Cover Page
Cover Page - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Feb. 13, 2020 | Jun. 30, 2019 | |
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Transition Report | false | ||
Entity File Number | 1-12609 | ||
Entity Incorporation, State or Country Code | CA | ||
Entity Tax Identification Number | 94-3234914 | ||
Entity Address, Address Line One | 77 Beale Street | ||
Entity Address, Address Line Two | P.O. Box 770000 | ||
Entity Address, City or Town | San Francisco, | ||
Entity Address, State or Province | CA | ||
Entity Address, Postal Zip Code | 94117 | ||
City Area Code | 415 | ||
Local Phone Number | 973-1000 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Bankruptcy Proceedings, Reporting Current | false | ||
Entity Public Float | $ 12,130 | ||
Entity Common Stock, Shares Outstanding | 529,254,082 | ||
Documents Incorporated by Reference | DOCUMENTS INCORPORATED BY REFERENCE Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved: Designated portions of the Joint Proxy Statement relating to the 2020 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14) | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | PG&E CORP | ||
Entity Central Index Key | 0001004980 | ||
Current Fiscal Year End Date | --12-31 | ||
Pacific Gas & Electric Co | |||
Entity File Number | 1-2348 | ||
Entity Incorporation, State or Country Code | CA | ||
Entity Tax Identification Number | 94-0742640 | ||
Entity Address, Address Line One | 77 Beale Street | ||
Entity Address, Address Line Two | P.O. Box 770000 | ||
Entity Address, City or Town | San Francisco, | ||
Entity Address, State or Province | CA | ||
Entity Address, Postal Zip Code | 94117 | ||
City Area Code | 415 | ||
Local Phone Number | 973-1000 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Bankruptcy Proceedings, Reporting Current | false | ||
Entity Common Stock, Shares Outstanding | 264,374,809 | ||
Documents Incorporated by Reference | DOCUMENTS INCORPORATED BY REFERENCE Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved: Designated portions of the Joint Proxy Statement relating to the 2020 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14) | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | PACIFIC GAS & ELECTRIC CO | ||
Entity Central Index Key | 0000075488 | ||
The New York Stock Exchange | Common stock, no par value | |||
Title of 12(b) Security | Common stock, no par value | ||
Trading Symbol | PCG | ||
Security Exchange Name | NYSE | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% series A redeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 5% series A redeemable | ||
Trading Symbol | PCG-PE | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% redeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 5% redeemable | ||
Trading Symbol | PCG-PD | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.80% redeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 4.80% redeemable | ||
Trading Symbol | PCG-PG | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.50% redeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 4.50% redeemable | ||
Trading Symbol | PCG-PH | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable | ||
Trading Symbol | PCG-PI | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 6% nonredeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 6% nonredeemable | ||
Trading Symbol | PCG-PA | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable | ||
Trading Symbol | PCG-PB | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% nonredeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 5% nonredeemable | ||
Trading Symbol | PCG-PC | ||
Security Exchange Name | NYSEAMER |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating Revenues | |||
Total operating revenues | $ 17,129 | $ 16,759 | $ 17,135 |
Operating Expenses | |||
Operating and maintenance | 8,725 | 7,153 | 6,321 |
Wildfire-related claims, net of insurance recoveries | 11,435 | 11,771 | 0 |
Depreciation, amortization, and decommissioning | 3,234 | 3,036 | 2,854 |
Total operating expenses | 27,223 | 26,459 | 14,230 |
Operating Income (Loss) | (10,094) | (9,700) | 2,905 |
Interest income | 82 | 76 | 31 |
Interest expense | (934) | (929) | (888) |
Other income, net | 250 | 424 | 123 |
Reorganization items, net | (346) | 0 | 0 |
Income (Loss) Before Income Taxes | (11,042) | (10,129) | 2,171 |
Income tax provision (benefit) | (3,400) | (3,292) | 511 |
Net Income (Loss) | (7,642) | (6,837) | 1,660 |
Preferred stock dividend requirement of subsidiary | 14 | 14 | 14 |
Income (Loss) Available for Common Shareholders | $ (7,656) | $ (6,851) | $ 1,646 |
Weighted Average Common Shares Outstanding, Basic (in shares) | 528 | 517 | 512 |
Weighted Average Common Shares Outstanding, Diluted (in shares) | 528 | 517 | 513 |
Net Earnings (Loss) Per Common Share, Basic (in dollars per share) | $ (14.50) | $ (13.25) | $ 3.21 |
Net Earnings (Loss) Per Common Share, Diluted (in dollars per share) | $ (14.50) | $ (13.25) | $ 3.21 |
Pacific Gas & Electric Co | |||
Operating Revenues | |||
Total operating revenues | $ 17,129 | $ 16,760 | $ 17,138 |
Operating Expenses | |||
Operating and maintenance | 8,750 | 7,153 | 6,383 |
Wildfire-related claims, net of insurance recoveries | 11,435 | 11,771 | 0 |
Depreciation, amortization, and decommissioning | 3,233 | 3,036 | 2,854 |
Total operating expenses | 27,247 | 26,459 | 14,292 |
Operating Income (Loss) | (10,118) | (9,699) | 2,846 |
Interest income | 82 | 74 | 30 |
Interest expense | (912) | (914) | (877) |
Other income, net | 239 | 426 | 119 |
Reorganization items, net | (320) | 0 | 0 |
Income (Loss) Before Income Taxes | (11,029) | (10,113) | 2,118 |
Income tax provision (benefit) | (3,407) | (3,295) | 427 |
Net Income (Loss) | (7,622) | (6,818) | 1,691 |
Preferred stock dividend requirement | 14 | 14 | 14 |
Income (Loss) Available for Common Shareholders | (7,636) | (6,832) | 1,677 |
Electric | |||
Operating Revenues | |||
Total operating revenues | 12,740 | 12,713 | 13,124 |
Operating Expenses | |||
Cost of goods | 3,095 | 3,828 | 4,309 |
Electric | Pacific Gas & Electric Co | |||
Operating Revenues | |||
Total operating revenues | 12,740 | 12,713 | 13,127 |
Operating Expenses | |||
Cost of goods | 3,095 | 3,828 | 4,309 |
Natural gas | |||
Operating Revenues | |||
Total operating revenues | 4,389 | 4,046 | 4,011 |
Operating Expenses | |||
Cost of goods | 734 | 671 | 746 |
Natural gas | Pacific Gas & Electric Co | |||
Operating Revenues | |||
Total operating revenues | 4,389 | 4,047 | 4,011 |
Operating Expenses | |||
Cost of goods | $ 734 | $ 671 | $ 746 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Net Income (Loss) | $ (7,642) | $ (6,837) | $ 1,660 |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations (net of taxes of $0, $2, and $0, at respective dates) | (1) | 4 | 1 |
Total other comprehensive income (loss) | (1) | 4 | 1 |
Comprehensive Income (Loss) | (7,643) | (6,833) | 1,661 |
Preferred stock dividend requirement of subsidiary | 14 | 14 | 14 |
Comprehensive Income (Loss) Attributable to Common Shareholders | (7,657) | (6,847) | 1,647 |
Pacific Gas & Electric Co | |||
Net Income (Loss) | (7,622) | (6,818) | 1,691 |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations (net of taxes of $0, $2, and $0, at respective dates) | 2 | (5) | 4 |
Total other comprehensive income (loss) | 2 | (5) | 4 |
Comprehensive Income (Loss) | $ (7,620) | $ (6,823) | $ 1,695 |
CONSOLIDATED STATEMENTS OF CO_2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pension and other postretirement benefit plans obligations, tax | $ 0 | $ 2 | $ 0 |
Pacific Gas & Electric Co | |||
Pension and other postretirement benefit plans obligations, tax | $ 1 | $ 2 | $ 3 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Current Assets | ||
Cash and cash equivalents | $ 1,570 | $ 1,668 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $43 and $56 at respective dates) | 1,287 | 1,148 |
Accrued unbilled revenue | 969 | 1,000 |
Regulatory balancing accounts | 2,114 | 1,435 |
Other | 2,617 | 2,686 |
Regulatory assets | 315 | 233 |
Inventories | ||
Gas stored underground and fuel oil | 97 | 111 |
Materials and supplies | 550 | 443 |
Income taxes receivable | 0 | 23 |
Other | 646 | 448 |
Total current assets | 10,165 | 9,195 |
Property, Plant, and Equipment | ||
Electric | 62,707 | 59,150 |
Gas | 22,688 | 21,556 |
Construction work in progress | 2,675 | 2,564 |
Other | 20 | 2 |
Total property, plant, and equipment | 88,090 | 83,272 |
Accumulated depreciation | (26,455) | (24,715) |
Net property, plant, and equipment | 61,635 | 58,557 |
Other Noncurrent Assets | ||
Regulatory assets | 6,066 | 4,964 |
Nuclear decommissioning trusts | 3,173 | 2,730 |
Operating lease right of use asset | 2,286 | |
Income taxes receivable | 67 | 69 |
Other | 1,804 | 1,480 |
Total other noncurrent assets | 13,396 | 9,243 |
TOTAL ASSETS | 85,196 | 76,995 |
Current Liabilities | ||
Short-term borrowings | 0 | 3,435 |
Long-term debt, classified as current | 0 | 18,559 |
Debtor-in-possession financing, classified as current | 1,500 | 0 |
Accounts payable | ||
Trade creditors | 1,954 | 1,975 |
Regulatory balancing accounts | 1,797 | 1,076 |
Other | 566 | 464 |
Operating lease liabilities | 556 | |
Disputed claims and customer refunds | 0 | 220 |
Wildfire-related claims | 0 | 14,226 |
Interest payable | 4 | 228 |
Other | 1,254 | 1,512 |
Total current liabilities | 7,631 | 41,695 |
Noncurrent Liabilities | ||
Regulatory liabilities | 9,270 | 8,539 |
Pension and other postretirement benefits | 1,884 | 2,119 |
Asset retirement obligations | 5,854 | 5,994 |
Deferred income taxes | 320 | 3,281 |
Operating lease liabilities | 1,730 | |
Other | 2,573 | 2,464 |
Total noncurrent liabilities | 21,631 | 22,397 |
Liabilities Subject to Compromise | 50,546 | 0 |
Contingencies and Commitments | ||
Shareholders' Equity | ||
Common stock, no par value | 13,038 | 12,910 |
Reinvested earnings | (7,892) | (250) |
Accumulated other comprehensive income (loss) | (10) | (9) |
Total shareholders' equity | 5,136 | 12,651 |
Noncontrolling Interest - Preferred Stock of Subsidiary | 252 | 252 |
Total equity | 5,388 | 12,903 |
TOTAL LIABILITIES AND EQUITY | 85,196 | 76,995 |
Pacific Gas & Electric Co | ||
Current Assets | ||
Cash and cash equivalents | 1,122 | 1,295 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $43 and $56 at respective dates) | 1,287 | 1,148 |
Accrued unbilled revenue | 969 | 1,000 |
Regulatory balancing accounts | 2,114 | 1,435 |
Other | 2,647 | 2,688 |
Regulatory assets | 315 | 233 |
Inventories | ||
Gas stored underground and fuel oil | 97 | 111 |
Materials and supplies | 550 | 443 |
Income taxes receivable | 0 | 5 |
Other | 635 | 448 |
Total current assets | 9,736 | 8,806 |
Property, Plant, and Equipment | ||
Electric | 62,707 | 59,150 |
Gas | 22,688 | 21,556 |
Construction work in progress | 2,675 | 2,564 |
Other | 18 | 0 |
Total property, plant, and equipment | 88,088 | 83,270 |
Accumulated depreciation | (26,453) | (24,713) |
Net property, plant, and equipment | 61,635 | 58,557 |
Other Noncurrent Assets | ||
Regulatory assets | 6,066 | 4,964 |
Nuclear decommissioning trusts | 3,173 | 2,730 |
Operating lease right of use asset | 2,279 | |
Income taxes receivable | 66 | 66 |
Other | 1,659 | 1,348 |
Total other noncurrent assets | 13,243 | 9,108 |
TOTAL ASSETS | 84,614 | 76,471 |
Current Liabilities | ||
Short-term borrowings | 0 | 3,135 |
Long-term debt, classified as current | 0 | 18,209 |
Debtor-in-possession financing, classified as current | 1,500 | 0 |
Accounts payable | ||
Trade creditors | 1,949 | 1,972 |
Regulatory balancing accounts | 1,797 | 1,076 |
Other | 675 | 498 |
Operating lease liabilities | 553 | |
Disputed claims and customer refunds | 0 | 220 |
Wildfire-related claims | 0 | 14,226 |
Interest payable | 4 | 227 |
Other | 1,263 | 1,497 |
Total current liabilities | 7,741 | 41,060 |
Noncurrent Liabilities | ||
Regulatory liabilities | 9,270 | 8,539 |
Pension and other postretirement benefits | 1,884 | 2,026 |
Asset retirement obligations | 5,854 | 5,994 |
Deferred income taxes | 442 | 3,405 |
Operating lease liabilities | 1,726 | |
Other | 2,626 | 2,492 |
Total noncurrent liabilities | 21,802 | 22,456 |
Liabilities Subject to Compromise | 49,736 | 0 |
Contingencies and Commitments | ||
Shareholders' Equity | ||
Preferred stock | 258 | 258 |
Common stock, no par value | 1,322 | 1,322 |
Additional paid-in capital | 8,550 | 8,550 |
Reinvested earnings | (4,796) | 2,826 |
Accumulated other comprehensive income (loss) | 1 | (1) |
Total shareholders' equity | 5,335 | 12,955 |
TOTAL LIABILITIES AND EQUITY | $ 84,614 | $ 76,471 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Allowance for doubtful accounts | $ 43 | $ 56 |
Common stock, par value (in dollars per share) | $ 0 | $ 0 |
Common stock, shares authorized (in shares) | 800,000,000 | 800,000,000 |
Common stock, shares outstanding (in shares) | 529,236,741 | 520,338,710 |
Pacific Gas & Electric Co | ||
Allowance for doubtful accounts | $ 43 | $ 56 |
Common stock, par value (in dollars per share) | $ 5 | $ 5 |
Common stock, shares authorized (in shares) | 800,000,000 | 800,000,000 |
Common stock, shares outstanding (in shares) | 264,374,809 | 264,374,809 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash Flows from Operating Activities | |||
Net Income (Loss) | $ (7,642) | $ (6,837) | $ 1,660 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, amortization, and decommissioning | 3,234 | 3,036 | 2,854 |
Allowance for equity funds used during construction | (79) | (129) | (89) |
Deferred income taxes and tax credits, net | (2,948) | (2,532) | 1,254 |
Reorganization items, net | 108 | 0 | 0 |
Disallowed capital expenditures | 581 | (45) | 47 |
Other | 207 | 332 | 307 |
Effect of changes in operating assets and liabilities: | |||
Accounts receivable | (104) | (121) | 67 |
Wildfire-related insurance receivable | 35 | (1,698) | (21) |
Inventories | (80) | (73) | (18) |
Accounts payable | 516 | 409 | 173 |
Wildfire-related claims | (114) | 13,665 | (129) |
Income taxes receivable/payable | 23 | (23) | 160 |
Other current assets and liabilities | 77 | (281) | 42 |
Regulatory assets, liabilities, and balancing accounts, net | (1,417) | (800) | (387) |
Liabilities subject to compromise | 12,222 | 0 | 0 |
Other noncurrent assets and liabilities | 197 | (151) | 57 |
Net cash provided by operating activities | 4,816 | 4,752 | 5,977 |
Cash Flows from Investing Activities | |||
Capital expenditures | (6,313) | (6,514) | (5,641) |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 956 | 1,412 | 1,291 |
Purchases of nuclear decommissioning trust investments | (1,032) | (1,485) | (1,323) |
Other | 11 | 23 | 23 |
Net cash used in investing activities | (6,378) | (6,564) | (5,650) |
Cash Flows from Financing Activities | |||
Proceeds from debtor-in-possession credit facility | 1,850 | 0 | 0 |
Repayments of debtor-in-possession credit facility | (350) | 0 | 0 |
Debtor-in-possession credit facility debt issuance costs | (113) | 0 | 0 |
Borrowings under revolving credit facilities | 0 | 3,960 | 0 |
Repayments under revolving credit facilities | 0 | (775) | 0 |
Net repayments of commercial paper, net of discount | 0 | (182) | (840) |
Short-term debt financing | 0 | 600 | 750 |
Short-term debt matured | 0 | (750) | (500) |
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs | 0 | 793 | 2,713 |
Long-term debt matured or repurchased | 0 | (795) | (1,445) |
Common stock dividends paid | 0 | 0 | (1,021) |
Other | (8) | (20) | (107) |
Net cash provided by (used in) financing activities | 1,464 | 3,031 | (55) |
Net change in cash, cash equivalents, and restricted cash | (98) | 1,219 | 272 |
Cash, cash equivalents, and restricted cash at January 1 | 1,675 | 456 | 184 |
Cash, cash equivalents, and restricted cash at December 31 | 1,577 | 1,675 | 456 |
Less: Restricted cash and restricted cash equivalents | (7) | (7) | (7) |
Cash and cash equivalents | 1,570 | 1,668 | 449 |
Cash received (paid) for: | |||
Interest, net of amounts capitalized | (10) | (786) | (790) |
Income taxes, net | 0 | (49) | 162 |
Supplemental disclosures of noncash investing and financing activities | |||
Capital expenditures financed through accounts payable | 826 | 368 | 501 |
Noncash common stock issuances | 0 | 0 | 21 |
Operating lease liabilities arising from obtaining ROU assets | 2,816 | 0 | 0 |
Pacific Gas & Electric Co | |||
Cash Flows from Operating Activities | |||
Net Income (Loss) | (7,622) | (6,818) | 1,691 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, amortization, and decommissioning | 3,233 | 3,036 | 2,854 |
Allowance for equity funds used during construction | (79) | (129) | (89) |
Deferred income taxes and tax credits, net | (2,952) | (2,548) | 1,103 |
Reorganization items, net | 97 | 0 | 0 |
Disallowed capital expenditures | 581 | (45) | 47 |
Other | 167 | 258 | 283 |
Effect of changes in operating assets and liabilities: | |||
Accounts receivable | (132) | (122) | 66 |
Wildfire-related insurance receivable | 35 | (1,698) | (21) |
Inventories | (80) | (73) | (18) |
Accounts payable | 579 | 421 | 173 |
Wildfire-related claims | (114) | 13,665 | (129) |
Income taxes receivable/payable | 5 | (5) | 159 |
Other current assets and liabilities | 101 | (301) | 59 |
Regulatory assets, liabilities, and balancing accounts, net | (1,417) | (800) | (390) |
Liabilities subject to compromise | 12,194 | 0 | 0 |
Other noncurrent assets and liabilities | 214 | (137) | 128 |
Net cash provided by operating activities | 4,810 | 4,704 | 5,916 |
Cash Flows from Investing Activities | |||
Capital expenditures | (6,313) | (6,514) | (5,641) |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 956 | 1,412 | 1,291 |
Purchases of nuclear decommissioning trust investments | (1,032) | (1,485) | (1,323) |
Other | 11 | 23 | 23 |
Net cash used in investing activities | (6,378) | (6,564) | (5,650) |
Cash Flows from Financing Activities | |||
Proceeds from debtor-in-possession credit facility | 1,850 | 0 | 0 |
Repayments of debtor-in-possession credit facility | (350) | 0 | 0 |
Debtor-in-possession credit facility debt issuance costs | (97) | 0 | 0 |
Borrowings under revolving credit facilities | 0 | 3,535 | 0 |
Repayments under revolving credit facilities | 0 | (650) | 0 |
Net repayments of commercial paper, net of discount | 0 | (50) | (972) |
Short-term debt financing | 0 | 250 | 750 |
Short-term debt matured | 0 | (750) | (500) |
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs | 0 | 793 | 2,713 |
Long-term debt matured or repurchased | 0 | (445) | (1,445) |
Preferred stock dividends paid | 0 | 0 | (14) |
Common stock dividends paid | 0 | 0 | (784) |
Equity contribution from PG&E Corporation | 0 | 45 | 455 |
Other | (8) | (20) | (93) |
Net cash provided by (used in) financing activities | 1,395 | 2,708 | 110 |
Net change in cash, cash equivalents, and restricted cash | (173) | 848 | 376 |
Cash, cash equivalents, and restricted cash at January 1 | 1,302 | 454 | 78 |
Cash, cash equivalents, and restricted cash at December 31 | 1,129 | 1,302 | 454 |
Less: Restricted cash and restricted cash equivalents | (7) | (7) | (7) |
Cash and cash equivalents | 1,122 | 1,295 | 447 |
Cash received (paid) for: | |||
Interest, net of amounts capitalized | (7) | (773) | (781) |
Income taxes, net | 0 | (59) | 162 |
Supplemental disclosures of noncash investing and financing activities | |||
Capital expenditures financed through accounts payable | 826 | 368 | 501 |
Operating lease liabilities arising from obtaining ROU assets | $ 2,807 | $ 0 | $ 0 |
CONSOLIDATED STATEMENTS OF CA_2
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash Flows from Financing Activities | |||
Discount on net issuances of commercial paper | $ 0 | $ 1 | $ 5 |
Premium, discount, and issuance costs on proceeds from long-term debt | 0 | 7 | 32 |
Pacific Gas & Electric Co | |||
Cash Flows from Financing Activities | |||
Discount on net issuances of commercial paper | 0 | 0 | 5 |
Premium, discount, and issuance costs on proceeds from long-term debt | $ 0 | $ 7 | $ 32 |
CONSOLIDATED STATEMENTS OF EQUI
CONSOLIDATED STATEMENTS OF EQUITY - USD ($) | Total | Pacific Gas & Electric Co | Preferred StockPacific Gas & Electric Co | Common Stock | Common StockPacific Gas & Electric Co | Additional Paid-in CapitalPacific Gas & Electric Co | Reinvested Earnings | Reinvested EarningsPacific Gas & Electric Co | Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss)Pacific Gas & Electric Co | Total Shareholders' Equity | Total Shareholders' EquityPacific Gas & Electric Co | Non controlling Interest - Preferred Stock of Subsidiary |
Balance, beginning of period (in shares) at Dec. 31, 2016 | 506,891,874 | ||||||||||||
Beginning balance at Dec. 31, 2016 | $ 18,192,000,000 | $ 258,000,000 | $ 12,198,000,000 | $ 1,322,000,000 | $ 8,050,000,000 | $ 5,751,000,000 | $ 8,763,000,000 | $ (9,000,000) | $ 2,000,000 | $ 17,940,000,000 | $ 18,395,000,000 | $ 252,000,000 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Net Income (Loss) | 1,660,000,000 | $ 1,691,000,000 | 1,660,000,000 | 1,691,000,000 | 1,660,000,000 | 1,691,000,000 | |||||||
Other comprehensive income (loss) | 1,000,000 | 4,000,000 | 1,000,000 | 4,000,000 | 1,000,000 | 4,000,000 | |||||||
Equity contribution | 455,000,000 | 0 | 455,000,000 | ||||||||||
Common stock issued, net (in shares) | 7,863,971 | ||||||||||||
Common stock issued, net | 416,000,000 | $ 416,000,000 | 416,000,000 | ||||||||||
Stock-based compensation amortization | 18,000,000 | $ 18,000,000 | 18,000,000 | ||||||||||
Common stock dividends declared | (801,000,000) | (801,000,000) | (784,000,000) | (801,000,000) | (784,000,000) | ||||||||
Preferred stock dividend | (14,000,000) | (14,000,000) | (14,000,000) | ||||||||||
Preferred stock dividend requirement of subsidiary | (14,000,000) | (14,000,000) | (14,000,000) | ||||||||||
Balance, end of period (in shares) at Dec. 31, 2017 | 514,755,845 | ||||||||||||
Ending balance at Dec. 31, 2017 | 19,472,000,000 | 258,000,000 | $ 12,632,000,000 | 1,322,000,000 | 8,505,000,000 | 6,596,000,000 | 9,656,000,000 | (8,000,000) | 6,000,000 | 19,220,000,000 | 19,747,000,000 | 252,000,000 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Net Income (Loss) | (6,837,000,000) | (6,818,000,000) | (6,837,000,000) | (6,818,000,000) | (6,837,000,000) | (6,818,000,000) | |||||||
Other comprehensive income (loss) | 4,000,000 | (5,000,000) | 5,000,000 | 2,000,000 | (1,000,000) | (7,000,000) | 4,000,000 | (5,000,000) | |||||
Equity contribution | 45,000,000 | 45,000,000 | |||||||||||
Common stock issued, net (in shares) | 5,582,865 | ||||||||||||
Common stock issued, net | 200,000,000 | $ 200,000,000 | 200,000,000 | ||||||||||
Stock-based compensation amortization | 78,000,000 | $ 78,000,000 | 78,000,000 | ||||||||||
Preferred stock dividend | $ 0 | (14,000,000) | (14,000,000) | ||||||||||
Preferred stock dividend requirement of subsidiary | $ (14,000,000) | (14,000,000) | (14,000,000) | ||||||||||
Balance, end of period (in shares) at Dec. 31, 2018 | 520,338,710 | 264,374,809 | 520,338,710 | ||||||||||
Ending balance at Dec. 31, 2018 | $ 12,903,000,000 | 258,000,000 | $ 12,910,000,000 | 1,322,000,000 | 8,550,000,000 | (250,000,000) | 2,826,000,000 | (9,000,000) | (1,000,000) | 12,651,000,000 | 12,955,000,000 | 252,000,000 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Net Income (Loss) | (7,642,000,000) | $ (7,622,000,000) | (7,642,000,000) | (7,622,000,000) | (7,642,000,000) | (7,622,000,000) | |||||||
Other comprehensive income (loss) | (1,000,000) | 2,000,000 | (1,000,000) | 2,000,000 | (1,000,000) | 2,000,000 | |||||||
Common stock issued, net (in shares) | 8,898,031 | ||||||||||||
Common stock issued, net | 85,000,000 | $ 85,000,000 | 85,000,000 | ||||||||||
Stock-based compensation amortization | $ 43,000,000 | $ 43,000,000 | 43,000,000 | ||||||||||
Preferred stock dividend | $ 0 | ||||||||||||
Balance, end of period (in shares) at Dec. 31, 2019 | 529,236,741 | 264,374,809 | 529,236,741 | ||||||||||
Ending balance at Dec. 31, 2019 | $ 5,388,000,000 | $ 258,000,000 | $ 13,038,000,000 | $ 1,322,000,000 | $ 8,550,000,000 | $ (7,892,000,000) | $ (4,796,000,000) | $ (10,000,000) | $ 1,000,000 | $ 5,136,000,000 | $ 5,335,000,000 | $ 252,000,000 |
ORGANIZATION AND BASIS OF PRESE
ORGANIZATION AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
ORGANIZATION AND BASIS OF PRESENTATION | ORGANIZATION AND BASIS OF PRESENTATION 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, operation, and decommissioning of the Utility’s nuclear generation facilities. This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The 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). The 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 wildfire-related liabilities, legal and regulatory contingencies, environmental remediation liabilities, insurance receivables, regulatory assets and liabilities, AROs, pension and other postretirement benefit plans obligations, and the valuation of LSTC. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred. Chapter 11 Filing and Going Concern The accompanying Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. However, as a result of the challenges that are further described below, such realization of assets and satisfaction of liabilities are subject to uncertainty. PG&E Corporation and the Utility suffered material losses as a result of the 2017 Northern California wildfires and the 2018 Camp fire, which contributed to the decision to file for Chapter 11 protection. See Note 14 below. Uncertainty regarding these matters raises substantial doubt about PG&E Corporation’s and the Utility’s abilities to continue as going concerns. PG&E Corporation and the Utility have determined that commencing reorganization cases under Chapter 11 was necessary to restore PG&E Corporation’s and the Utility’s financial stability to fund ongoing operations and provide safe service to customers. However, there can be no assurance that such proceedings will restore PG&E Corporation’s and the Utility’s financial stability. On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. The Consolidated Financial Statements do not include any adjustments that might be necessary should PG&E Corporation and the Utility be unable to continue as going concerns. Pursuant to sections 1107(a) and 1108 of the Bankruptcy Code, PG&E Corporation and the Utility retain control of their assets and are authorized to operate their business as debtors-in-possession while being subject to the jurisdiction of the Bankruptcy Court. While operating as debtors-in-possession under Chapter 11, PG&E Corporation and the Utility may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business and subject to restrictions in PG&E Corporation's and the Utility's DIP Credit Agreement (see Note 5 below) and applicable orders of the Bankruptcy Court, for amounts other than those reflected in the accompanying Consolidated Financial Statements. Any such actions occurring during the Chapter 11 Cases authorized by the Bankruptcy Court could materially impact the amounts and classifications of assets and liabilities reported in PG&E Corporation's and the Utility's Consolidated Financial Statements. (For more information regarding the Chapter 11 Cases, see Note 2 below.) |
BANKRUPTCY FILING
BANKRUPTCY FILING | 12 Months Ended |
Dec. 31, 2019 | |
Reorganizations [Abstract] | |
BANKRUPTCY FILING | BANKRUPTCY FILING Chapter 11 Proceedings On January 29, 2019, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. PG&E Corporation and the Utility continue to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Under the Bankruptcy Code, third-party actions to collect pre-petition indebtedness owed by PG&E Corporation or the Utility, as well as most litigation pending against PG&E Corporation and the Utility (including the third-party matters described in Note 14 below) as of the Petition Date, are subject to an automatic stay. Absent an order of the Bankruptcy Court providing otherwise, substantially all pre-petition liabilities will be resolved under a Chapter 11 plan of reorganization to be voted upon by impaired creditors and interest holders, and approved by the Bankruptcy Court. However, under the Bankruptcy Code, regulatory or criminal proceedings generally are not subject to an automatic stay, and these proceedings have been continuing during the pendency of the Chapter 11 Cases. Under the priority scheme established by the Bankruptcy Code, certain post-petition and secured or “priority” pre-petition liabilities need to be satisfied before general unsecured creditors and holders of PG&E Corporation's and the Utility’s equity are entitled to receive any distribution. No assurance can be given as to what values, if any, will be ascribed in the Chapter 11 Cases to the claims and interests of each of these constituencies. Additionally, no assurance can be given as to whether, when or in what form unsecured creditors and holders of PG&E Corporation’s or the Utility’s equity may receive a distribution on such claims or interests. Under the Bankruptcy Code, PG&E Corporation and the Utility may assume, assume and assign, or reject certain executory contracts and unexpired leases, including, without limitation, leases of real property and equipment, subject to the approval of the Bankruptcy Court and to certain other conditions. Any description of an executory contract or unexpired lease in this Annual Report on Form 10-K, including, where applicable, the express termination rights thereunder or a quantification of their obligations, must be read in conjunction with, and is qualified by, any overriding rejection rights PG&E Corporation and the Utility have under the Bankruptcy Code. Significant Bankruptcy Court Actions First Day Motions On January 31, 2019, the Bankruptcy Court approved, on an interim basis, certain motions (the “First Day Motions”) authorizing, but not directing, PG&E Corporation and the Utility to, among other things, (a) secure $5.5 billion of debtor-in-possession financing; (b) continue to use PG&E Corporation’s and the Utility’s cash management system; and (c) pay certain pre-petition claims relating to (i) certain safety, reliability, outage, and nuclear facility suppliers; (ii) shippers, warehousemen, and other lien claimants; (iii) taxes; (iv) employee wages, salaries, and other compensation and benefits; and (v) customer programs, including public purpose programs. The First Day Motions were subsequently approved by the Bankruptcy Court on a final basis at hearings on February 27, 2019, March 12, 2019, March 13, 2019, and March 27, 2019. Bar Date On July 1, 2019, the Bankruptcy Court entered an order approving a deadline of October 21, 2019, at 5:00 p.m. (Pacific Time) (the “Bar Date”) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date. The Bar Date is subject to certain exceptions, including for claims arising under section 503(b)(9) of the Bankruptcy Code, the bar date for which occurred on April 22, 2019. The Bankruptcy Court also approved PG&E Corporation’s and the Utility’s plan to provide notice of the Bar Date to parties in interest, including potential wildfire-related claimants and other potential creditors. On November 11, 2019, the Bankruptcy Court entered an order approving a stipulation between PG&E Corporation and the Utility and the TCC to extend the Bar Date for unfiled, non-governmental fire claimants to December 31, 2019, at 5:00 p.m. (Pacific Time). Other Significant Actions Related to the Chapter 11 Cases Other significant actions and developments related to the Chapter 11 Cases, including the Tubbs Lift Stay Decision, the Tubbs Trial and the Estimation Proceeding are described in Note 14 (including under the headings “Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims” and “Wildfire Claims Estimation Proceeding in the U.S. District Court for the Northern District of California”). On October 28, 2019, the Bankruptcy Court issued an order directing the principal parties in the Chapter 11 Cases to participate in mediation. Plan of Reorganization, RSAs, Equity Backstop Commitments and Debt Commitment Letters On September 9, 2019, PG&E Corporation and the Utility filed with the Bankruptcy Court their Joint Chapter 11 Plan of Reorganization for the resolution of the outstanding pre-petition claims against and interests in PG&E Corporation and the Utility, which was thereafter amended on September 23, 2019 and November 4, 2019. On January 31, 2020, PG&E Corporation and the Utility, certain funds and accounts managed or advised by Abrams Capital Management, LP (“Abrams”), and certain funds and accounts managed or advised by Knighthead Capital Management, LLC (“Knighthead” and, together with Abrams, the “Shareholder Proponents”) filed the Debtors’ and Shareholder Proponents’ Joint Chapter 11 Plan of Reorganization dated January 31, 2020 with the Bankruptcy Court (as may be amended, modified or supplemented from time to time, the “Proposed Plan”). On September 22, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with certain holders of insurance subrogation claims (collectively, the “Consenting Subrogation Creditors”) which agreement was amended and restated on November 1, 2019 and subsequently amended further during November and December 2019 (as amended, the “Subrogation RSA”). The Subrogation RSA provides for an aggregate amount of $11.0 billion (the “Allowed Subrogation Claim Amount”) to be paid by PG&E Corporation and the Utility pursuant to the Proposed Plan in order to settle all insurance subrogation claims (the “Subrogation Claims”) relating to the 2017 Northern California wildfires and the 2018 Camp fire (the “Subrogation Claims Settlement”), upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility also have agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA. On September 24, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the Subrogation RSA and approval of the Subrogation Claims Settlement. Hearings on PG&E Corporation’s and the Utility’s motion to approve the Subrogation RSA were held on October 23, 2019, December 4, 2019 and December 17, 2019. On December 19, 2019, the Bankruptcy Court entered an order granting PG&E Corporation’s and the Utility’s motion to approve the Subrogation RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 14 for further information on the Subrogation RSA. On December 6, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement, which was subsequently amended on December 16, 2019 (as amended, the “TCC RSA”), with the TCC, the attorneys and other advisors and agents for holders of Fire Victim Claims (as defined below) that are signatories to the TCC RSA (each a “Consenting Fire Claimant Professional”), and the Shareholder Proponents. The TCC RSA provides for, among other things, an aggregate of $13.5 billion in value to be provided by PG&E Corporation and the Utility pursuant to the Proposed Plan in order to settle and discharge all claims against PG&E Corporation and the Utility relating to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (other than the Subrogation Claims and the Public Entity Wildfire Claims) (the “Fire Victim Claims”), upon the terms and conditions set forth in the TCC RSA and the Proposed Plan. On December 9, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the TCC RSA. A hearing on PG&E Corporation’s and the Utility’s motion to approve the TCC RSA was held on December 17, 2019. On December 19, 2019, the Bankruptcy Court entered an order granting PG&E Corporation’s and the Utility’s motion to approve the TCC RSA. See “Restructuring Support Agreement with the TCC” in Note 14 for further information on the TCC RSA. Proposed Plan of Reorganization The Proposed Plan proposes the following: • compensation of wildfire victims and certain public entities from a trust funded for their benefit in an aggregate value of $13.5 billion in accordance with the terms of the TCC RSA (as further described under the heading “Restructuring Support Agreement with the TCC” in Note 14); • compensation of insurance subrogation claimants from a trust funded for their benefit in the amount of $11.0 billion in cash in accordance with the terms of the Subrogation Claims Settlement and Subrogation RSA (as further described under the heading “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 14); • payment of $1.0 billion in cash in full settlement of the claims of the settling public entities relating to the wildfires (as further described under the heading “Plan Support Agreements with Public Entities” in Note 14); • entitlement for the holders of claims related to the 2016 Ghost Ship fire to pursue their claims after the Effective Date, with any recovery being limited to amounts available under PG&E Corporation’s and the Utility’s insurance policies; • refinancing of Utility Short-Term Notes, Utility Long-Term Notes and Utility Funded Debt (except Pollution Control Bonds Series 2008F and 2010E, which will be repaid in cash) with the issuance of new notes, reinstatement of Utility Reinstated Notes and reimbursement of the holders of Utility Long-Term Senior Notes for debt placement fees and the members of the Ad Hoc Noteholder Committee for professional fees of up to $99 million (as further described under the heading “Restructuring Support Agreement with the Ad Hoc Noteholder Committee”); • payment in full of all pre-petition funded debt obligations of PG&E Corporation, all pre-petition trade claims and all pre-petition employee-related unsecured claims; • assumption of all power purchase agreements and community choice aggregation servicing agreements; • assumption of all pension obligations, other employee obligations, and collective bargaining agreements with labor; • future participation in the state wildfire fund established by AB 1054; and • satisfaction of the requirements of AB 1054. The Proposed Plan proposes the following key financing sources: • one or more equity offerings of up to $9.0 billion, in accordance with the Backstop Commitment Letters, although the Backstop Commitment Letters (as described below) permit PG&E Corporation to draw up to $12.0 billion; • the issuance of $6.75 billion of new equity to the Fire Victim Trust; • the issuance of $4.75 billion of new PG&E Corporation debt; • the reinstatement of $9.575 billion of pre-petition debt of the Utility; • the issuance of $23.775 billion of new Utility debt, consisting of (i) $6.2 billion of New Utility Long-Term Notes to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Proposed Plan, (ii) $1.75 billion of New Utility Short-Term Notes to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Proposed Plan, (iii) $3.9 billion of Utility Funded Debt Exchange Notes to be issued to holders of certain pre-petition indebtedness of the Utility pursuant to the Proposed Plan and (iv) $11.925 billion of new debt securities or bank debt of the Utility to be issued to third parties for cash on or prior to the Effective Date (of which $6.0 billion is expected to be repaid with the proceeds of a new securitization transaction after the Effective Date); • approximately $2.2 billion in proceeds of PG&E Corporation’s and the Utility’s liability insurance proceeds for wildfire events; and • cash available to PG&E Corporation or the Utility immediately prior to the Effective Date. On October 4, 2019, the CPUC issued an OII to consider the ratemaking and other implications of the Proposed Plan. The Proposed Plan has not been approved and is subject to regulatory review by the CPUC and FERC, as and to the extent required by law, including as potentially causing a change in control under Section 203 of the Federal Power Act. The Proposed Plan may be further amended, modified, or supplemented as necessary or desired by PG&E Corporation and the Utility or as required by the Bankruptcy Court or the CPUC. Disclosure Statement On February 7, 2020, pursuant to section 1125 of the Bankruptcy Code, PG&E Corporation and the Utility filed a proposed disclosure statement (the “Proposed Disclosure Statement”), with all schedules and exhibits thereto, for the Proposed Plan. PG&E Corporation and the Utility filed on February 18, 2020, a motion requesting that the Court (i) establish Plan solicitation and voting procedures, and (ii) approve the forms of Ballots, Solicitation Packages, and related notices to be sent to the various creditors and interest holders in connection with confirmation of the Plan (the “Solicitation Procedures Motion”). A hearing to consider approval of the Proposed Disclosure Statement and the relief requested in the Solicitation Procedures Motion is scheduled for March 10, 2020. Restructuring Support Agreement with the Ad Hoc Noteholder Committee On January 22, 2020, PG&E Corporation and the Utility entered into the Noteholder RSA with those holders of senior unsecured debt of the Utility that are identified as “Consenting Noteholders” below and the Shareholder Proponents. The Noteholder RSA provides for, among other things, (i) the refinancing of the Utility’s senior unsecured debt in satisfaction of all claims arising out of the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt, each as defined below, and (ii) the reinstatement of the Utility Reinstated Senior Notes, as defined below (together with the Utility Short-Term Senior Notes and Utility Long-Term Senior Notes, the “Utility Senior Note Claims”), in each case pursuant to the Proposed Plan and upon the terms and conditions set forth in the Noteholder RSA. Under the Noteholder RSA, PG&E Corporation and the Utility have also agreed to reimburse the holders of Utility Long-Term Senior Notes for debt placement fees and the members of the Ad Hoc Noteholder Committee for professional fees of up to $99 million upon the terms and conditions set forth in the Noteholder RSA. The following holders of Utility Senior Notes Claims are party to the Noteholder RSA as “Consenting Noteholders” as of the date hereof: Apollo Global Management LLC, Elliott Management Corporation, Oaktree Capital Management L.P., Farallon Capital Management LLC, Capital Group, Värde Partners Inc., Davidson Kempner Capital Management LP, Canyon Capital Advisors LLC, Third Point LLC, Pacific Investment Management Company LLC, Citadel Advisors LLC and Sculptor Capital Investments, LLC. Any holder of Utility Senior Note Claims or Utility Funded Debt can become a party to the Noteholder RSA by executing the joinder attached to the Noteholder RSA. The Noteholder RSA provides for the following treatment of Utility Senior Note Claims and Utility Funded Debt which treatment has been incorporated into the Proposed Plan: • Utility Short-Term Senior Notes: Currently outstanding Utility notes maturing through 2022 in an aggregate principal amount of $1.75 billion (the “Utility Short-Term Senior Notes”) will receive new Utility secured notes in the following aggregate principal amounts: $875 million of new Utility 3.45% secured notes due 2025 and $875 million of new Utility 3.75% secured notes due 2028 (together, the “New Utility Short-Term Notes”). The