 
 
 
 
The following table shows the future fixed capacity payments due under QF agreements that are treated as capital leases.    (These amounts are also included in the table above.)  These payments are discounted to their present value in the table below using the Utility's incremental borrowing rate at the inception of the leases. These capital lease QF agreements expire between April 2014 and September 2021.  The amount of this discount is shown in the table below as the amount representing interest.  
 
 
(in millions)
 
 
2014
$
27
2015
 
24
2016
 
22
2017
 
18
2018
 
12
Thereafter
 
8
Total fixed capacity payments
 
111
Less: amount representing interest
 
14
Present value of fixed capacity payments
$
97
 
 
Minimum lease payments associated wit            h the lease obligations are included in the Utility's cost of electricity.  The timing of the recognition of the lease expense conforms to the ratemaking treatment for the Utility's recovery of the cost of electricity.  
 
The present value of the fixed capacity payments due under these agreements is recorded on the Consolidated Balance Sheets.  At December 31, 2013 and 2012, current liabilities - other included $23 million and $29 million, respectively, and noncurrent liabilities - other included $74 million and $96 million, respectively.  The corresponding assets at December 31, 2013 and 2012 of $97 million and $125 million including accumulated amortization of $176 million and $148 million, respectively are included in property, plant, and equipment on the Consolidated Balance Sheets.
 
Natural Gas Supply, Transportation, and Storage Commitments 
 
The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility's natural gas transportation system begins.  In addition, the Utility has contracted for natural gas storage services in northern California in order to more reliably meet customers' loads.  
 
At December 31, 2013, the Utility's undiscounted future expected payment obligations for natural gas supplies, transportation and storage were as follows:
 
 
(in millions)
 
 
2014
$
727
2015
 
198
2016
 
150
2017
 
108
2018
 
108
Thereafter
 
756
Total
$
2,047
 
 
Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts less than 1 year, amounted to $1.6 billion in 2013, $1.3 billion in 2012, and $1.8 billion in 2011.
 
Nuclear Fuel Agreements
 
The Utility has entered into several purchase agreements for nuclear fuel.  These agreements have remaining terms ranging from one to 12 years and are intended to ensure long-term nuclear fuel supply.  The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2020, while contracts for fuel fabrication services provide for 100% coverage of reactor requirements through 2017.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.  
 
At December 31, 2013, the undiscounted future expected payment obligations for nuclear fuel were as follows:
 
(in millions)
 
 
2014
$
145
2015
 
162
2016
 
146
2017
 
148
2018
 
132
Thereafter
 
647
Total
$
1,380
 
 
Payments for nuclear fuel amounted to $162 million in 2013, $118 million in 2012, and $77 million in 2011.
 
Other Commitments
 
PG&E Corporation and the Utility have other commitments relating to operating leases.  At December 31, 2013, the future minimum payments related to these commitments were as follows:
 
 
(in millions)
 
 
2014
$
42
2015
 
37
2016
 
34
2017
 
27
2018
 
24
Thereafter
 
193
Total
$
357
 
 
Payments for other commitments relating to operating leases amounted to $40 million in 2013, $32 million in 2012, and $27 million in 2011.  PG&E Corporation and the Utility had operating leases on office facilities expiring at various dates from 2014 to 2023.  Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2% to 5%. The rentals payable under these leases may increase by a fixed amount each year, a percentage of increase over base year, or the consumer price index.  Most leases contain extension options ranging between one and five years.
 
Quarterly Consolidated Financial Data
Quarterly Consolidated Financial Data
QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
 
 
Quarter ended
(in millions, except per share amounts)
December 31 
 
September 30 
 
June 30 
 
March 31 
2013
 
 
 
 
 
 
 
 
 
 
 
PG&E CORPORATION
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,975
 
$
4,175
 
$
3,776
 
$
3,672
Operating income
 
333
 
 
291
 
 
636
 
 
502
Income tax (benefit) provision
 
25
 
 
(24
 ) 
 
153
 
 
114
Net income
 
90
 
 
164
 
 
332
 
 
242
Income available for common shareholders
 
86
 
 
161
 
 
328
 
 
239
Comprehensive income
 
210
 
 
165
 
 
352
 
 
252
Net earnings per common share, basic
 
0.19
 
 
0.36
 
 
0.74
 
 
0.55
Net earnings per common share, diluted
 
0.19
 
 
0.36
 
 
0.74
 
 
0.55
Common stock price per share:
 
 
 
 
 
 
 
 
 
 
 
High
 
42.75
 
 
46.37
 
 
48.44
 
 
44.53
Low
 
40.07
 
 
40.76
 
 
43.59
 
 
40.47
UTILITY
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,973
 
$
4,174
 
$
3,775
 
$
3,671
Operating income
 
360
 
 
292
 
 
635
 
 
503
Income tax (benefit) provision
 
65
 
 
(20
 ) 
 
160
 
 
121
Net income
 
138
 
 
162
 
 
329
 
 
237
Income available for common stock
 
134
 
 
159
 
 
325
 
 
234
Comprehensive income
 
231
 
 
166
 
 
333
 
 
242
 
 
 
 
 
 
 
 
 
 
 
 
2012
 
 
 
 
 
 
 
 
 
 
 
PG&E CORPORATION
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,830
 
$
3,976
 
$
3,593
 
$
3,641
Operating income
 
125
 
 
614
 
 
467
 
 
487
Income tax (benefit) provision
 
(54
 ) 
 
100
 
 
87
 
 
104
Net income (loss)
 
(9
 ) 
 
364
 
 
239
 
 
236
Income (loss) available for common shareholders
 
(13
 ) 
 
361
 
 
235
 
 
233
Comprehensive income
 
77
 
 
372
 
 
247
 
 
246
Net earnings (loss) per common share, basic
 
(0.03
 ) 
 
0.84
 
 
0.56
 
 
0.56
Net earnings (loss) per common share, diluted
 
(0.03
 ) 
 
0.84
 
 
0.55
 
 
0.56
Common stock price per share:
 
 
 
 
 
 
 
 
 
 
 
High
 
43.48
 
 
46.51
 
 
45.20
 
 
43.72
Low
 
39.71
 
 
42.41
 
 
42.04
 
 
40.16
UTILITY
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,829
 
$
3,974
 
$
3,592
 
$
3,640
Operating income
 
127
 
 
613
 
 
467
 
 
488
Net income
 
13
 
 
340
 
 
227
 
 
231
Income tax provision
 
(30
 ) 
 
122
 
 
93
 
 
113
Income available for common stock
 
9
 
 
337
 
 
223
 
 
228
Comprehensive income
 
96
 
 
348
 
 
235
 
 
241
 
The Utility recorded a charge to net income of $196 million in the third quarter of 2013 and $353 million during the fourth quarter 2012, for disallowed capital expenditures associated with the Utility's pipeline safety enhancement plan.  See Note 14 of the Notes to the Consolidated Financial Statements.
 
The Utility recorded a provision of $110 million and $80 million in the third quarter 2013 and in the second quarter 2012, respectively, for estimated third-party claims related to the San Bruno accident.  During the second quarter 2013 and third quarter 2013, the Utility recognized $45 million and $25 million, respectively, for insurance claims.  During the first quarter 2012, second quarter of 2012, third quarter of 2012, and fourth quarter 2012 the Utility recognized $11 million, $25 million, $99 million, and $50 million, respectively, for insurance recoveries.  See Note 14 of the Notes to the Consolidated Financial Statements.
 
Schedule I - Condensed Financial Information Of Parent
Schedule I - Condensed Financial Information Of Parent
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 (in millions, except per share amounts)
 
 
Year Ended December 31,
 
2013
2012
2011
Administrative service revenue
$ 41 
$ 43 
$ 44 
Operating expenses
(42
 )(41)
(44
)
Interest income
1 
1 
1 
Interest expense
(25
 )(22)
(22
)
Other income
(57
 )(39)
(17
)
Equity in earnings of subsidiaries
848 
817 
852 
Income before income taxes
766 
759 
814 
Income tax benefit
48 
57 
30 
Net income
$ 814 
$ 816 
$ 844 
Other Comprehensive Income
 
 
 
Pension and other postretirement benefit plans (net of taxes of $80, $72, $9, at respective dates)
113 
108 
(11
)
Other (net of taxes of $26, $3, and $0, at respective dates)
38 
4 
- 
Total other comprehensive income (loss)
151 
112 
(11
)
Comprehensive Income
$ 965 
$ 928 
$ 833 
Weighted average common shares outstanding, basic
444 
424 
401 
Weighted average common shares outstanding, diluted
445 
425 
402 
Net earnings per common share, basic
$ 1.83 
$ 1.92 
$ 2.10 
Net earnings per common share, diluted
$ 1.83 
$ 1.92 
$ 2.10 
 
 
 
 
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT - (Continued)
CONDENSED BALANCE SHEETS
(in millions)
 
 
Balance at December 31,
 
2013
2012
ASSETS
 
 
Current Assets
 
 
Cash and cash equivalents
$ 231 
$ 207 
Advances to affiliates
30 
26 
Income taxes receivable
13 
33 
Other current assets
86 
- 
Total current assets
360 
266 
Noncurrent Assets
 
 
Equipment
2 
1 
Accumulated depreciation
(1
 )(1)
Net equipment
1 
- 
Investments in subsidiaries
14,711 
13,387 
Other investments
110 
102 
Income taxes receivable
5 
5 
Deferred income taxes
188 
178 
Other
- 
1 
Total noncurrent assets
15,015 
13,673 
Total Assets
$ 15,375 
$ 13,939 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
Current Liabilities
 
 
Short-term borrowings
$ 260 
$ 120 
Long-term debt, classified as current
350 
- 
Accounts payable - other
66 
48 
Other
230 
221 
Total current liabilities
906 
389 
Noncurrent Liabilities
 
 
Longdebt
- 
349 
Other
127 
127 
Total noncurrent liabilities
127 
476 
Common Shareholders' Equity
 
 
Common stock
9,550 
8,428 
Reinvested earnings
4,742 
4,747 
Accumulated other comprehensive income (loss)
50 
(101
)
Total common shareholders' equity
14,342 
13,074 
Total Liabilities and Shareholders' Equity
$ 15,375 
$ 13,939 
 
 
PG&E CORPORATION
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT - (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
 
 
 
 
Year Ended December 31,
 
 
 
2013
 
2012
 
2011
 
Cash Flows from Operating Activities:
 
 
 
 
 
 
 
 
 
 
Net income
 
 $
814 
    
 $
816 
 
 $
 
844 
 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
 
 
 
 
   Stock-based compensation amortization
 
 
54 
   
 
51 
 
 
36 
 
   Equity in earnings of subsidiaries
 
 
(848
 ) 
 
(817
 ) 
 
(852
 ) 
   Deferred income taxes and tax credits, net
 
 
(10
 ) 
 
(31
 ) 
 
(26
 ) 
   Noncurrent income taxes receivable/payable
 
 
- 
 
 
(6
 ) 
 
(47
 ) 
   Current income taxes receivable/payable
 
 
20 
 
 
(82
 ) 
 
49 
 
   Other
 
 
(20
 ) 
 
20 
 
 
(80
 ) 
Net cash provided by (used in) operating activities
 
 
10 
 
 
(49) 
 
 
(76
 ) 
Cash Flows From Investing Activities:
 
 
 
 
 
 
 
 
 
 
Investment in subsidiaries
 
 
(1,371
 ) 
 
(1,023
 ) 
 
(759
 ) 
Dividends received from subsidiaries (1)
 
 
716 
   
 
716 
 
 
716 
 
Proceeds from tax equity investments
 
 
275 
 
 
228 
 
 
129 
 
Other
 
 
(8
 ) 
 
- 
 
 
- 
 
Net cash provided by (used in) investing activities
 
 
(388
 ) 
 
(79) 
 
 
86 
 
Cash Flows From Financing Activities:
 
 
 
 
 
 
 
 
 
 
Borrowings under revolving credit facilities
 
 
140 
 
 
120 
 
 
150 
 
Repayments under revolving credit facilities
 
 
- 
 
 
- 
 
 
(150
 ) 
Common stock issued
 
 
1,045 
  
 
751 
 
 
662 
 
Common stock dividends paid (2) 
 
 
(782
 ) 
 
(746
 ) 
 
(704
 ) 
Other
 
 
(1
 ) 
 
1 
 
 
1 
 
Net cash provided by (used in) financing activities
 
 
402 
 
 
126 
 
 
(41
 ) 
Net change in cash and cash equivalents
 
 
24 
   
 
(2
 ) 
 
(31
 ) 
Cash and cash equivalents at January 1
 
 
207 
 
 
209 
 
 
240 
 
Cash and cash equivalents at December 31
 
$
231 
 
$
207 
 
$
209 
 
Supplemental disclosures of cash flow information
 
 
 
 
 
 
 
 
 
 
   Cash received (paid) for:
 
 
 
 
 
 
 
 
 
 
   Interest, net of amounts capitalized
 
$
(23
 ) 
$
(20
 ) 
$
(20
 ) 
   Income taxes, net
 
 
21 
 
 
(60
 ) 
 
8 
 
Supplemental disclosures of noncash investing and financing
 
 
 
 
 
 
 
 
 
 
   activities
 
 
 
 
 
 
 
 
 
 
   Noncash common stock issuances
 
$
22 
 
$
22 
 
$
24 
 
   Common stock dividends declared but not yet paid
 
 
208 
 
 
196 
 
 
188 
 
 
 
 
 
 
 
 
 
 
 
 
(1)
Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.
 
 
(2)
On January 15, April 15, July 15, October 15, 2013, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
 
 
 
On January 15, April 15, July 15, October 15, 2012, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
 
 
 
On January 15, April 15, July 15, October 15, 2011, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
Schedule II - Consolidated Valuation And Qualifying Accounts
Schedule II - Consolidated Valuation And Qualifying Accounts
PG&E Corporation
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2013, 2012, and 2011
(in millions)
 
 
 
Additions
 
 
Description
Balance at Beginning of Period
Charged to Costs and Expenses
Charged to Other Accounts
Deductions (2)
Balance at End of Period
Valuation and qualifying accounts deducted from assets:
 
 
 
 
 
2013:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 87
$ 53
$ -
$ 60
$ 80
2012:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 81
$ 66
$ -
$ 60
$ 87
2011:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 81
$ 60
$ -
$ 60
$ 81
 
 
 
 
 
 
 
 
 
 
 
 
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
 
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
 
 
 
Pacific Gas and Electric Company
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2013, 2012, and 2011
(in millions)
 
 
 
Additions
 
 
Description
Balance at Beginning of Period
Charged to Costs and Expenses
Charged to Other Accounts
Deductions (2)
Balance at End of Period
Valuation and qualifying accounts deducted from assets:
 
 
 
 
 
2013:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 87
$ 53
$ -
$ 60
$ 80
2012:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 81
$ 66
$ -
$ 60
$ 87
2011:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 81
$ 60
$ -
$ 60
$ 81
 
 
 
 
 
 
 
 
 
 
 
 
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
 
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
Summary Of Significant Accounting Policies (Policy)
Cash And Cash Equivalents 
Cash and Cash Equivalents
 
Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.  
Restricted Cash 
Restricted Cash
 
Restricted cash consists primarily of the Utility's cash held in escrow pending the resolution of the remaining disputed claims made by electricity suppliers in the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code.  (See Note 12 below.)  
Allowance For Doubtful Accounts Receivable 
Allowance for Doubtful Accounts Receivable
 
Accounts receivable are primarily composed of trade receivables and unbilled revenue.  PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record accounts receivable at estimated net realizable value.  The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.
Inventories 
 
Inventories
 
Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground represents gas that is recorded to inventory when purchased and then expensed as the gas is withdrawn for distribution  to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed.
 
 
      The Utility also purchases greenhouse gas emission allowances that are recorded as inventory. They are carried at weighted average cost and included in Other Noncurrent Assets - Other in the Consolidated Balance Sheets.  The costs of the greenhouse gas emissions are expensed and recoverable through rates.
 
Property, Plant, And Equipment 
 
Property, Plant, and Equipment
 
Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.) The Utility's total estimated useful lives and balances of its property, plant, and equipment were as follows:
 
 
 
Estimated Useful
 
Balance at December 31,
(in millions, except estimated useful lives)
Lives (years)
 
2013
 
2012
Electricity generating facilities (1)
20 to 100
 
$
9,116
 
$
8,253
Electricity distribution facilities
10 to 55
 
 
25,333
 
 
23,767
Electricity transmission
10 to 70
 
 
8,429
 
 
7,681
Natural gas distribution facilities
20 to 53
 
 
9,117
 
 
8,257
Natural gas transportation and storage
5 to 65
 
 
5,265
 
 
4,314
Construction work in progress
 
 
 
1,834
 
 
1,894
Total property, plant, and equipment
 
 
 
59,094
 
 
54,166
Accumulated depreciation
 
 
 
(17,843
 ) 
 
(16,643
)
Net property, plant, and equipment
 
 
$
41,251
 
$
37,523
 
 
 
 
 
 
 
 
 (1) Balance includes nuclear fuel inventories.  Stored nuclear fuel inventory is stated at weighted average cost.  Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output.  (See Note 14 below.)
 
 
The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property.  This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment.  The Utility's composite depreciation rates were 3.51% in 2013, 3.63% in 2012, and 3.67% in 2011.  The useful lives of the Utility's property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.  
 
AFUDC 
AFUDC
 
AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions and is capitalized as part of the cost of construction.  AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.  The Utility recorded AFUDC related to debt and equity, respectively, of $47 million and $101 million during 2013, $49 million and $107 million during 2012, and $40 million and $87 million during 2011.
Regulation And Regulated Operations 
Regulation and Regulated Operations
 
As a regulated entity, the Utility collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility's costs of service.  The Utility's ability to recover a significant portion of its authorized revenue requirements through rates is independent, or “decoupled,” from the volume of the Utility's electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.  Regulatory assets are amortized over the future periods in which the costs are recovered.  If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.
 
The Utility also records a regulatory balancing account asset or liability for differences between actual customer billings and authorized revenue requirements that are probable of recovery or refund.  These differences do not have an impact on net income.  The Utility also records differences between incurred costs and customer billings or authorized revenue meant to recover those costs.  To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively, and the differences do not have an impact on net income.  See “Revenue Recognition” below.
 
To the extent that portions of the Utility's operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.  
 
Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.
Asset Retirement Obligations 
 
Asset Retirement Obligations
 
PG&E Corporation and the Utility record an ARO at discounted fair value in the period in which the obligation is incurred if the discounted fair value can be reasonably estimated.  In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset.  In each subsequent period, the ARO is accreted to its present value.  PG&E Corporation and the Utility also record an ARO if a legal obligation to perform an asset removal exists and can be reasonably estimated, but performance is conditional upon a future event.  The Utility recognizes timing differences between the recognition of costs and the costs recovered through the ratemaking process as regulatory assets or liabilities.  (See Note 3 below.)  The Utility has an ARO primarily for its nuclear generation facilities, certain fossil fuel-fired generation facilities, and gas transmission system assets.  
 
For the year ended December 31, 2013, the Utility recorded an increase of $596 million to its ARO. The increase primarily reflects a higher expected cost per unit of transmission pipeline replacements.
 
Detailed studies of the cost to decommission the Utility's nuclear generation facilities are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC.  In December 2012, the Utility submitted its updated decommissioning cost estimate with the CPUC.  The estimated undiscounted cost to decommission the Utility's nuclear power plants increased by $1.4 billion in 2012 due to higher spent nuclear fuel disposal costs and an increase in the scope of work.  A significant portion of the increase in decommissioning cost estimates is due to the need to develop on-site storage for spent nuclear fuel because the federal government has failed to meet its obligation to develop a permanent repository for the disposal of nuclear waste from nuclear facilities in the United States.  The Utility expects that it will recover its future on-site storage costs from the federal government. Recovered amounts will be refunded to customers through rates.
 
The estimated undiscounted nuclear decommissioning cost for the Utility's nuclear generation facilities was approximately $3.5 billion at December 31, 2013 and 2012, as filed in the 2012 NDCTP.  In future dollars, the estimated nuclear decommissioning cost is approximately $6.1 billion at December 31, 2013 and 2012.  These estimates are based on the 2012 decommissioning cost studies and are prepared in accordance with CPUC requirements.  The estimated nuclear decommissioning cost in future dollars is discounted for GAAP purposes and recognized as an ARO on the Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued in accordance with GAAP was $2.5 billion at December 31, 2013 and 2012.  
 
