Document And Entity Information
Document And Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 07, 2017 | Jun. 30, 2016 | |
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2016 | ||
Amendment Flag | false | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Registrant Name | PG&E CORP | ||
Entity Central Index Key | 1,004,980 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2,016 | ||
Entity Current Reporting Status | Yes | ||
Trading Symbol | PCG | ||
Document Fiscal Period Focus | FY | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Public Float | $ 31,807 | ||
Entity Common Stock, Shares Outstanding | 507,782,249 | ||
Pacific Gas And Electric Company [Member] | |||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2016 | ||
Amendment Flag | false | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Registrant Name | PACIFIC GAS & ELECTRIC CO | ||
Entity Central Index Key | 75,488 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2,016 | ||
Entity Current Reporting Status | Yes | ||
Trading Symbol | PCG | ||
Document Fiscal Period Focus | FY | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Common Stock, Shares Outstanding | 264,374,809 |
Consolidated Statements Of Inco
Consolidated Statements Of Income - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating Revenues | |||
Electric | $ 13,864 | $ 13,657 | $ 13,658 |
Natural gas | 3,802 | 3,176 | 3,432 |
Total operating revenues | 17,666 | 16,833 | 17,090 |
Operating Expenses | |||
Cost of electricity | 4,765 | 5,099 | 5,615 |
Cost of natural gas | 615 | 663 | 954 |
Operating and maintenance | 7,354 | 6,951 | 5,638 |
Depreciation, amortization, and decommissioning | 2,755 | 2,612 | 2,433 |
Total operating expenses | 15,489 | 15,325 | 14,640 |
Operating Income | 2,177 | 1,508 | 2,450 |
Interest income | 23 | 9 | 9 |
Interest expense | (829) | (773) | (734) |
Other income (expense) | 91 | 117 | 70 |
Income Before Income Taxes | 1,462 | 861 | 1,795 |
Income tax provision (benefit) | 55 | (27) | 345 |
Net Income | 1,407 | 888 | 1,450 |
Preferred stock dividend requirement of subsidiary | 14 | 14 | 14 |
Income Available for Common Shareholders | $ 1,393 | $ 874 | $ 1,436 |
Weighted Average Common Shares Outstanding, Basic | 499 | 484 | 468 |
Weighted Average Common Shares Outstanding, Diluted | 501 | 487 | 470 |
Net earnings per common share, basic | $ 2.79 | $ 1.81 | $ 3.07 |
Net Earnings Per Common Share, Diluted | $ 2.78 | $ 1.79 | $ 3.06 |
Pacific Gas And Electric Company [Member] | |||
Operating Revenues | |||
Electric | $ 13,865 | $ 13,657 | $ 13,656 |
Natural gas | 3,802 | 3,176 | 3,432 |
Total operating revenues | 17,667 | 16,833 | 17,088 |
Operating Expenses | |||
Cost of electricity | 4,765 | 5,099 | 5,615 |
Cost of natural gas | 615 | 663 | 954 |
Operating and maintenance | 7,352 | 6,949 | 5,635 |
Depreciation, amortization, and decommissioning | 2,754 | 2,611 | 2,432 |
Total operating expenses | 15,486 | 15,322 | 14,636 |
Operating Income | 2,181 | 1,511 | 2,452 |
Interest income | 22 | 8 | 8 |
Interest expense | (819) | (763) | (720) |
Other income (expense) | 88 | 87 | 77 |
Income Before Income Taxes | 1,472 | 843 | 1,817 |
Income tax provision (benefit) | 70 | (19) | 384 |
Net Income | 1,402 | 862 | 1,433 |
Preferred stock dividend requirement | 14 | 14 | 14 |
Income Available for Common Shareholders | $ 1,388 | $ 848 | $ 1,419 |
Consolidated Statements Of Comp
Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Net income | $ 1,407 | $ 888 | $ 1,450 |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations (related to PG&E Corporation net of income tax of $1, $0 and $10 and related to the Utility of $1, $1, and $6, at respective dates) | (2) | (1) | (14) |
Net change in investments (net of taxes $0, $12, and $17, at respective dates) | 0 | (17) | (25) |
Total other comprehensive income (loss) | (2) | (18) | (39) |
Comprehensive Income | 1,405 | 870 | 1,411 |
Preferred stock dividend requirement of subsidiary | 14 | 14 | 14 |
Comprehensive Income Attributable to Common Shareholders | 1,391 | 856 | 1,397 |
Pacific Gas And Electric Company [Member] | |||
Net income | 1,402 | 862 | 1,433 |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations (related to PG&E Corporation net of income tax of $1, $0 and $10 and related to the Utility of $1, $1, and $6, at respective dates) | (1) | (2) | (8) |
Total other comprehensive income (loss) | (1) | (2) | (8) |
Comprehensive Income | $ 1,401 | $ 860 | $ 1,425 |
Consolidated Statements Of Com4
Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension and other postretirement benefit plans obligations tax | $ 1 | $ 0 | $ 10 |
Change in investments tax | 0 | 12 | 17 |
Pacific Gas And Electric Company [Member] | |||
Pension and other postretirement benefit plans obligations tax | $ 1 | $ 1 | $ 6 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Current Assets | ||
Cash and cash equivalents | $ 177 | $ 123 |
Restricted cash | 7 | 234 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $58 and $54 at respective dates) | 1,252 | 1,106 |
Accrued unbilled revenue | 1,098 | 855 |
Regulatory balancing accounts | 1,500 | 1,760 |
Other | 801 | 286 |
Regulatory assets | 423 | 517 |
Inventories | ||
Gas stored underground and fuel oil | 117 | 126 |
Materials and supplies | 346 | 313 |
Income taxes receivable | 160 | 155 |
Other | 283 | 338 |
Total current assets | 6,164 | 5,813 |
Property, Plant, and Equipment | ||
Electric | 52,556 | 48,532 |
Gas | 17,853 | 16,749 |
Construction work in progress | 2,184 | 2,059 |
Other | 2 | 2 |
Total property, plant, and equipment | 72,595 | 67,342 |
Accumulated depreciation | (22,014) | (20,619) |
Net property, plant, and equipment | 50,581 | 46,723 |
Other Noncurrent Assets | ||
Regulatory assets | 7,951 | 7,029 |
Nuclear decommissioning trusts | 2,606 | 2,470 |
Income taxes receivable | 70 | 135 |
Other | 1,226 | 1,064 |
Total other noncurrent assets | 11,853 | 10,698 |
TOTAL ASSETS | 68,598 | 63,234 |
Current Liabilities | ||
Short-term borrowings | 1,516 | 1,019 |
Long-term debt, classified as current | 700 | 160 |
Accounts payable | ||
Trade creditors | 1,495 | 1,414 |
Regulatory balancing accounts | 645 | 715 |
Other | 433 | 398 |
Disputed claims and customer refunds | 236 | 454 |
Interest payable | 216 | 206 |
Other | 2,323 | 1,997 |
Total current liabilities | 7,564 | 6,363 |
Noncurrent Liabilities | ||
Long-term debt | 16,220 | 15,925 |
Regulatory liabilities | 6,805 | 6,321 |
Pension and other postretirement benefits | 2,641 | 2,622 |
Asset retirement obligations | 4,684 | 3,643 |
Deferred income taxes | 10,213 | 9,206 |
Other | 2,279 | 2,326 |
Total noncurrent liabilities | 42,842 | 40,043 |
Commitments and Contingencies (Note 13) | ||
Shareholders' Equity | ||
Common stock | 12,198 | 11,282 |
Reinvested earnings | 5,751 | 5,301 |
Accumulated other comprehensive(loss)income | (9) | (7) |
Total shareholders' equity | 17,940 | 16,576 |
Noncontrolling Interest - Preferred Stock of Subsidiary | 252 | 252 |
Total equity | 18,192 | 16,828 |
TOTAL LIABILITIES AND EQUITY | 68,598 | 63,234 |
Pacific Gas And Electric Company [Member] | ||
Current Assets | ||
Cash and cash equivalents | 71 | 59 |
Restricted cash | 7 | 234 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $58 and $54 at respective dates) | 1,252 | 1,106 |
Accrued unbilled revenue | 1,098 | 855 |
Regulatory balancing accounts | 1,500 | 1,760 |
Other | 801 | 284 |
Regulatory assets | 423 | 517 |
Inventories | ||
Gas stored underground and fuel oil | 117 | 126 |
Materials and supplies | 346 | 313 |
Income taxes receivable | 159 | 130 |
Other | 282 | 338 |
Total current assets | 6,056 | 5,722 |
Property, Plant, and Equipment | ||
Electric | 52,556 | 48,532 |
Gas | 17,853 | 16,749 |
Construction work in progress | 2,184 | 2,059 |
Total property, plant, and equipment | 72,593 | 67,340 |
Accumulated depreciation | (22,012) | (20,617) |
Net property, plant, and equipment | 50,581 | 46,723 |
Other Noncurrent Assets | ||
Regulatory assets | 7,951 | 7,029 |
Nuclear decommissioning trusts | 2,606 | 2,470 |
Income taxes receivable | 70 | 135 |
Other | 1,110 | 958 |
Total other noncurrent assets | 11,737 | 10,592 |
TOTAL ASSETS | 68,374 | 63,037 |
Current Liabilities | ||
Short-term borrowings | 1,516 | 1,019 |
Long-term debt, classified as current | 700 | 160 |
Accounts payable | ||
Trade creditors | 1,494 | 1,414 |
Regulatory balancing accounts | 645 | 715 |
Other | 453 | 418 |
Disputed claims and customer refunds | 236 | 454 |
Interest payable | 214 | 203 |
Other | 2,072 | 1,750 |
Total current liabilities | 7,330 | 6,133 |
Noncurrent Liabilities | ||
Long-term debt | 15,872 | 15,577 |
Regulatory liabilities | 6,805 | 6,321 |
Pension and other postretirement benefits | 2,548 | 2,534 |
Asset retirement obligations | 4,684 | 3,643 |
Deferred income taxes | 10,510 | 9,487 |
Other | 2,230 | 2,282 |
Total noncurrent liabilities | 42,649 | 39,844 |
Commitments and Contingencies (Note 13) | ||
Shareholders' Equity | ||
Preferred stock | 258 | 258 |
Common stock | 1,322 | 1,322 |
Additional paid-in capital | 8,050 | 7,215 |
Reinvested earnings | 8,763 | 8,262 |
Accumulated other comprehensive(loss)income | 2 | 3 |
Total shareholders' equity | 18,395 | 17,060 |
TOTAL LIABILITIES AND EQUITY | $ 68,374 | $ 63,037 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Allowance for doubtful accounts | $ 58 | $ 54 |
Common stock, par value | $ 0 | $ 0 |
Common stock, shares authorized | 800,000,000 | 800,000,000 |
Common stock, shares outstanding | 506,891,874 | 492,025,443 |
Pacific Gas And Electric Company [Member] | ||
Allowance for doubtful accounts | $ 58 | $ 54 |
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
Consolidated Statements Of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Cash Flows from Operating Activities | |||
Net income | $ 1,407 | $ 888 | $ 1,450 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, amortization, and decommissioning | 2,755 | 2,612 | 2,433 |
Allowance for equity funds used during construction | (112) | (107) | (100) |
Deferred income taxes and tax credits, net | 1,030 | 693 | 690 |
Charge for disallowed capital | 507 | 407 | 116 |
Other | 379 | 326 | 286 |
Butte-related third-party claims | 690 | 0 | 0 |
Butte-related insurance receivable | 575 | 0 | 0 |
Effect of changes in operating assets and liabilities: | |||
Accounts receivable | (473) | (177) | 13 |
Inventories | (24) | 37 | (22) |
Accounts payable | 180 | (55) | (61) |
Income taxes receivable/payable | (5) | 43 | 376 |
Other current assets and liabilities | 83 | (288) | 218 |
Regulatory assets, liabilities, and balancing accounts, net | (1,214) | (244) | (1,642) |
Other noncurrent assets and liabilities | (219) | (355) | (67) |
Net cash provided by operating activities | 4,409 | 3,780 | 3,690 |
Cash Flows from Investing Activities | |||
Capital expenditures | (5,709) | (5,173) | (4,833) |
Decrease in restricted cash | 227 | 64 | 3 |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,295 | 1,268 | 1,336 |
Purchases of nuclear decommissioning trust investments | (1,352) | (1,392) | (1,334) |
Other | 13 | 22 | 114 |
Net cash used in investing activities | (5,526) | (5,211) | (4,714) |
Cash Flows from Financing Activities | |||
Borrowings (repayments) under revolving credit facilities | 0 | 0 | (260) |
Net issuances (repayments) of commercial paper, net of discount of $6, $3, and $2 at respective dates | (9) | 683 | (583) |
Short-term debt financing | 500 | 0 | 300 |
Short-term debt matured | 0 | (300) | 0 |
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of (for PG&E Corporaiton $17, $27, and $17 and for the Utility $17, $27, and $17, at respective dates) | 983 | 1,123 | 2,308 |
Repayments of long-term debt | (160) | 0 | (889) |
Common stock issued | 822 | 780 | 802 |
Common stock dividends paid | (921) | (856) | (828) |
Other | (44) | (27) | 29 |
Net cash provided by (used in) financing activities | 1,171 | 1,403 | 879 |
Net change in cash and cash equivalents | 54 | (28) | (145) |
Cash and cash equivalents at January 1 | 123 | 151 | 296 |
Cash and cash equivalents at December 31 | 177 | 123 | 151 |
Cash received (paid) for: | |||
Interest, net of amounts capitalized | (726) | (684) | (633) |
Income taxes, net | 231 | 77 | 501 |
Supplemental disclosures of noncash investing and financing activities | |||
Common stock dividends declared but not yet paid | 248 | 224 | 217 |
Capital expenditures financed through accounts payable | 403 | 440 | 339 |
Noncash common stock issuances | 20 | 21 | 21 |
Terminated Capital Leases | 18 | 0 | 71 |
Pacific Gas And Electric Company [Member] | |||
Cash Flows from Operating Activities | |||
Net income | 1,402 | 862 | 1,433 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, amortization, and decommissioning | 2,754 | 2,611 | 2,432 |
Allowance for equity funds used during construction | (112) | (107) | (100) |
Deferred income taxes and tax credits, net | 1,042 | 714 | 731 |
Charge for disallowed capital | 507 | 407 | 116 |
Other | 306 | 263 | 226 |
Effect of changes in operating assets and liabilities: | |||
Accounts receivable | (475) | (177) | 16 |
Inventories | (24) | 37 | (22) |
Accounts payable | 179 | (2) | (55) |
Income taxes receivable/payable | (29) | 38 | 395 |
Other current assets and liabilities | 112 | (315) | 168 |
Regulatory assets, liabilities, and balancing accounts, net | (1,214) | (244) | (1,642) |
Other noncurrent assets and liabilities | (219) | (340) | (66) |
Net cash provided by operating activities | 4,344 | 3,747 | 3,632 |
Cash Flows from Investing Activities | |||
Capital expenditures | (5,709) | (5,173) | (4,833) |
Decrease in restricted cash | 227 | 64 | 3 |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,295 | 1,268 | 1,336 |
Purchases of nuclear decommissioning trust investments | (1,352) | (1,392) | (1,334) |
Other | 13 | 22 | 29 |
Net cash used in investing activities | (5,526) | (5,211) | (4,799) |
Cash Flows from Financing Activities | |||
Net issuances (repayments) of commercial paper, net of discount of $6, $3, and $2 at respective dates | (9) | 683 | (583) |
Short-term debt financing | 500 | 0 | 300 |
Short-term debt matured | 0 | (300) | 0 |
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of (for PG&E Corporaiton $17, $27, and $17 and for the Utility $17, $27, and $17, at respective dates) | 983 | 1,123 | 1,961 |
Repayments of long-term debt | (160) | 0 | (539) |
Preferred stock dividends paid | (14) | (14) | (14) |
Common stock dividends paid | (911) | (716) | (716) |
Equity contribution from PG&E Corporation | 835 | 705 | 705 |
Other | (30) | (13) | 43 |
Net cash provided by (used in) financing activities | 1,194 | 1,468 | 1,157 |
Net change in cash and cash equivalents | 12 | 4 | (10) |
Cash and cash equivalents at January 1 | 59 | 55 | 65 |
Cash and cash equivalents at December 31 | 71 | 59 | 55 |
Cash received (paid) for: | |||
Interest, net of amounts capitalized | (717) | (675) | (618) |
Income taxes, net | 244 | 77 | 500 |
Supplemental disclosures of noncash investing and financing activities | |||
Capital expenditures financed through accounts payable | 403 | 440 | 339 |
Terminated Capital Leases | $ 18 | $ 0 | $ 71 |
Consolidated Statements Of Cas8
Consolidated Statements Of Cash Flows (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Cash Flows from Financing Activities | |||
Net issuances of commercial paper, discount | $ 6 | $ 3 | $ 2 |
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs | 17 | 27 | 17 |
Pacific Gas And Electric Company [Member] | |||
Cash Flows from Financing Activities | |||
Net issuances of commercial paper, discount | 6 | 3 | 2 |
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs | $ 17 | $ 27 | $ 14 |
Consolidated Statements Of Equi
Consolidated Statements Of Equity - USD ($) $ in Millions | Total | Pacific Gas And Electric Company [Member] | Common Stock Shares [Member] | Preferred Stock [Member]Pacific Gas And Electric Company [Member] | Common Stock Amount [Member] | Common Stock Amount [Member]Pacific Gas And Electric Company [Member] | Additional Paid-In Capital [Member]Pacific Gas And Electric Company [Member] | Reinvested Earnings [Member] | Reinvested Earnings [Member]Pacific Gas And Electric Company [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Accumulated Other Comprehensive Income (Loss) [Member]Pacific Gas And Electric Company [Member] | Total Shareholders' Equity [Member] | Total Shareholders' Equity [Member]Pacific Gas And Electric Company [Member] | Noncontrolling Interest - Preferred Stock Of Subsidiary [Member] |
Balance at Dec. 31, 2013 | $ 14,594 | $ 258 | $ 9,550 | $ 1,322 | $ 5,821 | $ 4,742 | $ 7,427 | $ 50 | $ 13 | $ 14,342 | $ 14,841 | $ 252 | ||
Balance, in shares at Dec. 31, 2013 | 456,670,424 | |||||||||||||
Net income | 1,450 | $ 1,433 | 1,450 | 1,433 | 1,450 | 1,433 | ||||||||
Other comprehensive income (loss) | (39) | (8) | (39) | (8) | (39) | (8) | ||||||||
Equity contribution from PG&E Corporation | 705 | 705 | 705 | |||||||||||
Common stock issued, net | 823 | 823 | 823 | |||||||||||
Common stock issued, net, shares | 19,242,980 | |||||||||||||
Stock-based compensation amortization | 65 | 65 | 65 | |||||||||||
Tax expense from employee stock plans | (17) | (17) | (12) | (17) | (12) | |||||||||
Common stock dividends declared | (862) | (862) | (716) | (862) | (716) | |||||||||
Preferred stock dividend | (14) | (14) | ||||||||||||
Preferred stock dividend requirement of subsidiary | (14) | (14) | (14) | |||||||||||
Balance at Dec. 31, 2014 | 16,000 | 258 | 10,421 | 1,322 | 6,514 | 5,316 | 8,130 | 11 | 5 | 15,748 | 16,229 | 252 | ||
Balance, in shares at Dec. 31, 2014 | 475,913,404 | |||||||||||||
Net income | 888 | 862 | 888 | 862 | 888 | 862 | ||||||||
Other comprehensive income (loss) | (18) | (2) | (18) | (2) | (18) | (2) | ||||||||
Equity contribution from PG&E Corporation | $ 705 | 705 | 705 | |||||||||||
Common stock issued, net | 801 | 801 | 801 | |||||||||||
Common stock issued, net, shares | 16,112,039 | |||||||||||||
Stock-based compensation amortization | 66 | 66 | 66 | |||||||||||
Tax expense from employee stock plans | (6) | (6) | (4) | (6) | (4) | |||||||||
Common stock dividends declared | (889) | (889) | (716) | (889) | (716) | |||||||||
Preferred stock dividend | (14) | (14) | ||||||||||||
Preferred stock dividend requirement of subsidiary | (14) | (14) | (14) | |||||||||||
Balance at Dec. 31, 2015 | $ 16,828 | 258 | 11,282 | 1,322 | 7,215 | 5,301 | 8,262 | (7) | 3 | 16,576 | 17,060 | 252 | ||
Balance, in shares at Dec. 31, 2015 | 492,025,443 | 264,374,809 | 492,025,443 | |||||||||||
Net income | $ 1,407 | $ 1,402 | 1,407 | 1,402 | 1,407 | 1,402 | ||||||||
Other comprehensive income (loss) | (2) | (1) | (2) | (1) | (2) | (1) | ||||||||
Equity contribution from PG&E Corporation | $ 835 | 835 | 835 | |||||||||||
Common stock issued, net | 842 | 842 | 842 | |||||||||||
Common stock issued, net, shares | 14,866,431 | |||||||||||||
Stock-based compensation amortization | 74 | 74 | 74 | |||||||||||
Common stock dividends declared | (972) | (972) | (911) | (972) | (911) | |||||||||
Preferred stock dividend | (14) | (14) | ||||||||||||
Preferred stock dividend requirement of subsidiary | (14) | (14) | (14) | |||||||||||
Balance at Dec. 31, 2016 | $ 18,192 | $ 258 | $ 12,198 | $ 1,322 | $ 8,050 | 5,751 | 8,763 | $ (9) | $ 2 | 17,940 | 18,395 | $ 252 | ||
Balance, in shares at Dec. 31, 2016 | 506,891,874 | 264,374,809 | 506,891,874 | |||||||||||
Cumulative Effect Of New Accounting Principle In Period Of Adoption | $ 29 | $ 29 | $ 24 | $ 29 | $ 24 |
Organization And Basis Of Prese
Organization And Basis Of Presentation | 12 Months Ended |
Dec. 31, 2016 | |
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 serving 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, operatio n, 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 in consolidation. T he Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment). T he accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabil ities, legal and regulatory contingencies, environmental remediation liabilities, AROs, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statemen ts are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations and cash flows durin g the period in which such change occurred. |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Summary Of Significant Accounting Policies | NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “reve nue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. T he Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally 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 cap italizes 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 recove red. 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 customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, t he Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. (See “Revenue Recognition” below.) Management continues to believe the use of regulatory accounting is applicable a nd that all regulatory assets and liabilities are recoverable or refundable. 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. Revenue Recognition The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unb illed revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. 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 or four years. T he Utility’s ability to recover r evenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility’s sales of electricity and na tural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, revenue is recognized ratably over the y ear. 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. In general, 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 period ic (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. Cash and Cash Equ ivalents 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 Prior to October 2016, restricted cash primarily consisted 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 “ Resolution of Remaining Chapter 11 Disput ed Claims” in Note 13 below.) Allowance for Doubtful Accounts Receivable PG& E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer 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 is recorded to inventory when injected 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 expen sed or capitalized to plant, as appropriate, when consumed or installed. Emission Allowances The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates. Property, Plant, and Equipment Property, plant, and equipment are reported at the lower of their his torical 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) 2016 2015 Electricity generating facilities (1) 5 to 100 $ 11,308 $ 9,860 Electricity distribution facilities 15 to 55 29,836 28,476 Electricity transmission facilities 15 to 75 11,412 10,196 Natural gas distribution facilities 5 to 60 11,362 10,397 Natural gas transmission and storage facilities 5 to 65 6,491 6,352 Construction work in progress 2,184 2,059 Total property, plant, and equipment 72,593 67,340 Accumulated depreciation (22,012) (20,617) Net property, plant, and equipment $ 50,581 $ 46,723 (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 13 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 de preciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.73 % in 2016 , 3.80 % in 2015 , and 3.77% in 2014 . 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 custo mers. 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 before they go into service 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 e quity, respectively, of $ 51 million and $ 112 million during 2016 , $ 48 million and $ 107 million during 2015 , and $ 45 million and $ 100 million during 2014 . Asset Retirement Obligations The following table summarizes the changes in ARO liability during 2016 and 2015 , including nuclear decommissioning obligations: (in millions) 2016 2015 ARO liability at beginning of year $ 3,643 $ 3,575 Revision in estimated cash flows 968 13 Accretion 194 169 Liabilities settled (121) (114) ARO liability at end of year $ 4,684 $ 3,643 The Utility has not recorded a liability related to certain ARO’s for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration or land to the conditions under certain agreements. Nuclear Decommissioning Obligation Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear D ecommissioning Cost Triennial Proceeding conducted by the CPUC. In March 2016, the Utility submitted its updated decommissioning cost estimate to the CPUC. As a result, the estimated undiscounted cost to decommission the Utility’s nuclear power plants in creased by approximately $1.4 billion. The change in total estimated cost resulted in an $818 million adjustment to the ARO. The adjustment was a result of increased estimated costs related to spent fuel storage, staffing, and out-of-state waste disposal . The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The Utility requested that the CPUC authorize the collection of increased annual revenue requirements beginning on January 1, 2017 based on these updated cost estimates. On August 11, 2016, the Utility submitted an application to the CPUC to retire Diablo Canyon at the expiration of its current operating licenses in 2024 (Unit 1) and 2025 (Unit 2). The application includes a joint proposal between the Utility and certain interested parties, entered into on June 20, 2016 , which resulted in a $115 million increase to the ARO recognized on the Consolidated Balance Sheets in June 2016. The Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimated costs of decommissioning its nuclear powe r facilities and records this as an adjustment to the ARO liability on its Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued was $ 3.5 billion and $2.5 billion at December 31, 2016 and 2015 , respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $ 5.1 billion and $3.5 billion at December 31, 2016 and 2015 (or $ 7.3 billion in future dollars), respectively. These estimates are based on the 2016 decommissioning cost studies, prepared in accordance with CPUC requirements. 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. (See “Enforcement and Litigation Matters” in Note 13 below.) Nuclear Decommissioning Trusts The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one 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 Utilit y'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.” Sin ce 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 impair ments. 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 controllin g financial interest in a VIE is a primary beneficiary and is required to consolidate 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 ge nerate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2016, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expect ed 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 performa nce, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated wit h 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, 2016, 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 “Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies and Commitments” in Note 13 herein. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income The changes, net of income tax, in PG& E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2016 consisted of the following: Pension Other (in millions, net of income tax) Benefits Benefits Total Beginning balance $ (23) $ 16 $ (7) Other comprehensive income before reclassifications: Unrecognized prior service cost (net of taxes of $37 and $15, respectively) 54 (21) 33 Unrecognized net actuarial loss (net of taxes of $45 and $15, respectively) (64) 21 (43) Regulatory account transfer (net of taxes of $5 and $0, respectively) 7 - 7 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $3 and $6, respectively) (1) 5 9 14 Amortization of net actuarial loss (net of taxes of $10 and $2, respectively) (1) 14 2 16 Regulatory account transfer (net of taxes of $13 and $8, respectively) (1) (18) (11) (29) Net current period other comprehensive loss (2) - (2) Ending balance $ (25) $ 16 $ (9) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.) The changes, net of income tax, in PG& E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2015 consisted of the following: Pension Other Other (in millions, net of income tax) Benefits Benefits Investments Total Beginning balance $ (21) $ 15 $ 17 $ 11 Other comprehensive income before reclassifications: Unrecognized net actuarial loss (net of taxes of $51, $21, and $0, respectively) (76) (31) - (107) Regulatory account transfer (net of taxes of $51, $21, and $0, respectively) 73 31 - 104 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $7, $8, and $0, respectively) (1) 8 11 - 19 Amortization of net actuarial loss (net of taxes of $4, $1, and $0, respectively) (1) 6 3 - 9 Regulatory account transfer (net of taxes of $10, $9, and $0, respectively) (1) (13) (13) - (26) Realized gain on investments (net of taxes of $0, $0, and $12, respectively) - - (17) (17) Net current period other comprehensive loss (2) 1 (17) (18) Ending balance $ (23) $ 16 $ - $ (7) (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. Recently Adopted Accounting Guidance Share-Based Payment Accounting In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718) , which amends the existing guidance relating to the accounting for share-based payment awards issued to employees, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016. ASU 2016-09 requires recognition of excess tax benefits and deficiencies in the income statement, which resulted in the recognition of $6.3 million in income tax benefit for PG&E Corporation and the Utility for the year ended December 31, 2016. Previously, these amounts were recognized in additional paid-in capital. Previously unrecognized excess tax benefits were reclassified via a cumulative-effect adjustment. ASU 2016-09 also requires excess tax benefits and deficiencies to be prospectively excluded from assumed future proceeds in the calculation of diluted shares when calculating diluted earnings per share utilizing the treasury stock method. The effect of this change on diluted EPS is immaterial. Additionally, excess income tax benefits from stock-based compensation arrangements are now classified as cash flows from operating activities rather than as cash flows from financing activities, which resulted in an increase to cash flows from operating activities of approximately $7.2 million for the year ended December 31, 2016. Furthe rmore, ASU 2016-09 requires, on a retrospective basis, that employee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities. As such, the consolidated statements of cash flo ws for PG&E Corporation and the Utility for the prior periods presented were restated. This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $34.6 million, $26.8 million, and $13.2 million for the years ended December 31, 2016, 2015, and 2014, respectively. PG&E Corporation and the Utility have elected to continue to estimate forfeitures expected to occur to determine the amount of compensation cost to be recognized in each pe riod and have not changed their policy on statutory withholding requirements and will continue to allow the employee to withhold up to the minimum statutory withholding requirements. Fair Value Measurement In May 2015, the FASB issued ASU No. 2015-07, Fa ir Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) , which standardizes reporting practices related to the fair value hierarchy for all investments for which fair va lue is measured using net asset value per share. PG&E Corporation and the Utility adopted this guidance effective January 1, 2016. The adoption of this standard did not have a material impact on their Consolidated Financial Statements. All prior periods presented in these Consolidated Financial Statements reflect the retrospective adoption of this guidance. (See Notes 10 and 11 below.) Accounting for Fees Paid in a Cloud Computing Arrangement In April 2015, the FASB issued ASU No. 2015-05, Intangible s – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement , which adds guidance to help entities evaluate the accounting treatment for cloud computing arrangements. PG&E Corporati on and the Utility adopted this guidance effective January 1, 2016. The adoption of this guidance did not have a material impact on their Consolidated Financial Statements. Presentation of Debt Issuance Costs In April 2015, the FASB issued ASU No. 2015- 03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs , which amends the existing guidance relating to the presentation of debt issuance costs. The amendments in this ASU require that debt issuance cos ts related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. PG&E Corporation and the Utility adopted this guidance effective January 1, 2016 and applied the requirements retrospectively for all periods presented. The adoption of this guidance did not have a material impact on their Consolidated Financial Statements. PG&E Corporation and the Utility restated $105 million and $103 million, respectively, of debt issuance costs as of December 31, 2015 with no impact to net income or total shareholders’ equity previously reported. All prior periods presented in these Consolidated Financial Statements reflect the retrospective adoption of this guidance. Accounting Standards Issued But Not Yet Adopted Restricted Cash In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230) , which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating th e impact the guidance will have on their Consolidated Statements of Cash Flows. Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which amends the existing guidance relating to the recogni tion of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheet, which were previously not recognized. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019 with retrospective application. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidate d Financial Statements and related disclosures. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Fi nancial Assets and Financial Liabilities , which amends the existing guidance relating to the recognition and measurement of financial instruments. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018. PG&E Corporation and t he Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. Revenue Recognition Standard In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, w hich amends existing revenue recognition guidance, effective January 1, 2018 . The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, indu stries, jurisdiction, and capital markets and to provide more useful information to users of financial statements through improved disclosure requirements. PG&E Corporation and the Utility do not plan to early adopt the standard and are currently reviewin g all revenue streams and evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. The Utility does not expect ASU 2014-09 to materially impact the timing or recognition of revenue generated through the sale and delivery of electricity and natural gas to customers. However, th e Utility continues to consider the impacts of outstanding industry-related issues being addressed by the American Institute of CPAs’ Revenue Recognition Working Group and the FASB’s Transition Resource Group. |
Regulatory Assets, Liabilities,
Regulatory Assets, Liabilities, And Balancing Accounts | 12 Months Ended |
Dec. 31, 2016 | |
Regulatory Assets, Liabilities, And Balancing Accounts | NOTE 3: REGULATORY ASSETS, LIABILITIES, AND B ALANCING ACCOUNTS Regulatory Assets Long-term regulatory assets are comprised of the following: Balance at December 31, Recovery (in millions) 2016 2015 Period Pension benefits (1) $ 2,429 $ 2,414 Indefinitely (3) Deferred income taxes (1) 3,859 3,054 47 years Utility retained generation (2) 364 411 9 years Environmental compliance costs (1) 778 748 32 years Price risk management (1) 92 138 10 years Unamortized loss, net of gain, on reacquired debt (1) 76 94 26 years Other 353 170 Various Total long-term regulatory assets $ 7,951 $ 7,029 (1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. (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 thes e 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) Payments into the pension and other benefits plans are based on annu al contribution requirements. As these annual requirements continue indefinitely into the future, 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, and regulatory assets for unamortized loss, net of gain, on reacquired debt. Regulatory Liabilities Long-term regulatory liabilities are comprised of the following: Balance at December 31, (in millions) 2016 2015 Cost of removal obligations (1) $ 5,060 $ 4,605 Recoveries in excess of AROs (2) 626 631 Public purpose programs (3) 567 600 Other 552 485 Total long-term regulatory liabilities $ 6,805 $ 6,321 (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. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory li ability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 10 below.) (3) Represents amounts received from customers designated for public purpo se program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs. Regulatory Balancing Accounts The Utility tracks (1) differences between the Utility’s authorized revenue requirement and 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. Regu latory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Bala nce Sheets. These differences do not have an impact on net income. Balancing accounts 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 regula tory balancing accounts receivable and payable are comprised of the following: Receivable Balance at December 31, (in millions) 2016 2015 Electric distribution $ 132 $ 380 Utility generation 48 122 Gas distribution and transmission 541 493 Energy procurement 132 262 Public purpose programs 106 155 Other 541 348 Total regulatory balancing accounts receivable $ 1,500 $ 1,760 Payable Balance at December 31, (in millions) 2016 2015 Gas distribution and transmission $ 48 $ - Energy procurement 13 112 Public purpose programs 264 244 Other 320 359 Total regulatory balancing accounts payable $ 645 $ 715 The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case. Energy procurement balancing accounts track recovery of costs related to the procurement of elect ricity, including any environmental compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2016 | |
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) 2016 2015 PG&E Corporation Senior notes: Maturity Interest Rates 2019 2.40% 350 350 Unamortized discount, net of premium and debt issuance costs (2) (2) Total PG&E Corporation long-term debt 348 348 Utility Senior notes: Maturity Interest Rates 2017 5.625% 700 700 2018 8.25% 800 800 2020 3.50% 800 800 2021 3.25% to 4.25% 550 550 2022 through 2046 2.45% to 6.35% 12,775 11,775 Less: current portion (700) - Unamortized discount, net of premium and debt issuance costs (161) (156) Total senior notes, net of current portion 14,764 14,469 Pollution control bonds: Maturity Interest Rates Series 2004 A-D, due 2023 (1) 4.75% 345 345 Series 2009 A-D, due 2026 (2) variable rate (4) 149 309 Series 1996 C, E, F, 1997 B due 2026 (3) variable rate (5) 614 614 Less: current portion - (160) Total pollution control bonds 1,108 1,108 Total Utility long-term debt, net of current portion 15,872 15,577 Total consolidated long-term debt, net of current portion $ 16,220 $ 15,925 (1) The Utility has obtained credit support from an insurance company for these bonds. (2) Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit faci lity without issuer consent. Series C and D pollution control bonds were redeemed on November 30, 2016. (3) Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended to December 1, 2020. 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 cre dit facility. (4) At December 31, 2016 , the interest rate on these bonds was 0.74 %. (5) At December 31, 2016, the interest rate on thes e bonds ranged from 0.72% - 0.73%. 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 sales 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. Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, 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 long-term debt principal repayment amounts at December 31, 2016 are reflected in the table below: (in millions, except interest rates) 2017 2018 2019 2020 2021 Thereafter Total PG&E Corporation Average fixed interest rate - - 2.40% - - - 2.40% Fixed rate obligations $ - $ - $ 350 $ - $ - $ - $ 350 Utility Average fixed interest rate 5.6 25 % 8.25% - 3.50% 3.80% 4.84% 4.94% Fixed rate obligations $ 700 $ 800 $ - $ 800 $ 550 $ 13,120 $ 15,970 Variable interest rate as of December 31, 2016 - - 0.74% 0.73% - - 0.73% Variable rate obligations (1) $ - $ - $ 149 $ 614 $ - $ - $ 763 Total consolidated debt $ 700 $ 800 $ 499 $ 1,414 $ 550 $ 13,120 $ 17,083 (1) The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019, or December 1, 2020. Short-term Borrowings The following table summarizes PG& E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at December 31, 2016 : Credit Letters of Commercial Termination Facility Credit Paper Facility (in millions) Date Limit Outstanding Outstanding Availability PG&E Corporation April 2021 $ 300 (1) $ - $ - $ 300 Utility April 2021 3,000 (2) 41 1,016 1,943 Total revolving credit facilities $ 3,300 $ 41 $ 1,016 $ 2,243 (1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans. For the year ended December 31, 2016 , PG&E Corporation’s average outstanding commercial paper balance was $ 84 million and the maximum outstanding balance during the year was $ 176 million. For 2016 , the Utility’s average outstanding commercial paper balance was $ 837 million an d the maximum outstanding balance during the year was $ 1.4 billion. There were no bank borrowings for PG&E Corporation or the Utility in 2016 . Revolving Credit Facilities In June 2016, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2020 to April 27, 2021. PG&E C orporation'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 fac ilities may be extended for one additional period. Borrowings under each credit agreement (other than swingline loans) will bear interest based, at each borrower’s election, on (1) a London Interbank Offered Rate (“LIBOR”) 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 overnight federal funds rate, and the one-month LIBOR plus an applicable margin. The applicabl e margin for LIBOR loans will range between 0.9% and 1.475% under PG&E Corporation’s credit agreement and between 0.8% and 1.275% under the Utility’s credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E C orporation’s credit agreement and between 0% and 0.275% under the Utility’s credit agreement. In addition, the facility fee under PG&E Corporation’s and the Utility’s credit agreements will range between 0.1% and 0.275% and between 0.075% and 0.225%, resp ectively. 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 un der their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes. In addition, the respective revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total co nsolidated 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 outstandi ng common stock and at least 70% of the outstanding voting capital stock of the Utility. Commercial Paper Programs The borrowings from PG&E Corporation’s and the Utility’s commercial paper programs are used primarily to fund temporary financing needs. PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, respectively. PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a reduction to the amount available u nder their respective revolving credit facilities. 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. For 2016, the average yield on outstanding PG&E Corporation and Utility commercial paper was 0.63 % and 0.64 % , respectively. Other Short-term Borrowings In March 2016, the Utility entered into a $250 million floating rate unsecured term loan that matures on February 2, 2017. Additionally, in December 2016, the Utility issued a $250 million unsecured senior floating rate note that matures on November 30, 2017. The proceeds were used for general corporate purposes, including the repa yment of a portion of the Utility’s outstanding commercial paper. |
Common Stock And Share-Based Co
Common Stock And Share-Based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
Common Stock And Share-Based Compensation | NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION PG&E Corporation had 506,891,874 shares of common stock outstanding at December 31, 2016 . PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2016 . During 2016 , PG&E Corporation sold 2.6 million shares of common stock under the February 2015 equity distribution agreement for cash proceeds of $ 149 million, net of commissions paid of $ 1.3 million. As of December 31, 2016, the remaining gross sales available under this agreement were $275 million. In August 2016, PG&E Corporation sold 4.9 million shares of its common stock in an underwritten public offering for net cash p roceeds of $309 million. In addition, during 2016 , PG&E Corporation sold 7.4 million shares of common stock under its 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans for total cash proceeds of $ 364 million. Dividends The Board of Directors of PG&E Corp oration 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 the first qua rter of 2016, the Board of Directors of PG&E Corporation declared a common stock dividend of $0.455 per share . In May 2016, the Board of Directors of PG&E Corporation adopted a new quarterly common stock dividend of $0.49 per share. In 2016, total dividen ds were $1.925 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%. Additionally, the CPUC requires the Utili ty to maintain a capital structure composed of at least 52% equity on a weighted average over five years. At December 31, 2016, the Utility had restricted net assets of $ 15.8 billion and was limited to $ 25 million of additional common stock dividends it could pay to PG&E Corporation. Long-Term Incentive Plan The PG&E Corporation LTIP permits various forms of share-based incentive awards, including restricted stock awards, restricted s tock units, performance shares, 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 17 million shar es of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the 2014 LTIP, of which 13,826,995 shares were available for future awards at December 31, 2016 . The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2016 , 2015 , and 2014 : (in millions) 2016 2015 2014 Restricted stock units $ 53 $ 47 $ 42 Performance shares 55 46 36 Total compensation expense (pre-tax) $ 108 $ 93 $ 78 Total compensation expense (after-tax) $ 64 $ 55 $ 47 The amount of share-based compensation costs capitalized during 2016 , 2015 , and 2014 was immaterial. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Restricted Stock Units Prior to 2014, restricted stock units generally vested over four years 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. Restricted stock units granted after 2014 generally vest equally over three years. Vested restricted stock units are settle d in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units. Compensation expense is generally recognized rateably over the vesting period based on grant-da te fair value. The weighted average grant-date fair value for restricted stock units granted during 2016 , 2015 , and 2014 was $ 56.68 , $53.30, and $43.76, res pectively. The total fair value of restricted stock units that vested during 2016 , 2015 , and 2014 was $ 36 million, $57 million, and $34 million, respectively. The tax benefit from restricted stock units that vested during each period was not material. In general, forfeitures are recorded rateably over the vesting period, using historical averages and adjusted to actuals when vesting occu rs. As of December 31, 2016 , $ 37 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.22 years. The following table summarizes restricted stock unit activity for 2016 : Number of Weighted Average Grant- Restricted Stock Units Date Fair Value Nonvested at January 1 1,972,899 $ 47.33 Granted 776,312 $ 56.68 Vested (770,968) $ 46.79 Forfeited (55,233) $ 49.65 Nonvested at December 31 1,923,010 $ 51.26 Performance Shares Performance shares generally will vest three years after the grant date. Upon vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period or , for a small number of awards, an internal PG&E Corporation metric. Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled. Compensation expense attributable to performance share is generally recognized rateably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the total shareholder return based awards or the grant-date market value of PG&E Corporation common s tock for internal metric based awards. The weighted average grant-date fair value for performance shares granted during 2016 , 2015 , and 2014 was $ 53.61 , $68.27, and $51.81 respectively. There was no tax benefit associated with performance shares during each of these periods. In general, forfeitures are recorded rateably over the vesting period, using historical averages and adjusted to actuals when vesti ng occurs. As of December 31, 2016 , $ 40 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.57 years. The following table summarizes activity for performance shares in 2016 : Number of Weighted Average Grant- Performance Shares Date Fair Value Nonvested at January 1 1,450,612 $ 59.24 Granted 1,233,884 53.61 Vested (777,719) 51.81 Forfeited (1) (67,922) 58.20 Nonvested at December 31 1,838,855 $ 58.65 (1) Includes performance shares that expired with zero value as performance targets were not met. |
Preferred Stock
Preferred Stock | 12 Months Ended |
Dec. 31, 2016 | |
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 sh ares of $ 25 par value preferred stock and 10 million shares of $ 100 par value preferred stock. At December 31, 2016 and December 31, 2015, the Utility’s preferred stock outstanding included $ 145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $ 113 million of shares with interest rates between 4.36% and 5% that are redeemable between $ 25.75 and $ 27.25 per share. The Utility’s preferred stock outstanding are not subject to mandatory redemption. All outstandin g preferred stock has a $25 par value. At December 31, 2016 , 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, 2016 , 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 preferr ed stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The Utility paid $ 14 million of dividends on preferred stock in each of 2016 , 2015, and 2014. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 , 2015 , and 2014 . Year Ended December 31, (in millions, except per share amounts) 2016 2015 2014 Income available for common shareholders $ 1,393 $ 874 $ 1,436 Weighted average common shares outstanding, basic 499 484 468 Add incremental shares from assumed conversions: Employee share-based compensation 2 3 2 Weighted average common share outstanding, diluted 501 487 470 Total earnings per common share, diluted $ 2.78 $ 1.79 $ 3.06 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 | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes | NOTE 8: INCOME TAXES PG&E Corporation and the Utility use the asset and 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. 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 ta x 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 re turn in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortiz es its investment tax credits over the projected investment recovery period. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment. PG&E Corporation files a consolidated U.S. federa l 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 agreemen t under which the Utility determines its income tax provision (benefit) on a stand-alone basis. The significant components of income tax provision (benefit) by taxing jurisdiction were as follows: PG&E Corporation Utility Year Ended December 31, (in millions) 2016 2015 2014 2016 2015 2014 Current: Federal $ (105) $ (89) $ (84) $ (105) $ (88) $ (84) State (70) 11 (41) (66) 6 (29) Defe rred: Federal 218 131 396 229 136 426 Stat e 16 (76) 78 16 (69) 75 Tax credits (4) (4) (4) (4) (4) (4) Inco me tax provision (benefit) $ 55 $ (27) $ 345 $ 70 $ (19) $ 384 The following table describes net deferred income tax liabilities: PG&E Corporation Utility Year Ended December 31, (in millions) 2016 2015 2016 2015 Deferred income tax assets: Tax carryforwards 1,851 1,703 1,596 1,462 Other (1) 463 757 402 700 Total deferred income tax assets $ 2,314 $ 2,460 $ 1,998 $ 2,162 D eferred income tax liabilities: Property related basis differences 10,429 9,656 10,411 9,638 Income tax regulatory asset (2) 1,572 1,244 1,572 1,245 Other (3) 526 766 525 766 Total deferred income tax liabilities $ 12,527 $ 11,666 $ 12,508 $ 11,649 Total net deferred income tax liabilities $ 10,213 $ 9,206 $ 10,510 $ 9,487 (1) Amounts include compensation and benefits, environmental reserve, and customer advances for construction. (2) Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.) (3) Amounts primarily relate to regulatory balancing accounts. Greenhouse gas allowances are temporary timing differences that reverse through regulatory balancing accounts. 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, 2016 2015 2014 2016 2015 2014 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) (1) (2.5) (4.9) 1.4 (2.2) (4.8) 1.6 Effect of regulatory treatment of fixed asset differences (2) (23.7) (33.6) (15.0) (23.4) (33.7) (14.7) Tax credits (0.8) (1.3) (0.7) (0.8) (1.3) (0.7) Benefit of loss carryback (1.1) (1.5) (0.8) (1.1) (1.5) (0.8) Non deductible penalties (3) 0.8 4.3 0.3 0.8 4.3 0.3 Other, net (4) (3.9) (1.1) (0.8) (3.5) (0.2) 0.4 Effective tax rate 3.8 % (3.1) % 19.4 % 4.8 % (2.2) % 21.1 % (1) Includes the effect of state flow-through ratemaking treatment. In 2016 and 2015, amounts include an agreement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 2014 GRC decision in all periods presented and by the 2015 GT&S decision which impacts only 2016. All amounts are impacted by the level of income before income taxes. The 2014 GRC and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related c osts for federal tax purposes. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Ut ility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to cus tomers in future rates. (3) Primarily represents the effects of non-tax deductible fines and penalties associated with the natural gas distribution facilities record-keeping decision for the year ended December 31, 2016 and the effects of the Penalty Dec ision for the year ended December 31, 2015. For more information about the Penalty Decision see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8. (4) In 2016, the amount primarily represents t he impact of tax audit settlements. Unrecognized tax benefits The following table reconciles the changes in unrecognized tax benefits: PG&E Corporation Utility (in millions) 2016 2015 2014 2016 2015 2014 Balance at beginning of year $ 468 $ 713 $ 666 $ 462 $ 707 $ 660 Additions for tax position taken during a prior year - 40 7 - 40 7 Reductions for tax position taken d uring a prior year (77) (349) (9) (77) (349) (9) Additio ns for tax position taken during the current year 56 64 61 56 64 61 Settlements (59) - (12) (59) - (12) Balance at end of year $ 388 $ 468 $ 713 $ 382 $ 462 $ 707 The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 3 1, 2016 for PG&E Corporation and the Utility was $ 25 million. PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly wi thin the next 12 months due to the resolution of several matters, including audits. As of December 31, 2016, it is reasonably possible that unrecognized tax benefits will decrease by approximately $ 70 million within the next 12 months. PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income. Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income. For the years ended December 31, 2016, 2015, and 2014, these amounts were immaterial. IRS settlements PG&E Corporation previously participated 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. PG&E Corporation’s participation in the Compliance Assurance Process ended effective with the submission of its 2015 tax return . PG&E Corporation’s tax returns have been accepted through 2015 except for a few matters, the most significant of which relates to deductible repair costs. In March 2016, PG&E Corporation reached an agreement with the IRS on deductible electric transmis sion and distribution repair costs for the 2012 tax year. The agreement provided that the methodology used in determining the deductible amount should be followed for all subsequent periods, absent any material change in facts. Deductible repair costs fo r other lines of business will continue to be subject to examination by the IRS for subsequent years. The IRS is expected to issue guidance in 2017 that clarifies which repair costs are deductible for the natural gas transmission and distribution business es. Tax years after 2008 remain subject to examination by the state of California. 2015 Gas Transmission and Storage Rate Case In comments to the proposed decision in phase two of the 2015 GT&S rate case , the Utility questioned whether the methodology employed to calculate the capital disallowance portion of the San Bruno penalty might constitute a normalization violation. In recognition of this concern, the CPUC, in the final phase two decision, provided the Utility an opportunity to submit a ruling to the IRS for guidance and establish a memorandum account to track the additional revenue that would be recoverable if the method is deemed to be a normalization violation. The Utility anticipates filing the ruling request in early 2017. As a result of the final phase two decision, PG&E Corporation and the Utility applied flow through accounting to property-related timing differences for 2016 and 2015. Carryforwards The following table describes PG&E Corporation’s operating loss and tax credit carryfo rward balances: December 31, Expiration (in millions) 2016 Year Federal: Net operating loss carryforward $ 5,009 2029 - 2036 Tax credit carryforward 116 2029 - 2036 Charitable contribution loss carryforward 192 2017 - 2021 State: Net operating loss carryforward $ - N/A Tax credit carryforward 51 Various Charitable contribution loss carryforward 112 2019 - 2021 PG&E Corporation believes it is more likely than not the tax benefits associated with the federal and California net operating losses, charitable contributions and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of December 31, 2016 for these tax attributes. |
Derivatives And Hedging Activit
Derivatives And Hedging Activities | 12 Months Ended |
Dec. 31, 2016 | |