New Utility Short-Term Notes will otherwise have substantially similar terms and conditions as the Utility’s 6.05% Senior Notes due March 1, 2034. Additionally, holders of claims arising out of the Utility Short-Term Senior Notes will receive cash in an amount equal to the sum of (1) the amount of pre-petition interest outstanding on the Utility Short-Term Senior Notes calculated using the applicable non-default contract rate and (2) interest calculated using the federal judgment rate on the sum of (A) the applicable principal amount of the Utility Short-Term Senior Notes and (B) the amount in clause (1) for the period commencing on the day after the Petition Date and ending on the Effective Date. • Utility Long-Term Senior Notes: All long-term Utility notes bearing an interest rate greater than 5% of which there is an aggregate principal amount outstanding of $6.2 billion (the “Utility Long-Term Senior Notes”), will receive new Utility secured notes in the following aggregate principal amounts: $3.1 billion of new Utility 4.55% secured notes due 2030 and $3.1 billion of new Utility 4.95% secured notes due 2050 (together, the “New Utility Long-Term Notes”). The New Utility Long-Term Notes will otherwise have substantially similar terms and conditions as the Utility’s 3.95% Senior Notes due December 1, 2047. Additionally, holders of claims arising out of the Utility Long-Term Senior Notes will receive cash in an amount equal to the sum of (1) the amount of pre-petition interest outstanding on the Utility Long-Term Senior Notes calculated using the applicable non-default contract rate and (2) interest calculated using the federal judgment rate on the sum of (A) the applicable principal amount of the Utility Long-Term Senior Notes and (B) the amount in clause (1) for the period commencing on the Petition Date and ending on the Effective Date. • Utility Reinstated Senior Notes: The remaining outstanding $9.575 billion aggregate principal amount of Utility notes (the “Utility Reinstated Senior Notes”) will be reinstated on their contractual terms, including being secured equally and ratably with the New Utility Short-Term Notes and the New Utility Long-Term Notes. • Utility Funded Debt: Holders of the Utility’s pre-petition credit facilities and Pollution Control bonds (collectively, the “Utility Funded Debt”) will receive new Utility secured notes in the following aggregate principal amounts: $1.949 billion in new Utility 3.15% senior secured notes due 2025, and $1.949 billion in new Utility 4.50% senior secured notes due 2040 (the “New Utility Funded Debt Exchange Notes”). The New Utility Funded Debt Exchange Notes will otherwise have substantially similar terms and conditions as the Utility’s 6.05% Senior Notes due March 1, 2034. Additionally, holders of claims arising out of the Utility Funded Debt will receive cash in an amount equal to the sum of (1) the amount of pre-petition interest outstanding on the Utility Funded Debt calculated using the applicable non-default contract rate, (2) fees and charges and other obligations owed as of the Petition Date in respect of the Utility Funded Debt, (3) reasonable attorney’s fees and expenses of counsel, subject a maximum of $6 million and (4) interest calculated using the federal judgment rate on the sum of (A) the applicable principal amount of the Utility Funded Debt and (B) the amount in clauses (1) and (2) for the period commencing on the Petition Date and ending on the Effective Date. The Noteholder RSA further provides that PG&E Corporation and the Utility must use their best efforts to cause various parties to PG&E Corporation and the Utility’s equity backstop commitment letters to transfer up to $2.0 billion of equity backstop commitments to certain of the Consenting Noteholders. Under the Noteholder RSA, each Consenting Noteholder must, among other things, (i) withdraw any participation in and support for the Ad Hoc Noteholder Plan, including by taking certain actions to defer further action on the make-whole and post-petition interest issues, (ii) immediately direct counsel for the Ad Hoc Noteholder Committee to suspend its motion to reconsider the Bankruptcy Court order approving the Subrogation RSA and the TCC RSA and oppose any and all efforts and procedures to terminate, vacate or modify the TCC RSA or the Subrogation RSA, (iii) immediately withdraw all discovery issued in connection with PG&E Corporation and the Utility’s motion to approve their exit financing and file a statement in support of such motion, (iv) immediately withdraw all filings submitted in any proceeding before the CPUC involving PG&E Corporation and the Utility and cease participation in any proceeding before the CPUC involving PG&E Corporation and the Utility, and (v) vote to accept the Proposed Plan. Further, each Consenting Noteholder and each of its affiliates shall not, among other things, object to, delay, impede or take any other action to interfere with the approval of PG&E Corporation and the Utility’s disclosure statement or the solicitation of votes to accept, acceptance, confirmation, or implementation of the Proposed Plan. Each Consenting Noteholder further agreed, subject to certain exceptions, not to transfer any of its claims against PG&E Corporation and the Utility, unless the transferee either is a Consenting Noteholder, or before such transfer agrees in writing to become a Consenting Noteholder and to be bound by all the terms of the Noteholder RSA. The Noteholder RSA will automatically terminate if the Effective Date of the Proposed Plan does not occur on or prior to September 30, 2020 or December 31, 2020 if such later outside date is approved by the Bankruptcy Court. The Noteholder RSA may be terminated by a majority of the Consenting Noteholders under certain circumstances, including, among others, if (i) the treatment of the Utility Senior Note Claims or claims arising from Utility Funded Debt in the Proposed Plan are, or are modified to be, inconsistent with the Noteholder RSA, (ii) an order confirming the Proposed Plan is not entered on or before June 30, 2020, (iii) PG&E Corporation and the Utility fail to achieve an investment grade rating on the new senior secured notes from at least one credit rating agency on the Effective Date, (iv) PG&E Corporation and the Utility’s equity backstop commitment letters representing a majority of the equity backstop commitments are terminated or (v) PG&E Corporation and the Utility or the Shareholder Proponents breach certain provisions of the Noteholder RSA. The Noteholder RSA may be terminated by PG&E Corporation and the Utility or the Shareholder Proponents under certain circumstances, including, among others, if the Consenting Noteholders breach certain provisions of the Noteholder RSA. PG&E Corporation and the Utility and the Shareholder Proponents have separately agreed with certain of the Consenting Noteholders that, among other things, these Consenting Noteholders and certain of their representatives will not have any communications regarding the Proposed Plan, any changes to the Proposed Plan, or any alternative plan of reorganization or other strategic transaction related to PG&E Corporation and the Utility, with certain external stakeholders of PG&E Corporation and the Utility, including certain claimholders, government officials and certain of their representatives. This agreement will be filed under seal with the Bankruptcy Court. Equity Backstop Commitments As of December 31, 2019, PG&E Corporation has entered into Chapter 11 Plan Backstop Commitment Letters (collectively, the “Backstop Commitment Letters”) with investors (collectively, the “Backstop Parties”), pursuant to which the Backstop Parties severally agreed to fund up to $12.0 billion of proceeds to finance the Proposed Plan through the purchase of PG&E Corporation common stock, subject to the terms and conditions set forth in such Backstop Commitment Letters (the “Backstop Commitments”). The price at which any such new shares would be issued to the Backstop Parties would be equal to (a) 10 (subject to adjustment as provided in the Backstop Commitment Letters), times (b) PG&E Corporation’s consolidated Normalized Estimated Net Income (as defined in the Backstop Commitment Letters) for the estimated year 2021, divided by (c) the number of fully diluted shares of PG&E Corporation that will be outstanding on the effective date of the Proposed Plan (the “Effective Date”) (assuming that all equity is raised by funding the Backstop Commitments). The Backstop Commitment Letters provide that, under certain circumstances, PG&E Corporation and the Utility will be permitted to issue new shares of common stock of PG&E Corporation for up to $12.0 billion of proceeds to finance the transactions contemplated by the Proposed Plan through one or more equity offerings that, under certain circumstances, must include a rights offering (the “Rights Offering”). The structure, terms and conditions of any such equity offering (including a Rights Offering) are expected to be determined by PG&E Corporation and the Utility at a later time in the Chapter 11 process, subject to the terms and conditions of the Backstop Commitment Letters. This may include terms and conditions that are designed to preserve the ability of PG&E Corporation or the Utility to utilize their net operating loss carryforwards. There can be no assurance that any such equity offering would be successful. In the event that such equity offerings (together with additional permitted capital sources) do not raise at least $12.0 billion of proceeds in the aggregate or if PG&E Corporation and the Utility do not otherwise consummate such offerings, then PG&E Corporation and the Utility may draw on the Backstop Commitments for equity funding to finance the transactions contemplated by the Proposed Plan, subject to the satisfaction or waiver by the Backstop Parties of the conditions set forth therein. Although the Backstop Commitment Letters permit PG&E Corporation to draw up to $12.0 billion in equity, the Proposed Plan contemplates an equity raise of only $9.0 billion, which equity will be raised in accordance with the terms of the Backstop Commitment Letters. Under the Backstop Commitment Letters, PG&E Corporation agrees that if the Backstop Commitments are drawn, and PG&E Corporation does not expect to conduct a third-party transaction based upon or related to the utilization or monetization of any net operating losses or tax deductions resulting from the payment of pre-petition wildfire-related claims (a “Tax Benefits Monetization Transaction”) on the Effective Date, no later than five business days prior to the Effective Date, PG&E Corporation and the Utility must form a trust which would provide for periodic distributions of cash to the Backstop Parties in amounts equal to (i) all tax benefits arising from the payment of wildfire-related claims in excess of (ii) the first $1.35 billion of tax benefits, starting with fiscal year 2020. PG&E Corporation intends to explore a Tax Benefits Monetization Transaction. The Backstop Parties’ funding obligations under the Backstop Commitment Letters are subject to numerous conditions, including, among others, that (a) the Backstop Commitment Letters have been approved by the Bankruptcy Court, (b) the conditions precedent to the Effective Date set forth in the Proposed Plan have been satisfied or waived in accordance with the Proposed Plan, (c) the Bankruptcy Court has entered an order confirming the Proposed Plan and approving the transactions contemplated thereunder, which shall confirm the Proposed Plan with such amendments, modifications, changes and consents as are approved by holders of a majority of the aggregate Backstop Commitments (the “Confirmation Order”), (d) PG&E Corporation’s and the Utility’s weighted average earning rate base for 2021 is no less than 95% of $48 billion, and (e) there has been no event, occurrence or other circumstance that would have or would reasonably be expected to have a material adverse effect on the business of PG&E Corporation and the Utility or their ability to consummate the transactions contemplated by the Backstop Commitment Letters and the Proposed Plan. The Backstop Parties have consented to move the deadline for Bankruptcy Court approval of the Backstop Commitment Letters to February 28, 2020. In addition, the Backstop Parties have certain termination rights under the Backstop Commitment Letters, including, among others, if (a) the Proposed Plan (including as may be amended, modified or otherwise changed) does not include Abrams and Knighthead as plan proponents and is not in a form acceptable to each of Abrams and Knighthead, (b) the Bankruptcy Court has not entered an order approving the Backstop Commitment Letters by February 28, 2020, (c) PG&E Corporation’s and the Utility’s aggregate liability with respect to pre-petition wildfire-related claims exceeds $25.5 billion, (d) the Proposed Plan is amended without the consent of the holders of a majority of the aggregate Backstop Commitments, (e) the Confirmation Order has not been entered by the Bankruptcy Court by June 30, 2020, (f) the Effective Date has not occurred within 60 days of entry of the Confirmation Order, (g) a material adverse effect (as described above) occurs, (h) wildfires occur in the Utility’s service area in 2019 that damage or destroy in excess of 500 dwellings or commercial structures in the aggregate, (i) the CPUC fails to issue all necessary approvals, authorizations and final orders to implement the Proposed Plan prior to June 30, 2020, including approvals related to the Utility’s capital structure and authorized rate of return and the resolution of the CPUC’s claims against the Utility for fines or penalties, all of which must be satisfactory to the holders of a majority of the aggregate Backstop Commitments, (j) the amount of asserted administrative expense claims or the amount of administrative expense claims PG&E Corporation and the Utility have reserved for and/or paid in the aggregate exceeds $250 million, in each case excluding administrative expense claims that are ordinary course, professional fee claims, claims that are disallowed in the Chapter 11 Cases and the portion of an administrative expense claim that is covered by insurance, (k) one or more wildfires occur in the Utility’s service area on or after January 1, 2020 that damage or destroy at least 500 dwellings or commercial structures in the aggregate at a time when the portion of the Utility’s system at the location of such wildfire was not successfully de-energized, (l) as of the Effective Date, the Utility has not elected and received Bankruptcy Court approval, or satisfied the other required conditions, to participate in the statewide wildfire fund established by AB 1054, (m) at any time the Bankruptcy Court determines that PG&E Corporation and the Utility are insolvent, (n) PG&E Corporation and the Utility enter into any Tax Benefit Monetization Transaction and the net cash proceeds thereof are less than $3.0 billion, excluding the $1.35 billion of tax benefits to be utilized in the Proposed Plan, and (o) the Proposed Plan or any supplements to or other documents in connection with the Proposed Plan has been amended, modified or changed, without the consent of the holders of at least 66 2/3% of the aggregate Backstop Commitments, to include a process for transferring the license and operating assets of the Utility to the State of California or a third party (a “Transfer”) or PG&E Corporation and the Utility effect a Transfer other than pursuant to the Proposed Plan. There can be no assurance that the conditions precedent set forth in the Backstop Commitment Letters will be satisfied or waived, nor that events or circumstances will not occur that give rise to termination rights of the Backstop Parties. The commitment premium for the Backstop Commitments is 6.364% of the amount of the Backstop Commitments. Such commitment premium will be earned in full upon Bankruptcy Court approval of the Backstop Commitment Letters, subjec |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Loss Contingencies A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The 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 capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities. The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the 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 and 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 from Contracts with Customers 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. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. Regulatory Balancing Account Revenue 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. The Utility's ability to recover revenue requirements authorized by the CPUC in these rate cases is independent or “decoupled” from the volume of the Utility's sales of electricity and natural 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, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. 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 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. As a result, these differences have no impact on net income. The following table presents the Utility’s revenues disaggregated by type of customer: Year Ended (in millions) 2019 2018 Electric Revenue from contracts with customers Residential $ 4,847 $ 5,051 Commercial 4,756 4,908 Industrial 1,493 1,532 Agricultural 1,106 1,234 Public street and highway lighting 67 72 Other (1) 168 (720) Total revenue from contracts with customers - electric 12,437 12,077 Regulatory balancing accounts (2) 303 636 Total electric operating revenue $ 12,740 $ 12,713 Natural gas Revenue from contracts with customers Residential $ 2,325 $ 2,042 Commercial 605 537 Transportation service only 1,249 1,151 Other (1) 123 75 Total revenue from contracts with customers - gas 4,302 3,805 Regulatory balancing accounts (2) 87 242 Total natural gas operating revenue 4,389 4,047 Total operating revenues $ 17,129 $ 16,760 (1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. Cash and Cash Equivalents Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value. 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 expensed 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 historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows: Estimated Useful Balance at December 31, (in millions, except estimated useful lives) Lives (years) 2019 2018 Electricity generating facilities (1) 10 to 75 $ 13,189 $ 13,047 Electricity distribution facilities 10 to 65 35,237 32,926 Electricity transmission facilities 15 to 75 14,281 13,177 Natural gas distribution facilities 20 to 60 14,236 13,296 Natural gas transmission and storage facilities 5 to 66 8,452 8,260 Construction work in progress 2,675 2,564 Other 18 — Total property, plant, and equipment 88,088 83,270 Accumulated depreciation (26,453) (24,713) Net property, plant, and equipment $ 61,635 $ 58,557 (1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.) The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.80% in 2019, 3.82% in 2018, and 3.83% in 2017. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred. AFUDC AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions 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 equity, respectively, of $55 million and $79 million during 2019, $53 million and $129 million during 2018, and $38 million and $89 million during 2017. Asset Retirement Obligations The following table summarizes the changes in ARO liability during 2019 and 2018, including nuclear decommissioning obligations: (in millions) 2019 2018 ARO liability at beginning of year $ 5,994 $ 4,899 Revision in estimated cash flows (376) 993 Accretion 274 211 Liabilities settled (38) (109) ARO liability at end of year $ 5,854 $ 5,994 The Utility has not recorded a liability related to certain AROs 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, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of 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 Decommissioning Cost Triennial Proceeding conducted by the CPUC. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. 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 total nuclear decommissioning obligation accrued was $4.9 billion and $4.7 billion at December 31, 2019 and 2018, respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion at December 31, 2019 and 2018. 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 15 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 Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC. The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification. Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is 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 generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2019, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2019, 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 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, and “Contingencies and Commitments” in Notes 14 and 15 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, 2019 consisted of the following: (in millions, net of income tax) Pension Other Total Beginning balance $ (21) $ 17 $ (4) Other comprehensive income before reclassifications: Unrecognized net actuarial loss (net of taxes of $24 and $88, respectively) 61 227 288 Regulatory account transfer (net of taxes of $24 and $88, respectively) (62) (227) (289) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1) (4) 10 6 Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1) 2 (2) — Regulatory account transfer (net of taxes of $1 and $3, respectively) (1) 2 (8) (6) Net current period other comprehensive loss (1) — (1) Ending balance $ (22) $ 17 $ (5) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 12 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, 2018 consisted of the following: (in millions, net of income tax) Pension Other Total Beginning balance $ (25) $ 17 $ (8) Other comprehensive income before reclassifications: Unrecognized net actuarial loss (net of taxes of $41 and $9, respectively) (104) (23) (127) Regulatory account transfer (net of taxes of $41 and $9, respectively) 107 23 130 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1) (4) 10 6 Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) (1) 3 (4) (1) Regulatory account transfer (net of taxes of $1 and $3, respectively) (1) 2 (6) (4) Net current period other comprehensive loss 4 — 4 Ending balance $ (21) $ 17 $ (4) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 12 below for additional details.) Recently Adopted Accounting Standards Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which amended the guidance related to the definition of a lease, the recognition of lease assets and liabilities, and the disclosure of key information about leasing arrangements. Under the new standard, a lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility adopted the ASU for leases on January 1, 2019. PG&E Corporation and the Utility elected certain practical expedients and will carry forward historical conclusions related to (1) contracts that contain leases, (2) existing lease and easement classification, and (3) initial direct costs. After adoption of the new standard, PG&E Corporation and Utility elected not to separate lease and non-lease components. Additionally, PG&E Corporation and the Utility will not restate comparative reporting periods. The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates, unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking. Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the year ended December 31, 2019. On January 1, 2019, PG&E Corporation and the Utility recorded ROU assets and lease liabilities of $2.8 billion, representing the net present value of only the fixed lease payments. This amount is presented within the supplemental disclosures of noncash activities. For the year ended December 31, 2019, the Utility made total cash payments, including fixed and variable, of $2.4 billion for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows. The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements. At December 31, 2019, the Utility’s leases had a weighted average remaining lease term of 5.9 years and a weighted average discount rate of 6.2%. The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations: (in millions) Year Ended December 31, 2019 Operating lease fixed cost $ 686 Operating lease variable cost 1,778 Total operating lease costs $ 2,464 The following table shows the Utility’s future expected operating lease payments: (in millions) December 31, 2019 2020 $ 679 2021 623 2022 548 2023 255 2024 96 Thereafter 596 Total lease payments 2,797 Less imputed interest (518) Total $ 2,279 The following table shows the Utility’s future expected obligations for power purchase and other lease commitments: (in millions) December 31, 2018 2019 $ 684 2020 677 2021 621 2022 546 2023 252 Thereafter 581 Total lease commitments $ 3,361 Fair Value Measurement In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurements , which amends the existing guidance relating to the disclosure requirements for fair value measurements. PG&E Corporation and the Utility early adopted the ASU as of December 31, 2019. The adoption of this ASU did not have a material impact on the Consolidated Financial Statements and related disclosures. Accounting Standards Issued But Not Yet Adopted Intangibles-Goodwill and Other In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract . This ASU became effective for PG&E Corporation and the Utility on January 1, 2020 and did not have a material impact on the Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. This ASU became effective for PG&E Corporation and the Utility on January 1, 2020 and did not have a material impact on the Consolidated Financial Statements and related disclosures. |
REGULATORY ASSETS, LIABILITIES,
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS | 12 Months Ended |
Dec. 31, 2019 | |
Regulated Operations [Abstract] | |
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS | REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets Long-term regulatory assets are comprised of the following: Balance at December 31, Recovery (in millions) 2019 2018 Pension benefits (1) $ 1,823 $ 1,947 Indefinitely Environmental compliance costs 1,062 1,013 32 years Utility retained generation (2) 228 274 8 years Price risk management 124 90 10 years Unamortized loss, net of gain, on reacquired debt 63 76 25 years Catastrophic event memorandum account (3) 656 790 1 - 4 years Wildfire expense memorandum account (4) 423 94 1 - 4 years Fire hazard prevention memorandum account (5) 259 263 1 - 4 years Fire risk mitigation memorandum account (6) 95 — 1 - 4 years Wildfire mitigation plan memorandum account (7) 558 — 1 - 4 years Deferred income taxes (8) 252 — 47 years Other (9) 523 417 Various Total long-term regulatory assets $ 6,066 $ 4,964 (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) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. (3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. Recovery of CEMA costs are subject to CPUC review and approval. (4) Includes specific incremental wildfire-related liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are subject to CPUC review and approval. (5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs are subject to CPUC review and approval. (6) Includes costs associated with the 2019 Wildfire Mitigation Plan for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs are subject to CPUC review and approval. (7) Includes costs associated with the 2019 Wildfire Mitigation Plan for the period June 5, 2019 through December 31, 2019. Recovery of WMPMA costs are subject to CPUC review and approval. (8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (See Note 9 below.) (9) December 31, 2019 balance includes $178 million of unamortized debt issuance costs and debt discount that was written off to present the debt subject to compromise at the outstanding face value. In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return 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) 2019 2018 Cost of removal obligations (1) $ 6,456 $ 5,981 Deferred income taxes (2) — 283 Recoveries in excess of AROs (3) 393 356 Public purpose programs (4) 817 674 Retirement plans (5) 750 421 Other 854 824 Total long-term regulatory liabilities $ 9,270 $ 8,539 (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 amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (See Note 9 below.) (3) 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 liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 11 below.) (4) 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. (5) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long-Term Disability Plans. 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. Regulatory 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 Balance 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 regulatory balancing accounts receivable and payable are comprised of the following: Receivable (in millions) 2019 2018 Electric distribution $ — $ 160 Electric transmission 9 128 Utility generation — 79 Gas distribution and transmission 363 462 Energy procurement 901 168 Public purpose programs 209 111 Other 632 327 Total regulatory balancing accounts receivable $ 2,114 $ 1,435 Payable (in millions) 2019 2018 Electric distribution $ 31 $ — Electric transmission 119 134 Gas distribution and transmission 45 9 Energy procurement 649 59 Public purpose programs 559 587 Other 394 287 Total regulatory balancing accounts payable $ 1,797 $ 1,076 The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. 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 electricity, 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, 2019 | |
Debt Disclosure [Abstract] | |
DEBT | DEBT Debtor-In-Possession Facilities In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto (together with such other financial institutions from time to time party thereto, the “DIP Lenders”). The DIP Credit Agreement provides for $5.5 billion in senior secured superpriority debtor in possession credit facilities in the form of (i) a revolving credit facility in an aggregate amount of $3.5 billion (the “DIP Revolving Facility”), including a $1.5 billion letter of credit subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term loan facility in an aggregate principal amount of $500 million (the “DIP Delayed Draw Term Loan Facility,” together with the DIP Revolving Facility and the DIP Initial Term Loan Facility, the “DIP Facilities”), subject to the terms and conditions set forth therein. The DIP Credit Agreement also provides for up to $4.0 billion of incremental facilities in the form of (i) one or more additional tranches of term loans or (ii) one or more increases in the aggregate amount of revolving commitments under the DIP Revolving Facility (together, the “Incremental Facilities”), subject to the terms and conditions set forth therein. The Incremental Facilities are uncommitted and would require approval from the Bankruptcy Court. On the Petition Date, PG&E Corporation and the Utility filed a motion seeking, among other things, interim and final approval of the DIP Facilities, which motion was granted on an interim basis by the Bankruptcy Court following a hearing on January 31, 2019. As a result of the Bankruptcy Court’s interim approval of the DIP Facilities and the satisfaction of the other conditions thereof, the DIP Credit Agreement became effective on February 1, 2019 and a portion of the DIP Revolving Facility in the amount of $1.5 billion (including $750 million of the letter of credit subfacility) was made available to the Utility. On March 27, 2019, the Bankruptcy Court approved the DIP Facilities on a final basis, authorizing the Utility to borrow up to the remainder of the DIP Revolving Facility (including the remainder of the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, in each case subject to the terms and conditions of the DIP Credit Agreement. Borrowings under the DIP Facilities are senior secured obligations of the Utility, secured by substantially all of the Utility’s assets and entitled to superpriority administrative expense claim status in the Utility’s Chapter 11 Case. The Utility’s obligations under the DIP Facilities are guaranteed by PG&E Corporation, and such guarantee is a senior secured obligation of PG&E Corporation, secured by substantially all of PG&E Corporation’s assets and entitled to superpriority administrative expense claim status in PG&E Corporation’s Chapter 11 Case. The proceeds of the borrowings under the DIP Facilities can be used for working capital and general corporate purposes and to pay fees, costs and expenses incurred in connection with the transactions contemplated by the DIP Credit Agreement and professional and other fees and costs of administration incurred in connection with the Chapter 11 Cases. On February 1, 2019, the Utility borrowed $350 million under the DIP Revolving Facility. On April 3, 2019, following the Bankruptcy Court’s final approval of the DIP Facilities, the Utility borrowed $1.5 billion under the DIP Initial Term Loan Facility and repaid the $350 million outstanding under the DIP Revolving Facility. On January 29, 2020, the Utility borrowed $500 million under the DIP Delayed Draw Term Loan Facility. The DIP Facilities mature on December 31, 2020 (the “Maturity Date”), subject to the Utility’s option to extend the maturity to December 31, 2021 if certain terms and conditions are satisfied, including the payment of an extension fee equal to 0.25% of the then-outstanding loans and available commitments. As of December 31, 2019, the Utility does not intend to extend the Maturity Date. Both the DIP Initial Term Loan Facility and the Delayed Draw Term Loan bear interest at a spread of 225 basis points over LIBOR. Borrowings under the DIP Revolving Facilities will bear interest based, at the Utility’s election, on (1) LIBOR plus an applicable margin of 2.25% or (2) ABR plus an applicable margin of 1.25%. ABR will equal the highest of the following: (i) the administrative agent’s announced base rate, (ii) 0.50% above the (x) federal funds effective rate or (y) the overnight federal funds rate, whichever is higher, (iii) one-month LIBOR plus 1.00%, and (iv) zero. The Utility is also required to pay unused fees of 0.375% per annum in respect of the average daily unutilized commitments under the DIP Revolving Facility. The Utility must also pay (x) a fee equal to the applicable margin with respect to LIBOR loans under the DIP Revolving Facility on the aggregate drawable amount of all outstanding letters of credit under the DIP Revolving Facility and (y) a fronting fee to the relevant issuing DIP Lender equal to 0.125% per annum of the aggregate drawable amount of outstanding letters of credit issued by such issuing DIP Lender. The DIP Credit Agreement includes usual and customary covenants for debtor in possession loan agreements of this type, including covenants limiting PG&E Corporation’s and the Utility’s ability to, among other things, incur additional indebtedness, create liens on assets, make investments, loans or advances, engage in mergers, consolidations, sales of assets and acquisitions, pay dividends and distributions and make payments in respect of junior or pre-petition indebtedness, in each case subject to customary exceptions for debtor in possession loan agreements of this type. The DIP Credit Agreement also includes customary and usual representations and warranties and affirmative covenants, including an obligation to deliver 13-week cash flow forecasts and reports showing variances from such forecasts, in each case on a rolling 4-week basis. PG&E Corporation’s and the Utility’s obligations under the DIP Credit Agreement may be accelerated following certain events of default, including payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to post-petition or unstayed indebtedness of PG&E Corporation and the Utility and their subsidiaries in excess of $200 million, certain events under ERISA, unstayed judgments in respect of post-petition obligations involving an aggregate liability in excess of $200 million, change of control, specified governmental actions having a material adverse effect or condemnation or damage to a material portion of the collateral. Certain bankruptcy-related events are also events of default, including, but not limited to, the dismissal by the Bankruptcy Court of any of the Chapter 11 Cases, the conversion of any of the Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code, the appointment of a trustee pursuant to Chapter 11, any order authorizing the DIP Facilities being stayed, vacated, reversed or amended in a manner adverse to the DIP Lenders, and certain other events related to the impairment of the DIP Lenders’ rights or liens granted under the DIP Credit Agreement. The commencement of the Chapter 11 Cases constituted an event of default or termination event with respect to, and caused an automatic and immediate acceleration of the debt outstanding under or in respect of, certain instruments and agreements relating to direct financial obligations of PG&E Corporation and the Utility (the “Accelerated Direct Financial Obligations”). However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the Utility's outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation's term loan facility, as well as short-term borrowings under PG&E Corporation's and the Utility's revolving credit facilities and the Utility's term loan facility. Debtor-in-Possession Financing The following table summarizes the Utility’s outstanding borrowings and availability under the DIP Facilities at December 31, 2019: (in millions) Termination Aggregate Limit Term Loan Borrowings Revolver Borrowings Letters of Credit Outstanding Aggregate DIP Facilities December 2020 (1) $ 5,500 $ 1,500 $ — $ 663 $ 3,337 (1) May be extended to December 2021, subject to satisfaction of certain terms and conditions, including payment of a 25 basis point extension fee. On January 29, 2020, the Utility borrowed $500 million under the DIP Delayed Draw Term Loan Facility. Debt The following table summarizes PG&E Corporation’s and the Utility’s outstanding debt subject to compromise: December 31, (in millions) Contractual Interest Rates 2019 2018 Treatment under Proposed Plan (1) Debt Subject to Compromise (2) PG&E Corporation Borrowings under Pre-Petition Credit Facility PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 variable rate (3) $ 300 $ 300 Repaid in cash Other borrowings Term Loan - Stated Maturity: 2020 variable rate (4) 350 350 Repaid in cash Total PG&E Corporation Debt Subject to Compromise 650 650 Utility Senior Notes - Stated Maturity: 2020 3.50% 800 800 Exchanged for New Utility Short-Term Notes 2021 3.25% to 4.25% 550 550 Exchanged for New Utility Short-Term Notes 2022 2.45% 400 400 Exchanged for New Utility Short-Term Notes 2023 3.25% to 4.25% 1,175 1,175 Reinstated 2024 through 2028 2.95% to 4.65% 3,850 3,850 Reinstated 2034 through 2040 5.40% to 6.35% 5,700 5,700 Exchanged for New Utility Long-Term Notes 2041 through 2042 3.75% to 4.50% 1,000 1,000 Reinstated 2043 4.60% 375 375 Reinstated 2043 5.13% 500 500 Exchanged for New Utility Long-Term Notes 2044 through 2047 3.95% to 4.75% 3,175 3,175 Reinstated Unamortized discount, net of premium and debt issuance costs — (178) Total Senior notes, net of premium and debt issuance costs 17,525 17,347 Pollution Control Bonds - Stated Maturity: Series 2008 F and 2010 E, due 2026 (5) 1.75% 100 100 Repaid in cash Series 2009 A-B, due 2026 (6) variable rate (7) 149 149 Exchanged for New Utility Funded Debt Exchange Notes Series 1996 C, E, F, 1997 B due 2026 (6) variable rate (8) 614 614 Exchanged for New Utility Funded Debt Exchange Notes Total pollution control bonds 863 863 Borrowings under Pre-Petition Credit Facilities Utility Revolving Credit Facilities - Stated Maturity: 2022 (9) variable rate (10) 2,888 2,965 Exchanged for New Utility Funded Debt Exchange Notes Other borrowings: Term Loan - Stated Maturity: 2019 variable rate (11) 250 250 Exchanged for New Utility Funded Debt Exchange Notes Total Borrowings under Pre-Petition Credit Facility Subject to Compromise 3,138 3,215 Total Utility Debt Subject to Compromise 21,526 21,425 Total PG&E Corporation Consolidated Debt Subject to Compromise $ 22,176 $ 22,075 (1) The treatments of debt under the Proposed Plan, described in this column relate only to the treatment of principal amounts and not pre-petition or post-petition interest. The New Utility Short-Term Notes, New Utility Long-Term Senior Notes and New Utility Funded Debt Exchange Notes are described in more detail under “Restructuring Support Agreement with the Ad Hoc Noteholder Committee” in Note 2. (2) Debt subject to compromise must be reported at the amounts expected to be allowed by the Bankruptcy Court and the carrying values will be adjusted as claims are approved. Total Debt Subject to Compromise does not include accrued contractual interest of $1 million and $286 million for PG&E Corporation and the Utility, respectively, to the Petition Date. Total Debt Subject to Compromise also does not include post-petition interest of $15 million and $638 million for PG&E Corporation and the Utility, respectively, in accordance with the terms of the Noteholder RSA. As of December 31, 2019, PG&E Corporation and the Utility wrote off $178 million of unamortized debt issuance costs and debt discount to present the debt subject to compromise at the outstanding face value. The write-offs are included within long-term regulatory assets in the Consolidated Balance Sheets. See Notes 2 and 4 for further details. (3) At December 31, 2019, the contractual LIBOR-based interest rate on loans was 3.24%. (4) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.96%. (5) Pollution Control Bonds series 2008F and 2010E were reissued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 31, 2022. (6) Each series of these bonds is supported by a separate direct-pay letter of credit. Following the Utility’s Chapter 11 filing, investors in these bonds drew on the letter of credit facilities. The letter of credit facility supporting the Series 2009 A-B bonds matured on June 5, 2019. In December 2015, the maturity dates of the letter of credit facilities supporting the Series 1996 C, E, F, 1997 B bonds were extended to December 1, 2020. Although the stated maturity date of these bonds 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. (7) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 7.95%. (8) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 7.95% to 8.08%. (9) At December 31, 2019, excludes $22 million of undrawn letters of credit. (10) At December 31, 2019, the contractual LIBOR-based interest rate on the loans was 3.04%. (11) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.36%. Pollution Control Bonds Subject to Compromise 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. Revolving Credit Facilities Subject to Compromise PG&E Corporation's and the Utility's revolving credit facilities have been subject to an automatic and immediate acceleration as a result of the Chapter 11 Cases. Prior to the Chapter 11 Cases, proceeds from the revolving credit facilities were used for working capital, the repayment of commercial paper, and other corporate purposes. Contractual Repayment Schedule PG&E Corporation and the Utility have entered into the Noteholder RSA with Consenting Noteholders which provides for, among other things, (i) the refinancing of the Utility’s senior unsecured debt in satisfaction of all claims arising out of the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt, and (ii) the reinstatement of the Utility Reinstated Senior Notes, in each case pursuant to the Proposed Plan and upon the terms and conditions set forth in the Noteholder RSA. See “Restructuring Support Agreement with the Ad Hoc Noteholder Committee” in Note 2 for further information on the Noteholder RSA. PG&E Corporation’s and the Utility’s existing long-term debt is in default, and the Accelerated Direct Financial Obligations became immediately due and payable upon the commencement of the Chapter 11 Cases. PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2019 are reflected in the table below: (in millions, except interest rates) 2020 2021 2022 2023 2024 Thereafter Total PG&E Corporation Variable interest rate as of December 31, 2019 2.96 % — % 3.24 % — % — % — % 2.96 % Variable rate obligations $ 350 $ — $ 300 $ — $ — $ — $ 650 Utility Average fixed interest rate 3.50 % 3.80 % 2.31 % 3.83 % 3.60 % 4.80 % 4.52 % Fixed rate obligations $ 800 $ 550 $ 500 $ 1,175 $ 800 $ 13,800 $ 17,625 Variable interest rate as of December 31, 2019 various (1) — % 3.04 % — % — % — % 8.00 % Variable rate obligations $ 1,013 $ — $ 2,888 $ — $ — $ — $ 3,901 Total consolidated debt $ 2,163 $ 550 $ 3,688 $ 1,175 $ 800 $ 13,800 $ 22,176 (1) At December 31, 2019, the average interest rates for the pollution control bonds and the term loan were 8.00% and 2.36%, respectively. Commercial Paper Programs As of December 31, 2019, PG&E Corporation and the Utility terminated their respective programs commercial paper programs and had no commercial paper borrowings outstanding. |