A reconciliation of the changes in the ARO liability is as follows:
(in millions)
 
 
ARO liability at December 31, 2011
$
1,609
Revision in estimated cash flows
 
1,301
Accretion
 
101
Liabilities settled
 
(92
)
ARO liability at December 31, 2012
 
2,919
Revision in estimated cash flows
 
596
Accretion
 
130
Liabilities settled
 
(107
)
ARO liability at December 31, 2013
$
3,538
 
 
The Utility has identified the following AROs for which a reasonable estimate of fair value could not be made.  As a result, the Utility has not recorded a liability related to these AROs:  
∙      Restoration of land to its pre-use condition under the terms of certain land rights agreements.  Land rights will be maintained for the foreseeable future, and therefore, the Utility cannot reasonably estimate the settlement date(s) or range of settlement dates for the obligations associated with these assets;  
 
Removal and proper disposal of lead-based paint contained in some Utility facilities.  The Utility does not have information available that specifies which facilities contain lead-based paint and, therefore, cannot reasonably estimate the settlement date(s) associated with the obligations; and
 
Removal of certain communications equipment from leased property, and retirement activities associated with substation and certain hydroelectric facilities.  The Utility will maintain and continue to operate its hydroelectric facilities until the operation of a facility becomes uneconomical.  The operation of the majority of the Utility's hydroelectric facilities is currently, and for the foreseeable future, expected to be economically beneficial.  Therefore, the settlement date(s) cannot be reasonably estimated at this time.
 
Disallowance of Plant Costs 
Disallowance of Plant Costs
 
PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.  During 2013 and 2012, the Utility recorded charges of $196 million and $353 million, respectively, for PSEP capital costs that are expected to exceed the CPUC's authorized levels or that are specifically disallowed.  (See “Natural Gas Matters” in Note 14 below).  No material disallowance losses were recorded in 2011.
Gains And Losses On Debt Extinguishments 
Gains and Losses on Debt Extinguishments
 
Deferred gains and losses on debt extinguishments are recorded to current assets - regulatory assets and other noncurrent assets - regulatory assets in the Consolidated Balance Sheets. Gains and losses on debt extinguishments associated with regulated operations are deferred and amortized over a period consistent with the recovery of costs through regulated rates.  PG&E Corporation and the Utility recorded unamortized loss on debt extinguishments, net of gain, of $157 million, $163 million, and $186 million at December 31, 2013, 2012, and 2011, respectively.  The amortization expense related to this loss was $23 million in both 2013 and 2012, and $18 million in 2011.  
Revenue Recognition 
Revenue Recognition
 
The Utility recognizes revenues as electricity and natural gas services are delivered, and includes amounts for services rendered but not yet billed at the end of the period. 
 
The CPUC authorizes most of the Utility's revenues in the Utility's GRC and its GT&S rate cases, which generally occur every three years.  In general, the Utility's ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility's sales of electricity and natural gas services.  The Utility recognizes revenues once they have been authorized for rate recovery, amounts are objectively determinable and probable of recovery, and amounts are expected to be collected within 24 months.  Generally, the revenue is recognized ratably over the year. 
 
The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs.  Generally, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred.
 
The FERC authorizes the Utility's revenue requirements in periodic (often annual) TO rate cases.  The Utility's ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility's electricity sales, and revenue is recognized only for amounts billed and unbilled.
 
The Utility's revenues and net income can be affected by incentive ratemaking mechanisms that adjust rates depending on the extent to which the Utility meets certain performance criteria. 
Income Taxes 
Income Taxes
 
PG&E Corporation and the Utility use the liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year.  PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.  (See Note 8 below.)
 
PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position.  The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.  
 
Investment tax credits are deferred and amortized to income over time. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.  PG&E Corporation amortizes its investment tax credits over the projected investment recovery period.
 
PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  PG&E Corporation files a combined state income tax return in California.  PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.
Nuclear Decommissioning Trusts 
Nuclear Decommissioning Trusts
 
The Utility's nuclear generation facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.  
 
The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.”  Since the Utility's nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion.  Therefore, all unrealized losses are considered other-than-temporary impairments.  Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates.  Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility's earnings or accumulated other comprehensive income.  The cost of debt and equity securities sold by the trust is determined by specific identification.
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 December 31, 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 December 31, 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 $362 million from 2010 to 2013 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 December 31, 2013 and 2012, the carrying amount of PG&E Corporation's investment in these agreements was $98 million and $166 million, respectively.  PG&E Corporation has no material remaining commitment to fund these agreements.  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.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs at December 31, 2013, it did not consolidate any of them.
Summary Of Significant Accounting Policies (Tables)
Schedule Of Estimated Useful Lives And Balances Of Utility's Property, Plant And Equipment 
 
Estimated Useful
 
Balance at December 31,
(in millions, except estimated useful lives)
Lives (years)
 
2013
 
2012
Electricity generating facilities (1)
20 to 100
 
$
9,116
 
$
8,253
Electricity distribution facilities
10 to 55
 
 
25,333
 
 
23,767
Electricity transmission
10 to 70
 
 
8,429
 
 
7,681
Natural gas distribution facilities
20 to 53
 
 
9,117
 
 
8,257
Natural gas transportation and storage
5 to 65
 
 
5,265
 
 
4,314
Construction work in progress
 
 
 
1,834
 
 
1,894
Total property, plant, and equipment
 
 
 
59,094
 
 
54,166
Accumulated depreciation
 
 
 
(17,843
 ) 
 
(16,643
)
Net property, plant, and equipment
 
 
$
41,251
 
$
37,523
 
 
 
 
 
 
 
 
 (1) Balance includes nuclear fuel inventories.  Stored nuclear fuel inventory is stated at weighted average cost.  Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output.  (See Note 14 below.)
 
 
Schedule Of Changes In Asset Retirement Obligations 
(in millions)
 
 
ARO liability at December 31, 2011
$
1,609
Revision in estimated cash flows
 
1,301
Accretion
 
101
Liabilities settled
 
(92
)
ARO liability at December 31, 2012
 
2,919
Revision in estimated cash flows
 
596
Accretion
 
130
Liabilities settled
 
(107
)
ARO liability at December 31, 2013
$
3,538
Reclassification Out Of Accumulated Other Comprehensive Income TableText Block 
The changes, net of income tax, in PG&E Corporation's accumulated other comprehensive income for the year ended December 31, 2013 consisted of the following:
 
 
Pension
 
Other
 
Other
 
 
 
(in millions)
Benefits
 
Benefits
 
Investments
 
Total
Beginning balance
$
(28
 ) 
$
(77
 ) 
$
4
 
$
(101
)
Other comprehensive income before reclassifications:
 
 
 
 
 
 
 
 
 
 
 
      Unrecognized net actuarial loss (net of taxes of $804,
 
 
 
 
 
 
 
 
 
 
 
      $35, and $0, respectively)
 
1,169
 
 
45
 
 
-
 
 
1,214
     Transfer to regulatory account (net of taxes of
 
 
 
 
 
 
 
 
 
 
 
     $790, $22, and $0, respectively)
 
(1,150
 ) 
 
31
 
 
-
 
 
(1,119
)
      Gain on investments (net of taxes of $0, $0, and $26,
 
 
 
 
 
 
 
 
 
 
 
      respectively)
 
-
 
 
-
 
 
38
 
 
38
Amounts reclassified from other comprehensive income: (1)
 
 
 
 
 
 
 
 
 
 
 
      Amortization of prior service cost (net of taxes of
 
 
 
 
 
 
 
 
 
 
 
      $8, $10, and $0, respectively)
 
12
 
 
13
 
 
-
 
 
25
      Amortization of net actuarial loss (net of taxes of
 
 
 
 
 
 
 
 
 
 
 
      $45, $3, and $0, respectively)
 
66
 
 
3
 
 
-
 
 
69
     Transfer to regulatory account (net of taxes of
 
 
 
 
 
 
 
 
 
 
 
     $54, $0, and $0, respectively)
 
(76
 ) 
 
-
 
 
-
 
 
(76
)
Net current period other comprehensive income
 
21
 
 
92
 
 
38
 
 
151
Ending balance
$
(7)
 
$
15
 
$
42
 
$
50
 
 
 
 
 
 
 
 
 
 
 
 
 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)
Regulatory Assets, Liabilities, And Balancing Accounts (Tables)
Long-Term Regulatory Assets 
 
Balance at December 31,
 
Recovery
(in millions)
2013
 
2012
 
Period
Pension benefits (1)
$
1,444
 
$
3,275
 
N/A (4)
Deferred income taxes (1)
 
1,835
 
 
1,627
 
1 - 45 years
Utility retained generation (2)
 
503
 
 
552
 
11 years
Environmental compliance costs (1)
 
628
 
 
604
 
32 years
Price risk management (1)
 
106
 
 
210
 
9 years
Electromechanical meters (3)
 
135
 
 
194
 
4 years
Unamortized loss, net of gain, on reacquired debt (1)
 
135
 
 
141
 
13 years
Other
 
127
 
 
206
 
Various
Total long-term regulatory assets
$
4,913
 
$
6,809
 
 
 
 
 
 
 
 
 
 
 
(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP and also includes amounts that otherwise would be recorded to accumulated other comprehensive loss in the Consolidated Balance Sheets.  (See Note 11 below.)
 
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility's proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility's retained generation assets.  The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.  
 
(3) Represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices.
 
(4) The Utility expects to continuously recover pension benefits.
Long-Term Regulatory Liabilities 
 
Balance at December 31,
(in millions)
2013
 
2012
Cost of removal obligations (1)
$
3,844
 
$
3,625
Recoveries in excess of AROs (2)
 
748
 
 
620
Public purpose programs (3)
 
587
 
 
590
Other
 
481
 
 
253
Total long-term regulatory liabilities
$
5,660
 
$
5,088
 
 
 
 
 
 
 
(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.
 
(2) Represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility's nuclear generation facilities.  Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments.  (See Note 10 below.)
 
(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
Current Regulatory Balancing Accounts, Net 
 
Receivable
 
Balance at December 31,
(in millions)
2013
 
2012
Electric distribution
$
102
 
$
219
Utility generation
 
57
 
 
117
Gas distribution
 
70
 
 
44
Energy procurement
 
410
 
 
193
Public purpose programs
 
56
 
 
48
Other
 
429
 
 
315
Total regulatory balancing accounts receivable
$
1,124
 
$
936
 
 
 
Payable
 
Balance at December 31,
(in millions)
2013
 
2012
Energy procurement
$
298
 
$
116
Public purpose programs
 
171
 
 
131
Other
 
539
 
 
387
Total regulatory balancing accounts payable
$
1,008
 
$
634
Debt (Tables)
Schedule Of Long-Term Debt 
 
December 31,
(in millions)
2013
 
2012
PG&E Corporation
 
 
 
Senior notes, 5.75%, due 2014
 
350
 
 
350
Less: current portion
 
(350
 ) 
 
-
Total senior notes
 
-
 
 
350
Total PG&E Corporation long-term debt
 
-
 
 
350
Utility
 
 
 
 
 
Senior notes:
 
 
 
 
 
6.25% due 2013
 
-
 
 
400
4.80% due 2014
 
539
 
 
1,000
5.625% due 2017
 
700
 
 
700
8.25% due 2018
 
800
 
 
800
3.50% due 2020
 
800
 
 
800
4.25% due 2021
 
300
 
 
300
3.25% due 2021
 
250
 
 
250
2.45% due 2022
 
400
 
 
400
3.25% due 2023
 
375
 
 
-
3.85% due 2023
 
300
 
 
-
6.05% due 2034
 
3,000
 
 
3,000
5.80% due 2037
 
950
 
 
950
6.35% due 2038
 
400
 
 
400
6.25% due 2039
 
550
 
 
550
5.40% due 2040
 
800
 
 
800
4.50% due 2041
 
250
 
 
250
4.45% due 2042
 
400
 
 
400
3.75% due 2042
 
350
 
 
350
4.60% due 2043
 
375
 
 
-
5.125% due 2043
 
500
 
 
-
Less: current portion
 
(539
 ) 
 
(400
)
Unamortized discount, net of premium
 
(51
 ) 
 
(51
)
Total senior notes, net of current portion
 
11,449
 
 
10,899
Pollution control bonds:
 
 
 
 
 
Series 1996 C, E, F, 1997 B, variable rates (1), due 2026 (2)
 
614
 
 
614
Series 2004 A-D, 4.75%, due 2023 (3)
 
345
 
 
345
Series 2009 A-D, variable rates (4), due 2016 and 2026 (5)
 
309
 
 
309
Total pollution control bonds
 
1,268
 
 
1,268
Total Utility long-term debt, net of current portion
 
12,717
 
 
12,167
Total consolidated long-term debt, net of current portion
$
12,717
 
$
12,517
 
 
 
 
 
 
(1)  At December 31, 2013, interest rates on these bonds and the related loans ranged from 0.01% to 0.04%.
(2)  Each series of these bonds is supported by a separate letter of credit.  In April 2013, the letters of credit were extended to April 1, 2018.  Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.
(3) The Utility has obtained credit support from an insurance company for these bonds.
(4) At December 31, 2013, interest rates on these bonds and the related loans ranged from 0.01% to 0.02%.
(5) Each series of these bonds is supported by a separate direct-pay letter of credit.  Series A and B letters of credit expire on May 31, 2016.  In October 2013, Series C and D letters of credit were extended to December 3, 2016 to coincide with the maturity of the underlying bonds.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.
Schedule Of Long-Term Debt Repayments 
(in millions,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 except interest rates)
2014
 
2015
 
2016
 
2017
 
 
2018
 
Thereafter
 
Total
PG&E Corporation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average fixed interest rate
 
5.75
%
 
 
              -
 
 
 
              -
 
 
 
              -
 
 
 
              -
 
 
 
              -
 
 
 
5.75
%
Fixed rate obligations
$
       350
 
 
$
              -
 
 
$
              -
 
 
$
              -
 
 
$
              -
 
 
$
              -
 
 
$
           350
 
Utility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average fixed interest rate
 
4.80
%
 
 
              -
 
 
 
              -
 
 
 
5.63
%
 
 
8.25
%
 
 
5.06
%
 
 
5.29
%
Fixed rate obligations
$
          539
 
 
$
              -
 
 
$
              -
 
 
$
          700
 
 
$
          800
 
 
$
      10,345
 
 
$
      12,384
 
Variable interest rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    as of December 31, 2013
 
              -
 
 
 
              -
 
 
 
0.02
%
 
 
              -
 
 
 
0.02
%
 
 
              -
 
 
 
0.02
%
Variable rate obligations (1)
$
              -
 
 
$
              -
 
 
$
          309
 
 
$
              -
 
 
$
          614
 
 
$
              -
 
 
$
          923
 
Total consolidated debt
$
          889
 
 
$
              -
 
 
$
       309
 
 
$
         700
 
 
$
       1,414
 
 
$
     10,345
 
 
$
     13,657
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (1) These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on May 31, 2016, December 3, 2016, or April 1, 2018.
Schedule Of Line Of Credit 
 
 
 
 
 
Letters of
 
 
 
 
 
 
 
Termination
 
Facility
 
 Credit
 
 
 
Commercial
 
Facility
(in millions)
Date
 
Limit
 
Outstanding
 
Borrowings
 
Paper
 
Availability
PG&E Corporation
April 2018
 
$
300
(1)
 
$
 
 
$
260
 
$
-
 
 
$
40
 
Utility
April 2018
 
 
3,000
(2)
 
 
79
 
 
-
 
 
914
(3)
 
 
2,007
(3)
Total revolving credit facilities
 
 
$
3,300
 
 
$
79
 
$
260
 
$
914
 
 
$
2,047
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
(2) Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
(3) The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.
Common Stock And Share-Based Compensation (Tables)
Schedule Of Compensation Expense For Share-Based Incentive Awards 
(in millions)
2013
 
2012
 
2011
Restricted stock units
$
36
 
$
31
 
$
23
Performance shares:
 
 
 
 
 
 
 
 
Equity awards
 
28
 
 
26
 
 
16
Liability awards
 
-
 
 
-
 
 
(13
)
Total compensation expense (pre-tax)
$
64
 
$
57
 
$
26
Total compensation expense (after-tax)
$
38
 
$
34
 
$
16
Schedule Of Restricted Stock Activity 
 
The following table summarizes RSU activity for 2013:
 
 
 
Number of
 
Weighted Average Grant-
 
Restricted Stock Units
 
Date Fair Value
Nonvested at January 1
2,069,291
 
$
42.52
Granted
993,115
 
$
42.92
Vested
(719,071
 ) 
$
41.03
Forfeited
(43,314
 ) 
$
42.68
Nonvested at December 31
2,300,021
 
$
43.16
 
Schedule Of Nonvested Performance-Based Units Activity 
The following table summarizes performance shares classified as equity awards activity for 2013:
 
 
 
Number of
 
Weighted Average Grant-
 
Performance Shares
 
Date Fair Value
Nonvested at January 1
1,497,473
 
$
38.15
Granted
911,620
 
$
33.45
Vested
-
 
$
-
Forfeited (1)
(617,773
 ) 
$
34.22
Nonvested at December 31
1,791,320
 
$
37.85
 
 
 
 
 
(1) Includes performance shares that expired with zero value as performance targets were not met.
Preferred Stock (Tables)
Summary Of Issued And Outstanding Preferred Stock
The following table summarizes the Utility's outstanding preferred stock, none of which had mandatory redemption provisions at December 31, 2013 and 2012:
 
(in millions, except share amounts, redemption
 
 
 
 
 
 
 
price, and par value)
Shares Outstanding
 
Redemption Price
 
Balance
Nonredeemable $25 par value preferred stock
 
 
 
 
 
 
 
5.00% Series
400,000
 
 
N/A
 
$
10
5.50% Series
1,173,163
 
 
N/A
 
 
30
6.00% Series
4,211,662
 
 
N/A
 
 
105
Total nonredeemable preferred stock
5,784,825
 
 
 
 
$
145
 
 
 
 
 
 
 
 
Redeemable $25 par value preferred stock
 
 
 
 
 
 
 
4.36% Series
418,291
 
$
25.75
 
$
11
4.50% Series
611,142
 
 
26.00
 
 
15
4.80% Series
793,031
 
 
27.25
 
 
20
5.00% Series
1,778,172
 
 
26.75
 
 
44
5.00% Series A
934,322
 
 
26.75
 
 
23
Total redeemable preferred stock
4,534,958
 
 
 
 
$
113
Preferred stock
 
 
 
 
 
$
258
Earnings Per Share (Tables)
Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Shares Of Common Stock Outstanding For Calculating Basic and Diluted EPS
 
Year Ended December 31,
(in millions, except per share amounts)
2013
 
2012
 
2011
Income available for common shareholders
$
814
 
$
816
 
$
844
Weighted average common shares outstanding, basic
 
444
 
 
424
 
 
401
Add incremental shares from assumed conversions:
 
 
 
 
 
 
 
 
Employee share-based compensation
 
1
 
 
1
 
 
1
Weighted average common share outstanding, diluted
 
445
 
 
425
 
 
402
Total earnings per common share, diluted
$
1.83
 
$
1.92
 
$
2.10
Income Taxes (Tables)
Schedule Of Components Of Income Tax Expense (Benefit) 
 
PG&E Corporation
 
Utility
 
Year Ended December 31,
(in millions)
2013
 
2012
 
2011
 
2013
 
2012
 
2011
Current:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Federal
$
(218
 ) 
$
(74
 ) 
$
(77
 ) 
$
(222
 ) 
$
(52
 ) 
$
(83
)
State
 
(26
 ) 
 
33
 
 
152
 
 
(23
 ) 
 
41
 
 
161
Deferred:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Federal
 
552
 
 
374
 
 
504
 
 
604
 
 
404
 
 
534
State
 
(35
 ) 
 
(92
 ) 
 
(135
 ) 
 
(28
 ) 
 
(91
 ) 
 
(128
)
Tax credits
 
(5
 ) 
 
(4
 ) 
 
(4
 ) 
 
(5
 ) 
 
(4
 ) 
 
(4
)
Income tax provision
$
268
 
$
237
 
$
440
 
$
326
 
$
298
 
$
480
Schedule Of Deferred Tax Assets And Liabilities 
 
PG&E Corporation
 
Utility
 
Year Ended December 31,
(in millions)
2013
 
2012
 
2013
 
2012
Deferred income tax assets:
 
 
 
 
 
 
 
 
 
 
 
Customer advances for construction
$
90
 
$
101
 
$
90
 
$
101
Reserve for damages
 
161
 
 
175
 
 
161
 
 
175
Environmental reserve
 
152
 
 
97
 
 
152
 
 
97
Compensation
 
167
 
 
229
 
 
102
 
 
179
Net operating loss carryforward
 
890
 
 
938
 
 
670
 
 
736
GHG allowances
 
108
 
 
34
 
 
108
 
 
34
Other
 
135
 
 
230
 
 
128
 
 
221
Total deferred income tax assets
$
1,703
 
$
1,804
 
$
1,411
 
$
1,543
Deferred income tax liabilities:
 
 
 
 
 
 
 
 
 
 
 
Regulatory balancing accounts
$
261
 
$
256
 
$
261
 
$
256
Property related basis differences
 
8,048
 
 
7,449
 
 
8,038
 
 
7,447
Income tax regulatory asset
 
748
 
 
663
 
 
748
 
 
663
Other
 
151
 
 
173
 
 
86
 
 
99
Total deferred income tax liabilities
$
9,208
 
$
8,541
 
$
9,133
 
$
8,465
Total net deferred income tax liabilities
$
7,505
 
$
6,737
 
$
7,722
 
$
6,922
Classification of net deferred income tax liabilities:
 