Derivatives And Hedging Activities | NOTE 9: DERIVATIVES Use of Deriv ative Instruments The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include forward contracts, swaps, futures, options, and CRRs. Derivatives are presented in the Utility’s Consolidated Balance Sheets on a net basis in accordance wit h master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all co sts related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the chan ge 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. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those t hat 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. These items are not reflected in the Consolidated Balance Sheets at fair value. Eligible derivatives are accounted for under the accrual method of accounting. Volume of Derivative Activity At December 31, 2016 and 2015 , respectively, the volumes of the Utility’s outstanding derivatives were as follows: Contract Volume Underlying Product Instruments 2016 2015 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 323,301,331 333,091,813 Options 96,602,785 111,550,004 Electricity (Megawatt-hours) Forwards and Swaps 3,287,397 3,663,512 Congestion Revenue Rights (3) 278,143,281 216,383,389 (1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges du e to transmission grid limitations. Presentation of Derivative Instruments in the Financial Statements At December 31, 2016 , 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 $ 91 $ (10) $ 1 $ 82 Other noncurrent assets – other 149 (9) - 140 Current liabilities – other (48) 10 - (38) Noncurrent liabilities – other (101) 9 3 (89) Total commodity risk $ 91 $ - $ 4 $ 95 At December 31, 2015 , 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 $ 97 $ (4) $ 25 $ 118 Other noncurrent assets – other 172 (2) - 170 Current liabilities – other (102) 4 44 (54) Noncurrent liabilities – other (140) 2 21 (117) Total commodity risk $ 27 $ - $ 90 $ 117 Gains and losses associated with price risk management activities were recorded as follows: Commodity Risk For the year ended December 31, (in millions) 2016 2015 2014 Unrealized gain/(loss) - regulatory assets and liabilities (1) $ 64 $ (6) $ 124 Realized loss - cost of electricity (2) (53) (14) (83) Realized loss - cost of natural gas (2) (18) (10) (8) Total commodity risk $ (7) $ (30) $ 33 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Consolidated Statements of Income. These amounts exclude the impact of cash col lateral 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 fl ows on 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, 2016 , 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 deriv ative 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) 2016 2015 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (24) $ (2) Related derivatives in an asset position 19 - Collateral posting in the normal course of business related to these derivatives 4 - Net position of derivative contracts/additional collateral posting requirements (1) $ (1) $ (2) (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 | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Measurements | NOTE 10: FAIR VALUE MEASUREMENTS PG&E Corporation and the Utility measure their cash equi valents, trust assets and price risk management instruments 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 fa ir 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 a re summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements At December 31, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 105 $ - $ - $ - $ 105 Nuclear decommissioning trusts Short-term investments 9 - - - 9 Global equity securities 1,724 - - - 1,724 Fixed-income securities 665 527 - - 1,192 Assets measured at NAV - - - - 14 Total nuclear decommissioning trusts (2) 2,398 527 - - 2,939 Price risk management instruments (Note 9) Electricity 30 18 181 (18) 211 Gas - 11 - - 11 Total price risk management 30 29 181 (18) 222 instruments Rabbi trusts Fixed-income securities - 61 - - 61 Life insurance contracts - 70 - - 70 Total rabbi trusts - 131 - - 131 Long-term disability trust Short-term investments 8 - - - 8 Assets measured at NAV - - - - 170 Total long-term disability trust 8 - - - 178 TOTAL ASSETS $ 2,541 $ 687 $ 181 $ (18) $ 3,575 Liabilities: Price risk management instruments (Note 9) Electricity $ 9 $ 12 $ 126 $ (21) $ 126 Gas - 2 - (1) 1 TOTAL LIABILITIES $ 9 $ 14 $ 126 $ (22) $ 127 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 333 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2015 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 64 $ - $ - $ - $ 64 Nuclear decommissioning trusts Short-term investments 36 - - - 36 Global equity securities 1,520 - - - 1,520 Fixed-income securities 694 521 - - 1,215 Assets measured at NAV - - - - 13 Total nuclear decommissioning trusts (2) 2,250 521 - - 2,784 Price risk management instruments (Note 9) Electricity - 9 259 18 286 Gas - 1 - 1 2 Total price risk management instruments - 10 259 19 288 Rabbi trusts Fixed-income securities - 57 - - 57 Life insurance contracts - 70 - - 70 Total rabbi trusts - 127 - - 127 Long-term disability trust Short-term investments 7 - - - 7 Assets measured at NAV - - - - 158 Total long-term disability trust 7 - - - 165 TOTAL ASSETS $ 2,321 $ 658 $ 259 $ 19 $ 3,428 Liabilities: Price risk management instruments (Note 9) Electricity $ 69 $ 1 $ 170 $ (70) $ 170 Gas - 2 - (1) 1 TOTAL LIABILITIES $ 69 $ 3 $ 170 $ (71) $ 171 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value. V aluation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. Equity investments valued at net asset value per share utilize investment strategies aimed at matching the performance of indexed funds. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the years ended December 31, 2016 and 2015 . Trust Assets In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1. Global equity securities primarily include investments in common stock that are valued based on quoted pr ices in active markets and are classified as Level 1. Fixed-income 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 s ecurities 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. Th e external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. On January 1, 2016, PG&E Corporation and the Utility adopted FASB ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) and applied it retrospectively for the periods presented in their Consolidated Financial Statements. (See Note 2 above.) In accordance with this guidance, inve stments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are inclu ded in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities tha t are composed primarily of U.S. government securities and asset-backed securities. There are no restrictions on the terms and conditions upon which the investments may be redeemed. Price Risk Management Instruments Price risk management instruments i nclude 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 discou nted 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 extrapolati on from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inp uts from brokers and historical data. The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3. Level 3 Measurements and Sensitivity Analysis The Utility’s market and credit risk management function, which reports to the Chief Financial Officer, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used a nd the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. 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) At December 31, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 181 $ 35 Market approach CRR auction prices $ (11.88) - 6.93 Power purchase agreements $ - $ 91 Discounted cash flow Forward prices $ 18.07 - 38.80 Represents price per megawatt-hour Fair Value at (in millions) At December 31, 2015 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 259 $ 63 Market approach CRR auction prices $ (161.36) - 8.76 Power pur chase agreements $ - $ 107 Discounted cash flow Forward prices $ 15.08 - 37.27 (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, 2016 and 2015 , respectively: Price Risk Management Instruments (in millions) 2016 2015 Asset (liability) balance as of January 1 $ 89 $ 69 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (34) 20 Asset (liability) balance as of December 31 $ 55 $ 89 (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, floating rate senior notes, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2016 an d 2015 , 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 we re based on quoted market prices at December 31, 2016 and 2015 . The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes fina ncial instruments with carrying values that approximate their fair values): At December 31, 2016 2015 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 4) PG&E Corporation $ 348 $ 352 $ 348 $ 354 Utility 15,813 17,790 14,818 16,422 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, 2016 Nuclear decommissioning trusts Short-term investments $ 9 $ - $ - $ 9 Global equity securities 584 1,157 (3) 1,738 Fixed-income securities 1,156 48 (12) 1,192 Total (1) $ 1,749 $ 1,205 $ (15) $ 2,939 As of December 31, 2015 Nuclear decommissioning trusts Short-term investments $ 36 $ - $ - $ 36 Global equity securities 508 1,034 (9) 1,533 Fixed-income securities 1,165 58 (8) 1,215 Total (1) $ 1,709 $ 1,092 $ (17) $ 2,784 (1) Represents amounts before deducting $ 333 million and $314 million at December 31, 2016 and 2015 , respectively, primarily related to deferred taxes on appreciation of investment value. The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) December 31, 2016 Less than 1 year $ 13 1–5 years 419 5–10 years 255 More than 10 years 505 Total maturities of fixed-income securities $ 1,192 The following table provides a summary of activity for the fixed-income and equity securities: 2016 2015 2014 (in millions) Proceeds from sales and maturities of nuclear decommissioning investments $ 1,295 $ 1,268 $ 1,336 Gross realized gains on securities held as available-for-sale 18 55 118 Gross realized losses on securities held as available-for-sale (26) (37) (12) |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2016 | |
Employee Benefit Plans | NOTE 11: EMPLOYEE BENEFIT PLANS Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”) PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”). The trusts underlying certain of these plans are qualified trusts under th e 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’s and the Utility’s funding policy is to contr ibute 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 is ze ro. PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. PG&E Corporation and t he Utility use a fiscal year-end measurement date for all plans. Change in Plan Assets, Benefit Obligations, and Funded Status The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded s tatus for pension benefits and other benefits for PG&E Corporation during 2016 and 2015 : Pension Plan (in millions) 2016 2015 Change in plan assets: Fair value of plan assets at beginning of year $ 13,745 $ 14,216 Actual return on plan assets 1,358 (176) Company contributions 334 334 Benefits and expenses paid (708) (629) Fair value of plan assets at end of year $ 14,729 $ 13,745 Change in benefit obligation: Benefit obligation at beginning of year $ 16,299 $ 16,696 Service cost for benefits earned 453 479 Interest cost 715 673 Actuarial (gain) loss 637 (922) Plan amendments (91) 1 Transitional costs - 1 Benefits and expenses paid (708) (629) Benefit obligation at end of year (1) $ 17,305 $ 16,299 Funded Status: Current liability $ (7) $ (6) Noncurrent liability (2,569) (2,547) Net liability at end of year $ (2,576) $ (2,553) ( 1) PG& E Corporation’s accumulated benefit obligation was $15.6 billion and $14.7 billion at December 31, 2016 and 2015 , respectively. Postretirement Benefits Other t han Pensions (in millions) 2016 2015 Change in plan assets: Fair value of plan assets at beginning of year $ 2,035 $ 2,092 Actual return on plan assets 167 (26) Company contributions 52 61 Plan participant contribution 85 68 Benefits and expenses paid (166) (160) Fair value of plan assets at end of year $ 2,173 $ 2,035 Change in benefit obligation: Benefit obligation at beginning of year $ 1,766 $ 1,811 Service cost for benefits earned 52 55 Interest cost 76 71 Actuarial (gain) loss 11 (98) Plan amendments 37 - Transitional costs - 1 Benefits and expenses paid (153) (146) Federal subsidy on benefits paid 3 4 Plan participant contributions 85 68 Benefit obligation at end of year $ 1,877 $ 1,766 Funded Status: (1) Noncurrent asset $ 368 $ 344 Noncurrent liability (72) (75) Net asset at end of year $ 296 $ 269 (1) At December 31, 2016 and 2015 , the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Compon ents of Net Periodic Benefit Cost Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows: Pension Plan (in millions) 2016 2015 2014 Service cost $ 453 $ 479 $ 383 Interest cost 715 673 695 Expected return on plan assets (828) (873) (807) Amortization of prior service cost 8 15 20 Amortization of net actuarial loss 24 10 2 Net periodic benefit cost 372 304 293 Less: transfer to regulatory account (1) (34) 34 42 Tota l expense recognized $ 338 $ 338 $ 335 (1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates. Postretirement Benefits Other than Pensions (in millions) 2016 2015 2014 Service cost $ 52 $ 55 $ 45 Interest cost 76 71 76 Expected return on plan assets (107) (112) (103) Amortization of prior service cost 15 19 23 Amortization of net actuarial loss 4 4 2 Net periodic benefit cost $ 40 $ 37 $ 43 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 unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax. In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions. For pension ben efits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts th at would otherwise be recorded to accumulated other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss). The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2017 are as follows: (in millions) Pension Plan PBOP Plans Unrecognized prior service cost $ (7) $ 15 Unrecognized net loss 22 4 Total $ 15 $ 19 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 Plan PBOP Plans December 31, December 31, 2016 2015 2014 2016 2015 2014 Discount rate 4.11 % 4.37 % 4.00 % 4.05 - 4.19 % 4.27 - 4.48 % 3.89 - 4.09 % Rate of future compensation increases 4.00 % 4.00 % 4.00 % - - - Expected return on plan assets 5.30 % 6.10 % 6.20 % 2.80 - 6.00 % 3.20 - 6.60 % 3.30 - 6.70 % The assumed health care cost trend rate as of December 31, 2016 was 7.2 %, decreasing gradually to an ultimate trend rate in 2025 and beyond of approximately 4.5 % . A one-percentage-point change in assumed health care cost trend rate would have the following effects: One-Perc entage-Point One-Percentage-Point (in millions) Increase Decrease Effect on postretirement benefit obligation $ 118 $ (120) Effect on service and interest cost 9 (10) 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 inve stments 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 5.3 % compares to a ten-year actual return of 7.3 %. The rate used to discount pension benefits and other benefits was based on a yield curve devel oped from market data of over approximately 696 Aa-grade non-callable bonds at December 31, 2016 . 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 Strate gies The financial position of PG&E Corporation’s and the Utility’s 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 liab ility values and can result in fluctuations in costs in 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 pol icies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility. The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings. Inte rest 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 trusts’ fixed income portfolio market values, interest rate changes also influence liability valuati ons as discount rates move with current bond yields. To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity in vestments are held to reduce long-term funding costs due to their higher expected return. 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 correlat ion to the direction of these markets. R eal assets include commodities futures, global REITS, global listed infrastructure equities, and private real estate funds. Absolute return investments include hedge fund portfolios. In the Pension Plan, target al locations for 2017 were updated to reflect a 2% increase in global equity investments and a 2% decrease in fixed income investments. Target allocations for PBOP Plans remain unchanged. Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a port ion of the non U.S. dollar exposure of global equity investments. The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows: Pension Plan PBOP Plans 2017 2016 2015 2017 2016 2015 Global equity 27 % 25 % 25 % 32 % 32 % 31 % Absolute return 5 % 5 % 5 % 3 % 3 % 3 % Real assets 10 % 10 % 10 % 7 % 7 % 8 % Fixed income 58 % 60 % 60 % 58 % 58 % 58 % Total 100 % 100 % 100 % 100 % 100 % 100 % 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 an d 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 appropriat e use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments. 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, 2016 and 2015 . Fair Value Measurements At December 31, 2016 2015 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 364 $ 369 $ - $ 733 $ 247 $ 375 $ - $ 622 Global equity 996 - - 996 903 - - 903 Real assets 610 - - 610 581 - - 581 Fixed-income 1,754 4,774 5 6,533 1,841 4,495 3 6,339 Assets measured at NAV - - - 5,950 - - - 5,308 Total $ 3,724 $ 5,143 $ 5 $ 14,822 $ 3,572 $ 4,870 $ 3 $ 13,753 PBOP Plans: Short-term investments $ 33 $ - $ - $ 33 $ 20 $ - $ - $ 20 Global equity 115 - - 115 104 - - 104 Real assets 70 - - 70 69 - - 69 Fixed-income 150 656 - 806 150 632 - 782 Assets measured at NAV - - - 1,153 - - - 1,065 Total $ 368 $ 656 $ - $ 2,177 $ 343 $ 632 $ - $ 2,040 Total plan assets at fair value $ 16,999 $ 15,793 In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $ 97 million and $13 million at December 31, 2016 and 2015 , respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable. 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. Short-Term Investments Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets. Global Equity The global equity category includes investments in common sto ck and equity-index futures. 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. Real Assets The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and priv ate real estate funds. The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets. Fixed-Income Fixed-income 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 mode l, as applicable. Assets Measured at NAV On January 1, 2016, PG&E Corporation and the Utility adopted FASB ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or I ts Equivalent) and applied it retrospectively for the periods presented in their Consolidated Financial Statements. (See Note 2 above.) In accordance with this guidance, investments in the pension and PBOP plans that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investme nts include commingled funds that are composed of equity securities traded publicly on exchanges, hedge funds, private real estate funds, and fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities. Tr ansfers Between Levels Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. No material transfers between levels occurred in the years ended December 31, 2016 and 2015 . Level 3 Reconciliation The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2016 and 2015 : (in millions) Fixed- For the year ended December 31, 2016 Income Balance at beginning of year $ 3 Actual return on plan assets: Relating to assets still held at the reporting date 3 Relating to assets sold during the period - Purchases, issuances, sales, and settlements: Purchases - Settlements (1) Balance at end of year $ 5 (in millions) Fixed- For the year ended December 31, 2015 Income Balance at beginning of year $ 12 Actual return on plan assets: Relating to assets still held at the reporting date (3) Relating to assets sold during the period 1 Purchases, issuances, sales, and settlements: Purchases 2 Settlements (9) Balance at end of year $ 3 There were no material transfers out of Level 3 in 2016 and 2015 . Cash Flow Information Employer Contributions PG&E Corporation and the Utility contributed $ 334 million to t he pension benefit plans and $ 52 million to the other benefit plans in 2016 . 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 2016 . 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 $ 61 million to the pension plan and other postretirement benefit plans, respectively, for 2017 . Benefits Payments and Receipts As of December 31, 2016 , 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: Pension PBOP Federal (in millions) Plan Plans Subsidy 2017 $ 739 $ 87 $ (8) 2018 781 93 (9) 2019 821 97 (10) 2020 857 103 (10) 2021 892 108 (11) Thereafter in the succeeding five years 4,879 592 (15) 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 Utili ty for the years presented above. Retirement Savings Plan PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended. This plan permits eligible em ployees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants. Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated St atements of Income were $ 97 million, $89 million, and $80 million in 2016 , 2015 , and 2014 , respectively. There were no materia l differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above. |
Related Party Agreements And Tr
Related Party Agreements And Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Agreements And Transactions | NOTE 12: 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 general ly 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 acc ounting requirements of its regulatory agencies. The Utility’s significant related party transactions were: Year Ended December 31, (in millions) 2016 2015 2014 Utility revenues from: Administrative services provided to PG&E Corporation $ 7 $ 6 $ 5 Utility expenses from: Administrative services received from PG&E Corporation $ 74 $ 53 $ 54 Utility employee benefit due to PG&E Corporation 91 82 70 At December 31, 2016 and 2015 , the Utility had receivables of $ 18 million and $22 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 $ 22 million and $21 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets. |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies | NOTE 13: CONTINGENCIES AND COMMITMENTS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. 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 re asonably 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 reasonably possible, and whether the loss o r 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, settlem ents 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. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation has financial commitments described in “Other Commitme nts” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters. Enforcement and Litigation Matters CPUC Matters Order Instituting an Investigation into Compliance with Ex Parte Communication Rules During 2014 and 2015, the Utility filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte commu nications that either should not have occurred or that should have been timely reported to the CPUC. Ex parte communications include communications between a decision maker or a commissioner’s advisor and interested persons concerning substantive issues i n certain formal proceedings. Certain communications are prohibited and others are permissible with proper noticing and reporting. On November 23, 2015, the CPUC issued an OII into whether the Utility should be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the CPUC’s Rules of Practice and Procedure governing the conduct of those appearing before the CPUC. The OII cites some of the communications the Utility reported to the CPUC. The OII also cites the ex parte vio lations alleged in the City of San Bruno’s July 2014 motion, which it filed in CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices. On October 14, 2016, the Cities of San Bruno and San Carlos, ORA, the SED, TURN, and the Utility submitted a status report to the CPUC which proposed an update to the framework for resolving the proceeding. The revised framework includes a total of 164 communications in the scope of the proceeding. Throughout 2016, the par ties jointly submitted stipulations on all of the communications, and on November 30, 2016, the parties began settlement discussions. In the event a settlement cannot be reached, the parties will brief the matter based upon the identified communications a nd some related discovery as well as factual stipulations and agreed upon issues of policy and law for CPUC resolution. The opening briefs are due on March 24, 2017, and reply briefs are due on April 14, 2017. The Utility expects that the other parties m ay argue that the number of violations exceeds the 164 communications referenced in the October 14, 2016 joint status report either because a single communication may have violated more than one rule or because they believe some of the material provided du ring discovery constitutes impermissible ex parte communications. The Utility expects to contest many of these assertions. If the matter does not settle, the CPUC will determine which communications included within the scope of the proceeding were in vio lation of its rules. The CPUC will also determine whether to impose penalties or other remedies, as a result of a potential settlement or otherwise. The CPUC can impose fines up to $50,000 for each violation, and up to $50,000 per day if the CPUC determi nes that the violation was continuing. The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as how many days each violation continued; the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount o f the penalty to the size of the entity charged. The CPUC has historically exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. PG&E Corporation and the Utility believe it is probable th at the CPUC will impose penalties on the Utility in the OII. In light of recent CPUC decisions, such as the Penalty Decision and the decision in the 2015 GT&S rate case, the Utility expects that such penalties could include fines and future revenue requir ement reductions. In accordance with accounting rules, revenue requirement reductions would be recorded in the period they are incurred and fines would be recorded when considered probable and their amount or range can be reasonably estimated. The Utilit y is unable to determine the form or amount of penalties or reasonably estimate the amount or range of future charges that could be incurred because it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations. Fi nally, in 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. It is uncertain whether any charges will be brought against the Utility. CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping On November 20, 2014, the CPUC began an investigation into whether the Utility violated applicable laws pertaining to record-keeping practices with respect to maintaining safe operation of its natural gas distribution service and facilities. The order also required the Utility to show cause why (1) the CPUC should not fi nd that the Utility violated provisions of the California Public Utilities Code, CPUC general orders or decisions, other rules, or requirements, and/or engaged in unreasonable and/or imprudent practices related to these matters, and (2) the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. In particular, the order cited the SED’s investigative reports alleging that the Utility violated rules regarding safety record-keeping in connection with six natural gas di stribution incidents, including the natural gas explosion that occurred in Carmel, California on March 3, 2014. On August 18, 2016, the CPUC approved a final decision in this investigation. The CPUC assessed a fine of $25.6 million. With the $10.85 m illion citation previously paid in 2015 for the City of Carmel-by-the-Sea (“Carmel”) incident, the total fine imposed on the Utility was $36.5 million. The remaining $25.6 million was paid in September 2016. The decision denied the appeals previously fil ed by the SED and Carmel from the presiding officer’s decision, and closed this proceeding but allowed the parties an opportunity to request that this proceeding be reopened if needed to ensure proper implementation of a compliance plan to be developed by the parties. On September 26, 2016, the SED filed an application for rehearing of the CPUC’s decision. Specifically, the application indicates that the CPUC erred in certain of its determinations (including those related to maximum allowable operating pressure documentation that, if adopted, could result in an additional fine of $7 million), calculations (including those related to the missing De Anza records violations) and certain other findings, and requests that the CPUC adopt its recommendations. On October 11, 2016, the Utility submitted its response to the CPUC in which it opposed the SED’s application for rehearing arguing that the application failed to identify a legal error warranting rehearing by the CPUC. The Utility cannot predict when or if the CPUC will grant the rehearing or if it will adopt the SED’s recommendations. On October 24, 2016 and November 30, 2016, the Utility held meet and confer sessions with parties to develop remedial measures necessary to address the issues identified in the CPUC decision with the objective of establishing a compliance plan. On December 16, 2016, the Utility submitted its Initial Gas Distribution Records Compliance Plan that includes feasible and cost-effective measures necessary to improve natural gas distribution system record-keeping. Natural Gas Transmission Pipeline Rights-of-Way In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to addres s a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth t he scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey had been completed and that remediat ion work, including removal of the encroachments, was expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments. T he Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that c an be considered in determining penalties. Potential Safety Citations The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilitie s’ electric and natural gas facilities and operations. The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. Under both the gas and electric programs , the SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED can consider the discretionary factors discussed above (see “Order Instituting an Investigation into Compliance with Ex Parte Communication Rules” above) in determini ng the number of violations and whether to impose daily fines for continuing violations. There is also an administrative limit of $8 million per citation issued. The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violatio ns of electric and natural gas laws and regulations. The Utility believes it is probable that the SED will impose penalties or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations, based on th e SED’s investigations of incidents reported to the CPUC, or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits or investigations. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed by the SED with respect to these matters given the wide discretion the SED and other CPUC staff has in determining whether to bring enforcement action and the number of factors that can be c onsidered in determining the amount of fines. In September 2016, the Utility reported that it discovered in November 2015 that approximately 550,000 atmospheric corrosion inspections on above-ground gas distribution meters completed in 2014, which constit uted 35% of such inspections in 2014, were performed by non-operator qualified personnel. The Utility did not provide timely notification of such non-compliance to the CPUC. On December 23, 2016, the SED issued the Utility a citation with a $5.45 million fine related to this self-report. The citation included a $5.05 million fine for not ensuring that contractor inspectors were operator-qualified, a $350,000 fine for not completing inspections within 39 months from the previous inspections, and a $50,000 fine for not reporting the self-identified violations within ten days of discovery. The amount of the fine is conditioned upon the Utility implementing certain remedial measures. The Utility paid the fine in January 2017. In February 2017, the Utility reported that it discovered in April 2014 that customer service representatives who handle gas emergency calls within the Utility’s call centers are not included in the drug and alcohol testing program as required by PHMSA regulations. The Utility did not provide timely notification of such non-compliance to the CPUC. The SED could impose fines on the Utility of $50,000 per violation, and also for failure to timely file a self-report in connection with the non-compliance. The SED has the authority to iss ue more than one citation for a series of related incidents and can impose daily fines for continuing violations, and the CPUC can issue an OII and possible additional fines even after the SED has issued a citation. The Utility is unable to reasonably est imate the amount or range of future charges that could be incurred for fines that could be imposed with respect to this self-report, for the reasons indicated above, or to predict whether the CPUC will open a formal proceeding. Federal Matters Federal Criminal Trial On June 14, 2016, a federal criminal trial against the Utility began in the United States District Court for the Northern District of California, in San Francisco, on 12 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats, and one felony count charging that the Utility obstructed the NTSB investigation into the cause of the San Bruno accident. On July 26, 2016, the court granted the government’s motion to dismiss one count alleging that the Utility knowingly and willfully failed to retain a strength test pressure record with respect to a distribution fe eder main, thereby reducing the total number of counts from 13 to 12. On August 9, 2016, the jury returned its verdict. The jury acquitted the Utility on all six of the record-keeping allegations but found the Utility guilty on six felony counts that i nclude one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On January 26, 2017, the court issued a judgment of conviction sentencing the Utility to a five-year corporate probation period, oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertis ing requirements, and community service. The Utility has decided not to appeal the convictions. The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility is required to retain a third-party monitor. The goal of the monito rship will be to prevent the criminal conduct with respect to gas pipeline transmission safety that gave rise to the conviction. To that end, the goal of the monitor will be to help ensure that the Utility takes reasonable and appropriate steps to maintai n the safety of the gas transmission pipeline system, performs appropriate integrity management assessments on its gas transmission pipelines, and maintains an effective ethics and compliance program and safety related incentive program. After an initial assessment is conducted and an initial report is prepared by the monitor, the monitor will prepare reports on a semi-annual basis setting forth the monitor’s continued assessment and making recommendations consistent with the goals and scope of the monitor ship. The Utility expects that the monitor will be retained before the end of the second quarter of 2017. At December 31, 2016, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $3 million accrual in connection with this matter . On February 1, 2017, the Utility paid the $3 million fine imposed by the court. The Utility could incur material costs, not recoverable through rates, in the event of non-compliance with the terms of probation and in connection with the monitorship (in cluding but not limited to the monitor’s compensation or costs resulting from recommendations of the monitor). Other Federal Matters In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investiga tions into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. In addition, in October 2016, the Utility received a grand jury subpoena and letter from the U.S. Attorney for the Northern District of California advising that the Utility is a target of a federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act. The investigation involves a remo val by the Utility of a hazardous tree that contained an osprey nest and egg in Inverness, California, on March 18, 2016. It is uncertain whether any charges will be brought against the Utility as a result of these investigations. Other Matters Butte Fi re Litigation In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfi re. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. Cal Fire’s report concluded that the wildfire was caused when a Gray Pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during i ts vegetation management program ultimately led to the failure of the tree. In a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility. On May 23, 2016, i ndividual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The C alifornia Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of December 31, 2016, complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of Califor nia in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,950 individual plaintiffs representing approximately 950 households and their insuran ce companies. These complaints are part of or are in the process of being added to the two master complaints. Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability. The number of individual complaints and plaintiffs may increase in the future. The Utility continues mediating and settling cases . The next case management conference is scheduled for March 2, 2017. In connection with this matter, the Utility may be liable for p roperty damages, interest, and attorneys’ fees without having been found negligent, through the theory of inverse condemnation. In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility we re found to have been negligent. The Utility believes it was not negligent; however, there can be no assurance that a court or jury would agree with the Utility. The Utility believes that it is probable that it will incur a loss of at least $750 million for all potential damages described above. This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and other damages that the Utility could be liable for under the theories of inverse condemnation and/or negligence. The following table presents changes in the third-party claims liability since December 31, 2015. The balance for the third-party claims liability is included in Other current liabilities in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets: Loss Accrual (in millions) Balance at December 31, 2015 $ - Accrued losses 750 Payments (60) Balance at December 31, 2016 $ 690 In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $27 million. The Utility believes that it is reasonably possible that it will incur losses related to Butte fire claims in excess of $750 million accrued through December 31, 2016 but is currently unable to reasonably estimate the upper end of the range of losses because it is still in an early stage of the eva luation of claims, the mediation and settlement process, and discovery. The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs and results from the ongoing mediation and settlement process, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of approximately $900 million. The Utility re cords insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range. The Utility has recorded $625 million for probable insurance recoveries in connection with losses related to the Butte fire. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. In addition, the Utility is pursuing coverage under the insurance policies of its two veg etation management contractors, including under policies where the Utility is listed as an additional insured. Recoveries of any amounts under these policies are uncertain. The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets: Insurance Receivable (in millions) Balance at December 31, 2015 $ - Accrued insurance recoveries 625 Reimbursements (50) Balance at December 31, 2016 $ 575 If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded, depending on whether the Utility is able to record or collect insu rance recoveries in amounts sufficient to offset such additional accruals. Other Contingencies PG&E Corporation and the Utility are subject to various claims, lawsuits and regulatory proceedings that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $45 million at December 31, 2016 and $63 million at December 31, 2015. These amounts are included in Other current liabilities in the Consolidated Balance Sheets. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows. 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 and the amount of disallowance can be reasonably esti mated. Capital disallowances are reflected in operating and maintenance expenses in the Consolidated Statements of Income. Disallowances as a result of the CPUC’s June 23, 2016 final phase one decision and December 1, 2016 final phase two decision in the Utility’s 2015 GT&S rate case, the April 9, 2015 Penalty Decision and the Utility’s Pipeline Safety Enhancement Plan are discussed below. 2015 GT&S Rate Case Disallowance of Capital Expenditures On June 23, 2016, the CPUC approved a final phase one dec ision in the Utility’s 2015 GT&S rate case. The decision permanently disallowed a portion of the 2011 through 2014 capital spending in excess of the amount adopted and established various cost caps that will increase the risk of overspend over the current rate case cycle, including new one-way capital balancing accounts. As a result, in 2016, the Utility incurred charges of $219 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This included $13 4 million to the net plant balance for 2011 through 2014 capital expenditures in excess of adopted amounts and $85 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. Additional c harges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending. Penalty Decision’s Disallowance of Natural Gas Capital Expenditures On April 9, 2015, the CPUC issued a decision in its investigative enforcement proceedings against the Utility to impose total penalties of $1.6 billion on the Utility after determining that the Utility had committed numerous violations of laws and regulations rela ted to its natural gas transmission operations (the “Penalty Decision”). In January 2016, the CPUC closed the investigative proceedings. The total penalty includes (1) a $300 million fine, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million. On December 1, 2016, the CPUC approved a final phase two decision in the Utility’ s 2015 GT&S rate case, which applies $689 million of the $850 million penalty to capital expenditures. The decision also approves the Utility’s list of programs and projects that meet the CPUC’s definition of “safety related,” the costs of which are to be funded through the $850 million penalty. For the twelve months ended December 31, 2016, the Utility recorded charges for disallowed capital spending of $283 million as a result of the Penalty Decision. The cumulative charges at December 31, 2016, and t he additional future charges that will be recognized in the first quarter of 2017 are shown in the following table: Twelve Months Cumulative Future Ended Charges Charges December 31, December 31, and Total (in millions) 2016 2016 Costs Amount Fine paid to the state $ - $ 300 $ - $ 300 Customer bill credit paid - 400 - 400 Charge for disallowed capital (1) 283 689 - 689 Disallowed revenue for pipeline safety expenses (2) 129 129 32 161 CPUC estimated cost of other remedies (3) - - - 50 Total Penalty Decision fines and remedies $ 412 $ 1,518 $ 32 $ 1,600 (1) The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs. On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT& S rate case which allocates $689 million of the $850 million penalty to capital expenditures. (2) GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first quarter of 2017. (3) In the Penalty De cision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated future remedy-rel ated costs. Capital Expenditures Relating to Pipeline Safety Enhancement Plan The CPUC has authorized the Utility to collect $766 million for recovery of PSEP capital costs. As of December 31, 2016, the Utility has spent $1.35 billion on PSEP-related capital costs, of which $665 million was expensed in previous years for costs that are expected to exceed the authorized amount. The Utility expects the remaining PSEP work to continue beyond 2017. The Utility would be requi red to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected. Environmental Remediation Contingencies Given the complexities of the legal and regulatory environment and the inherent uncertainties inv olved 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 reme diation 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 ra nge is a better estimate than any other amount. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is compo sed of the following: Balance at December 31 December 31, (in millions) 2016 2015 Topock natural gas compressor station (1) $ 299 $ 300 Hinkley natural gas compressor station (1) 135 140 Former manufactured gas plant sites owned by the Utility or third parties 285 271 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 131 164 Fossil fuel-fired generation facilities and sites 108 94 Total environmental remediation liability $ 958 $ 969 (1) See “Natural Gas Compressor Station Sites” below. The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the EPA under the federal Resource Conversation and Recovery Act as well as other state hazardous waste laws. The Utility has a comprehensive progra m in place designed to comply with federal, state, and local laws and regulations relate |
Schedule I - Condensed Financia
Schedule I - Condensed Financial Information Of Parent | 12 Months Ended |
Dec. 31, 2016 | |
Schedule I - Condensed Financial Information Of Parent | PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME Years Ended December 31, (in millions, except per share amounts) 2016 2015 2014 Administrative service revenue $ 70 $ 51 $ 51 Operating expenses (73) (53) (53) Interest income 1 1 1 Interest expense (10) (10) (14) Other income (expense) 2 30 (1) Equity in earnings of subsidiaries 1,388 852 1,413 Income before income taxes 1,378 871 1,397 Income tax benefit 15 3 39 Net income $ 1,393 $ 874 $ 1,436 Other Comprehensive Income Pension and other postretirement benefit plans obligations (net of taxes of $1, $0, and $10, at respective dates) $ (2) $ (1) $ (14) Net change in investments (net of taxes of $0, $12, and $17, at respective dates) - (17) (25) Total other comprehensive income (loss) (2) (18) (39) Comp rehensive Income $ 1,391 $ 856 $ 1,397 Weighted Average Common Shares Outstanding, Basic 499 484 468 Weig hted Average Common Shares Outstanding, Diluted 501 487 470 Net earnings per common share, basic $ 2.79 $ 1.81 $ 3.07 Net earnings per common share, diluted $ 2.78 $ 1.79 $ 3.06 PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED BALANCE SHEETS Balance at December 31, (in millions) 2016 2015 ASSETS Current Assets Cash and cash equivalents $ 106 $ 64 Advances to affiliates 24 22 Income taxes receivable 25 24 Other - 1 Total current assets 155 111 Noncurrent Assets Equipment 2 2 Accumulated depreciation (2) (2) Net equipment - - Investments in subsidiaries 18,172 16,837 Other investments 133 130 Deferred income taxes 267 250 Total noncurrent assets 18,572 17,217 Total Assets $ 18,727 $ 17,328 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Accounts payable – other 7 3 Other 274 246 Total current liabilities 281 249 Noncurrent Liabilities Long-term debt 348 348 Other 158 155 Total noncurrent liabilities 506 503 Common Shareholders’ Equity Common stock 12,198 11,282 Reinvested earnings 5,751 5,301 Accumulated other comprehensive income (loss) (9) (7) Total common shareholders’ equity 17,940 16,576 Total Liabilities and Shareholders’ Equity $ 18,727 $ 17,328 PG&E CORPORATION SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED STATEMENTS OF CASH FLOWS (in millions) Year ended December 31, 2016 2015 2014 Cash Flows from Operating Activities: Net income $ 1,393 $ 874 $ 1,436 Adjustments to reconcile net income to net cash provided by operating activities: Stock-based compensation amortization 74 66 65 Equity in earnings of subsidiaries (1,388) (852) (1,413) Deferred income taxes and tax credits-net 11 10 (72) Noncurrent income taxes receivable/payable - - 5 Current income taxes receivable/payable (1) 5 (16) Other (24) (70) 43 Net cash provided by operating activities 65 33 48 Cash Flows From Investing Activities: Investment in subsidiaries (835) (705) (978) Dividends received from subsidiaries (1) 911 716 716 Proceeds from tax equity investments - - 368 Net cash provided by (used in) investing activities 76 11 106 Cash Flows From Financing Activities: Borrowings (repayments) under revolving credit facilities - - (260) Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 - - 347 Repayments of long-term debt - - (350) Common stock issued 822 780 802 Common stock dividends paid (2) (921) (856) (828) Net cash provided by (used in) financing activities (99) (76) (289) Net change in cash and cash equivalents 42 (32) (135) Cash and cash equivalents at January 1 64 96 231 Cash and cash equivalents at December 31 $ 106 $ 64 $ 96 Supplemental disclosure of cash flow information Cash received (paid) for: Interest, net of amounts capitalized $ (9) $ (9) $ (15) Income taxes, net (13) - 1 Supplemental disclosure of noncash investing and financing activities Noncash common stock issuances $ 20 $ 21 $ 21 Common stock dividends declared but not yet paid 248 224 217 (1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. (2) In January of 2016, PG&E Corporation paid a quarterly common stock dividend of $0.455 per share. In April, July and October of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share. In January, April, July, and October of 2015 and 2014, respectively, PG&E Corporation paid quarterly common stock dividends of $0 .455 per share. |
Schedule II - Consolidated Valu
Schedule II - Consolidated Valuation And Qualifying Accounts | 12 Months Ended |
Dec. 31, 2016 | |
Schedule II - Consolidated Valuation And Qualifying Accounts | PG&E Corporation SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2016, 2015, and 2014 (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: 2016: Allowance for uncollectible accounts (1) $ 54 $ 50 $ - $ 46 $ 58 2015: Allowance for uncollectible accounts (1) $ 66 $ 43 $ - $ 55 $ 54 2014: Allowance for uncollectible accounts (1) $ 80 $ 41 $ - $ 55 $ 66 (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, 2016, 2015, and 2014 (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: 2016: Allowance for uncollectible accounts (1) $ 54 $ 50 $ - $ 46 $ 58 2015: Allowance for uncollectible accounts (1) $ 66 $ 43 $ - $ 55 $ 54 2014: Allowance for uncollectible accounts (1) $ 80 $ 41 $ - $ 55 $ 66 (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 of f |
Summary Of Significant Accoun25
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2016 | |
Summary Of Significant Accounting Policies [Abstract] | |
Regulation And Regulated Operations | Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “reve nue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. T he Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally 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 cap italizes 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 recove red. 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 customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, t he Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. (See “Revenue Recognition” below.) Management continues to believe the use of regulatory accounting is applicable a nd that all regulatory assets and liabilities are recoverable or refundable. 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. |
Revenue Recognition | Revenue Recognition The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unb illed revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. 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 or four years. T he Utility’s ability to recover r evenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility’s sales of electricity and na tural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, revenue is recognized ratably over the y ear. 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. In general, 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 period ic (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. |
Cash And Cash Equivalents | Cash and Cash Equ ivalents 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 Prior to October 2016, restricted cash primarily consisted 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 “ Resolution of Remaining Chapter 11 Disput ed Claims” in Note 13 below.) |
Allowance For Doubtful Accounts Receivable | Allowance for Doubtful Accounts Receivable PG& E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer 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 is recorded to inventory when injected 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 expen sed or capitalized to plant, as appropriate, when consumed or installed. |
Emission Allowances | Emission Allowances The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates. |
Property, Plant, And Equipment | Property, Plant, and Equipment Property, plant, and equipment are reported at the lower of their his torical 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) 2016 2015 Electricity generating facilities (1) 5 to 100 $ 11,308 $ 9,860 Electricity distribution facilities 15 to 55 29,836 28,476 Electricity transmission facilities 15 to 75 11,412 10,196 Natural gas distribution facilities 5 to 60 11,362 10,397 Natural gas transmission and storage facilities 5 to 65 6,491 6,352 Construction work in progress 2,184 2,059 Total property, plant, and equipment 72,593 67,340 Accumulated depreciation (22,012) (20,617) Net property, plant, and equipment $ 50,581 $ 46,723 (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 13 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 de preciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.73 % in 2016 , 3.80 % in 2015 , and 3.77% in 2014 . 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 custo mers. 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 before they go into service 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 e quity, respectively, of $ 51 million and $ 112 million during 2016 , $ 48 million and $ 107 million during 2015 , and $ 45 million and $ 100 million during 2014 . |
Asset Retirement Obligations | Asset Retirement Obligations The following table summarizes the changes in ARO liability during 2016 and 2015 , including nuclear decommissioning obligations: (in millions) 2016 2015 ARO liability at beginning of year $ 3,643 $ 3,575 Revision in estimated cash flows 968 13 Accretion 194 169 Liabilities settled (121) (114) ARO liability at end of year $ 4,684 $ 3,643 The Utility has not recorded a liability related to certain ARO’s for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration or land to the conditions under certain agreements. Nuclear Decommissioning Obligation Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear D ecommissioning Cost Triennial Proceeding conducted by the CPUC. In March 2016, the Utility submitted its updated decommissioning cost estimate to the CPUC. As a result, the estimated undiscounted cost to decommission the Utility’s nuclear power plants in creased by approximately $1.4 billion. The change in total estimated cost resulted in an $818 million adjustment to the ARO. The adjustment was a result of increased estimated costs related to spent fuel storage, staffing, and out-of-state waste disposal . The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The Utility requested that the CPUC authorize the collection of increased annual revenue requirements beginning on January 1, 2017 based on these updated cost estimates. On August 11, 2016, the Utility submitted an application to the CPUC to retire Diablo Canyon at the expiration of its current operating licenses in 2024 (Unit 1) and 2025 (Unit 2). The application includes a joint proposal between the Utility and certain interested parties, entered into on June 20, 2016 , which resulted in a $115 million increase to the ARO recognized on the Consolidated Balance Sheets in June 2016. The Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimated costs of decommissioning its nuclear powe r facilities and records this as an adjustment to the ARO liability on its Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued was $ 3.5 billion and $2.5 billion at December 31, 2016 and 2015 , respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $ 5.1 billion and $3.5 billion at December 31, 2016 and 2015 (or $ 7.3 billion in future dollars), respectively. These estimates are based on the 2016 decommissioning cost studies, prepared in accordance with CPUC requirements. |
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. (See “Enforcement and Litigation Matters” in Note 13 below.) |
Nuclear Decommissioning Trusts | Nuclear Decommissioning Trusts The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one 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 Utilit y'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.” Sin ce 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 impair ments. 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 controllin g financial interest in a VIE is a primary beneficiary and is required to consolidate 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 ge nerate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2016, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expect ed 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 performa nce, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated wit h 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, 2016, it did not consolidate any of them. |
Recently Adopted Accounting Guidance | Recently Adopted Accounting Guidance Share-Based Payment Accounting In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718) , which amends the existing guidance relating to the accounting for share-based payment awards issued to employees, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016. ASU 2016-09 requires recognition of excess tax benefits and deficiencies in the income statement, which resulted in the recognition of $6.3 million in income tax benefit for PG&E Corporation and the Utility for the year ended December 31, 2016. Previously, these amounts were recognized in additional paid-in capital. Previously unrecognized excess tax benefits were reclassified via a cumulative-effect adjustment. ASU 2016-09 also requires excess tax benefits and deficiencies to be prospectively excluded from assumed future proceeds in the calculation of diluted shares when calculating diluted earnings per share utilizing the treasury stock method. The effect of this change on diluted EPS is immaterial. Additionally, excess income tax benefits from stock-based compensation arrangements are now classified as cash flows from operating activities rather than as cash flows from financing activities, which resulted in an increase to cash flows from operating activities of approximately $7.2 million for the year ended December 31, 2016. Furthe rmore, ASU 2016-09 requires, on a retrospective basis, that employee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities. As such, the consolidated statements of cash flo ws for PG&E Corporation and the Utility for the prior periods presented were restated. This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $34.6 million, $26.8 million, and $13.2 million for the years ended December 31, 2016, 2015, and 2014, respectively. PG&E Corporation and the Utility have elected to continue to estimate forfeitures expected to occur to determine the amount of compensation cost to be recognized in each pe riod and have not changed their policy on statutory withholding requirements and will continue to allow the employee to withhold up to the minimum statutory withholding requirements. Fair Value Measurement In May 2015, the FASB issued ASU No. 2015-07, Fa ir Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) , which standardizes reporting practices related to the fair value hierarchy for all investments for which fair va lue is measured using net asset value per share. PG&E Corporation and the Utility adopted this guidance effective January 1, 2016. The adoption of this standard did not have a material impact on their Consolidated Financial Statements. All prior periods presented in these Consolidated Financial Statements reflect the retrospective adoption of this guidance. (See Notes 10 and 11 below.) Accounting for Fees Paid in a Cloud Computing Arrangement In April 2015, the FASB issued ASU No. 2015-05, Intangible s – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement , which adds guidance to help entities evaluate the accounting treatment for cloud computing arrangements. PG&E Corporati on and the Utility adopted this guidance effective January 1, 2016. The adoption of this guidance did not have a material impact on their Consolidated Financial Statements. Presentation of Debt Issuance Costs In April 2015, the FASB issued ASU No. 2015- 03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs , which amends the existing guidance relating to the presentation of debt issuance costs. The amendments in this ASU require that debt issuance cos ts related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. PG&E Corporation and the Utility adopted this guidance effective January 1, 2016 and applied the requirements retrospectively for all periods presented. The adoption of this guidance did not have a material impact on their Consolidated Financial Statements. PG&E Corporation and the Utility restated $105 million and $103 million, respectively, of debt issuance costs as of December 31, 2015 with no impact to net income or total shareholders’ equity previously reported. All prior periods presented in these Consolidated Financial Statements reflect the retrospective adoption of this guidance. Accounting Standards Issued But Not Yet Adopted Restricted Cash In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230) , which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating th e impact the guidance will have on their Consolidated Statements of Cash Flows. Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which amends the existing guidance relating to the recogni tion of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheet, which were previously not recognized. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019 with retrospective application. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidate d Financial Statements and related disclosures. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Fi nancial Assets and Financial Liabilities , which amends the existing guidance relating to the recognition and measurement of financial instruments. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018. PG&E Corporation and t he Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. Revenue Recognition Standard In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, w hich amends existing revenue recognition guidance, effective January 1, 2018 . The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, indu stries, jurisdiction, and capital markets and to provide more useful information to users of financial statements through improved disclosure requirements. PG&E Corporation and the Utility do not plan to early adopt the standard and are currently reviewin g all revenue streams and evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. The Utility does not expect ASU 2014-09 to materially impact the timing or recognition of revenue generated through the sale and delivery of electricity and natural gas to customers. However, th e Utility continues to consider the impacts of outstanding industry-related issues being addressed by the American Institute of CPAs’ Revenue Recognition Working Group and the FASB’s Transition Resource Group. |