COMMON STOCK AND SHARE-BASED CO
COMMON STOCK AND SHARE-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2019 | |
Common Stock And Share-Based Compensation [Abstract] | |
COMMON STOCK AND SHARE-BASED COMPENSATION | COMMON STOCK AND SHARE-BASED COMPENSATION PG&E Corporation had 529,236,741 shares of common stock outstanding at December 31, 2019. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2019. There were no issuances under the PG&E Corporation February 2017 equity distribution agreement for the year ended December 31, 2019. The remaining gross sales available under this agreement were $246 million. PG&E Corporation issued 8.9 million shares of common stock under the PG&E Corporation 401(k) plan and share-based compensation plans, for cash proceeds of $85 million, during the year ended December 31, 2019. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation. Dividends On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of and potential liabilities associated with wildfires. See Wildfire-related contingencies in Note 14 below. 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. Under their respective pre-petition credit agreements, PG&E Corporation and the Utility were each required to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%. As of the Petition Date, these obligations were automatically stayed and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The DIP Facilities have no such restriction. Additionally, the Utility’s net assets, and therefore its ability to pay dividends, are restricted by the CPUC-authorized capital structure, which requires the Utility to maintain, on average, at least 52% equity. Due to the net charges recorded in connection with the 2018 Camp fire and the 2017 Northern California wildfires as of December 31, 2018, the Utility submitted to the CPUC an application for a waiver of the capital structure condition on February 28, 2019. The waiver is subject to CPUC approval. The Utility is not considered to be in violation of these conditions during the period the waiver application is pending resolution. Beginning in 2020, the Utility expects to resume payment of preferred dividends on the Utility’s preferred stock, subject to the Utility’s Board of Directors’ approval. PG&E Corporation does not expect to pay any cash for common stock dividends for at least the next two years, subject to PG&E Corporation’s Board of Directors’ approval. Long-Term Incentive Plan The PG&E Corporation LTIP permits various forms of share-based incentive awards, including stock options, restricted stock 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 shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the 2014 LTIP, of which 12,338,419 shares were available for future awards at December 31, 2019. The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2019: (in millions) 2019 2018 2017 Stock Options $ 7 $ 10 $ — Restricted stock units 21 43 40 Performance shares 22 36 45 Total compensation expense (pre-tax) $ 50 $ 89 $ 85 Total compensation expense (after-tax) $ 35 $ 63 $ 50 Share-based compensation costs are generally not capitalized. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Stock Options The exercise price of stock options granted under the 2014 LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant. Stock options generally have a 10-year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2019, $10.5 million of total unrecognized compensation costs related to nonvested stock options were expected to be recognized over a weighted average period of 1.73 years for PG&E Corporation. The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. The weighted average grant date fair value of options granted using the Black-Scholes valuation method in 2019 and 2018 was $3.87 and $10.24 per share, respectively. The significant assumptions used for shares granted in 2019 were: 2019 2018 Expected stock price volatility 57.00 % 23.00 % Expected annual dividend payment — % 3.10 % Risk-free interest rate 1.51% to 1.52% 2.58 % Expected life (years) 4.5 6 Expected volatilities are based on historical volatility of PG&E Corporation’s common stock. The expected dividend payment is the dividend yield at the date of grant. The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant. The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior. There was no tax benefit recognized from stock options for the year ended December 31, 2019. The following table summarizes stock option activity for PG&E Corporation and the Utility for 2019: Number of Weighted Average Grant- Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1 1,522,137 $ 10.24 $ — Granted 2,866,667 3.87 — Exercised — — — Forfeited or expired (107,401) 10.24 — Outstanding at December 31 4,281,403 5.98 5.40 years — Vested or expected to vest at December 31 4,225,180 5.92 5.36 years — Exercisable at December 31 1,433,234 $ 5.99 5.41 years $ — Restricted Stock Units Restricted stock units granted after 2014 generally vest equally over three years. Vested restricted stock units are settled 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 ratably over the vesting period based on grant-date fair value. The weighted average grant-date fair value for restricted stock units granted during 2019, 2018, and 2017 was $18.57, $40.92, and $66.95, respectively. The total fair value of restricted stock units that vested during 2019, 2018, and 2017 was $42 million, $41 million, and $57 million, respectively. The tax benefit from restricted stock units that vested during each period was not material. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2019, $19 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.14 years. The following table summarizes restricted stock unit activity for 2019: Number of Weighted Average Grant- Nonvested at January 1 1,979,812 $ 47.66 Granted 74,479 18.57 Vested (822,249) 51.01 Forfeited (191,207) 41.49 Nonvested at December 31 1,040,835 $ 44.06 Performance Shares Performance shares generally will vest three three Compensation expense attributable to performance shares is generally recognized ratably over the applicable three The following table summarizes activity for performance shares in 2019: Number of Weighted Average Grant- Nonvested at January 1 1,438,091 $ 56.32 Granted 130,251 15.39 Vested (255,324) 40.74 Forfeited (1) (624,595) 75.54 Nonvested at December 31 688,423 $ 36.92 (1) Includes performance shares that expired with zero value as performance targets were not met. |
PREFERRED STOCK
PREFERRED STOCK | 12 Months Ended |
Dec. 31, 2019 | |
Preferred Stock [Abstract] | |
PREFERRED STOCK | PREFERRED STOCK PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value preferred stock, which may be issued as redeemable or nonredeemable preferred stock. PG&E Corporation does not have any preferred stock outstanding. The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock. At December 31, 2019 and December 31, 2018, 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 outstanding preferred stock has a $25 par value. At December 31, 2019, 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, 2019, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share. |
EARNINGS PER SHARE
EARNINGS PER SHARE | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE | EARNINGS PER SHARE PG&E Corporation’s basic EPS is calculated by dividing the income (loss) 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 (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2019, 2018, and 2017. Year Ended December 31, (in millions, except per share amounts) 2019 2018 2017 Income (loss) available for common shareholders $ (7,656) $ (6,851) $ 1,646 Weighted average common shares outstanding, basic 528 517 512 Add incremental shares from assumed conversions: Employee share-based compensation — — 1 Weighted average common share outstanding, diluted 528 517 513 Total earnings (loss) per common share, diluted $ (14.50) $ (13.25) $ 3.21 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, 2019 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | 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 tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortizes 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. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more. PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis. The significant components of income tax provision (benefit) by taxing jurisdiction were as follows: PG&E Corporation Utility Year Ended December 31, (in millions) 2019 2018 2017 2019 2018 2017 Current: Federal $ 1 $ (5) $ (10) $ 4 $ 5 $ 61 State 101 (8) 48 94 (7) 50 Deferred: Federal (2,361) (2,264) 481 (2,363) (2,278) 326 State (1,136) (1,009) 6 (1,137) (1,009) 4 Tax credits (5) (6) (14) (5) (6) (14) Income tax provision (benefit) $ (3,400) $ (3,292) $ 511 $ (3,407) $ (3,295) $ 427 The following tables describe net deferred income tax assets and liabilities: PG&E Corporation Utility Year Ended December 31, (in millions) 2019 2018 2019 2018 Deferred income tax assets: Tax carryforwards $ 1,390 $ 740 $ 1,308 $ 650 Compensation 151 173 92 121 Income tax regulatory liability (1) — 79 — 79 Wildfire-related claims (2) 6,520 3,433 6,520 3,433 Operating lease liability 642 — 640 — Other (3) 112 87 121 93 Total deferred income tax assets $ 8,815 $ 4,512 $ 8,681 $ 4,376 Deferred income tax liabilities: Property related basis differences 7,984 7,672 7,973 7,660 Regulatory balancing accounts 381 118 381 118 Operating lease right of use asset 642 — 640 — Income tax regulatory asset (1) 71 — 71 — Other (4) 57 3 58 3 Total deferred income tax liabilities $ 9,135 $ 7,793 $ 9,123 $ 7,781 Total net deferred income tax liabilities $ 320 $ 3,281 $ 442 $ 3,405 (1) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. (For more information see Note 3 above). (2) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to the 2018 Camp fire, 2017 Northern California wildfires, and the 2015 Butte fire. (3) Amounts include benefits, environmental reserve, and customer advances for construction. (4) Amount primarily includes an environmental reserve. 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, 2019 2018 2017 2019 2018 2017 Federal statutory income tax rate 21.0 % 21.0 % 35.0 % 21.0 % 21.0 % 35.0 % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) 7.5 7.9 1.5 7.5 7.9 1.6 Effect of regulatory treatment of fixed asset differences (2) 2.8 3.6 (16.5) 2.8 3.6 (16.8) Tax credits 0.1 0.1 (1.1) 0.1 0.1 (1.1) Compensation related (3) — (0.2) (1.0) — (0.1) (0.9) Tax Reform adjustment (4) — 0.1 6.8 — 0.1 3.0 Other, net (5) (0.6) — (1.1) (0.5) — (0.7) Effective tax rate 30.8 % 32.5 % 23.6 % 30.9 % 32.6 % 20.1 % (1) Includes the effect of state flow-through ratemaking treatment. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. 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 Utility’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 customers in future rates. In 2019 and 2018, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017. (3) Primarily represents adjustments to compensation as a result of the enactment of the Tax Act. (4) Represents adjustments to deferred tax balances under Staff Accounting Bulletin No. 118 reflecting the tax rate reduction required by the Tax Act. (5) These amounts primarily represent the impact of non-tax deductible bankruptcy costs in 2019 and tax audit settlements in 2017. Unrecognized tax benefits The following table reconciles the changes in unrecognized tax benefits: PG&E Corporation Utility (in millions) 2019 2018 2017 2019 2018 2017 Balance at beginning of year $ 377 $ 349 $ 388 $ 377 $ 349 $ 382 Reductions for tax position taken during a prior year (1) (27) (71) (1) (27) (71) Additions for tax position taken during the current year 44 55 48 44 55 48 Settlements — — (14) — — (8) Expiration of statute — — (3) — — (3) Balance at end of year $ 420 $ 377 $ 349 $ 420 $ 377 $ 349 The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2019 for PG&E Corporation and the Utility was $6 million. PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months. As of December 31, 2019, it is reasonably possible that unrecognized tax benefits will decrease by approximately $10 million within the next 12 months. 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, 2019, 2018, and 2017, these amounts were immaterial. Tax Cuts and Jobs Act of 2017 On December 22, 2017, the U.S. government enacted expansive tax legislation commonly referred to as the Tax Act. Among other provisions, the Tax Act reduces the federal income tax rate from 35% to 21% beginning on January 1, 2018 and eliminated bonus depreciation for utilities. The Treasury is still issuing interpretive guidance on various aspects of the Tax Act. If future guidance requires a change in the recorded tax amounts, any necessary change will be reflected in the period such guidance is issued. Tax settlements PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes, except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the Penalty Decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. Tax years after 2007 remain subject to examination by the state of California. Carryforwards The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances: (in millions) December 31, 2019 Expiration Federal: Net operating loss carryforward - Pre-2018 $ 3,940 2031 - 2036 Net operating loss carryforward - Post-2017 1,777 N/A Tax credit carryforward 127 2029 - 2039 State: Net operating loss carryforward $ 1,927 N/A Tax credit carryforward 96 Various |
DERIVATIVES
DERIVATIVES | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVES | DERIVATIVES Use of Derivative 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 contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. By order dated April 8, 2019, the Bankruptcy Court authorized the Utility to continue these programs in the ordinary course of business in a manner consistent with its pre-petition practices. Derivatives are presented in the Utility’s Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counter-party. 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 costs 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 change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Consolidated Balance Sheets at fair value. Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume At December 31, Underlying Product Instruments 2019 2018 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 131,896,159 177,750,349 Options 14,720,000 13,735,405 Electricity (Megawatt-hours) Forwards and Swaps 18,675,852 3,833,490 Congestion Revenue Rights (3) 308,467,999 340,783,089 (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. Presentation of Derivative Instruments in the Financial Statements At December 31, 2019, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 36 $ (6) $ 4 $ 34 Other noncurrent assets – other 130 (6) — 124 Current liabilities – other (31) 6 2 (23) Noncurrent liabilities – other (130) 6 — (124) Total commodity risk $ 5 $ — $ 6 $ 11 At December 31, 2018, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 44 $ (1) $ 89 $ 132 Other noncurrent assets – other 165 — — 165 Current liabilities – other (29) 1 7 (21) Noncurrent liabilities – other (90) — 2 (88) Total commodity risk $ 90 $ — $ 98 $ 188 Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS PG&E Corporation and the Utility measure their cash equivalents, 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 fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements At December 31, 2019 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 1,323 $ — $ — $ — $ 1,323 Nuclear decommissioning trusts Short-term investments 6 — — — 6 Global equity securities 2,086 — — — 2,086 Fixed-income securities 862 728 — — 1,590 Assets measured at NAV — — — — 21 Total nuclear decommissioning trusts (2) 2,954 728 — — 3,703 Price risk management instruments (Note 10) Electricity — 2 161 (11) 152 Gas — 3 — 3 6 Total price risk management instruments — 5 161 (8) 158 Rabbi trusts Fixed-income securities — 100 — — 100 Life insurance contracts — 73 — — 73 Total rabbi trusts — 173 — — 173 Long-term disability trust Short-term investments 10 — — — 10 Assets measured at NAV — — — — 156 Total long-term disability trust 10 — — — 166 TOTAL ASSETS $ 4,287 $ 906 $ 161 $ (8) $ 5,523 Liabilities: Price risk management instruments (Note 10) Electricity $ 1 $ 2 $ 156 $ (13) $ 146 Gas — 2 — (1) 1 TOTAL LIABILITIES $ 1 $ 4 $ 156 $ (14) $ 147 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $530 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2018 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 1,593 $ — $ — $ — $ 1,593 Nuclear decommissioning trusts Short-term investments 29 — — — 29 Global equity securities 1,793 — — — 1,793 Fixed-income securities 661 639 — — 1,300 Assets measured at NAV — — — — 16 Total nuclear decommissioning trusts (2) 2,483 639 — — 3,138 Price risk management instruments (Note 10) Electricity — 5 203 51 259 Gas — 1 — 37 38 Total price risk management instruments — 6 203 88 297 Rabbi trusts Fixed-income securities — 93 — — 93 Life insurance contracts — 67 — — 67 Total rabbi trusts — 160 — — 160 Long-term disability trust Short-term investments 7 — — — 7 Assets measured at NAV — — — — 155 Total long-term disability trust 7 — — — 162 TOTAL ASSETS $ 4,083 $ 805 $ 203 $ 88 $ 5,350 Liabilities: Price risk management instruments (Note 10) Electricity 4 5 108 (10) 107 Gas — 2 — — 2 TOTAL LIABILITIES $ 4 $ 7 $ 108 $ (10) $ 109 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $408 million, primarily related to deferred taxes on appreciation of investment value. Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the years ended December 31, 2019 and 2018. Trust Assets Assets Measured at Fair Value 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 prices 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 fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments 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 included 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 that are composed primarily of U.S. government securities and asset-backed securities. Price Risk Management Instruments Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures 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 futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs 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 Uncertainty Analysis Inputs used and 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 10 above. Fair Value at (in millions) At December 31, 2019 Valuation Unobservable Fair Value Measurement Assets Liabilities Range (1) /Weighted-Average Price (2) Congestion revenue rights $ 140 $ 44 Market approach CRR auction prices $ (20.20) - 20.20 / 0.28 Power purchase agreements $ 21 $ 112 Discounted cash flow Forward prices $ 11.77 - 59.38 / 33.62 (1) Represents price per megawatt-hour. (2) Unobservable inputs were weighted by the relative fair value of the instruments. Fair Value at (in millions) At December 31, 2018 Valuation Unobservable Fair Value Measurement Assets Liabilities Range (1) Congestion revenue rights $ 203 $ 75 Market approach CRR auction prices $ (18.61) - 32.26 Power purchase agreements $ — $ 33 Discounted cash flow Forward prices $ 19.81 - 38.80 (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, 2019 and 2018, respectively: Price Risk Management Instruments (in millions) 2019 2018 Asset (liability) balance as of January 1 $ 95 $ 42 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (90) 53 Asset (liability) balance as of December 31 $ 5 $ 95 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. 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, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2019 and 2018, as they are short-term in nature. The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At December 31, 2019 2018 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 5) PG&E Corporation (1) $ — $ — $ 350 $ 350 Utility (1)(2) 1,500 1,500 17,450 14,747 (1) On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 5. (2) The fair value of the Utility pre-petition debt is $17.9 billion as of December 31, 2019. For more information, see Note 2 and Note 5. Nuclear Decommissioning Trust Investments The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Total Total Total Fair As of December 31, 2019 Nuclear decommissioning trusts Short-term investments $ 6 $ — $ — $ 6 Global equity securities 500 1,609 (2) 2,107 Fixed-income securities 1,505 89 (4) 1,590 Total (1) $ 2,011 $ 1,698 $ (6) $ 3,703 As of December 31, 2018 Nuclear decommissioning trusts Short-term investments $ 29 $ — $ — $ 29 Global equity securities 568 1,246 (5) 1,809 Fixed-income securities 1,288 30 (18) 1,300 Total (1) $ 1,885 $ 1,276 $ (23) $ 3,138 (1) Represents amounts before deducting $530 million and $408 million at December 31, 2019 and 2018, 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, 2019 Less than 1 year $ 42 1–5 years 488 5–10 years 397 More than 10 years 663 Total maturities of fixed-income securities $ 1,590 The following table provides a summary of activity for the fixed-income and equity securities: (in millions) 2019 2018 2017 Proceeds from sales and maturities of nuclear decommissioning investments $ 956 $ 1,412 $ 1,291 Gross realized gains on securities 69 54 53 Gross realized losses on securities (14) (24) (11) |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 12 Months Ended |
Dec. 31, 2019 | |
Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract] | |
EMPLOYEE BENEFIT PLANS | 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”). Certain trusts underlying these plans are qualified trusts under the Internal Revenue Code of 1986, as amended. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations. PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. On an annual basis, the Utility funds the pension plans up to the amount it is authorized to recover in rates, $328 million for both 2019 and 2018. 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 the Utility use a fiscal year-end measurement date for all plans. On February 27, 2019, PG&E Corporation and the Utility received approval from the Bankruptcy Court to maintain existing pension and other benefit plans during the pendency of the Chapter 11 Cases. (For more information see “First Day Motions” in Note 2 above.) Change in Plan Assets, Benefit Obligations, and Funded Status The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2019 and 2018: Pension Plan (in millions) 2019 2018 Change in plan assets: Fair value of plan assets at beginning of year $ 15,312 $ 16,652 Actual return on plan assets 3,713 (923) Company contributions 328 334 Benefits and expenses paid (806) (751) Fair value of plan assets at end of year $ 18,547 $ 15,312 Change in benefit obligation: Benefit obligation at beginning of year $ 17,407 $ 18,757 Service cost for benefits earned 443 514 Interest cost 758 687 Actuarial (gain) loss 2,723 (1,800) Plan amendments — — Benefits and expenses paid (806) (751) Benefit obligation at end of year (1) $ 20,525 $ 17,407 Funded Status: Current liability $ (14) $ (8) Noncurrent liability (1,964) (2,087) Net liability at end of year $ (1,978) $ (2,095) (1) PG&E Corporation’s accumulated benefit obligation was $18.4 billion and $15.8 billion at December 31, 2019 and 2018, respectively. Postretirement Benefits Other than Pensions (in millions) 2019 2018 Change in plan assets: Fair value of plan assets at beginning of year $ 2,258 $ 2,420 Actual return on plan assets 474 (108) Company contributions 29 31 Plan participant contribution 82 81 Benefits and expenses paid (165) (166) Fair value of plan assets at end of year $ 2,678 $ 2,258 Change in benefit obligation: Benefit obligation at beginning of year $ 1,745 $ 1,897 Service cost for benefits earned 56 66 Interest cost 76 69 Actuarial (gain) loss 22 (221) Benefits and expenses paid (150) (150) Federal subsidy on benefits paid 2 3 Plan participant contributions 81 81 Benefit obligation at end of year $ 1,832 $ 1,745 Funded Status: (1) Noncurrent asset $ 879 $ 545 Noncurrent liability (33) (32) Net asset at end of year $ 846 $ 513 (1) At December 31, 2019 and 2018, 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. Components of Net Periodic Benefit Cost PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows: Pension Plan (in millions) 2019 2018 2017 Service cost for benefits earned (1) $ 443 $ 514 $ 472 Interest cost 758 687 714 Expected return on plan assets (906) (1,021) (770) Amortization of prior service cost (6) (6) (7) Amortization of net actuarial loss 3 5 22 Net periodic benefit cost 292 179 431 Less: transfer to regulatory account (2) 42 157 (92) Total expense recognized $ 334 $ 336 $ 339 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) 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) 2019 2018 2017 Service cost for benefits earned (1) $ 56 $ 66 $ 59 Interest cost 76 69 77 Expected return on plan assets (123) (130) (97) Amortization of prior service cost 14 14 15 Amortization of net actuarial loss (3) (5) 4 Net periodic benefit cost $ 20 $ 14 $ 58 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. Non-service costs are reflected in Other income, net on the Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Consolidated Statements of Income. 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 benefits, 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 that 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 2020 are as follows: (in millions) Pension Plan PBOP Plans Unrecognized prior service cost $ (6) $ 14 Unrecognized net loss 3 (21) Total $ (3) $ (7) 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, 2019 2018 2017 2019 2018 2017 Discount rate 3.46 % 4.35 % 3.64 % 3.37 - 3.47% 4.29 - 4.37% 3.60 - 3.67% Rate of future compensation increases 3.90 % 3.90 % 3.90 % — — — Expected return on plan assets 5.70 % 6.00 % 6.20 % 3.50 - 6.60% 3.60 - 6.80% 3.30 - 7.10% The assumed health care cost trend rate as of December 31, 2019 was 6.3%, decreasing gradually to an ultimate trend rate in 2027 and beyond of approximately 4.5%. A one-percentage-point change in assumed health care cost trend rate would have the following effects: (in millions) One-Percentage-Point One-Percentage-Point Effect on postretirement benefit obligation $ 131 $ (129) Effect on service and interest cost 9 (9) Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the pension plan, the assumed return of 5.7% compares to a ten-year actual return of 9.3%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 936 Aa-grade non-callable bonds at December 31, 2019. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate. Investment Policies and Strategies The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs 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 policies 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. Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations 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 investments 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 correlation to the direction of these markets. Real assets include commodities futures, global REITS, global listed infrastructure equities, and private real estate funds. Absolute return investments include hedge fund portfolios. 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 portion 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 2020 2019 2018 2020 2019 2018 Global equity securities 30 % 29 % 29 % 28 % 33 % 33 % Absolute return 2 % 5 % 5 % 2 % 3 % 3 % Real assets 8 % 8 % 8 % 8 % 6 % 6 % Fixed-income securities 60 % 58 % 58 % 62 % 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 and responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments. 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, 2019 and 2018. Fair Value Measurements At December 31, 2019 2018 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 613 $ 231 $ — $ 844 $ 333 $ 22 $ — $ 355 Global equity securities 1,650 — — 1,650 1,145 — — 1,145 Absolute Return — 1 — 1 — — — — Real assets 548 1 — 549 461 — — 461 Fixed-income securities 2,227 6,413 15 8,655 1,897 5,216 8 7,121 Assets measured at NAV — — — 6,937 — — — 6,202 Total $ 5,038 $ 6,646 $ 15 $ 18,636 $ 3,836 $ 5,238 $ 8 $ 15,284 PBOP Plans: Short-term investments $ 37 $ — $ — $ 37 $ 33 $ — $ — $ 33 Global equity securities 151 — — 151 115 — — 115 Real assets 58 — — 58 50 — — 50 Fixed-income securities 193 875 1 1,069 153 857 — 1,010 Assets measured at NAV — — — 1,373 — — — 1,056 Total $ 439 $ 875 $ 1 $ 2,688 $ 351 $ 857 $ — $ 2,264 Total plan assets at fair value $ 21,324 $ 17,548 In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $99 million and other net assets of $22 million at December 31, 2019 and 2018, 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 securities The global equity category includes investments in common stock 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 private 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 securities 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 model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the trusts 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 investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, asset-backed securities, and private real estate funds. There are no restrictions on the terms and conditions upon which the investments may be redeemed. Transfers Between Levels No material transfers between levels occurred in the years ended December 31, 2019 and 2018. 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, 2019 and 2018: (in millions) For the year ended December 31, 2019 Fixed-Income Balance at beginning of year $ 8 Actual return on plan assets: Relating to assets still held at the reporting date — Relating to assets sold during the period — Purchases, issuances, sales, and settlements: Purchases 11 Settlements (4) Balance at end of year $ 15 (in millions) For the year ended December 31, 2018 Fixed-Income Balance at beginning of year $ 4 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 6 Settlements 1 Balance at end of year $ 8 There were no material transfers out of Level 3 in 2019 and 2018. Cash Flow Information Employer Contributions PG&E Corporation and the Utility contributed $328 million to the pension benefit plans and $29 million to the other benefit plans in 2019. 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 2019. The Utility’s pension benefits met all the funding requirements under Employee Retirement Income Security Act. PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $15 million to the pension plan and other postretirement benefit plans, respectively, for 2020. Benefits Payments and Receipts As of December 31, 2019, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows: (in millions) Pension PBOP Federal 2020 801 92 (8) 2021 874 94 (9) 2022 910 92 (2) 2023 944 95 (2) 2024 975 98 (3) Thereafter in the succeeding five years 5,238 482 (8) There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above. There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above. 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 employees 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 Statements of Income were $109 million, $105 million, and $103 million in 2019, 2018, and 2017, respectively. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation. There were no material 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, 2019 | |
Related Party Transactions [Abstract] | |
RELATED PARTY AGREEMENTS AND TRANSACTIONS | RELATED PARTY AGREEMENTS AND TRANSACTIONS The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies. The Utility’s significant related party transactions were: Year Ended December 31, (in millions) 2019 2018 2017 Utility revenues from: Administrative services provided to PG&E Corporation $ 4 $ 4 $ 8 Utility expenses from: Administrative services received from PG&E Corporation $ 107 $ 94 $ 65 Utility employee benefit due to PG&E Corporation 42 76 73 |
WILDFIRE-RELATED CONTINGENCIES
WILDFIRE-RELATED CONTINGENCIES | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
WILDFIRE-RELATED CONTINGENCIES | WILDFIRE-RELATED CONTINGENCIES PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. Pre-petition Wildfire-Related Claims Pre-petition wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire. At December 31, 2019 and December 31, 2018, the Utility’s Consolidated Balance Sheets include estimated liabilities in respect of total wildfire-related claims of $25.5 billion and $14.2 billion, respectively. The aggregate liability of $25.5 billion for claims in connection with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire is comprised of (i) $11 billion for subrogated insurance claimholders pursuant to the Subrogation RSA, plus (ii) $47.5 million for expected professional fees for professionals retained by subrogated insurance claimholders to be reimbursed pursuant to the Subrogation RSA, plus (iii) $1 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs, plus (iv) $13.5 billion for all other wildfire-related claims, including individual wildfire claimholders (including those with uninsured and underinsured property losses) and clean-up and fire suppression costs, pursuant to the TCC RSA. The aggregate liability of $25.5 billion for claims in connection with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire corresponds PG&E Corporation’s and the Utility’s best estimate of probable losses and is subject to change based on additional information, including the other factors discussed below. (See “2018 Camp Fire, 2017 Northern California Wildfires and 2015 Butte Fire Accounting Charge” below.) On the Petition Date, all wildfire-related claims were classified as LSTC and all pending litigation was stayed. In addition, during the year ended December 31, 2019, the Utility incurred legal and other costs of $152 million related to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire with $245 million corresponding costs in the same period in 2018. 2018 Camp Fire Background According to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of November 15, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 18,804 structures resulting from the 2018 Camp fire. There have been no subsequent updates of this information on the Cal Fire website. On May 15, 2019, Cal Fire issued a news release announcing the results of its investigation into the cause of the 2018 Camp fire. According to the news release: • Cal Fire determined that the 2018 Camp fire was caused by electrical transmission lines owned and operated by the Utility near Pulga, California. • Cal Fire identified a second ignition site and stated that the second fire was consumed by the original fire which started earlier near Pulga, California. Cal Fire stated that the cause of the second fire was determined to be “vegetation into electrical distribution lines owned and operated by” the Utility. Cal Fire indicated in its news release that its investigation report for the 2018 Camp fire has been forwarded to the Butte County District Attorney. The California Attorney General’s Office is also investigating the 2018 Camp fire. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the 2018 Camp fire.) As of the date of this filing, Cal Fire’s investigation report has not been shared with PG&E Corporation or the Utility. PG&E Corporation and the Utility accept Cal Fire’s determination that the 2018 Camp fire ignited at the first ignition site. PG&E Corporation and the Utility have not been able to form a conclusion as to whether a second fire ignited as a result of vegetation contact with the Utility’s facilities. PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigation or to the investigation report prepared by Cal Fire. Further, the CPUC’s SED also conducted investigations into whether the Utility committed civil violations in connection with the 2018 Camp fire. On November 26, 2019, the SED concluded its investigation into the 2018 Camp fire and released a report alleging certain violations of state law and CPUC regulations. See “Order Instituting an Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire” in Note 15 for a description of these proceedings, including the alleged violations in connection with the 2018 Camp fire. 2017 Northern California Wildfires Background Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities. Cal Fire has investigated the causes of the 2017 Northern California wildfires and made the following determinations: • the Utility’s equipment was involved in causing 20 wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket, Atlas, Cascade, Pressley, Point and Youngs fires); and • the Tubbs fire was caused by a private electrical system adjacent to a residential structure. As described under the heading “District Attorneys’ Offices’ Investigations” below, certain of the 2017 Northern California wildfires were the subject of criminal investigations, which have been settled or resulted in PG&E Corporation and the Utility being informed by the applicable district attorneys’ office of a decision not to prosecute. The SED also conducted investigations into whether the Utility committed civil violations in connection with the 2017 Northern California wildfires. See “Order Instituting an Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire” in Note 15 for a description of these proceedings, including the alleged violations in connection with the 2017 Northern California wildfires. Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the substantial cause of one or more fires, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires, including in connection with SB 901.) On October 25, 2019, PG&E Corporation and the Utility submitted a brief to the Bankruptcy Court challenging the application of inverse condemnation to California’s investor-owned utilities, including the Utility. The Bankruptcy Court heard argument regarding PG&E Corporation’s and the Utility’s motion on November 19, 2019. On December 3, 2019, the Bankruptcy Court entered an order holding that the doctrine of inverse condemnation applied to California’s investor-owned utilities, including the Utility, and certifying the decision for direct appeal to the U.S. Court of Appeals for the Ninth Circuit. PG&E Corporation and the Utility have appealed this decision; however, as of the date of this filing, this appeal was stayed upon request of PG&E Corporation and the Utility. In addition to claims for property damage, business interruption, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if the Utility were found to have been negligent. Further, the Utility could be subject to material fines, penalties, or restitution orders if the CPUC or any law enforcement agency were to bring an enforcement action, including a criminal proceeding, and it were determined that the Utility had failed to comply with applicable laws and regulations. As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 100 complaints on behalf of at least 4,200 plaintiffs related to the 2018 Camp fire, nine of which sought to be certified as class actions. The pending civil litigation against PG&E Corporation and the Utility related to the 2018 Camp fire, which is currently stayed as a result of the commencement of the Chapter 11 Cases, included claims under multiple theories of liability, including, but not limited to, inverse condemnation, trespass, private nuisance, public nuisance, negligence, negligence per se, negligent interference with prospective economic advantage, negligent infliction of emotional distress, premises liability, violations of the Public Utilities Code, violations of the Health & Safety Code, malice and false advertising in violation of the California Business and Professions Code. The plaintiffs principally asserted that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2018 Camp fire. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, establishment of a class action medical monitoring fund, punitive damages, attorneys’ fees and other damages. As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 750 complaints on behalf of at least 3,800 plaintiffs related to the 2017 Northern California wildfires, five of which sought to be certified as class actions. These cases were coordinated in the San Francisco County Superior Court. As of the Petition Date, the coordinated litigation was in the early stages of discovery. A trial with respect to the Atlas fire was scheduled to begin on September 23, 2019. The pending civil litigation against PG&E Corporation and the Utility related to the 2017 Northern California wildfires included claims under multiple theories of liability, including, but not limited to, inverse condemnation, trespass, private nuisance and negligence. This litigation, including the trial date with respect to the Atlas fire, currently is stayed as a result of the commencement of the Chapter 11 Cases. The plaintiffs principally asserted that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2017 Northern California wildfires. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees and other damages. As described below under the heading “Restructuring Support Agreement with the TCC,” on December 6, 2019, PG&E Corporation and the Utility entered into a RSA with the TCC, the Consenting Fire Claimant Professionals and the Shareholder Proponents to potentially resolve all wildfire-related claims relating to the 2017 Northern California wildfires and the 2018 Camp fire (other than subrogated insurance claims and Public Entity Wildfire Claims) through the Chapter 11 process. On December 19, 2019, the Bankruptcy Court entered an order granting PG&E Corporation’s and the Utility’s motion to approve the TCC RSA. Insurance carriers who have made payments to their insureds for property damage arising out of the 2017 Northern California wildfires filed 52 subrogation complaints in the San Francisco County Superior Court and the Sonoma County Superior Court as of January 28, 2019. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations are similar to the ones made by individual plaintiffs. As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, insurance carriers filed 39 similar subrogation complaints with respect to the 2018 Camp fire in the Sacramento County Superior Court and the Butte County Superior Court. As described below under the heading “Restructuring Support Agreement with Holders of Subrogation Claims,” on September 22, 2019, PG&E Corporation and the Utility entered into a RSA with certain holders of insurance subrogation claims to potentially resolve all insurance subrogation claims relating to the 2017 Northern California wildfires and the 2018 Camp fire through the Chapter 11 process. On December 19, 2019, the Bankruptcy Court entered an order granting PG&E Corporation’s and the Utility’s motion to approve the Subrogation RSA. Various government entities, including Yuba, Nevada, Lake, Mendocino, Napa and Sonoma Counties and the Cities of Santa Rosa and Clearlake, also asserted claims against PG&E Corporation and the Utility based on the damages that these government entities allegedly suffered as a result of the 2017 Northern California wildfires. Such alleged damages included, among other things, loss of natural resources, loss of public parks, property damages and fire suppression costs. The causes of action and allegations are similar to the ones made by individual plaintiffs and the insurance carriers. With respect to the 2018 Camp fire, Butte County has filed similar claims against PG&E Corporation and the Utility. As described below under the heading “Plan Support Agreements with Public Entities,” on June 18, 2019, PG&E Corporation and the Utility entered into agreements with certain government entities to potentially resolve their wildfire-related claims through the Chapter 11 process. The PSAs do not require Bankruptcy Court approval to be effective; however, the Bankruptcy Court must ultimately approve the Proposed Plan that incorporates the terms of the PSAs. FEMA has filed proofs of claim in the Chapter 11 Cases in the amount of $1.2 billion in connection with the 2017 Northern California wildfires and $2.6 billion in connection with the 2018 Camp fire. FEMA has objected to the classification of their claims under the Proposed Plan as Fire Victim Claims and has indicated that it intends to seek to have its claims classified separately from the Fire Victim Claims. In addition, Cal Fire has filed proofs of claim in the Chapter 11 Cases in the amount of $133 million in connection with the 2017 Northern California wildfires and specifying at least $110 million in connection with the 2018 Camp fire. The OES has filed proofs of claim in the amount of $347 million in connection with the 2017 Northern California wildfires and $2.3 billion in connection with the 2018 Camp fire. The California Department of Transportation has filed proofs of claim in the Chapter 11 Cases in the amount of $217 million in connection with the 2018 Camp fire. Certain other Federal, state and local entities (that are not Supporting Public Entities) have filed proofs of claim in the Chapter 11 Cases in connection with the 2017 Northern California wildfires and the 2018 Camp fire asserting total claims in the amount of $503 million. Proofs of claim have also been filed for unspecified amounts to be determined at a later time. On December 12, 2019, the TCC filed an objection to the claims filed by OES in which it argued that the Bankruptcy Court should disallow the OES claims. On January 9, 2020, the TCC filed a supplement to its objection in which it also objected to the claims filed by FEMA. On February 5, 2020, PG&E Corporation and the Utility joined in the TCC's objection to the OES and FEMA claims. On February 12, 2020, a number of individuals and businesses who hold wildfire-related claims in connection with the 2015 Butte fire, 2017 Northern California wildfires and 2018 Camp fire, as well as certain of the Tubbs Preference Plaintiffs, joined in the TCC’s objection to the OES and FEMA claims. Also on February 12, 2020, OES and FEMA filed oppositions to the TCC’s objection. A hearing on the objection is scheduled for February 26, 2020. As described in Note 2, on July 1, 2019, the Bankruptcy Court entered an order approving the Bar Date of October 21, 2019, at 5:00 p.m. (Pacific Time) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date, including claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires. On November 11, 2019, the Bankruptcy Court entered an order approving a stipulation between PG&E Corporation and the Utility and the TCC to extend the Bar Date for unfiled, non-governmental fire claimants to December 31, 2019, at 5:00 p.m. (Pacific Time). See “Potential Claims” in Note 2 above. Regardless of any determinations of cause by Cal Fire with respect to any pre-petition fire, ultimately PG&E Corporation’s and the Utility’s liability will be determined through the Chapter 11 process (including the settlement agreements described below), regulatory proceedings and any potential enforcement proceedings. The timing and outcome of these and other potential proceedings are uncertain. As discussed under the headings “Plan Support Agreements with Public Entities,” “Restructuring Support Agreement with Holders of Subrogation Claims” and “Restructuring Support Agreement with the TCC,” PG&E Corporation and the Utility have entered into agreements with certain government entity claimholders, certain insurance subrogation claimholders, and the TCC and the Consenting Fire Claimant Professionals, which agreements would potentially resolve all wildfire-related claims arising from the 2017 Northern California wildfires and the 2018 Camp fire. The resolution of claims asserted by certain federal and California government entities that are not Supporting Public Entities is contemplated by the TCC RSA, however, no government entity is a party to the TCC RSA, and accordingly there can be no assurance that such government entities will support the Proposed Plan or the treatment of their claims in the Chapter 11 cases as provided by the Proposed Plan. Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims (the “Tubbs Trial”) In connection with the TCC RSA, on December 26, 2019, the San Francisco Superior Court entered an order vacating all dates and deadlines in the Tubbs Trial and scheduled a hearing for March 2, 2020 to show cause regarding dismissal of the Tubbs Trial. On January 6, 2020, in accordance with the terms of the TCC RSA, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into settlement agreements settling and liquidating the claims asserted against PG&E Corporation and the Utility by each of the Tubbs preference plaintiffs. On January 30, 2020, the Bankruptcy Court issued an order granting PG&E Corporation and the Utility’s motion to enter into settlement agreements with each of the Tubbs preference plaintiffs. Wildfire Claims Estimation Proceeding in the U.S. District Court for the Northern District of California (the “Estimation Proceeding”) On July 18, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for certain claims arising out of the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. On August 21, 2019, the Bankruptcy Court issued recommendations to the District Court recommending the District Court order the partial withdrawal of the reference of the section 502(c) estimation of unliquidated claims arising from the 2018 Camp fire and the 2017 Northern California wildfires. On August 23, 2019, the District Court issued an order adopting the recommendation of the Bankruptcy Court in full and ordering that the reference to the Bankruptcy Court be withdrawn in part. On October 9, 2019, the District Court issued an initial order for the estimation hearings to begin on February 18, 2020 and conclude on February 28, 2020, with the possibility of an additional week of hearings if warranted. In connection with the TCC RSA, on December 20, 2019, the District Court entered an order staying the Estimation Proceeding and vacating the February 18, 2020 hearing and all pre-hearing dates. Plan Support Agreements with Public Entities On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to the Proposed Plan in order to settle such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”). PG&E Corporation and the Utility have entered into a PSA with each of the following public entities or groups of public entities, as applicable: • the City of Clearlake, the City of Napa, the City of Santa Rosa, the County of Lake, the Lake County Sanitation District, the County of Mendocino, Napa County, the County of Nevada, the County of Sonoma, the Sonoma County Agricultural Preservation and Open Space District, the Sonoma County Community Development Commission, the Sonoma County Water Agency, the Sonoma Valley County Sanitation District and the County of Yuba (collectively, the “2017 Northern California Wildfire Public Entities”); • the Town of Paradise; • the County of Butte; • the Paradise Recreation & Park District; • the County of Yuba; and • the Calaveras County Water District. For purposes of each PSA, the local public entities that are party to such PSA are referred to herein as “Supporting Public Entities.” Each PSA provides that the Proposed Plan will include, among other things, the following elements: • following the effective date of the Proposed Plan, PG&E Corporation and the Utility will remit a Settlement Amount (as defined below) in the amount set forth below to the applicable Supporting Public Entities in full and final satisfaction and discharge of their Public Entity Wildfire Claims, and • subject to the Supporting Public Entities voting affirmatively to accept the Proposed Plan, following the effective date of the Proposed Plan, PG&E Corporation and the Utility will create and promptly fund $10.0 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”). The “Settlement Amount” set forth in each PSA is as follows: • for the 2017 Northern California Wildfire Public Entities, $415.0 million (which amount will be allocated among such entities), • for the Town of Paradise, $270.0 million, • for the County of Butte, $252.0 million, • for the Paradise Recreation & Park District, $47.5 million, • for the County of Yuba, $12.5 million, and • for the Calaveras County Water District, $3.0 million. Each PSA provides that, subject to certain terms and conditions, the Supporting Public Entities will support the Proposed Plan with respect to its treatment of their respective Public Entity Wildfire Claims, including by voting to accept the Proposed Plan in the Chapter 11 Cases. Each PSA may be terminated by the applicable Supporting Public Entities under certain circumstances, including: • if the Federal Emergency Management Agency or the OES fails to agree that no reimbursement is required from the Supporting Public Entities on account of assistance rendered by either agency in connection with the wildfires noted above, and • by any individual Supporting Public Entity, if a material amount of Third Party Claims is filed against such Supporting Public Entity and such Third Party Claims are not released pursuant to the Proposed Plan. Each PSA may be terminated by PG&E Corporation and the Utility under certain circumstances, including if: • PG&E Corporation and the Utility do not obtain the consent, or the waiver of the lack of consent as a defense, of their insurance carriers for the policy years 2017 and 2018, • the Board of Directors of either PG&E Corporation or the Utility determines in good faith that continued performance under the PSA would be inconsistent with the exercise of its fiduciary duties, and • any Supporting Public Entity terminates a PSA, in which case PG&E Corporation and the Utility may terminate any other PSA. Restructuring Support Agreement with Holders of Subrogation Claims On September 22, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with the Consenting Subrogation Creditors of insurance subrogation claims, which agreement was amended and restated on November 1, 2019 and subsequently further amended during November and December 2019 (as amended, the “Subrogation RSA”). The Subrogation RSA provides for an aggregate amount of $11.0 billion (the “Aggregate Subrogation Recovery”) to be paid by PG&E Corporation and the Utility pursuant to the Proposed Plan in order to settle the Subrogation Claims, upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility have also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA. The Subrogation RSA provides that, subject to certain terms and conditions (including that PG&E Corporation and the Utility remain solvent), the Consenting Subrogation Creditors will support the Proposed Plan with respect to its treatment of the Subrogation Claims, including by voting their Subrogation Claims to accept the Proposed Plan in the Chapter 11 Cases. On September 24, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the Subrogation RSA and approving the terms of the settlement contemplated under the Subrogation RSA. On December 19, 2019, the Bankruptcy Court entered an order granting PG&E Corporation’s and the Utility’s motion to approve the Subrogation RSA. On December 31, 2019, the Ad Hoc Noteholder Committee filed a motion with the Bankruptcy Court to vacate the Bankruptcy Court’s order approving the Subrogation RSA in its entirety or, in the alternative, vacate the Bankruptcy Court’s order approving the Subrogation RSA and condition approval of the Subrogation RSA on removal of certain provisions contained therein. Pursuant to the Noteholder RSA, the Ad Hoc Noteholder Committee withdrew its motion on February 5, 2020. The Subrogation RSA will automatically terminate if (i) the Proposed Plan is not confirmed by June 30, 2020 (or such later date as may be authorized by any amendment to AB 1054) or (ii) the Effective Date does not occur prior to December 31, 2020 (or six months following the deadline for confirmation of the Proposed Plan if such deadline is extended by any amendment to AB 1054). The Subrogation RSA may be terminated by any Consenting Subrogation Creditor as to itself if the Aggregate Subrogation Recovery is modified. The Subrogation RSA may be terminated by the Consenting Subrogation Creditors holding at least two-thirds of the Subrogation Claims held by Consenting Subrogation Creditors under certain circumstances, including, among others, if (i) they reasonably determine in good faith at any time prior to confirmation of the Proposed Plan that PG&E Corporation and the Utility are insolvent or otherwise unable to raise sufficient capital to pay the Aggregate Subrogation Recovery on the Effective Date, (ii) PG&E Corporation and the Utility breach the terms of the Subrogation RSA or otherwise fail to take certain actions specified in the Subrogation RSA, (iii) the Proposed Plan does not treat the individual plaintiffs’ wildfire-related claims consistent with the provisions of AB 1054, (iv) the Bankruptcy Court allows a plan proponent other than PG&E Corporation and the Utility to commence soliciting votes on a plan (other than the Proposed Plan) that incorporates the terms of the settlement contemplated by the Subrogation RSA and PG&E Corporation and the Utility have not already commenced soliciting votes on the Proposed Plan which incorporates such settlement, (v) the Bankruptcy Court confirms a plan other than the Proposed Plan or (vi) the Proposed Plan is modified to be inconsistent with such settlement. The Subrogation RSA may be terminated by PG&E Corporation and the Utility (a) in the event of certain breaches of the Subrogation RSA by Consenting Subrogation Creditors holding at least 5% of the Subrogation Claims held by Consenting Subrogation Creditors or (b) if the Bankruptcy Court confirms a plan other than the Proposed Plan or if the terms of the Proposed Plan related to the settlement contemplated by the Subrogation RSA become unenforceable or are enjoined. Subject to certain limited exceptions, the valuation of the Subrogation Claims in an aggregate amount of $11.0 billion (the “Allowed Subrogation Claim Amount”) will survive any termination of the Subrogation RSA and will be binding on PG&E Corporation and the Utility in the Chapter 11 Cases. Restructuring Support Agreement with the TCC On December 6, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement, which was subsequently amended on December 16, 2019, with the TCC, the Consenting Fire Claimant Professionals and the Sha |
OTHER CONTINGENCIES AND COMMITM
OTHER CONTINGENCIES AND COMMITMENTS | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
OTHER CONTINGENCIES AND COMMITMENTS | WILDFIRE-RELATED CONTINGENCIES PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. Pre-petition Wildfire-Related Claims Pre-petition wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire. At December 31, 2019 and December 31, 2018, the Utility’s Consolidated Balance Sheets include estimated liabilities in respect of total wildfire-related claims of $25.5 billion and $14.2 billion, respectively. The aggregate liability of $25.5 billion for claims in connection with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire is comprised of (i) $11 billion for subrogated insurance claimholders pursuant to the Subrogation RSA, plus (ii) $47.5 million for expected professional fees for professionals retained by subrogated insurance claimholders to be reimbursed pursuant to the Subrogation RSA, plus (iii) $1 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs, plus (iv) $13.5 billion for all other wildfire-related claims, including individual wildfire claimholders (including those with uninsured and underinsured property losses) and clean-up and fire suppression costs, pursuant to the TCC RSA. The aggregate liability of $25.5 billion for claims in connection with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire corresponds PG&E Corporation’s and the Utility’s best estimate of probable losses and is subject to change based on additional information, including the other factors discussed below. (See “2018 Camp Fire, 2017 Northern California Wildfires and 2015 Butte Fire Accounting Charge” below.) On the Petition Date, all wildfire-related claims were classified as LSTC and all pending litigation was stayed. In addition, during the year ended December 31, 2019, the Utility incurred legal and other costs of $152 million related to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire with $245 million corresponding costs in the same period in 2018. 2018 Camp Fire Background According to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of November 15, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 18,804 structures resulting from the 2018 Camp fire. There have been no subsequent updates of this information on the Cal Fire website. On May 15, 2019, Cal Fire issued a news release announcing the results of its investigation into the cause of the 2018 Camp fire. According to the news release: • Cal Fire determined that the 2018 Camp fire was caused by electrical transmission lines owned and operated by the Utility near Pulga, California. • Cal Fire identified a second ignition site and stated that the second fire was consumed by the original fire which started earlier near Pulga, California. Cal Fire stated that the cause of the second fire was determined to be “vegetation into electrical distribution lines owned and operated by” the Utility. Cal Fire indicated in its news release that its investigation report for the 2018 Camp fire has been forwarded to the Butte County District Attorney. The California Attorney General’s Office is also investigating the 2018 Camp fire. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the 2018 Camp fire.) As of the date of this filing, Cal Fire’s investigation report has not been shared with PG&E Corporation or the Utility. PG&E Corporation and the Utility accept Cal Fire’s determination that the 2018 Camp fire ignited at the first ignition site. PG&E Corporation and the Utility have not been able to form a conclusion as to whether a second fire ignited as a result of vegetation contact with the Utility’s facilities. PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigation or to the investigation report prepared by Cal Fire. Further, the CPUC’s SED also conducted investigations into whether the Utility committed civil violations in connection with the 2018 Camp fire. On November 26, 2019, the SED concluded its investigation into the 2018 Camp fire and released a report alleging certain violations of state law and CPUC regulations. See “Order Instituting an Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire” in Note 15 for a description of these proceedings, including the alleged violations in connection with the 2018 Camp fire. 2017 Northern California Wildfires Background Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities. Cal Fire has investigated the causes of the 2017 Northern California wildfires and made the following determinations: • the Utility’s equipment was involved in causing 20 wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket, Atlas, Cascade, Pressley, Point and Youngs fires); and • the Tubbs fire was caused by a private electrical system adjacent to a residential structure. As described under the heading “District Attorneys’ Offices’ Investigations” below, certain of the 2017 Northern California wildfires were the subject of criminal investigations, which have been settled or resulted in PG&E Corporation and the Utility being informed by the applicable district attorneys’ office of a decision not to prosecute. The SED also conducted investigations into whether the Utility committed civil violations in connection with the 2017 Northern California wildfires. See “Order Instituting an Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire” in Note 15 for a description of these proceedings, including the alleged violations in connection with the 2017 Northern California wildfires. Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the substantial cause of one or more fires, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires, including in connection with SB 901.) On October 25, 2019, PG&E Corporation and the Utility submitted a brief to the Bankruptcy Court challenging the application of inverse condemnation to California’s investor-owned utilities, including the Utility. The Bankruptcy Court heard argument regarding PG&E Corporation’s and the Utility’s motion on November 19, 2019. On December 3, 2019, the Bankruptcy Court entered an order holding that the doctrine of inverse condemnation applied to California’s investor-owned utilities, including the Utility, and certifying the decision for direct appeal to the U.S. Court of Appeals for the Ninth Circuit. PG&E Corporation and the Utility have appealed this decision; however, as of the date of this filing, this appeal was stayed upon request of PG&E Corporation and the Utility. In addition to claims for property damage, business interruption, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if the Utility were found to have been negligent. Further, the Utility could be subject to material fines, penalties, or restitution orders if the CPUC or any law enforcement agency were to bring an enforcement action, including a criminal proceeding, and it were determined that the Utility had failed to comply with applicable laws and regulations. As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 100 complaints on behalf of at least 4,200 plaintiffs related to the 2018 Camp fire, nine of which sought to be certified as class actions. The pending civil litigation against PG&E Corporation and the Utility related to the 2018 Camp fire, which is currently stayed as a result of the commencement of the Chapter 11 Cases, included claims under multiple theories of liability, including, but not limited to, inverse condemnation, trespass, private nuisance, public nuisance, negligence, negligence per se, negligent interference with prospective economic advantage, negligent infliction of emotional distress, premises liability, violations of the Public Utilities Code, violations of the Health & Safety Code, malice and false advertising in violation of the California Business and Professions Code. The plaintiffs principally asserted that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2018 Camp fire. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, establishment of a class action medical monitoring fund, punitive damages, attorneys’ fees and other damages. As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 750 complaints on behalf of at least 3,800 plaintiffs related to the 2017 Northern California wildfires, five of which sought to be certified as class actions. These cases were coordinated in the San Francisco County Superior Court. As of the Petition Date, the coordinated litigation was in the early stages of discovery. A trial with respect to the Atlas fire was scheduled to begin on September 23, 2019. The pending civil litigation against PG&E Corporation and the Utility related to the 2017 Northern California wildfires included claims under multiple theories of liability, including, but not limited to, inverse condemnation, trespass, private nuisance and negligence. This litigation, including the trial date with respect to the Atlas fire, currently is stayed as a result of the commencement of the Chapter 11 Cases. The plaintiffs principally asserted that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2017 Northern California wildfires. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees and other damages. As described below under the heading “Restructuring Support Agreement with the TCC,” on December 6, 2019, PG&E Corporation and the Utility entered into a RSA with the TCC, the Consenting Fire Claimant Professionals and the Shareholder Proponents to potentially resolve all wildfire-related claims relating to the 2017 Northern California wildfires and the 2018 Camp fire (other than subrogated insurance claims and Public Entity Wildfire Claims) through the Chapter 11 process. On December 19, 2019, the Bankruptcy Court entered an order granting PG&E Corporation’s and the Utility’s motion to approve the TCC RSA. Insurance carriers who have made payments to their insureds for property damage arising out of the 2017 Northern California wildfires filed 52 subrogation complaints in the San Francisco County Superior Court and the Sonoma County Superior Court as of January 28, 2019. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations are similar to the ones made by individual plaintiffs. As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, insurance carriers filed 39 similar subrogation complaints with respect to the 2018 Camp fire in the Sacramento County Superior Court and the Butte County Superior Court. As described below under the heading “Restructuring Support Agreement with Holders of Subrogation Claims,” on September 22, 2019, PG&E Corporation and the Utility entered into a RSA with certain holders of insurance subrogation claims to potentially resolve all insurance subrogation claims relating to the 2017 Northern California wildfires and the 2018 Camp fire through the Chapter 11 process. On December 19, 2019, the Bankruptcy Court entered an order granting PG&E Corporation’s and the Utility’s motion to approve the Subrogation RSA. Various government entities, including Yuba, Nevada, Lake, Mendocino, Napa and Sonoma Counties and the Cities of Santa Rosa and Clearlake, also asserted claims against PG&E Corporation and the Utility based on the damages that these government entities allegedly suffered as a result of the 2017 Northern California wildfires. Such alleged damages included, among other things, loss of natural resources, loss of public parks, property damages and fire suppression costs. The causes of action and allegations are similar to the ones made by individual plaintiffs and the insurance carriers. With respect to the 2018 Camp fire, Butte County has filed similar claims against PG&E Corporation and the Utility. As described below under the heading “Plan Support Agreements with Public Entities,” on June 18, 2019, PG&E Corporation and the Utility entered into agreements with certain government entities to potentially resolve their wildfire-related claims through the Chapter 11 process. The PSAs do not require Bankruptcy Court approval to be effective; however, the Bankruptcy Court must ultimately approve the Proposed Plan that incorporates the terms of the PSAs. FEMA has filed proofs of claim in the Chapter 11 Cases in the amount of $1.2 billion in connection with the 2017 Northern California wildfires and $2.6 billion in connection with the 2018 Camp fire. FEMA has objected to the classification of their claims under the Proposed Plan as Fire Victim Claims and has indicated that it intends to seek to have its claims classified separately from the Fire Victim Claims. In addition, Cal Fire has filed proofs of claim in the Chapter 11 Cases in the amount of $133 million in connection with the 2017 Northern California wildfires and specifying at least $110 million in connection with the 2018 Camp fire. The OES has filed proofs of claim in the amount of $347 million in connection with the 2017 Northern California wildfires and $2.3 billion in connection with the 2018 Camp fire. The California Department of Transportation has filed proofs of claim in the Chapter 11 Cases in the amount of $217 million in connection with the 2018 Camp fire. Certain other Federal, state and local entities (that are not Supporting Public Entities) have filed proofs of claim in the Chapter 11 Cases in connection with the 2017 Northern California wildfires and the 2018 Camp fire asserting total claims in the amount of $503 million. Proofs of claim have also been filed for unspecified amounts to be determined at a later time. On December 12, 2019, the TCC filed an objection to the claims filed by OES in which it argued that the Bankruptcy Court should disallow the OES claims. On January 9, 2020, the TCC filed a supplement to its objection in which it also objected to the claims filed by FEMA. On February 5, 2020, PG&E Corporation and the Utility joined in the TCC's objection to the OES and FEMA claims. On February 12, 2020, a number of individuals and businesses who hold wildfire-related claims in connection with the 2015 Butte fire, 2017 Northern California wildfires and 2018 Camp fire, as well as certain of the Tubbs Preference Plaintiffs, joined in the TCC’s objection to the OES and FEMA claims. Also on February 12, 2020, OES and FEMA filed oppositions to the TCC’s objection. A hearing on the objection is scheduled for February 26, 2020. As described in Note 2, on July 1, 2019, the Bankruptcy Court entered an order approving the Bar Date of October 21, 2019, at 5:00 p.m. (Pacific Time) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date, including claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires. On November 11, 2019, the Bankruptcy Court entered an order approving a stipulation between PG&E Corporation and the Utility and the TCC to extend the Bar Date for unfiled, non-governmental fire claimants to December 31, 2019, at 5:00 p.m. (Pacific Time). See “Potential Claims” in Note 2 above. Regardless of any determinations of cause by Cal Fire with respect to any pre-petition fire, ultimately PG&E Corporation’s and the Utility’s liability will be determined through the Chapter 11 process (including the settlement agreements described below), regulatory proceedings and any potential enforcement proceedings. The timing and outcome of these and other potential proceedings are uncertain. As discussed under the headings “Plan Support Agreements with Public Entities,” “Restructuring Support Agreement with Holders of Subrogation Claims” and “Restructuring Support Agreement with the TCC,” PG&E Corporation and the Utility have entered into agreements with certain government entity claimholders, certain insurance subrogation claimholders, and the TCC and the Consenting Fire Claimant Professionals, which agreements would potentially resolve all wildfire-related claims arising from the 2017 Northern California wildfires and the 2018 Camp fire. The resolution of claims asserted by certain federal and California government entities that are not Supporting Public Entities is contemplated by the TCC RSA, however, no government entity is a party to the TCC RSA, and accordingly there can be no assurance that such government entities will support the Proposed Plan or the treatment of their claims in the Chapter 11 cases as provided by the Proposed Plan. Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims (the “Tubbs Trial”) In connection with the TCC RSA, on December 26, 2019, the San Francisco Superior Court entered an order vacating all dates and deadlines in the Tubbs Trial and scheduled a hearing for March 2, 2020 to show cause regarding dismissal of the Tubbs Trial. On January 6, 2020, in accordance with the terms of the TCC RSA, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into settlement agreements settling and liquidating the claims asserted against PG&E Corporation and the Utility by each of the Tubbs preference plaintiffs. On January 30, 2020, the Bankruptcy Court issued an order granting PG&E Corporation and the Utility’s motion to enter into settlement agreements with each of the Tubbs preference plaintiffs. Wildfire Claims Estimation Proceeding in the U.S. District Court for the Northern District of California (the “Estimation Proceeding”) On July 18, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for certain claims arising out of the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. On August 21, 2019, the Bankruptcy Court issued recommendations to the District Court recommending the District Court order the partial withdrawal of the reference of the section 502(c) estimation of unliquidated claims arising from the 2018 Camp fire and the 2017 Northern California wildfires. On August 23, 2019, the District Court issued an order adopting the recommendation of the Bankruptcy Court in full and ordering that the reference to the Bankruptcy Court be withdrawn in part. On October 9, 2019, the District Court issued an initial order for the estimation hearings to begin on February 18, 2020 and conclude on February 28, 2020, with the possibility of an additional week of hearings if warranted. In connection with the TCC RSA, on December 20, 2019, the District Court entered an order staying the Estimation Proceeding and vacating the February 18, 2020 hearing and all pre-hearing dates. Plan Support Agreements with Public Entities On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to the Proposed Plan in order to settle such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”). PG&E Corporation and the Utility have entered into a PSA with each of the following public entities or groups of public entities, as applicable: • the City of Clearlake, the City of Napa, the City of Santa Rosa, the County of Lake, the Lake County Sanitation District, the County of Mendocino, Napa County, the County of Nevada, the County of Sonoma, the Sonoma County Agricultural Preservation and Open Space District, the Sonoma County Community Development Commission, the Sonoma County Water Agency, the Sonoma Valley County Sanitation District and the County of Yuba (collectively, the “2017 Northern California Wildfire Public Entities”); • the Town of Paradise; • the County of Butte; • the Paradise Recreation & Park District; • the County of Yuba; and • the Calaveras County Water District. For purposes of each PSA, the local public entities that are party to such PSA are referred to herein as “Supporting Public Entities.” Each PSA provides that the Proposed Plan will include, among other things, the following elements: • following the effective date of the Proposed Plan, PG&E Corporation and the Utility will remit a Settlement Amount (as defined below) in the amount set forth below to the applicable Supporting Public Entities in full and final satisfaction and discharge of their Public Entity Wildfire Claims, and • subject to the Supporting Public Entities voting affirmatively to accept the Proposed Plan, following the effective date of the Proposed Plan, PG&E Corporation and the Utility will create and promptly fund $10.0 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”). The “Settlement Amount” set forth in each PSA is as follows: • for the 2017 Northern California Wildfire Public Entities, $415.0 million (which amount will be allocated among such entities), • for the Town of Paradise, $270.0 million, • for the County of Butte, $252.0 million, • for the Paradise Recreation & Park District, $47.5 million, • for the County of Yuba, $12.5 million, and • for the Calaveras County Water District, $3.0 million. Each PSA provides that, subject to certain terms and conditions, the Supporting Public Entities will support the Proposed Plan with respect to its treatment of their respective Public Entity Wildfire Claims, including by voting to accept the Proposed Plan in the Chapter 11 Cases. Each PSA may be terminated by the applicable Supporting Public Entities under certain circumstances, including: • if the Federal Emergency Management Agency or the OES fails to agree that no reimbursement is required from the Supporting Public Entities on account of assistance rendered by either agency in connection with the wildfires noted above, and • by any individual Supporting Public Entity, if a material amount of Third Party Claims is filed against such Supporting Public Entity and such Third Party Claims are not released pursuant to the Proposed Plan. Each PSA may be terminated by PG&E Corporation and the Utility under certain circumstances, including if: • PG&E Corporation and the Utility do not obtain the consent, or the waiver of the lack of consent as a defense, of their insurance carriers for the policy years 2017 and 2018, • the Board of Directors of either PG&E Corporation or the Utility determines in good faith that continued performance under the PSA would be inconsistent with the exercise of its fiduciary duties, and • any Supporting Public Entity terminates a PSA, in which case PG&E Corporation and the Utility may terminate any other PSA. Restructuring Support Agreement with Holders of Subrogation Claims On September 22, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with the Consenting Subrogation Creditors of insurance subrogation claims, which agreement was amended and restated on November 1, 2019 and subsequently further amended during November and December 2019 (as amended, the “Subrogation RSA”). The Subrogation RSA provides for an aggregate amount of $11.0 billion (the “Aggregate Subrogation Recovery”) to be paid by PG&E Corporation and the Utility pursuant to the Proposed Plan in order to settle the Subrogation Claims, upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility have also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA. The Subrogation RSA provides that, subject to certain terms and conditions (including that PG&E Corporation and the Utility remain solvent), the Consenting Subrogation Creditors will support the Proposed Plan with respect to its treatment of the Subrogation Claims, including by voting their Subrogation Claims to accept the Proposed Plan in the Chapter 11 Cases. On September 24, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the Subrogation RSA and approving the terms of the settlement contemplated under the Subrogation RSA. On December 19, 2019, the Bankruptcy Court entered an order granting PG&E Corporation’s and the Utility’s motion to approve the Subrogation RSA. On December 31, 2019, the Ad Hoc Noteholder Committee filed a motion with the Bankruptcy Court to vacate the Bankruptcy Court’s order approving the Subrogation RSA in its entirety or, in the alternative, vacate the Bankruptcy Court’s order approving the Subrogation RSA and condition approval of the Subrogation RSA on removal of certain provisions contained therein. Pursuant to the Noteholder RSA, the Ad Hoc Noteholder Committee withdrew its motion on February 5, 2020. The Subrogation RSA will automatically terminate if (i) the Proposed Plan is not confirmed by June 30, 2020 (or such later date as may be authorized by any amendment to AB 1054) or (ii) the Effective Date does not occur prior to December 31, 2020 (or six months following the deadline for confirmation of the Proposed Plan if such deadline is extended by any amendment to AB 1054). The Subrogation RSA may be terminated by any Consenting Subrogation Creditor as to itself if the Aggregate Subrogation Recovery is modified. The Subrogation RSA may be terminated by the Consenting Subrogation Creditors holding at least two-thirds of the Subrogation Claims held by Consenting Subrogation Creditors under certain circumstances, including, among others, if (i) they reasonably determine in good faith at any time prior to confirmation of the Proposed Plan that PG&E Corporation and the Utility are insolvent or otherwise unable to raise sufficient capital to pay the Aggregate Subrogation Recovery on the Effective Date, (ii) PG&E Corporation and the Utility breach the terms of the Subrogation RSA or otherwise fail to take certain actions specified in the Subrogation RSA, (iii) the Proposed Plan does not treat the individual plaintiffs’ wildfire-related claims consistent with the provisions of AB 1054, (iv) the Bankruptcy Court allows a plan proponent other than PG&E Corporation and the Utility to commence soliciting votes on a plan (other than the Proposed Plan) that incorporates the terms of the settlement contemplated by the Subrogation RSA and PG&E Corporation and the Utility have not already commenced soliciting votes on the Proposed Plan which incorporates such settlement, (v) the Bankruptcy Court confirms a plan other than the Proposed Plan or (vi) the Proposed Plan is modified to be inconsistent with such settlement. The Subrogation RSA may be terminated by PG&E Corporation and the Utility (a) in the event of certain breaches of the Subrogation RSA by Consenting Subrogation Creditors holding at least 5% of the Subrogation Claims held by Consenting Subrogation Creditors or (b) if the Bankruptcy Court confirms a plan other than the Proposed Plan or if the terms of the Proposed Plan related to the settlement contemplated by the Subrogation RSA become unenforceable or are enjoined. Subject to certain limited exceptions, the valuation of the Subrogation Claims in an aggregate amount of $11.0 billion (the “Allowed Subrogation Claim Amount”) will survive any termination of the Subrogation RSA and will be binding on PG&E Corporation and the Utility in the Chapter 11 Cases. Restructuring Support Agreement with the TCC On December 6, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement, which was subsequently amended on December 16, 2019, with the TCC, the Consenting Fire Claimant Professionals and the Sha |