 
 
 
 
 
 
 
 
 
 
Included in current liabilities (assets)
$
(318
 ) 
$
(11
 ) 
$
(320
 ) 
$
(17
)
Included in noncurrent liabilities
 
7,823
 
 
6,748
 
 
8,042
 
 
6,939
Total net deferred income tax liabilities
$
7,505
 
$
6,737
 
$
7,722
 
$
6,922
Schedule Of Effective Income Tax Rate Reconciliation 
 
PG&E Corporation
 
Utility
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
Federal statutory income tax rate
35.0
%
 
35.0
%
 
35.0
%
 
35.0
%
 
35.0
%
 
35.0
%
Increase (decrease) in income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
tax rate resulting from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
State income tax (net of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
federal benefit)
(3.1
 ) 
 
(3.9
 ) 
 
1.1
 
 
(2.2
 ) 
 
(3.0
 ) 
 
1.6
 
Effect of regulatory treatment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
of fixed asset differences
(4.2
 ) 
 
(4.1
 ) 
 
(4.4
 ) 
 
(3.8
 ) 
 
(3.9
 ) 
 
(4.2
 ) 
Tax credits
(0.4
 ) 
 
(0.6
 ) 
 
(0.5
 ) 
 
(0.4
 ) 
 
(0.6
 ) 
 
(0.5
 ) 
Benefit of loss carryback
(1.1
 ) 
 
(0.7
 ) 
 
(1.9
 ) 
 
(1.0
 ) 
 
(0.4
 ) 
 
(2.1
 ) 
Non deductible penalties
0.8
 
 
0.6
 
 
6.5
 
 
0.7
 
 
0.5
 
 
6.3
 
Other, net
(2.2
 ) 
 
(3.8
 ) 
 
(1.5
 ) 
 
(0.9
 ) 
 
(0.8
 ) 
 
0.1
 
Effective tax rate
24.8
%
 
22.5
%
 
34.3
%
 
27.4
%
 
26.8
%
 
36.2
%
Schedule Of Change In Unrecognized Tax Benefits 
 
PG&E Corporation
 
Utility
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of year
$
581
 
$
506
 
$
714
 
$
575
 
$
503
 
$
712
Additions for tax position taken
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
during a prior year
 
12
 
 
32
 
 
2
 
 
12
 
 
26
 
 
2
Reductions for tax position
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
taken during a prior year
 
(6
 ) 
 
(13
 ) 
 
(198
 ) 
 
(6
 ) 
 
(10
 ) 
 
(196
)
Additions for tax position
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
taken during the current year
 
79
 
 
67
 
 
3
 
 
79
 
 
67
 
 
-
Settlements
 
-
 
 
(11
 ) 
 
(15
 ) 
 
-
 
 
(11
 ) 
 
(15
)
Balance at end of year
$
666
 
$
581
 
$
506
 
$
660
 
$
575
 
$
503
Derivatives And Hedging Activities (Tables)
Volumes Of Outstanding Derivative Contracts 
 
At December 31, 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
 
243,213,288
 
79,735,000
 
8,892,500
 
-
 
 
Options
 
169,123,208
 
87,689,708
 
3,450,000
 
-
Electricity
 
Forwards and
 
 
 
 
 
 
 
 
(Megawatt-hours)
 
Swaps
 
2,537,023
 
2,009,505
 
2,008,046
 
1,534,695
 
 
Congestion
 
 
 
 
 
 
 
 
 
 
Revenue Rights
 
73,510,440
 
83,747,782
 
63,718,517
 
29,945,852
 
 
 
 
 
 
 
 
 
 
 
 (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 2019 and 2022.
(3) Amounts shown are for the combined positions of the electric fuels and core gas supply 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 2023.
(3) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(4) Million British Thermal Units.
 
Outstanding Derivative Balances 
At December 31, 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
$
42
 
$
(10
 ) 
$
16
 
$
48
Other noncurrent assets - other
 
99
 
 
(4
 ) 
 
-
 
 
95
Current liabilities - other
 
(122
 ) 
 
10
 
 
69
 
 
(43
)
Noncurrent liabilities - other
 
(110
 ) 
 
4
 
 
2
 
 
(104
)
Total commodity risk
$
(91)
 
$
-
 
$
87
 
$
(4)
 
 
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 
Gains and losses recorded on PG&E Corporation's and the Utility's derivatives were as follows:
 
 
Commodity Risk
 
For the year ended December 31,
(in millions)
2013
 
2012
 
2011
Unrealized gain/(loss) - regulatory assets and liabilities (1)
$
238
 
$
391
 
$
21
Realized loss - cost of electricity (2)
 
(178
 ) 
 
(486
 ) 
 
(558
)
Realized loss - cost of natural gas (2)
 
(22
 ) 
 
(38
 ) 
 
(106
)
Total commodity risk
$
38
 
$
(133)
 
$
(643)
 
 
 
 
 
 
 
 
 
 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the  Consolidated Statements of Income.  These amounts exclude the impact of cash collateral postings.
(2) These amounts are fully passed through to customers in rates.  Accordingly, net income was not impacted by realized amounts on these instruments.
Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered 
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 December 31,
(in millions)
2013
 
2012
Derivatives in a liability position with credit risk-related
 
 
 
 
 
 contingencies that are not fully collateralized
$
(79
 ) 
$
(266
)
Related derivatives in an asset position
 
4
 
 
59
Collateral posting in the normal course of business related to
 
 
 
 
 
these derivatives
 
65
 
 
103
Net position of derivative contracts/additional collateral
 
 
 
 
 
posting requirements (1)
$
(10)
 
$
(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  December 31, 2013
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting (1)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
226
 
$
-
 
$
-
 
$
-
 
$
226
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
38
 
 
-
 
 
-
 
 
-
 
 
38
  U.S. equity securities
 
1,046
 
 
11
 
 
 
 
 
-
 
 
1,057
  Non-U.S. equity securities
 
457
 
 
-
 
 
-
 
 
-
 
 
457
  U.S. government and agency securities
 
760
 
 
156
 
 
-
 
 
-
 
 
916
  Municipal securities
 
-
 
 
25
 
 
-
 
 
-
 
 
25
  Other fixed-income securities
 
-
 
 
162
 
 
-
 
 
-
 
 
162
Total nuclear decommissioning trusts (2)
 
2,301
 
 
354
 
 
-
 
 
-
 
 
2,655
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 9)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
 
2
 
 
27
 
 
107
 
 
3
 
 
139
  Gas
 
-
 
 
5
 
 
-
 
 
(1
 ) 
 
4
Total price risk management instruments
 
2
 
 
32
 
 
107
 
 
2
 
 
143
Rabbi trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Fixed-income securities
 
-
 
 
39
 
 
-
 
 
-
 
 
39
  Life insurance contracts
 
-
 
 
70
 
 
-
 
 
-
 
 
70
Total rabbi trusts
 
-
 
 
109
 
 
-
 
 
-
 
 
109
Long-term disability trust
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
 
9
 
 
-
 
 
-
 
 
-
 
 
9
  U.S. equity securities
 
-
 
 
14
 
 
-
 
 
-
 
 
14
  Non-U.S. equity securities
 
-
 
 
12
 
 
-
 
 
-
 
 
12
  Fixed-income securities
 
-
 
 
122
 
 
-
 
 
-
 
 
122
Total long-term disability trust
 
9
 
 
148
 
 
-
 
 
-
 
 
157
Other investments
 
84
 
 
-
 
 
-
 
 
-
 
 
84
Total assets
$
2,622
 
$
643
 
$
107
 
$
2
 
$
3,374
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Price risk management instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Note 9)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Electricity
$
19
 
$
72
 
$
137
 
$
(84
 ) 
$
144
  Gas
 
1
 
 
3
 
 
-
 
 
(1
 ) 
 
3
Total liabilities
$
20
 
$
75
 
$
137
 
$
(85)
 
$
147
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $313 million, primarily related to deferred taxes on 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 9)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  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 9)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  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, primarily related to deferred taxes on appreciation of investment value.
Sensitivity Analysis 
 
 
 
Fair Value at
 
 
 
 
 
 
 
(in millions)
 
December 31, 2013
 
 
 
 
 
 
 
Fair Value Measurement
 
Assets
 
Liabilities
 
Valuation Technique
 
Unobservable Input
 
Range (1)
Congestion revenue rights
 
$
107
 
$
32
 
Market approach
 
CRR auction prices
 
$
(6.47) - 12.04
Power purchase agreements
 
$
-
 
$
105
 
Discounted cash flow
 
Forward prices
 
$
23.43 - 51.75
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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 January 1
$
(79)
 
$
(74)
Realized and unrealized gains (losses):
 
 
 
 
 
Included in regulatory assets and liabilities or balancing accounts (1)
 
49
 
 
(5
)
Liability balance as of December 31
$
(30)
 
$
(79)
 
 
 
 
 
 
    (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 
 
At December 31,
 
2013
 
2012
(in millions)
Carrying Amount
 
Level 2 Fair Value
 
Carrying Amount
 
Level 2 Fair Value
Debt (Note 4)
 
 
 
 
 
 
 
 
 
 
 
PG&E Corporation
$
350
 
$
354
 
$
349
 
$
371
Utility
 
12,334
 
 
13,444
 
 
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 December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trusts
 
 
 
 
 
 
 
 
 
 
 
  Money market investments
$
38
 
$
-
 
$
-
 
$
38
  Equity securities
 
 
 
 
 
 
 
 
 
 
 
  U.S.
 
246
 
 
811
 
 
-
 
 
1,057
  Non-U.S.
 
215
 
 
242
 
 
-
 
 
457
  Debt securities
 
 
 
 
 
 
 
 
 
 
 
    U.S. government and agency securities
 
870
 
 
51
 
 
(5
 ) 
 
916
    Municipal securities
 
24
 
 
2
 
 
(1
 ) 
 
25
    Other fixed-income securities
 
163
 
 
1
 
 
(2
 ) 
 
162
Total nuclear decommissioning trusts (1)
 
1,556
 
 
1,107
 
 
(8
 ) 
 
2,655
Other investments
 
13
 
 
71
 
 
-
 
 
84
Total
$
1,569
 
$
1,178
 
$
(8)
 
$
2,739
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 $313 million and $240 million at December 31, 2013 and 2012, respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule Of Long Term Debt Repayments 
(in millions)
As of December 31, 2013
Less than 1 year
$
22
1-5 years
 
519
5-10 years
 
230
More than 10 years
 
332
Total maturities of debt securities
$
1,103
Schedule Of Activity For Debt And Equity Securities 
 
2013
 
2012
 
2011
(in millions)
 
 
 
 
 
 
 
 
Proceeds from sales and maturities of nuclear decommissioning trust
 
 
 
 
 
 
 
 
investments
$
1,619
 
$
1,133
 
$
1,928
Gross realized gains on sales of securities held as available-for-sale
 
94
 
 
19
 
 
43
Gross realized losses on sales of securities held as available-for-sale
 
(13
 ) 
 
(17
 ) 
 
(30
)
Employee Benefit Plans (Tables)
Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status 
Pension Benefits
 
(in millions)
2013
 
2012
Change in plan assets:
 
 
 
Fair value of plan assets at January 1
$
12,141
 
$
10,993
Actual return on plan assets
 
673
 
 
1,488
Company contributions
 
323
 
 
282
Benefits and expenses paid
 
(610
 ) 
 
(622
)
Fair value of plan assets at December 31
$
12,527
 
$
12,141
 
 
 
 
 
 
Change in benefit obligation:
 
 
 
 
 
Projected benefit obligation at January 1
$
15,541
 
$
14,000
Service cost for benefits earned
 
468
 
 
396
Interest cost
 
627
 
 
658
Actuarial (gain) loss
 
(1,950
 ) 
 
1,099
Plan amendments
 
-
 
 
9
Transitional costs
 
1
 
 
1
Benefits and expenses paid
 
(610
 ) 
 
(622
)
Projected benefit obligation at December 31 (1)
$
14,077
 
$
15,541
 
 
 
 
 
 
Funded status:
 
 
 
 
 
Current liability
$
(6
 ) 
$
(6
)
Noncurrent liability
 
(1,544
 ) 
 
(3,394
)
Accrued benefit cost at December 31
$
(1,550)
 
$
(3,400)
 
 
 
 
 
 
 (1) PG&E Corporation's accumulated benefit obligation was $12,659  million and $13,778 million at December 31, 2013 and 2012, respectively.
 
Other Benefits
 
(in millions)
2013
 
2012
Change in plan assets:
 
 
 
 
 
Fair value of plan assets at January 1
$
1,758
 
$
1,491
Actual return on plan assets
 
64
 
 
191
Company contributions
 
145
 
 
149
Plan participant contribution
 
64
 
 
55
Benefits and expenses paid
 
(139
 ) 
 
(128
)
Fair value of plan assets at December 31
$
1,892
 
$
1,758
 
 
 
 
 
 
Change in benefit obligation:
 
 
 
 
 
Benefit obligation at January 1
$
1,940
 
$
1,885
Service cost for benefits earned
 
53
 
 
49
Interest cost
 
74
 
 
83
Actuarial gain
 
(415
 ) 
 
(23
)
Plan amendments
 
-
 
 
5
Benefits paid
 
(123
 ) 
 
(119
)
Federal subsidy on benefits paid
 
4
 
 
5
Plan participant contributions
 
64
 
 
55
Benefit obligation at December 31
$
1,597
 
$
1,940
 
 
 
 
 
 
Funded status (1):
 
 
 
 
 
Noncurrent asset
$
352
 
$
-
Noncurrent liability
 
(57
 ) 
 
(181
)
Accrued benefit cost at December 31
$
295
 
$
(181)
 
 
 
 
 
 
 (1) At December 31, 2013, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.       At December 31, 2012, both the postretirement medical plan and the postretirement life insurance plan were in underfunded positions.
Components Of Net Periodic Benefit Cost 
Pension Benefits
 
(in millions)
2013
 
2012
 
2011
Service cost for benefits earned
$
468
 
$
396
 
$
320
Interest cost
 
627
 
 
658
 
 
660
Expected return on plan assets
 
(650
 ) 
 
(598
 ) 
 
(669
)
Amortization of prior service cost
 
20
 
 
20
 
 
34
Amortization of net actuarial loss
 
111
 
 
123
 
 
50
Net periodic benefit cost
 
576
 
 
599
 
 
395
Less: transfer to regulatory account (1)
 
(238
 ) 
 
(301
 ) 
 
(139
)
Total
$
338
 
$
298
 
$
256
 
 
 
 
 
 
 
 
 
 (1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates
 
 
Other Benefits
 
(in millions)
2013
 
2012
 
2011
Service cost for benefits earned
$
53
 
$
49
 
$
42
Interest cost
 
74
 
 
83
 
 
91
Expected return on plan assets
 
(79
 ) 
 
(77
 ) 
 
(82
)
Amortization of transition obligation
 
-
 
 
24
 
 
26
Amortization of prior service cost
 
23
 
 
25
 
 
27
Amortization of net actuarial loss
 
6
 
 
6
 
 
4
Net periodic benefit cost
$
77
 
$
110
 
$
108
Estimated Amortized Net Periodic Benefit For 2012 
 
Pension Benefit
 
(in millions)
 
Unrecognized prior service cost
$
20
Unrecognized net loss
 
2
Total
$
22
 
 
Other Benefits
(in millions)
 
 
Unrecognized prior service cost
$
23
Unrecognized net gain
 
2
Total
$
25
 
Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost 
 
Pension Benefits
 
Other Benefits
 
December 31,
 
December 31,
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
Discount rate
4.89
%
 
3.98
%
 
4.66
%
 
4.70 - 5.00
%
 
3.75 - 4.08
%
 
4.41 - 4.77
%
Average rate of future
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
compensation increases
4.00
%
 
4.00
%
 
5.00
%
 
-
 
 
-
 
 
-
 
Expected return on plan assets
6.50
%
 
5.40
%
 
5.50
%
 
3.50 - 6.70
%
 
2.90 - 6.10
%
 
4.40 - 5.50
%
Schedule Of Assumed Health Care Cost Trend 
 
One-
 
One-
 
Percentage-
 
Percentage-
 
Point
 
Point
(in millions)
Increase
 
Decrease
Effect on postretirement benefit obligation
$
86
 
$
(88
)
Effect on service and interest cost
 
9
 
 
(9
)
Target Asset Allocation Percentages 
 
Pension Benefits
 
Other Benefits
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Global equity securities
25
%
 
25
%
 
35
%
 
30
%
 
28
%
 
38
%
Absolute return
5
%
 
5
%
 
5
%
 
3
%
 
4
%
 
4
%
Real assets
10
%
 
10
%
 
10
%
 
8
%
 
8
%
 
8
%
Extended fixed-income securities
3
%
 
3
%
 
3
%
 
-
%
 
-
%
 
-
%
Fixed-income securities
57
%
 
57
%
 
47
%
 
59
%
 
60
%
 
50
%
Total
100
%
 
100
%
 
100
%
 
100
%
 
100
%
 
100
%
Schedule Of Changes In Fair Value Of Plan Assets 
 
Fair Value Measurements
 
At December 31,
 
2013
 
2012
(in millions)
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Pension Benefits:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
70
 
$
-
 
$
-
 
$
70
 
$
112
 
$
-
 
$
-
 
$
112
Global equity securities
 
1,123
 
 
2,363
 
 
-
 
 
3,486
 
 
402
 
 
3,017
 
 
-
 
 
3,419
Absolute return
 
-
 
 
-
 
 
554
 
 
554
 
 
-
 
 
-
 
 
513
 
 
513
Real assets
 
562
 
 
-
 
 
544
 
 
1,106
 
 
525
 
 
-
 
 
285
 
 
810
Fixed-income securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. government
 
1,281
 
 
319
 
 
-
 
 
1,600
 
 
1,576
 
 
139
 
 
-
 
 
1,715
Corporate
 
1
 
 
4,230
 
 
625
 
 
4,856
 
 
3
 
 
4,275
 
 
611
 
 
4,889
Other
 
166
 
 
555
 
 
-
 
 
721
 
 
-
 
 
576
 
 
-
 
 
576
Total
$
3,203
 
$
7,467
 
$
1,723
 
$
12,393
 
$
2,618
 
$
8,007
 
$
1,409
 
$
12,034
Other Benefits:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Money market investments
$
31
 
$
-
 
$
-
 
$
31
 
$
77
 
$
-
 
$
-
 
$
77
Global equity securities
 
127
 
 
504
 
 
-
 
 
631
 
 
118
 
 
397
 
 
-
 
 
515
Absolute return
 
-
 
 
-
 
 
53
 
 
53
 
 
-
 
 
-
 
 
49
 
 
49
Real assets
 
67
 
 
-
 
 
38
 
 
105
 
 
68
 
 
-
 
 
28
 
 
96
Fixed-income securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. government
 
119
 
 
5
 
 
-
 
 
124
 
 
148
 
 
5
 
 
-
 
 
153
Corporate
 
4
 
 
894
 
 
2
 
 
900
 
 
9
 
 
795
 
 
1
 
 
805
Other
 
14
 
 
37
 
 
-
 
 
51
 
 
-
 
 
38
 
 
-
 
 
38
Total
$
362
 
$
1,440
 
$
93
 
$
1,895
 
$
420
 
$
1,235
 
$
78
 
$
1,733
Total plan assets at fair value
 
 
 
 
 
 
 
 
 
$
14,288
 
 
 
 
 
 
 
 
 
 
$
13,767
Schedule Of Level 3 Reconciliation 
 
 
Pension Benefits
 
Absolute
 
Corporate
 
 
 
 
(in millions)
Return
 
Fixed-Income
 
Real Assets
 
Total
Balance as of January 1, 2012
$
487
 
$
585
 
$
65
 
$
1,137
Actual return on plan assets:
 
 
 
 
 
 
 
 
 
 
 
Relating to assets still held at the reporting date
 
26
 
 
28
 
 
12
 
 
66
Relating to assets sold during the period
 
-
 
 
(1
 ) 
 
-
 
 
(1)
Purchases, issuances, sales, and settlements
 
 
 
 
 
 
 
 
 
 
 
Purchases
 
-
 
 
12
 
 
208
 
 
220
Settlements
 
-
 
 
(13
 ) 
 
-
 
 
(13)
Balance as of December 31, 2012
$
513
 
$
611
 
$
285
 
$
1,409
Actual return on plan  assets:
 
 
 
 
 
 
 
 
 
 
 
Relating to assets still held at the reporting date
 
37
 
 
1
 
 
49
 
 
87
Relating to assets sold during the period
 
4
 
 
-
 
 
(3
 ) 
 
1
Purchases, issuances, sales, and settlements
 
 
 
 
 
 
 
 
 
 
 
Purchases
 
-
 
 
20
 
 
352
 
 
372
Settlements
 
-
 
 
(7
 ) 
 
(139)
 