Summary Of Significant Accoun26
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Summary Of Significant Accounting Policies [Abstract] | |
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) 2016 2015 Electricity generating facilities (1) 5 to 100 $ 11,308 $ 9,860 Electricity distribution facilities 15 to 55 29,836 28,476 Electricity transmission facilities 15 to 75 11,412 10,196 Natural gas distribution facilities 5 to 60 11,362 10,397 Natural gas transmission and storage facilities 5 to 65 6,491 6,352 Construction work in progress 2,184 2,059 Total property, plant, and equipment 72,593 67,340 Accumulated depreciation (22,012) (20,617) Net property, plant, and equipment $ 50,581 $ 46,723 (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 13 below.) |
Schedule Of Changes In Asset Retirement Obligations | (in millions) 2016 2015 ARO liability at beginning of year $ 3,643 $ 3,575 Revision in estimated cash flows 968 13 Accretion 194 169 Liabilities settled (121) (114) ARO liability at end of year $ 4,684 $ 3,643 |
Reclassification Out Of Accumulated Other Comprehensive Income TableText Block | The changes, net of income tax, in PG& E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2016 consisted of the following: Pension Other (in millions, net of income tax) Benefits Benefits Total Beginning balance $ (23) $ 16 $ (7) Other comprehensive income before reclassifications: Unrecognized prior service cost (net of taxes of $37 and $15, respectively) 54 (21) 33 Unrecognized net actuarial loss (net of taxes of $45 and $15, respectively) (64) 21 (43) Regulatory account transfer (net of taxes of $5 and $0, respectively) 7 - 7 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $3 and $6, respectively) (1) 5 9 14 Amortization of net actuarial loss (net of taxes of $10 and $2, respectively) (1) 14 2 16 Regulatory account transfer (net of taxes of $13 and $8, respectively) (1) (18) (11) (29) Net current period other comprehensive loss (2) - (2) Ending balance $ (25) $ 16 $ (9) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.) The changes, net of income tax, in PG& E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2015 consisted of the following: Pension Other Other (in millions, net of income tax) Benefits Benefits Investments Total Beginning balance $ (21) $ 15 $ 17 $ 11 Other comprehensive income before reclassifications: Unrecognized net actuarial loss (net of taxes of $51, $21, and $0, respectively) (76) (31) - (107) Regulatory account transfer (net of taxes of $51, $21, and $0, respectively) 73 31 - 104 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $7, $8, and $0, respectively) (1) 8 11 - 19 Amortization of net actuarial loss (net of taxes of $4, $1, and $0, respectively) (1) 6 3 - 9 Regulatory account transfer (net of taxes of $10, $9, and $0, respectively) (1) (13) (13) - (26) Realized gain on investments (net of taxes of $0, $0, and $12, respectively) - - (17) (17) Net current period other comprehensive loss (2) 1 (17) (18) Ending balance $ (23) $ 16 $ - $ (7) (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, Liabilitie27
Regulatory Assets, Liabilities, And Balancing Accounts (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Regulatory Assets, Liabilities, And Balancing Accounts [Abstract] | |
Long-Term Regulatory Assets | Balance at December 31, Recovery (in millions) 2016 2015 Period Pension benefits (1) $ 2,429 $ 2,414 Indefinitely (3) Deferred income taxes (1) 3,859 3,054 47 years Utility retained generation (2) 364 411 9 years Environmental compliance costs (1) 778 748 32 years Price risk management (1) 92 138 10 years Unamortized loss, net of gain, on reacquired debt (1) 76 94 26 years Other 353 170 Various Total long-term regulatory assets $ 7,951 $ 7,029 (1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. (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 thes e 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) Payments into the pension and other benefits plans are based on annu al contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits. |
Long-Term Regulatory Liabilities | Balance at December 31, (in millions) 2016 2015 Cost of removal obligations (1) $ 5,060 $ 4,605 Recoveries in excess of AROs (2) 626 631 Public purpose programs (3) 567 600 Other 552 485 Total long-term regulatory liabilities $ 6,805 $ 6,321 (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. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory li ability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 10 below.) (3) Represents amounts received from customers designated for public purpo se program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs. |
Current Regulatory Balancing Accounts Receivable | Receivable Balance at December 31, (in millions) 2016 2015 Electric distribution $ 132 $ 380 Utility generation 48 122 Gas distribution and transmission 541 493 Energy procurement 132 262 Public purpose programs 106 155 Other 541 348 Total regulatory balancing accounts receivable $ 1,500 $ 1,760 |
Current Regulatory Balancing Accounts Payable | Payable Balance at December 31, (in millions) 2016 2015 Gas distribution and transmission $ 48 $ - Energy procurement 13 112 Public purpose programs 264 244 Other 320 359 Total regulatory balancing accounts payable $ 645 $ 715 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt [Abstract] | |
Schedule Of Long-Term Debt | December 31, (in millions) 2016 2015 PG&E Corporation Senior notes: Maturity Interest Rates 2019 2.40% 350 350 Unamortized discount, net of premium and debt issuance costs (2) (2) Total PG&E Corporation long-term debt 348 348 Utility Senior notes: Maturity Interest Rates 2017 5.625% 700 700 2018 8.25% 800 800 2020 3.50% 800 800 2021 3.25% to 4.25% 550 550 2022 through 2046 2.45% to 6.35% 12,775 11,775 Less: current portion (700) - Unamortized discount, net of premium and debt issuance costs (161) (156) Total senior notes, net of current portion 14,764 14,469 Pollution control bonds: Maturity Interest Rates Series 2004 A-D, due 2023 (1) 4.75% 345 345 Series 2009 A-D, due 2026 (2) variable rate (4) 149 309 Series 1996 C, E, F, 1997 B due 2026 (3) variable rate (5) 614 614 Less: current portion - (160) Total pollution control bonds 1,108 1,108 Total Utility long-term debt, net of current portion 15,872 15,577 Total consolidated long-term debt, net of current portion $ 16,220 $ 15,925 (1) The Utility has obtained credit support from an insurance company for these bonds. (2) Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit faci lity without issuer consent. Series C and D pollution control bonds were redeemed on November 30, 2016. (3) Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended to December 1, 2020. 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 cre dit facility. (4) At December 31, 2016 , the interest rate on these bonds was 0.74 %. (5) At December 31, 2016, the interest rate on thes e bonds ranged from 0.72% - 0.73%. |
Schedule Of Short-Term Borrowings | Credit Letters of Commercial Termination Facility Credit Paper Facility (in millions) Date Limit Outstanding Outstanding Availability PG&E Corporation April 2021 $ 300 (1) $ - $ - $ 300 Utility April 2021 3,000 (2) 41 1,016 1,943 Total revolving credit facilities $ 3,300 $ 41 $ 1,016 $ 2,243 (1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans. |
Schedule Of Repayment Schedule | (in millions, except interest rates) 2017 2018 2019 2020 2021 Thereafter Total PG&E Corporation Average fixed interest rate - - 2.40% - - - 2.40% Fixed rate obligations $ - $ - $ 350 $ - $ - $ - $ 350 Utility Average fixed interest rate 5.6 25 % 8.25% - 3.50% 3.80% 4.84% 4.94% Fixed rate obligations $ 700 $ 800 $ - $ 800 $ 550 $ 13,120 $ 15,970 Variable interest rate as of December 31, 2016 - - 0.74% 0.73% - - 0.73% Variable rate obligations (1) $ - $ - $ 149 $ 614 $ - $ - $ 763 Total consolidated debt $ 700 $ 800 $ 499 $ 1,414 $ 550 $ 13,120 $ 17,083 (1) The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019, or December 1, 2020. |
Common Stock And Share-Based 29
Common Stock And Share-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule Of Compensation Expense For Share-Based Incentive Awards | (in millions) 2016 2015 2014 Restricted stock units $ 53 $ 47 $ 42 Performance shares 55 46 36 Total compensation expense (pre-tax) $ 108 $ 93 $ 78 Total compensation expense (after-tax) $ 64 $ 55 $ 47 |
Schedule Of Restricted Stock Units | The following table summarizes restricted stock unit activity for 2016 : Number of Weighted Average Grant- Restricted Stock Units Date Fair Value Nonvested at January 1 1,972,899 $ 47.33 Granted 776,312 $ 56.68 Vested (770,968) $ 46.79 Forfeited (55,233) $ 49.65 Nonvested at December 31 1,923,010 $ 51.26 |
Schedule Of Performance Shares | The following table summarizes activity for performance shares in 2016 : Number of Weighted Average Grant- Performance Shares Date Fair Value Nonvested at January 1 1,450,612 $ 59.24 Granted 1,233,884 53.61 Vested (777,719) 51.81 Forfeited (1) (67,922) 58.20 Nonvested at December 31 1,838,855 $ 58.65 (1) Includes performance shares that expired with zero value as performance targets were not met. |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
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) 2016 2015 2014 Income available for common shareholders $ 1,393 $ 874 $ 1,436 Weighted average common shares outstanding, basic 499 484 468 Add incremental shares from assumed conversions: Employee share-based compensation 2 3 2 Weighted average common share outstanding, diluted 501 487 470 Total earnings per common share, diluted $ 2.78 $ 1.79 $ 3.06 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Abstract] | |
Schedule Of Components Of Income Tax Expense (Benefit) | PG&E Corporation Utility Year Ended December 31, (in millions) 2016 2015 2014 2016 2015 2014 Current: Federal $ (105) $ (89) $ (84) $ (105) $ (88) $ (84) State (70) 11 (41) (66) 6 (29) Defe rred: Federal 218 131 396 229 136 426 Stat e 16 (76) 78 16 (69) 75 Tax credits (4) (4) (4) (4) (4) (4) Inco me tax provision (benefit) $ 55 $ (27) $ 345 $ 70 $ (19) $ 384 |
Schedule Of Deferred Tax Assets And Liabilities | PG&E Corporation Utility Year Ended December 31, (in millions) 2016 2015 2016 2015 Deferred income tax assets: Tax carryforwards 1,851 1,703 1,596 1,462 Other (1) 463 757 402 700 Total deferred income tax assets $ 2,314 $ 2,460 $ 1,998 $ 2,162 D eferred income tax liabilities: Property related basis differences 10,429 9,656 10,411 9,638 Income tax regulatory asset (2) 1,572 1,244 1,572 1,245 Other (3) 526 766 525 766 Total deferred income tax liabilities $ 12,527 $ 11,666 $ 12,508 $ 11,649 Total net deferred income tax liabilities $ 10,213 $ 9,206 $ 10,510 $ 9,487 (1) Amounts include compensation and benefits, environmental reserve, and customer advances for construction. (2) Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.) (3) Amounts primarily relate to regulatory balancing accounts. Greenhouse gas allowances are temporary timing differences that reverse through regulatory balancing accounts. |
Schedule Of Effective Income Tax Rate Reconciliation | PG&E Corporation Utility Year Ended December 31, 2016 2015 2014 2016 2015 2014 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) (1) (2.5) (4.9) 1.4 (2.2) (4.8) 1.6 Effect of regulatory treatment of fixed asset differences (2) (23.7) (33.6) (15.0) (23.4) (33.7) (14.7) Tax credits (0.8) (1.3) (0.7) (0.8) (1.3) (0.7) Benefit of loss carryback (1.1) (1.5) (0.8) (1.1) (1.5) (0.8) Non deductible penalties (3) 0.8 4.3 0.3 0.8 4.3 0.3 Other, net (4) (3.9) (1.1) (0.8) (3.5) (0.2) 0.4 Effective tax rate 3.8 % (3.1) % 19.4 % 4.8 % (2.2) % 21.1 % (1) Includes the effect of state flow-through ratemaking treatment. In 2016 and 2015, amounts include an agreement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 2014 GRC decision in all periods presented and by the 2015 GT&S decision which impacts only 2016. All amounts are impacted by the level of income before income taxes. The 2014 GRC and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related c osts for federal tax purposes. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Ut ility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to cus tomers in future rates. (3) Primarily represents the effects of non-tax deductible fines and penalties associated with the natural gas distribution facilities record-keeping decision for the year ended December 31, 2016 and the effects of the Penalty Dec ision for the year ended December 31, 2015. For more information about the Penalty Decision see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8. (4) In 2016, the amount primarily represents t he impact of tax audit settlements. |
Schedule Of Change In Unrecognized Tax Benefits | PG&E Corporation Utility (in millions) 2016 2015 2014 2016 2015 2014 Balance at beginning of year $ 468 $ 713 $ 666 $ 462 $ 707 $ 660 Additions for tax position taken during a prior year - 40 7 - 40 7 Reductions for tax position taken d uring a prior year (77) (349) (9) (77) (349) (9) Additio ns for tax position taken during the current year 56 64 61 56 64 61 Settlements (59) - (12) (59) - (12) Balance at end of year $ 388 $ 468 $ 713 $ 382 $ 462 $ 707 |
Schedule of Operating Loss And Tax Credit Carryforward Balances | December 31, Expiration (in millions) 2016 Year Federal: Net operating loss carryforward $ 5,009 2029 - 2036 Tax credit carryforward 116 2029 - 2036 Charitable contribution loss carryforward 192 2017 - 2021 State: Net operating loss carryforward $ - N/A Tax credit carryforward 51 Various Charitable contribution loss carryforward 112 2019 - 2021 |
Derivatives And Hedging Activ32
Derivatives And Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivatives And Hedging Activities [Abstract] | |
Volumes Of Outstanding Derivative Contracts | Contract Volume Underlying Product Instruments 2016 2015 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 323,301,331 333,091,813 Options 96,602,785 111,550,004 Electricity (Megawatt-hours) Forwards and Swaps 3,287,397 3,663,512 Congestion Revenue Rights (3) 278,143,281 216,383,389 (1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges du e to transmission grid limitations. |
Outstanding Derivative Balances | At December 31, 2016 , 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 $ 91 $ (10) $ 1 $ 82 Other noncurrent assets – other 149 (9) - 140 Current liabilities – other (48) 10 - (38) Noncurrent liabilities – other (101) 9 3 (89) Total commodity risk $ 91 $ - $ 4 $ 95 At December 31, 2015 , 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 $ 97 $ (4) $ 25 $ 118 Other noncurrent assets – other 172 (2) - 170 Current liabilities – other (102) 4 44 (54) Noncurrent liabilities – other (140) 2 21 (117) Total commodity risk $ 27 $ - $ 90 $ 117 |
Gains And Losses On Derivative Instruments | Commodity Risk For the year ended December 31, (in millions) 2016 2015 2014 Unrealized gain/(loss) - regulatory assets and liabilities (1) $ 64 $ (6) $ 124 Realized loss - cost of electricity (2) (53) (14) (83) Realized loss - cost of natural gas (2) (18) (10) (8) Total commodity risk $ (7) $ (30) $ 33 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Consolidated Statements of Income. These amounts exclude the impact of cash col lateral 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 | Balance at December 31, (in millions) 2016 2015 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (24) $ (2) Related derivatives in an asset position 19 - Collateral posting in the normal course of business related to these derivatives 4 - Net position of derivative contracts/additional collateral posting requirements (1) $ (1) $ (2) (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
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Measurements [Abstract] | |
Assets And Liabilities Measured At Fair Value On A Recurring Basis | Fair Value Measurements At December 31, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 105 $ - $ - $ - $ 105 Nuclear decommissioning trusts Short-term investments 9 - - - 9 Global equity securities 1,724 - - - 1,724 Fixed-income securities 665 527 - - 1,192 Assets measured at NAV - - - - 14 Total nuclear decommissioning trusts (2) 2,398 527 - - 2,939 Price risk management instruments (Note 9) Electricity 30 18 181 (18) 211 Gas - 11 - - 11 Total price risk management 30 29 181 (18) 222 instruments Rabbi trusts Fixed-income securities - 61 - - 61 Life insurance contracts - 70 - - 70 Total rabbi trusts - 131 - - 131 Long-term disability trust Short-term investments 8 - - - 8 Assets measured at NAV - - - - 170 Total long-term disability trust 8 - - - 178 TOTAL ASSETS $ 2,541 $ 687 $ 181 $ (18) $ 3,575 Liabilities: Price risk management instruments (Note 9) Electricity $ 9 $ 12 $ 126 $ (21) $ 126 Gas - 2 - (1) 1 TOTAL LIABILITIES $ 9 $ 14 $ 126 $ (22) $ 127 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 333 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2015 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 64 $ - $ - $ - $ 64 Nuclear decommissioning trusts Short-term investments 36 - - - 36 Global equity securities 1,520 - - - 1,520 Fixed-income securities 694 521 - - 1,215 Assets measured at NAV - - - - 13 Total nuclear decommissioning trusts (2) 2,250 521 - - 2,784 Price risk management instruments (Note 9) Electricity - 9 259 18 286 Gas - 1 - 1 2 Total price risk management instruments - 10 259 19 288 Rabbi trusts Fixed-income securities - 57 - - 57 Life insurance contracts - 70 - - 70 Total rabbi trusts - 127 - - 127 Long-term disability trust Short-term investments 7 - - - 7 Assets measured at NAV - - - - 158 Total long-term disability trust 7 - - - 165 TOTAL ASSETS $ 2,321 $ 658 $ 259 $ 19 $ 3,428 Liabilities: Price risk management instruments (Note 9) Electricity $ 69 $ 1 $ 170 $ (70) $ 170 Gas - 2 - (1) 1 TOTAL LIABILITIES $ 69 $ 3 $ 170 $ (71) $ 171 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value. |
Sensitivity Analysis | Fair Value at (in millions) At December 31, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 181 $ 35 Market approach CRR auction prices $ (11.88) - 6.93 Power purchase agreements $ - $ 91 Discounted cash flow Forward prices $ 18.07 - 38.80 Represents price per megawatt-hour Fair Value at (in millions) At December 31, 2015 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 259 $ 63 Market approach CRR auction prices $ (161.36) - 8.76 Power pur chase agreements $ - $ 107 Discounted cash flow Forward prices $ 15.08 - 37.27 (1) Represents price per megawatt-hour |
Level 3 Reconciliation | Price Risk Management Instruments (in millions) 2016 2015 Asset (liability) balance as of January 1 $ 89 $ 69 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (34) 20 Asset (liability) balance as of December 31 $ 55 $ 89 (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, 2016 2015 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 4) PG&E Corporation $ 348 $ 352 $ 348 $ 354 Utility 15,813 17,790 14,818 16,422 |
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, 2016 Nuclear decommissioning trusts Short-term investments $ 9 $ - $ - $ 9 Global equity securities 584 1,157 (3) 1,738 Fixed-income securities 1,156 48 (12) 1,192 Total (1) $ 1,749 $ 1,205 $ (15) $ 2,939 As of December 31, 2015 Nuclear decommissioning trusts Short-term investments $ 36 $ - $ - $ 36 Global equity securities 508 1,034 (9) 1,533 Fixed-income securities 1,165 58 (8) 1,215 Total (1) $ 1,709 $ 1,092 $ (17) $ 2,784 (1) Represents amounts before deducting $ 333 million and $314 million at December 31, 2016 and 2015 , respectively, primarily related to deferred taxes on appreciation of investment value. |
Schedule Of Long Term Debt Repayments | As of (in millions) December 31, 2016 Less than 1 year $ 13 1–5 years 419 5–10 years 255 More than 10 years 505 Total maturities of fixed-income securities $ 1,192 |
Schedule Of Activity For Debt And Equity Securities | 2016 2015 2014 (in millions) Proceeds from sales and maturities of nuclear decommissioning investments $ 1,295 $ 1,268 $ 1,336 Gross realized gains on securities held as available-for-sale 18 55 118 Gross realized losses on securities held as available-for-sale (26) (37) (12) |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | |
Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status | Pension Plan (in millions) 2016 2015 Change in plan assets: Fair value of plan assets at beginning of year $ 13,745 $ 14,216 Actual return on plan assets 1,358 (176) Company contributions 334 334 Benefits and expenses paid (708) (629) Fair value of plan assets at end of year $ 14,729 $ 13,745 Change in benefit obligation: Benefit obligation at beginning of year $ 16,299 $ 16,696 Service cost for benefits earned 453 479 Interest cost 715 673 Actuarial (gain) loss 637 (922) Plan amendments (91) 1 Transitional costs - 1 Benefits and expenses paid (708) (629) Benefit obligation at end of year (1) $ 17,305 $ 16,299 Funded Status: Current liability $ (7) $ (6) Noncurrent liability (2,569) (2,547) Net liability at end of year $ (2,576) $ (2,553) ( 1) PG& E Corporation’s accumulated benefit obligation was $15.6 billion and $14.7 billion at December 31, 2016 and 2015 , respectively. Postretirement Benefits Other t han Pensions (in millions) 2016 2015 Change in plan assets: Fair value of plan assets at beginning of year $ 2,035 $ 2,092 Actual return on plan assets 167 (26) Company contributions 52 61 Plan participant contribution 85 68 Benefits and expenses paid (166) (160) Fair value of plan assets at end of year $ 2,173 $ 2,035 Change in benefit obligation: Benefit obligation at beginning of year $ 1,766 $ 1,811 Service cost for benefits earned 52 55 Interest cost 76 71 Actuarial (gain) loss 11 (98) Plan amendments 37 - Transitional costs - 1 Benefits and expenses paid (153) (146) Federal subsidy on benefits paid 3 4 Plan participant contributions 85 68 Benefit obligation at end of year $ 1,877 $ 1,766 Funded Status: (1) Noncurrent asset $ 368 $ 344 Noncurrent liability (72) (75) Net asset at end of year $ 296 $ 269 (1) At December 31, 2016 and 2015 , the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. |
Components Of Net Periodic Benefit Cost | Pension Plan (in millions) 2016 2015 2014 Service cost $ 453 $ 479 $ 383 Interest cost 715 673 695 Expected return on plan assets (828) (873) (807) Amortization of prior service cost 8 15 20 Amortization of net actuarial loss 24 10 2 Net periodic benefit cost 372 304 293 Less: transfer to regulatory account (1) (34) 34 42 Tota l expense recognized $ 338 $ 338 $ 335 (1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates. Postretirement Benefits Other than Pensions (in millions) 2016 2015 2014 Service cost $ 52 $ 55 $ 45 Interest cost 76 71 76 Expected return on plan assets (107) (112) (103) Amortization of prior service cost 15 19 23 Amortization of net actuarial loss 4 4 2 Net periodic benefit cost $ 40 $ 37 $ 43 |
Estimated Amortized Net Periodic Benefit For 2012 | (in millions) Pension Plan PBOP Plans Unrecognized prior service cost $ (7) $ 15 Unrecognized net loss 22 4 Total $ 15 $ 19 |
Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost | Pension Plan PBOP Plans December 31, December 31, 2016 2015 2014 2016 2015 2014 Discount rate 4.11 % 4.37 % 4.00 % 4.05 - 4.19 % 4.27 - 4.48 % 3.89 - 4.09 % Rate of future compensation increases 4.00 % 4.00 % 4.00 % - - - Expected return on plan assets 5.30 % 6.10 % 6.20 % 2.80 - 6.00 % 3.20 - 6.60 % 3.30 - 6.70 % |
Schedule Of Assumed Health Care Cost Trend | The assumed health care cost trend rate as of December 31, 2016 was 7.2 %, decreasing gradually to an ultimate trend rate in 2025 and beyond of approximately 4.5 % . A one-percentage-point change in assumed health care cost trend rate would have the following effects: One-Perc entage-Point One-Percentage-Point (in millions) Increase Decrease Effect on postretirement benefit obligation $ 118 $ (120) Effect on service and interest cost 9 (10) |
Target Asset Allocation Percentages | Pension Plan PBOP Plans 2017 2016 2015 2017 2016 2015 Global equity 27 % 25 % 25 % 32 % 32 % 31 % Absolute return 5 % 5 % 5 % 3 % 3 % 3 % Real assets 10 % 10 % 10 % 7 % 7 % 8 % Fixed income 58 % 60 % 60 % 58 % 58 % 58 % Total 100 % 100 % 100 % 100 % 100 % 100 % |
Schedule Of Changes In Fair Value Of Plan Assets | Fair Value Measurements At December 31, 2016 2015 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 364 $ 369 $ - $ 733 $ 247 $ 375 $ - $ 622 Global equity 996 - - 996 903 - - 903 Real assets 610 - - 610 581 - - 581 Fixed-income 1,754 4,774 5 6,533 1,841 4,495 3 6,339 Assets measured at NAV - - - 5,950 - - - 5,308 Total $ 3,724 $ 5,143 $ 5 $ 14,822 $ 3,572 $ 4,870 $ 3 $ 13,753 PBOP Plans: Short-term investments $ 33 $ - $ - $ 33 $ 20 $ - $ - $ 20 Global equity 115 - - 115 104 - - 104 Real assets 70 - - 70 69 - - 69 Fixed-income 150 656 - 806 150 632 - 782 Assets measured at NAV - - - 1,153 - - - 1,065 Total $ 368 $ 656 $ - $ 2,177 $ 343 $ 632 $ - $ 2,040 Total plan assets at fair value $ 16,999 $ 15,793 |
Schedule Of Level 3 Reconciliation | The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2016 and 2015 : (in millions) Fixed- For the year ended December 31, 2016 Income Balance at beginning of year $ 3 Actual return on plan assets: Relating to assets still held at the reporting date 3 Relating to assets sold during the period - Purchases, issuances, sales, and settlements: Purchases - Settlements (1) Balance at end of year $ 5 (in millions) Fixed- For the year ended December 31, 2015 Income Balance at beginning of year $ 12 Actual return on plan assets: Relating to assets still held at the reporting date (3) Relating to assets sold during the period 1 Purchases, issuances, sales, and settlements: Purchases 2 Settlements (9) Balance at end of year $ 3 |
Schedule Of Estimated Benefits Expected To Be Paid | Pension PBOP Federal (in millions) Plan Plans Subsidy 2017 $ 739 $ 87 $ (8) 2018 781 93 (9) 2019 821 97 (10) 2020 857 103 (10) 2021 892 108 (11) Thereafter in the succeeding five years 4,879 592 (15) |
Related Party Agreements And 35
Related Party Agreements And Transactions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Agreements And Transactions [Abstract] | |
Schedule Of Significant Related Party Transactions | Year Ended December 31, (in millions) 2016 2015 2014 Utility revenues from: Administrative services provided to PG&E Corporation $ 7 $ 6 $ 5 Utility expenses from: Administrative services received from PG&E Corporation $ 74 $ 53 $ 54 Utility employee benefit due to PG&E Corporation 91 82 70 |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies [Abstract] | |
Impact Of The Penalty Decision | Twelve Months Cumulative Future Ended Charges Charges December 31, December 31, and Total (in millions) 2016 2016 Costs Amount Fine paid to the state $ - $ 300 $ - $ 300 Customer bill credit paid - 400 - 400 Charge for disallowed capital (1) 283 689 - 689 Disallowed revenue for pipeline safety expenses (2) 129 129 32 161 CPUC estimated cost of other remedies (3) - - - 50 Total Penalty Decision fines and remedies $ 412 $ 1,518 $ 32 $ 1,600 (1) The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs. On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT& S rate case which allocates $689 million of the $850 million penalty to capital expenditures. (2) GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first quarter of 2017. (3) In the Penalty De cision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated future remedy-rel ated costs. |
Schedule of Environmental Remediation Liability | Balance at December 31 December 31, (in millions) 2016 2015 Topock natural gas compressor station (1) $ 299 $ 300 Hinkley natural gas compressor station (1) 135 140 Former manufactured gas plant sites owned by the Utility or third parties 285 271 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 131 164 Fossil fuel-fired generation facilities and sites 108 94 Total environmental remediation liability $ 958 $ 969 (1) See “Natural Gas Compressor Station Sites” below. |
Schedule Of Undiscounted Future Expected Power Purchase Agreement Payments | Power Purchase Agreements Renewable Conventional Natural Nuclear (in millions) Energy Energy Other Gas Fuel Total 2017 $ 2,233 $ 815 $ 369 $ 536 $ 97 $ 4,050 2018 2,108 716 284 169 93 3,370 2019 2,144 698 225 160 95 3,322 2020 2,139 677 179 148 130 3,273 2021 2,117 585 147 93 49 2,991 Thereafter 27,685 1,168 653 455 136 30,097 Total purchase commitments $ 38,426 $ 4,659 $ 1,857 $ 1,561 $ 600 $ 47,103 |
Schedule of Future Minimum Payments For Operating Leases | (in millions) Operat ing Leases 2017 $ 44 2018 41 2019 39 2020 39 2021 36 Thereafter 168 Total minimum lease payments $ 367 |
Schedule Of Loss Accrual | Loss Accrual (in millions) Balance at December 31, 2015 $ - Accrued losses 750 Payments (60) Balance at December 31, 2016 $ 690 |