SCHEDULE I _ CONDENSED FINANCIA
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT | 12 Months Ended |
Dec. 31, 2019 | |
Condensed Financial Information Disclosure [Abstract] | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT | PG&E CORPORATION (DEBTOR-IN-POSSESSION) SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME Years Ended December 31, (in millions, except per share amounts) 2019 2018 2017 Administrative service revenue $ 138 $ 90 $ 63 Operating expenses (114) (91) (5) Interest income 1 2 1 Interest expense (21) (15) (11) Other income (expense) 10 (2) 4 Reorganization items, net (26) — — Equity in earnings of subsidiaries (7,622) (6,832) 1,667 Income before income taxes (7,634) (6,848) 1,719 Income tax provision (benefit) 8 3 73 Net income (loss) $ (7,642) $ (6,851) $ 1,646 Other Comprehensive Income (Loss) Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, and $0, at respective dates) $ (1) $ 4 $ 1 Total other comprehensive income (loss) (1) 4 1 Comprehensive Income (Loss) $ (7,643) $ (6,847) $ 1,647 Weighted Average Common Shares Outstanding, Basic 528 517 512 Weighted Average Common Shares Outstanding, Diluted 528 513 513 Net earnings (loss) per common share, basic $ (14.50) $ (13.25) $ 3.21 Net earnings (loss) per common share, diluted $ (14.50) $ (13.25) $ 3.21 PG&E CORPORATION (DEBTOR-IN-POSSESSION) SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED BALANCE SHEETS Balance at December 31, (in millions) 2019 2018 ASSETS Current Assets Cash and cash equivalents $ 448 $ 373 Advances to affiliates 120 44 Income taxes receivable 12 18 Other current assets 11 — Total current assets 591 435 Noncurrent Assets Equipment 2 2 Accumulated depreciation (2) (2) Net equipment — — Investments in subsidiaries 5,102 12,722 Other investments 173 162 Intercompany receivable — — Operating lease right of use asset 6 — Deferred income taxes 187 187 Total noncurrent assets 5,468 13,071 Total Assets $ 6,059 $ 13,506 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Short-term borrowings — 300 Long-term debt, classified as current — 350 Accounts payable – other 47 16 Operating lease liabilities 3 — Other current liabilities 3 17 Total current liabilities 53 683 Noncurrent Liabilities Debtor-in-possession financing — — Operating lease liabilities 3 — Other noncurrent liabilities 58 172 Total noncurrent liabilities 61 172 Liabilities Subject to Compromise 810 — Common Shareholders’ Equity Common stock 13,038 12,910 Reinvested earnings (7,893) (250) Accumulated other comprehensive income (loss) (10) (9) Total common shareholders’ equity 5,135 12,651 Total Liabilities and Shareholders’ Equity $ 6,059 $ 13,506 PG&E CORPORATION (DEBTOR-IN-POSSESSION) SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED STATEMENTS OF CASH FLOWS (in millions) Year ended December 31, 2019 2018 2017 Cash Flows from Operating Activities: Net income (loss) $ (7,642) $ (6,851) $ 1,646 Adjustments to reconcile net income to net cash provided by operating activities: Stock-based compensation amortization 43 78 20 Equity in earnings of subsidiaries 7,622 6,833 (1,667) Deferred income taxes and tax credits-net — (62) 139 Reorganization items, net (Note 2) 11 — — Current income taxes receivable/payable 6 9 (2) Liabilities subject to compromise 28 — — Other (62) 41 (75) Net cash provided by operating activities 6 48 61 Cash Flows From Investing Activities: Investment in subsidiaries — (45) (455) Dividends received from subsidiaries (1) — — 784 Net cash provided by (used in) investing activities — (45) 329 Cash Flows From Financing Activities: Debtor-in-possession credit facility debt issuance costs (16) — — Borrowings under revolving credit facility — 425 — Repayments under revolving credit facility — (125) — Net issuances (repayments) of commercial paper, net of discount of $1 in 2017 — (132) 132 Short-term debt financing — 350 — Long-term debt matured or repurchased — (350) — Common stock issued 85 200 395 Common stock dividends paid (2) — — (1,021) Net cash provided by (used in) financing activities 69 368 (494) Net change in cash and cash equivalents 75 371 (104) Cash and cash equivalents at January 1 373 2 106 Cash and cash equivalents at December 31 $ 448 $ 373 $ 2 Supplemental disclosures of cash flow information Cash received (paid) for: Interest, net of amounts capitalized $ (3) $ (13) $ (9) Income taxes, net — 10 — Supplemental disclosures of noncash investing and financing activities Common stock dividends declared but not yet paid $ — $ — $ — Noncash common stock issuances — — 21 Operating lease liabilities arising from obtaining ROU assets 9 — — (1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. On December 20, 2017, the Board of Directors of the Utility suspended quarterly cash dividends on the Utility's common stock, beginning the fourth quarter of 2017. (2) On December 20, 2017, the Board of Directors of PG&E Corporation suspended quarterly cash dividends on PG&E Corporation's common stock, beginning the fourth quarter of 2017. In July and October of 2017, respectively, PG&E Corporation paid quarterly common stock dividends of $0.53 per share. In January and April of 2017, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share. |
SCHEDULE II _ CONSOLIDATED VALU
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS | 12 Months Ended |
Dec. 31, 2019 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS | (DEBTOR-IN-POSSESSION) SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2019, 2018, and 2017 (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: 2019: Allowance for uncollectible accounts (1) $ 56 $ — $ — $ 13 $ 43 2018: Allowance for uncollectible accounts (1) $ 64 $ 34 $ — $ 42 $ 56 2017: Allowance for uncollectible accounts (1) $ 58 $ 55 $ — $ 49 $ 64 (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 (DEBTOR-IN-POSSESSION) SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2019, 2018, and 2017 (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: 2019: Allowance for uncollectible accounts (1) $ 56 $ — $ — $ 13 $ 43 2018: Allowance for uncollectible accounts (1) $ 64 $ 34 $ — $ 42 $ 56 2017: Allowance for uncollectible accounts (1) $ 58 $ 55 $ — $ 49 $ 64 (1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.” (2) Deductions consist principally of write-offs, net of collections of receivables previously written off. |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Basis of Presentation | 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. The 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). |
Use of Estimates and Assumptions | 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 wildfire-related liabilities, legal and regulatory contingencies, environmental remediation liabilities, insurance receivables, regulatory assets and liabilities, AROs, pension and other postretirement benefit plans obligations, and the valuation of LSTC. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred. |
Loss Contingencies | Loss Contingencies A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. |
Regulation and Regulated Operations | Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The 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 capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities. The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the 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 and 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 Revenue from Contracts with Customers 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. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. Regulatory Balancing Account Revenue 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. The Utility's ability to recover revenue requirements authorized by the CPUC in these rate cases is independent or “decoupled” from the volume of the Utility's sales of electricity and natural 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, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. 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 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. As a result, these differences have no impact on net income. |
Cash and Cash Equivalents | Cash and Cash EquivalentsCash 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. |
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 expensed 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 historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows: Estimated Useful Balance at December 31, (in millions, except estimated useful lives) Lives (years) 2019 2018 Electricity generating facilities (1) 10 to 75 $ 13,189 $ 13,047 Electricity distribution facilities 10 to 65 35,237 32,926 Electricity transmission facilities 15 to 75 14,281 13,177 Natural gas distribution facilities 20 to 60 14,236 13,296 Natural gas transmission and storage facilities 5 to 66 8,452 8,260 Construction work in progress 2,675 2,564 Other 18 — Total property, plant, and equipment 88,088 83,270 Accumulated depreciation (26,453) (24,713) Net property, plant, and equipment $ 61,635 $ 58,557 (1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.) The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.80% in 2019, 3.82% in 2018, and 3.83% in 2017. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred. |
AFUDC | AFUDCAFUDC 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. |
Asset Retirement Obligations | 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 Decommissioning Cost Triennial Proceeding conducted by the CPUC. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. 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 total nuclear decommissioning obligation accrued was $4.9 billion and $4.7 billion at December 31, 2019 and 2018, respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion at December 31, 2019 and 2018. |
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 15 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 Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC. The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification. |
Variable Interest Entities | Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is 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 generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2019, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2019, it did not consolidate any of them. |
Recently Adopted Accounting Guidance and Accounting Standards Issued But Not Yet Adopted | Recently Adopted Accounting Standards Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which amended the guidance related to the definition of a lease, the recognition of lease assets and liabilities, and the disclosure of key information about leasing arrangements. Under the new standard, a lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility adopted the ASU for leases on January 1, 2019. PG&E Corporation and the Utility elected certain practical expedients and will carry forward historical conclusions related to (1) contracts that contain leases, (2) existing lease and easement classification, and (3) initial direct costs. After adoption of the new standard, PG&E Corporation and Utility elected not to separate lease and non-lease components. Additionally, PG&E Corporation and the Utility will not restate comparative reporting periods. The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates, unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking. Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the year ended December 31, 2019. On January 1, 2019, PG&E Corporation and the Utility recorded ROU assets and lease liabilities of $2.8 billion, representing the net present value of only the fixed lease payments. This amount is presented within the supplemental disclosures of noncash activities. For the year ended December 31, 2019, the Utility made total cash payments, including fixed and variable, of $2.4 billion for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows. The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements. At December 31, 2019, the Utility’s leases had a weighted average remaining lease term of 5.9 years and a weighted average discount rate of 6.2%. The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations: (in millions) Year Ended December 31, 2019 Operating lease fixed cost $ 686 Operating lease variable cost 1,778 Total operating lease costs $ 2,464 The following table shows the Utility’s future expected operating lease payments: (in millions) December 31, 2019 2020 $ 679 2021 623 2022 548 2023 255 2024 96 Thereafter 596 Total lease payments 2,797 Less imputed interest (518) Total $ 2,279 The following table shows the Utility’s future expected obligations for power purchase and other lease commitments: (in millions) December 31, 2018 2019 $ 684 2020 677 2021 621 2022 546 2023 252 Thereafter 581 Total lease commitments $ 3,361 Fair Value Measurement In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurements , which amends the existing guidance relating to the disclosure requirements for fair value measurements. PG&E Corporation and the Utility early adopted the ASU as of December 31, 2019. The adoption of this ASU did not have a material impact on the Consolidated Financial Statements and related disclosures. Accounting Standards Issued But Not Yet Adopted Intangibles-Goodwill and Other In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract . This ASU became effective for PG&E Corporation and the Utility on January 1, 2020 and did not have a material impact on the Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. This ASU became effective for PG&E Corporation and the Utility on January 1, 2020 and did not have a material impact on the Consolidated Financial Statements and related disclosures. |
Earnings Per Share | PG&E Corporation’s basic EPS is calculated by dividing the income (loss) 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. |
Fair Value Measurement | PG&E Corporation and the Utility measure their cash equivalents, 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 fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. |
BANKRUPTCY FILING (Tables)
BANKRUPTCY FILING (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Reorganizations [Abstract] | |
Schedule Of Liabilities Subject To Compromise | The following table presents LSTC as reported in the Consolidated Balance Sheets at December 31, 2019: (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Financing debt (2) $ 22,450 $ 666 $ 23,116 Wildfire-related claims (3) 25,548 — 25,548 Trade creditors 1,183 5 1,188 Non-qualified benefit plan 20 137 157 2001 bankruptcy disputed claims (4) 234 — 234 Customer deposits & advances 71 — 71 Other 230 2 232 Total Liabilities Subject to Compromise $ 49,736 $ 810 $ 50,546 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) At December 31, 2019, PG&E Corporation and the Utility had $650 million and $21,526 million in aggregate principal amount of pre-petition indebtedness, respectively. Pre-petition financing debt includes accrued contractual interest of $1 million and $286 million for PG&E Corporation and the Utility, respectively, to the Petition Date. Financing debt also includes post-petition interest of $15 million and $638 million for PG&E Corporation and the Utility, respectively, in accordance with the terms of the Noteholder RSA. See Note 5 for details of pre-petition debt reported as LSTC. (3) See “Pre-petition Wildfire-related claims” in Note 14 for information regarding pre-petition wildfire-related claims reported as LSTC. (4) 2001 bankruptcy disputed claims includes $14 million of interest recorded at the interest rate specified by FERC in accordance with S35.19a of the Commission’s regulations. |
Schedule Of Debtor Reorganization Items | Reorganization items, net from the Petition Date through December 31, 2019 include the following: Petition Date Through December 31, 2019 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ 97 $ 17 $ 114 Legal and other 273 19 292 Interest income (50) (10) (60) Adjustments to LSTC — — — Total reorganization items, net $ 320 $ 26 $ 346 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Summary of Revenues Disaggregated by Type of Customer | The following table presents the Utility’s revenues disaggregated by type of customer: Year Ended (in millions) 2019 2018 Electric Revenue from contracts with customers Residential $ 4,847 $ 5,051 Commercial 4,756 4,908 Industrial 1,493 1,532 Agricultural 1,106 1,234 Public street and highway lighting 67 72 Other (1) 168 (720) Total revenue from contracts with customers - electric 12,437 12,077 Regulatory balancing accounts (2) 303 636 Total electric operating revenue $ 12,740 $ 12,713 Natural gas Revenue from contracts with customers Residential $ 2,325 $ 2,042 Commercial 605 537 Transportation service only 1,249 1,151 Other (1) 123 75 Total revenue from contracts with customers - gas 4,302 3,805 Regulatory balancing accounts (2) 87 242 Total natural gas operating revenue 4,389 4,047 Total operating revenues $ 17,129 $ 16,760 (1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. |
Schedule of Estimated Useful Lives and Balances of Utility's Property, Plant and Equipment | 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) 2019 2018 Electricity generating facilities (1) 10 to 75 $ 13,189 $ 13,047 Electricity distribution facilities 10 to 65 35,237 32,926 Electricity transmission facilities 15 to 75 14,281 13,177 Natural gas distribution facilities 20 to 60 14,236 13,296 Natural gas transmission and storage facilities 5 to 66 8,452 8,260 Construction work in progress 2,675 2,564 Other 18 — Total property, plant, and equipment 88,088 83,270 Accumulated depreciation (26,453) (24,713) Net property, plant, and equipment $ 61,635 $ 58,557 (1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.) |
Schedule of Changes in Asset Retirement Obligations | The following table summarizes the changes in ARO liability during 2019 and 2018, including nuclear decommissioning obligations: (in millions) 2019 2018 ARO liability at beginning of year $ 5,994 $ 4,899 Revision in estimated cash flows (376) 993 Accretion 274 211 Liabilities settled (38) (109) ARO liability at end of year $ 5,854 $ 5,994 |
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, 2019 consisted of the following: (in millions, net of income tax) Pension Other Total Beginning balance $ (21) $ 17 $ (4) Other comprehensive income before reclassifications: Unrecognized net actuarial loss (net of taxes of $24 and $88, respectively) 61 227 288 Regulatory account transfer (net of taxes of $24 and $88, respectively) (62) (227) (289) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1) (4) 10 6 Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1) 2 (2) — Regulatory account transfer (net of taxes of $1 and $3, respectively) (1) 2 (8) (6) Net current period other comprehensive loss (1) — (1) Ending balance $ (22) $ 17 $ (5) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 12 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, 2018 consisted of the following: (in millions, net of income tax) Pension Other Total Beginning balance $ (25) $ 17 $ (8) Other comprehensive income before reclassifications: Unrecognized net actuarial loss (net of taxes of $41 and $9, respectively) (104) (23) (127) Regulatory account transfer (net of taxes of $41 and $9, respectively) 107 23 130 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1) (4) 10 6 Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) (1) 3 (4) (1) Regulatory account transfer (net of taxes of $1 and $3, respectively) (1) 2 (6) (4) Net current period other comprehensive loss 4 — 4 Ending balance $ (21) $ 17 $ (4) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 12 below for additional details.) |
Schedule of Lease Expense | The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations: (in millions) Year Ended December 31, 2019 Operating lease fixed cost $ 686 Operating lease variable cost 1,778 Total operating lease costs $ 2,464 |
Schedule of Future Expected Operating Lease Payments and Expected Obligations for Power Purchase and Other Lease Commitments | The following table shows the Utility’s future expected operating lease payments: (in millions) December 31, 2019 2020 $ 679 2021 623 2022 548 2023 255 2024 96 Thereafter 596 Total lease payments 2,797 Less imputed interest (518) Total $ 2,279 |
Schedule of Future Minimum Rental Payments for Operating Leases | The following table shows the Utility’s future expected obligations for power purchase and other lease commitments: (in millions) December 31, 2018 2019 $ 684 2020 677 2021 621 2022 546 2023 252 Thereafter 581 Total lease commitments $ 3,361 |
REGULATORY ASSETS, LIABILITIE_2
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Regulated Operations [Abstract] | |
Long-Term Regulatory Assets | Long-term regulatory assets are comprised of the following: Balance at December 31, Recovery (in millions) 2019 2018 Pension benefits (1) $ 1,823 $ 1,947 Indefinitely Environmental compliance costs 1,062 1,013 32 years Utility retained generation (2) 228 274 8 years Price risk management 124 90 10 years Unamortized loss, net of gain, on reacquired debt 63 76 25 years Catastrophic event memorandum account (3) 656 790 1 - 4 years Wildfire expense memorandum account (4) 423 94 1 - 4 years Fire hazard prevention memorandum account (5) 259 263 1 - 4 years Fire risk mitigation memorandum account (6) 95 — 1 - 4 years Wildfire mitigation plan memorandum account (7) 558 — 1 - 4 years Deferred income taxes (8) 252 — 47 years Other (9) 523 417 Various Total long-term regulatory assets $ 6,066 $ 4,964 (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) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. (3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. Recovery of CEMA costs are subject to CPUC review and approval. (4) Includes specific incremental wildfire-related liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are subject to CPUC review and approval. (5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs are subject to CPUC review and approval. (6) Includes costs associated with the 2019 Wildfire Mitigation Plan for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs are subject to CPUC review and approval. (7) Includes costs associated with the 2019 Wildfire Mitigation Plan for the period June 5, 2019 through December 31, 2019. Recovery of WMPMA costs are subject to CPUC review and approval. (8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (See Note 9 below.) (9) December 31, 2019 balance includes $178 million of unamortized debt issuance costs and debt discount that was written off to present the debt subject to compromise at the outstanding face value. |
Long-Term Regulatory Liabilities | Long-term regulatory liabilities are comprised of the following: Balance at December 31, (in millions) 2019 2018 Cost of removal obligations (1) $ 6,456 $ 5,981 Deferred income taxes (2) — 283 Recoveries in excess of AROs (3) 393 356 Public purpose programs (4) 817 674 Retirement plans (5) 750 421 Other 854 824 Total long-term regulatory liabilities $ 9,270 $ 8,539 (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 amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (See Note 9 below.) (3) 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 liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 11 below.) (4) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs. |
Current Regulatory Balancing Accounts Receivable | Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable (in millions) 2019 2018 Electric distribution $ — $ 160 Electric transmission 9 128 Utility generation — 79 Gas distribution and transmission 363 462 Energy procurement 901 168 Public purpose programs 209 111 Other 632 327 Total regulatory balancing accounts receivable $ 2,114 $ 1,435 |
Current Regulatory Balancing Accounts Payable | Payable (in millions) 2019 2018 Electric distribution $ 31 $ — Electric transmission 119 134 Gas distribution and transmission 45 9 Energy procurement 649 59 Public purpose programs 559 587 Other 394 287 Total regulatory balancing accounts payable $ 1,797 $ 1,076 |
DEBT (Tables)
DEBT (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Schedule of Debtor-in-Possession Financing | The following table summarizes the Utility’s outstanding borrowings and availability under the DIP Facilities at December 31, 2019: (in millions) Termination Aggregate Limit Term Loan Borrowings Revolver Borrowings Letters of Credit Outstanding Aggregate DIP Facilities December 2020 (1) $ 5,500 $ 1,500 $ — $ 663 $ 3,337 |
Schedule of Long-term Debt | The following table summarizes PG&E Corporation’s and the Utility’s outstanding debt subject to compromise: December 31, (in millions) Contractual Interest Rates 2019 2018 Treatment under Proposed Plan (1) Debt Subject to Compromise (2) PG&E Corporation Borrowings under Pre-Petition Credit Facility PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 variable rate (3) $ 300 $ 300 Repaid in cash Other borrowings Term Loan - Stated Maturity: 2020 variable rate (4) 350 350 Repaid in cash Total PG&E Corporation Debt Subject to Compromise 650 650 Utility Senior Notes - Stated Maturity: 2020 3.50% 800 800 Exchanged for New Utility Short-Term Notes 2021 3.25% to 4.25% 550 550 Exchanged for New Utility Short-Term Notes 2022 2.45% 400 400 Exchanged for New Utility Short-Term Notes 2023 3.25% to 4.25% 1,175 1,175 Reinstated 2024 through 2028 2.95% to 4.65% 3,850 3,850 Reinstated 2034 through 2040 5.40% to 6.35% 5,700 5,700 Exchanged for New Utility Long-Term Notes 2041 through 2042 3.75% to 4.50% 1,000 1,000 Reinstated 2043 4.60% 375 375 Reinstated 2043 5.13% 500 500 Exchanged for New Utility Long-Term Notes 2044 through 2047 3.95% to 4.75% 3,175 3,175 Reinstated Unamortized discount, net of premium and debt issuance costs — (178) Total Senior notes, net of premium and debt issuance costs 17,525 17,347 Pollution Control Bonds - Stated Maturity: Series 2008 F and 2010 E, due 2026 (5) 1.75% 100 100 Repaid in cash Series 2009 A-B, due 2026 (6) variable rate (7) 149 149 Exchanged for New Utility Funded Debt Exchange Notes Series 1996 C, E, F, 1997 B due 2026 (6) variable rate (8) 614 614 Exchanged for New Utility Funded Debt Exchange Notes Total pollution control bonds 863 863 Borrowings under Pre-Petition Credit Facilities Utility Revolving Credit Facilities - Stated Maturity: 2022 (9) variable rate (10) 2,888 2,965 Exchanged for New Utility Funded Debt Exchange Notes Other borrowings: Term Loan - Stated Maturity: 2019 variable rate (11) 250 250 Exchanged for New Utility Funded Debt Exchange Notes Total Borrowings under Pre-Petition Credit Facility Subject to Compromise 3,138 3,215 Total Utility Debt Subject to Compromise 21,526 21,425 Total PG&E Corporation Consolidated Debt Subject to Compromise $ 22,176 $ 22,075 (1) The treatments of debt under the Proposed Plan, described in this column relate only to the treatment of principal amounts and not pre-petition or post-petition interest. The New Utility Short-Term Notes, New Utility Long-Term Senior Notes and New Utility Funded Debt Exchange Notes are described in more detail under “Restructuring Support Agreement with the Ad Hoc Noteholder Committee” in Note 2. (2) Debt subject to compromise must be reported at the amounts expected to be allowed by the Bankruptcy Court and the carrying values will be adjusted as claims are approved. Total Debt Subject to Compromise does not include accrued contractual interest of $1 million and $286 million for PG&E Corporation and the Utility, respectively, to the Petition Date. Total Debt Subject to Compromise also does not include post-petition interest of $15 million and $638 million for PG&E Corporation and the Utility, respectively, in accordance with the terms of the Noteholder RSA. As of December 31, 2019, PG&E Corporation and the Utility wrote off $178 million of unamortized debt issuance costs and debt discount to present the debt subject to compromise at the outstanding face value. The write-offs are included within long-term regulatory assets in the Consolidated Balance Sheets. See Notes 2 and 4 for further details. (3) At December 31, 2019, the contractual LIBOR-based interest rate on loans was 3.24%. (4) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.96%. (5) Pollution Control Bonds series 2008F and 2010E were reissued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 31, 2022. (6) Each series of these bonds is supported by a separate direct-pay letter of credit. Following the Utility’s Chapter 11 filing, investors in these bonds drew on the letter of credit facilities. The letter of credit facility supporting the Series 2009 A-B bonds matured on June 5, 2019. In December 2015, the maturity dates of the letter of credit facilities supporting the Series 1996 C, E, F, 1997 B bonds were extended to December 1, 2020. Although the stated maturity date of these bonds 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. (7) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 7.95%. (8) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 7.95% to 8.08%. (9) At December 31, 2019, excludes $22 million of undrawn letters of credit. (10) At December 31, 2019, the contractual LIBOR-based interest rate on the loans was 3.04%. (11) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.36%. |
Schedule of Contractual Repayment Schedule | Contractual Repayment Schedule PG&E Corporation and the Utility have entered into the Noteholder RSA with Consenting Noteholders which provides for, among other things, (i) the refinancing of the Utility’s senior unsecured debt in satisfaction of all claims arising out of the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt, and (ii) the reinstatement of the Utility Reinstated Senior Notes, in each case pursuant to the Proposed Plan and upon the terms and conditions set forth in the Noteholder RSA. See “Restructuring Support Agreement with the Ad Hoc Noteholder Committee” in Note 2 for further information on the Noteholder RSA. PG&E Corporation’s and the Utility’s existing long-term debt is in default, and the Accelerated Direct Financial Obligations became immediately due and payable upon the commencement of the Chapter 11 Cases. PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2019 are reflected in the table below: (in millions, except interest rates) 2020 2021 2022 2023 2024 Thereafter Total PG&E Corporation Variable interest rate as of December 31, 2019 2.96 % — % 3.24 % — % — % — % 2.96 % Variable rate obligations $ 350 $ — $ 300 $ — $ — $ — $ 650 Utility Average fixed interest rate 3.50 % 3.80 % 2.31 % 3.83 % 3.60 % 4.80 % 4.52 % Fixed rate obligations $ 800 $ 550 $ 500 $ 1,175 $ 800 $ 13,800 $ 17,625 Variable interest rate as of December 31, 2019 various (1) — % 3.04 % — % — % — % 8.00 % Variable rate obligations $ 1,013 $ — $ 2,888 $ — $ — $ — $ 3,901 Total consolidated debt $ 2,163 $ 550 $ 3,688 $ 1,175 $ 800 $ 13,800 $ 22,176 (1) At December 31, 2019, the average interest rates for the pollution control bonds and the term loan were 8.00% and 2.36%, respectively. |
COMMON STOCK AND SHARE-BASED _2
COMMON STOCK AND SHARE-BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Common Stock And Share-Based Compensation [Abstract] | |
Schedule of Compensation Expense for Share-based Incentive Awards | The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2019: (in millions) 2019 2018 2017 Stock Options $ 7 $ 10 $ — Restricted stock units 21 43 40 Performance shares 22 36 45 Total compensation expense (pre-tax) $ 50 $ 89 $ 85 Total compensation expense (after-tax) $ 35 $ 63 $ 50 |
Summary of Significant Assumptions Used for Shares Granted | The significant assumptions used for shares granted in 2019 were: 2019 2018 Expected stock price volatility 57.00 % 23.00 % Expected annual dividend payment — % 3.10 % Risk-free interest rate 1.51% to 1.52% 2.58 % Expected life (years) 4.5 6 |
Summary of Stock Option Activity | The following table summarizes stock option activity for PG&E Corporation and the Utility for 2019: Number of Weighted Average Grant- Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1 1,522,137 $ 10.24 $ — Granted 2,866,667 3.87 — Exercised — — — Forfeited or expired (107,401) 10.24 — Outstanding at December 31 4,281,403 5.98 5.40 years — Vested or expected to vest at December 31 4,225,180 5.92 5.36 years — Exercisable at December 31 1,433,234 $ 5.99 5.41 years $ — |
Schedule of Restricted Stock Units | The following table summarizes restricted stock unit activity for 2019: Number of Weighted Average Grant- Nonvested at January 1 1,979,812 $ 47.66 Granted 74,479 18.57 Vested (822,249) 51.01 Forfeited (191,207) 41.49 Nonvested at December 31 1,040,835 $ 44.06 |
Schedule of Performance Shares | The following table summarizes activity for performance shares in 2019: Number of Weighted Average Grant- Nonvested at January 1 1,438,091 $ 56.32 Granted 130,251 15.39 Vested (255,324) 40.74 Forfeited (1) (624,595) 75.54 Nonvested at December 31 688,423 $ 36.92 (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, 2019 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2019, 2018, and 2017. Year Ended December 31, (in millions, except per share amounts) 2019 2018 2017 Income (loss) available for common shareholders $ (7,656) $ (6,851) $ 1,646 Weighted average common shares outstanding, basic 528 517 512 Add incremental shares from assumed conversions: Employee share-based compensation — — 1 Weighted average common share outstanding, diluted 528 517 513 Total earnings (loss) per common share, diluted $ (14.50) $ (13.25) $ 3.21 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | The significant components of income tax provision (benefit) by taxing jurisdiction were as follows: PG&E Corporation Utility Year Ended December 31, (in millions) 2019 2018 2017 2019 2018 2017 Current: Federal $ 1 $ (5) $ (10) $ 4 $ 5 $ 61 State 101 (8) 48 94 (7) 50 Deferred: Federal (2,361) (2,264) 481 (2,363) (2,278) 326 State (1,136) (1,009) 6 (1,137) (1,009) 4 Tax credits (5) (6) (14) (5) (6) (14) Income tax provision (benefit) $ (3,400) $ (3,292) $ 511 $ (3,407) $ (3,295) $ 427 |
Schedule of Deferred Tax Assets and Liabilities | The following tables describe net deferred income tax assets and liabilities: PG&E Corporation Utility Year Ended December 31, (in millions) 2019 2018 2019 2018 Deferred income tax assets: Tax carryforwards $ 1,390 $ 740 $ 1,308 $ 650 Compensation 151 173 92 121 Income tax regulatory liability (1) — 79 — 79 Wildfire-related claims (2) 6,520 3,433 6,520 3,433 Operating lease liability 642 — 640 — Other (3) 112 87 121 93 Total deferred income tax assets $ 8,815 $ 4,512 $ 8,681 $ 4,376 Deferred income tax liabilities: Property related basis differences 7,984 7,672 7,973 7,660 Regulatory balancing accounts 381 118 381 118 Operating lease right of use asset 642 — 640 — Income tax regulatory asset (1) 71 — 71 — Other (4) 57 3 58 3 Total deferred income tax liabilities $ 9,135 $ 7,793 $ 9,123 $ 7,781 Total net deferred income tax liabilities $ 320 $ 3,281 $ 442 $ 3,405 (1) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. (For more information see Note 3 above). (2) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to the 2018 Camp fire, 2017 Northern California wildfires, and the 2015 Butte fire. (3) Amounts include benefits, environmental reserve, and customer advances for construction. |
Schedule of Effective Income Tax Rate Reconciliation | 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, 2019 2018 2017 2019 2018 2017 Federal statutory income tax rate 21.0 % 21.0 % 35.0 % 21.0 % 21.0 % 35.0 % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) 7.5 7.9 1.5 7.5 7.9 1.6 Effect of regulatory treatment of fixed asset differences (2) 2.8 3.6 (16.5) 2.8 3.6 (16.8) Tax credits 0.1 0.1 (1.1) 0.1 0.1 (1.1) Compensation related (3) — (0.2) (1.0) — (0.1) (0.9) Tax Reform adjustment (4) — 0.1 6.8 — 0.1 3.0 Other, net (5) (0.6) — (1.1) (0.5) — (0.7) Effective tax rate 30.8 % 32.5 % 23.6 % 30.9 % 32.6 % 20.1 % (1) Includes the effect of state flow-through ratemaking treatment. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. 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 Utility’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 customers in future rates. In 2019 and 2018, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017. (3) Primarily represents adjustments to compensation as a result of the enactment of the Tax Act. (4) Represents adjustments to deferred tax balances under Staff Accounting Bulletin No. 118 reflecting the tax rate reduction required by the Tax Act. (5) These amounts primarily represent the impact of non-tax deductible bankruptcy costs in 2019 and tax audit settlements in 2017. |
Schedule of Change in Unrecognized Tax Benefits | The following table reconciles the changes in unrecognized tax benefits: PG&E Corporation Utility (in millions) 2019 2018 2017 2019 2018 2017 Balance at beginning of year $ 377 $ 349 $ 388 $ 377 $ 349 $ 382 Reductions for tax position taken during a prior year (1) (27) (71) (1) (27) (71) Additions for tax position taken during the current year 44 55 48 44 55 48 Settlements — — (14) — — (8) Expiration of statute — — (3) — — (3) Balance at end of year $ 420 $ 377 $ 349 $ 420 $ 377 $ 349 |
Schedule of Operating Loss and Tax Credit Carryforward Balances | The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances: (in millions) December 31, 2019 Expiration Federal: Net operating loss carryforward - Pre-2018 $ 3,940 2031 - 2036 Net operating loss carryforward - Post-2017 1,777 N/A Tax credit carryforward 127 2029 - 2039 State: Net operating loss carryforward $ 1,927 N/A Tax credit carryforward 96 Various |
DERIVATIVES (Tables)
DERIVATIVES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Volumes of Outstanding Derivative Contracts | he volumes of the Utility’s outstanding derivatives were as follows: Contract Volume At December 31, Underlying Product Instruments 2019 2018 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 131,896,159 177,750,349 Options 14,720,000 13,735,405 Electricity (Megawatt-hours) Forwards and Swaps 18,675,852 3,833,490 Congestion Revenue Rights (3) 308,467,999 340,783,089 (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. |
Outstanding Derivative Balances | At December 31, 2019, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 36 $ (6) $ 4 $ 34 Other noncurrent assets – other 130 (6) — 124 Current liabilities – other (31) 6 2 (23) Noncurrent liabilities – other (130) 6 — (124) Total commodity risk $ 5 $ — $ 6 $ 11 At December 31, 2018, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 44 $ (1) $ 89 $ 132 Other noncurrent assets – other 165 — — 165 Current liabilities – other (29) 1 7 (21) Noncurrent liabilities – other (90) — 2 (88) Total commodity risk $ 90 $ — $ 98 $ 188 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements At December 31, 2019 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 1,323 $ — $ — $ — $ 1,323 Nuclear decommissioning trusts Short-term investments 6 — — — 6 Global equity securities 2,086 — — — 2,086 Fixed-income securities 862 728 — — 1,590 Assets measured at NAV — — — — 21 Total nuclear decommissioning trusts (2) 2,954 728 — — 3,703 Price risk management instruments (Note 10) Electricity — 2 161 (11) 152 Gas — 3 — 3 6 Total price risk management instruments — 5 161 (8) 158 Rabbi trusts Fixed-income securities — 100 — — 100 Life insurance contracts — 73 — — 73 Total rabbi trusts — 173 — — 173 Long-term disability trust Short-term investments 10 — — — 10 Assets measured at NAV — — — — 156 Total long-term disability trust 10 — — — 166 TOTAL ASSETS $ 4,287 $ 906 $ 161 $ (8) $ 5,523 Liabilities: Price risk management instruments (Note 10) Electricity $ 1 $ 2 $ 156 $ (13) $ 146 Gas — 2 — (1) 1 TOTAL LIABILITIES $ 1 $ 4 $ 156 $ (14) $ 147 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $530 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2018 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 1,593 $ — $ — $ — $ 1,593 Nuclear decommissioning trusts Short-term investments 29 — — — 29 Global equity securities 1,793 — — — 1,793 Fixed-income securities 661 639 — — 1,300 Assets measured at NAV — — — — 16 Total nuclear decommissioning trusts (2) 2,483 639 — — 3,138 Price risk management instruments (Note 10) Electricity — 5 203 51 259 Gas — 1 — 37 38 Total price risk management instruments — 6 203 88 297 Rabbi trusts Fixed-income securities — 93 — — 93 Life insurance contracts — 67 — — 67 Total rabbi trusts — 160 — — 160 Long-term disability trust Short-term investments 7 — — — 7 Assets measured at NAV — — — — 155 Total long-term disability trust 7 — — — 162 TOTAL ASSETS $ 4,083 $ 805 $ 203 $ 88 $ 5,350 Liabilities: Price risk management instruments (Note 10) Electricity 4 5 108 (10) 107 Gas — 2 — — 2 TOTAL LIABILITIES $ 4 $ 7 $ 108 $ (10) $ 109 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $408 million, primarily related to deferred taxes on appreciation of investment value. |
Uncertainty Analysis | Fair Value at (in millions) At December 31, 2019 Valuation Unobservable Fair Value Measurement Assets Liabilities Range (1) /Weighted-Average Price (2) Congestion revenue rights $ 140 $ 44 Market approach CRR auction prices $ (20.20) - 20.20 / 0.28 Power purchase agreements $ 21 $ 112 Discounted cash flow Forward prices $ 11.77 - 59.38 / 33.62 (1) Represents price per megawatt-hour. (2) Unobservable inputs were weighted by the relative fair value of the instruments. Fair Value at (in millions) At December 31, 2018 Valuation Unobservable Fair Value Measurement Assets Liabilities Range (1) Congestion revenue rights $ 203 $ 75 Market approach CRR auction prices $ (18.61) - 32.26 Power purchase agreements $ — $ 33 Discounted cash flow Forward prices $ 19.81 - 38.80 (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, 2019 and 2018, respectively: Price Risk Management Instruments (in millions) 2019 2018 Asset (liability) balance as of January 1 $ 95 $ 42 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (90) 53 Asset (liability) balance as of December 31 $ 5 $ 95 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. |