 
(146)
Balance as of December 31, 2013
$
554
 
$
625
 
$
544
 
$
1,723
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Benefits
 
Absolute
 
Corporate
 
 
 
 
(in millions)
Return
 
Fixed-Income
 
Real Assets
 
Total
Balance as of January 1, 2012
$
47
 
$
1
 
 
6
 
$
54
Actual return on plan assets:
 
 
 
 
 
 
 
 
 
 
 
Relating to assets still held at the reporting date
 
2
 
 
-
 
 
1
 
 
3
Relating to assets sold during the period
 
-
 
 
-
 
 
-
 
 
-
Purchases, issuances, sales, and settlements
 
 
 
 
 
 
 
 
 
 
 
Purchases
 
-
 
 
1
 
 
21
 
 
22
Settlements
 
-
 
 
(1
 ) 
 
-
 
 
(1)
Balance as of December 31, 2012
$
49
 
$
1
 
$
28
 
$
78
Actual return on plan  assets:
 
 
 
 
 
 
 
 
 
 
 
Relating to assets still held at the reporting date
 
4
 
 
-
 
 
3
 
 
7
Relating to assets sold during the period
 
-
 
 
-
 
 
-
 
 
-
Purchases, issuances, sales, and settlements
 
 
 
 
 
 
 
 
 
 
 
Purchases
 
12
 
 
1
 
 
21
 
 
34
Settlements
 
(12
 ) 
 
-
 
 
(14
 ) 
 
(26)
Balance as of December 31, 2013
$
53
 
$
2
 
$
38
 
$
93
 
Schedule Of Estimated Benefits Expected To Be Paid 
(in millions)
Pension
 
Other
 
Federal Subsidy
2014
$
613
 
$
90
 
$
(6
)
2015
 
652
 
 
95
 
 
(7
)
2016
 
692
 
 
100
 
 
(8
)
2017
 
730
 
 
107
 
 
(8
)
2018
 
766
 
 
113
 
 
(9
)
2019 - 2023
 
4,326
 
 
609
 
 
(35
)
Schedule Of Employer Contribution Expense 
(in millions)
 
 
Year ended December 31,
 
 
2013
$
71
2012
 
67
2011
 
65
Resolution Of Remaining Chapter 11 Disputed Claims (Tables)
Changes In The Remaining Net Disputed Claims Liability
(in millions)
  
 
Balance at December 31, 2012
$
842
Interest accrued, net of settlement
  
25
Less: supplier settlements-principal amount
  
(3
)
Balance at December 31, 2013
$
864
Related Party Agreements And Transactions (Tables)
Schedule Of Significant Related Party Transactions
 
Year Ended December 31, 
(in millions)
2013
 
2012
 
2011
Utility revenues from:
 
 
 
 
 
Administrative services provided to PG&E Corporation
$
7
 
$
7
 
$
6
Utility expenses from:
 
 
 
 
 
 
 
 
Administrative services received from PG&E
 
 
 
 
 
 
 
 
Corporation
$
45
 
$
50
 
$
49
Utility employee benefit due to PG&E Corporation
 
57
 
 
51
 
 
33
Commitments And Contingencies (Tables)
Schedule Of Costs Incurred Attributable To Each Category Of Power Purchase Agreements 
 
 
(in millions)
2013
 
2012
 
2011
Qualifying facilities (1)
$
813
 
$
779
 
$
1,069
Renewable energy contracts
 
1,281
 
 
815
 
 
622
Other power purchase agreements
 
902
 
 
661
 
 
690
 
(1) Costs incurred include $271, $286, and $297 attributable to renewable energy contracts with qualifying facilities at December 31, 2013, 2012, and 2011, respectively.
 
Schedule Of Undiscounted Future Expected Power Purchase Agreement Payments 
 
 
 
Renewable
 
 
 
 
 
 
(in millions)
Qualifying Facility
 
(Other than QFs)
 
Other
 
Total Payments
2014
$
913
 
$
1,906
 
$
829
 
$
3,648
2015
 
707
 
 
2,102
 
 
770
 
 
3,579
2016
 
587
 
 
2,109
 
 
722
 
 
3,418
2017
 
450
 
 
2,104
 
 
684
 
 
3,238
2018
 
406
 
 
1,962
 
 
640
 
 
3,008
Thereafter
 
1,614
 
 
30,242
 
 
2,984
 
 
34,840
Total
$
4,677
 
$
40,425
 
$
6,629
 
$
51,731
Schedule Of Fixed Capacity Payments Due Under The QF Contracts Discount 
(in millions)
 
 
2014
$
27
2015
 
24
2016
 
22
2017
 
18
2018
 
12
Thereafter
 
8
Total fixed capacity payments
 
111
Less: amount representing interest
 
14
Present value of fixed capacity payments
$
97
Undiscounted Obligations For Natural Gas Purchases, Gas Transportation Services, And Gas Storage 
(in millions)
 
 
2014
$
727
2015
 
198
2016
 
150
2017
 
108
2018
 
108
Thereafter
 
756
Total
$
2,047
Undiscounted Obligations Under Nuclear Fuel Agreements 
(in millions)
 
 
2014
$
145
2015
 
162
2016
 
146
2017
 
148
2018
 
132
Thereafter
 
647
Total
$
1,380
Future Minimum Payments Of Operating Leases 
(in millions)
 
 
2014
$
42
2015
 
37
2016
 
34
2017
 
27
2018
 
24
Thereafter
 
193
Total
$
357
Environmental Remediation Liability Disclosure 
 
 
 
(in millions)
 
 
Balance at December 31, 2012
$
910
Additional remediation costs accrued:
 
 
Transfer to regulatory account for  recovery
 
116
Amounts not recoverable from customers
 
49
Less: Payments
 
(175
)
Balance at December 31, 2013
$
900
 
 
 
 
 
Balance at December 31,
(in millions)
2013
 
2012
Utility-owned natural gas compressor site near Hinkley, California (1)
$
190
 
$
226
Utility-owned natural gas compressor site near Topock, Arizona (1)
 
264
 
 
239
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites
 
160
 
 
158
Former MGP sites owned by the Utility or third parties
 
184
 
 
181
Fossil fuel-fired generation facilities and sites
 
102
 
 
106
Total environmental remediation liability
$
900
 
$
910
 
 
 
 
 
 
      (1) See “Natural Gas Compressor Sites” below.
 
Quarterly Consolidated Financial Data (Tables)
Schedule Of Quarterly Consolidated Financial Data
 
Quarter ended
(in millions, except per share amounts)
December 31 
 
September 30 
 
June 30 
 
March 31 
2013
 
 
 
 
 
 
 
 
 
 
 
PG&E CORPORATION
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,975
 
$
4,175
 
$
3,776
 
$
3,672
Operating income
 
333
 
 
291
 
 
636
 
 
502
Income tax (benefit) provision
 
25
 
 
(24
 ) 
 
153
 
 
114
Net income
 
90
 
 
164
 
 
332
 
 
242
Income available for common shareholders
 
86
 
 
161
 
 
328
 
 
239
Comprehensive income
 
210
 
 
165
 
 
352
 
 
252
Net earnings per common share, basic
 
0.19
 
 
0.36
 
 
0.74
 
 
0.55
Net earnings per common share, diluted
 
0.19
 
 
0.36
 
 
0.74
 
 
0.55
Common stock price per share:
 
 
 
 
 
 
 
 
 
 
 
High
 
42.75
 
 
46.37
 
 
48.44
 
 
44.53
Low
 
40.07
 
 
40.76
 
 
43.59
 
 
40.47
UTILITY
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,973
 
$
4,174
 
$
3,775
 
$
3,671
Operating income
 
360
 
 
292
 
 
635
 
 
503
Income tax (benefit) provision
 
65
 
 
(20
 ) 
 
160
 
 
121
Net income
 
138
 
 
162
 
 
329
 
 
237
Income available for common stock
 
134
 
 
159
 
 
325
 
 
234
Comprehensive income
 
231
 
 
166
 
 
333
 
 
242
 
 
 
 
 
 
 
 
 
 
 
 
2012
 
 
 
 
 
 
 
 
 
 
 
PG&E CORPORATION
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,830
 
$
3,976
 
$
3,593
 
$
3,641
Operating income
 
125
 
 
614
 
 
467
 
 
487
Income tax (benefit) provision
 
(54
 ) 
 
100
 
 
87
 
 
104
Net income (loss)
 
(9
 ) 
 
364
 
 
239
 
 
236
Income (loss) available for common shareholders
 
(13
 ) 
 
361
 
 
235
 
 
233
Comprehensive income
 
77
 
 
372
 
 
247
 
 
246
Net earnings (loss) per common share, basic
 
(0.03
 ) 
 
0.84
 
 
0.56
 
 
0.56
Net earnings (loss) per common share, diluted
 
(0.03
 ) 
 
0.84
 
 
0.55
 
 
0.56
Common stock price per share:
 
 
 
 
 
 
 
 
 
 
 
High
 
43.48
 
 
46.51
 
 
45.20
 
 
43.72
Low
 
39.71
 
 
42.41
 
 
42.04
 
 
40.16
UTILITY
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,829
 
$
3,974
 
$
3,592
 
$
3,640
Operating income
 
127
 
 
613
 
 
467
 
 
488
Net income
 
13
 
 
340
 
 
227
 
 
231
Income tax provision
 
(30
 ) 
 
122
 
 
93
 
 
113
Income available for common stock
 
9
 
 
337
 
 
223
 
 
228
Comprehensive income
 
96
 
 
348
 
 
235
 
 
241
Schedule I - Condensed Financial Information Of Parent (Tables)
Schedule of Condensed Statements of Income 
 
Year Ended December 31,
 
2013
2012
2011
Administrative service revenue
$ 41 
$ 43 
$ 44 
Operating expenses
(42
 )(41)
(44
)
Interest income
1 
1 
1 
Interest expense
(25
 )(22)
(22
)
Other income
(57
 )(39)
(17
)
Equity in earnings of subsidiaries
848 
817 
852 
Income before income taxes
766 
759 
814 
Income tax benefit
48 
57 
30 
Net income
$ 814 
$ 816 
$ 844 
Other Comprehensive Income
 
 
 
Pension and other postretirement benefit plans (net of taxes of $80, $72, $9, at respective dates)
113 
108 
(11
)
Other (net of taxes of $26, $3, and $0, at respective dates)
38 
4 
- 
Total other comprehensive income (loss)
151 
112 
(11
)
Comprehensive Income
$ 965 
$ 928 
$ 833 
Weighted average common shares outstanding, basic
444 
424 
401 
Weighted average common shares outstanding, diluted
445 
425 
402 
Net earnings per common share, basic
$ 1.83 
$ 1.92 
$ 2.10 
Net earnings per common share, diluted
$ 1.83 
$ 1.92 
$ 2.10 
Schedule of Condensed Balance Sheet 
 
Balance at December 31,
 
2013
2012
ASSETS
 
 
Current Assets
 
 
Cash and cash equivalents
$ 231 
$ 207 
Advances to affiliates
30 
26 
Income taxes receivable
13 
33 
Other current assets
86 
- 
Total current assets
360 
266 
Noncurrent Assets
 
 
Equipment
2 
1 
Accumulated depreciation
(1
 )(1)
Net equipment
1 
- 
Investments in subsidiaries
14,711 
13,387 
Other investments
110 
102 
Income taxes receivable
5 
5 
Deferred income taxes
188 
178 
Other
- 
1 
Total noncurrent assets
15,015 
13,673 
Total Assets
$ 15,375 
$ 13,939 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
Current Liabilities
 
 
Short-term borrowings
$ 260 
$ 120 
Long-term debt, classified as current
350 
- 
Accounts payable - other
66 
48 
Other
230 
221 
Total current liabilities
906 
389 
Noncurrent Liabilities
 
 
Longdebt
- 
349 
Other
127 
127 
Total noncurrent liabilities
127 
476 
Common Shareholders' Equity
 
 
Common stock
9,550 
8,428 
Reinvested earnings
4,742 
4,747 
Accumulated other comprehensive income (loss)
50 
(101
)
Total common shareholders' equity
14,342 
13,074 
Total Liabilities and Shareholders' Equity
$ 15,375 
$ 13,939 
Schedule Of Condensed Statement Of Cash Flows 
 
 
Year Ended December 31,
 
 
 
2013
 
2012
 
2011
 
Cash Flows from Operating Activities:
 
 
 
 
 
 
 
 
 
 
Net income
 
 $
814 
    
 $
816 
 
 $
 
844 
 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
 
 
 
 
   Stock-based compensation amortization
 
 
54 
   
 
51 
 
 
36 
 
   Equity in earnings of subsidiaries
 
 
(848
 ) 
 
(817
 ) 
 
(852
 ) 
   Deferred income taxes and tax credits, net
 
 
(10
 ) 
 
(31
 ) 
 
(26
 ) 
   Noncurrent income taxes receivable/payable
 
 
- 
 
 
(6
 ) 
 
(47
 ) 
   Current income taxes receivable/payable
 
 
20 
 
 
(82
 ) 
 
49 
 
   Other
 
 
(20
 ) 
 
20 
 
 
(80
 ) 
Net cash provided by (used in) operating activities
 
 
10 
 
 
(49) 
 
 
(76
 ) 
Cash Flows From Investing Activities:
 
 
 
 
 
 
 
 
 
 
Investment in subsidiaries
 
 
(1,371
 ) 
 
(1,023
 ) 
 
(759
 ) 
Dividends received from subsidiaries (1)
 
 
716 
   
 
716 
 
 
716 
 
Proceeds from tax equity investments
 
 
275 
 
 
228 
 
 
129 
 
Other
 
 
(8
 ) 
 
- 
 
 
- 
 
Net cash provided by (used in) investing activities
 
 
(388
 ) 
 
(79) 
 
 
86 
 
Cash Flows From Financing Activities:
 
 
 
 
 
 
 
 
 
 
Borrowings under revolving credit facilities
 
 
140 
 
 
120 
 
 
150 
 
Repayments under revolving credit facilities
 
 
- 
 
 
- 
 
 
(150
 ) 
Common stock issued
 
 
1,045 
  
 
751 
 
 
662 
 
Common stock dividends paid (2) 
 
 
(782
 ) 
 
(746
 ) 
 
(704
 ) 
Other
 
 
(1
 ) 
 
1 
 
 
1 
 
Net cash provided by (used in) financing activities
 
 
402 
 
 
126 
 
 
(41
 ) 
Net change in cash and cash equivalents
 
 
24 
   
 
(2
 ) 
 
(31
 ) 
Cash and cash equivalents at January 1
 
 
207 
 
 
209 
 
 
240 
 
Cash and cash equivalents at December 31
 
$
231 
 
$
207 
 
$
209 
 
Supplemental disclosures of cash flow information
 
 
 
 
 
 
 
 
 
 
   Cash received (paid) for:
 
 
 
 
 
 
 
 
 
 
   Interest, net of amounts capitalized
 
$
(23
 ) 
$
(20
 ) 
$
(20
 ) 
   Income taxes, net
 
 
21 
 
 
(60
 ) 
 
8 
 
Supplemental disclosures of noncash investing and financing
 
 
 
 
 
 
 
 
 
 
   activities
 
 
 
 
 
 
 
 
 
 
   Noncash common stock issuances
 
$
22 
 
$
22 
 
$
24 
 
   Common stock dividends declared but not yet paid
 
 
208 
 
 
196 
 
 
188 
 
 
 
 
 
 
 
 
 
 
 
 
(1)
Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.
 
 
(2)
On January 15, April 15, July 15, October 15, 2013, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
 
 
 
On January 15, April 15, July 15, October 15, 2012, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
 
 
 
On January 15, April 15, July 15, October 15, 2011, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
Schedule II - Consolidated Valuation And Qualifying Accounts (Tables)
Schedule II - Consolidated Valuation And Qualifying Accounts
PG&E Corporation
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2013, 2012, and 2011
(in millions)
 
 
 
Additions
 
 
Description
Balance at Beginning of Period
Charged to Costs and Expenses
Charged to Other Accounts
Deductions (2)
Balance at End of Period
Valuation and qualifying accounts deducted from assets:
 
 
 
 
 
2013:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 87
$ 53
$ -
$ 60
$ 80
2012:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 81
$ 66
$ -
$ 60
$ 87
2011:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 81
$ 60
$ -
$ 60
$ 81
 
 
 
 
 
 
 
 
 
 
 
 
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
 
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
 
 
 
 
 
Pacific Gas and Electric Company
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2013, 2012, and 2011
(in millions)
 
 
 
Additions
 
 
Description
Balance at Beginning of Period
Charged to Costs and Expenses
Charged to Other Accounts
Deductions (2)
Balance at End of Period
Valuation and qualifying accounts deducted from assets:
 
 
 
 
 
2013:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 87
$ 53
$ -
$ 60
$ 80
2012:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 81
$ 66
$ -
$ 60
$ 87
2011:
 
 
 
 
 
Allowance for uncollectible accounts(1)
$ 81
$ 60
$ -
$ 60
$ 81
 
 
 
 
 
 
 
 
 
 
 
 
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
 
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Public Utility, Property, Plant and Equipment [Line Items]
 
 
 
Disallowed capital expenditure losses
 
$ 353 
 
Increase of estimated cost to decommision nuclear power plant
1,400 
 
 
Increase in asset retirement obligaiton
596 
 
 
Number of tax equity agreements
4 
 
 
Carrying amount of investments in tax equity agreements
98 
166 
 
Pacific Gas And Electric Company [Member]
 
 
 
Public Utility, Property, Plant and Equipment [Line Items]
 
 
 
Disallowed capital expenditure losses
196 
353 
 
PGE Corporation And Utility [Member]
 
 
 
Public Utility, Property, Plant and Equipment [Line Items]
 
 
 
Loss on debt extinguishment
157 
163 
186 
Amortization on loss on debt extinguishment
23 
23 
18 
Utility [Member]
 
 
 
Public Utility, Property, Plant and Equipment [Line Items]
 
 
 
Composite depreciation rate
3.51% 
3.63% 
3.67% 
AFUDC interest recorded
47 
49 
40 
AFUDC equity recorded
101 
107 
87 
Nuclear decommissioning obligation accrued
2,500 
2,500 
 
Estimated cost recovery on spent nuclear fuel storage proceeding every year
3,500 
3,500 
 
Approximate estimated nuclear decommissioning cost in future dollars
6,100 
6,100 
 
Residential And Commercial Retail Solar Energy Installations [Member]
 
 
 
Public Utility, Property, Plant and Equipment [Line Items]
 
 
 
Payments made under tax equity agreements
$ 362 
 
 
Summary Of Significant Accounting Policies (Schedule Of Estimated Useful Lives And Balances Of Utility's Property, Plant And Equipment) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2013
Electricity generating facilities [Member]
Utility [Member]
Dec. 31, 2012
Electricity generating facilities [Member]
Utility [Member]
Dec. 31, 2013
Electricity generating facilities [Member]
Utility [Member]
Minimum [Member]
Dec. 31, 2013
Electricity generating facilities [Member]
Utility [Member]
Maximum [Member]
Dec. 31, 2013
Electricity distribution facilities [Member]
Utility [Member]
Dec. 31, 2012
Electricity distribution facilities [Member]
Utility [Member]
Dec. 31, 2013
Electricity distribution facilities [Member]
Utility [Member]
Minimum [Member]
Dec. 31, 2013
Electricity distribution facilities [Member]
Utility [Member]
Maximum [Member]
Dec. 31, 2013
Electricity transmission [Member]
Utility [Member]
Dec. 31, 2012
Electricity transmission [Member]
Utility [Member]
Dec. 31, 2013
Electricity transmission [Member]
Utility [Member]
Minimum [Member]
Dec. 31, 2013
Electricity transmission [Member]
Utility [Member]
Maximum [Member]
Dec. 31, 2013
Natural gas distribution facilities [Member]
Utility [Member]
Dec. 31, 2012
Natural gas distribution facilities [Member]
Utility [Member]
Dec. 31, 2013
Natural gas distribution facilities [Member]
Utility [Member]
Minimum [Member]
Dec. 31, 2013
Natural gas distribution facilities [Member]
Utility [Member]
Maximum [Member]
Dec. 31, 2013
Natural gas transportation and storage [Member]
Utility [Member]
Dec. 31, 2012
Natural gas transportation and storage [Member]
Utility [Member]
Dec. 31, 2013
Natural gas transportation and storage [Member]
Utility [Member]
Minimum [Member]
Dec. 31, 2013
Natural gas transportation and storage [Member]
Utility [Member]
Maximum [Member]
Dec. 31, 2013
Construction Work In Progress [Member]
Utility [Member]
Dec. 31, 2012
Construction Work In Progress [Member]
Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total property, plant, and equipment
$ 59,094 
$ 54,166 
$ 9,116 1
$ 8,253 1
 
 
$ 25,333 
$ 23,767 
 
 
$ 8,429 
$ 7,681 
 
 
$ 9,117 
$ 8,257 
 
 
$ 5,265 
$ 4,314 
 
 
$ 1,834 
$ 1,894 
Accumulated depreciation
(17,843)
(16,643)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net property, plant, and equipment
$ 41,251 
$ 37,523 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, Plant and Equipment, Useful Life
 