Schedule Of Insurance Receivable | Insurance Receivable (in millions) Balance at December 31, 2015 $ - Accrued insurance recoveries 625 Reimbursements (50) Balance at December 31, 2016 $ 575 |
Schedule I - Condensed Financ37
Schedule I - Condensed Financial Information Of Parent (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Schedule I - Condensed Financial Information Of Parent [Abstract] | |
Schedule of Condensed Statements of Income | PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME Years Ended December 31, (in millions, except per share amounts) 2016 2015 2014 Administrative service revenue $ 70 $ 51 $ 51 Operating expenses (73) (53) (53) Interest income 1 1 1 Interest expense (10) (10) (14) Other income (expense) 2 30 (1) Equity in earnings of subsidiaries 1,388 852 1,413 Income before income taxes 1,378 871 1,397 Income tax benefit 15 3 39 Net income $ 1,393 $ 874 $ 1,436 Other Comprehensive Income Pension and other postretirement benefit plans obligations (net of taxes of $1, $0, and $10, at respective dates) $ (2) $ (1) $ (14) Net change in investments (net of taxes of $0, $12, and $17, at respective dates) - (17) (25) Total other comprehensive income (loss) (2) (18) (39) Comp rehensive Income $ 1,391 $ 856 $ 1,397 Weighted Average Common Shares Outstanding, Basic 499 484 468 Weig hted Average Common Shares Outstanding, Diluted 501 487 470 Net earnings per common share, basic $ 2.79 $ 1.81 $ 3.07 Net earnings per common share, diluted $ 2.78 $ 1.79 $ 3.06 |
Schedule of Condensed Balance Sheet | PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED BALANCE SHEETS Balance at December 31, (in millions) 2016 2015 ASSETS Current Assets Cash and cash equivalents $ 106 $ 64 Advances to affiliates 24 22 Income taxes receivable 25 24 Other - 1 Total current assets 155 111 Noncurrent Assets Equipment 2 2 Accumulated depreciation (2) (2) Net equipment - - Investments in subsidiaries 18,172 16,837 Other investments 133 130 Deferred income taxes 267 250 Total noncurrent assets 18,572 17,217 Total Assets $ 18,727 $ 17,328 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Accounts payable – other 7 3 Other 274 246 Total current liabilities 281 249 Noncurrent Liabilities Long-term debt 348 348 Other 158 155 Total noncurrent liabilities 506 503 Common Shareholders’ Equity Common stock 12,198 11,282 Reinvested earnings 5,751 5,301 Accumulated other comprehensive income (loss) (9) (7) Total common shareholders’ equity 17,940 16,576 Total Liabilities and Shareholders’ Equity $ 18,727 $ 17,328 |
Schedule Of Condensed Statement Of Cash Flows | PG&E CORPORATION SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED STATEMENTS OF CASH FLOWS (in millions) Year ended December 31, 2016 2015 2014 Cash Flows from Operating Activities: Net income $ 1,393 $ 874 $ 1,436 Adjustments to reconcile net income to net cash provided by operating activities: Stock-based compensation amortization 74 66 65 Equity in earnings of subsidiaries (1,388) (852) (1,413) Deferred income taxes and tax credits-net 11 10 (72) Noncurrent income taxes receivable/payable - - 5 Current income taxes receivable/payable (1) 5 (16) Other (24) (70) 43 Net cash provided by operating activities 65 33 48 Cash Flows From Investing Activities: Investment in subsidiaries (835) (705) (978) Dividends received from subsidiaries (1) 911 716 716 Proceeds from tax equity investments - - 368 Net cash provided by (used in) investing activities 76 11 106 Cash Flows From Financing Activities: Borrowings (repayments) under revolving credit facilities - - (260) Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 - - 347 Repayments of long-term debt - - (350) Common stock issued 822 780 802 Common stock dividends paid (2) (921) (856) (828) Net cash provided by (used in) financing activities (99) (76) (289) Net change in cash and cash equivalents 42 (32) (135) Cash and cash equivalents at January 1 64 96 231 Cash and cash equivalents at December 31 $ 106 $ 64 $ 96 Supplemental disclosure of cash flow information Cash received (paid) for: Interest, net of amounts capitalized $ (9) $ (9) $ (15) Income taxes, net (13) - 1 Supplemental disclosure of noncash investing and financing activities Noncash common stock issuances $ 20 $ 21 $ 21 Common stock dividends declared but not yet paid 248 224 217 (1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. (2) In January of 2016, PG&E Corporation paid a quarterly common stock dividend of $0.455 per share. In April, July and October of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share. In January, April, July, and October of 2015 and 2014, respectively, PG&E Corporation paid quarterly common stock dividends of $0 .455 per share. |
Schedule II - Consolidated Va38
Schedule II - Consolidated Valuation And Qualifying Accounts (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract] | |
Schedule II - Consolidated Valuation And Qualifying Accounts | PG&E Corporation SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2016, 2015, and 2014 (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: 2016: Allowance for uncollectible accounts (1) $ 54 $ 50 $ - $ 46 $ 58 2015: Allowance for uncollectible accounts (1) $ 66 $ 43 $ - $ 55 $ 54 2014: Allowance for uncollectible accounts (1) $ 80 $ 41 $ - $ 55 $ 66 (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, 2016, 2015, and 2014 (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: 2016: Allowance for uncollectible accounts (1) $ 54 $ 50 $ - $ 46 $ 58 2015: Allowance for uncollectible accounts (1) $ 66 $ 43 $ - $ 55 $ 54 2014: Allowance for uncollectible accounts (1) $ 80 $ 41 $ - $ 55 $ 66 (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 of f |
Summary Of Significant Accoun39
Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Increase to cash flows from operating activities | $ 379,000 | $ 326,000 | $ 286,000 |
Decrease to cash flows from financing activities | (44,000) | (27,000) | 29,000 |
Income tax provision (benefit) | $ 55,000 | $ (27,000) | $ 345,000 |
Pacific Gas And Electric Company [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Composite depreciation rate | 3.73% | 3.80% | 3.77% |
AFUDC interest recorded | $ 51,000 | $ 48,000 | $ 45,000 |
AFUDC equity recorded | 112,000 | 107,000 | 100,000 |
Nuclear decommissioning obligation accrued | 3,500,000 | 2,500,000 | |
Estimated cost recovery on spent nuclear fuel storage proceeding every year | 4,300,000 | 3,500,000 | |
Approximate estimated nuclear decommissioning cost in future dollars | 7,300,000 | 6,100,000 | |
Increase to cash flows from operating activities | 306,000 | 263,000 | 226,000 |
Decrease to cash flows from financing activities | (30,000) | (13,000) | 43,000 |
Income tax provision (benefit) | 70,000 | (19,000) | 384,000 |
New Accounting Pronouncement [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Increase to cash flows from operating activities | 7,200 | ||
Decrease to cash flows from financing activities | 34,600 | $ 26,800 | $ 13,200 |
Income tax provision (benefit) | 6,300 | ||
Accounting Standards Update 2015-03 [Member] | Pacific Gas And Electric Company [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Debt issuance costs | 103,000 | ||
Accounting Standards Update 2015-03 [Member] | PGE Corporation and Utility [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Debt issuance costs | $ 105,000 |
Summary Of Significant Accoun40
Summary Of Significant Accounting Policies (Schedule Of Estimated Useful Lives And Balances Of Utility's Property, Plant And Equipment) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Accumulated depreciation | $ (22,012) | $ (20,617) | |
Net property, plant, and equipment | 50,581 | 46,723 | |
Utility [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant, and equipment | 72,593 | 67,340 | |
Electricity generating facilities [Member] | Utility [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant, and equipment | [1] | $ 11,308 | 9,860 |
Electricity generating facilities [Member] | Utility [Member] | Minimum [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Useful Life | 5 years | ||
Electricity generating facilities [Member] | Utility [Member] | Maximum [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Useful Life | 100 years | ||
Electricity distribution facilities [Member] | Utility [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant, and equipment | $ 29,836 | 28,476 | |
Electricity distribution facilities [Member] | Utility [Member] | Minimum [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Useful Life | 15 years | ||
Electricity distribution facilities [Member] | Utility [Member] | Maximum [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Useful Life | 55 years | ||
Electricity transmission [Member] | Utility [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant, and equipment | $ 11,412 | 10,196 | |
Electricity transmission [Member] | Utility [Member] | Minimum [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Useful Life | 15 years | ||
Electricity transmission [Member] | Utility [Member] | Maximum [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Useful Life | 75 years | ||
Natural gas distribution facilities [Member] | Utility [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant, and equipment | $ 11,362 | 10,397 | |
Natural gas distribution facilities [Member] | Utility [Member] | Minimum [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Useful Life | 5 years | ||
Natural gas distribution facilities [Member] | Utility [Member] | Maximum [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Useful Life | 60 years | ||
Natural gas transportation and storage [Member] | Utility [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant, and equipment | $ 6,491 | 6,352 | |
Natural gas transportation and storage [Member] | Utility [Member] | Minimum [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Useful Life | 5 years | ||
Natural gas transportation and storage [Member] | Utility [Member] | Maximum [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, Plant and Equipment, Useful Life | 65 years | ||
Construction Work In Progress [Member] | Utility [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total property, plant, and equipment | $ 2,184 | $ 2,059 | |
[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 13 below.) |
Summary Of Significant Accoun41
Summary Of Significant Accounting Policies (Schedule Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Summary Of Significant Accounting Policies [Abstract] | ||
Balance at beginning of year | $ 3,643 | $ 3,575 |
Revision in estimated cash flows | 968 | 13 |
Accretion | 194 | 169 |
Liabilities settled | (121) | (114) |
Balance at end of year | $ 4,684 | $ 3,643 |
New and Significant Accounting
New and Significant Accounting Policies (Reclassifications Out of Accumulated Other Comprehensived Income) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | $ (7) | ||
Change in investments | 0 | $ (17) | $ (25) |
Total other comprehensive income (loss) | (2) | (18) | (39) |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | (9) | (7) | |
Net actuarial loss tax | 1 | 0 | 10 |
Change in investments tax | 0 | 12 | 17 |
Amounts Reclassified From Other Comprehensive Income [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Unrecognized net actuarial loss | (16) | (9) | |
Unrecognized prior service cost | 14 | 19 | |
Transfer to regulatory account | 29 | 26 | |
Realized gain on investments | (17) | ||
Other Comprehensive Income Before Reclassifications [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Unrecognized prior service cost | 33 | ||
Transfer to regulatory account | (7) | (104) | |
Amortization of net actuarial loss | (43) | (107) | |
Other Benefits [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | 16 | ||
Unrecognized net actuarial loss | 4 | ||
Unrecognized prior service cost | 15 | ||
Amortization of prior service cost | 15 | 19 | 23 |
Amortization of net actuarial loss | 4 | 4 | $ 2 |
Total other comprehensive income (loss) | 0 | 1 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | 16 | 16 | |
Other Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Unrecognized net actuarial loss | (2) | (3) | |
Unrecognized prior service cost | 9 | 11 | |
Transfer to regulatory account | 11 | 13 | |
Realized gain on investments | 0 | ||
Net actuarial loss tax | 2 | 1 | |
Transfer To Regulatory Account Tax | 8 | 9 | |
Amortization of prior service cost tax | 6 | 8 | |
Realized gain on investments tax | 0 | ||
Other Benefits [Member] | Other Comprehensive Income Before Reclassifications [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Unrecognized prior service cost | (21) | ||
Transfer to regulatory account | 0 | (31) | |
Amortization of net actuarial loss | 21 | (31) | |
Net actuarial loss tax | 15 | 21 | |
Transfer To Regulatory Account Tax | 0 | 21 | |
Amortization of prior service cost tax | 15 | ||
Other Investments [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | 0 | ||
Total other comprehensive income (loss) | (17) | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | 0 | ||
Other Investments [Member] | Amounts Reclassified From Other Comprehensive Income [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Unrecognized net actuarial loss | 0 | ||
Unrecognized prior service cost | 0 | ||
Transfer to regulatory account | 0 | ||
Realized gain on investments | (17) | ||
Net actuarial loss tax | 0 | ||
Transfer To Regulatory Account Tax | 0 | ||
Amortization of prior service cost tax | 0 | ||
Realized gain on investments tax | 12 | ||
Other Investments [Member] | Other Comprehensive Income Before Reclassifications [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Transfer to regulatory account | 0 | ||
Amortization of net actuarial loss | 0 | ||
Net actuarial loss tax | 0 | ||
Transfer To Regulatory Account Tax | 0 | ||
Pension [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | (23) | ||
Total other comprehensive income (loss) | (2) | (2) | |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | (25) | (23) | |
Pension [Member] | Amounts Reclassified From Other Comprehensive Income [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Unrecognized net actuarial loss | (14) | (6) | |
Unrecognized prior service cost | 5 | 8 | |
Transfer to regulatory account | 18 | 13 | |
Realized gain on investments | 0 | ||
Net actuarial loss tax | 10 | 4 | |
Transfer To Regulatory Account Tax | 13 | 10 | |
Amortization of prior service cost tax | 3 | 7 | |
Realized gain on investments tax | 0 | ||
Pension [Member] | Other Comprehensive Income Before Reclassifications [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Unrecognized prior service cost | 54 | ||
Transfer to regulatory account | (7) | (73) | |
Amortization of net actuarial loss | (64) | (76) | |
Net actuarial loss tax | 45 | 51 | |
Transfer To Regulatory Account Tax | 5 | $ 51 | |
Amortization of prior service cost tax | $ 37 |
Regulatory Assets, Liabilitie43
Regulatory Assets, Liabilities, And Balancing Accounts (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Regulatory Assets [Line Items] | ||
Deferred income taxes regulatory asset recovery maximum (years) | 47 years | |
Utility retained generation asset costs | $ 1,200 | |
Weighted average remaining life of Utility retained generation assets (years) | 9 years | |
Environmental compliance costs regulatory asset recovery (years) | 32 years | |
Price risk management regulatory assets recovery (years) | 10 years | |
Recovery of costs related to debt reacquired or redeemed prior to maturity (years) | 26 years | |
Current regulatory assets | $ 423 | $ 517 |
Regulatory Assets, Liabilitie44
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Regulatory Assets [Line Items] | |||
Total long-term regulatory assets | $ 7,951 | $ 7,029 | |
Deferred income taxes regulatory asset recovery maximum (years) | 47 years | ||
Weighted average remaining life of Utility retained generation assets (years) | 9 years | ||
Environmental compliance costs regulatory asset recovery (years) | 32 years | ||
Price risk management regulatory assets recovery (years) | 10 years | ||
Recovery of costs related to debt reacquired or redeemed prior to maturity (years) | 26 years | ||
Retained Generation Asset Costs | $ 1,200 | ||
Pension benefits regulatory assets recovery (years) | Indefinitely | ||
Other regulatory assets recovery (years) | Various | ||
Current regulatory assets | $ 423 | 517 | |
Pension Plans Defined Benefit [Member] | |||
Regulatory Assets [Line Items] | |||
Total long-term regulatory assets | [1],[2] | 2,429 | 2,414 |
Deferred Income Taxes [Member] | |||
Regulatory Assets [Line Items] | |||
Total long-term regulatory assets | [2] | 3,859 | 3,054 |
Utility Retained Generation [Member] | |||
Regulatory Assets [Line Items] | |||
Total long-term regulatory assets | [3] | 364 | 411 |
Environmental Compliance Costs [Member] | |||
Regulatory Assets [Line Items] | |||
Total long-term regulatory assets | [2] | 778 | 748 |
Price Risk Management [Member] | |||
Regulatory Assets [Line Items] | |||
Total long-term regulatory assets | [2] | 92 | 138 |
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member] | |||
Regulatory Assets [Line Items] | |||
Total long-term regulatory assets | [2] | 76 | 94 |
Other Regulatory Assets ( Liabilities) [Member] | |||
Regulatory Assets [Line Items] | |||
Total long-term regulatory assets | $ 353 | $ 170 | |
[1] | Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits. | ||
[2] | Represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. Pension benefits also includes amounts that otherwise would be recorded to accumulated other comprehensive income/loss in the Consolidated Balance Sheets. (See Note 11 below.) | ||
[3] | 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 $1.2 billion of costs related to the Utility's retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. |
Regulatory Assets, Liabilitie45
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | $ 6,805 | $ 6,321 | |
Cost Of Removal Obligation [Member] | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | [1] | 5,060 | 4,605 |
Recoveries In Excess Of ARO [Member] | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | [2] | 626 | 631 |
Public Purpose Programs [Member] | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | [3] | 567 | 600 |
Other Regulatory Assets ( Liabilities) [Member] | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | $ 552 | $ 485 | |
[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 Assets, Liabilitie46
Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | $ 1,500 | $ 1,760 |
Regulatory Balancing Accounts Payable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 645 | 715 |
Electric Distribution [Member] | Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 132 | 380 |
Utility Generation [Member] | Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 48 | 122 |
Public Purpose Programs [Member] | Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 106 | 155 |
Public Purpose Programs [Member] | Regulatory Balancing Accounts Payable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 264 | 244 |
Gas Distribution and Transmission [Member] | Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 541 | 493 |
Gas Distribution and Transmission [Member] | Regulatory Balancing Accounts Payable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 48 | 0 |
Energy Procurement [Member] | Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 132 | 262 |
Energy Procurement [Member] | Regulatory Balancing Accounts Payable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 13 | 112 |
Other [Member] | Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 541 | 348 |
Other [Member] | Regulatory Balancing Accounts Payable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | $ 320 | $ 359 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Debt [Line Items] | ||||
Interest including LIBOR on credit facilities | Borrowings under each amended and restated credit agreement (other than swing line loans) will bear interest based, at each borrower’s election, on (1) a London Interbank Offered Rate (“LIBOR”) 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 overnight federal funds rate, and the one-month LIBOR plus an applicable margin. The applicable margin for LIBOR loans will range between 0.9% and 1.475% under PG&E Corporation’s amended and restated credit agreement and between 0.8% and 1.275% under the Utility’s amended and restated credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s amended and restated credit agreement and between 0% and 0.275% under the Utility’s amended and restated credit agreement. In addition, the facility fee under PG&E Corporation’s and the Utility’s amended and restated credit agreements will range between 0.1% and 0.275% and between 0.075% and 0.225%, respectively. | |||
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 | |||
Short-term debt matured | $ 0 | $ (300) | $ 0 | |
Pacific Gas And Electric Company [Member] | ||||
Debt [Line Items] | ||||
Line of credit facility, maximum borrowing capacity | [1] | $ 3,000 | ||
Commercial paper average yield | 0.70% | |||
Line of Credit Facility, Expiration Date | Apr. 27, 2021 | |||
Short-term debt matured | $ 0 | $ (300) | $ 0 | |
PG&E Corporation [Member] | ||||
Debt [Line Items] | ||||
Line of credit facility, maximum borrowing capacity | [2] | $ 300 | ||
Commercial paper average yield | 0.65% | |||
Line of Credit Facility, Expiration Date | Apr. 27, 2021 | |||
Credit Facilities [Member] | ||||
Debt [Line Items] | ||||
Line of credit facility, maximum borrowing capacity | $ 3,300 | |||
Commercial Paper [Member] | Pacific Gas And Electric Company [Member] | ||||
Debt [Line Items] | ||||
Average outstanding borrowings | 837 | |||
Maximum outstanding balance | 1,400 | |||
Commercial Paper [Member] | PG&E Corporation [Member] | ||||
Debt [Line Items] | ||||
Average outstanding borrowings | 84 | |||
Maximum outstanding balance | $ 176 | |||
[1] | Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans. | |||
[2] | Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. |
Debt (Schedule Of Long-Term Deb
Debt (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | |||
Debt [Line Items] | ||||
Total long-term debt, net of current portion | $ 16,220 | $ 15,925 | ||
Pacific Gas And Electric Company [Member] | ||||
Debt [Line Items] | ||||
Total long-term debt, net of current portion | 15,872 | 15,577 | ||
Utility [Member] | ||||
Debt [Line Items] | ||||
Less: current portion | 700 | 0 | ||
Unamortized discount, net of premium and debt issuance costs | 161 | 156 | ||
Total senior notes, net of current portion | 14,764 | 14,469 | ||
Less: current portion | 0 | 160 | ||
Total pollution control bonds | 1,108 | 1,108 | ||
PG&E Corporation [Member] | ||||
Debt [Line Items] | ||||
Unamortized discount, net of premium and debt issuance costs | 2 | 2 | ||
Total senior notes, net of current portion | 348 | 348 | ||
Total long-term debt, net of current portion | 348 | 348 | ||
Senior Notes, 2.40% Due 2019 [Member] | PG&E Corporation [Member] | ||||
Debt [Line Items] | ||||
Senior notes | 350 | 350 | ||
Senior Notes, 5.625% Due 2017 [Member] | Utility [Member] | ||||
Debt [Line Items] | ||||
Senior notes | 700 | 700 | ||
Senior Notes, 8.25% Due 2018 [Member] | Utility [Member] | ||||
Debt [Line Items] | ||||
Senior notes | 800 | 800 | ||
Senior Notes, 3.50% Due 2020 [Member] | Utility [Member] | ||||
Debt [Line Items] | ||||
Senior notes | 800 | 800 | ||
Senior Notes, 3.25% - 4.25% Due 2021[Member] | Utility [Member] | ||||
Debt [Line Items] | ||||
Senior notes | 550 | 550 | ||
Senior Notes, 2.45% - 6.35% Due 2022 - 2046 [Member] | Utility [Member] | ||||
Debt [Line Items] | ||||
Senior notes | 12,775 | 11,775 | ||
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member] | Utility [Member] | ||||
Debt [Line Items] | ||||
Pollution control bonds | $ 614 | [1],[2],[3] | 614 | |
Interest rate on bonds, minimum | 0.72% | |||
Interest rate on bonds, maximum | 0.73% | |||
Pollution Control Bonds, Series 2004 A-D, 4.75%, Due 2023 [Member] | Utility [Member] | ||||
Debt [Line Items] | ||||
Pollution control bonds | [4] | $ 345 | 345 | |
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member] | ||||
Debt [Line Items] | ||||
Interest rate on bonds, minimum | 0.74% | |||
Interest rate on bonds, maximum | 0.74% | |||
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member] | Utility [Member] | ||||
Debt [Line Items] | ||||
Pollution control bonds | $ 149 | [3],[5] | $ 309 | |
[1] | At December 31, 2016, the interest rate on these bonds ranged from 0.72% - 0.73% | |||
[2] | Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent. Series C and D pollution control bonds were redeemed on November 30, 2016. | |||
[3] | Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended to December 1, 2020. 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. | |||
[4] | The Utility has obtained credit support from an insurance company for these bonds. | |||
[5] | At December 31, 2016, interest rates on these bonds were 0.74%. |
Debt (Schedule Of Long-Term D49
Debt (Schedule Of Long-Term Debt Repayments) (Details) $ in Millions | Dec. 31, 2016USD ($) | |
Debt [Line Items] | ||
Total consolidated long-term debt | $ 17,083 | |
Pacific Gas And Electric Company [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 4.94% | |
Fixed rate obligations | $ 15,970 | |
Variable interest rate as of December 31, 2016 | 0.73% | |
Variable rate obligations | $ 763 | [1] |
PG&E Corporation [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 2.40% | |
Fixed rate obligations | $ 350 | |
2017 [Member] | ||
Debt [Line Items] | ||
Total consolidated long-term debt | $ 700 | |
2017 [Member] | Pacific Gas And Electric Company [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 5.625% | |
Fixed rate obligations | $ 700 | |
Variable interest rate as of December 31, 2016 | 0.00% | |
Variable rate obligations | $ 0 | [1] |
2017 [Member] | PG&E Corporation [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 0.00% | |
Fixed rate obligations | $ 0 | |
2018 [Member] | ||
Debt [Line Items] | ||
Total consolidated long-term debt | $ 800 | |
2018 [Member] | Pacific Gas And Electric Company [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 8.25% | |
Fixed rate obligations | $ 800 | |
Variable interest rate as of December 31, 2016 | 0.00% | |
Variable rate obligations | $ 0 | [1] |
2018 [Member] | PG&E Corporation [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 0.00% | |
Fixed rate obligations | $ 0 | |
2019 [Member] | ||
Debt [Line Items] | ||
Total consolidated long-term debt | $ 499 | |
2019 [Member] | Pacific Gas And Electric Company [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 0.00% | |
Fixed rate obligations | $ 0 | |
Variable interest rate as of December 31, 2016 | 0.74% | |
Variable rate obligations | $ 149 | [1] |
2019 [Member] | PG&E Corporation [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 2.40% | |
Fixed rate obligations | $ 350 | |
2020 [Member] | ||
Debt [Line Items] | ||
Total consolidated long-term debt | $ 1,414 | |
2020 [Member] | Pacific Gas And Electric Company [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 3.50% | |
Fixed rate obligations | $ 800 | |
Variable interest rate as of December 31, 2016 | 0.73% | |
Variable rate obligations | $ 614 | [1] |
2020 [Member] | PG&E Corporation [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 0.00% | |
Fixed rate obligations | $ 0 | |
2021 [Member] | ||
Debt [Line Items] | ||
Total consolidated long-term debt | $ 550 | |
2021 [Member] | Pacific Gas And Electric Company [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 3.80% | |
Fixed rate obligations | $ 550 | |
Variable interest rate as of December 31, 2016 | 0.00% | |
Variable rate obligations | $ 0 | [1] |
2021 [Member] | PG&E Corporation [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 0.00% | |
Fixed rate obligations | $ 0 | |
Thereafter [Member] | ||
Debt [Line Items] | ||
Total consolidated long-term debt | $ 13,120 | |
Thereafter [Member] | Pacific Gas And Electric Company [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 4.84% | |
Fixed rate obligations | $ 13,120 | |
Variable interest rate as of December 31, 2016 | 0.00% | |
Variable rate obligations | $ 0 | [1] |
Thereafter [Member] | PG&E Corporation [Member] | ||
Debt [Line Items] | ||
Average fixed interest rate | 0.00% | |
Fixed rate obligations | $ 0 | |
[1] | The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019 or December 1, 2020. |
Debt (Schedule Of Line Of Credi
Debt (Schedule Of Line Of Credit) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Jul. 02, 2015 | Apr. 27, 2015 | ||
Pacific Gas And Electric Company [Member] | ||||
Debt [Line Items] | ||||
Expiration date for credit agreement | Apr. 27, 2021 | |||
Facility Limit | [1] | $ 3,000 | ||
Letters of Credit outstanding | 41 | |||
Commercial Paper | 1,016 | |||
Facility Availability | 1,943 | |||
Letters of credit, sublimit | 500 | $ 1,000 | ||
Swingline loans, sublimit | 75 | 300 | ||
Commercial Paper Sublimit | $ 2,500 | $ 1,750 | ||
PG&E Corporation [Member] | ||||
Debt [Line Items] | ||||
Expiration date for credit agreement | Apr. 27, 2021 | |||
Facility Limit | [2] | $ 300 | ||
Letters of Credit outstanding | 0 | |||
Commercial Paper | 0 | |||
Facility Availability | 300 | |||
Letters of credit, sublimit | 50 | $ 100 | ||
Swingline loans, sublimit | 100 | |||
Commercial Paper Sublimit | 300 | |||
Credit Facilities [Member] | ||||
Debt [Line Items] | ||||
Facility Limit | 3,300 | |||
Letters of Credit outstanding | 41 | |||
Commercial Paper | 1,016 | |||
Facility Availability | $ 2,243 | |||
[1] | Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans. | |||
[2] | Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. |
Common Stock And Share-Based 51
Common Stock And Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Common stock, shares outstanding | 506,891,874 | 492,025,443 |
Dividend per share | $ 0.49 | $ 0.445 |
Debt covenant ratio of total consolidated debt to total consolidated capitalization percentage | 65.00% | |
Percentage of equity for capital structure to be maintained | 52.00% | |
Common stock | $ 12,198,000 | $ 11,282,000 |
Equity Contract [Member] | ||
Equity distribution agreement amount | $ 275,000 | |
Common stock shares issued | 2,600,000 | |
Fees and Commissions | $ 1,300 | |
Common stock | $ 149,000 | |
Underwritten Public Offering [Member] | ||
Sale of common stock in an underwritten public offering | 4,900,000 | |
Common stock issued, amount | $ 309,000 | |
Four Zero One K Plan D R S P P Shared Based Compensation Plans [Member] | ||