Carrying Amount and Fair Value of Financial Instruments | The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At December 31, 2019 2018 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 5) PG&E Corporation (1) $ — $ — $ 350 $ 350 Utility (1)(2) 1,500 1,500 17,450 14,747 (1) On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 5. |
Schedule of Unrealized Gains (Losses) Related to Available-for-sale Investments | The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Total Total Total Fair As of December 31, 2019 Nuclear decommissioning trusts Short-term investments $ 6 $ — $ — $ 6 Global equity securities 500 1,609 (2) 2,107 Fixed-income securities 1,505 89 (4) 1,590 Total (1) $ 2,011 $ 1,698 $ (6) $ 3,703 As of December 31, 2018 Nuclear decommissioning trusts Short-term investments $ 29 $ — $ — $ 29 Global equity securities 568 1,246 (5) 1,809 Fixed-income securities 1,288 30 (18) 1,300 Total (1) $ 1,885 $ 1,276 $ (23) $ 3,138 (1) Represents amounts before deducting $530 million and $408 million at December 31, 2019 and 2018, respectively, primarily related to deferred taxes on appreciation of investment value. |
Schedule of Long Term Debt Repayments | The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) December 31, 2019 Less than 1 year $ 42 1–5 years 488 5–10 years 397 More than 10 years 663 Total maturities of fixed-income securities $ 1,590 |
Schedule of Activity for Debt and Equity Securities | The following table provides a summary of activity for the fixed-income and equity securities: (in millions) 2019 2018 2017 Proceeds from sales and maturities of nuclear decommissioning investments $ 956 $ 1,412 $ 1,291 Gross realized gains on securities 69 54 53 Gross realized losses on securities (14) (24) (11) |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract] | |
Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status | The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2019 and 2018: Pension Plan (in millions) 2019 2018 Change in plan assets: Fair value of plan assets at beginning of year $ 15,312 $ 16,652 Actual return on plan assets 3,713 (923) Company contributions 328 334 Benefits and expenses paid (806) (751) Fair value of plan assets at end of year $ 18,547 $ 15,312 Change in benefit obligation: Benefit obligation at beginning of year $ 17,407 $ 18,757 Service cost for benefits earned 443 514 Interest cost 758 687 Actuarial (gain) loss 2,723 (1,800) Plan amendments — — Benefits and expenses paid (806) (751) Benefit obligation at end of year (1) $ 20,525 $ 17,407 Funded Status: Current liability $ (14) $ (8) Noncurrent liability (1,964) (2,087) Net liability at end of year $ (1,978) $ (2,095) (1) PG&E Corporation’s accumulated benefit obligation was $18.4 billion and $15.8 billion at December 31, 2019 and 2018, respectively. Postretirement Benefits Other than Pensions (in millions) 2019 2018 Change in plan assets: Fair value of plan assets at beginning of year $ 2,258 $ 2,420 Actual return on plan assets 474 (108) Company contributions 29 31 Plan participant contribution 82 81 Benefits and expenses paid (165) (166) Fair value of plan assets at end of year $ 2,678 $ 2,258 Change in benefit obligation: Benefit obligation at beginning of year $ 1,745 $ 1,897 Service cost for benefits earned 56 66 Interest cost 76 69 Actuarial (gain) loss 22 (221) Benefits and expenses paid (150) (150) Federal subsidy on benefits paid 2 3 Plan participant contributions 81 81 Benefit obligation at end of year $ 1,832 $ 1,745 Funded Status: (1) Noncurrent asset $ 879 $ 545 Noncurrent liability (33) (32) Net asset at end of year $ 846 $ 513 (1) At December 31, 2019 and 2018, 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 | Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows: Pension Plan (in millions) 2019 2018 2017 Service cost for benefits earned (1) $ 443 $ 514 $ 472 Interest cost 758 687 714 Expected return on plan assets (906) (1,021) (770) Amortization of prior service cost (6) (6) (7) Amortization of net actuarial loss 3 5 22 Net periodic benefit cost 292 179 431 Less: transfer to regulatory account (2) 42 157 (92) Total expense recognized $ 334 $ 336 $ 339 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) 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) 2019 2018 2017 Service cost for benefits earned (1) $ 56 $ 66 $ 59 Interest cost 76 69 77 Expected return on plan assets (123) (130) (97) Amortization of prior service cost 14 14 15 Amortization of net actuarial loss (3) (5) 4 Net periodic benefit cost $ 20 $ 14 $ 58 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. |
Estimated Amortized Net Periodic Benefit | The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2020 are as follows: (in millions) Pension Plan PBOP Plans Unrecognized prior service cost $ (6) $ 14 Unrecognized net loss 3 (21) Total $ (3) $ (7) |
Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost | 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, 2019 2018 2017 2019 2018 2017 Discount rate 3.46 % 4.35 % 3.64 % 3.37 - 3.47% 4.29 - 4.37% 3.60 - 3.67% Rate of future compensation increases 3.90 % 3.90 % 3.90 % — — — Expected return on plan assets 5.70 % 6.00 % 6.20 % 3.50 - 6.60% 3.60 - 6.80% 3.30 - 7.10% |
Schedule of Assumed Health Care Cost Trend | A one-percentage-point change in assumed health care cost trend rate would have the following effects: (in millions) One-Percentage-Point One-Percentage-Point Effect on postretirement benefit obligation $ 131 $ (129) Effect on service and interest cost 9 (9) |
Target Asset Allocation Percentages | The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows: Pension Plan PBOP Plans 2020 2019 2018 2020 2019 2018 Global equity securities 30 % 29 % 29 % 28 % 33 % 33 % Absolute return 2 % 5 % 5 % 2 % 3 % 3 % Real assets 8 % 8 % 8 % 8 % 6 % 6 % Fixed-income securities 60 % 58 % 58 % 62 % 58 % 58 % Total 100 % 100 % 100 % 100 % 100 % 100 % |
Schedule of Changes in Fair Value of Plan Assets | The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2019 and 2018. Fair Value Measurements At December 31, 2019 2018 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 613 $ 231 $ — $ 844 $ 333 $ 22 $ — $ 355 Global equity securities 1,650 — — 1,650 1,145 — — 1,145 Absolute Return — 1 — 1 — — — — Real assets 548 1 — 549 461 — — 461 Fixed-income securities 2,227 6,413 15 8,655 1,897 5,216 8 7,121 Assets measured at NAV — — — 6,937 — — — 6,202 Total $ 5,038 $ 6,646 $ 15 $ 18,636 $ 3,836 $ 5,238 $ 8 $ 15,284 PBOP Plans: Short-term investments $ 37 $ — $ — $ 37 $ 33 $ — $ — $ 33 Global equity securities 151 — — 151 115 — — 115 Real assets 58 — — 58 50 — — 50 Fixed-income securities 193 875 1 1,069 153 857 — 1,010 Assets measured at NAV — — — 1,373 — — — 1,056 Total $ 439 $ 875 $ 1 $ 2,688 $ 351 $ 857 $ — $ 2,264 Total plan assets at fair value $ 21,324 $ 17,548 |
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, 2019 and 2018: (in millions) For the year ended December 31, 2019 Fixed-Income Balance at beginning of year $ 8 Actual return on plan assets: Relating to assets still held at the reporting date — Relating to assets sold during the period — Purchases, issuances, sales, and settlements: Purchases 11 Settlements (4) Balance at end of year $ 15 (in millions) For the year ended December 31, 2018 Fixed-Income Balance at beginning of year $ 4 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 6 Settlements 1 Balance at end of year $ 8 |
Schedule of Estimated Benefits Expected to be Paid | As of December 31, 2019, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows: (in millions) Pension PBOP Federal 2020 801 92 (8) 2021 874 94 (9) 2022 910 92 (2) 2023 944 95 (2) 2024 975 98 (3) Thereafter in the succeeding five years 5,238 482 (8) |
RELATED PARTY AGREEMENTS AND _2
RELATED PARTY AGREEMENTS AND TRANSACTIONS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Schedule of Significant Related Party Transactions | The Utility’s significant related party transactions were: Year Ended December 31, (in millions) 2019 2018 2017 Utility revenues from: Administrative services provided to PG&E Corporation $ 4 $ 4 $ 8 Utility expenses from: Administrative services received from PG&E Corporation $ 107 $ 94 $ 65 Utility employee benefit due to PG&E Corporation 42 76 73 |
OTHER CONTINGENCIES AND COMMI_2
OTHER CONTINGENCIES AND COMMITMENTS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Expense and Capital Expenditures | The amounts set forth in the table below include actual recorded costs and forecasted cost estimates for expenses and capital expenditures which the Utility has incurred or will incur to comply with its legal obligations to provide safe and reliable service. (in millions) Description (1) Expense Capital Total Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA) (2) $ 236 $ — $ 236 Transmission Safety Inspections and Repairs Expense (TO) (3) 433 — 433 Vegetation Management Support Costs (FHPMA) 36 — 36 2017 Northern California Wildfires CEMA Expense and Capital (CEMA) 82 66 148 2018 Camp Fire CEMA Expense (CEMA) 435 — 435 2018 Camp Fire CEMA Capital for Restoration (CEMA) — 253 253 2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA) (4) — 84 84 Total $ 1,222 $ 403 $ 1,625 (1) Unless indicated otherwise, all amounts included in the table reflect actual recorded costs for 2019. (2) Includes $29 million forecasted for 2020. (3) Transmission amounts are under the FERC's regulatory authority. |
Schedule of Environmental Remediation Liability | 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 comprised of the following: Balance at (in millions) December 31, 2019 December 31, 2018 Topock natural gas compressor station $ 362 $ 369 Hinkley natural gas compressor station 138 146 Former manufactured gas plant sites owned by the Utility or third parties (1) 568 520 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) 101 111 Fossil fuel-fired generation facilities and sites (3) 106 137 Total environmental remediation liability $ 1,275 $ 1,283 (1) Primarily driven by the following sites: Vallejo, San Francisco East Harbor and Outside East Harbor, Napa, Beach Street and San Francisco North Beach. (2) Primarily driven by Geothermal landfill and Shell Pond site. |
Schedule of Undiscounted Future Expected Power Purchase Agreement Payments | The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2019: Power Purchase Agreements (in millions) Renewable Conventional Other Natural Nuclear Total 2020 $ 2,230 $ 640 $ 82 $ 411 $ 151 $ 3,514 2021 2,234 582 65 155 64 3,100 2022 2,021 511 61 155 54 2,802 2023 1,941 224 60 155 49 2,429 2024 1,917 72 60 155 47 2,251 Thereafter 22,853 351 94 346 — 23,644 Total purchase commitments $ 33,196 $ 2,380 $ 422 $ 1,377 $ 365 $ 37,740 |
Schedule of Future Minimum Payments for Operating Leases | At December 31, 2019, the future minimum payments related to these commitments were as follows: (in millions) Other Commitments 2020 $ 45 2021 39 2022 31 2023 24 2024 14 Thereafter 111 Total minimum lease payments $ 264 |
ORGANIZATION AND BASIS OF PRE_2
ORGANIZATION AND BASIS OF PRESENTATION (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2019segment | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of operating segments (segment) | 1 |
BANKRUPTCY FILING (Narrative) (
BANKRUPTCY FILING (Narrative) (Details) | Oct. 11, 2019USD ($) | Sep. 23, 2019USD ($) | Sep. 22, 2019USD ($) | Dec. 31, 2019USD ($)structure | Feb. 14, 2020USD ($) | Feb. 13, 2020USD ($) | Jan. 22, 2020USD ($) | Dec. 30, 2019USD ($) | Dec. 06, 2019USD ($) | Jan. 31, 2019USD ($) |
Debt Instrument [Line Items] | ||||||||||
TCC RSA settlement | $ 13,500,000,000 | $ 13,500,000,000 | ||||||||
Compensation of insurance subrogation claimants | 11,000,000,000 | |||||||||
Payment for settlement of claims | 1,000,000,000 | |||||||||
Professional fees | 99,000,000 | |||||||||
Equity raise | $ 9,000,000,000 | |||||||||
Insurance from wildfire events | 2,200,000,000 | |||||||||
Debt commitment letters, required equity funding, preferred equity | 2,000,000,000 | |||||||||
Equity offering | $ 12,000,000,000 | |||||||||
Backstop commitment letters, tax benefits | $ 1,350,000,000 | |||||||||
Reorganization, weighted average earning base rate | 0.95 | |||||||||
Reorganization, weighted average earning | $ 48,000,000,000 | |||||||||
Aggregate liability for prepetition wildfire related claims, cannot exceed amount | $ 25,500,000,000 | |||||||||
Number of days for effective date for confirmation order | 60 days | |||||||||
Maximum number of structures that can be destroyed during current fiscal year | structure | 500 | |||||||||
Asserted administrative expense claims, maximum | $ 250,000,000 | |||||||||
Maximum number of structures that can be destroyed in wildfire in 2019 | structure | 500 | |||||||||
Backstop commitment letters, cash proceeds | $ 3,000,000,000 | |||||||||
Backstop commitment letters, premium | 6.364% | |||||||||
Legal Advisor | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Professional fees and expenses | $ 17,000,000 | |||||||||
Financial Advisor | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Professional fees and expenses | 19,000,000 | |||||||||
PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maximum amount able to be drawn | 12,000,000,000 | |||||||||
Legal fees | 6,000,000 | |||||||||
Payments for reorganization items | 15,000,000 | |||||||||
Pacific Gas & Electric Co | ||||||||||
Debt Instrument [Line Items] | ||||||||||
TCC claims settlement, amount | $ 11,000,000,000 | |||||||||
Subrogation claims, professional fees | $ 55,000,000 | 47,500,000 | ||||||||
Payments for reorganization items | 223,000,000 | |||||||||
Subsequent Event | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Subrogation claims, professional fees | $ 99,000,000 | |||||||||
Subsequent Event | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Amendment, debt and equity amount | $ 5,000,000,000 | $ 7,000,000,000 | ||||||||
Amendment, other funding, increase amount | 2,000,000,000 | |||||||||
Subsequent Event | Pacific Gas & Electric Co | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Amendment, debt and equity amount | 33,350,000,000 | $ 30,000,000,000 | ||||||||
Amendment, other funding, increase amount | $ 6,000,000,000 | |||||||||
Bridge Loan | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Line of credit facility, maximum borrowing capacity | $ 10,825,000,000 | |||||||||
Debt Instrument, term | 364 days | |||||||||
DIP Credit Agreement | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt, face value | $ 11,900,000,000 | |||||||||
Post-petition interest rate | 2.59% | |||||||||
Fire Victim Trust | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | 6,750,000,000 | |||||||||
New PG&E Corporation Debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | 4,750,000,000 | |||||||||
New Utility Debt | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | 23,775,000,000 | |||||||||
New Utility Short-Term Notes | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | 1,750,000,000 | |||||||||
Debt, face value | $ 875,000,000 | |||||||||
Stated interest rate | 3.75% | |||||||||
New Debt Securities or Bank Debt | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | $ 11,925,000,000 | |||||||||
Expected repayment | 6,000,000,000 | |||||||||
Utility Short-Term Senior Notes | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt, face value | 1,750,000,000 | |||||||||
Utility Short-Term Secured Notes Due 2025 | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt, face value | $ 875,000,000 | |||||||||
Stated interest rate | 3.45% | |||||||||
Senior Note Due March 1, 2034 | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 6.05% | |||||||||
Utility Long-Term Senior Notes | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt, face value | $ 6,200,000,000 | |||||||||
Stated interest rate | 5.00% | |||||||||
Utility Long-Term Secured Notes Due 2030 | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt, face value | $ 3,100,000,000 | |||||||||
Stated interest rate | 4.55% | |||||||||
New Utility Long-Term Notes | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | $ 6,200,000,000 | |||||||||
Debt, face value | $ 3,100,000,000 | |||||||||
Stated interest rate | 4.95% | |||||||||
Senior Note Due December 1, 2047 | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.95% | |||||||||
Utility Reinstated Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt, face value | $ 9,580,000,000 | |||||||||
Utility Reinstated Senior Notes | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt, outstanding | $ 9,575,000,000 | |||||||||
Utility Funded Debt | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt, face value | $ 1,949,000,000 | |||||||||
Stated interest rate | 3.15% | |||||||||
New Utility Funded Debt Exchange Notes | PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | $ 3,900,000,000 | |||||||||
Debt, face value | $ 1,949,000,000 | |||||||||
Stated interest rate | 4.50% | |||||||||
Senior Secured Superpriority Debt | Bridge Loan | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Line of credit facility, maximum borrowing capacity | $ 5,825,000,000 | |||||||||
Senior Secured Superpriority Debt | DIP Credit Agreement | Line of Credit | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Amount arranged | $ 5,500,000,000 | |||||||||
Unsecured Debt | Bridge Loan | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Line of credit facility, maximum borrowing capacity | $ 5,000,000,000 |
BANKRUPTCY FILING (Schedule of
BANKRUPTCY FILING (Schedule of Liabilities Subject to Compromise) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Reorganizations [Line Items] | ||
Financing debt | $ 23,116 | |
Wildfire-related claims | 25,548 | |
Trade creditors | 1,188 | |
Non-qualified benefit plan | 157 | |
2001 bankruptcy disputed claims | 234 | |
Customer deposits & advances | 71 | |
Other | 232 | |
Total Liabilities Subject to Compromise | 50,546 | $ 0 |
Interest expense | 14 | |
Pacific Gas & Electric Co | ||
Reorganizations [Line Items] | ||
Financing debt | 22,450 | |
Wildfire-related claims | 25,548 | |
Trade creditors | 1,183 | |
Non-qualified benefit plan | 20 | |
2001 bankruptcy disputed claims | 234 | |
Customer deposits & advances | 71 | |
Other | 230 | |
Total Liabilities Subject to Compromise | 49,736 | 0 |
Aggregate principal amount of debt subject to compromise | 21,526 | |
Liabilities subject to compromise, accrued interest | (286) | |
Post-petition interest expense | (638) | |
PG&E Corporation | ||
Reorganizations [Line Items] | ||
Financing debt | 666 | |
Wildfire-related claims | 0 | |
Trade creditors | 5 | |
Non-qualified benefit plan | 137 | |
2001 bankruptcy disputed claims | 0 | |
Customer deposits & advances | 0 | |
Other | 2 | |
Total Liabilities Subject to Compromise | 810 | $ 0 |
Aggregate principal amount of debt subject to compromise | 650 | |
Liabilities subject to compromise, accrued interest | (1) | |
Post-petition interest expense | $ (15) |
BANKRUPTCY FILING (Schedule o_2
BANKRUPTCY FILING (Schedule of Debtor Reorganization Items) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Reorganizations [Line Items] | |||
Debtor-in-possession financing costs | $ 114 | ||
Legal and other | 292 | ||
Interest income | (60) | ||
Adjustments to LSTC | 0 | ||
Total reorganization items, net | 346 | $ 0 | $ 0 |
PG&E Corporation | |||
Reorganizations [Line Items] | |||
Debtor-in-possession financing costs | 17 | ||
Legal and other | 19 | ||
Interest income | (10) | ||
Adjustments to LSTC | 0 | ||
Total reorganization items, net | 26 | 0 | 0 |
Pacific Gas & Electric Co | |||
Reorganizations [Line Items] | |||
Debtor-in-possession financing costs | 97 | ||
Legal and other | 273 | ||
Interest income | (50) | ||
Adjustments to LSTC | 0 | ||
Total reorganization items, net | $ 320 | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019USD ($)facility | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Jan. 01, 2019USD ($) | |
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Period for probable revenue recovery | 24 months | |||
Operating lease right of use asset | $ 2,286 | |||
Operating lease, right-of-use liability | 2,279 | |||
Operating lease, payments | $ 2,400 | |||
Weighted average remaining lease term | 5 years 10 months 24 days | |||
Weighted average discount rate | 6.20% | |||
Accounting Standards Update 2016-02 | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Operating lease right of use asset | $ 2,800 | |||
Operating lease, right-of-use liability | $ 2,800 | |||
Pacific Gas & Electric Co | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Composite depreciation rate | 3.80% | 3.82% | 3.83% | |
AFUDC debt recorded | $ 55 | $ 53 | $ 38 | |
AFUDC equity recorded | 79 | 129 | $ 89 | |
Nuclear decommissioning obligation accrued | 4,900 | 4,700 | ||
Estimated cost recovery on spent nuclear fuel storage proceeding every year | 10,600 | $ 10,600 | ||
Operating lease right of use asset | $ 2,279 | |||
Pacific Gas & Electric Co | Diablo Canyon | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Number of generation facilities | facility | 2 | |||
Pacific Gas & Electric Co | Humboldt Bay | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Number of generation facilities | facility | 1 |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenue from contracts with customers | |||
Total operating revenues | $ 17,129 | $ 16,759 | $ 17,135 |
Electric | |||
Revenue from contracts with customers | |||
Total operating revenues | 12,740 | 12,713 | 13,124 |
Natural gas | |||
Revenue from contracts with customers | |||
Total operating revenues | 4,389 | 4,046 | 4,011 |
Pacific Gas & Electric Co | |||
Revenue from contracts with customers | |||
Total operating revenues | 17,129 | 16,760 | 17,138 |
Pacific Gas & Electric Co | Electric | |||
Revenue from contracts with customers | |||
Total operating revenues | 12,437 | 12,077 | |
Regulatory balancing accounts | 303 | 636 | |
Total operating revenues | 12,740 | 12,713 | 13,127 |
Pacific Gas & Electric Co | Electric | Residential | |||
Revenue from contracts with customers | |||
Total operating revenues | 4,847 | 5,051 | |
Pacific Gas & Electric Co | Electric | Commercial | |||
Revenue from contracts with customers | |||
Total operating revenues | 4,756 | 4,908 | |
Pacific Gas & Electric Co | Electric | Industrial | |||
Revenue from contracts with customers | |||
Total operating revenues | 1,493 | 1,532 | |
Pacific Gas & Electric Co | Electric | Agricultural | |||
Revenue from contracts with customers | |||
Total operating revenues | 1,106 | 1,234 | |
Pacific Gas & Electric Co | Electric | Public street and highway lighting | |||
Revenue from contracts with customers | |||
Total operating revenues | 67 | 72 | |
Pacific Gas & Electric Co | Electric | Other | |||
Revenue from contracts with customers | |||
Total operating revenues | 168 | (720) | |
Pacific Gas & Electric Co | Natural gas | |||
Revenue from contracts with customers | |||
Total operating revenues | 4,302 | 3,805 | |
Regulatory balancing accounts | 87 | 242 | |
Total operating revenues | 4,389 | 4,047 | $ 4,011 |
Pacific Gas & Electric Co | Natural gas | Residential | |||
Revenue from contracts with customers | |||
Total operating revenues | 2,325 | 2,042 | |
Pacific Gas & Electric Co | Natural gas | Commercial | |||
Revenue from contracts with customers | |||
Total operating revenues | 605 | 537 | |
Pacific Gas & Electric Co | Natural gas | Transportation service only | |||
Revenue from contracts with customers | |||
Total operating revenues | 1,249 | 1,151 | |
Pacific Gas & Electric Co | Natural gas | Other | |||
Revenue from contracts with customers | |||
Total operating revenues | $ 123 | $ 75 |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Estimated Useful Lives and Balances of Utility's Property, Plant and Equipment) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 88,088 | $ 83,270 |
Accumulated depreciation | (26,453) | (24,713) |
Net property, plant, and equipment | 61,635 | 58,557 |
Electricity generating facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 13,189 | 13,047 |
Electricity generating facilities | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 10 years | |
Electricity generating facilities | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 75 years | |
Electricity distribution facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 35,237 | 32,926 |
Electricity distribution facilities | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 10 years | |
Electricity distribution facilities | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 65 years | |
Electricity transmission facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 14,281 | 13,177 |
Electricity transmission facilities | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 15 years | |
Electricity transmission facilities | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 75 years | |
Natural gas distribution facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 14,236 | 13,296 |
Natural gas distribution facilities | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 20 years | |
Natural gas distribution facilities | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 60 years | |
Natural gas transmission and storage facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 8,452 | 8,260 |
Natural gas transmission and storage facilities | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 5 years | |
Natural gas transmission and storage facilities | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 66 years | |
Construction work in progress | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 2,675 | 2,564 |
Other | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 18 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
ARO liability at beginning of year | $ 5,994 | $ 4,899 |
Revision in estimated cash flows | (376) | 993 |
Accretion | 274 | 211 |
Liabilities settled | (38) | (109) |
ARO liability at end of year | $ 5,854 | $ 5,994 |
SUMMARY OF SIGNIFICANT ACCOUN_8
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Accumulated Other Comprehensive Income (Loss) | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Beginning balance | $ (4) | $ (8) |
Net current period other comprehensive loss | (1) | 4 |
Ending balance | (5) | (4) |
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | 288 | (127) |
Amounts reclassified from other comprehensive income: | 0 | (1) |
Accumulated Defined Benefit Plans Adjustment, Net Transition Attributable to Parent | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | (289) | 130 |
Amounts reclassified from other comprehensive income: | (6) | (4) |
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Amounts reclassified from other comprehensive income: | 6 | 6 |
Pension Plan | Accumulated Other Comprehensive Income (Loss) | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Beginning balance | (21) | (25) |
Net current period other comprehensive loss | (1) | 4 |
Ending balance | (22) | (21) |
Pension Plan | Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | 61 | (104) |
Amounts reclassified from other comprehensive income: | 2 | 3 |
Other comprehensive income before reclassifications, tax | 24 | 41 |
Amounts reclassified from other comprehensive income, tax | 1 | 2 |
Pension Plan | Accumulated Defined Benefit Plans Adjustment, Net Transition Attributable to Parent | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | (62) | 107 |
Amounts reclassified from other comprehensive income: | 2 | 2 |
Other comprehensive income before reclassifications, tax | 24 | 41 |
Amounts reclassified from other comprehensive income, tax | 1 | 1 |
Pension Plan | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Amounts reclassified from other comprehensive income: | (4) | (4) |
Amounts reclassified from other comprehensive income, tax | 2 | 2 |
PBOP Plans | Accumulated Other Comprehensive Income (Loss) | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Beginning balance | 17 | 17 |
Net current period other comprehensive loss | 0 | 0 |
Ending balance | 17 | 17 |
PBOP Plans | Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | 227 | (23) |
Amounts reclassified from other comprehensive income: | (2) | (4) |
Other comprehensive income before reclassifications, tax | 88 | 9 |
Amounts reclassified from other comprehensive income, tax | 1 | 1 |
PBOP Plans | Accumulated Defined Benefit Plans Adjustment, Net Transition Attributable to Parent | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | (227) | 23 |
Amounts reclassified from other comprehensive income: | (8) | (6) |
Other comprehensive income before reclassifications, tax | 88 | 9 |
Amounts reclassified from other comprehensive income, tax | 3 | 3 |
PBOP Plans | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Amounts reclassified from other comprehensive income: | 10 | 10 |
Amounts reclassified from other comprehensive income, tax | $ 4 | $ 4 |
SUMMARY OF SIGNIFICANT ACCOUN_9
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Lease Expense) (Details) $ in Millions | 3 Months Ended |
Dec. 31, 2019USD ($) | |
Accounting Policies [Abstract] | |
Operating lease fixed cost | $ 686 |
Operating lease variable cost | 1,778 |
Total operating lease cost | $ 2,464 |
SUMMARY OF SIGNIFICANT ACCOU_10
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Future Expected Operating Lease Payments and Expected Obligations for Power Purchase and Other Lease Commitments) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Future Expected Operating Lease Payments | ||
2020 | $ 679 | |
2021 | 623 | |
2022 | 548 | |
2023 | 255 | |
2024 | 96 | |
Thereafter | 596 | |
Total lease payments | 2,797 | |
Less imputed interest | (518) | |
Total | $ 2,279 | |
Future Expected Obligations and Other Commitments | ||
2020 | $ 684 | |
2021 | 677 | |
2022 | 621 | |
2023 | 546 | |
2024 | 252 | |
Thereafter | 581 | |
Total minimum lease payments | $ 3,361 |
REGULATORY ASSETS, LIABILITIE_3
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 6,066 | $ 4,964 |
Utility retained generation asset costs | 1,200 | |
Debtor reorganization items, write-off of debt issuance costs and debt discounts | (178) | |
Pension benefits | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 1,823 | 1,947 |
Environmental compliance costs | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 1,062 | 1,013 |
Recovery Period | 32 years | |
Utility retained generation | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 228 | 274 |
Recovery Period | 8 years | |
Price risk management | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 124 | 90 |
Recovery Period | 10 years | |
Unamortized loss, net of gain, on reacquired debt | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 63 | 76 |
Recovery Period | 25 years | |
Catastrophic event memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 656 | 790 |
Catastrophic event memorandum account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Catastrophic event memorandum account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 4 years | |
Wildfire expense memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 423 | 94 |
Wildfire expense memorandum account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Wildfire expense memorandum account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 4 years | |
Fire hazard prevention memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 259 | 263 |
Fire hazard prevention memorandum account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Fire hazard prevention memorandum account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 4 years | |
Fire risk mitigation memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 95 | 0 |
Fire risk mitigation memorandum account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Fire risk mitigation memorandum account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 4 years | |
Wildfire mitigation plan memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 558 | 0 |
Wildfire mitigation plan memorandum account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Wildfire mitigation plan memorandum account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 4 years | |
Deferred income tax | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 252 | 0 |
Recovery Period | 47 years | |
Other | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 523 | $ 417 |
REGULATORY ASSETS, LIABILITIE_4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 9,270 | $ 8,539 |
Cost of removal obligations | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 6,456 | 5,981 |
Deferred income tax | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 0 | 283 |
Recoveries in excess of AROs | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 393 | 356 |
Public purpose programs | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 817 | 674 |
Retirement Plan | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 750 | 421 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 854 | $ 824 |
REGULATORY ASSETS, LIABILITIE_5
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | $ 1,797 | $ 1,076 |
Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 2,114 | 1,435 |
Electric distribution | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 31 | 0 |
Electric distribution | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 0 | 160 |
Electric transmission | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 119 | 134 |
Electric transmission | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 9 | 128 |
Utility generation | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 0 | 79 |
Gas distribution and transmission | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 45 | 9 |
Gas distribution and transmission | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 363 | 462 |
Energy procurement | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 649 | 59 |
Energy procurement | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 901 | 168 |
Public purpose programs | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 559 | 587 |
Public purpose programs | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 209 | 111 |
Other | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 394 | 287 |
Other | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | $ 632 | $ 327 |
DEBT (Debtor In Possession ("DI
DEBT (Debtor In Possession ("DIP") Facilities) (Details) | 12 Months Ended | ||||||
Dec. 31, 2019USD ($) | Jan. 29, 2020USD ($) | Apr. 03, 2019USD ($) | Mar. 27, 2019USD ($) | Feb. 01, 2019USD ($) | Jan. 31, 2019USD ($) | Dec. 31, 2018USD ($) | |
Line of Credit Facility [Line Items] | |||||||
Debtor-in-possession financing, classified as current | $ 1,500,000,000 | $ 0 | |||||
Pacific Gas & Electric Co | |||||||
Line of Credit Facility [Line Items] | |||||||
Debtor-in-possession financing, classified as current | 1,500,000,000 | $ 0 | |||||
Senior Secured Superpriority Debt | Line of Credit | DIP Credit Agreement | |||||||
Line of Credit Facility [Line Items] | |||||||
Amount arranged | $ 5,500,000,000 | ||||||
Covenant terms, unstayed indebtedness, maximum amount | 200,000,000 | ||||||
Covenant terms, post-petition obligations liability, maximum amount | $ 200,000,000 | ||||||
Senior Secured Superpriority Debt | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co | |||||||
Line of Credit Facility [Line Items] | |||||||
Extension fee | 0.0025 | ||||||
Senior Secured Superpriority Debt | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co | LIBOR | |||||||
Line of Credit Facility [Line Items] | |||||||
Basis spread on variable rate | 1.00% | ||||||
Senior Secured Superpriority Debt | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co | Federal Funds Effective Swap Rate | |||||||
Line of Credit Facility [Line Items] | |||||||
Basis spread on variable rate | 0.50% | ||||||
Senior Secured Superpriority Debt | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co | Minimum | |||||||
Line of Credit Facility [Line Items] | |||||||
Basis spread on variable rate | 0.00% | ||||||
DIP Revolving Facility | DIP Credit Agreement | Pacific Gas & Electric Co | |||||||
Line of Credit Facility [Line Items] | |||||||
Basis spread on variable rate | 0.25% | ||||||
DIP Revolving Facility | Line of Credit | DIP Credit Agreement | |||||||
Line of Credit Facility [Line Items] | |||||||
Amount arranged | $ 3,500,000,000 | ||||||
DIP Revolving Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co | |||||||
Line of Credit Facility [Line Items] | |||||||
Debtor-in-possession financing, classified as current | 1,500,000,000 | ||||||
Fee on unused borrowings based on average daily unutilized commitments | 0.375% | ||||||
Fronting fee | 0.125% | ||||||
DIP Revolving Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co | LIBOR | |||||||
Line of Credit Facility [Line Items] | |||||||
Basis spread on variable rate | 2.25% | ||||||
DIP Revolving Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co | Base Rate | |||||||
Line of Credit Facility [Line Items] | |||||||
Basis spread on variable rate | 1.25% | ||||||
Letter of Credit Subfacility | Line of Credit | DIP Credit Agreement | |||||||
Line of Credit Facility [Line Items] | |||||||
Amount arranged | 1,500,000,000 | ||||||
Letter of Credit Subfacility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co | |||||||
Line of Credit Facility [Line Items] | |||||||
Amount arranged | $ 1,500,000,000 | ||||||
Letters of credit available | 750,000,000 | ||||||
DIP Initial Term Loan Facility | LIBOR | |||||||
Line of Credit Facility [Line Items] | |||||||
Basis spread on variable rate | 2.25% | ||||||
DIP Initial Term Loan Facility | Line of Credit | DIP Credit Agreement | |||||||
Line of Credit Facility [Line Items] | |||||||
Amount arranged | 1,500,000,000 | ||||||
DIP Initial Term Loan Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co | |||||||
Line of Credit Facility [Line Items] | |||||||
Amount arranged | $ 1,500,000,000 | ||||||
DIP Delayed Draw Term Loan Facility | LIBOR | |||||||
Line of Credit Facility [Line Items] | |||||||
Basis spread on variable rate | 2.25% | ||||||
DIP Delayed Draw Term Loan Facility | Line of Credit | DIP Credit Agreement | |||||||
Line of Credit Facility [Line Items] | |||||||
Amount arranged | 500,000,000 | ||||||
DIP Delayed Draw Term Loan Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co | |||||||
Line of Credit Facility [Line Items] | |||||||
Amount arranged | 350,000,000 | ||||||
Repayments of debt | $ 350,000,000 | ||||||
DIP Delayed Draw Term Loan Facility | Subsequent Event | DIP Credit Agreement | Pacific Gas & Electric Co | |||||||
Line of Credit Facility [Line Items] | |||||||
Amount arranged | $ 500,000,000 | ||||||
DIP Incremental Facilities | Line of Credit | DIP Credit Agreement | |||||||
Line of Credit Facility [Line Items] | |||||||
Amount arranged | $ 4,000,000,000 |
DEBT (Schedule of DIP Financing
DEBT (Schedule of DIP Financing) (Details) - Revolving Credit Facility $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Debt [Line Items] | |
Aggregate Availability | $ 3,337 |
Pacific Gas & Electric Co | DIP Credit Agreement | |
Debt [Line Items] | |
Aggregate Limit | 5,500 |
Term Loan Borrowings | 1,500 |
Letters of Credit Outstanding | $ 663 |
Basis spread on variable rate | 0.25% |
DEBT (Schedule of Long-term Deb
DEBT (Schedule of Long-term Debt) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Debt [Line Items] | ||
Total PG&E Corporation Consolidated Debt Subject to Compromise | $ 22,176 | $ 22,075 |
Debtor reorganization items, write-off of debt issuance costs and debt discounts | (178) | |
Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Unamortized discount, net of premium and debt issuance costs | 0 | (178) |
Total Senior notes, net of premium and debt issuance costs | 17,525 | 17,347 |
Pollution control bonds | 863 | 863 |
Total Borrowings under Pre-Petition Credit Facility Subject to Compromise | 3,138 | 3,215 |
Total PG&E Corporation Consolidated Debt Subject to Compromise | 21,526 | 21,425 |
Liabilities subject to compromise, accrued interest | (286) | |
Post-petition interest expense | 638 | |
PG&E Corporation | ||
Debt [Line Items] | ||
Total Senior notes, net of premium and debt issuance costs | 650 | 650 |
Total PG&E Corporation Consolidated Debt Subject to Compromise | 0 | 0 |
Liabilities subject to compromise, accrued interest | (1) | |
Post-petition interest expense | $ 15 | |
Senior Notes Due 2022 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Stated interest rate | 2.45% | |
Senior notes | $ 400 | 400 |
Borrowings under Pre-Petition Credit Facilities | (2,888) | (2,965) |
Undrawn letters of credit | $ 22 | |
Senior Notes Due 2022 | Pacific Gas & Electric Co | LIBOR | ||
Debt [Line Items] | ||
Stated interest rate | 3.04% | |
Senior Notes Due 2022 | PG&E Corporation | ||
Debt [Line Items] | ||
Senior notes | $ 300 | 300 |
Senior Notes Due 2022 | PG&E Corporation | LIBOR | ||
Debt [Line Items] | ||
Stated interest rate | 3.24% | |
Senior Notes Due 2020 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Stated interest rate | 3.50% | |
Senior notes | $ 800 | 800 |
Senior Notes Due 2020 | PG&E Corporation | ||
Debt [Line Items] | ||
Total Senior notes, net of premium and debt issuance costs | $ 350 | 350 |
Senior Notes Due 2020 | PG&E Corporation | LIBOR | ||
Debt [Line Items] | ||
Stated interest rate | 2.96% | |
Senior Notes Due 2021 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Senior notes | $ 550 | 550 |
Senior Notes Due 2021 | Pacific Gas & Electric Co | Minimum | ||
Debt [Line Items] | ||
Stated interest rate | 3.25% | |
Senior Notes Due 2021 | Pacific Gas & Electric Co | Maximum | ||
Debt [Line Items] | ||
Stated interest rate | 4.25% | |
Seniors Note Due 2023 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Senior notes | $ 1,175 | 1,175 |
Seniors Note Due 2023 | Pacific Gas & Electric Co | Minimum | ||
Debt [Line Items] | ||
Stated interest rate | 3.25% | |
Seniors Note Due 2023 | Pacific Gas & Electric Co | Maximum | ||
Debt [Line Items] | ||
Stated interest rate | 4.25% | |
Senior Notes Due 2024 Through 2028 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Senior notes | $ 3,850 | 3,850 |
Senior Notes Due 2024 Through 2028 | Pacific Gas & Electric Co | Minimum | ||
Debt [Line Items] | ||
Stated interest rate | 2.95% | |
Senior Notes Due 2024 Through 2028 | Pacific Gas & Electric Co | Maximum | ||
Debt [Line Items] | ||
Stated interest rate | 4.65% | |