 
 
 
20 years 
100 years 
 
 
10 years 
55 years 
 
 
10 years 
70 years 
 
 
20 years 
53 years 
 
 
5 years 
65 years 
 
 
Summary Of Significant Accounting Policies (Schedule Of Changes In Asset Retirement Obligations) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Summary Of Significant Accounting Policies [Abstract]
 
 
ARO liability at December 31
$ 2,919 
$ 1,609 
Revision in estimated cash flows
596 
1,301 
Accretion
130 
101 
Liabilities settled
(107)
(92)
ARO liability at December 31
$ 3,538 
$ 2,919 
New and Significant Accounting Policies (Reclassifications Out of Accumulated Other Comprehensived Income) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance
$ (101)
 
 
Gain on investments
38 
4 
0 
Total other comprehensive income (loss)
151 
112 
(11)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance
50 
(101)
 
Net actuarial loss tax
80 
72 
9 
Gain on investments tax
26 
3 
0 
Amounts Reclassified From Other Comprehensive Income [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Transfer to regulatory account
(76)
 
 
Amortization of prior service cost
25 
 
 
Amortization of net actuarial loss
69 
 
 
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Unrecognized net actuarial loss
1,214 
 
 
Transfer to regulatory account
(1,119)
 
 
Gain on investments
38 
 
 
Other Benefits [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance
(77)
 
 
Unrecognized net actuarial loss
2 
 
 
Amortization of prior service cost
23 
25 
27 
Amortization of net actuarial loss
6 
6 
4 
Total other comprehensive income (loss)
92 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance
15 
(77)
 
Other Benefits [Member] |
Amounts Reclassified From Other Comprehensive Income [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Transfer to regulatory account
0 
 
 
Amortization of prior service cost
13 
 
 
Amortization of net actuarial loss
3 
 
 
Net actuarial loss tax
3 
 
 
Transfer To Regulatory Account Tax
0 
 
 
Amortization of prior service cost tax
10 
 
 
Other Benefits [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Unrecognized net actuarial loss
45 
 
 
Transfer to regulatory account
31 
 
 
Gain on investments
0 
 
 
Net actuarial loss tax
35 
 
 
Transfer To Regulatory Account Tax
22 
 
 
Gain on investments tax
0 
 
 
Other Investments [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance
4 
 
 
Total other comprehensive income (loss)
38 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance
42 
 
 
Other Investments [Member] |
Amounts Reclassified From Other Comprehensive Income [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Transfer to regulatory account
0 
 
 
Amortization of prior service cost
0 
 
 
Amortization of net actuarial loss
0 
 
 
Net actuarial loss tax
0 
 
 
Transfer To Regulatory Account Tax
0 
 
 
Amortization of prior service cost tax
0 
 
 
Other Investments [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Unrecognized net actuarial loss
0 
 
 
Transfer to regulatory account
0 
 
 
Gain on investments
38 
 
 
Net actuarial loss tax
0 
 
 
Transfer To Regulatory Account Tax
0 
 
 
Gain on investments tax
26 
 
 
Pension [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance
(28)
 
 
Total other comprehensive income (loss)
21 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance
(7)
 
 
Pension [Member] |
Amounts Reclassified From Other Comprehensive Income [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Transfer to regulatory account
(76)
 
 
Amortization of prior service cost
12 
 
 
Amortization of net actuarial loss
66 
 
 
Net actuarial loss tax
45 
 
 
Transfer To Regulatory Account Tax
54 
 
 
Amortization of prior service cost tax
8 
 
 
Pension [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
Accumulated Other Comprehensive Income Loss [Line Items]
 
 
 
Unrecognized net actuarial loss
1,169 
 
 
Transfer to regulatory account
(1,150)
 
 
Gain on investments
0 
 
 
Net actuarial loss tax
804 
 
 
Transfer To Regulatory Account Tax
790 
 
 
Gain on investments tax
$ 0 
 
 
Regulatory Assets, Liabilities, And Balancing Accounts (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Regulatory Assets [Line Items]
 
Deferred income taxes regulatory asset recovery minimum (years)
1 year 
Deferred income taxes regulatory asset recovery maximum (years)
45 years 
Utility retained generation asset costs
$ 1,200 
Weighted average remaining life of Utility retained generation assets (years)
11 years 
Environmental compliance costs regulatory asset recovery (years)
32 years 
Price risk management regulatory assets recovery (years)
9 years 
Expected recovery of electromechanical meters (years)
4 years 
Recovery of costs related to debt reacquired or redeemed prior to maturity (years)
13 years 
Period of time expected to receive authorized rate adjustments (months)
12 months 
Period of time exceeded for regulatory balancing accounts to be recorded in other noncurrent assets (months)
12 months 
Period Of Time Expected To Refund Regulatory Liabilities To Customers
12 months 
Period Of Time Expected To Incur Public Purpose Program Costs Minimum
12 months 
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
$ 4,913 1
$ 6,809 1
Pension Plans Defined Benefit [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
1,444 1 2 3
3,275 1 2 4
Deferred Income Taxes [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
1,835 1 2
1,627 1 2
Utility Retained Generation [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
503 1 5
552 1 5
Environmental Compliance Costs [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
628 1 2 6 7 8
604 1 2 6 7 8
Price Risk Management [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
106 1 2 6 7 8
210 1 2 6 7 8 9
Electromechanical meters [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
135 1 10
194 1 10
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
135 1 2 8 9
141 1 2 8 9
Other Regulatory Assets ( Liabilities) [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total long-term regulatory assets
$ 127 1
$ 206 1
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Regulatory Liabilities [Line Items]
 
 
Total long-term regulatory liabilities
$ 5,660 
$ 5,088 
Cost Of Removal Obligation [Member]
 
 
Regulatory Liabilities [Line Items]
 
 
Total long-term regulatory liabilities
3,844 1
3,625 1
Recoveries In Excess Of ARO [Member]
 
 
Regulatory Liabilities [Line Items]
 
 
Total long-term regulatory liabilities
748 2
620 2
Public Purpose Programs [Member]
 
 
Regulatory Liabilities [Line Items]
 
 
Total long-term regulatory liabilities
587 3
590 3
Other Regulatory Assets ( Liabilities) [Member]
 
 
Regulatory Liabilities [Line Items]
 
 
Total long-term regulatory liabilities
$ 481 
$ 253 
Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Regulatory Balancing Accounts Receivable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
$ 1,124 
$ 936 
Public Purpose Programs [Member] |
Regulatory Balancing Accounts Receivable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
56 
48 
Regulatory Balancing Accounts Payable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
1,008 
634 
Electric Distribution [Member] |
Regulatory Balancing Accounts Receivable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
102 
219 
Utility Generation [Member] |
Regulatory Balancing Accounts Receivable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
57 
117 
Public Purpose Programs [Member] |
Regulatory Balancing Accounts Payable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
171 
131 
Gas Distribution [Member] |
Regulatory Balancing Accounts Receivable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
70 
44 
Energy Procurement [Member] |
Regulatory Balancing Accounts Receivable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
410 
193 
Energy Procurement [Member] |
Regulatory Balancing Accounts Payable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
298 
116 
Other [Member] |
Regulatory Balancing Accounts Receivable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
429 
315 
Other [Member] |
Regulatory Balancing Accounts Payable [Member]
 
 
Regulatory Assets [Line Items]
 
 
Total regulatory balancing accounts
$ 539 
$ 387 
Debt (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Debt [Line Items]
 
Interest including LIBOR on credit facilities
Borrowings under the revolving credit facilities (other than swingline loans) bear interest based, at PG&E Corporation?s and the Utility?s election, on (1) a London Interbank Offered Rate plus an applicable margin or (2) the base rate plus an applicable margin. The base rate will equal the higher of the following: the administrative agent?s announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods. 
Debt covenant ratio of total consolidated debt to total consolidated capitalization percentage
65.00% 
Ownership requirement percentage
80.00% 
Required ownership of voting capital stock
70.00% 
Commercial paper, maturities (days)
365 days 
Commercial paper average yield
0.26% 
Interest including LIBOR on Floating Rate Senior Notes
For the years ended December 31, 2013 and 2012 the average interest rate on the Floating Rate Senior Notes was 0.92% and 0.94%, respectivley. 
Utility [Member]
 
Debt [Line Items]
 
Line of credit facility, maximum borrowing capacity
$ 3,000 1
Right to increase commitments
500 
Line of Credit Facility, Expiration Date
Apr. 30, 2018 
Commercial Paper [Member]
 
Debt [Line Items]
 
Average outstanding borrowings
542 
Maximum outstanding balance
1,100 
Pg E Corporation [Member]
 
Debt [Line Items]
 
Average outstanding borrowings
214 
Maximum outstanding balance
260 
Line of credit facility, maximum borrowing capacity
300 2
Right to increase commitments
100 
Line of Credit Facility, Expiration Date
Apr. 30, 2018 
Credit Facilities [Member]
 
Debt [Line Items]
 
Line of credit facility, maximum borrowing capacity
$ 3,300 
Debt (Schedule Of Long-Term Debt) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2013
Utility [Member]
Dec. 31, 2012
Utility [Member]
Dec. 31, 2013
Pg E Corporation [Member]
Dec. 31, 2012
Pg E Corporation [Member]
Dec. 31, 2013
Senior Notes, 5.75%, Due 2014 [Member]
Pg E Corporation [Member]
Dec. 31, 2012
Senior Notes, 5.75%, Due 2014 [Member]
Pg E Corporation [Member]
Dec. 31, 2013
Senior Notes, 6.25% Due 2013 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 6.25% Due 2013 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 4.80% Due 2014 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 4.80% Due 2014 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 5.625% Due 2017 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 5.625% Due 2017 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 8.25% Due 2018 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 8.25% Due 2018 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 3.50% Due 2020 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 3.50% Due 2020 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 4.25% Due 2021[Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 4.25% Due 2021[Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 3.25% Due 2021 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 3.25% Due 2021 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 2.45% Due 2022 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 2.45% Due 2022 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 3.25% Due 2023 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 3.25% Due 2023 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 3.85% Due 2023 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 3.85% Due 2023 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 6.05% Due 2034 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 6.05% Due 2034 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 5.80% Due 2037 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 5.80% Due 2037 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 6.35% Due 2038 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 6.35% Due 2038 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 6.25% Due 2039 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 6.25% Due 2039 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 5.40% Due 2040 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 5.40% Due 2040 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 4.50% Due 2041 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 4.50% Due 2041 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 4.45% Due 2042 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 4.45% Due 2042 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 3.75% Due 2042 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 3.75% Due 2042 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 4.60% Due 2043 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 4.60% Due 2043 [Member]
Utility [Member]
Dec. 31, 2013
Senior Notes, 5.125% Due 2043 [Member]
Utility [Member]
Dec. 31, 2012
Senior Notes, 5.125% Due 2043 [Member]
Utility [Member]
Dec. 31, 2013
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member]
Dec. 31, 2013
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member]
Utility [Member]
Dec. 31, 2012
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member]
Utility [Member]
Dec. 31, 2013
Pollution Control Bonds, Series 2004 A-D, 4.75%, Due 2023 [Member]
Utility [Member]
Dec. 31, 2012
Pollution Control Bonds, Series 2004 A-D, 4.75%, Due 2023 [Member]
Utility [Member]
Dec. 31, 2013
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member]
Dec. 31, 2013
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member]
Utility [Member]
Dec. 31, 2012
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member]
Utility [Member]
Debt [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior notes
 
 
 
 
$ 0 
$ 350 
$ 350 
$ 350 
$ 0 
$ 400 
$ 539 
$ 1,000 
$ 700 
$ 700 
$ 800 
$ 800 
$ 800 
$ 800 
$ 300 
$ 300 
$ 250 
$ 250 
$ 400 
$ 400 
$ 375 
$ 0 
$ 300 
$ 0 
$ 3,000 
$ 3,000 
$ 950 
$ 950 
$ 400 
$ 400 
$ 550 
$ 550 
$ 800 
$ 800 
$ 250 
$ 250 
$ 400 
$ 400 
$ 350 
$ 350 
$ 375 
$ 0 
$ 500 
$ 0 
 
 
 
 
 
 
 
 
Less: current portion
 
 
(539)
(400)
(350)
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unamortized discount, net of premium
 
 
(51)
(51)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total senior notes, net of current portion
 
 
11,449 
10,899 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pollution control bonds
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
614 1 2
614 1 2
345 3
345 3
 
309 4 5 6
309 4 5
Total pollution control bonds
 
 
1,268 
1,268 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total long-term debt, net of current portion
$ 12,717 
$ 12,517 
$ 12,717 
$ 12,167 
$ 0 
$ 349 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate on bonds, minimum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.01% 
 
 
 
 
0.01% 
 
 
Interest rate on bonds, maximum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.04% 
 
 
 
 
0.02% 
 
 
Debt (Schedule Of Long-Term Debt Repayments) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Debt [Line Items]
 
Total consolidated long-term debt
$ 13,657 
Utility [Member]
 
Debt [Line Items]
 
Average fixed interest rate
5.29% 
Fixed rate obligations
12,384 
Variable interest rate as of December 31, 2013
0.02% 
Variable rate obligations
923 1
Pg E Corporation [Member]
 
Debt [Line Items]
 
Average fixed interest rate
5.75% 
Fixed rate obligations
350 
2014 [Member]
 
Debt [Line Items]
 
Total consolidated long-term debt
889 
2014 [Member] |
Utility [Member]
 
Debt [Line Items]
 
Average fixed interest rate
4.80% 
Fixed rate obligations
539 
2014 [Member] |
Pg E Corporation [Member]
 
Debt [Line Items]
 
Average fixed interest rate
5.75% 
Fixed rate obligations
350 
2015 [Member]
 
Debt [Line Items]
 
Total consolidated long-term debt
0 
2015 [Member] |
Pacific Gas And Electric Company [Member]
 
Debt [Line Items]
 
Average fixed interest rate
0.00% 
Fixed rate obligations
0 
2015 [Member] |
Utility [Member]
 
Debt [Line Items]
 
Average fixed interest rate
0.00% 
Fixed rate obligations
0 
Variable interest rate as of December 31, 2013
0.00% 
Variable rate obligations
0 
2016 [Member]
 
Debt [Line Items]
 
Total consolidated long-term debt
309 
2016 [Member] |
Utility [Member]
 
Debt [Line Items]
 
Variable interest rate as of December 31, 2013
0.02% 
Variable rate obligations
309 1
2017 [Member]
 
Debt [Line Items]
 
Total consolidated long-term debt
700 
2017 [Member] |
Utility [Member]
 
Debt [Line Items]
 
Average fixed interest rate
5.63% 
Fixed rate obligations
700 
2018 [Member] |
Utility [Member]
 
Debt [Line Items]
 
Average fixed interest rate
8.25% 
Fixed rate obligations
800 
Variable interest rate as of December 31, 2013
0.02% 
Variable rate obligations
614 1
Total consolidated long-term debt
1,414 
Thereafter [Member]
 
Debt [Line Items]
 
Total consolidated long-term debt
10,345 
Thereafter [Member] |
Utility [Member]
 
Debt [Line Items]
 
Average fixed interest rate
5.06% 
Fixed rate obligations
$ 10,345 
Debt (Schedule Of Line Of Credit) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Utility [Member]
 
Debt [Line Items]
 
Expiration date for credit agreement
Apr. 30, 2018 
Facility Limit
$ 3,000 1
Letters of Credit outstanding
79 
Borrowings
0 
Commercial Paper
914 2
Facility Availability
2,007 2
Letters of credit, sublimit
1,000 
Swingline loans, sublimit
300 
Swingline loan repay term (days)
7 days 
Pg E Corporation [Member]
 
Debt [Line Items]
 
Expiration date for credit agreement
Apr. 30, 2018 
Facility Limit
300 3
Letters of Credit outstanding
0 
Borrowings
260 
Commercial Paper
0 
Facility Availability
40 
Letters of credit, sublimit
100 
Swingline loans, sublimit
100 
Swingline loan repay term (days)
7 days 
Credit Facilities [Member]
 
Debt [Line Items]
 
Facility Limit
3,300 
Letters of Credit outstanding
79 
Borrowings
260 
Commercial Paper
914 
Facility Availability
$ 2,047 
Common Stock And Share-Based Compensation (Narrative) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
May 2, 2013
Feb. 28, 2013
Dec. 31, 2012
Common stock, shares outstanding
456,670,424 
 
 
 
 
430,718,293 
Equity distribution agreement amount
$ 395 
 
 
$ 400 
 
 
Ability to issuance of additional common stock under equity distribution agreement
5 
 
 
 
 
 
Dividend per share
$ 0.455 
$ 0.455 
$ 0.455 
 
$ 0.455 
 
Debt covenant ratio of total consolidated debt to total consolidated capitalization percentage
65.00% 
 
 
 
 
 
Retained earnings maintained as equity
7,400 
 
 
 
 
 
Percentage of equity for capital structure to be maintained
52.00% 
 
 
 
 
 
Fees and Commissions
4 
 
 
 
 
 
Common stock
9,550 
 
 
 
 
8,428 
Equity Contract [Member]
 
 
 
 
 
 
Common stock shares issued
11,000,000 
 
 
 
 
 
Common stock
455 
 
 
 
 
 
Underwritten Public Offering [Member]
 
 
 
 
 
 
Common stock shares issued
7,000,000 
 
 
 
 
 
Common stock
300 
 
 
 
 
 
Four Zero One K Plan D R S P P Shared Based Compensation Plans [Member]
 
 
 
 
 
 
Common stock shares issued
8,000,000 
 
 
 
 
 
Common stock
290 
 
 
 
 
 
May 2, 2013 Equity Contract [Member]
 
 
 
 
 
 
Fees and Commissions
3 
 
 
 
 
 
Utility [Member]
 
 
 
 
 
 
Net restricted assets for revolving credit facility ratio requirement
7,700 
 
 
 
 
 
Net restricted assets for equity component requirement
14,600 
 
 
 
 
 
Restricted reinvested earnings
$ 493 
 
 
 
 
 
Common Stock And Share-Based Compensation (Long-Term Incentive Plan) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Number of shares issued for LTIP, maximum
12,000,000 
 
 
Shares available for LTIP award
3,310,474 
 
 
Total Compensation Expense (pre-tax)
$ 64 
$ 57 
$ 26 
Total Compensation Expense (after-tax)
38 
34 
16 
Restricted Stock Units [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Total Compensation Expense (pre-tax)
36 
31 
23 
Performance Shares, Equity Awards [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Total Compensation Expense (pre-tax)
28 
26 
16 
Performance Shares, Liability Awards [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Total Compensation Expense (pre-tax)
$ 0 
$ 0 
$ (13)
Common Stock And Share-Based Compensation (Restricted Stock Units) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Common Stock And Share-Based Compensation [Abstract]
 
 
 
Restricted stock units terms, percentage of shares to vest
20.00% 
 
 
Restricted stock units terms, percentage of shares to vest, remaining percentage
40.00% 
 
 
Weighted average grant-date fair value of RSU's
$ 42.92 
$ 42.17 
$ 45.1 
Total fair value
$ 30 
$ 18 
$ 11 
Total unrecognized compensation costs
$ 50 
 
 
Remaining weighted average period, Years
2 years 2 months 0 days 
 
 
Nonvested at January 1, Number of Restricted Stock Units
2,069,291 
 
 
Granted, Number of Restricted Stock Units
993,115 
 
 
Vested, Number of Restricted Stock Units
(719,071)
 
 
Forfeited, Number of Restricted Stock Units
(43,314)
 
 
Nonvested at December 31, Number of Restricted Stock Units
2,300,021 
2,069,291 
 
Nonvested at January 1, Weighted Average Grant-Date Fair Value
$ 42.52 
 
 
Granted, Weighted Average Grant Date Fair Value
$ 42.92 
 
 
Vested, Weighted Average Grant Date Fair Value
$ 41.03 
 
 
Forfeited, Weighted Average Grant Date Fair Value
$ 42.68 
 
 
Nonvested at December 31, Weighted Average Grant-Date Fair Value
$ 43.16 
$ 42.52 
 
Common Stock And Share-Based Compensation (Performance Shares) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Performance period for vesting of performance shares, years
3 years 
 
 
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized
$ 29 
 
 
Weighted-average period (years)
1 year 3 months 0 days 
 
 
Performance Shares, Equity Awards [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Nonvested at January 1, Number of Performance Shares
1,497,473 
 
 
Granted, Number of Performance Shares
911,620 
 
 
Vested, Number of Performance Shares
0 
 
 
Forfeited, Number of Performance Shares
(617,773)1
 
 
Nonvested at December 31, Number of Performance Shares
1,791,320 
1,497,473 
 
Nonvested at January 1, Weighted Average Exercise Price
$ 38.15 
 
 
Granted, Weighted Average Exercise Price
33.45 
41.93 
33.91 
Vested, Weighted Average Exercise Price
0 
 
