UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 FORM 10-Q | ||||||||
(Mark One) | ||||||||
[X] | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||
For the quarterly period ended September 30, 2018 OR | ||||||||
[ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||
For the transition period from ___________ to __________ | ||||||||
Commission File Number | Exact Name of Registrant as Specified in its Charter | State or Other Jurisdiction of Incorporation | IRS Employer Identification Number | |||||
1-12609 | PG&E Corporation | California | 94-3234914 | |||||
1-2348 | Pacific Gas and Electric Company | California | 94-0742640 | |||||
PG&E Corporation 77 Beale Street P.O. Box 770000 San Francisco, California 94177 | Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177 | |||||||
Address of principal executive offices, including zip code | ||||||||
PG&E Corporation (415) 973-1000 | Pacific Gas and Electric Company (415) 973-7000 | |||||||
Registrant's telephone number, including area code | ||||||||
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. | ||||||||
PG&E Corporation: | [X] Yes [ ] No | |||||||
Pacific Gas and Electric Company: | [X] Yes [ ] No | |||||||
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). | ||||||||
PG&E Corporation: | [X] Yes [ ] No | |||||||
Pacific Gas and Electric Company: | [X] Yes [ ] No | |||||||
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. | ||||||||
PG&E Corporation: | [X] Large accelerated filer | [ ] Accelerated filer | ||||||
[ ] Non-accelerated filer | ||||||||
[ ] Smaller reporting company | [ ] Emerging growth company | |||||||
Pacific Gas and Electric Company: | [ ] Large accelerated filer | [ ] Accelerated filer | ||||||
[X] Non-accelerated filer | ||||||||
[ ] Smaller reporting company | [ ] Emerging growth company | |||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. | ||||||||
PG&E Corporation: | [ ] | |||||||
Pacific Gas and Electric Company: | [ ] | |||||||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). | ||||||||
PG&E Corporation: | [ ] Yes [X] No | |||||||
Pacific Gas and Electric Company: | [ ] Yes [X] No |
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. | |||||||||
Common stock outstanding as of October 25, 2018: | |||||||||
PG&E Corporation: | 518,674,276 | ||||||||
Pacific Gas and Electric Company: | 264,374,809 | ||||||||
2017 Form 10-K | PG&E Corporation and Pacific Gas and Electric Company's combined Annual Report on Form 10-K for the year ended December 31, 2017 |
ALJ | administrative law judge |
ARO | asset retirement obligation |
ASU | accounting standard update issued by the FASB (see below) |
CAISO | California Independent System Operator |
Cal Fire | California Department of Forestry and Fire Protection |
Cal PA | Public Advocates Office of the California Public Utilities Commission (formerly known as Office of Ratepayer Advocates or ORA) |
CCA | Community Choice Aggregator |
CEC | California Energy Resources Conservation and Development Commission |
CEMA | Catastrophic Event Memorandum Account |
CPUC | California Public Utilities Commission |
CRRs | congestion revenue rights |
DER | distributed energy resources |
Diablo Canyon | Diablo Canyon nuclear power plant |
DOGGR | Division of Oil, Gas, and Geothermal Resources of the California Department of Conservation |
DTSC | Department of Toxic Substances Control |
EPS | earnings per common share |
EV | electric vehicle |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
FHPMA | fire hazard prevention memorandum account |
GAAP | U.S. Generally Accepted Accounting Principles |
GHG | greenhouse gas |
GRC | general rate case |
GT&S | gas transmission and storage |
HSM | hazardous substance memorandum account |
IOU(s) | investor-owned utility(ies) |
MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 2 of this Form 10-Q |