Senior Notes Due 2034 Through 2040 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Senior notes | $ 5,700 | 5,700 |
Senior Notes Due 2034 Through 2040 | Pacific Gas & Electric Co | Minimum | ||
Debt [Line Items] | ||
Stated interest rate | 5.40% | |
Senior Notes Due 2034 Through 2040 | Pacific Gas & Electric Co | Maximum | ||
Debt [Line Items] | ||
Stated interest rate | 6.35% | |
Senior Notes Due 2041 Through 2042 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Senior notes | $ 1,000 | 1,000 |
Senior Notes Due 2041 Through 2042 | Pacific Gas & Electric Co | Minimum | ||
Debt [Line Items] | ||
Stated interest rate | 3.75% | |
Senior Notes Due 2041 Through 2042 | Pacific Gas & Electric Co | Maximum | ||
Debt [Line Items] | ||
Stated interest rate | 4.50% | |
Senior Notes Due 2043 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Stated interest rate | 4.60% | |
Senior notes | $ 375 | 375 |
Senior Notes Due 2043 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Stated interest rate | 5.13% | |
Senior notes | $ 500 | 500 |
Senior Notes Due 2024 through 2047 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Senior notes | $ 3,175 | 3,175 |
Senior Notes Due 2024 through 2047 | Pacific Gas & Electric Co | Minimum | ||
Debt [Line Items] | ||
Stated interest rate | 3.95% | |
Senior Notes Due 2024 through 2047 | Pacific Gas & Electric Co | Maximum | ||
Debt [Line Items] | ||
Stated interest rate | 4.75% | |
Pollution Control Bonds Series 2008, F, And 2010, E, 1.75%, Due 2026 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Stated interest rate | 1.75% | |
Pollution control bonds | $ 100 | 100 |
Pollution Control Bonds Series 2009, A-B, Variable Rate, Due 2026 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Stated interest rate | 7.95% | |
Pollution control bonds | $ 149 | 149 |
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Pollution control bonds | $ 614 | 614 |
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 | Pacific Gas & Electric Co | Minimum | ||
Debt [Line Items] | ||
Stated interest rate | 7.95% | |
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 | Pacific Gas & Electric Co | Maximum | ||
Debt [Line Items] | ||
Stated interest rate | 8.08% | |
Senior Notes Due 2019 | Pacific Gas & Electric Co | ||
Debt [Line Items] | ||
Total Senior notes, net of premium and debt issuance costs | $ 250 | $ 250 |
Senior Notes Due 2019 | Pacific Gas & Electric Co | LIBOR | ||
Debt [Line Items] | ||
Stated interest rate | 2.36% |
DEBT (Schedule of Contractual R
DEBT (Schedule of Contractual Repayment Schedule) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Debt [Line Items] | |
Variable rate obligations | $ 650 |
Total consolidated debt | $ 22,176 |
Pacific Gas & Electric Co | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 8.00% |
Variable rate obligations | $ 3,901 |
Average fixed interest rate | 4.52% |
Fixed rate obligations | $ 17,625 |
PG&E Corporation | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 2.96% |
2020 | |
Debt [Line Items] | |
Total consolidated debt | $ 2,163 |
2020 | Pacific Gas & Electric Co | |
Debt [Line Items] | |
Variable rate obligations | $ 1,013 |
Average fixed interest rate | 3.50% |
Fixed rate obligations | $ 800 |
2020 | Pacific Gas & Electric Co | Pollution Control Bond | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 8.00% |
2020 | Pacific Gas & Electric Co | Term Loan | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 2.36% |
2020 | PG&E Corporation | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 2.96% |
Variable rate obligations | $ 350 |
2021 | |
Debt [Line Items] | |
Total consolidated debt | $ 550 |
2021 | Pacific Gas & Electric Co | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 0.00% |
Variable rate obligations | $ 0 |
Average fixed interest rate | 3.80% |
Fixed rate obligations | $ 550 |
2021 | PG&E Corporation | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 0.00% |
Variable rate obligations | $ 0 |
2022 | |
Debt [Line Items] | |
Total consolidated debt | $ 3,688 |
2022 | Pacific Gas & Electric Co | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 3.04% |
Variable rate obligations | $ 2,888 |
Average fixed interest rate | 2.31% |
Fixed rate obligations | $ 500 |
2022 | PG&E Corporation | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 3.24% |
Variable rate obligations | $ 300 |
2023 | |
Debt [Line Items] | |
Total consolidated debt | $ 1,175 |
2023 | Pacific Gas & Electric Co | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 0.00% |
Variable rate obligations | $ 0 |
Average fixed interest rate | 3.83% |
Fixed rate obligations | $ 1,175 |
2023 | PG&E Corporation | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 0.00% |
Variable rate obligations | $ 0 |
2024 | |
Debt [Line Items] | |
Total consolidated debt | $ 800 |
2024 | Pacific Gas & Electric Co | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 0.00% |
Variable rate obligations | $ 0 |
Average fixed interest rate | 3.60% |
Fixed rate obligations | $ 800 |
2024 | PG&E Corporation | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 0.00% |
Variable rate obligations | $ 0 |
Thereafter | |
Debt [Line Items] | |
Total consolidated debt | $ 13,800 |
Thereafter | Pacific Gas & Electric Co | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 0.00% |
Variable rate obligations | $ 0 |
Average fixed interest rate | 4.80% |
Fixed rate obligations | $ 13,800 |
Thereafter | PG&E Corporation | |
Debt [Line Items] | |
Variable interest rate as of December 31, 2019 | 0.00% |
Variable rate obligations | $ 0 |
COMMON STOCK AND SHARE-BASED _3
COMMON STOCK AND SHARE-BASED COMPENSATION (Narrative) (Details) - USD ($) | 12 Months Ended | 60 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2019 | |
Common stock, shares outstanding (in shares) | 529,236,741 | 520,338,710 | 529,236,741 | |
Cash proceeds from stock issuance | $ 13,038,000,000 | $ 12,910,000,000 | $ 13,038,000,000 | |
Consolidated total debt to consolidated capitalization, percentage | 65.00% | 65.00% | ||
Consolidated total debt to consolidated capitalization, equity, percentage | 52.00% | 52.00% | ||
Period in which cash dividends is not expected to be paid for | 2 years | |||
Number of shares issued for LTIP, maximum (in shares) | 17,000,000 | 17,000,000 | ||
Shares available for LTIP award (in shares) | 12,338,419 | 12,338,419 | ||
Weighted average grant date fair value of granted shares (in dollars per share) | $ 18.57 | $ 40.92 | $ 66.95 | |
Total fair value | $ 42,000,000 | $ 41,000,000 | $ 57,000,000 | |
Total unrecognized compensation costs | $ 19,000,000 | |||
Remaining weighted average period | 1 year 1 month 20 days | |||
Pacific Gas & Electric Co | ||||
Common stock, shares outstanding (in shares) | 264,374,809 | 264,374,809 | 264,374,809 | |
Cash proceeds from stock issuance | $ 1,322,000,000 | $ 1,322,000,000 | $ 1,322,000,000 | |
Stock Options | ||||
Tax benefit from share based awards | $ 0 | |||
Weighted-average period | 1 year 2 months 1 day | |||
Stock Options | 2014 LTIP | ||||
Term of award | 10 years | |||
Award vesting period | 3 years | |||
Total unrecognized compensation costs | $ 10,500,000 | $ 10,500,000 | ||
Weighted average grant date fair value of granted shares (in dollars per share) | $ 3.87 | $ 10.24 | ||
Restricted stock units | ||||
Award vesting period | 3 years | |||
Performance shares | ||||
Award vesting period | 3 years | |||
Tax benefit from share based awards | $ 0 | $ 0 | $ 0 | |
Industry performance period | 3 years | |||
Award grant date fair value recognition period | 3 years | |||
Performance shares granted (in dollars per share) | $ 15.39 | $ 36.92 | $ 77 | |
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized | $ 11,000,000 | |||
Expirations, fair value (in dollars per share) | $ 0 | |||
February 2017 Equity Distribution Agreement | ||||
Common stock issued (in shares) | 0 | 0 | ||
Common stock, gross sales available | $ 246,000,000 | $ 246,000,000 | ||
Dividend Reinvestment and Stock Purchase Plan | ||||
Common stock issued (in shares) | 8,900,000 | 8,900,000 | ||
Cash proceeds from stock issuance | $ 85,000,000 | $ 85,000,000 | ||
PG&E Corporation | ||||
Cash proceeds from stock issuance | $ 13,038,000,000 | $ 12,910,000,000 | $ 13,038,000,000 | |
unrecognized compensation cost, period | 1 year 8 months 23 days |
COMMON STOCK AND SHARE-BASED _4
COMMON STOCK AND SHARE-BASED COMPENSATION (Long-term Incentive Plan) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | $ 50 | $ 89 | $ 85 |
Total compensation expense (after-tax) | 35 | 63 | 50 |
Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | 7 | 10 | 0 |
Restricted stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | 21 | 43 | 40 |
Performance shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | $ 22 | $ 36 | $ 45 |
COMMON STOCK AND SHARE-BASED _5
COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Significant Assumptions Used for Shares Granted) (Details) - 2014 LTIP - Stock Options | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Expected stock price volatility | 57.00% | 23.00% |
Expected annual dividend payment | 0.00% | 3.10% |
Risk-free interest rate | 2.58% | |
Expected life (years) | 4 years 6 months | 6 years |
Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Risk-free interest rate | 1.51% | |
Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Risk-free interest rate | 1.52% |
COMMON STOCK AND SHARE-BASED _6
COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Stock Option Activity) (Details) - 2014 LTIP - Stock Options | 12 Months Ended |
Dec. 31, 2019$ / sharesshares | |
Number of Stock Option | |
Outstanding, beginning of period (in shares) | 1,522,137 |
Granted (in shares) | 2,866,667 |
Exercised (in shares) | 0 |
Forfeited or expired (in shares) | (107,401) |
Outstanding, end of period (in shares) | 4,281,403 |
Vested or expected to vest (in shares) | 4,225,180 |
Exercisable (in shares) | 1,433,234 |
Weighted Average Grant- Date Fair Value | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 10.24 |
Granted (in dollars per share) | $ / shares | 3.87 |
Forfeited or expired (in dollars per share) | $ / shares | 10.24 |
Outstanding, end of period (in dollars per share) | $ / shares | 5.98 |
Vested or expected to vest (in dollars per share) | $ / shares | 5.92 |
Exercisable (in dollars per share) | $ / shares | $ 5.99 |
Weighted Average Remaining Contractual Term | |
Outstanding | 5 years 4 months 24 days |
Expected to vest | 5 years 4 months 9 days |
Exercisable | 5 years 4 months 28 days |
COMMON STOCK AND SHARE-BASED _7
COMMON STOCK AND SHARE-BASED COMPENSATION (Restricted Stock Units) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Number of Restricted Stock Units | |||
Nonvested (in shares) | 1,979,812 | ||
Granted (in shares) | 74,479 | ||
Vested (in shares) | (822,249) | ||
Forfeited (in shares) | (191,207) | ||
Nonvested (in shares) | 1,040,835 | 1,979,812 | |
Weighted Average Grant- Date Fair Value | |||
Nonvested (in dollars per share) | $ 47.66 | ||
Granted (in dollars per share) | 18.57 | $ 40.92 | $ 66.95 |
Vested (in dollars per share) | 51.01 | ||
Forfeited (in dollars per share) | 41.49 | ||
Nonvested (in dollars per share) | $ 44.06 | $ 47.66 |
COMMON STOCK AND SHARE-BASED _8
COMMON STOCK AND SHARE-BASED COMPENSATION (Performance Shares) (Details) - Performance shares - $ / shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Number of Performance Shares | |||
Nonvested (in shares) | 1,438,091 | ||
Granted (in shares) | 130,251 | ||
Vested (in shares) | (255,324) | ||
Forfeited (in shares) | (624,595) | ||
Nonvested (in shares) | 688,423 | 1,438,091 | |
Weighted Average Grant- Date Fair Value | |||
Nonvested (ins dollars per share) | $ 56.32 | ||
Granted (in dollars per share) | 15.39 | $ 36.92 | $ 77 |
Vested (in dollars per share) | 40.74 | ||
Forfeited (in dollars per share) | 75.54 | ||
Nonvested (in dollars per share) | $ 36.92 | $ 56.32 |
PREFERRED STOCK (Narrative) (De
PREFERRED STOCK (Narrative) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Minimum | |||
Preferred Stock [Line Items] | |||
Redemption price (in dollars per share) | $ 25.75 | $ 25.75 | |
Maximum | |||
Preferred Stock [Line Items] | |||
Redemption price (in dollars per share) | $ 27.25 | $ 27.25 | |
Pacific Gas & Electric Co | |||
Preferred Stock [Line Items] | |||
Preferred stock dividend | $ 0 | $ 0 | $ 14,000,000 |
Pacific Gas & Electric Co | Nonredeemable Preferred Stock | |||
Preferred Stock [Line Items] | |||
Nonredeemable preferred stock outstanding | $ 145,000,000 | $ 145,000,000 | |
Preferred stock dividends per share, low range (in dollars per share) | $ 1.25 | ||
Preferred stock dividends per share, high range (in dollars per share) | $ 1.50 | ||
Pacific Gas & Electric Co | Nonredeemable Preferred Stock | Minimum | |||
Preferred Stock [Line Items] | |||
Preferred stock interest rate | 5.00% | 5.00% | |
Pacific Gas & Electric Co | Nonredeemable Preferred Stock | Maximum | 6.00% Series | |||
Preferred Stock [Line Items] | |||
Preferred stock interest rate | 6.00% | 6.00% | |
Pacific Gas & Electric Co | Redeemable Preferred Stock | |||
Preferred Stock [Line Items] | |||
Redeemable preferred stock outstanding | $ 113,000,000 | $ 113,000,000 | |
Preferred stock dividends per share, low range (in dollars per share) | $ 1.09 | ||
Preferred stock dividends per share, high range (in dollars per share) | $ 1.25 | ||
Pacific Gas & Electric Co | Redeemable Preferred Stock | Minimum | |||
Preferred Stock [Line Items] | |||
Preferred stock interest rate | 4.36% | 4.36% | |
Pacific Gas & Electric Co | Redeemable Preferred Stock | Maximum | 5% Series A | |||
Preferred Stock [Line Items] | |||
Preferred stock interest rate | 5.00% | 5.00% | |
No Par Value | PG&E Corporation | |||
Preferred Stock [Line Items] | |||
Preferred stock, shares authorized (in shares) | 80,000,000 | ||
$100 Par Value | Pacific Gas & Electric Co | |||
Preferred Stock [Line Items] | |||
Preferred stock, shares authorized (in shares) | 10,000,000 | ||
Preferred stock, par value (in dollars per share) | $ 100 | ||
$100 Par Value | PG&E Corporation | |||
Preferred Stock [Line Items] | |||
Preferred stock, shares authorized (in shares) | 5,000,000 | ||
Preferred stock, par value (in dollars per share) | $ 100 | ||
$25 Par Value | |||
Preferred Stock [Line Items] | |||
Preferred stock, shares authorized (in shares) | 75,000,000 | ||
Preferred stock, par value (in dollars per share) | $ 25 | ||
$25 Par Value | Pacific Gas & Electric Co | |||
Preferred Stock [Line Items] | |||
Preferred stock, par value (in dollars per share) | $ 25 |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |||
Income (loss) available for common shareholders | $ (7,656) | $ (6,851) | $ 1,646 |
Weighted average common shares outstanding, basic | 528 | 517 | 512 |
Add incremental shares from assumed conversions: | |||
Employee share-based compensation (in shares) | 0 | 0 | 1 |
Weighted average common share outstanding, diluted (in shares) | 528 | 517 | 513 |
Total earnings (loss) per common share, diluted (in dollars per share) | $ (14.50) | $ (13.25) | $ 3.21 |
INCOME TAXES (Schedule of Incom
INCOME TAXES (Schedule of Income Tax Provision) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Current: | |||
Federal | $ 1 | $ (5) | $ (10) |
State | 101 | (8) | 48 |
Deferred: | |||
Federal | (2,361) | (2,264) | 481 |
State | (1,136) | (1,009) | 6 |
Tax credits | (5) | (6) | (14) |
Income tax provision (benefit) | (3,400) | (3,292) | 511 |
Pacific Gas & Electric Co | |||
Current: | |||
Federal | 4 | 5 | 61 |
State | 94 | (7) | 50 |
Deferred: | |||
Federal | (2,363) | (2,278) | 326 |
State | (1,137) | (1,009) | 4 |
Tax credits | (5) | (6) | (14) |
Income tax provision (benefit) | $ (3,407) | $ (3,295) | $ 427 |
INCOME TAXES (Schedule of Defer
INCOME TAXES (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Pacific Gas & Electric Co | ||
Deferred income tax assets: | ||
Tax carryforwards | $ 1,308 | $ 650 |
Compensation | 92 | 121 |
Income tax regulatory liability | 0 | 79 |
Wildfire-related claims | 6,520 | 3,433 |
Operating lease liability | 640 | 0 |
Other | 121 | 93 |
Total deferred income tax assets | 8,681 | 4,376 |
Deferred income tax liabilities: | ||
Property related basis differences | 7,973 | 7,660 |
Regulatory balancing accounts | 381 | 118 |
Operating lease right of use asset | 640 | 0 |
Income tax regulatory asset | 71 | 0 |
Other | 58 | 3 |
Total deferred income tax liabilities | 9,123 | 7,781 |
Total net deferred income tax liabilities | 442 | 3,405 |
PG&E Corporation | ||
Deferred income tax assets: | ||
Tax carryforwards | 1,390 | 740 |
Compensation | 151 | 173 |
Income tax regulatory liability | 0 | 79 |
Wildfire-related claims | 6,520 | 3,433 |
Operating lease liability | 642 | 0 |
Other | 112 | 87 |
Total deferred income tax assets | 8,815 | 4,512 |
Deferred income tax liabilities: | ||
Property related basis differences | 7,984 | 7,672 |
Regulatory balancing accounts | 381 | 118 |
Operating lease right of use asset | 642 | 0 |
Income tax regulatory asset | 71 | 0 |
Other | 57 | 3 |
Total deferred income tax liabilities | 9,135 | 7,793 |
Total net deferred income tax liabilities | $ 320 | $ 3,281 |
INCOME TAXES (Schedule of Effec
INCOME TAXES (Schedule of Effective Income Tax Rate Reconciliation) (Details) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pacific Gas & Electric Co | |||
Federal statutory income tax rate | 21.00% | 21.00% | 35.00% |
State income tax (net of federal benefit) | 7.50% | 7.90% | 1.60% |
Effect of regulatory treatment of fixed asset differences | 2.80% | 3.60% | (16.80%) |
Tax credits | 0.10% | 0.10% | (1.10%) |
Compensation Related | 0.00% | (0.10%) | (0.90%) |
Tax Reform Adjustment | 0.00% | 0.10% | 3.00% |
Other, net | (0.50%) | 0.00% | (0.70%) |
Effective tax rate | 30.90% | 32.60% | 20.10% |
PG&E Corporation | |||
Federal statutory income tax rate | 21.00% | 21.00% | 35.00% |
State income tax (net of federal benefit) | 7.50% | 7.90% | 1.50% |
Effect of regulatory treatment of fixed asset differences | 2.80% | 3.60% | (16.50%) |
Tax credits | 0.10% | 0.10% | (1.10%) |
Compensation Related | 0.00% | (0.20%) | (1.00%) |
Tax Reform Adjustment | 0.00% | 0.10% | 6.80% |
Other, net | (0.60%) | 0.00% | (1.10%) |
Effective tax rate | 30.80% | 32.50% | 23.60% |
INCOME TAXES (Schedule of Chang
INCOME TAXES (Schedule of Change in Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pacific Gas & Electric Co | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Balance, beginning of period | $ 377 | $ 349 | $ 382 |
Reductions for tax position taken during a prior year | (1) | (27) | (71) |
Additions for tax position taken during the current year | 44 | 55 | 48 |
Settlements | 0 | 0 | (8) |
Expiration of statute | 0 | 0 | (3) |
Balance, end of period | 420 | 377 | 349 |
PG&E Corporation | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Balance, beginning of period | 377 | 349 | 388 |
Reductions for tax position taken during a prior year | (1) | (27) | (71) |
Additions for tax position taken during the current year | 44 | 55 | 48 |
Settlements | 0 | 0 | (14) |
Expiration of statute | 0 | 0 | (3) |
Balance, end of period | $ 420 | $ 377 | $ 349 |
INCOME TAXES (Narrative) (Detai
INCOME TAXES (Narrative) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Income Tax Disclosure [Abstract] | |
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year | $ 6 |
Decrease in unrecognized tax benefits is reasonably possible | $ 10 |
INCOME TAXES (Summary of Operat
INCOME TAXES (Summary of Operating Loss and Tax Credit Carryforward) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Federal | |
Operating Loss Carryforwards [Line Items] | |
Tax credit carryforward | $ 127 |
Federal | Pre-2018 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | 3,940 |
Federal | Post-2017 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | 1,777 |
State | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | 1,927 |
Tax credit carryforward | $ 96 |
DERIVATIVES (Volumes of Outstan
DERIVATIVES (Volumes of Outstanding Derivative Contracts) (Details) | Dec. 31, 2019MMBTUMWh | Dec. 31, 2018MMBTUMWh |
Forwards and Swaps | Natural Gas (MMBtus) | ||
Derivative [Line Items] | ||
Contract Volume | MMBTU | 131,896,159 | 177,750,349 |
Forwards and Swaps | Electricity (Megawatt-hours) | ||
Derivative [Line Items] | ||
Contract Volume | MWh | 18,675,852 | 3,833,490 |
Options | Natural Gas (MMBtus) | ||
Derivative [Line Items] | ||
Contract Volume | MMBTU | 14,720,000 | 13,735,405 |
Congestion revenue rights | Electricity (Megawatt-hours) | ||
Derivative [Line Items] | ||
Contract Volume | MWh | 308,467,999 | 340,783,089 |
DERIVATIVES (Outstanding Deriva
DERIVATIVES (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Derivatives And Hedging Activities [Line Items] | ||
Derivative asset, netting | $ 8 | $ (88) |
Derivative liability, netting | 14 | 10 |
Commodity Contract | Pacific Gas & Electric Co | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Assets | 5 | 90 |
Derivative asset, netting | 0 | 0 |
Cash Collateral | 6 | 98 |
Total Derivative Balance, Assets | 11 | 188 |
Commodity Contract | Pacific Gas & Electric Co | Current assets – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Assets | 36 | 44 |
Derivative asset, netting | (6) | (1) |
Cash Collateral | 4 | 89 |
Total Derivative Balance, Assets | 34 | 132 |
Commodity Contract | Pacific Gas & Electric Co | Other noncurrent assets – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Assets | 130 | 165 |
Derivative asset, netting | (6) | 0 |
Cash Collateral | 0 | 0 |
Total Derivative Balance, Assets | 124 | 165 |
Commodity Contract | Pacific Gas & Electric Co | Current liabilities – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Liabilities | (31) | (29) |
Derivative liability, netting | 6 | 1 |
Cash Collateral | 2 | 7 |
Total Derivative Balance, Liabilities | (23) | (21) |
Commodity Contract | Pacific Gas & Electric Co | Noncurrent liabilities – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Liabilities | (130) | (90) |
Derivative liability, netting | 6 | 0 |
Cash Collateral | 0 | 2 |
Total Derivative Balance, Liabilities | $ (124) | $ (88) |
FAIR VALUE MEASUREMENTS (Assets
FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Short-term investments | $ 1,323 | $ 1,593 |
Total nuclear decommissioning trusts | 3,703 | 3,138 |
Rabbi trusts | 173 | 160 |
Long-term disability trust | 166 | 162 |
Derivative asset, netting | (8) | 88 |
Total assets | 5,523 | 5,350 |
Derivative liability, netting | (14) | (10) |
Amount primarily related to deferred taxes on appreciation of investment value | 530 | 408 |
Electric | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative asset, netting | (11) | 51 |
Derivative liability, netting | (13) | (10) |
Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative asset, netting | 3 | 37 |
Derivative liability, netting | (1) | 0 |
Short-term investments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 6 | 29 |
Long-term disability trust | 10 | 7 |
Global equity securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 2,086 | 1,793 |
Fixed-income securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 1,590 | 1,300 |
Rabbi trusts | 100 | 93 |
Price risk management instruments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 158 | 297 |
TOTAL LIABILITIES | 147 | 109 |
Price risk management instruments | Electric | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 152 | 259 |
TOTAL LIABILITIES | 146 | 107 |
Price risk management instruments | Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 6 | 38 |
TOTAL LIABILITIES | 1 | 2 |
Life insurance contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Rabbi trusts | 73 | 67 |
Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Short-term investments | 1,323 | 1,593 |
Total nuclear decommissioning trusts | 2,954 | 2,483 |
Rabbi trusts | 0 | 0 |
Long-term disability trust | 10 | 7 |
Total assets | 4,287 | 4,083 |
Level 1 | Short-term investments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 6 | 29 |
Long-term disability trust | 10 | 7 |
Level 1 | Global equity securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 2,086 | 1,793 |
Level 1 | Fixed-income securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 862 | 661 |
Rabbi trusts | 0 | 0 |
Level 1 | Price risk management instruments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 0 | 0 |
TOTAL LIABILITIES | 1 | 4 |
Level 1 | Price risk management instruments | Electric | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 0 | 0 |
TOTAL LIABILITIES | 1 | 4 |
Level 1 | Price risk management instruments | Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 0 | 0 |
TOTAL LIABILITIES | 0 | 0 |
Level 1 | Life insurance contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Rabbi trusts | 0 | 0 |
Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Short-term investments | 0 | 0 |
Total nuclear decommissioning trusts | 728 | 639 |
Rabbi trusts | 173 | 160 |
Long-term disability trust | 0 | 0 |
Total assets | 906 | 805 |
Level 2 | Short-term investments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 0 | 0 |
Long-term disability trust | 0 | 0 |
Level 2 | Global equity securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 0 | 0 |
Level 2 | Fixed-income securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 728 | 639 |
Rabbi trusts | 100 | 93 |
Level 2 | Price risk management instruments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 5 | 6 |
TOTAL LIABILITIES | 4 | 7 |
Level 2 | Price risk management instruments | Electric | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 2 | 5 |
TOTAL LIABILITIES | 2 | 5 |
Level 2 | Price risk management instruments | Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 3 | 1 |
TOTAL LIABILITIES | 2 | 2 |
Level 2 | Life insurance contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Rabbi trusts | 73 | 67 |
Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Short-term investments | 0 | 0 |
Total nuclear decommissioning trusts | 0 | 0 |
Rabbi trusts | 0 | 0 |
Long-term disability trust | 0 | 0 |
Total assets | 161 | 203 |
Level 3 | Short-term investments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 0 | 0 |
Long-term disability trust | 0 | 0 |
Level 3 | Global equity securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 0 | 0 |
Level 3 | Fixed-income securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 0 | 0 |
Rabbi trusts | 0 | 0 |
Level 3 | Price risk management instruments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 161 | 203 |
TOTAL LIABILITIES | 156 | 108 |
Level 3 | Price risk management instruments | Electric | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 161 | 203 |
TOTAL LIABILITIES | 156 | 108 |
Level 3 | Price risk management instruments | Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 0 | 0 |
TOTAL LIABILITIES | 0 | 0 |
Level 3 | Life insurance contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Rabbi trusts | 0 | 0 |
Assets measured at NAV | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 21 | 16 |
Long-term disability trust | $ 156 | $ 155 |
FAIR VALUE MEASUREMENTS (Level
FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions | Dec. 31, 2019USD ($)$ / shares | Dec. 31, 2018USD ($)$ / shares |
Market approach | Congestion revenue rights | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets | $ | $ 140 | $ 203 |
Liabilities | $ | 44 | 75 |
Discounted cash flow | Power purchase agreements | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets | $ | 21 | 0 |
Liabilities | $ | $ 112 | $ 33 |
CRR auction prices | Market approach | Congestion revenue rights | Minimum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | (20.20) | (18.61) |
CRR auction prices | Market approach | Congestion revenue rights | Maximum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | 20.20 | 32.26 |
CRR auction prices | Market approach | Congestion revenue rights | Weighted average price | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | 0.28 | |
Forward prices | Discounted cash flow | Power purchase agreements | Minimum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | 11.77 | 19.81 |
Forward prices | Discounted cash flow | Power purchase agreements | Maximum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | 59.38 | 38.80 |
Forward prices | Discounted cash flow | Power purchase agreements | Weighted average price | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | 33.62 |
FAIR VALUE MEASUREMENTS (Leve_2
FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price risk management instruments - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Asset (liability) balance, beginning of period | $ 95 | $ 42 |
Included in regulatory assets and liabilities or balancing accounts | (90) | 53 |
Asset (liability) balance, end of period | $ 5 | $ 95 |
FAIR VALUE MEASUREMENTS (Carryi
FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Pacific Gas & Electric Co | Pre-Petition Debt | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt instrument, face amount | $ 17,900 | |
Carrying Amount | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | 0 | $ 350 |
Carrying Amount | Pacific Gas & Electric Co | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | 1,500 | 17,450 |
Level 2 | Estimate of Fair Value Measurement | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | 0 | 350 |
Level 2 | Estimate of Fair Value Measurement | Pacific Gas & Electric Co | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | $ 1,500 | $ 14,747 |
FAIR VALUE MEASUREMENTS (Schedu
FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains Losses Related to Available-for-sale Investments) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | $ 2,011 | $ 1,885 |
Total Unrealized Gains | 1,698 | 1,276 |
Total Unrealized Losses | (6) | (23) |
Total Fair Value | 3,703 | 3,138 |
Amount primarily related to deferred taxes on appreciation of investment value | 530 | 408 |
Short-term investments | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 6 | 29 |
Total Unrealized Gains | 0 | 0 |
Total Unrealized Losses | 0 | 0 |
Total Fair Value | 6 | 29 |
Global equity securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 500 | 568 |
Total Unrealized Gains | 1,609 | 1,246 |
Total Unrealized Losses | (2) | (5) |
Total Fair Value | 2,107 | 1,809 |
Fixed-income securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 1,505 | 1,288 |
Total Unrealized Gains | 89 | 30 |
Total Unrealized Losses | (4) | (18) |
Total Fair Value | $ 1,590 | $ 1,300 |
FAIR VALUE MEASUREMENTS (Sche_2
FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Debt Securities, Available-for-sale [Line Items] | ||
Total maturities of fixed-income securities | $ 3,703 | $ 3,138 |
Fixed-income securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Less than 1 year | 42 | |
1–5 years | 488 | |
5–10 years | 397 | |
More than 10 years | 663 | |
Total maturities of fixed-income securities | $ 1,590 | $ 1,300 |
FAIR VALUE MEASUREMENTS (Sche_3
FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |||
Proceeds from sales and maturities of nuclear decommissioning investments | $ 956 | $ 1,412 | $ 1,291 |
Gross realized gains on securities | 69 | 54 | 53 |
Gross realized losses on securities | $ (14) | $ (24) | $ (11) |
EMPLOYEE BENEFIT PLANS (Narrati
EMPLOYEE BENEFIT PLANS (Narrative) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019USD ($)noncallable_bond | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Defined Benefit Plan Disclosure [Line Items] | |||
Assumed health care cost trend rate | 6.30% | ||
Ultimate trend rate | 4.50% | ||
Assumed return | 5.70% | ||
10 year actual rate of return | 9.30% | ||
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used (noncallable bond) | noncallable_bond | 936 | ||
Total fair value of trust other net liabilities | $ 99 | $ 99 | |
Total fair value of trust other net assets | 22 | 22 | |
Retirement savings plan expense | $ 109 | $ 105 | $ 103 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
10 year actual rate of return | 5.70% | 6.00% | 6.20% |
Company contributions | $ 328 | $ 334 | |
Expected employer contribution next year | 327 | ||
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Company contributions | 29 | 31 | |
Expected employer contribution next year | 15 | ||
Pacific Gas & Electric Co | Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Public utilities, approved rate, amount | $ 328 | $ 328 |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Funded Status: | |||
Noncurrent liability | $ (1,884) | $ (2,119) | |
Pension Plan | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of year | 15,312 | 16,652 | |
Actual return on plan assets | 3,713 | (923) | |
Company contributions | 328 | 334 | |
Benefits and expenses paid | (806) | (751) | |
Fair value of plan assets at end of year | 18,547 | 15,312 | $ 16,652 |
Change in benefit obligation: | |||
Benefit obligation at beginning of year | 17,407 | 18,757 | |
Service cost for benefits earned | 443 | 514 | 472 |
Interest cost | 758 | 687 | 714 |
Actuarial (gain) loss | 2,723 | (1,800) | |
Plan amendments | 0 | 0 | |
Benefits and expenses paid | (806) | (751) | |
Benefit obligation at end of year | 20,525 | 17,407 | 18,757 |
Funded Status: | |||
Current liability | (14) | (8) | |
Noncurrent liability | (1,964) | (2,087) | |
Net (liability) asset at end of year | (1,978) | (2,095) | |
Accumulated benefit obligation | 18,400 | 15,800 | |
PBOP Plans | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of year | 2,258 | 2,420 | |
Actual return on plan assets | 474 | (108) | |
Company contributions | 29 | 31 | |
Plan participant contribution | 82 | 81 | |
Benefits and expenses paid | (165) | (166) | |
Fair value of plan assets at end of year | 2,678 | 2,258 | 2,420 |
Change in benefit obligation: | |||
Benefit obligation at beginning of year | 1,745 | 1,897 | |
Service cost for benefits earned | 56 | 66 | 59 |
Interest cost | 76 | 69 | 77 |
Actuarial (gain) loss | 22 | (221) | |
Benefits and expenses paid | (150) | (150) | |
Federal subsidy on benefits paid | 2 | 3 | |
Plan participant contributions | 81 | 81 | |
Benefit obligation at end of year | 1,832 | 1,745 | $ 1,897 |
Funded Status: | |||
Noncurrent asset | 879 | 545 | |
Noncurrent liability | (33) | (32) | |
Net (liability) asset at end of year | $ 846 | $ 513 |
EMPLOYEE BENEFIT PLANS (Compone
EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost for benefits earned | $ 443 | $ 514 | $ 472 |
Interest cost | 758 | 687 | 714 |
Expected return on plan assets | (906) | (1,021) | (770) |
Amortization of prior service cost | (6) | (6) | (7) |
Amortization of net actuarial loss | 3 | 5 | 22 |
Net periodic benefit cost | 292 | 179 | 431 |
Less: transfer to regulatory account | 42 | 157 | (92) |
Total expense recognized | 334 | 336 | 339 |
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost for benefits earned | 56 | 66 | 59 |
Interest cost | 76 | 69 | 77 |
Expected return on plan assets | (123) | (130) | (97) |
Amortization of prior service cost | 14 | 14 | 15 |
Amortization of net actuarial loss | (3) | (5) | 4 |
Net periodic benefit cost | $ 20 | $ 14 | $ 58 |
EMPLOYEE BENEFIT PLANS (Estimat
EMPLOYEE BENEFIT PLANS (Estimated Amortized Net Periodic Benefit) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Pension Plan | |
Defined Benefit Plan Disclosure [Line Items] | |
Unrecognized prior service cost | $ (6) |
Unrecognized net loss | 3 |
Total | (3) |
PBOP Plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Unrecognized prior service cost | 14 |
Unrecognized net loss | (21) |
Total | $ (7) |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Expected return on plan assets | 9.30% | ||
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 3.46% | 4.35% | 3.64% |
Rate of future compensation increases | 3.90% | 3.90% | 3.90% |
Expected return on plan assets | 5.70% | 6.00% | 6.20% |
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Rate of future compensation increases | 0.00% | 0.00% | 0.00% |
PBOP Plans | Minimum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 3.37% | 4.29% | 3.60% |
Expected return on plan assets | 3.50% | 3.60% | 3.30% |
PBOP Plans | Maximum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 3.47% | 4.37% | 3.67% |
Expected return on plan assets | 6.60% | 6.80% | 7.10% |
EMPLOYEE BENEFIT PLANS (Sched_2
EMPLOYEE BENEFIT PLANS (Schedule of Assumed Health Care Cost Trend) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract] | |
Effect on postretirement benefit obligation, One-Percentage-Point Increase | $ 131 |
Effect on postretirement benefit obligation, One-Percentage-Point Decrease | (129) |
Effect on service and interest cost, One-Percentage-Point Increase | 9 |
Effect on service and interest cost, One-Percentage-Point Decrease | $ (9) |
EMPLOYEE BENEFIT PLANS (Target
EMPLOYEE BENEFIT PLANS (Target Asset Allocation Percentages) (Details) | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100.00% | 100.00% | |
Pension Plan | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 29.00% | 29.00% | |
Pension Plan | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 5.00% | 5.00% | |
Pension Plan | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 8.00% | 8.00% | |
Pension Plan | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 58.00% | 58.00% | |
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100.00% | 100.00% | |
PBOP Plans | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 33.00% | 33.00% | |
PBOP Plans | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 3.00% | 3.00% | |
PBOP Plans | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 6.00% | 6.00% | |
PBOP Plans | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 58.00% | 58.00% | |
Scenario, Forecast | Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100.00% | ||
Scenario, Forecast | Pension Plan | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 30.00% | ||
Scenario, Forecast | Pension Plan | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 2.00% | ||
Scenario, Forecast | Pension Plan | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 8.00% | ||
Scenario, Forecast | Pension Plan | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 60.00% | ||
Scenario, Forecast | PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100.00% | ||
Scenario, Forecast | PBOP Plans | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 28.00% | ||
Scenario, Forecast | PBOP Plans | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 2.00% | ||
Scenario, Forecast | PBOP Plans | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 8.00% | ||
Scenario, Forecast | PBOP Plans | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 62.00% |
EMPLOYEE BENEFIT PLANS (Sched_3
EMPLOYEE BENEFIT PLANS (Schedule of Fair Value of Plan Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | $ 21,324 | $ 17,548 | |
Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Assets measured at NAV | 15 | 8 | $ 4 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 18,636 | 15,284 | |
Assets measured at NAV | 18,547 | 15,312 | 16,652 |
Pension Plan | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 844 | 355 | |
Pension Plan | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1,650 | 1,145 | |
Pension Plan | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1 | 0 | |
Pension Plan | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 549 | 461 | |
Pension Plan | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 8,655 | 7,121 | |
Pension Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 5,038 | 3,836 | |
Pension Plan | Level 1 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 613 | 333 | |
Pension Plan | Level 1 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1,650 | 1,145 | |
Pension Plan | Level 1 | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 1 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 548 | 461 | |
Pension Plan | Level 1 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 2,227 | 1,897 | |
Pension Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 6,646 | 5,238 | |
Pension Plan | Level 2 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 231 | 22 | |
Pension Plan | Level 2 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 2 | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1 | 0 | |
Pension Plan | Level 2 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1 | 0 | |
Pension Plan | Level 2 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 6,413 | 5,216 | |
Pension Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 15 | 8 | |
Pension Plan | Level 3 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 3 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 3 | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 3 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 3 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 15 | 8 | |
Pension Plan | Assets measured at NAV | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Assets measured at NAV | 6,937 | 6,202 | |
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 2,688 | 2,264 | |
Assets measured at NAV | 2,678 | 2,258 | $ 2,420 |
PBOP Plans | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 37 | 33 | |
PBOP Plans | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 151 | 115 | |
PBOP Plans | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 58 | 50 | |
PBOP Plans | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1,069 | 1,010 | |
PBOP Plans | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 439 | 351 | |
PBOP Plans | Level 1 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 37 | 33 | |
PBOP Plans | Level 1 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 151 | 115 | |
PBOP Plans | Level 1 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 58 | 50 | |
PBOP Plans | Level 1 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 193 | 153 | |
PBOP Plans | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 875 | 857 | |
PBOP Plans | Level 2 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 2 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 2 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 2 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 875 | 857 | |
PBOP Plans | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1 | 0 | |
PBOP Plans | Level 3 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 3 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 3 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 3 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1 | 0 | |
PBOP Plans | Assets measured at NAV | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Assets measured at NAV | $ 1,373 | $ 1,056 |
EMPLOYEE BENEFIT PLANS (Sched_4
EMPLOYEE BENEFIT PLANS (Schedule of Level 3 Reconciliation) (Details) - Level 3 - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Fair value of plan assets at beginning of year | $ 8 | $ 4 |
Actual return on plan assets: | ||
Relating to assets still held at the reporting date | 0 | (3) |
Relating to assets sold during the period | 0 | 0 |
Purchases, issuances, sales, and settlements: | ||