 
Forfeited, Weighted Average Exercise Price
34.22 1
 
 
Nonvested at December 31, Weighted Average Exercise Price
$ 37.85 
$ 38.15 
 
Preferred Stock (Narrative) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Preferred Stock [Line Items]
 
 
 
Preferred stock dividends
$ 14 
$ 14 
$ 14 
$25 Par Value [Member] |
Utility [Member]
 
 
 
Preferred Stock [Line Items]
 
 
 
Preferred stock, par value
$ 25 
 
 
Preferred stock, shares issued
75,000,000 
 
 
$100 Par Value [Member] |
Utility [Member]
 
 
 
Preferred Stock [Line Items]
 
 
 
Preferred stock, par value
$ 100.00 
 
 
Preferred stock, shares issued
10,000,000 
 
 
$100 Par Value [Member] |
PG&E Corporation [Member]
 
 
 
Preferred Stock [Line Items]
 
 
 
Preferred stock, par value
$ 100.00 
 
 
Preferred stock, shares issued
5,000,000 
 
 
No Par Value [Member] |
PG&E Corporation [Member]
 
 
 
Preferred Stock [Line Items]
 
 
 
Preferred stock, shares authorized
80,000,000 
 
 
Nonredeemable Preferred Stock [Member]
 
 
 
Preferred Stock [Line Items]
 
 
 
Preferred stock dividends per share, low range
$ 1.25 
 
 
Preferred stock dividends per share, high range
$ 1.5 
 
 
Nonredeemable Preferred Stock [Member] |
$25 Par Value [Member]
 
 
 
Preferred Stock [Line Items]
 
 
 
Preferred stock, par value
$ 25 
 
 
Preferred stock, shares authorized
5,784,825 
 
 
Redeemable Preferred Stock [Member]
 
 
 
Preferred Stock [Line Items]
 
 
 
Preferred stock dividends per share, low range
$ 1.09 
 
 
Preferred stock dividends per share, high range
$ 1.25 
 
 
Redeemable Preferred Stock [Member] |
Utility [Member]
 
 
 
Preferred Stock [Line Items]
 
 
 
Preferred stock, shares issued
4,534,958,000,000 
 
 
Preferred Stock (Summary Of Issued And Outstanding Preferred Stock) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Preferred Stock [Line Items]
 
 
Total Preferred Stock
$ 0 
$ 0 
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Total Preferred Stock
258 
 
Nonredeemable Preferred Stock [Member] |
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Nonredeemable preferred stock, value
145 
 
Redeemable Preferred Stock [Member] |
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Total Preferred Stock
4,534,958,000,000 
 
Redeemable preferred stock, value
113 
 
5.50% Series [Member] |
Nonredeemable Preferred Stock [Member] |
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Total Preferred Stock
1,173,163,000,000 
 
Nonredeemable preferred stock, value
30 
 
6.00% Series [Member] |
Nonredeemable Preferred Stock [Member] |
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Total Preferred Stock
4,211,662,000,000 
 
Nonredeemable preferred stock, value
105 
 
4.36% Series [Member] |
Redeemable Preferred Stock [Member] |
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Total Preferred Stock
418,291,000,000 
 
Redemption Price
$ 25.75 
 
Redeemable preferred stock, value
11 
 
4.50% Series [Member] |
Redeemable Preferred Stock [Member] |
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Total Preferred Stock
611,142,000,000 
 
Redemption Price
$ 26 
 
Redeemable preferred stock, value
15 
 
4.80% Series [Member] |
Redeemable Preferred Stock [Member] |
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Total Preferred Stock
793,031,000,000 
 
Redemption Price
$ 27.25 
 
Redeemable preferred stock, value
20 
 
5.00% Series [Member] |
Nonredeemable Preferred Stock [Member] |
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Total Preferred Stock
400,000,000,000 
 
Nonredeemable preferred stock, value
10 
 
5.00% Series [Member] |
Redeemable Preferred Stock [Member] |
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Total Preferred Stock
1,778,172,000,000 
 
Redemption Price
$ 26.75 
 
Redeemable preferred stock, value
44 
 
5.00% Series A [Member] |
Redeemable Preferred Stock [Member] |
Utility [Member]
 
 
Preferred Stock [Line Items]
 
 
Total Preferred Stock
934,322,000,000 
 
Redemption Price
$ 26.75 
 
Redeemable preferred stock, value
$ 23 
 
Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Shares Of Common Stock Outstanding For Calculating Diluted EPS) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Earnings Per Share [Abstract]
 
 
 
Income available for common shareholders
$ 814 
$ 816 
$ 844 
Weighted average common shares outstanding, basic
444 
424 
401 
Add Incremental Shares From Assumed conversions:
 
 
 
Employee share-based compensation
1 
1 
1 
Weighted average common shares outstanding, diluted
445 
425 
402 
Net earnings per common share, basic
$ 1.83 
$ 1.92 
$ 2.1 
Total earnings per common share, diluted
$ 1.83 
$ 1.92 
$ 2.1 
Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Shares Of Common Stock Outstanding For Calculating Basic EPS) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Earnings Per Share Basic And Diluted [Line Items]
 
 
 
Income Available for Common Shareholders
$ 814 
$ 816 
 
Weighted average common shares outstanding, basic
444 
424 
401 
Employee share-based compensation
1 
1 
1 
Total
$ 1.83 
$ 1.92 
$ 2.1 
Income Taxes (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year
 
$ 29 
Decrease of unrecognized tax benefit
350 
 
Aggregate amount of federal capital loss carryforwards
 
3,300 
Tax credit carryforwards, expiration amount
 
68 
Loss carryforwards, charitable contribution
 
121 
Tax benefit from employee stock plans
 
$ 15 
Tax Credit Carryforward Expiration Date [Minimum]
 
Dec. 31, 2029 
Tax Credit Carryforward Expiration Date [Maximum]
 
Dec. 31, 2033 
Charitable Contribution Carryforward Expiration Date [Minimum]
 
Dec. 31, 2014 
Charitable Contribution Carryforward Expiration Date [Maximum]
 
Dec. 31, 2018 
Income Taxes (Schedule Of Income Tax Provision) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Current, Federal
 
 
 
 
 
 
 
 
$ (218)
$ (74)
$ (77)
Current, State
 
 
 
 
 
 
 
 
(26)
33 
152 
Deferred, Federal
 
 
 
 
 
 
 
 
552 
374 
504 
Deferred, State
 
 
 
 
 
 
 
 
(35)
(92)
(135)
Tax credits
 
 
 
 
 
 
 
 
(5)
4 
4 
Income Tax Provision
 
 
 
 
 
 
 
 
268 
237 
440 
Pacific Gas And Electric Company [Member]
 
 
 
 
 
 
 
 
 
 
 
Income Tax Provision
 
 
 
 
 
 
 
 
326 
298 
480 
Utility [Member]
 
 
 
 
 
 
 
 
 
 
 
Current, Federal
 
 
 
 
 
 
 
 
(222)
(52)
(83)
Current, State
 
 
 
 
 
 
 
 
(23)
41 
161 
Deferred, Federal
 
 
 
 
 
 
 
 
604 
404 
534 
Deferred, State
 
 
 
 
 
 
 
 
(28)
(91)
(128)
Tax credits
 
 
 
 
 
 
 
 
(5)
(4)
(4)
Income Tax Provision
$ 65 
$ (20)
$ 160 
$ 121 
$ 13 
$ 340 
$ 227 
$ 231 
$ 326 
$ 298 
$ 480 
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Pacific Gas And Electric Company [Member]
 
 
Customer advances for construction
$ 90 
$ 101 
Reserve for damages
161 
175 
Environmental reserve
152 
97 
Compensation
167 
229 
Net operating loss carryforward
890 
938 
GHG Allowances
108 
34 
Other
135 
34 
Total deferred income tax assets
1,703 
1,804 
Regulatory balancing accounts
261 
256 
Property related basis differences
8,048 
7,449 
Income tax regulatory asset
748 
663 
Other
151 
173 
Total deferred income tax liabilities
9,208 
8,541 
Total net deferred income tax liabilities
7,505 
6,737 
Included in current liabilities (assets)
(318)
(11)
Included in noncurrent liabilities
7,823 
6,748 
Utility [Member]
 
 
Customer advances for construction
90 
101 
Reserve for damages
161 
175 
Environmental reserve
152 
97 
Compensation
102 
179 
Net operating loss carryforward
670 
736 
GHG Allowances
108 
34 
Other
128 
221 
Total deferred income tax assets
1,411 
1,543 
Regulatory balancing accounts
261 
256 
Property related basis differences
8,038 
7,447 
Income tax regulatory asset
748 
663 
Other
86 
99 
Total deferred income tax liabilities
9,133 
8,465 
Total net deferred income tax liabilities
7,722 
6,922 
Included in current liabilities (assets)
(320)
(17)
Included in noncurrent liabilities
$ 8,042 
$ 6,939 
Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Pacific Gas And Electric Company [Member]
 
 
 
Federal statutory income tax rate
35.00% 
35.00% 
35.00% 
State income tax (net of federal benefit)
(3.10%)
(3.90%)
1.10% 
Effect of regulatory treatment of fixed asset differences
(4.20%)
(4.10%)
(4.40%)
Tax credits
(0.40%)
(0.60%)
(0.50%)
Benefit of loss carryback
(1.10%)
(0.70%)
(1.90%)
Non deductible penalties
0.80% 
0.60% 
6.50% 
Other, net
(2.20%)
(3.80%)
(1.50%)
Effective tax rate
24.80% 
22.50% 
34.30% 
Utility [Member]
 
 
 
Federal statutory income tax rate
35.00% 
35.00% 
35.00% 
State income tax (net of federal benefit)
(2.20%)
(3.00%)
1.60% 
Effect of regulatory treatment of fixed asset differences
(3.80%)
(3.90%)
(4.20%)
Tax credits
(0.40%)
(0.60%)
(0.50%)
Benefit of loss carryback
(1.00%)
(0.40%)
(2.10%)
Non deductible penalties
0.70% 
0.50% 
6.30% 
Other, net
(0.90%)
(0.80%)
0.10% 
Effective tax rate
27.40% 
26.80% 
36.20% 
Income Taxes (Schedule Of Change In Unrecognized Tax Benefits) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Pacific Gas And Electric Company [Member]
 
 
 
Balance at beginning of year
$ 581 
$ 506 
$ 714 
Additions for tax position taken during a prior year
12 
32 
2 
Reductions for tax position taken during a prior year
(6)
(13)
(198)
Additions for tax position taken during the current year
79 
67 
3 
Settlements
0 
(11)
(15)
Balance at end of year
666 
581 
506 
Utility [Member]
 
 
 
Balance at beginning of year
575 
503 
712 
Additions for tax position taken during a prior year
12 
26 
2 
Reductions for tax position taken during a prior year
(6)
(10)
(196)
Additions for tax position taken during the current year
79 
67 
0 
Settlements
0 
(11)
(15)
Balance at end of year
$ 660 
$ 575 
$ 503 
Derivatives And Hedging Activities (Volumes Of Outstanding Derivative Contracts) (Details)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Derivative [Line Items]
 
 
Derivatives expiration, lower
2019 years 
2018 years 
Derivatives expiration, higher
2022 years 
2023 years 
Forwards And Swaps [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Less Than 1 Year
243,213,288 1 2 3 4 5
329,466,510 1 2 3
Greater Than 1 Year but Less Than 3 Years
79,735,000 1 2 3 4 5
98,628,398 1 2 3
Greater Than 3 Years but Less Than 5 Years
8,892,500 1 2 3 4 5
5,490,000 1 2 3
Greater Than 5 Years
0 1 2 3 4 5 6
0 1 2 3 7
Forwards And Swaps [Member] |
Electricity [Member]
 
 
Derivative [Line Items]
 
 
Less Than 1 Year
2,537,023 1
2,537,023 1 8 9
Greater Than 1 Year but Less Than 3 Years
2,009,505 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
1,534,695 1 4 5 6
2,538,718 1 7
Options [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Less Than 1 Year
169,123,208 1
221,587,431 1
Greater Than 1 Year but Less Than 3 Years
87,689,708 1
216,279,767 1
Greater Than 3 Years but Less Than 5 Years
3,450,000 1
10,050,000 1
Greater Than 5 Years
0 1 4 5 6
0 1 7
Options [Member] |
Electricity [Member]
 
 
Derivative [Line Items]
 
 
Less Than 1 Year
 
0 1
Greater Than 1 Year but Less Than 3 Years
 
239,015 1
Greater Than 3 Years but Less Than 5 Years
 
239,233 1
Greater Than 5 Years
 
119,508 1 7
Congestion Revenue Rights [Member] |
Electricity [Member]
 
 
Derivative [Line Items]
 
 
Less Than 1 Year
73,510,440 1
74,198,690 1
Greater Than 1 Year but Less Than 3 Years
83,747,782 1
74,187,803 1
Greater Than 3 Years but Less Than 5 Years
63,718,517 1
74,240,147 1
Greater Than 5 Years
29,945,852 1 6
25,699,804 1 7
Derivatives And Hedging Activities (Outstanding Derivative Balances) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Other Current Assets [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Gross Derivative Balance
$ 42 
$ 48 
Cash Collateral
16 
36 
Total Derivative Balances
48 
59 
Derivative Liability Offsetting Derivative Asset
(10)
(25)
Other Noncurrent Assets [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Gross Derivative Balance
99 
99 
Cash Collateral
0 
0 
Total Derivative Balances
95 
88 
Derivative Liability Offsetting Derivative Asset
(4)
(11)
Other Current Liabilities [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Gross Derivative Balance
(122)
(255)
Cash Collateral
69 
115 
Total Derivative Balances
(43)
(115)
Derivative Asset Offsetting Derivative Liability
10 
25 
Other Noncurrent Liabilities [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Gross Derivative Balance
(110)
(221)
Cash Collateral
2 
14 
Total Derivative Balances
(104)
(196)
Derivative Asset Offsetting Derivative Liability
4 
11 
Gross Derivative Balance [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Gross Derivative Balance
(91)
(329)
Netting [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Netting
0 
0 
Cash Collatera [lMember]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Cash Collateral
87 
165 
Total Derivatve Balance [Member]
 
 
Derivatives And Hedging Activities [Line Items]
 
 
Total Derivative Balances
$ (4)
$ (164)
Derivatives And Hedging Activities (Gains And Losses On Derivative Instruments) (Details) (PGE Corporation And Utility [Member], USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
PGE Corporation And Utility [Member]
 
 
 
Unrealized (loss) gain - regulatory assets and liabilities
$ 238 1
$ 391 1
$ 21 1
Realized loss-cost of electricity
(178)2
(486)2
(558)2
Realized loss-cost of natural gas
(22)2
(38)2
(106)2
Total commodity risk instruments
$ 38 
$ (133)
$ (643)
Derivatives And Hedging Activities (Additional Cash Collateral The Utility Would Be Required To Post If Its Credit-Risk-Related Contingency Features Were Triggered) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Derivatives And Hedging Activities [Abstract]
 
 
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized
$ (79)
$ (266)
Related derivatives in an asset position
4 
59 
Collateral posting in the normal course of business related to these derivatives
65 
103 
Net position of derivative contracts/additional collateral posting requirements
$ (10)1
$ (104)1
Fair Value Measurements (Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Amount primarily related to deferred taxes on appreciation of investment value
$ 313 
$ 240 
Other investments
84 
 
Estimate Of Fair Value Fair Value Disclosure [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
226 
209 
Total assets
3,374 
3,030 
Total liabilities
147 
311 
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
226 
209 
Total assets
2,622 
2,241 
Total liabilities
20 
163 
Other investments
84 
 
Fair Value, Inputs, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
643 
708 
Total liabilities
75 
153 
Fair Value, Inputs, Level 3 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
107 
81 
Total liabilities
137 
160 
Netting [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
2 1
0 1
Total liabilities
(85)1
(165)1
Nuclear Decommissioning Trusts [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
38 
21 
U.S. equity securities
1,046 
940 
Non-U.S. equity securities
457 
379 
U.S. government and agency securities
760 
681 
Total assets
2,301 2
2,021 3
Nuclear Decommissioning Trusts [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
U.S. equity securities
11 
9 
U.S. government and agency securities
156 
139 
Municipal securities
25 
59 
Other fixed-income securities
162 
173 
Total assets
354 2
380 3
Nuclear Decommissioning Trusts [Member] |
Estimate Of Fair Value [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
38 
21 
U.S. equity securities
1,057 
949 
Non-U.S. equity securities
457 
379 
U.S. government and agency securities
916 
820 
Municipal securities
25 
59 
Other fixed-income securities
162 
173 
Total assets
2,655 2
2,401 3
Price Risk Management Instruments [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
2 
1 
Electric
2 
1 
Electric
19 
155 
Gas
1 
8 
Price Risk Management Instruments [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
32 
65 
Electric
27 
60 
Gas
5 
5 
Electric
72 
144 
Gas
3 
9 
Price Risk Management Instruments [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
107 
81 
Electric
107 
80 
Gas
0 
1 
Electric
137 
160 
Price Risk Management Instruments [Member] |
Netting [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
2 1
0 1
Electric
3 1
6 1
Gas
(1)1
(6)1
Electric
(84)1
(156)1
Gas
(1)1
(9)1
Price Risk Management Instruments [Member] |
Estimate Of Fair Value [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Total assets
143 
147 
Electric
139 
147 
Gas
4 
0 
Electric
144 
303 
Gas
3 
8 
Rabbi Trusts [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Other fixed-income securities
39 
30 
Life insurance contracts
70 
72 
Total assets
109 
102 
Rabbi Trusts [Member] |
Estimate Of Fair Value [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Other fixed-income securities
39 
30 
Life insurance contracts
70 
72 
Total assets
109 
102 
Long-Term Disability Trust [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
9 
10 
U.S. equity securities
0 
0 
Total assets
9 
10 
Long-Term Disability Trust [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
U.S. equity securities
14 
14 
Non-U.S. equity securities
12 
11 
Fixed-income securities
122 
136 
Total assets
148 
161 
Long-Term Disability Trust [Member] |
Estimate Of Fair Value [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Money market investments
9 
10 
U.S. equity securities
14 
14 
Non-U.S. equity securities
12 
11 
Fixed-income securities
122 
136 
Total assets
$ 157 
$ 171 
Fair Value Measurements (Level 3 Reconciliation) (Details) (Fair Value, Inputs, Level 3 [Member], Price Risk Management Instruments [Member], USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Fair Value, Inputs, Level 3 [Member] |
Price Risk Management Instruments [Member]
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
 
 
Liability balance as of January 1
$ (79)
$ (74)
Realized and unrealized gains (losses): Included in regulatory assets and liabilities or balancing accounts
49 1
(5)1
Liability balance as of December 31
$ (30)
$ (79)
Fair Value Measurements (Carrying Amount And Fair Value Of Financial Instruments) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Carrying Amount [Member]
 
 
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
 
 
Debt financial instrument
$ 350 
$ 349 
Carrying Amount [Member] |
Pacific Gas And Electric Company [Member]
 
 
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
 
 
Debt financial instrument
12,334 
11,645 
Estimate Of Fair Value [Member]
 
 
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
 
 
Debt financial instrument
354 
371 
Estimate Of Fair Value [Member] |
Pacific Gas And Electric Company [Member]
 
 
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
 
 
Debt financial instrument
$ 13,444 
$ 13,946 
Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Fair Value Measurements [Abstract]
 
Less than 1 year
$ 22 
1-5 years
519 
5-10 years
230 
More than 10 years
332 
Total maturities of debt securities
$ 1,103 
Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Fair Value Measurements [Abstract]
 
 
 
Proceeds from sales and maturities of nuclear decommissioning trust investments
$ 1,619 
$ 1,133 
$ 1,928 
Gross realized gains on sales of securities held as available-for-sale
94 
19 
43 
Gross realized losses on sales of securities held as available-for-sale
$ (13)
$ (17)
$ (30)
Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Congestion Revenue Rights [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Assets, Fair Value
$ 107 
$ 80 
Liabilities, Fair Value
32 
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]
 
 
Assets, Fair Value
0 
0 
Liabilities, Fair Value
$ 105 
$ 145 
Fair value measurement Valuation technique
Discounted cash flow 
Discounted cash flow 
Fair value measurement Unobservable Input
Forward prices 
Forward prices 
Minimum [Member] |
CRR Auction Prices [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Range
(6.47)1
(9.04)
Minimum [Member] |
Forward Prices [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Range
23.43 1
8.59 
Maximum [Member] |
CRR Auction Prices [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Range
12.04 1
55.15 
Maximum [Member] |
Forward Prices [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Range
51.75 1
62.9 
Employee Benefit Plans (Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Noncurrent liability
$ (1,601)
$ (3,575)
 
Accumulated benefit obligation
12,659 
13,778 
 
Decrease in other comprehensive income
 
(108)
11 
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets at January 1
1,758 
1,491 
 