Common stock shares issued | 7,400,603 | |
Common stock | $ 364,000 | |
Utility [Member] | ||
Net restricted assets for revolving credit facility ratio requirement | 15,800,000 | |
Additional Common Stock Dividends | $ 25,000 |
Common Stock And Share-Based 52
Common Stock And Share-Based Compensation (Long-Term Incentive Plan) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares issued for LTIP, maximum | 17,000,000 | ||
Shares available for LTIP award | 13,826,995 | ||
Total Compensation Expense (pre-tax) | $ 108 | $ 93 | $ 78 |
Total Compensation Expense (after-tax) | 64 | 55 | 47 |
Restricted Stock Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total Compensation Expense (pre-tax) | 53 | 47 | 42 |
Performance Shares, Equity Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total Compensation Expense (pre-tax) | $ 55 | $ 46 | $ 36 |
Common Stock And Share-Based 53
Common Stock And Share-Based Compensation (Restricted Stock Units) (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Common Stock And Share-Based Compensation [Abstract] | |||
Total fair value | $ 36 | $ 57 | $ 34 |
Total unrecognized compensation costs | $ 37 | ||
Remaining weighted average period, Years | 1 year 2 months 19 days | ||
Nonvested at January 1, Number of Restricted Stock Units | 1,972,899 | ||
Granted, Number of Restricted Stock Units | 776,312 | ||
Vested, Number of Restricted Stock Units | (770,968) | ||
Forfeited, Number of Restricted Stock Units | (55,233) | ||
Nonvested at December 31, Number of Restricted Stock Units | 1,923,010 | 1,972,899 | |
Nonvested at January 1, Weighted Average Grant-Date Fair Value | $ 47.33 | ||
Granted, Weighted Average Grant Date Fair Value | 56.68 | $ 53.3 | $ 43.76 |
Vested, Weighted Average Grant Date Fair Value | 46.79 | ||
Forfeited, Weighted Average Grant Date Fair Value | 49.65 | ||
Nonvested at December 31, Weighted Average Grant-Date Fair Value | $ 51.26 | $ 47.33 |
Common Stock And Share-Based 54
Common Stock And Share-Based Compensation (Performance Shares) (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Weighted-average period (years) | 1 year 6 months 26 days | |||
Performance Shares, Equity Awards [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized | $ 40 | |||
Nonvested at January 1, Number of Performance Shares | 1,450,612 | |||
Granted, Number of Performance Shares | 1,233,884 | |||
Vested, Number of Performance Shares | (777,719) | |||
Forfeited, Number of Performance Shares | [1] | (67,922) | ||
Nonvested at December 31, Number of Performance Shares | 1,838,855 | 1,450,612 | ||
Nonvested at January 1, Weighted Average Exercise Price | $ 59.24 | |||
Granted, Weighted Average Exercise Price | 53.61 | $ 68.27 | $ 51.81 | |
Vested, Weighted Average Exercise Price | 51.81 | |||
Forfeited, Weighted Average Exercise Price | [1] | 58.20 | ||
Nonvested at December 31, Weighted Average Exercise Price | $ 58.65 | $ 59.24 | ||
[1] | Includes performance shares that expired with 50% value as a result of total shareholder return results. |
Preferred Stock (Narrative) (De
Preferred Stock (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pacific Gas And Electric Company [Member] | |||
Preferred Stock [Line Items] | |||
Preferred stock dividends | $ 14 | $ 14 | $ 14 |
$25 Par Value [Member] | |||
Preferred Stock [Line Items] | |||
Preferred stock, par value | $ 25 | ||
Preferred stock, shares issued | 75,000,000 | ||
$25 Par Value [Member] | Pacific Gas And Electric Company [Member] | |||
Preferred Stock [Line Items] | |||
Preferred stock, par value | $ 25 | ||
$100 Par Value [Member] | Pacific Gas And Electric Company [Member] | |||
Preferred Stock [Line Items] | |||
Preferred stock, par value | $ 100 | ||
Preferred stock, shares issued | 10,000,000 | ||
$100 Par Value [Member] | PG&E Corporation [Member] | |||
Preferred Stock [Line Items] | |||
Preferred stock, par value | $ 100 | ||
Preferred stock, shares issued | 5,000,000 | ||
No Par Value [Member] | PG&E Corporation [Member] | |||
Preferred Stock [Line Items] | |||
Preferred stock, shares authorized | 80 | ||
Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | |||
Preferred Stock [Line Items] | |||
Preferred stock dividends per share, low range | $ 1.25 | ||
Preferred stock dividends per share, high range | 1.5 | ||
Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | |||
Preferred Stock [Line Items] | |||
Preferred stock dividends per share, low range | 1.09 | ||
Preferred stock dividends per share, high range | $ 1.25 |
Preferred Stock (Summary Of Iss
Preferred Stock (Summary Of Issued And Outstanding Preferred Stock) (Details) $ / shares in Units, $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($)$ / shares | |
Minimum [Member] | |
Preferred Stock [Line Items] | |
Redemption Price | $ / shares | $ 25.75 |
Maximum [Member] | |
Preferred Stock [Line Items] | |
Redemption Price | $ / shares | $ 27.25 |
Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | |
Preferred Stock [Line Items] | |
Nonredeemable preferred stock, value | $ | $ 145 |
Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Minimum [Member] | |
Preferred Stock [Line Items] | |
Preferred stock interest rate | 5.00% |
Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | |
Preferred Stock [Line Items] | |
Redeemable preferred stock, value | $ | $ 113 |
Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Minimum [Member] | |
Preferred Stock [Line Items] | |
Preferred stock interest rate | 4.36% |
6.00% Series [Member] | Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Maximum [Member] | |
Preferred Stock [Line Items] | |
Preferred stock interest rate | 6.00% |
5.00% Series A [Member] | Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Maximum [Member] | |
Preferred Stock [Line Items] | |
Preferred stock interest rate | 5.00% |
Earnings Per Share (Reconciliat
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 ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Earnings Per Share [Abstract] | |||
Income available for common shareholders | $ 1,393 | $ 874 | $ 1,436 |
Weighted average common shares outstanding, basic | 499 | 484 | 468 |
Add Incremental Shares From Assumed conversions: | |||
Employee share-based compensation | 2 | 3 | 2 |
Weighted average common shares outstanding, diluted | 501 | 487 | 470 |
Total earnings per common share, diluted | $ 2.78 | $ 1.79 | $ 3.06 |
Income Taxes (Schedule Of Incom
Income Taxes (Schedule Of Income Tax Provision) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Current, Federal | $ (105) | $ (89) | $ (84) |
Current, State | (70) | 11 | (41) |
Deferred, Federal | 218 | 131 | 396 |
Deferred, State | 16 | (76) | 78 |
Tax credits | (4) | (4) | (4) |
Income Tax Provision | 55 | (27) | 345 |
Pacific Gas And Electric Company [Member] | |||
Current, Federal | (105) | (88) | (84) |
Current, State | (66) | 6 | (29) |
Deferred, Federal | 229 | 136 | 426 |
Deferred, State | 16 | (69) | 75 |
Tax credits | (4) | (4) | (4) |
Income Tax Provision | 70 | (19) | 384 |
PG&E Corporation [Member] | |||
Income Tax Provision | $ 15 | $ 3 | $ 39 |
Income Taxes (Schedule Of Defer
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | ||
Pacific Gas And Electric Company [Member] | ||||
Tax carryforwards | $ 1,596 | $ 1,462 | ||
Other | 402 | 700 | ||
Total deferred income tax assets | 1,998 | 2,162 | ||
Property related basis differences | 10,411 | 9,638 | ||
Income tax regulatory asset | 1,572 | 1,245 | [1] | |
Other | 525 | 766 | ||
Total deferred income tax liabilities | 12,508 | 11,649 | ||
Total net deferred income tax liabilities | 10,510 | 9,487 | ||
PG&E Corporation [Member] | ||||
Tax carryforwards | 1,851 | 1,703 | ||
Other | 463 | 757 | ||
Total deferred income tax assets | 2,314 | 2,460 | ||
Property related basis differences | 10,429 | 9,656 | ||
Income tax regulatory asset | [1] | 1,572 | 1,244 | |
Other | 526 | 766 | ||
Total deferred income tax liabilities | 12,527 | 11,666 | ||
Total net deferred income tax liabilities | $ 10,213 | $ 9,206 | ||
[1] | Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. (See Note 3 above.) |
Income Taxes (Schedule Of Effec
Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Pacific Gas And Electric Company [Member] | ||||
Federal statutory income tax rate | 35.00% | 35.00% | 35.00% | |
State income tax (net of federal benefit) | [1] | (2.20%) | (4.80%) | 1.60% |
Effect of regulatory treatment of fixed asset differences | [2] | (23.40%) | (33.70%) | (14.70%) |
Tax credits | (0.80%) | (1.30%) | (0.70%) | |
Benefit of loss carryback | (1.10%) | (1.50%) | (0.80%) | |
Non deductible penalties | [3] | 0.80% | 4.30% | 0.30% |
Other, net | (3.50%) | (0.20%) | 0.40% | |
Effective tax rate | 4.80% | (2.20%) | 21.10% | |
PG&E Corporation [Member] | ||||
Federal statutory income tax rate | 35.00% | 35.00% | 35.00% | |
State income tax (net of federal benefit) | [1] | (2.50%) | (4.90%) | 1.40% |
Effect of regulatory treatment of fixed asset differences | [2] | (23.70%) | (33.60%) | (15.00%) |
Tax credits | (0.80%) | (1.30%) | (0.70%) | |
Benefit of loss carryback | (1.10%) | (1.50%) | (0.80%) | |
Non deductible penalties | [3] | 0.80% | 4.30% | 0.30% |
Other, net | (3.90%) | (1.10%) | (0.80%) | |
Effective tax rate | 3.80% | (3.10%) | 19.40% | |
[1] | Includes the effect of state flow-through ratemaking treatment. | |||
[2] | Represents effect of federal flow-through ratemaking treatment including those deductions related to repairs and certain other property-related costs discussed below in the 2014 GRC Impact section. | |||
[3] | Represents the effects of non-tax deductible fines and penalties associated with the Penalty Decision. For more information about the Penalty Decision see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8. |
Income Taxes (Schedule Of Chang
Income Taxes (Schedule Of Change In Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pacific Gas And Electric Company [Member] | |||
Balance at beginning of year | $ 462 | $ 707 | $ 660 |
Additions for tax position taken during a prior year | 0 | 40 | 7 |
Reductions for tax position taken during a prior year | (77) | (349) | (9) |
Additions for tax position taken during the current year | 56 | 64 | 61 |
Settlements | (59) | 0 | (12) |
Balance at end of year | 382 | 462 | 707 |
PG&E Corporation [Member] | |||
Balance at beginning of year | 468 | 713 | 666 |
Additions for tax position taken during a prior year | 0 | 40 | 7 |
Reductions for tax position taken during a prior year | (77) | (349) | (9) |
Additions for tax position taken during the current year | 56 | 64 | 61 |
Settlements | (59) | 0 | (12) |
Balance at end of year | $ 388 | $ 468 | $ 713 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year | $ 25 |
Decrease of unrecognized tax benefit | 70 |
State [Member] | |
Net operating loss carryforwards | 0 |
Tax credit carryforward, amount | 51 |
Loss carryforwards, charitable contribution | $ 112 |
Charitable Contribution Carryforward Expiration Date [Minimum] | Dec. 31, 2019 |
Charitable Contribution Carryforward Expiration Date [Maximum] | Dec. 31, 2021 |
Federal [Member] | |
Net operating loss carryforwards | $ 5,009 |
Tax credit carryforward, amount | 116 |
Loss carryforwards, charitable contribution | $ 192 |
Tax Credit Carryforward Expiration Date [Minimum] | Dec. 31, 2029 |
Tax Credit Carryforward Expiration Date [Maximum] | Dec. 31, 2036 |
Charitable Contribution Carryforward Expiration Date [Minimum] | Dec. 31, 2017 |
Charitable Contribution Carryforward Expiration Date [Maximum] | Dec. 31, 2021 |
Minimum [Member] | State [Member] | |
Tax credit carryforward expiration date | |
Minimum [Member] | Federal [Member] | |
Tax credit carryforward expiration date | Dec. 31, 2029 |
Maximum [Member] | State [Member] | |
Tax credit carryforward expiration date | |
Maximum [Member] | Federal [Member] | |
Tax credit carryforward expiration date | Dec. 31, 2036 |
Derivatives And Hedging Activ63
Derivatives And Hedging Activities (Volumes Of Outstanding Derivative Contracts) (Details) | Dec. 31, 2016MMBTUMWh | Dec. 31, 2015MMBTUMWh | |
Forwards And Swaps [Member] | Natural Gas (MMBtus)[Member] | |||
Derivative [Line Items] | |||
Derivative Number of Instruments Held | MMBTU | [1],[2] | 323,301,331 | 333,091,813 |
Forwards And Swaps [Member] | Electricity (Megawatt-hours) [Member] | |||
Derivative [Line Items] | |||
Derivative Number of Instruments Held | MWh | 3,287,397 | 3,663,512 | |
Options [Member] | Natural Gas (MMBtus)[Member] | |||
Derivative [Line Items] | |||
Derivative Number of Instruments Held | MMBTU | [1],[2] | 96,602,785 | 111,550,004 |
Congestion Revenue Rights [Member] | Electricity (Megawatt-hours) [Member] | |||
Derivative [Line Items] | |||
Derivative Number of Instruments Held | MWh | [3] | 278,143,281 | 216,383,389 |
[1] | Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. | ||
[2] | Million British Thermal Units. | ||
[3] | CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations. |
Derivatives And Hedging Activ64
Derivatives And Hedging Activities (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Other Current Assets [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | $ 91 | $ 97 |
Cash Collateral | 1 | 25 |
Total Derivative Balances | 82 | 118 |
Derivative Liability Offsetting Derivative Asset | (10) | (4) |
Other Noncurrent Assets [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | 149 | 172 |
Cash Collateral | 0 | 0 |
Total Derivative Balances | 140 | 170 |
Derivative Liability Offsetting Derivative Asset | (9) | (2) |
Other Current Liabilities [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (48) | (102) |
Cash Collateral | 0 | 44 |
Total Derivative Balances | (38) | (54) |
Derivative Asset Offsetting Derivative Liability | 10 | 4 |
Other Noncurrent Liabilities [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (101) | (140) |
Cash Collateral | 3 | 21 |
Total Derivative Balances | (89) | (117) |
Derivative Asset Offsetting Derivative Liability | 9 | 2 |
Gross Derivative Balance [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Total Gross Derivative Balance | 91 | 27 |
Netting [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Derivative Asset Offsetting Derivative Liability | 0 | 0 |
Cash Collatera [lMember] | ||
Derivatives And Hedging Activities [Line Items] | ||
Cash Collateral | 4 | 90 |
Total Derivatve Balance [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Total Derivative Balances | $ 95 | $ 117 |
Derivatives And Hedging Activ65
Derivatives And Hedging Activities (Gains And Losses On Derivative Instruments) (Details) - PGE Corporation Utility [Member] - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Unrealized (loss) gain - regulatory assets and liabilities | [1] | $ 64 | $ (6) | $ 124 |
Realized loss-cost of electricity | [2] | (53) | (14) | (83) |
Realized loss-cost of natural gas | [2] | (18) | (10) | (8) |
Total commodity risk instruments | $ (7) | $ (30) | $ 33 | |
[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. |
Derivatives And Hedging Activ66
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 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivatives And Hedging Activities [Abstract] | |||
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized | $ (24) | $ (2) | |
Related derivatives in an asset position | 19 | 0 | |
Collateral posting in the normal course of business related to these derivatives | 4 | 0 | |
Net position of derivative contracts/additional collateral posting requirements | [1] | $ (1) | $ (2) |
[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 (Assets
Fair Value Measurements (Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Amount primarily related to deferred taxes on appreciation of investment value | $ 333 | $ 314 | |||
Fair Value, Inputs, Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 105 | 64 | |||
Total assets | 2,541 | 2,321 | |||
Fair Value, Inputs, Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 687 | 658 | |||
Fair Value, Inputs, Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 181 | 259 | |||
Netting [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | [1] | (18) | 19 | ||
Estimate Of Fair Value [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 105 | 64 | |||
Total assets | 3,575 | 3,428 | |||
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 9 | 36 | |||
Global equity securities | 1,724 | 1,520 | |||
Fixed-income securities | 665 | 694 | |||
Total assets | 2,398 | 2,250 | [2] | ||
Assets measured at NAV | 0 | 0 | |||
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Global equity securities | 0 | 0 | |||
Fixed-income securities | 527 | 521 | |||
Total assets | 527 | 521 | [2] | ||
Assets measured at NAV | 0 | 0 | |||
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Global equity securities | 0 | 0 | |||
Fixed-income securities | 0 | 0 | |||
Total assets | 0 | 0 | |||
Assets measured at NAV | 0 | 0 | |||
Nuclear Decommissioning Trusts [Member] | Netting [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Global equity securities | 0 | 0 | |||
Fixed-income securities | 0 | 0 | |||
Total assets | 0 | 0 | |||
Assets measured at NAV | 0 | 0 | |||
Nuclear Decommissioning Trusts [Member] | Estimate Of Fair Value [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 9 | 36 | |||
Global equity securities | 1,724 | 1,520 | |||
Fixed-income securities | 1,192 | 1,215 | |||
Total assets | 2,939 | 2,784 | [2] | ||
Assets measured at NAV | 14 | 13 | |||
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 | 30 | 0 | |||
Electric | 30 | 0 | |||
Gas | 0 | 0 | |||
Electric | 9 | 69 | |||
Gas | 0 | 0 | |||
Total liabilities | 9 | 69 | |||
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 | 29 | 10 | |||
Electric | 18 | 9 | |||
Gas | 11 | 1 | |||
Electric | 12 | 1 | |||
Gas | 2 | 2 | |||
Total liabilities | 14 | 3 | |||
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 | 181 | 259 | |||
Electric | 181 | 259 | |||
Gas | 0 | 0 | |||
Electric | 126 | 170 | |||
Gas | 0 | 0 | |||
Total liabilities | 126 | 170 | |||
Price Risk Management Instruments [Member] | Netting [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | (18) | 19 | [1] | ||
Electric | (18) | 18 | [1] | ||
Gas | 0 | 1 | |||
Electric | [1] | (21) | (70) | ||
Gas | (1) | [1] | (1) | ||
Total liabilities | [1] | (22) | (71) | ||
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 | 222 | 288 | |||
Electric | 211 | 286 | |||
Gas | 11 | 2 | |||
Electric | 126 | 170 | |||
Gas | 1 | 1 | |||
Total liabilities | 127 | 171 | |||
Rabbi Trusts [Member] | Fair Value, Inputs, Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fixed-income securities | 0 | 0 | |||
Life insurance contracts | 0 | 0 | |||
Total assets | 0 | 0 | |||
Rabbi Trusts [Member] | Fair Value, Inputs, Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fixed-income securities | 61 | 57 | |||
Life insurance contracts | 70 | 70 | |||
Total assets | 131 | 127 | |||
Rabbi Trusts [Member] | Fair Value, Inputs, Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fixed-income securities | 0 | 0 | |||
Life insurance contracts | 0 | 0 | |||
Total assets | 0 | 0 | |||
Rabbi Trusts [Member] | Netting [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fixed-income securities | 0 | 0 | |||
Life insurance contracts | 0 | 0 | |||
Total assets | 0 | 0 | |||
Rabbi Trusts [Member] | Estimate Of Fair Value [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fixed-income securities | 61 | 57 | |||
Life insurance contracts | 70 | 70 | |||
Total assets | 131 | 127 | |||
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 8 | 7 | |||
Total assets | 8 | 7 | |||
Assets measured at NAV | 0 | 0 | |||
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 0 | 0 | |||
Assets measured at NAV | 0 | 0 | |||
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 0 | 0 | |||
Assets measured at NAV | 0 | 0 | |||
Long-Term Disability Trust [Member] | Netting [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 0 | 0 | |||
Assets measured at NAV | 0 | 0 | |||
Long-Term Disability Trust [Member] | Estimate Of Fair Value [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 8 | 7 | |||
Total assets | 178 | 165 | |||
Assets measured at NAV | $ 170 | $ 158 | |||
[1] | Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. | ||||
[2] | Represents amounts before deducting $333 million and $314 million at December 31, 2016 and 2015, respectively, primarily related to deferred taxes on appreciation of investment value. |
Fair Value Measurements (Level
Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Detail) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | ||
Congestion Revenue Rights [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, Fair Value | $ 181 | $ 259 | |
Liabilities, Fair Value | $ 35 | $ 63 | |
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 | $ 91 | $ 107 | |
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] | Congestion Revenue Rights [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | (11.88) | (161.36) |
Minimum [Member] | Forward Prices [Member] | Power Purchase Agreements [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | 18.07 | 15.08 |
Maximum [Member] | CRR Auction Prices [Member] | Congestion Revenue Rights [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | 6.93 | 8.76 |
Maximum [Member] | Forward Prices [Member] | Power Purchase Agreements [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | 38.80 | 37.27 |
[1] | Represents price per megawatt-hour |
Fair Value Measurements (Leve69
Fair Value Measurements (Level 3 Reconciliation) (Details) - Fair Value, Inputs, Level 3 [Member] - Price Risk Management Instruments [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Liability balance as of January 1 | $ 89 | $ 69 | |
Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts | [1] | (34) | 20 |
Liability balance as of December 31 | $ 55 | $ 89 | |
[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. |
Fair Value Measurements (Carryi
Fair Value Measurements (Carrying Amount And Fair Value Of Financial Instruments) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Carrying Amount [Member] | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ||
Debt financial instrument | $ 348 | $ 348 |
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 | 15,813 | 14,818 |
Fair Value Inputs Level2 [Member] | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ||
Debt financial instrument | 352 | 354 |
Fair Value Inputs Level2 [Member] | Pacific Gas And Electric Company [Member] | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ||
Debt financial instrument | $ 17,790 | $ 16,422 |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule Of Unrealized Gains Losses Related To Available-For-Sale Investments) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Schedule of Available-for-sale Securities [Line Items] | |||
Amount primarily related to deferred taxes on appreciation of investment value | $ 333 | $ 314 | |
Money Market Investments [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Amortized Cost | 9 | 36 | |
Total Unrealized Gains | 0 | 0 | |
Total Unrealized Losses | 0 | 0 | |
Total Fair Value | 9 | 36 | |
Global equity securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Amortized Cost | 584 | 508 | |
Total Unrealized Gains | 1,157 | 1,034 | |
Total Unrealized Losses | (3) | (9) | |
Total Fair Value | 1,738 | 1,533 | |
Fixed-Income Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Amortized Cost | 1,156 | 1,165 | |
Total Unrealized Gains | 48 | 58 | |
Total Unrealized Losses | (12) | (8) | |
Total Fair Value | 1,192 | 1,215 | |
Securities (Assets) [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Amortized Cost | [1],[2] | 1,749 | |
Total Unrealized Gains | [1],[2] | 1,205 | |
Total Unrealized Losses | [1],[2] | (15) | |
Total Fair Value | [1],[2] | $ 2,939 | |
Nuclear Decommissioning Trusts [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Amortized Cost | [1] | 1,709 | |
Total Unrealized Gains | [1] | 1,092 | |
Total Unrealized Losses | [1] | (17) | |
Total Fair Value | [1] | $ 2,784 | |
[1] | Represents amount before deducting $313 million, primarily related to deferred taxes on appreciation of investment value. | ||
[2] | Represents amounts before deducting $333 million and $314 million at December 31, 2016 and 2015, respectively, primarily related to deferred taxes on appreciation of investment value. |
Fair Value Measurements (Sche72
Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Fair Value Measurements [Abstract] | |
Less than 1 year | $ 13 |
1-5 years | 419 |
5-10 years | 255 |
More than 10 years | 505 |
Total maturities of debt securities | $ 1,192 |
Fair Value Measurements (Sche73
Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value Measurements [Abstract] | |||
Proceeds from sales and maturities of nuclear decommissioning trust investments | $ 1,295 | $ 1,268 | $ 1,336 |
Gross realized gains on sales of securities held as available-for-sale | 18 | 55 | 118 |
Gross realized losses on sales of securities held as available-for-sale | $ (26) | $ (37) | $ (12) |
Employee Benefit Plans (Reconci
Employee Benefit Plans (Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status) (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Defined Benefit Plan Disclosure [Line Items] | |||||
Noncurrent liability | $ (2,641) | $ (2,622) | |||
Decrease in other comprehensive income | 2 | 1 | $ 14 | ||
Other Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Fair value of plan assets at January 1 | 2,035 | 2,092 | |||
Actual return on plan assets | 167 | (26) | |||
Company contributions | 52 | 61 | |||
Plan participant contribution | 85 | 68 | |||
Benefits and expenses paid | (166) | (160) | |||
Fair value of plan assets at December 31 | 2,173 | 2,035 | 2,092 | ||
Projected benefit obligation at January 1 | 1,766 | 1,811 | |||
Service cost for benefits earned | 52 | 55 | |||
Interest cost | 76 | 71 | 76 | ||
Actuarial (gain) loss | 11 | (98) | |||
Plan amendments | 37 | 0 | |||
Benefits and expenses paid | (153) | (146) | |||
Federal subsidy on benefits paid | 3 | 4 | |||
Projected benefit obligation at December 31 | 1,877 | 1,766 | 1,811 | ||
Current liability | [1] | (72) | (75) | ||
Net assets (liabilities) at end of year | 296 | 269 | |||
Noncurrent asset | [1] | 368 | 344 | ||
Pension Plans Defined Benefit [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Fair value of plan assets at January 1 | 13,745 | 14,216 | |||
Actual return on plan assets | 1,358 | (176) | |||
Company contributions | 334 | 334 | |||
Benefits and expenses paid | (708) | (629) | |||
Fair value of plan assets at December 31 | 14,729 | 13,745 | 14,216 | ||
Projected benefit obligation at January 1 | 16,299 | 16,696 | |||
Service cost for benefits earned | 453 | 479 | |||
Interest cost | 715 | 673 | 695 | ||
Actuarial (gain) loss | 637 | (922) | |||
Plan amendments | (91) | 1 | |||
Transitional costs | 0 | ||||
Benefits and expenses paid | (708) | (629) | |||
Projected benefit obligation at December 31 | 17,305 | [2] | 16,299 | $ 16,696 | |
Current liability | (7) | (6) | |||
Noncurrent liability | (2,569) | (2,547) | |||
Net assets (liabilities) at end of year | $ (2,576) | $ (2,553) | |||
[1] | At December 31, 2016 and 2015, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. | ||||
[2] | PG&E Corporation's accumulated benefit obligation was $15.6 billion and $14.7 billion at December 31, 2016 and 2015, respectively. |
Employee Benefit Plans (Compone
Employee Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Other Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service cost | $ 52 | $ 55 | $ 45 | |
Interest cost | 76 | 71 | 76 | |
Expected return on plan assets | (107) | (112) | (103) | |
Amortization of prior service cost | 15 | 19 | 23 | |
Amortization of net actuarial loss | 4 | 4 | 2 | |
Net periodic benefit cost | 40 | 37 | 43 | |
Pension Plans Defined Benefit [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service cost | 453 | 479 | 383 | |
Interest cost | 715 | 673 | 695 | |
Expected return on plan assets | (828) | (873) | (807) | |
Amortization of prior service cost | 8 | 15 | 20 | |
Amortization of net actuarial loss | 24 | 10 | 2 | |
Net periodic benefit cost | 372 | 304 | 293 | |
Less: transfer to regulatory account | [1] | (34) | 34 | 42 |
Total | $ 338 | $ 338 | $ 335 | |
[1] | The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates. |
Employee Benefit Plans (Estimat
Employee Benefit Plans (Estimated Amortized Net Periodic Benefit For 2016) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Other Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Unrecognized prior service cost | $ 15 |
Unrecognized net actuarial loss | 4 |
Total | 19 |
Pension Plans Defined Benefit [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Unrecognized prior service cost | (7) |
Unrecognized net actuarial loss | 22 |
Total | $ 15 |
Employee Benefit Plans (Schedul
Employee Benefit Plans (Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost) (Details) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Expected return on plan assets | 5.30% | ||
Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate range | 4.05-4.19 | 4.27-4.48 | 3.89-4.09 |
Expected return on plan assets percentage range | 2.80-6.00 | 3.20-6.60 | 3.30-6.70 |
Pension Plans Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 4.11% | 4.37% | 4.00% |
Average rate of future compensation increases | 4.00% | 4.00% | 4.00% |
Expected return on plan assets | 5.30% | 6.10% | 6.20% |
Employee Benefit Plans (Sched78
Employee Benefit Plans (Schedule Of Assumed Health Care Cost Trend) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Employee Benefit Plans [Abstract] | |
Effect on postretirement benefit obligation, One-Percentage-Point Increase | $ 118 |
Effect on postretirement benefit obligation, One-Percentage-Point Decrease | (120) |
Effect on service and interest cost, One-Percentage-Point Increase | 9 |
Effect on service and interest cost, One-Percentage-Point Decrease | $ (10) |
Assumed health care cost trend rate | 7.20% |
Ultimate trend rate | 4.50% |
Assumed return | 5.30% |
10 year actual rate of return | 7.30% |
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used | 696 |
Employee Benefit Plans (Target
Employee Benefit Plans (Target Asset Allocation Percentages) (Details) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
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 | 58.00% | 58.00% | 58.00% |
Fixed Income Securities[Member] | Pension Plans Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Target Allocation Percentage of Assets, Other | 58.00% | 60.00% | 60.00% |