MGP(s) | manufactured gas plants |
NAV | net asset value |
NDCTP | Nuclear Decommissioning Cost Triennial Proceedings |
NEIL | Nuclear Electric Insurance Limited |
NRC | Nuclear Regulatory Commission |
OES | State of California Office of Emergency Services |
OII | order instituting investigation |
OIR | order instituting rulemaking |
PCIA | Power Charge Indifference Adjustment |
PD | proposed decision |
PFM | petition for modification |
RAMP | Risk Assessment Mitigation Phase |
ROE | return on equity |
SB | Senate Bill |
SEC | U.S. Securities and Exchange Commission |
SED | Safety and Enforcement Division of the CPUC |
Tax Act | Tax Cuts and Jobs Act of 2017 |
TE | transportation electrification |
TO | transmission owner |
TURN | The Utility Reform Network |
Utility | Pacific Gas and Electric Company |
VIE(s) | variable interest entity(ies) |
WEMA | Wildfire Expense Memorandum Account |
(Unaudited) | |||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions, except per share amounts) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Operating Revenues | |||||||||||||||
Electric | $ | 3,466 | $ | 3,648 | $ | 9,729 | $ | 10,036 | |||||||
Natural gas | 915 | 869 | 2,942 | 2,999 | |||||||||||
Total operating revenues | 4,381 | 4,517 | 12,671 | 13,035 | |||||||||||
Operating Expenses | |||||||||||||||
Cost of electricity | 1,256 | 1,466 | 3,038 | 3,436 | |||||||||||
Cost of natural gas | 69 | 78 | 437 | 524 | |||||||||||
Operating and maintenance | 1,611 | 1,324 | 5,001 | 4,453 | |||||||||||
Wildfire-related claims, net of insurance recoveries | (10 | ) | 53 | 2,108 | — | ||||||||||
Depreciation, amortization, and decommissioning | 759 | 710 | 2,257 | 2,134 | |||||||||||
Total operating expenses | 3,685 | 3,631 | 12,841 | 10,547 | |||||||||||
Operating Income (Loss) | 696 | 886 | (170 | ) | 2,488 | ||||||||||
Interest income | 14 | 9 | 35 | 22 | |||||||||||
Interest expense | (232 | ) | (220 | ) | (678 | ) | (663 | ) | |||||||
Other income, net | 104 | 38 | 318 | 98 | |||||||||||
Income (Loss) Before Income Taxes | 582 | 713 | (495 | ) | 1,945 | ||||||||||
Income tax provision (benefit) | 15 | 160 | (527 | ) | 403 | ||||||||||
Net Income | 567 | 553 | 32 | 1,542 | |||||||||||
Preferred stock dividend requirement of subsidiary | 3 | 3 | 10 | 10 | |||||||||||
Income Available for Common Shareholders | $ | 564 | $ | 550 | $ | 22 | $ | 1,532 | |||||||
Weighted Average Common Shares Outstanding, Basic | 517 | 513 | 516 | 511 | |||||||||||
Weighted Average Common Shares Outstanding, Diluted | 517 | 516 | 517 | 514 | |||||||||||
Net Earnings Per Common Share, Basic | $ | 1.09 | $ | 1.07 | $ | 0.04 | $ | 3.00 | |||||||
Net Earnings Per Common Share, Diluted | $ | 1.09 | $ | 1.07 | $ | 0.04 | $ | 2.98 | |||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. |
(Unaudited) | |||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Net Income | $ | 567 | $ | 553 | $ | 32 | $ | 1,542 | |||||||
Other Comprehensive Income | |||||||||||||||
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates) | 1 | — | 1 | 1 | |||||||||||
Total other comprehensive income | 1 | — | 1 | 1 | |||||||||||
Comprehensive Income | 568 | 553 | 33 | 1,543 | |||||||||||
Preferred stock dividend requirement of subsidiary | 3 | 3 | 10 | 10 | |||||||||||
Comprehensive Income Attributable to Common Shareholders | $ | 565 | $ | 550 | $ | 23 | $ | 1,533 | |||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. |
(Unaudited) | |||||||
Balance At | |||||||
(in millions) | September 30, 2018 | December 31, 2017 | |||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | $ | 430 | $ | 449 | |||
Accounts receivable: | |||||||
Customers (net of allowance for doubtful accounts of $58 and $64 at respective dates) | 1,297 | 1,243 | |||||
Accrued unbilled revenue | 962 | 946 | |||||
Regulatory balancing accounts | 1,326 | 1,222 | |||||