Actual return on plan assets
64 
191 
 
Company contributions
145 
149 
 
Plan participant contribution
64 
55 
 
Benefits and expenses paid
(139)
(128)
 
Fair value of plan assets at December 31
1,892 
1,758 
1,491 
Projected benefit obligation at January 1
1,940 
1,885 
 
Service cost for benefits earned
53 
49 
 
Interest cost
74 
83 
91 
Actuarial gain
(415)
(23)
 
Plan amendments
0 
5 
 
Benefits and expenses paid
(123)
(119)
 
Federal subsidy on benefits paid
4 
5 
 
Projected benefit obligation at December 31
1,597 
1,940 
1,885 
Noncurrent liability
(57)1
(181)1
 
Accrued benefit cost
295 1
(181)1
 
Noncurrent asset
352 1
0 1
 
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets at January 1
12,141 
10,993 
 
Actual return on plan assets
673 
1,488 
 
Company contributions
323 
282 
 
Benefits and expenses paid
(610)
(622)
 
Fair value of plan assets at December 31
12,527 
12,141 
10,993 
Projected benefit obligation at January 1
15,541 2 3 4
14,000 
 
Service cost for benefits earned
468 
396 
 
Interest cost
627 
658 
660 
Actuarial gain
(1,950)
1,099 
 
Plan amendments
0 
9 
 
Transitional costs
1 
1 
 
Benefits and expenses paid
(610)
(622)
 
Projected benefit obligation at December 31
14,077 2
15,541 2 3 4
14,000 
Current liability
(6)
(6)
 
Noncurrent liability
(1,544)
(3,394)
 
Accrued benefit cost
(1,550)
(3,400)
 
Change In Benefit Obligation [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Plan participant contribution
$ 64 
$ 55 
 
Employee Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Amounts Reclassified From Other Comprehensive Income [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Amortization of prior service cost
$ 25 
 
 
Amortization of net actuarial loss
69 
 
 
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Service cost for benefits earned
53 
49 
42 
Interest cost
74 
83 
91 
Expected return on plan assets
(79)
(77)
(82)
Amortization of transition obligation
0 
24 
26 
Amortization of prior service cost
23 
25 
27 
Amortization of net actuarial loss
6 
6 
4 
Net periodic benefit cost
77 
110 
108 
Other Benefits [Member] |
Amounts Reclassified From Other Comprehensive Income [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Amortization of prior service cost
13 
 
 
Amortization of net actuarial loss
3 
 
 
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Service cost for benefits earned
468 
396 
320 
Interest cost
627 
658 
660 
Expected return on plan assets
(650)
(598)
(669)
Amortization of prior service cost
20 
20 
34 
Amortization of net actuarial loss
111 
123 
50 
Net periodic benefit cost
576 
599 
395 
Less: transfer to regulatory account
(238)1
(301)1
(139)1
Total
$ 338 
$ 298 
$ 256 
Employee Benefit Plans (Estimated Amortized Net Periodic Benefit For 2012) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Other Comprehensive Income Before Reclassifications [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Unrecognized net actuarial loss
$ 1,214 
Other Benefits [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Unrecognized prior service cost
23 
Unrecognized net actuarial loss
2 
Total
25 
Other Benefits [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Unrecognized net actuarial loss
45 
Pension Plans Defined Benefit [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Unrecognized prior service cost
20 
Unrecognized net actuarial loss
2 
Total
$ 22 
Employee Benefit Plans (Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost) (Details)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Discount rate
4.89% 
3.98% 
4.66% 
Average rate of future compensation increases
4.00% 
4.00% 
5.00% 
Expected return on plan assets
6.50% 
5.40% 
5.50% 
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Discount rate range
4.70-5.00 
3.75-4.08 
4.41-4.77 
Expected return on plan assets percentage range
3.50-6.70 
2.90-6.10 
4.40-5.50 
Employee Benefit Plans (Schedule Of Assumed Health Care Cost Trend) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Employee Benefit Plans [Abstract]
 
 
 
Effect on postretirement benefit obligation, One-Percentage-Point Increase
$ 86 
 
 
Effect on postretirement benefit obligation, One-Percentage-Point Decrease
(88)
 
 
Effect on service and interest cost, One-Percentage-Point Increase
9 
 
 
Effect on service and interest cost, One-Percentage-Point Decrease
$ (9)
 
 
Assumed health care cost trend rate
8.00% 
 
 
Ultimate trend rate
5.00% 
 
 
Year of ultimate trend rate
2020 
 
 
Assumed return
6.50% 
5.40% 
5.50% 
10 year actual rate of return
8.70% 
 
 
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used
494 
 
 
Employee Benefit Plans (Target Asset Allocation Percentages) (Details)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined benefit plan, target allocation percentage of assets, Total
100.00% 
100.00% 
100.00% 
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined benefit plan, target allocation percentage of assets, Total
100.00% 
100.00% 
100.00% 
Fixed Income Securities[Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Target Allocation Percentage of Assets, Other
59.00% 
60.00% 
50.00% 
Fixed Income Securities[Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Target Allocation Percentage of Assets, Other
57.00% 
57.00% 
47.00% 
Real Assets [member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Target Allocation Percentage of Assets, Other
8.00% 
8.00% 
8.00% 
Real Assets [member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Target Allocation Percentage of Assets, Other
10.00% 
10.00% 
10.00% 
Extended Fixed Income Securities [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Target Allocation Percentage of Assets, Other
0.00% 
0.00% 
0.00% 
Extended Fixed Income Securities [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Target Allocation Percentage of Assets, Other
3.00% 
3.00% 
3.00% 
Absolute Return [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Target Allocation Percentage of Assets, Other
3.00% 
4.00% 
4.00% 
Absolute Return [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Target Allocation Percentage of Assets, Other
5.00% 
5.00% 
5.00% 
Global Equity Securities [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Target Allocation Percentage of Assets, Other
30.00% 
28.00% 
38.00% 
Global Equity Securities [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Target Allocation Percentage of Assets, Other
25.00% 
25.00% 
35.00% 
Employee Benefit Plans (Schedule Of Fair Value Of Plan Assets) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
$ 14,288 
$ 13,767 
 
Total Fair Value Of Trust Other Net Assets
131 
132 
 
Notice To Redeem Investments days [maximum]
90 days 
 
 
Money Market Investments Net Asset Value Per Unit
$ 1 
 
 
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
1,895 
1,733 
 
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
12,393 
12,034 
 
Fair Value, Inputs, Level 1 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
362 
420 
 
Fair Value, Inputs, Level 1 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
3,203 
2,618 
 
Fair Value, Inputs, Level 2 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
1,440 
1,235 
 
Fair Value, Inputs, Level 2 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
7,467 
8,007 
 
Fair Value, Inputs, Level 3 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
93 
78 
54 
Fair Value, Inputs, Level 3 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
1,723 
1,409 
1,137 
Cash Equivalents [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
31 
77 
 
Cash Equivalents [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
70 
112 
 
Cash Equivalents [Member] |
Fair Value, Inputs, Level 1 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
31 
77 
 
Cash Equivalents [Member] |
Fair Value, Inputs, Level 1 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
70 
112 
 
Cash Equivalents [Member] |
Fair Value, Inputs, Level 2 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Cash Equivalents [Member] |
Fair Value, Inputs, Level 2 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Cash Equivalents [Member] |
Fair Value, Inputs, Level 3 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Cash Equivalents [Member] |
Fair Value, Inputs, Level 3 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Real Estate [Member] |
Fair Value, Inputs, Level 3 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
 
 
65 
U.S. Government And Agency Securities [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
124 
153 
 
U.S. Government And Agency Securities [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
1,600 
1,715 
 
U.S. Government And Agency Securities [Member] |
Fair Value, Inputs, Level 1 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
119 
148 
 
U.S. Government And Agency Securities [Member] |
Fair Value, Inputs, Level 1 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
1,281 
1,576 
 
U.S. Government And Agency Securities [Member] |
Fair Value, Inputs, Level 2 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
5 
5 
 
U.S. Government And Agency Securities [Member] |
Fair Value, Inputs, Level 2 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
319 
139 
 
U.S. Government And Agency Securities [Member] |
Fair Value, Inputs, Level 3 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
U.S. Government And Agency Securities [Member] |
Fair Value, Inputs, Level 3 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Residential Real Estate [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
105 
96 
 
Residential Real Estate [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
1,106 
810 
 
Residential Real Estate [Member] |
Fair Value, Inputs, Level 1 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
67 
68 
 
Residential Real Estate [Member] |
Fair Value, Inputs, Level 1 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
562 
525 
 
Residential Real Estate [Member] |
Fair Value, Inputs, Level 2 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Residential Real Estate [Member] |
Fair Value, Inputs, Level 2 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Residential Real Estate [Member] |
Fair Value, Inputs, Level 3 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
38 
28 
 
Residential Real Estate [Member] |
Fair Value, Inputs, Level 3 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
544 
285 
 
Corporate Debt Securities [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
900 
805 
 
Corporate Debt Securities [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
4,856 
4,889 
 
Corporate Debt Securities [Member] |
Fair Value, Inputs, Level 1 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
4 
9 
 
Corporate Debt Securities [Member] |
Fair Value, Inputs, Level 1 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
1 
3 
 
Corporate Debt Securities [Member] |
Fair Value, Inputs, Level 2 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
894 
795 
 
Corporate Debt Securities [Member] |
Fair Value, Inputs, Level 2 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
4,230 
4,275 
 
Corporate Debt Securities [Member] |
Fair Value, Inputs, Level 3 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
2 
1 
 
Corporate Debt Securities [Member] |
Fair Value, Inputs, Level 3 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
625 
611 
 
Other Fixed Income Securities [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
51 
38 
 
Other Fixed Income Securities [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
721 
576 
 
Other Fixed Income Securities [Member] |
Fair Value, Inputs, Level 1 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
14 
0 
 
Other Fixed Income Securities [Member] |
Fair Value, Inputs, Level 1 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
166 
0 
 
Other Fixed Income Securities [Member] |
Fair Value, Inputs, Level 2 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
37 
38 
 
Other Fixed Income Securities [Member] |
Fair Value, Inputs, Level 2 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
555 
576 
 
Other Fixed Income Securities [Member] |
Fair Value, Inputs, Level 3 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Other Fixed Income Securities [Member] |
Fair Value, Inputs, Level 3 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Global Equity Securities [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
631 
515 
 
Global Equity Securities [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
3,486 
3,419 
 
Global Equity Securities [Member] |
Fair Value, Inputs, Level 1 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
127 
118 
 
Global Equity Securities [Member] |
Fair Value, Inputs, Level 1 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
1,123 
402 
 
Global Equity Securities [Member] |
Fair Value, Inputs, Level 2 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
504 
397 
 
Global Equity Securities [Member] |
Fair Value, Inputs, Level 2 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
2,363 
3,017 
 
Global Equity Securities [Member] |
Fair Value, Inputs, Level 3 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Global Equity Securities [Member] |
Fair Value, Inputs, Level 3 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Absolute Return [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
53 
49 
 
Absolute Return [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
554 
513 
 
Absolute Return [Member] |
Fair Value, Inputs, Level 1 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Absolute Return [Member] |
Fair Value, Inputs, Level 1 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Absolute Return [Member] |
Fair Value, Inputs, Level 2 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Absolute Return [Member] |
Fair Value, Inputs, Level 2 [Member] |
Pension Plans Defined Benefit [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
0 
0 
 
Absolute Return [Member] |
Fair Value, Inputs, Level 3 [Member] |
Other Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Total fair value of plan assets for pension and other benefit plans
$ 53 
$ 49 
 
Employee Benefit Plans (Schedule Of Level 3 Reconciliation) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of December 31
$ 14,288 
$ 13,767 
Other Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of December 31
1,895 
1,733 
Other Benefits [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of December 31
362 
420 
Other Benefits [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of December 31
1,440 
1,235 
Other Benefits [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of January 1
78 
54 
Relating to assets still held at the reporting date
7 
3 
Relating to assets sold during the period
0 
0 
Purchases
34 
22 
Settlements
(26)
(1)
Balance as of December 31
93 
78 
Pension Plans Defined Benefit [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of December 31
12,393 
12,034 
Pension Plans Defined Benefit [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of December 31
3,203 
2,618 
Pension Plans Defined Benefit [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of December 31
7,467 
8,007 
Pension Plans Defined Benefit [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of January 1
1,409 
1,137 
Relating to assets still held at the reporting date
87 
66 
Relating to assets sold during the period
(1)
1 
Purchases
372 
220 
Settlements
(146)
(13)
Balance as of December 31
1,723 
1,409 
Real Estate [Member] |
Other Benefits [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of January 1
28 
6 
Relating to assets still held at the reporting date
3 
1 
Relating to assets sold during the period
0 
0 
Purchases
21 
21 
Settlements
(14)
0 
Balance as of December 31
38 
28 
Real Estate [Member] |
Pension Plans Defined Benefit [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of January 1
285 
 
Relating to assets still held at the reporting date
49 
12 
Relating to assets sold during the period
(3)
0 
Purchases
352 
208 
Settlements
(139)
0 
Balance as of December 31
544 
285 
Absolute Return [Member] |
Other Benefits [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of January 1
49 
47 
Relating to assets still held at the reporting date
4 
2 
Relating to assets sold during the period
0 
0 
Purchases
12 
0 
Settlements
(12)
0 
Balance as of December 31
53 
49 
Absolute Return [Member] |
Pension Plans Defined Benefit [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of January 1
513 
487 
Relating to assets still held at the reporting date
37 
26 
Relating to assets sold during the period
4 
0 
Purchases
0 
0 
Settlements
0 
0 
Balance as of December 31
554 
513 
Corporate Fixed Income Securities [Member] |
Other Benefits [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of January 1
1 
1 
Relating to assets still held at the reporting date
0 
0 
Relating to assets sold during the period
0 
0 
Purchases
1 
1 
Settlements
0 
(1)
Balance as of December 31
2 
1 
Corporate Fixed Income Securities [Member] |
Pension Plans Defined Benefit [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance as of January 1
611 
585 
Relating to assets still held at the reporting date
1 
28 
Relating to assets sold during the period
0 
(1)
Purchases
20 
12 
Settlements
(7)
(13)
Balance as of December 31
$ 625 
$ 611 
Employee Benefit Plans (Schedule Of Estimated Benefits Expected To Be Paid) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Pension Plans Defined Benefit [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
2013
$ 613 
 
2014
652 
 
2015
692 
 
2016
730 
 
2017
766 
 
2018-2022
4,326 
 
Contributed to the other benefit plans
323 
282 
Approximate contribution expected to be paid
327 
 
Other Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
2013
90 
 
2014
95 
 
2015
100 
 
2016
107 
 
2017
113 
 
2018-2022
609 
 
Contributed to the other benefit plans
145 
149 
Approximate contribution expected to be paid
71 
 
Federal Subsidy [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
2013
(6)
 
2014
(7)
 
2015
(8)
 
2016
(8)
 
2017
(9)
 
2018-2022
$ (35)
 
Employee Benefit Plans (Schedule Of Employer Contribution Expense) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Employee Benefit Plans [Abstract]
 
 
 
Pension expense
$ 71 
$ 67 
$ 65 
Resolution Of Remaining Chapter 11 Disputed Claims (Changes In The Remaining Net Disputed Claims Liability) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
 
 
Escrow for payment of remaining net disputed claims
$ 291 
$ 291 
Balance at December 31, 2011
842 
 
Interest accrued
25 
 
Less: supplier settlements
(3)
 
Balance at December 31, 2012
864 
 
Interest payable on disputed claims
710 
685 
Pacific Gas And Electric Company [Member]
 
 
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
 
 
Remaining disputed claims
154 
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
 
$ 494 
Related Party Agreements And Transactions (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Related Party Transaction [Line Items]
 
 
 
Current receivables
$ 22 
$ 19 
 
Current payables
17 
17 
 
Administrative Services Provided To PG&E Corporation [Member]
 
 
 
Related Party Transaction [Line Items]
 
 
 
Utility revenues from
7 
7 
6 
Administrative Services Received From PG&E Corporation [Member]
 
 
 
Related Party Transaction [Line Items]
 
 
 
Utility expenses from
45 
50 
49 
Utility Employee Benefit Due To PG&E Corporation [Member]
 
 
 
Related Party Transaction [Line Items]
 
 
 
Utility expenses from
$ 57 
$ 51 
$ 33 
Commitments And Contingencies (Schedule Of Costs Incurred Attributable To Each Category Of Power Purchase Agreements) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Third-Party Power Purchase Agreements [Line Items]
 
 
 
Payments for renewable energy contracts with QF's
$ 271 
$ 286 
$ 297 
Qualifying Facilities [Member]
 
 
 
Third-Party Power Purchase Agreements [Line Items]
 
 
 
Costs incurred in power purchase
813 1
779 1
1,069 1
Renewable Energy Contracts [Member]
 
 
 
Third-Party Power Purchase Agreements [Line Items]
 
 
 
Costs incurred in power purchase
1,281 
815 
622 
Other Power Purchase Agreements [Member]
 
 
 
Third-Party Power Purchase Agreements [Line Items]
 
 
 
Costs incurred in power purchase
$ 902 
$ 661 
$ 690 
Commitments And Contingencies (Third-Party Power Purchase Agreements) (Details)
12 Months Ended
Dec. 31, 2013
Third-Party Power Purchase Agreements [Line Items]
 
Long term contract for purchase of electric power, number of QF's
170 
Qualifying Facilities [Member]
 
Third-Party Power Purchase Agreements [Line Items]
 
Long term contract for purchase of electric power, date of contract expiration, beginning date
2014 
Long term contract for purchase of electric power, date of contract expiration, ending date
2028 
Commitments And Contingencies (Third-Party Power Purchases) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Long-term Purchase Commitment [Line Items]
 
2014
$ 3,648 
2015
3,579 
2016
3,418 
2017
3,238 
2018
3,008 
Thereafter
34,840 
Total
51,731 
QF Energy Payments [Member]
 
Long-term Purchase Commitment [Line Items]
 
2014
913 
2015
707 
2016
587 
2017
450 
2018
406 
Thereafter
1,614 
Total
4,677 
Renewable (Other Than QF) Energy [Member]
 
Long-term Purchase Commitment [Line Items]
 
2014
1,906 
2015
2,102 
2016
2,109 
2017
2,104 
2018
1,962 
Thereafter
30,242 
Total
40,425 
Other, Energy Payments [Member]
 
Long-term Purchase Commitment [Line Items]
 
2014
829 
2015
770 
2016
722 
2017
684 
2018
640 
Thereafter
2,984 
Total
$ 6,629 
Commitments And Contingencies (Schedule Of Capacity Payments Due Under The QF Contracts Discount) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2013
Maximum [Member]
Qualifying Facilities [Member]
Dec. 31, 2013
Minimum [Member]
Qualifying Facilities [Member]
Long-term Purchase Commitment [Line Items]
 
 
 
 
2013
$ 27 
 
 
 
2014
24 
 
 
 
2015
22 
 
 
 
2016
18 
 
 
 
2017
12 
 
 
 
Thereafter
8 
 
 
 
Total fixed capacity payments
111 
 
 
 
Less: amount representing interest
14 
 
 
 
Present value of fixed capacity payments
97 
 
 
 
Capital lease expiration dates of contracts
 
 
2014-04-01 
2021-09-01 
Present value of fixed capacity payments, portion classified as current liabilities
23 
29 
 
 
Present value of fixed capacity payments, portion classified as noncurrent liabilities
74 
96 
 
 
Capitalized asset for fixed capacity payments for corresponding assets
97 
125 
 
 
Capitalized asset for fixed capacity payments, accumulated amortization
$ 176 
$ 148 
 
 
Commitments And Contingencies (Gas Supply, Transportation And Storage) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Long-term Purchase Commitment [Line Items]
 
 
 
2014
$ 3,648 
 
 
2015
3,579 
 
 
2016
3,418 
 
 
2017
3,238 
 
 
2018
3,008 
 
 
Thereafter
34,840 
 
 
Total
51,731 
 
 
Pacific Gas And Electric Company [Member]
 
 
 
Long-term Purchase Commitment [Line Items]
 
 
 
Cost of natural gas purchases
1,600 
1,300 
1,800 
Natural Gas, Gas Transportation and Gas Storage Purchases [Member]
 
 
 
Long-term Purchase Commitment [Line Items]
 
 
 
2014
727 
 
 
2015
198 
 
 
2016
150 
 
 
2017
108 
 
 
2018
108 
 
 
Thereafter
756 
 
 
Total
$ 2,047 
 
 
Commitments And Contingencies (Nuclear Fuel Agreements) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Long-term Purchase Commitment [Line Items]
 
 
 
2014
$ 3,648 
 
 
2015
3,579 
 
 
2016
3,418 
 
 
2017
3,238 
 
 
2018
3,008 
 
 
Thereafter
34,840 
 
 
Total
51,731 
 
 
Pacific Gas And Electric Company [Member]
 
 
 
Long-term Purchase Commitment [Line Items]
 
 
 
Payments for nuclear fuel
162 
118 
77 
Length of contract terms, minimum (in years)
1 year 
 