Real Assets [member] | Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Target Allocation Percentage of Assets, Other | 7.00% | 7.00% | 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% |
Absolute Return [Member] | Other Benefits [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] | 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 | 32.00% | 32.00% | 31.00% |
Global Equity Securities [Member] | Pension Plans Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Target Allocation Percentage of Assets, Other | 27.00% | 25.00% | 25.00% |
Employee Benefit Plans (Sched80
Employee Benefit Plans (Schedule Of Fair Value Of Plan Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | ||
Total fair value of plan assets for pension and other benefit plans | $ 16,999 | $ 15,793 |
Total Fair Value Of Trust Other Net Assets | 97 | 13 |
Other Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total fair value of plan assets for pension and other benefit plans | 2,177 | 2,040 |
Assets measured at NAV | 1,153 | 1,065 |
Pension Plans Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total fair value of plan assets for pension and other benefit plans | 14,822 | 13,753 |
Assets measured at NAV | 5,950 | 5,308 |
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 | 368 | 343 |
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 | 3,724 | 3,572 |
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 | 656 | 632 |
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 | 5,143 | 4,870 |
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 |
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 | 5 | 3 |
Short-term investments [Member] | Other Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total fair value of plan assets for pension and other benefit plans | 33 | 20 |
Short-term investments [Member] | Pension Plans Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total fair value of plan assets for pension and other benefit plans | 733 | 622 |
Short-term investments [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 | 33 | 20 |
Short-term investments [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 | 364 | 247 |
Short-term investments [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 |
Short-term investments [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 | 369 | 375 |
Short-term investments [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 |
Short-term investments [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 | 70 | 69 |
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 | 610 | 581 |
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 | 70 | 69 |
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 | 610 | 581 |
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 | 0 | 0 |
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 | 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 | 115 | 104 |
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 | 996 | 903 |
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 | 115 | 104 |
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 | 996 | 903 |
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 | 0 | 0 |
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 | 0 | 0 |
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 |
Employee Benefit Plans (Sched81
Employee Benefit Plans (Schedule Of Level 3 Reconciliation) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | $ 15,793 | |
Balance as of December 31 | 16,999 | $ 15,793 |
Other Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 2,040 | |
Balance as of December 31 | 2,177 | 2,040 |
Other Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 343 | |
Balance as of December 31 | 368 | 343 |
Other Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 632 | |
Balance as of December 31 | 656 | 632 |
Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 0 | |
Balance as of December 31 | 0 | 0 |
Pension Plans Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 13,753 | |
Balance as of December 31 | 14,822 | 13,753 |
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 3,572 | |
Balance as of December 31 | 3,724 | 3,572 |
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 4,870 | |
Balance as of December 31 | 5,143 | 4,870 |
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 3 | |
Balance as of December 31 | 5 | 3 |
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 782 | |
Balance as of December 31 | 806 | 782 |
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 150 | |
Balance as of December 31 | 150 | 150 |
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 632 | |
Balance as of December 31 | 656 | 632 |
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 | 0 | |
Balance as of December 31 | 0 | 0 |
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 6,339 | |
Balance as of December 31 | 6,533 | 6,339 |
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 1,841 | |
Balance as of December 31 | 1,754 | 1,841 |
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Balance as of January 1 | 4,495 | |
Balance as of December 31 | 4,774 | 4,495 |
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 | 3 | 12 |
Relating to assets still held at the reporting date | 3 | (3) |
Relating to assets sold during the period | 0 | 1 |
Purchases | 0 | 2 |
Settlements | (1) | (9) |
Balance as of December 31 | $ 5 | $ 3 |
Employee Benefit Plans (Sched82
Employee Benefit Plans (Schedule Of Estimated Benefits Expected To Be Paid) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Plans Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
2,017 | $ 739 | |
2,018 | 781 | |
2,019 | 821 | |
2,020 | 857 | |
2,021 | 892 | |
Thereafter in the succeeding five years | 4,879 | |
Employer contribution | 334 | $ 334 |
Expected employer contribution next year | 327 | |
Other Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
2,017 | 87 | |
2,018 | 93 | |
2,019 | 97 | |
2,020 | 103 | |
2,021 | 108 | |
Thereafter in the succeeding five years | 592 | |
Employer contribution | 52 | $ 61 |
Expected employer contribution next year | 61 | |
Federal Subsidy [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
2,017 | (8) | |
2,018 | (9) | |
2,019 | (10) | |
2,020 | (10) | |
2,021 | (11) | |
Thereafter in the succeeding five years | $ (15) |
Employee Benefit Plans (Sched83
Employee Benefit Plans (Schedule Of Employer Contribution Expense) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Employee Benefit Plans [Abstract] | |||
Retirement Savings Plan expense | $ 97 | $ 89 | $ 80 |
Resolution Of Remaining Chapter
Resolution Of Remaining Chapter 11 Disputed Claims (Changes In The Remaining Net Disputed Claims Liability) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Apr. 12, 2004 | |
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items] | |||
Escrow for payment of remaining net disputed claims | $ 0 | $ 228 | $ 1,700 |
Net disputed claims and customer refunds | 236 | $ 454 | |
Increase Decrease To Disputed Claims Liability Balance | 231 | ||
Increase Decrease To Escrow For Payment Of Remaining Net Disputed Claims | 161 | ||
CAISO And PX [Member] | |||
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items] | |||
Increase Decrease To Disputed Claims Liability Balance | 165 | ||
Increase Decrease To Escrow For Payment Of Remaining Net Disputed Claims | $ 66 |
Related Party Agreements And 85
Related Party Agreements And Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||
Current receivables | $ 18 | $ 22 | |
Current payables | 22 | 21 | |
Administrative Services Provided To PG&E Corporation [Member] | |||
Related Party Transaction [Line Items] | |||
Utility revenues from | 7 | 6 | $ 5 |
Administrative Services Received From PG&E Corporation [Member] | |||
Related Party Transaction [Line Items] | |||
Utility expenses from | 74 | 53 | 54 |
Utility Employee Benefit Due To PG&E Corporation [Member] | |||
Related Party Transaction [Line Items] | |||
Utility expenses from | $ 91 | $ 82 | $ 70 |
Commitments And Contingencies86
Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | ||
Loss Contingencies [Line Items] | ||||
PSEP disallowed capital expenditures | $ 507,000 | $ 407,000 | $ 116,000 | |
Pacific Gas And Electric Company [Member] | ||||
Loss Contingencies [Line Items] | ||||
PSEP disallowed capital expenditures | 507,000 | 407,000 | $ 116,000 | |
Utility [Member] | ||||
Loss Contingencies [Line Items] | ||||
Accrued legal liabilities | 45,000 | 63,000 | ||
Butte Fire [Member] | ||||
Loss Contingencies [Line Items] | ||||
Cumulative Legal Expenses Related to Butte Fire | $ 27,000 | |||
Number Of Structures Burned By Fire | 44 | |||
Vegetation Management Contractors | 2 | |||
Total Insurance Coverage | $ 900,000 | |||
Number Of Homes Burned By Fire | 549 | |||
Number Of Households Represented In Court | 950 | |||
Number of Master Complaints | 2 | |||
Number Of Outbuildings Burned By Fire | 368 | |||
Number of plaintiffs | 1,950 | |||
Number Of Fatalities Caused By Fire | 2 | |||
Number Of Commerical Properties Burned By Fire | 4 | |||
Fire Fighting Costs Recovery Requested | $ 90,000 | |||
Number Of Acres Burned | 70,868 | |||
Gas Distribution OII [Member] | ||||
Loss Contingencies [Line Items] | ||||
New Penalty Assessed By CPUC In Modified Presiding Officer Decision | $ 25,600 | |||
Fine Paid For Carmel Incident | 10,850 | |||
SED proposed an additional fine to the Utility | 7,000 | |||
Criminal Investigation [Member] | ||||
Loss Contingencies [Line Items] | ||||
Total maximum penalties | $ 3,000 | |||
Number of Alleged Felony Counts | 1 | |||
Number Of Counts The Jury Acquitted Utility | 6 | |||
Guilty Felony Count Of Obstructing Federal Agency Proceeding | 1 | |||
Number Of Counts Of Violations Of Integrity Management Regulations | 5 | |||
Dismissed Alleged Count Of Violation | 1 | |||
Number Of Years For Coporate Probation Period | 5 years | |||
Number Of Years With Oversight By Third Party Monitor | 5 years | |||
Number Of Years With Oversight By Third Party Monitor With Early Termination | 3 years | |||
Maximum [Member] | ||||
Loss Contingencies [Line Items] | ||||
S E D fines for self reported violations | $ 16,800 | |||
Safety And Enforcement Division Maximum Statutory Penalty Per Violation | 50 | |||
Minimum [Member] | ||||
Loss Contingencies [Line Items] | ||||
S E D fines for self reported violations | $ 50 | |||
Ex Parte Communications [Member] | ||||
Loss Contingencies [Line Items] | ||||
Total Ex Parte Communications | 164 | |||
CPUC Imposed Penalty Per Day Per Violation | $ 50 | |||
Penalty Decision Future Charges and Costs [Member] | ||||
Loss Contingencies [Line Items] | ||||
Disallowed Revenue For Pipeline Safety Expenses | [1] | 32,000 | ||
Total Penalty Decision Fines And Remedies | 32,000 | |||
Shareholder Funded Pipeline Safety Enhancement Plan Work | 850,000 | |||
Penalty Decision Cumulative Charges [Member] | ||||
Loss Contingencies [Line Items] | ||||
Customer bill credit paid | 400,000 | |||
Disallowed Revenue For Pipeline Safety Expenses | [1] | 129,000 | ||
Payment To State General Fund | 300,000 | |||
Total Penalty Decision Fines And Remedies | 1,518,000 | |||
PSEP disallowed capital expenditures | [2] | 689,000 | ||
Total Penalty Decision [Member] | ||||
Loss Contingencies [Line Items] | ||||
Customer bill credit paid | 400,000 | |||
C P U C Remedial Measures | [3] | 50,000 | ||
Disallowed Revenue For Pipeline Safety Expenses | [1] | 161,000 | ||
Payment To State General Fund | 300,000 | |||
Total Penalty Decision Fines And Remedies | 1,600,000 | |||
PSEP disallowed capital expenditures | [2] | 689,000 | ||
Insurance Receivable [Member] | Butte Fire [Member] | ||||
Loss Contingencies [Line Items] | ||||
Balance at December 31, 2015 | 0 | |||
Accrued Insurance Recoveries | 625,000 | |||
Reimbursements | (50,000) | |||
Balance at December 31, 2016 | 575,000 | $ 0 | ||
Potential Safety Citation [Member] | ||||
Loss Contingencies [Line Items] | ||||
Fines Related to Non-Operator Inspectors | $ 5,050 | |||
Amount of Time Required by the SED between Inspections | 39 months | |||
Fine For Not Completing Inspection Within Scheduled Time Frame | $ 350 | |||
Number Of Noncompliant Atmospheric Corrosion Inspections | 550,000 | |||
Percent Of Noncompliant Atmospheric Corrosion Inspections | 35.00% | |||
Fine For Not Reporting Self Identified Violations Within Ten Days Of Discovery | $ 50 | |||
SED Administrative Limit per Safety Citation | 8,000 | |||
Pipeline Safety Enhancement Plan [Member] | ||||
Loss Contingencies [Line Items] | ||||
CPUC authorized recovery | 766,000 | |||
Capitalized PSEP costs | 1,350,000 | |||
Pipeline Safety Enhancement Plan Charges | 665,000 | |||
2015-2018 [Member] | ||||
Loss Contingencies [Line Items] | ||||
GT&S Capital Dissallowance | 85,000 | |||
2011-2014 [Member] | ||||
Loss Contingencies [Line Items] | ||||
GT&S Capital Dissallowance | $ 134,000 | |||
Alleged Obstruction of NTSB Investigation [Member] | ||||
Loss Contingencies [Line Items] | ||||
Number of Alleged Felony Counts | 12 | |||
[1] | GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first quarter of 2017. | |||
[2] | The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs. On December 1, 2016, the CPUC issued a final phase two decision in the Utility’s 2015 GT&S rate case which allocates $689 million of the $850 million penalty to capital expenditures. | |||
[3] | In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated future remedy-related costs. |
Commitments And Contingencies87
Commitments And Contingencies (Loss Accrual) (Details) - Butte Fire [Member] - Loss Accrual [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Loss Contingencies [Line Items] | |
Balance at December 31, 2015 | $ 0 |
Accrued losses | 750 |
Payments | (60) |
Balance at December 31, 2016 | $ 690 |
Commitments And Contingencies88
Commitments And Contingencies (Impact Of Penalty Decision) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Impact Of Penalty Decision [Line Items] | ||||
Charge for disallowed capital | $ 507 | $ 407 | $ 116 | |
Penalty Decision [Member] | ||||
Impact Of Penalty Decision [Line Items] | ||||
Charge for disallowed capital | [1] | 283 | ||
Total Penalty Decision Fines And Remedies | 412 | |||
Disallowed Revenue For Pipeline Safety Expenses | [2] | 129 | ||
Total Penalty Decision [Member] | ||||
Impact Of Penalty Decision [Line Items] | ||||
Fine paid to the state | 300 | |||
Customer bill credit paid | 400 | |||
Charge for disallowed capital | [1] | 689 | ||
Total Penalty Decision Fines And Remedies | 1,600 | |||
CPUC estimated cost of other remedies | [3] | 50 | ||
Disallowed Revenue For Pipeline Safety Expenses | [2] | 161 | ||
Penalty Decision Cumulative Charges [Member] | ||||
Impact Of Penalty Decision [Line Items] | ||||
Fine paid to the state | 300 | |||
Customer bill credit paid | 400 | |||
Charge for disallowed capital | [1] | 689 | ||
Total Penalty Decision Fines And Remedies | 1,518 | |||
Disallowed Revenue For Pipeline Safety Expenses | [2] | 129 | ||
Penalty Decision Future Charges and Costs [Member] | ||||
Impact Of Penalty Decision [Line Items] | ||||
Total Penalty Decision Fines And Remedies | 32 | |||
Disallowed Revenue For Pipeline Safety Expenses | [2] | 32 | ||
Pacific Gas And Electric Company [Member] | ||||
Impact Of Penalty Decision [Line Items] | ||||
Charge for disallowed capital | $ 507 | $ 407 | $ 116 | |
[1] | The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs. On December 1, 2016, the CPUC issued a final phase two decision in the Utility’s 2015 GT&S rate case which allocates $689 million of the $850 million penalty to capital expenditures. | |||
[2] | GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first quarter of 2017. | |||
[3] | In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated future remedy-related costs. |
Commitments And Contingencies89
Commitments And Contingencies (Environmental Remediation Liability Composed) (Detail) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Topock natural gas compressor station | $ 299 | $ 300 |
Hinkley natural gas compressor station | 135 | 140 |
Former manufactured gas plant sites owned by the Utility or third parties | 285 | 271 |
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites | 131 | 164 |
Fossil fuel-fired generation facilities and sites | 108 | 94 |
Total environmental remediation liability | $ 958 | $ 969 |
Commitments And Contingencies90
Commitments And Contingencies (Environmental Remediation Contingencies) (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Long-term Purchase Commitment [Line Items] | |
Amount of environmental loss accrual expected to be recovered | $ 671,000 |
Utility Undiscounted Future Costs | $ 1,900 |
Pacific Gas And Electric Company [Member] | |
Long-term Purchase Commitment [Line Items] | |
Remediation cost recovery | 90.00% |
Commitments And Contingencies91
Commitments And Contingencies (Nuclear Insurance) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Long-term Purchase Commitment [Line Items] | |
Maximum total payment incurred per event under the loss sharing program | $ 375 |
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 |
Non Nuclear Incident [Member] | |
Long-term Purchase Commitment [Line Items] | |
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon | 2,600 |
EMANI [Member] | |
Long-term Purchase Commitment [Line Items] | |
Full insurance policy limit | 200 |
Potential premium obligation | 2 |
NEIL [Member] | |
Long-term Purchase Commitment [Line Items] | |
Potential premium obligation | 60 |
Diablo Canyon [Member] | |
Long-term Purchase Commitment [Line Items] | |
Maximum public liability per nuclear incident under Price-Anderson Act | 13,500 |
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act | 375 |
Maximum annual payment incurred per event under the loss sharing program | 255 |
Coverage for purchased public liability insurance, per incident | 38 |
Humboldt Bay Unit [Member] | |
Long-term Purchase Commitment [Line Items] | |
Amount of property damage coverage provided by NEIL | 131 |
Amount of liability insurance for Humboldt bay Unit 3 | 53 |
Humboldt Bay Unit [Member] | Nuclear Incident [Member] | |
Long-term Purchase Commitment [Line Items] | |
Amount of indemnification from the NRC for public liability arising from nuclear incidents | $ 500 |
Commitments And Contingencies92
Commitments And Contingencies (Third-Party Power Purchases) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Long-term Purchase Commitment [Line Items] | |
2,017 | $ 4,050 |
2,018 | 3,370 |
2,019 | 3,322 |
2,020 | 3,273 |
2,021 | 2,991 |
Thereafter | 30,097 |
Total | 47,103 |
Renewable Energy Power Purchase Agreements [Member] | |
Long-term Purchase Commitment [Line Items] | |
2,017 | 2,233 |
2,018 | 2,108 |
2,019 | 2,144 |
2,020 | 2,139 |
2,021 | 2,117 |
Thereafter | 27,685 |
Total | 38,426 |
Other Power Purchase Agreements [Member] | |
Long-term Purchase Commitment [Line Items] | |
2,017 | 369 |
2,018 | 284 |
2,019 | 225 |
2,020 | 179 |
2,021 | 147 |
Thereafter | 653 |
Total | 1,857 |
Nuclear Fuel Purchase Commitments [Member] | |
Long-term Purchase Commitment [Line Items] | |
2,017 | 97 |
2,018 | 93 |
2,019 | 95 |
2,020 | 130 |
2,021 | 49 |
Thereafter | 136 |
Total | 600 |
Natural Gas [Member] | |
Long-term Purchase Commitment [Line Items] | |
2,017 | 536 |
2,018 | 169 |
2,019 | 160 |
2,020 | 148 |
2,021 | 93 |
Thereafter | 455 |
Total | 1,561 |
Conventional Energy [Member] | |
Long-term Purchase Commitment [Line Items] | |
2,017 | 815 |
2,018 | 716 |
2,019 | 698 |
2,020 | 677 |
2,021 | 585 |
Thereafter | 1,168 |
Total | $ 4,659 |
Commitments And Contingencies93
Commitments And Contingencies (Third-Party Power Purchase Agreements) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Qualifying Facilities [Member] | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Long term contract for purchase commitments, date of contract expiration, beginning date | 2,017 | ||
Long term contract for purchase commitments, date of contract expiration, ending date | 2,028 | ||
Present value of fixed capacity payments, portion classified as current liabilities | $ 17 | $ 19 | |
Present value of fixed capacity payments, portion classified as noncurrent liabilities | 18 | 35 | |
Capitalized asset for fixed capacity payments for corresponding assets | 35 | 54 | |
Capitalized asset for fixed capacity payments, accumulated amortization | $ 148 | 147 | |
Renewable Energy [Member] | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Long term contract for purchase commitments, date of contract expiration, beginning date | 2,017 | ||
Long term contract for purchase commitments, date of contract expiration, ending date | 2,043 | ||
Power Purchases and Electric Capacity [Member] | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Costs Of Power Purchase | $ 3,500 | $ 3,500 | $ 3,600 |
Conventional Energy [Member] | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Long term contract for purchase commitments, date of contract expiration, beginning date | 2,017 | ||
Long term contract for purchase commitments, date of contract expiration, ending date | 2,033 |
Commitments And Contingencies94
Commitments And Contingencies (Gas Supply, Transportation And Storage) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pacific Gas And Electric Company [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Cost of natural gas purchases | $ 700 | $ 900 | $ 1,400 |
Natural Gas [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Long Term Contract For Purchase Commitments Expiration Beginning Date | 2,017 | ||
Long Term Contract For Purchase Commitments Expiration Ending Date | 2,026 |
Commitments And Contingencies95
Commitments And Contingencies (Nuclear Fuel Agreements) (Details) - Nuclear Fuel [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Long-term Purchase Commitment [Line Items] | |||
Long Term Contract For Purchase Commitments Expiration Beginning Date | 2,017 | ||
Long Term Contract For Purchase Commitments Expiration Ending Date | 2,025 | ||
Payments for Nuclear Fuel | $ 100 | $ 128 | $ 105 |
Other Commitments And Other Ope
Other Commitments And Other Operating Leases (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Commitments And Contingencies [Abstract] | |||
2,017 | $ 44 | ||
2,018 | 41 | ||
2,019 | 39 | ||
2,020 | 39 | ||
2,021 | 36 | ||
Thereafter | 168 | ||
Total | 367 | ||
Payments for other commitments and operating leases | $ 43 | $ 41 | $ 42 |
Property Subject To Or Available For Operating Lease Expiration Beginning Date | 2,017 | ||
Property Subject To Or Available For Operating Lease Expiration Ending Date | 2,052 |
Schedule I - Condensed Financ97
Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Income Statement) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating expenses | $ (15,489) | $ (15,325) | $ (14,640) |
Interest income | 23 | 9 | 9 |
Interest expense | (829) | (773) | (734) |
Other income (expense) | 91 | 117 | 70 |
Income Before Income Taxes | 1,462 | 861 | 1,795 |
Income tax provision (benefit) | 55 | (27) | 345 |
Income Available for Common Shareholders | 1,393 | 874 | 1,436 |
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract] | |||
Net change in investments (net of taxes $0, $12, and $17, at respective dates) | 0 | (17) | (25) |
Total other comprehensive income (loss) | (2) | (18) | (39) |
Comprehensive Income | $ 1,405 | $ 870 | $ 1,411 |
Weighted average common shares outstanding, basic | 499 | 484 | 468 |
Weighted average common shares outstanding, diluted | 501 | 487 | 470 |
Net earnings per common share, basic | $ 2.79 | $ 1.81 | $ 3.07 |
Net earnings per common share, diluted | $ 2.78 | $ 1.79 | $ 3.06 |
PG&E Corporation [Member] | |||
Administrative service revenue | $ 70 | $ 51 | $ 51 |
Operating expenses | (73) | (53) | (53) |
Interest income | 1 | 1 | 1 |
Interest expense | (10) | (10) | (14) |
Other income (expense) | 2 | 30 | (1) |
Equity in earnings of subsidiaries | 1,388 | 852 | 1,413 |
Income Before Income Taxes | 1,378 | 871 | 1,397 |
Income tax provision (benefit) | 15 | 3 | 39 |
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract] | |||
Pension and other postretirement benefit plans (net of taxes of $1, $0, $10, at respective dates) | (2) | (1) | (14) |
Net change in investments (net of taxes $0, $12, and $17, at respective dates) | 0 | (17) | (25) |
Total other comprehensive income (loss) | (2) | (18) | (39) |
Comprehensive Income | $ 1,391 | $ 856 | $ 1,397 |
Weighted average common shares outstanding, basic | 499 | 484 | 468 |
Weighted average common shares outstanding, diluted | 501 | 487 | 470 |
Net earnings per common share, basic | $ 2.79 | $ 1.81 | $ 3.07 |
Net earnings per common share, diluted | $ 2.78 | $ 1.79 | $ 3.06 |
Schedule I - Condensed Financ98
Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Balance Sheet) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Cash and cash equivalents | $ 177 | $ 123 | $ 151 | $ 296 |
Advances to affiliates | 22 | 21 | ||
Income taxes receivable | 160 | 155 | ||
Other Assets, Current | 283 | 338 | ||
Total current assets | 6,164 | 5,813 | ||
Equipment | 72,595 | 67,342 | ||
Accumulated depreciation | (22,014) | (20,619) | ||
Net property, plant, and equipment | 50,581 | 46,723 | ||
Income taxes receivable | 70 | 135 | ||
Other | 1,226 | 1,064 | ||
TOTAL ASSETS | 68,598 | 63,234 | ||
Short-term borrowings | 1,516 | 1,019 | ||
Long-term debt, classified as current | 700 | 160 | ||
Other | 2,323 | 1,997 | ||
Total current liabilities | 7,564 | 6,363 | ||
Long-term debt | 16,220 | 15,925 | ||
Other | 2,279 | 2,326 | ||
Total noncurrent liabilities | 42,842 | 40,043 | ||
Common stock | 12,198 | 11,282 | ||
Reinvested earnings | 5,751 | 5,301 | ||
Accumulated other comprehensive income (loss) | (9) | (7) | ||
Total shareholders' equity | 17,940 | 16,576 | ||
TOTAL LIABILITIES AND EQUITY | 68,598 | 63,234 | ||
PG&E Corporation [Member] | ||||
Cash and cash equivalents | 106 | 64 | $ 96 | $ 231 |
Advances to affiliates | 24 | 22 | ||
Income taxes receivable | 25 | 24 | ||
Other Assets, Current | 0 | 1 | ||
Total current assets | 155 | 111 | ||
Equipment | 2 | 2 | ||
Accumulated depreciation | (2) | (2) | ||
Net property, plant, and equipment | 0 | 0 | ||
Investments in subsidiaries | 18,172 | 16,837 | ||
Other investments | 133 | 130 | ||
Deferred income taxes | 267 | 250 | ||
Total noncurrent assets | 18,572 | 17,217 | ||
TOTAL ASSETS | 18,727 | 17,328 | ||
Accounts payable - other | 7 | 3 | ||
Other | 274 | 246 | ||
Total current liabilities | 281 | 249 | ||
Long-term debt | 348 | 348 | ||
Other | 158 | 155 | ||
Total noncurrent liabilities | 506 | 503 | ||
Common stock | 12,198 | 11,282 | ||
Reinvested earnings | 5,751 | 5,301 | ||
Accumulated other comprehensive income (loss) | (9) | (7) | ||
Total shareholders' equity | 17,940 | 16,576 | ||
TOTAL LIABILITIES AND EQUITY | $ 18,727 | $ 17,328 |
Schedule I - Condensed Financ99
Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Statement Of Cash Flows) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Net income | $ 1,407 | $ 888 | $ 1,450 | |
Deferred income taxes and tax credits, net | 1,030 | 693 | 690 | |
Net cash provided by operating activities | 4,409 | 3,780 | 3,690 | |
Other | 13 | 22 | 114 | |
Net cash used in investing activities | (5,526) | (5,211) | (4,714) | |
Borrowings under revolving credit facilities | 0 | 0 | (260) | |
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014 | 983 | 1,123 | 2,308 | |
Repayments of long-term debt | 160 | 0 | 889 | |
Common stock issued | 822 | 780 | 802 | |
Common stock dividends paid | (921) | (856) | (828) | |
Other | (44) | (27) | 29 | |
Net cash (used) in financing activities | 1,171 | 1,403 | 879 | |
Net change in cash and cash equivalents | 54 | (28) | (145) | |
Cash and cash equivalents at January 1 | 123 | 151 | 296 | |
Cash and cash equivalents at December 31 | 177 | 123 | 151 | |
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs | 17 | 27 | 17 | |
Cash received (paid) for: | ||||
Interest, net of amounts capitalized | (726) | (684) | (633) | |
Income taxes, net | 231 | 77 | 501 | |
Noncash common stock issuances | (20) | (21) | (21) | |
Common stock dividends declared but not yet paid | (248) | (224) | (217) | |
PG&E Corporation [Member] | ||||
Net income | 1,393 | 874 | 1,436 | |
Stock-based compensation amortization | 74 | 66 | 65 | |
Equity in earnings of subsidiaries | (1,388) | (852) | (1,413) | |
Deferred income taxes and tax credits, net | 11 | 10 | (72) | |
Noncurrent income taxes receivable/payable | 0 | 0 | 5 | |
Current income taxes receivable/payable | (1) | 5 | (16) | |
Other | (24) | (70) | 43 | |
Net cash provided by operating activities | 65 | 33 | 48 | |
Investment in subsidiaries | (835) | (705) | (978) | |
Dividends received from subsidiaries | [1] | 911 | 716 | 716 |
Proceeds from tax equity investments | 0 | 0 | 368 | |
Other | 0 | 0 | 0 | |
Net cash used in investing activities | 76 | 11 | 106 | |
Borrowings under revolving credit facilities | 0 | 0 | (260) | |
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014 | 0 | 0 | 347 | |
Repayments of long-term debt | 0 | 0 | (350) | |
Common stock issued | 822 | 780 | 802 | |
Common stock dividends paid | [2] | (921) | (856) | (828) |
Net cash (used) in financing activities | (99) | (76) | (289) | |
Net change in cash and cash equivalents | 42 | (32) | (135) | |
Cash and cash equivalents at January 1 | 64 | 96 | 231 | |
Cash and cash equivalents at December 31 | 106 | 64 | 96 | |
Cash received (paid) for: | ||||
Interest, net of amounts capitalized | (9) | (9) | (15) | |
Income taxes, net | (13) | 0 | 1 | |
Noncash common stock issuances | 20 | 21 | 21 | |
Common stock dividends declared but not yet paid | $ 248 | $ 224 | $ 217 | |
[1] | Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow. | |||
[2] | In January of 2016, PG&E Corporation paid a quarterly common stock dividend of $0.455 per share. In April, July and October of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share. In January, April, July, and October of 2015 and 2014, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share. |
Schedule II - Consolidated V100
Schedule II - Consolidated Valuation And Qualifying Accounts (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract] | ||||
Allowance for uncollectible accounts, Balance at Beginning of Period | [1] | $ 54 | $ 66 | $ 80 |
Allowance for uncollectible accounts, Charged to Costs and Expenses | [1] | 50 | 43 | 41 |
Allowance for uncollectible accounts, Deductions | [1],[2] | 46 | 55 | 55 |
Allowance for uncollectible accounts, Balance at End of Period | [1] | $ 58 | $ 54 | $ 66 |
[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. |