Other | 902 | 861 | |||||
Regulatory assets | 229 | 615 | |||||
Inventories: | |||||||
Gas stored underground and fuel oil | 116 | 115 | |||||
Materials and supplies | 389 | 366 | |||||
Other | 698 | 464 | |||||
Total current assets | 6,349 | 6,281 | |||||
Property, Plant, and Equipment | |||||||
Electric | 56,860 | 55,133 | |||||
Gas | 20,798 | 19,641 | |||||
Construction work in progress | 2,855 | 2,471 | |||||
Other | 2 | 3 | |||||
Total property, plant, and equipment | 80,515 | 77,248 | |||||
Accumulated depreciation | (24,310 | ) | (23,459 | ) | |||
Net property, plant, and equipment | 56,205 | 53,789 | |||||
Other Noncurrent Assets | |||||||
Regulatory assets | 4,429 | 3,793 | |||||
Nuclear decommissioning trusts | 2,917 | 2,863 | |||||
Income taxes receivable | 67 | 65 | |||||
Other | 1,418 | 1,221 | |||||
Total other noncurrent assets | 8,831 | 7,942 | |||||
TOTAL ASSETS | $ | 71,385 | $ | 68,012 | |||
See accompanying Notes to the Condensed Consolidated Financial Statements. |
(Unaudited) | |||||||
Balance At | |||||||
(in millions, except share amounts) | September 30, 2018 | December 31, 2017 | |||||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Short-term borrowings | $ | 750 | $ | 931 | |||
Long-term debt, classified as current | 193 | 445 | |||||
Accounts payable: | |||||||
Trade creditors | 1,699 | 1,646 | |||||
Regulatory balancing accounts | 1,230 | 1,120 | |||||
Other | 556 | 517 | |||||
Disputed claims and customer refunds | 217 | 243 | |||||
Interest payable | 151 | 217 | |||||
Wildfire-related claims | 2,794 | 561 | |||||
Other | 1,899 | 1,449 | |||||
Total current liabilities | 9,489 | 7,129 | |||||
Noncurrent Liabilities | |||||||
Long-term debt | 18,407 | 17,753 | |||||
Regulatory liabilities | 8,607 | 8,679 | |||||
Pension and other post-retirement benefits | 2,014 | 2,128 | |||||
Asset retirement obligations | 4,999 | 4,899 | |||||
Deferred income taxes | 5,822 | 5,822 | |||||
Other | 2,351 | 2,130 | |||||
Total noncurrent liabilities | 42,200 | 41,411 | |||||
Contingencies and Commitments (Note 9) | |||||||
Equity | |||||||
Shareholders' Equity | |||||||
Common stock, no par value, authorized 800,000,000 shares; 517,102,983 and 514,755,845 shares outstanding at respective dates | 12,833 | 12,632 | |||||
Reinvested earnings | 6,623 | 6,596 | |||||
Accumulated other comprehensive loss | (12 | ) | (8 | ) | |||
Total shareholders' equity | 19,444 | 19,220 | |||||
Noncontrolling Interest - Preferred Stock of Subsidiary | 252 | 252 | |||||
Total equity | 19,696 | 19,472 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 71,385 | $ | 68,012 | |||
See accompanying Notes to the Condensed Consolidated Financial Statements. |
(Unaudited) | |||||||
Nine Months Ended September 30, | |||||||
(in millions) | 2018 | 2017 | |||||
Cash Flows from Operating Activities | |||||||
Net income | $ | 32 | $ | 1,542 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, amortization, and decommissioning | 2,257 | 2,134 | |||||
Allowance for equity funds used during construction | (97 | ) | (63 | ) | |||
Deferred income taxes and tax credits, net | 10 | 848 | |||||
Disallowed capital expenditures | (38 | ) | 47 | ||||
Other | 231 | 204 | |||||
Effect of changes in operating assets and liabilities: | |||||||
Accounts receivable | (201 | ) | (58 | ) | |||
Wildfire-related insurance receivable | 64 | (166 | ) | ||||
Inventories | (24 | ) | (35 | ) | |||
Accounts payable | 245 | 76 | |||||
Wildfire-related claims | 2,233 | 12 | |||||
Income taxes receivable/payable | — | 135 | |||||
Other current assets and liabilities | (154 | ) | 23 | ||||
Regulatory assets, liabilities, and balancing accounts, net | (128 | ) | (30 | ) | |||
Other noncurrent assets and liabilities | (194 | ) | 68 | ||||
Net cash provided by operating activities | 4,236 | 4,737 | |||||