Purchases | 11 | 6 |
Settlements | (4) | 1 |
Fair value of plan assets at end of year | $ 15 | $ 8 |
EMPLOYEE BENEFIT PLANS (Sched_5
EMPLOYEE BENEFIT PLANS (Schedule of Estimated Benefits Expected to Be Paid) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Pension Plan | |
Defined Benefit Plan Disclosure [Line Items] | |
2020 | $ 801 |
2021 | 874 |
2022 | 910 |
2023 | 944 |
2024 | 975 |
Thereafter in the succeeding five years | 5,238 |
PBOP Plans | |
Defined Benefit Plan Disclosure [Line Items] | |
2020 | 92 |
2021 | 94 |
2022 | 92 |
2023 | 95 |
2024 | 98 |
Thereafter in the succeeding five years | 482 |
Federal Subsidy | |
Defined Benefit Plan Disclosure [Line Items] | |
2020 | (8) |
2021 | (9) |
2022 | (2) |
2023 | (2) |
2024 | (3) |
Thereafter in the succeeding five years | $ (8) |
RELATED PARTY AGREEMENTS AND _3
RELATED PARTY AGREEMENTS AND TRANSACTIONS (Summary of Significant Related Party Transactions) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Administrative services provided to PG&E Corporation | |||
Related Party Transaction [Line Items] | |||
Utility revenues from | $ 4 | $ 4 | $ 8 |
Administrative services received from PG&E Corporation | |||
Related Party Transaction [Line Items] | |||
Utility expenses from | 107 | 94 | 65 |
Utility employee benefit due to PG&E Corporation | |||
Related Party Transaction [Line Items] | |||
Utility expenses from | $ 42 | $ 76 | $ 73 |
RELATED PARTY AGREEMENTS AND _4
RELATED PARTY AGREEMENTS AND TRANSACTIONS (Narrative) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Related Party Transaction [Line Items] | ||
Current receivables | $ 60 | $ 33 |
Current payables | $ 118 | $ 38 |
WILDFIRE-RELATED CONTINGENCIES
WILDFIRE-RELATED CONTINGENCIES (Pre-petition Wildfire-Related Claims) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Sep. 22, 2019 | |
Loss Contingencies [Line Items] | |||
Total wildfire-related claims | $ 25,500 | ||
Pacific Gas & Electric Co | |||
Loss Contingencies [Line Items] | |||
Total wildfire-related claims | 25,500 | $ 14,200 | |
Subrogation insurance claims | 11,000 | ||
Subrogation claims, professional fees | 47.5 | $ 55 | |
Legal and other costs | 152 | $ 245 | |
Pacific Gas & Electric Co | Public Entity Wildfire Claims | |||
Loss Contingencies [Line Items] | |||
Total wildfire-related claims | 1,000 | ||
Pacific Gas & Electric Co | TCC Wildfire-related Claims | |||
Loss Contingencies [Line Items] | |||
Total wildfire-related claims | $ 13,500 |
WILDFIRE-RELATED CONTINGENCIE_2
WILDFIRE-RELATED CONTINGENCIES (2018 Camp Fire Background) (Details) - Pacific Gas & Electric Co - 2018 Camp fire | Nov. 08, 2018afatalitybuilding |
Loss Contingencies [Line Items] | |
Number of acres burned (acre) | a | 153,336 |
Number of fatalities (fatality) | fatality | 85 |
Number of other structures destroyed (structures) | building | 18,804 |
WILDFIRE-RELATED CONTINGENCIE_3
WILDFIRE-RELATED CONTINGENCIES (2017 Northern California Wildfires Background) (Details) - Pacific Gas & Electric Co - 2017 Northern California wildfires | Oct. 30, 2017awildfirefacilitystructure |
Loss Contingencies [Line Items] | |
Number of wildfires (wildfire) | 21 |
Number of acres burned (acre) | a | 245,000 |
Number of destroyed structures (structures) | structure | 8,900 |
Number of fatalities (fatality) | facility | 44 |
Number of wildfires caused by equipment (wildfire) | 20 |
WILDFIRE-RELATED CONTINGENCIE_4
WILDFIRE-RELATED CONTINGENCIES (Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires) (Details) $ in Millions | Jan. 28, 2019complaintplaintiff | Dec. 31, 2019USD ($) |
Pacific Gas & Electric Co | 2017 Northern California wildfires and the 2018 Camp fire | ||
Loss Contingencies [Line Items] | ||
Amount of claims filed | $ 503 | |
FEMA | 2017 Northern California wildfires | ||
Loss Contingencies [Line Items] | ||
Amount of claims filed | 1,200 | |
FEMA | 2018 Camp fire | ||
Loss Contingencies [Line Items] | ||
Amount of claims filed | 2,600 | |
Cal Fire | 2017 Northern California wildfires | ||
Loss Contingencies [Line Items] | ||
Amount of claims filed | 133 | |
Cal Fire | 2018 Camp fire | ||
Loss Contingencies [Line Items] | ||
Amount of claims filed | 110 | |
OES | 2017 Northern California wildfires | ||
Loss Contingencies [Line Items] | ||
Amount of claims filed | 347 | |
OES | 2018 Camp fire | ||
Loss Contingencies [Line Items] | ||
Amount of claims filed | 2,300 | |
California Department Of Transportation | 2018 Camp fire | ||
Loss Contingencies [Line Items] | ||
Amount of claims filed | $ 217 | |
Pending Litigation | Complaints Against PG&E Corporation and the Utility in Sacramento County Superior Court | 2018 Camp fire | ||
Loss Contingencies [Line Items] | ||
Number of lawsuits filed against company (lawsuit, complaint) | complaint | 100 | |
Number of plaintiffs in lawsuit (at least) (plaintiff) | plaintiff | 4,200 | |
Pending Litigation | Complaints Against PG&E Corporation and the Utility in Sacramento County Superior Court, Classified as Class Action | 2018 Camp fire | ||
Loss Contingencies [Line Items] | ||
Number of lawsuits filed against company (lawsuit, complaint) | complaint | 9 | |
Pending Litigation | Complaints Against PG&E Corporation and the Utility in San Francisco Counties Superior Courts | 2017 Northern California wildfires | ||
Loss Contingencies [Line Items] | ||
Number of lawsuits filed against company (lawsuit, complaint) | complaint | 750 | |
Number of plaintiffs in lawsuit (at least) (plaintiff) | plaintiff | 3,800 | |
Pending Litigation | Lawsuits Against PG&E Corporation and the Utility in the Sonoma, Napa and San Francisco Counties Superior Courts, Classified As Class Actions | 2017 Northern California wildfires | ||
Loss Contingencies [Line Items] | ||
Number of lawsuits filed against company (lawsuit, complaint) | complaint | 5 | |
Pending Litigation | Subrogation Complaints Against PG&E Corporation and the Utility in San Francisco County Superior Courts | 2017 Northern California wildfires | ||
Loss Contingencies [Line Items] | ||
Number of lawsuits filed against company (lawsuit, complaint) | complaint | 52 | |
Pending Litigation | Subrogation Complaints Against PG&E Corporation and the Utility in Sacramento County Superior Court | 2017 Northern California wildfires | ||
Loss Contingencies [Line Items] | ||
Number of lawsuits filed against company (lawsuit, complaint) | complaint | 39 |
WILDFIRE-RELATED CONTINGENCIE_5
WILDFIRE-RELATED CONTINGENCIES (Plan Support Agreements with Public Entities) (Details) - Settled Litigation $ in Millions | Jun. 18, 2019USD ($) |
Public Entity Wildfire Claims | |
Loss Contingencies [Line Items] | |
Settlement reached | $ 1,000 |
Fund to support defense or resolution of claims per plan support agreement | 10 |
2017 Northern California Wildfire Public Entities | |
Loss Contingencies [Line Items] | |
Settlement reached | 415 |
Town Of Paradise Wildfire Claims | |
Loss Contingencies [Line Items] | |
Settlement reached | 270 |
County Of Butte Wildfire Claims | |
Loss Contingencies [Line Items] | |
Settlement reached | 252 |
Paradise Recreation & Park District Wildfire Claims | |
Loss Contingencies [Line Items] | |
Settlement reached | 47.5 |
County Of Yuba Wildfire Claims | |
Loss Contingencies [Line Items] | |
Settlement reached | 12.5 |
Calaveras County Water District Wildfire Claims | |
Loss Contingencies [Line Items] | |
Settlement reached | $ 3 |
WILDFIRE- RELATED CONTINGENCIES
WILDFIRE- RELATED CONTINGENCIES (Restructuring Support Agreement) (Details) $ in Millions | Sep. 22, 2019USD ($) | Dec. 31, 2019USD ($) | Dec. 16, 2019USD ($) | Dec. 31, 2018USD ($) |
Loss Contingencies [Line Items] | ||||
Wildfire-related claims | $ 25,500 | |||
Pacific Gas & Electric Co | ||||
Loss Contingencies [Line Items] | ||||
TCC claims settlement, amount | $ 11,000 | |||
Subrogation claims, professional fees | $ 55 | 47.5 | ||
Wildfire-related claims | 25,500 | $ 14,200 | ||
Cash | $ 1,350 | |||
Common stock | $ 6,750 | |||
Multiplier, normalized estimated net income | 14.9 | |||
Number of fully diluted shares of the reorganized, percentage | 20.90% | |||
Pacific Gas & Electric Co | All Other Wildfire-related Claims | ||||
Loss Contingencies [Line Items] | ||||
Wildfire-related claims | $ 13,500 | |||
Pacific Gas & Electric Co | Effective Date | ||||
Loss Contingencies [Line Items] | ||||
Cash contribution by company | $ 5,400 | |||
Pacific Gas & Electric Co | On Or Before January 15, 2021 | ||||
Loss Contingencies [Line Items] | ||||
Cash | 650 | |||
Pacific Gas & Electric Co | On Or Before January 15, 2022 | ||||
Loss Contingencies [Line Items] | ||||
Cash | $ 700 |
WILDFIRE-RELATED CONTINGENCIE_6
WILDFIRE-RELATED CONTINGENCIES (Third-Party Claims) (Details) household in Thousands, $ in Millions | Jan. 28, 2019contractorhouseholdplaintiffcomplaint | Apr. 13, 2017USD ($) | Nov. 30, 2018USD ($) | May 31, 2017USD ($) | Sep. 30, 2018districtentity | May 01, 2018plaintiff | May 23, 2016contractor |
Loss Contingencies [Line Items] | |||||||
Number of plaintiffs in which agreements were made with | plaintiff | 2 | ||||||
2015 Butte fire | Pacific Gas & Electric Co | |||||||
Loss Contingencies [Line Items] | |||||||
Number of vegetation management contractors (contractor) | contractor | 2 | ||||||
Number of complaints filed (complaint) | complaint | 95 | ||||||
Number of plaintiffs (plaintiff) | plaintiff | 3,900 | ||||||
Number of households represented in court (household) | household | 2 | ||||||
Number of vegetation management contractors dismissed from complaints (contractor) | contractor | 2 | ||||||
Number of plaintiffs, smaller public entities (plaintiff) | entity | 4 | ||||||
Number of plaintiffs, fire districts (plaintiff) | district | 3 | ||||||
Fire fighting costs recovery requested | $ 87 | ||||||
Value of claims brought against the company | $ 190 | ||||||
Value of claims brought against the company, proof of claim | $ 107 | ||||||
2015 Butte fire | Pacific Gas & Electric Co | County of Calaveras | |||||||
Loss Contingencies [Line Items] | |||||||
Settlement reached | $ 25 |
WILDFIRE-RELATED CONTINGENCIE_7
WILDFIRE-RELATED CONTINGENCIES (2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge) (Details) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Sep. 30, 2019USD ($) | Jun. 30, 2019USD ($) | Dec. 31, 2019USD ($)wild_fire | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2015USD ($) | |
Loss Contingencies [Line Items] | ||||||
Wildfire-related claims, net of insurance recoveries | $ 11,435 | $ 11,771 | $ 0 | |||
Wildfire-related claims, net of insurance recoveries, additional charge | 5,000 | |||||
Wildfire-related claims, charges during period | 11,400 | |||||
Wildfire-related claims | 25,500 | |||||
Pacific Gas & Electric Co | ||||||
Loss Contingencies [Line Items] | ||||||
Wildfire-related claims, net of insurance recoveries | 11,435 | 11,771 | $ 0 | |||
Wildfire-related claims | $ 25,500 | 14,200 | ||||
2018 Camp Fire and 2017 Northern California Wildfires | ||||||
Loss Contingencies [Line Items] | ||||||
Number of fires with probable losses (wildfire) | wild_fire | 21 | |||||
2017 Northern California wildfires | ||||||
Loss Contingencies [Line Items] | ||||||
Wildfire-related claims, net of insurance recoveries | $ 2,500 | $ 3,900 | $ 14,000 | |||
2017 Northern California Wildfires, Other Than Tubbs And 37 Fires | ||||||
Loss Contingencies [Line Items] | ||||||
Number of fires with probable losses (wildfire) | wild_fire | 37 | |||||
Natural Gas Explosion | Pacific Gas & Electric Co | ||||||
Loss Contingencies [Line Items] | ||||||
Accrued losses | $ 1,600 | |||||
Loss contingency liability | $ 558 |
WILDFIRE-RELATED CONTINGENCIE_8
WILDFIRE-RELATED CONTINGENCIES (2019 Kincade Fire) (Details) - 2019 Kincade Fire | Nov. 04, 2019numberOfPeople | Oct. 23, 2019anumberOfStructurecustomerstructurefacilityinjury |
Loss Contingencies [Line Items] | ||
Number of acres burned (acre) | a | 77,758 | |
Number of fatalities (fatality) | facility | 0 | |
Number of injuries | injury | 4 | |
Number of structures destroyed (structure) | structure | 374 | |
Number of residences destroyed (residence) | 174 | |
Number of commercial structures destroyed (structure) | 11 | |
Number of other structures destroyed (structures) | 189 | |
Number of structures damaged (structure) | 60 | |
Number of residential structures damaged (structure) | 35 | |
Number of commercial structures damaged (structure) | 1 | |
Number of other structures damaged (structure) | 24 | |
Number of people part of mandatory evacuation order | numberOfPeople | 200,000 | |
Number of customers without power | customer | 27,837 |
WILDFIRE-RELATED CONTINGENCIE_9
WILDFIRE-RELATED CONTINGENCIES (Loss Recoveries) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Loss Contingencies [Line Items] | |||
Reimbursements | $ (35) | $ 1,698 | $ 21 |
Pacific Gas & Electric Co | |||
Loss Contingencies [Line Items] | |||
Reimbursements | (35) | 1,698 | $ 21 |
2015 Butte fire | |||
Loss Contingencies [Line Items] | |||
Insurance receivable | 50 | 85 | |
2015 Butte fire | Pacific Gas & Electric Co | |||
Loss Contingencies [Line Items] | |||
Coverage for third party liability | 922 | ||
Probable insurance recoveries | 922 | ||
Cumulative reimbursements from insurance policies | 60 | ||
Insurance receivable | 50 | $ 85 | |
Reimbursements | $ 35 |
WILDFIRE-RELATED CONTINGENCI_10
WILDFIRE-RELATED CONTINGENCIES (Insurance) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Jul. 31, 2019 | Dec. 31, 2018 |
2018 Camp Fire and 2017 Northern California Wildfires | |||
Loss Contingencies [Line Items] | |||
Liability insurance coverage | $ 1,400 | ||
Liability insurance coverage, general liability | 700 | ||
Initial self-insured retention per occurrence | 10 | ||
Liability insurance coverage, property damages | 700 | ||
Liability insurance coverage, property damages, reinsurance | $ 200 | ||
Insurance Coverage for Wildfire Events | |||
Loss Contingencies [Line Items] | |||
Liability insurance coverage | $ 430 | ||
Insurance Coverage for Wildfire Events | August 1, 2019 through July 31, 2020 | |||
Loss Contingencies [Line Items] | |||
Liability insurance coverage | 430 | ||
Initial self-insured retention per occurrence | 10 | ||
Insurance Coverage for Wildfire Liabilities | |||
Loss Contingencies [Line Items] | |||
Liability insurance coverage | 1,000 | ||
Initial self-insured retention per occurrence | 10 | ||
Insurance Coverage for Wildfire Liabilities | August 1, 2019 through July 31, 2020 | |||
Loss Contingencies [Line Items] | |||
Liability insurance coverage | 520 | ||
Insurance Coverage for Wildfire Liabilities | September 3, 2019 through September 2, 2020 | |||
Loss Contingencies [Line Items] | |||
Liability insurance coverage | 480 | ||
2018 Camp fire | |||
Loss Contingencies [Line Items] | |||
Settlement reached | 1,380 | ||
Insurance receivable | 1,380 | $ 1,380 | |
2017 Northern California wildfires | |||
Loss Contingencies [Line Items] | |||
Settlement reached | 843 | ||
Insurance receivable | $ 807 | $ 829 |
WILDFIRE-RELATED CONTINGENCI_11
WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details) - 2018 Camp Fire and 2017 Northern California Wildfires | Jul. 08, 2019 |
Loss Contingencies [Line Items] | |
Customer Harm Threshold, potential regulatory adjustment, percentage | 20.00% |
Customer Harm Threshold, Potential regulatory adjustment, percentage of total disallowed wildlife liability | 5.00% |
WILDFIRE-RELATED CONTINGENCI_12
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Derivative Litigation) (Details) | Nov. 20, 2017lawsuit |
Derivative Lawsuits Filed in the San Francisco County Superior Court | Breach of Fiduciary Duties | |
Loss Contingencies [Line Items] | |
Number of lawsuits filed against company (lawsuit, complaint) | 2 |
WILDFIRE-RELATED CONTINGENCI_13
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Class Action Litigation) (Details) - Securities Class Actions Filed in United States District Court for the Northern District of California | Feb. 22, 2019offering | Jun. 30, 2018lawsuit |
Loss Contingencies [Line Items] | ||
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit | 2 | |
Number of public offerings of notes with complaints against underwriters (offering) | offering | 4 |
WILDFIRE-RELATED CONTINGENCI_14
WILDFIRE-RELATED CONTINGENCIES (District Attorneys Offices Investigations) (Details) $ in Millions | 1 Months Ended |
Oct. 31, 2018USD ($) | |
Complaints Brought By Butte County District Attorney | Wildfires | Pacific Gas & Electric Co | |
Loss Contingencies [Line Items] | |
Settlement expense | $ 1.5 |
WILDFIRE-RELATED CONTINGENCI_15
WILDFIRE-RELATED CONTINGENCIES (Clean-up and Repair Costs) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Loss Contingencies [Line Items] | |||
Capital expenditures | $ 826 | $ 368 | $ 501 |
Total long-term regulatory assets | 6,066 | 4,964 | |
Catastrophic event memorandum account | |||
Loss Contingencies [Line Items] | |||
Total long-term regulatory assets | 656 | 790 | |
Pacific Gas & Electric Co | |||
Loss Contingencies [Line Items] | |||
Capital expenditures | 826 | 368 | $ 501 |
Total long-term regulatory assets | 6,066 | $ 4,964 | |
Pacific Gas & Electric Co | 2018 Camp fire | |||
Loss Contingencies [Line Items] | |||
Clean-up and repair costs | 772 | ||
Capital expenditures | 323 | ||
Pacific Gas & Electric Co | 2017 Northern California wildfires | |||
Loss Contingencies [Line Items] | |||
Clean-up and repair costs | 357 | ||
Capital expenditures | 180 | ||
Pacific Gas & Electric Co | Catastrophic event memorandum account | 2018 Camp fire | |||
Loss Contingencies [Line Items] | |||
Total long-term regulatory assets | 0 | ||
Pacific Gas & Electric Co | Catastrophic event memorandum account | 2017 Northern California wildfires | |||
Loss Contingencies [Line Items] | |||
Total long-term regulatory assets | $ 69 |
WILDFIRE-RELATED CONTINGENCI_16
WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Aug. 02, 2019 | Jul. 12, 2019 |
Loss Contingencies [Line Items] | |||
Disallowance cap, transmission and distribution equity rate base | $ 2,300 | ||
Expected capitalization, proceeds of bond | $ 10,500 | ||
Expected capitalization, initial contribution | 7,500 | ||
Expected capitalization, annual contribution | 300 | ||
Expected wildfire fund allocation metric, percentage | 64.20% | ||
Expected wildfire fund allocation metric, initial contribution | $ 4,800 | ||
Expected wildfire fund allocation metric, annual contributions | 193 | ||
Expected wildfire fund allocation metric, initial capital expenditure | $ 5,000 | ||
2018 Camp Fire and 2017 Northern California Wildfires | |||
Loss Contingencies [Line Items] | |||
Wildfire assistance fund, amount funded | $ 105 | ||
Wildfire assistance fund, claimant payments | $ 64 |
OTHER CONTINGENCIES AND COMMI_3
OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) $ in Millions | 12 Months Ended | ||||||
Dec. 31, 2019USD ($) | Jan. 31, 2020USD ($) | Jan. 17, 2020USD ($) | Dec. 17, 2019USD ($) | Dec. 05, 2019USD ($) | Oct. 03, 2019USD ($) | Dec. 06, 2018consultant | |
Loss Contingencies [Line Items] | |||||||
Expenses and capital expenditures, disallowed capital, gross | $ 344 | ||||||
Expenses and capital expenditures, disallowed capital, net | 403 | ||||||
Expenses and capital expenditures, expected charges to be recorded | 59 | ||||||
Settlement agreement, proposed payment to California general fund | $ 2 | ||||||
Unfavorable Regulatory Action | |||||||
Loss Contingencies [Line Items] | |||||||
Accrual | 44 | ||||||
Pacific Gas & Electric Co | Unfavorable Regulatory Action | |||||||
Loss Contingencies [Line Items] | |||||||
Settlement agreement, proposed penalty | $ 65 | ||||||
Settlement agreement, proposed payment to California general fund | 5 | ||||||
Settlement agreement, proposed payment to shareholders' funded initiatives | $ 60 | ||||||
Pacific Gas & Electric Co | Unfavorable Regulatory Action | Subsequent Event | |||||||
Loss Contingencies [Line Items] | |||||||
Settlement agreement, compliance audits cost | $ 6 | ||||||
Settlement agreement, additional fine | $ 39 | ||||||
Pacific Gas & Electric Co | Vegetation Management Support Costs (FHPMA) | |||||||
Loss Contingencies [Line Items] | |||||||
Expenses and capital expenditures | 36 | ||||||
Expenses and capital expenditures, expected charges to be recorded | 29 | ||||||
Expenses and capital expenditures, charges recorded | 55 | ||||||
Pacific Gas & Electric Co | Pending Litigation | Unfavorable Regulatory Action | |||||||
Loss Contingencies [Line Items] | |||||||
Expenses and capital expenditures | 1,625 | $ 1,625 | |||||
Shareholder-funded system enhancement initiatives, amount | $ 50 | ||||||
Expenses and capital expenditures, difference | $ 1,420 | ||||||
Number of consultants retained | consultant | 2 | ||||||
Pacific Gas & Electric Co | Pending Litigation | Unfavorable Regulatory Action | Subsequent Event | |||||||
Loss Contingencies [Line Items] | |||||||
Expenses and capital expenditures | $ 1,675 |
OTHER CONTINGENCIES AND COMMI_4
OTHER CONTINGENCIES AND COMMITMENTS (PSPS Class Action) (Details) $ in Millions | Dec. 19, 2019USD ($) |
PSPS Class Action | Pending Litigation | Pacific Gas & Electric Co | |
Loss Contingencies [Line Items] | |
Loss contingency, damages sought | $ 2,500 |
OTHER CONTINGENCIES AND COMMI_5
OTHER CONTINGENCIES AND COMMITMENTS (Legal Obligation) (Details) - Pacific Gas & Electric Co $ in Millions | Dec. 31, 2019USD ($) |
Loss Contingencies [Line Items] | |
Expense | $ 1,222 |
Capital | 403 |
Expenses and capital expenditures, forecast | 1,625 |
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA) | |
Loss Contingencies [Line Items] | |
Expense | 236 |
Capital | 0 |
Total | 236 |
Expenses and capital expenditures, forecast | 29 |
Transmission Safety Inspections and Repairs Expense (TO) | |
Loss Contingencies [Line Items] | |
Expense | 433 |
Capital | 0 |
Total | 433 |
Vegetation Management Support Costs (FHPMA) | |
Loss Contingencies [Line Items] | |
Expense | 36 |
Capital | 0 |
Total | 36 |
2017 Northern California Wildfires CEMA Expense and Capital (CEMA) | |
Loss Contingencies [Line Items] | |
Expense | 82 |
Capital | 66 |
Total | 148 |
2018 Camp Fire CEMA Expense (CEMA) | |
Loss Contingencies [Line Items] | |
Expense | 435 |
Capital | 0 |
Total | 435 |
2018 Camp Fire CEMA Capital for Restoration (CEMA) | |
Loss Contingencies [Line Items] | |
Expense | 0 |
Capital | 253 |
Total | 253 |
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA) | |
Loss Contingencies [Line Items] | |
Expense | 0 |
Capital | 84 |
Total | 84 |
Expenses and capital expenditures, forecast | $ 59 |
OTHER CONTINGENCIES AND COMMI_6
OTHER CONTINGENCIES AND COMMITMENTS (Ex Parte Communication Rules) (Details) - USD ($) $ in Thousands | Sep. 21, 2018 | May 17, 2018 | Apr. 26, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 05, 2019 |
Loss Contingencies [Line Items] | ||||||
Settlement agreement, proposed payment to California general fund | $ 2,000 | |||||
Accrued legal liabilities | $ 116,000 | |||||
Other Current Liabilities | ||||||
Loss Contingencies [Line Items] | ||||||
Accrued legal liabilities | $ 98,000 | |||||
Pacific Gas & Electric Co | Electric | ||||||
Loss Contingencies [Line Items] | ||||||
Requested revenue rate | 98.85% | |||||
Ex Parte Communications | ||||||
Loss Contingencies [Line Items] | ||||||
Proposed penalty | $ 97,500 | |||||
Payment to State General Fund | $ 12,000 | 12,000 | ||||
Gas transmission and storage revenue reduction | 63,500 | |||||
2018 GT&S revenue requirement reduction | 31,750 | |||||
2019 GT&S revenue requirement reduction | 31,750 | |||||
Revenue requirement reduction in Next GRC cycle | $ 10,000 | |||||
Payment to city of San Carlos | 6,000 | |||||
Payment to city of San Bruno | $ 6,000 | |||||
Settlement agreement, proposed penalty | 10,000 | |||||
Settlement agreement, proposed forgone revenue collection, 2019 GT&S rate case | 5,000 | |||||
Settlement agreement, proposed forgone revenue collection, 2020 GRC cycle | 1,000 | |||||
Settlement agreement, proposed compensation payments | 2,000 | |||||
Settlement agreement, proposed compensation payments, San Bruno | $ 1,000 | |||||
Ex Parte Communications | Pacific Gas & Electric Co | ||||||
Loss Contingencies [Line Items] | ||||||
Loss contingency liability | 4,000 | |||||
Disallowance of Plant Costs | ||||||
Loss Contingencies [Line Items] | ||||||
Cancelled Capital Project Costs | $ 63,500 | $ 63,500 |
OTHER CONTINGENCIES AND COMMI_7
OTHER CONTINGENCIES AND COMMITMENTS (Disallowance of Plant Costs) (Details) - Disallowance of Plant Costs $ in Millions | Jun. 23, 2016USD ($) |
Loss Contingencies [Line Items] | |
Gas transmission and storage capital disallowance | $ 696 |
Permanently disallowed capital | 120 |
Amount subject to audit | $ 576 |
OTHER CONTINGENCIES AND COMMI_8
OTHER CONTINGENCIES AND COMMITMENTS (Schedule Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Disclosure Commitments And Contingencies Environmental Remediation Liability Composed [Abstract] | ||
Topock natural gas compressor station | $ 362 | $ 369 |
Hinkley natural gas compressor station | 138 | 146 |
Former manufactured gas plant sites owned by the Utility or third parties | 568 | 520 |
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites | 101 | 111 |
Fossil fuel-fired generation facilities and sites | 106 | 137 |
Total environmental remediation liability | $ 1,275 | $ 1,283 |
OTHER CONTINGENCIES AND COMMI_9
OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Long-term Purchase Commitment [Line Items] | |
Amount of environmental loss accrual expected to be recovered | $ 950 |
Topock Site | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 208 |
Topock Site | Pacific Gas & Electric Co | |
Long-term Purchase Commitment [Line Items] | |
Remediation cost recovery percentage | 90.00% |
Hinkley Natural Gas Compressor Station | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 128 |
Former Manufactured Gas Plant | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 626 |
Former Manufactured Gas Plant | Pacific Gas & Electric Co | |
Long-term Purchase Commitment [Line Items] | |
Remediation cost recovery percentage | 90.00% |
Utility Owned Generation Facilities and Third Party Disposal Sites | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 77 |
Utility Owned Generation Facilities and Third Party Disposal Sites | Pacific Gas & Electric Co | |
Long-term Purchase Commitment [Line Items] | |
Remediation cost recovery percentage | 90.00% |
Fossil Fuel Fired Generation | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 82 |
OTHER CONTINGENCIES AND COMM_10
OTHER CONTINGENCIES AND COMMITMENTS (Wildfire Insurance) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Maximum | ||
Loss Contingencies [Line Items] | ||
Costs for insurance coverage | $ 1,400 | |
August 1, 2019 through September 2, 2020 | ||
Loss Contingencies [Line Items] | ||
Costs for insurance coverage | 212 | |
Pacific Gas & Electric Co | ||
Loss Contingencies [Line Items] | ||
Costs for insurance coverage | 50 | |
Insurance Coverage for Property Damages | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | $ 700 | |
Insurance Coverage for Wildfire Events | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | 430 | |
Insurance Coverage for Wildfire Events | August 1, 2019 through July 31, 2020 | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | 430 | |
Catastrophic bond reinsurance instrument | 10 | |
Insurance Coverage For Non-Wildfire Liabilities | August 1, 2019 through July 31, 2020 | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | 1,000 | |
Insurance Coverage for Wildfire Liabilities | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | 1,000 | |
Catastrophic bond reinsurance instrument | 10 | |
Insurance Coverage for Wildfire Liabilities | August 1, 2019 through July 31, 2020 | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | 520 | |
Insurance Coverage for Wildfire Liabilities | August 1, 2019 through July 31, 2020 | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | 520 | |
Catastrophic bond reinsurance instrument | 10 | |
Insurance Coverage for Wildfire Liabilities | September 3, 2019 through September 2, 2020 | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | 480 | |
2018 Camp fire | ||
Loss Contingencies [Line Items] | ||
Settlement reached | 1,380 | |
2017 Northern California wildfires | ||
Loss Contingencies [Line Items] | ||
Settlement reached | $ 843 |
OTHER CONTINGENCIES AND COMM_11
OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($)nuclear_generating_unit | |
Long-term Purchase Commitment [Line Items] | |
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit | 2 |
Maximum total payment incurred per event under the loss sharing program | $ 450 |
Humboldt Bay Unit | |
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 |
Diablo Canyon | |
Long-term Purchase Commitment [Line Items] | |
Maximum public liability per nuclear incident under Price-Anderson Act | 14,000 |
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act | 450 |
Maximum annual payment incurred per event under the loss sharing program | 275 |
Coverage for purchased public liability insurance, per incident | $ 41 |
Period for inflation adjustment | 5 years |
Nuclear Incident | |
Long-term Purchase Commitment [Line Items] | |
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon | $ 3,200 |
Nuclear Incident | Humboldt Bay Unit | |
Long-term Purchase Commitment [Line Items] | |
Amount of indemnification from the NRC for public liability arising from nuclear incidents | 500 |
Non-Nuclear Incident | |
Long-term Purchase Commitment [Line Items] | |
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon | 2,700 |
Nuclear Electric Insurance Limited | |
Long-term Purchase Commitment [Line Items] | |
Potential premium obligation | 44 |
European Mutual Association for Nuclear Insurance | |
Long-term Purchase Commitment [Line Items] | |
Full insurance policy limit | 200 |
Potential premium obligation | $ 4 |
OTHER CONTINGENCIES AND COMM_12
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Purchase Commitments) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Long-term Purchase Commitment [Line Items] | |
2020 | $ 3,514 |
2021 | 3,100 |
2022 | 2,802 |
2023 | 2,429 |
2024 | 2,251 |
Thereafter | 23,644 |
Total purchase commitments | 37,740 |
Renewable Energy | |
Long-term Purchase Commitment [Line Items] | |
2020 | 2,230 |
2021 | 2,234 |
2022 | 2,021 |
2023 | 1,941 |
2024 | 1,917 |
Thereafter | 22,853 |
Total purchase commitments | 33,196 |
Conventional Energy | |
Long-term Purchase Commitment [Line Items] | |
2020 | 640 |
2021 | 582 |
2022 | 511 |
2023 | 224 |
2024 | 72 |
Thereafter | 351 |
Total purchase commitments | 2,380 |
Other | |
Long-term Purchase Commitment [Line Items] | |
2020 | 82 |
2021 | 65 |
2022 | 61 |
2023 | 60 |
2024 | 60 |
Thereafter | 94 |
Total purchase commitments | 422 |
Natural Gas | |
Long-term Purchase Commitment [Line Items] | |
2020 | 411 |
2021 | 155 |
2022 | 155 |
2023 | 155 |
2024 | 155 |
Thereafter | 346 |
Total purchase commitments | 1,377 |
Nuclear Fuel | |
Long-term Purchase Commitment [Line Items] | |
2020 | 151 |
2021 | 64 |
2022 | 54 |
2023 | 49 |
2024 | 47 |
Thereafter | 0 |
Total purchase commitments | $ 365 |
OTHER CONTINGENCIES AND COMM_13
OTHER CONTINGENCIES AND COMMITMENTS (Third-Party Power Purchase Agreements and Other Agreements) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Power Purchases and Electric Capacity | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Costs incurred for power purchases and electric capacity | $ 3,000 | $ 3,100 | $ 3,300 |
Nuclear Fuel | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Payments for nuclear fuel | 74 | 73 | 83 |
Gas Contracts | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Cost of goods | $ 900 | $ 600 | $ 900 |
OTHER CONTINGENCIES AND COMM_14
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Other Commitments) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2020 | $ 45 |
2021 | 39 |
2022 | 31 |
2023 | 24 |
2024 | 14 |
Thereafter | 111 |
Total minimum lease payments | $ 264 |
OTHER CONTINGENCIES AND COMM_15
OTHER CONTINGENCIES AND COMMITMENTS (Other Commitments) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Payments for operating leases | $ 48 | $ 43 | $ 45 |
Operating Leased Assets [Line Items] | |||
Present value of fixed capacity payments, portion classified as current liabilities | 556 | ||
Present value of fixed capacity payments, portion classified as noncurrent liabilities | 1,730 | ||
Qualifying Facilities | |||
Operating Leased Assets [Line Items] | |||
Capitalized asset for fixed capacity payments for corresponding assets | 9 | 11 | |
Capitalized asset for fixed capacity payments, accumulated amortization | 9 | 8 | |
Present value of fixed capacity payments, portion classified as current liabilities | 2 | 2 | |
Present value of fixed capacity payments, portion classified as noncurrent liabilities | $ 7 | $ 9 | |
Minimum | |||
Operating Leased Assets [Line Items] | |||
Extension option for operating leases | 1 year | ||
Maximum | |||
Operating Leased Assets [Line Items] | |||
Extension option for operating leases | 5 years |
SCHEDULE I _ CONDENSED FINANC_2
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Income Statement and Comprehensive Income) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating expenses | $ (27,223) | $ (26,459) | $ (14,230) |
Interest income | 82 | 76 | 31 |
Interest expense | (934) | (929) | (888) |
Other income, net | 250 | 424 | 123 |
Reorganization items, net | (346) | 0 | 0 |
Income (Loss) Before Income Taxes | (11,042) | (10,129) | 2,171 |
Income tax provision (benefit) | (3,400) | (3,292) | 511 |
Income (Loss) Available for Common Shareholders | (7,656) | (6,851) | 1,646 |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations | (1) | 4 | 1 |
Total other comprehensive income (loss) | $ (1) | $ 4 | $ 1 |
Weighted Average Common Shares Outstanding, Basic (in shares) | 528 | 517 | 512 |
Weighted Average Common Shares Outstanding, Diluted (in shares) | 528 | 517 | 513 |
Net Earnings (Loss) Per Common Share, Basic (in dollars per share) | $ (14.50) | $ (13.25) | $ 3.21 |
Net Earnings (Loss) Per Common Share, Diluted (in dollars per share) | $ (14.50) | $ (13.25) | $ 3.21 |
Pension and other postretirement benefit plans obligations, tax | $ 0 | $ 2 | $ 0 |
PG&E Corporation | |||
Operating expenses | (114) | (91) | (5) |
Interest income | 1 | 2 | 1 |
Interest expense | (21) | (15) | (11) |
Other income, net | 10 | (2) | 4 |
Reorganization items, net | (26) | 0 | 0 |
Equity in earnings of subsidiaries | (7,622) | (6,832) | 1,667 |
Income (Loss) Before Income Taxes | (7,634) | (6,848) | 1,719 |
Income tax provision (benefit) | 8 | 3 | 73 |
Income (Loss) Available for Common Shareholders | (7,642) | (6,851) | 1,646 |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations | (1) | 4 | 1 |
Total other comprehensive income (loss) | (1) | 4 | 1 |
Comprehensive Income | $ (7,643) | $ (6,847) | $ 1,647 |
Weighted Average Common Shares Outstanding, Basic (in shares) | 528 | 517 | 512 |
Weighted Average Common Shares Outstanding, Diluted (in shares) | 528 | 513 | 513 |
Net Earnings (Loss) Per Common Share, Basic (in dollars per share) | $ (14.50) | $ (13.25) | $ 3.21 |
Net Earnings (Loss) Per Common Share, Diluted (in dollars per share) | $ (14.50) | $ (13.25) | $ 3.21 |
Pension and other postretirement benefit plans obligations, tax | $ 0 | $ 0 | $ 0 |
Administrative service revenue | PG&E Corporation | |||
Revenue | $ 138 | $ 90 | $ 63 |
SCHEDULE I _ CONDENSED FINANC_3
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Balance Sheet) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Current Assets | |||
Cash and cash equivalents | $ 1,570 | $ 1,668 | $ 449 |
Income taxes receivable | 0 | 23 | |
Other | 646 | 448 | |
Total current assets | 10,165 | 9,195 | |
Noncurrent Assets | |||
Equipment | 88,090 | 83,272 | |
Accumulated depreciation | (26,455) | (24,715) | |
Net property, plant, and equipment | 61,635 | 58,557 | |
Operating lease right of use asset | 2,286 | ||
TOTAL ASSETS | 85,196 | 76,995 | |
Current Liabilities | |||
Short-term borrowings | 0 | 3,435 | |
Long-term debt, classified as current | 0 | 18,559 | |
Operating lease liabilities | 556 | ||
Other current liabilities | 1,254 | 1,512 | |
Total current liabilities | 7,631 | 41,695 | |
Noncurrent Liabilities | |||
Debtor-in-possession financing | 22,176 | 22,075 | |
Operating lease liabilities | 1,730 | ||
Other | 2,573 | 2,464 | |
Total noncurrent liabilities | 21,631 | 22,397 | |
Liabilities Subject to Compromise | 50,546 | 0 | |
Common Shareholders’ Equity | |||
Common stock, no par value | 13,038 | 12,910 | |
Reinvested earnings | (7,892) | (250) | |
Accumulated other comprehensive income (loss) | (10) | (9) | |
Total shareholders' equity | 5,136 | 12,651 | |
TOTAL LIABILITIES AND EQUITY | 85,196 | 76,995 | |
PG&E Corporation | |||
Current Assets | |||
Cash and cash equivalents | 448 | 373 | |
Advances to affiliates | 120 | 44 | |
Income taxes receivable | 12 | 18 | |
Other | 11 | 0 | |
Total current assets | 591 | 435 | |
Noncurrent Assets | |||
Equipment | 2 | 2 | |
Accumulated depreciation | (2) | (2) | |
Net property, plant, and equipment | 0 | 0 | |
Investments in subsidiaries | 5,102 | 12,722 | |
Other investments | 173 | 162 | |
Intercompany receivable | 0 | 0 | |
Operating lease right of use asset | 6 | ||
Deferred income taxes | 187 | 187 | |
Total noncurrent assets | 5,468 | 13,071 | |
TOTAL ASSETS | 6,059 | 13,506 | |
Current Liabilities | |||
Short-term borrowings | 0 | 300 | |
Long-term debt, classified as current | 0 | 350 | |
Accounts payable – other | 47 | 16 | |
Operating lease liabilities | 3 | ||
Other current liabilities | 3 | 17 | |
Total current liabilities | 53 | 683 | |
Noncurrent Liabilities | |||
Debtor-in-possession financing | 0 | 0 | |
Operating lease liabilities | 3 | ||
Other | 58 | 172 | |
Total noncurrent liabilities | 61 | 172 | |
Liabilities Subject to Compromise | 810 | 0 | |
Common Shareholders’ Equity | |||
Common stock, no par value | 13,038 | 12,910 | |
Reinvested earnings | (7,893) | (250) | |
Accumulated other comprehensive income (loss) | (10) | (9) | |
Total shareholders' equity | 5,135 | 12,651 | |
TOTAL LIABILITIES AND EQUITY | $ 6,059 | $ 13,506 |
SCHEDULE I _ CONDENSED FINANC_4
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Statement of Cash Flows) (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | |||||
Oct. 31, 2017 | Jul. 31, 2017 | Apr. 30, 2017 | Jan. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash Flows from Operating Activities | |||||||
Net income (loss) | $ (7,642) | $ (6,837) | $ 1,660 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Deferred income taxes and tax credits, net | (2,948) | (2,532) | 1,254 | ||||
Reorganization items, net | 108 | 0 | 0 | ||||
Liabilities subject to compromise | 12,222 | 0 | 0 | ||||
Net cash provided by operating activities | 4,816 | 4,752 | 5,977 | ||||
Cash Flows from Investing Activities | |||||||
Net cash used in investing activities | (6,378) | (6,564) | (5,650) | ||||
Cash Flows From Financing Activities: | |||||||
Debtor-in-possession credit facility debt issuance costs | (113) | 0 | 0 | ||||
Borrowings under revolving credit facilities | 0 | 3,960 | 0 | ||||
Repayments under revolving credit facilities | 0 | (775) | 0 | ||||
Net issuances (repayments) of commercial paper, net of discount of $1 in 2017 | 0 | (182) | (840) | ||||
Long-term debt matured or repurchased | 0 | (795) | (1,445) | ||||
Common stock issued | 85 | 200 | 395 | ||||
Common stock dividends paid | 0 | 0 | (1,021) | ||||
Net cash provided by (used in) financing activities | 1,464 | 3,031 | (55) | ||||
Net change in cash, cash equivalents, and restricted cash | (98) | 1,219 | 272 | ||||
Cash, cash equivalents, and restricted cash at January 1 | $ 184 | 1,675 | 456 | 184 | |||
Cash, cash equivalents, and restricted cash at December 31 | 1,577 | 1,675 | 456 | ||||
Cash received (paid) for: | |||||||
Interest, net of amounts capitalized | (10) | (786) | (790) | ||||
Income taxes, net | 0 | (49) | 162 | ||||
Supplemental disclosures of noncash investing and financing activities | |||||||
Noncash common stock issuances | 0 | 0 | 21 | ||||
Operating lease liabilities arising from obtaining ROU assets | 2,816 | 0 | 0 | ||||
Discount on net issuances of commercial paper | 0 | 1 | 5 | ||||
PG&E Corporation | |||||||
Cash Flows from Operating Activities | |||||||
Net income (loss) | (7,642) | (6,851) | 1,646 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Stock-based compensation amortization | 43 | 78 | 20 | ||||
Equity in earnings of subsidiaries | 7,622 | 6,833 | (1,667) | ||||
Deferred income taxes and tax credits, net | 0 | (62) | 139 | ||||
Reorganization items, net | 11 | 0 | 0 | ||||
Current income taxes receivable/payable | 6 | 9 | (2) | ||||
Liabilities subject to compromise | 28 | 0 | 0 | ||||
Other | (62) | 41 | (75) | ||||
Net cash provided by operating activities | 6 | 48 | 61 | ||||
Cash Flows from Investing Activities | |||||||
Investment in subsidiaries | 0 | (45) | (455) | ||||
Dividends received from subsidiaries | 0 | 0 | 784 | ||||
Net cash used in investing activities | 0 | (45) | 329 | ||||
Cash Flows From Financing Activities: | |||||||
Debtor-in-possession credit facility debt issuance costs | (16) | 0 | 0 | ||||
Borrowings under revolving credit facilities | 0 | 425 | 0 | ||||
Repayments under revolving credit facilities | 0 | (125) | 0 | ||||
Net issuances (repayments) of commercial paper, net of discount of $1 in 2017 | 0 | (132) | 132 | ||||
Proceeds from Short-term Debt | 0 | 350 | 0 | ||||
Long-term debt matured or repurchased | 0 | (350) | 0 | ||||
Common stock issued | 85 | 200 | 395 | ||||
Common stock dividends paid | 0 | 0 | (1,021) | ||||
Net cash provided by (used in) financing activities | 69 | 368 | (494) | ||||
Net change in cash, cash equivalents, and restricted cash | 75 | 371 | (104) | ||||
Cash, cash equivalents, and restricted cash at January 1 | $ 106 | 373 | 2 | 106 | |||
Cash, cash equivalents, and restricted cash at December 31 | 448 | 373 | 2 | ||||
Cash received (paid) for: | |||||||
Interest, net of amounts capitalized | (3) | (13) | (9) | ||||
Income taxes, net | 0 | 10 | 0 | ||||
Supplemental disclosures of noncash investing and financing activities | |||||||
Common stock dividends declared but not yet paid | 0 | 0 | 0 | ||||
Noncash common stock issuances | 0 | 0 | 21 | ||||
Operating lease liabilities arising from obtaining ROU assets | $ 9 | 0 | $ 0 | ||||
Common stock dividends paid per share (in dollars per share) | $ 0.53 | $ 0.53 | $ 0.49 | $ 0.49 | |||
Discount on net issuances of commercial paper | $ 1 |
SCHEDULE II _ CONSOLIDATED VA_2
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance at Beginning of Period | $ 56 | $ 64 | $ 58 |
Charged to Costs and Expenses | 0 | 34 | 55 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | 13 | 42 | 49 |
Balance at End of Period | $ 43 | $ 56 | $ 64 |