 
Length of contract terms, maximum (in years)
12 years 
 
 
Percentage coverage of reactor requirements through 2020
100.00% 
 
 
Percentage coverage of reactor requirements through 2017
100.00% 
 
 
Nuclear Fuel Purchase Commitments [Member]
 
 
 
Long-term Purchase Commitment [Line Items]
 
 
 
2014
145 
 
 
2015
162 
 
 
2016
146 
 
 
2017
148 
 
 
2018
132 
 
 
Thereafter
647 
 
 
Total
$ 1,380 
 
 
Commitments And Contingencies (Other Commitments And Other Operating Leases) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Commitments And Contingencies [Abstract]
 
 
 
2013
$ 42 
 
 
2014
37 
 
 
2015
34 
 
 
2016
27 
 
 
2017
24 
 
 
Thereafter
193 
 
 
Total
357 
 
 
Payments for other commitments and operating leases
$ 40 
$ 32 
$ 27 
Expiration dates on operating leases beginning date
2014 
 
 
Expiration dates on operating leases ending date
2023 
 
 
Operating rental leases, annual percentage increase, low end
2.00% 
 
 
Operating rental leases, annual percentage increase. high end
5.00% 
 
 
Operating rental leases, extension options years, low end
1 year 
 
 
Operating rental leases, extension options years, high end
5 years 
 
 
Commitments And Contingencies (Nuclear Insurance) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Long-term Purchase Commitment [Line Items]
 
Humboldt Bay Unit 3 liability insurance
$ 53 
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 
Maximum public liability claims amount per nuclear event
13,600 
Maximum total payment incurred per event under the loss sharing program
255 
Maximum annual payment incurred per event under the loss sharing program
38 
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 (Legal And Regulatory Contingencies) (Details) (USD $)
12 Months Ended
Dec. 31, 2013
mi
Dec. 31, 2012
Loss Contingencies [Line Items]
 
 
Disallowed capital expenditure losses
 
$ 353,000,000 
PGE Corporation And Utility [Member]
 
 
Loss Contingencies [Line Items]
 
 
Accrued legal liabilities
43,000,000 
34,000,000 
Probable penalty amount
200,000,000 
 
Pacific Gas And Electric Company [Member]
 
 
Loss Contingencies [Line Items]
 
 
Accrued legal liabilities
45,000,000 
146,000,000 
Utility liability insurance for damages
992,000,000 
 
Utility liability insurance deductible
10,000,000 
 
Disallowed capital expenditure losses
196,000,000 
353,000,000 
Penalties recommended by various parties
2,250,000,000 
 
Capitalized PSEP costs
766,000,000 
 
Amount of capital included in Property, Plant, and Equipment
280,000,000 
 
Number of CPUC investigative enforcement proceedings
3 
 
Number of self-reports filed with SED
50 
 
SED fines for self-reported violations
 
16,800,000 
Cummulative payments for San Bruno settlements
520,000,000 
 
Cummulative insurance recoveries for third-party claims and associated legal costs
354,000,000 
 
CPUC fine in connection with OSC
14,000,000 
 
Natural gas pipeline Transmission Miles
6,750 
 
State General Fund [Member] |
Pacific Gas And Electric Company [Member]
 
 
Loss Contingencies [Line Items]
 
 
SED recommended penalty
300,000,000 
 
PSEP Costs Previously Disallowed By CPUC [Member] |
Pacific Gas And Electric Company [Member]
 
 
Loss Contingencies [Line Items]
 
 
SED recommended penalty
435,000,000 
 
PSEP Costs Approved, Implementation of Operational Remedies, Future PSEP Costs [Member] |
Pacific Gas And Electric Company [Member]
 
 
Loss Contingencies [Line Items]
 
 
SED recommended penalty
1,515,000,000 
 
Maximum [Member] |
Pacific Gas And Electric Company [Member]
 
 
Loss Contingencies [Line Items]
 
 
SED fines for self-reported violations
8,100,000 
 
Minimum [Member] |
Pacific Gas And Electric Company [Member]
 
 
Loss Contingencies [Line Items]
 
 
SED fines for self-reported violations
50,000 
 
San Bruno Explosion [Member] |
Pacific Gas And Electric Company [Member]
 
 
Loss Contingencies [Line Items]
 
 
Cumulative provision
$ 565,000,000 
 
San Bruno Explosion [Member] |
San Mateo County Superior Court [Member]
 
 
Loss Contingencies [Line Items]
 
 
Number of plaintiffs
525 
 
San Bruno Explosion [Member] |
Tort Lawsuits [Member] |
San Mateo County Superior Court [Member]
 
 
Loss Contingencies [Line Items]
 
 
Number of lawsuits
165 
 
Commitments And Contingencies (Environmental Remediation Contingencies) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Long-term Purchase Commitment [Line Items]
 
 
Amount of environmental loss accrual expected to be recovered
$ 579 
 
Eligible Resident Households For Voluntary Program
380 
 
Utility Undiscounted Future Costs
1,700 
 
Remediation cost recovery
90.00% 
 
Pacific Gas And Electric Company [Member]
 
 
Long-term Purchase Commitment [Line Items]
 
 
Utility Undiscounted future costs
$ 900 
$ 910 
Commitments And Contingencies (Environmental Remediation Liability Disclosure) (Details) (Pacific Gas And Electric Company [Member], USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Pacific Gas And Electric Company [Member]
 
Long-term Purchase Commitment [Line Items]
 
Balance at December 31, 2011
$ 910 
Transfer to regulatory account for recovery
116 
Amounts not recoverable from customers
49 
Less: Payments
(175)
Balance at December 31, 2012
$ 900 
Commitments And Contingencies (Environmental Remediation Liability Composed) (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Utility-owned natural gas compressor site near Hinkley, California
$ 190 1
$ 226 1
Utility Owned Natural Gas Compressor Site Near Topock Arizona
264 1
239 1
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites
160 
158 
Former MGP sites owned by the Utility or third parties
184 
181 
Fossil fuel-fired generation facilities and sites
102 
106 
Total environmental remediation liability
$ 900 
$ 910 
Quarterly Consolidated Financial Data (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 3 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Sep. 30, 2013
Utility [Member]
Dec. 31, 2012
Utility [Member]
Sep. 30, 2012
Utility [Member]
Jun. 30, 2012
Utility [Member]
Mar. 31, 2012
Utility [Member]
Loss accrued
 
 
 
$ 110 
 
 
$ 80 
 
Insurance recoveries for cost incurred related to third-party claims
 
 
 
25 
50 
99 
25 
11 
Disallowed capital expenditures
$ 196 
$ 353 
$ 0 
$ 196 
$ 353 
 
 
 
Quarterly Consolidated Financial Data (Schedule Of Quarterly Consolidated Financial Data) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Operating revenues
 
 
 
 
 
 
 
 
$ 15,598 
$ 15,040 
$ 14,956 
Operating income
 
 
 
 
 
 
 
 
1,762 
1,693 
1,942 
Income tax provision
 
 
 
 
 
 
 
 
268 
237 
440 
Net income
 
 
 
 
 
 
 
 
828 
830 
858 
Income available for common shareholders
 
 
 
 
 
 
 
 
814 
816 
 
ComprehensiveIncomeNetOfTaxIncludingPortionAttributableToNoncontrollingInterest
 
 
 
 
 
 
 
 
979 
942 
847 
Net earnings per common share, basic
 
 
 
 
 
 
 
 
$ 1.83 
$ 1.92 
$ 2.1 
Net earnings per common share, diluted
 
 
 
 
 
 
 
 
$ 1.83 
$ 1.92 
$ 2.1 
PG&E Corporation [Member]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
3,975 
4,175 
3,776 
3,672 
3,830 
3,976 
3,593 
3,641 
 
 
 
Operating income
333 
291 
636 
502 
125 
614 
467 
487 
 
 
 
Income tax provision
25 
(24)
153 
114 
(54)
100 
87 
104 
48 
57 
30 
Net income
90 
164 
332 
242 
(9)
364 
239 
236 
814 
816 
844 
Income available for common shareholders
86 
161 
328 
239 
(13)
361 
235 
233 
814 
816 
844 
ComprehensiveIncomeNetOfTaxIncludingPortionAttributableToNoncontrollingInterest
210 
165 
352 
252 
77 
372 
247 
246 
 
 
 
Net earnings per common share, basic
$ 0.19 
$ 0.36 
$ 0.74 
$ 0.55 
$ (0.03)
$ 0.84 
$ 0.56 
$ 0.56 
$ 1.83 
$ 1.92 
$ 2.1 
Net earnings per common share, diluted
$ 0.19 
$ 0.36 
$ 0.74 
$ 0.55 
$ (0.03)
$ 0.84 
$ 0.55 
$ 0.56 
$ 1.83 
$ 1.92 
$ 2,100,000.00 
Common stock price per share, High
$ 42.75 
$ 46.37 
$ 48.44 
$ 44.53 
$ 43.48 
$ 46.51 
$ 45.2 
$ 43.72 
 
 
 
Common stock price per share, Low
$ 40.07 
$ 40.76 
$ 43.59 
$ 40.47 
$ 39.71 
$ 42.41 
$ 42.04 
$ 40.16 
 
 
 
Utility [Member]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
3,973 
4,174 
3,775 
3,671 
3,829 
3,974 
3,592 
3,640 
 
 
 
Operating income
360 
292 
635 
503 
127 
613 
467 
488 
 
 
 
Income tax provision
65 
(20)
160 
121 
13 
340 
227 
231 
326 
298 
480 
Net income
138 
162 
329 
237 
 
122 
93 
113 
 
 
 
Income available for common shareholders
134 
159 
325 
234 
9 
337 
223 
228 
 
 
 
ComprehensiveIncomeNetOfTaxIncludingPortionAttributableToNoncontrollingInterest
$ 231 
$ 166 
$ 333 
$ 242 
$ 96 
$ 348 
$ 235 
$ 241 
 
 
 
Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Income Statement) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Operating expenses
 
 
 
 
 
 
 
 
$ (13,836)
$ (13,347)
$ (13,014)
Interest income
 
 
 
 
 
 
 
 
9 
7 
7 
Interest expense
 
 
 
 
 
 
 
 
(715)
(703)
(700)
Other income, net
 
 
 
 
 
 
 
 
40 
70 
49 
Income Before Income Taxes
 
 
 
 
 
 
 
 
1,096 
1,067 
1,298 
Income tax provision
 
 
 
 
 
 
 
 
268 
237 
440 
Income Available for Common Shareholders
 
 
 
 
 
 
 
 
814 
816 
 
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Unrealized Holding Gain Loss On Securities Arising During Period Net Of Tax
 
 
 
 
 
 
 
 
38 
4 
0 
Total other comprehensive income (loss)
 
 
 
 
 
 
 
 
151 
112 
(11)
Comprehensive Income
 
 
 
 
 
 
 
 
965 
928 
833 
Weighted average common shares outstanding, basic
 
 
 
 
 
 
 
 
444 
424 
401 
Weighted average common shares outstanding, diluted
 
 
 
 
 
 
 
 
445 
425 
402 
Net earnings per common share, basic
 
 
 
 
 
 
 
 
$ 1.83 
$ 1.92 
$ 2.1 
Net earnings per common share, diluted
 
 
 
 
 
 
 
 
$ 1.83 
$ 1.92 
$ 2.1 
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Unrealized Holding Gain Loss On Securities Arising During Period Net Of Tax
 
 
 
 
 
 
 
 
38 
 
 
Other Postretirement Benefit Plans Defined Benefit [Member]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Total other comprehensive income (loss)
 
 
 
 
 
 
 
 
92 
 
 
Other Postretirement Benefit Plans Defined Benefit [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Unrealized Holding Gain Loss On Securities Arising During Period Net Of Tax
 
 
 
 
 
 
 
 
0 
 
 
Other Pension Plans Defined Benefit [Member]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Total other comprehensive income (loss)
 
 
 
 
 
 
 
 
38 
 
 
Other Pension Plans Defined Benefit [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Unrealized Holding Gain Loss On Securities Arising During Period Net Of Tax
 
 
 
 
 
 
 
 
38 
 
 
Defined Benefits Plan Pension [Member]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Total other comprehensive income (loss)
 
 
 
 
 
 
 
 
21 
 
 
Defined Benefits Plan Pension [Member] |
Other Comprehensive Income Before Reclassifications [Member]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income Unrealized Holding Gain Loss On Securities Arising During Period Net Of Tax
 
 
 
 
 
 
 
 
0 
 
 
PG&E Corporation [Member]
 
 
 
 
 
 
 
 
 
 
 
Administrative service revenue
 
 
 
 
 
 
 
 
41 
43 
44 
Operating expenses
 
 
 
 
 
 
 
 
(42)
(41)
(44)
Interest income
 
 
 
 
 
 
 
 
1 
1 
1 
Interest expense
 
 
 
 
 
 
 
 
(25)
(22)
(22)
Other income, net
 
 
 
 
 
 
 
 
(57)
(39)
(17)
Equity in earnings of subsidiaries
 
 
 
 
 
 
 
 
848 
817 
852 
Income Before Income Taxes
 
 
 
 
 
 
 
 
766 
759 
814 
Income tax provision
25 
(24)
153 
114 
(54)
100 
87 
104 
48 
57 
30 
Income Available for Common Shareholders
86 
161 
328 
239 
(13)
361 
235 
233 
814 
816 
844 
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Pension and other postretirement benefit plans (net of income tax of $72, $9, $25 in 2012, 2011, and 2010 respectivley)
 
 
 
 
 
 
 
 
113 
108 
(11)
Other Comprehensive Income Unrealized Holding Gain Loss On Securities Arising During Period Net Of Tax
 
 
 
 
 
 
 
 
38 
4 
0 
Total other comprehensive income (loss)
 
 
 
 
 
 
 
 
151 
112 
(11)
Comprehensive Income
 
 
 
 
 
 
 
 
$ 965 
$ 928 
$ 833 
Weighted average common shares outstanding, basic
 
 
 
 
 
 
 
 
444 
424 
401 
Weighted average common shares outstanding, diluted
 
 
 
 
 
 
 
 
445 
425 
402 
Net earnings per common share, basic
$ 0.19 
$ 0.36 
$ 0.74 
$ 0.55 
$ (0.03)
$ 0.84 
$ 0.56 
$ 0.56 
$ 1.83 
$ 1.92 
$ 2.1 
Net earnings per common share, diluted
$ 0.19 
$ 0.36 
$ 0.74 
$ 0.55 
$ (0.03)
$ 0.84 
$ 0.55 
$ 0.56 
$ 1.83 
$ 1.92 
$ 2,100,000.00 
Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Balance Sheet) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Cash and cash equivalents
$ 296 
$ 401 
$ 513 
$ 291 
Advances to affiliates
17 
17 
 
 
Income taxes receivable
574 
211 
 
 
Other Assets, Current
611 
172 
 
 
Total current assets
5,977 
5,121 
 
 
Equipment
59,096 
54,167 
 
 
Accumulated depreciation
(17,844)
(16,644)
 
 
Net property, plant, and equipment
41,252 
37,523 
 
 
Income taxes receivable
85 
176 
 
 
Other
1,036 
659 
 
 
TOTAL ASSETS
55,605 
52,449 
 
 
Short-term borrowings
1,174 
492 
 
 
Long-term debt, classified as current
889 
400 
 
 
Other
1,612 
2,018 
 
 
Total current liabilities
7,493 
6,256 
 
 
Long-term debt
12,717 
12,517 
 
 
Other
2,178 
2,020 
 
 
Total noncurrent liabilities
33,518 
32,867 
 
 
Common stock
9,550 
8,428 
 
 
Reinvested earnings
4,742 
4,747 
 
 
Accumulated other comprehensive income (loss)
50 
(101)
 
 
Total shareholders' equity
14,342 
13,074 
 
 
TOTAL LIABILITIES AND EQUITY
55,605 
52,449 
 
 
Other Postretirement Benefit Plans Defined Benefit [Member]
 
 
 
 
Accumulated other comprehensive income (loss)
15 
(77)
 
 
Other Pension Plans Defined Benefit [Member]
 
 
 
 
Accumulated other comprehensive income (loss)
42 
4 
 
 
Defined Benefits Plan Pension [Member]
 
 
 
 
Accumulated other comprehensive income (loss)
(7)
(28)
 
 
PG&E Corporation [Member]
 
 
 
 
Cash and cash equivalents
231 
207 
209 
240 
Advances to affiliates
30 
26 
 
 
Income taxes receivable
13 
33 
 
 
Other Assets, Current
86 
0 
 
 
Total current assets
360 
226 
 
 
Equipment
2 
1 
 
 
Accumulated depreciation
(1)
(1)
 
 
Net property, plant, and equipment
1 
0 
 
 
Investments in subsidiaries
14,711 
13,387 
 
 
Other investments
110 
102 
 
 
Income taxes receivable
5 
5 
 
 
Deferred income taxes
188 
178 
 
 
Other
0 
1 
 
 
Total noncurrent assets
15,015 
13,673 
 
 
TOTAL ASSETS
15,375 
13,939 
 
 
Short-term borrowings
260 
120 
 
 
Long-term debt, classified as current
350 
0 
 
 
Accounts payable - other
66 
48 
 
 
Other
230 
221 
 
 
Total current liabilities
906 
289 
 
 
Long-term debt
0 
349 
 
 
Other
127 
127 
 
 
Total noncurrent liabilities
127 
476 
 
 
Common stock
9,550 
8,428 
 
 
Reinvested earnings
4,742 
4,747 
 
 
Accumulated other comprehensive income (loss)
50 
(101)
 
 
Total shareholders' equity
14,342 
13,074 
 
 
TOTAL LIABILITIES AND EQUITY
$ 15,375 
$ 13,939 
 
 
Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Statement Of Cash Flows) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Net income
$ 828 
$ 830 
$ 858 
Deferred income taxes and tax credits, net
1,075 
648 
544 
Net cash provided by operating activities
3,427 
4,882 
3,739 
Other
56 
104 
(113)
Net cash provided by (used in) investing activities
(5,107)
(4,526)
(3,986)
Borrowings under revolving credit facilities
140 
120 
358 
Repayments under revolving credit facilities
0 
0 
(358)
Proceeds from issuance of long-term debt, net of discount and issuance costs
1,532 
1,137 
792 
Common stock issued
1,045 
751 
662 
Common stock dividends paid
(782)
(746)
(704)
Other
(41)
14 
41 
Net cash (used) in financing activities
1,575 
(468)
469 
Net change in cash and cash equivalents
(105)
(112)
222 
Cash and cash equivalents at January 1
401 
513 
291 
Cash and cash equivalents at December 31
296 
401 
513 
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs
18 
13 
8 
Cash received (paid) for:
 
 
 
Interest, net of amounts capitalized
(623)
(594)
(647)
Income taxes, net
(41)
114 
(42)
Noncash common stock issuances
(22)
(22)
(24)
Common stock dividends declared but not yet paid
(208)
(196)
(188)
PG&E Corporation [Member]
 
 
 
Net income
814 
816 
844 
Depreciation and amortization
54 
51 
36 
Equity in earnings of subsidiaries
(848)
(817)
(852)
Deferred income taxes and tax credits, net
(10)
(31)
(26)
Noncurrent income taxes receivable/payable
0 
(6)
(47)
Current income taxes receivable/payable
20 
(82)
49 
Other
(20)
20 
(80)
Net cash provided by operating activities
10 
(49)
(76)
Investment in subsidiaries
(1,371)
(1,023)
(759)
Dividends received from subsidiaries
716 1
716 1
716 1
Proceeds from tax equity investments
275 
228 
129 
Other
(8)
0 
0 
Net cash provided by (used in) investing activities
(388)
(79)
86 
Borrowings under revolving credit facilities
140 
120 
150 
Repayments under revolving credit facilities
0 
0 
(150)
Common stock issued
1,045 
751 
662 
Common stock dividends paid
(782)2
(746)2
(704)2
Other
(1)
1 
1 
Net cash (used) in financing activities
402 
126 
(41)
Net change in cash and cash equivalents
24 
(2)
(31)
Cash and cash equivalents at January 1
207 
209 
240 
Cash and cash equivalents at December 31
231 
207 
209 
Cash received (paid) for:
 
 
 
Interest, net of amounts capitalized
(23)
(20)
(20)
Income taxes, net
21 
(60)
8 
Noncash common stock issuances
22 
22 
24 
Common stock dividends declared but not yet paid
$ 208 
$ 196 
$ 188 
Schedule II - Consolidated Valuation And Qualifying Accounts (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract]
 
 
 
Allowance for uncollectible accounts, Balance at Beginning of Period
$ 87 1
$ 81 1
$ 81 1
Allowance for uncollectible accounts, Charged to Costs and Expenses
53 1
66 1
60 1
Charged to other accounts
0 1
0 1
0 1
Allowance for uncollectible accounts, Deductions
60 1 2
60 1 2
60 1 2
Allowance for uncollectible accounts, Balance at End of Period
$ 80 1
$ 87 1
$ 81 1