Cash Flows from Investing Activities | |||||||
Capital expenditures | (4,592 | ) | (3,938 | ) | |||
Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,121 | 1,043 | |||||
Purchases of nuclear decommissioning trust investments | (1,165 | ) | (1,071 | ) | |||
Other | 19 | 16 | |||||
Net cash used in investing activities | (4,617 | ) | (3,950 | ) | |||
Cash Flows from Financing Activities | |||||||
Borrowings under revolving credit facilities | 775 | — | |||||
Repayments under revolving credit facilities | (775 | ) | — | ||||
Net issuances (repayments) of commercial paper, net of discount of $1 and $4 at respective dates | (182 | ) | (652 | ) | |||
Short-term debt financing | 250 | 250 | |||||
Short-term debt matured | (250 | ) | (250 | ) | |||
Proceeds from issuance of long-term debt, net of discount and issuance costs of $7 and $11 at respective dates | 1,143 | 734 | |||||
Long-term debt matured or repurchased | (750 | ) | (345 | ) | |||
Common stock issued | 137 | 345 | |||||
Common stock dividends paid | — | (754 | ) | ||||
Other | 14 | (101 | ) | ||||
Net cash provided by (used in) financing activities | 362 | (773 | ) | ||||
Net change in cash and cash equivalents | (19 | ) | 14 | ||||
Cash and cash equivalents at January 1 | 449 | 177 | |||||
Cash and cash equivalents at September 30 | $ | 430 | $ | 191 |
Supplemental disclosures of cash flow information | |||||||
Cash received (paid) for: | |||||||
Interest, net of amounts capitalized | $ | (650 | ) | $ | (644 | ) | |
Income taxes, net | (49 | ) | 158 | ||||
Supplemental disclosures of noncash investing and financing activities | |||||||
Common stock dividends declared but not yet paid | $ | — | $ | 272 | |||
Capital expenditures financed through accounts payable | 348 | 301 | |||||
Noncash common stock issuances | — | 16 | |||||
Terminated capital leases | 161 | — | |||||
See accompanying Notes to the Condensed Consolidated Financial Statements. |
(Unaudited) | |||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Operating Revenues | |||||||||||||||
Electric | $ | 3,467 | $ | 3,647 | $ | 9,730 | $ | 10,038 | |||||||
Natural gas | 915 | 869 | 2,942 | 2,999 | |||||||||||
Total operating revenues | 4,382 | 4,516 | 12,672 | 13,037 | |||||||||||
Operating Expenses | |||||||||||||||
Cost of electricity | 1,256 | 1,466 | 3,038 | 3,436 | |||||||||||
Cost of natural gas | 69 | 78 | 437 | 524 | |||||||||||
Operating and maintenance | 1,611 | 1,389 | 5,002 | 4,518 | |||||||||||
Wildfire-related claims, net of insurance recoveries | (10 | ) | 53 | 2,108 | — | ||||||||||
Depreciation, amortization, and decommissioning | 759 | 710 | 2,257 | 2,134 | |||||||||||
Total operating expenses | 3,685 | 3,696 | 12,842 | 10,612 | |||||||||||
Operating Income (Loss) | 697 | 820 | (170 | ) | 2,425 | ||||||||||
Interest income | 14 | 10 | 34 | 22 | |||||||||||
Interest expense | (229 | ) | (217 | ) | (668 | ) | (655 | ) | |||||||
Other income, net | 103 | 38 | 321 | 93 | |||||||||||
Income (Loss) Before Income Taxes | 585 | 651 | (483 | ) | 1,885 | ||||||||||
Income tax provision (benefit) | 14 | 138 | (530 | ) | 394 | ||||||||||
Net Income | 571 | 513 | 47 | 1,491 | |||||||||||
Preferred stock dividend requirement | 3 | 3 | 10 | 10 | |||||||||||
Income Available for Common Stock | $ | 568 | $ | 510 | $ | 37 | $ | 1,481 | |||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. |
(Unaudited) | |||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Net Income | $ | 571 | $ | 513 | $ | 47 | $ | 1,491 | |||||||
Other Comprehensive Income | |||||||||||||||
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates ) | — | — | 1 | 1 | |||||||||||
Total other comprehensive income | — | — | 1 | 1 | |||||||||||
Comprehensive Income | $ | 571 | $ | 513 | $ | 48 | $ | 1,492 | |||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. |
(Unaudited) | |||||||
Balance At | |||||||
September 30, 2018 | December 31, 2017 | ||||||
(in millions) | |||||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | $ | 371 | $ | 447 | |||
Accounts receivable: | |||||||
Customers (net of allowance for doubtful accounts of $58 and $64 at respective dates) | 1,297 | 1,243 | |||||
Accrued unbilled revenue | 962 | 946 | |||||
Regulatory balancing accounts | 1,326 | 1,222 | |||||
Other | 902 | 862 | |||||
Regulatory assets | 229 | 615 | |||||
Inventories: | |||||||
Gas stored underground and fuel oil | 116 | 115 | |||||
Materials and supplies | 389 | 366 | |||||
Other | 698 | 465 | |||||
Total current assets | 6,290 | 6,281 | |||||
Property, Plant, and Equipment | |||||||
Electric | 56,860 | 55,133 | |||||
Gas | 20,798 | 19,641 | |||||
Construction work in progress | 2,855 | 2,471 | |||||
Total property, plant, and equipment | 80,513 | 77,245 | |||||
Accumulated depreciation | (24,308 | ) | (23,456 | ) | |||
Net property, plant, and equipment | 56,205 | 53,789 | |||||
Other Noncurrent Assets | |||||||
Regulatory assets | 4,429 | 3,793 | |||||
Nuclear decommissioning trusts | 2,917 | 2,863 | |||||
Income taxes receivable | 66 | 64 | |||||
Other | 1,289 | 1,094 | |||||
Total other noncurrent assets | 8,701 | 7,814 | |||||
TOTAL ASSETS | $ | 71,196 | $ | 67,884 | |||
See accompanying Notes to the Condensed Consolidated Financial Statements. |
(Unaudited) | |||||||
Balance At | |||||||
September 30, 2018 | December 31, 2017 | ||||||
(in millions. except share amounts) | |||||||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Short-term borrowings | $ | 750 | $ | 799 | |||
Long-term debt, classified as current | 193 | 445 | |||||
Accounts payable: | |||||||
Trade creditors | 1,699 | 1,644 | |||||
Regulatory balancing accounts | 1,230 | 1,120 | |||||
Other | 575 | 538 | |||||
Disputed claims and customer refunds | 217 | 243 | |||||
Interest payable | 149 | 214 | |||||
Wildfire-related claims | 2,794 | 561 | |||||
Other | 1,904 | 1,457 | |||||
Total current liabilities | 9,511 | 7,021 | |||||
Noncurrent Liabilities | |||||||
Long-term debt | 18,057 | 17,403 | |||||
Regulatory liabilities | 8,607 | 8,679 | |||||
Pension and other post-retirement benefits | 1,910 | 2,026 | |||||
Asset retirement obligations | 4,999 | 4,899 | |||||
Deferred income taxes | 5,960 | 5,963 | |||||
Other | 2,367 | 2,146 | |||||
Total noncurrent liabilities | 41,900 | 41,116 | |||||
Contingencies and Commitments (Note 9) | |||||||
Shareholders' Equity | |||||||
Preferred stock | 258 | 258 | |||||
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates | 1,322 | 1,322 | |||||
Additional paid-in capital | 8,505 | 8,505 | |||||
Reinvested earnings | 9,695 | 9,656 | |||||
Accumulated other comprehensive income | 5 | 6 | |||||
Total shareholders' equity | 19,785 | 19,747 | |||||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 71,196 | $ | 67,884 | |||
See accompanying Notes to the Condensed Consolidated Financial Statements. |
(Unaudited) | |||||||
Nine Months Ended September 30, | |||||||
(in millions) | 2018 | 2017 | |||||
Cash Flows from Operating Activities | |||||||
Net income | $ | 47 | $ | 1,491 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, amortization, and decommissioning | 2,257 | 2,134 | |||||
Allowance for equity funds used during construction | (97 | ) | (63 | ) | |||
Deferred income taxes and tax credits, net | 5 | 848 | |||||
Disallowed capital expenditures | (38 | ) | 47 | ||||
Other | 170 | 196 | |||||
Effect of changes in operating assets and liabilities: | |||||||
Accounts receivable | (200 | ) | (58 | ) | |||
Wildfire-related insurance receivable | 64 | (166 | ) | ||||
Inventories | (24 | ) | (35 | ) | |||
Accounts payable | 245 | 76 | |||||
Wildfire-related claims | 2,233 | 12 | |||||
Income taxes receivable/payable | — | 135 | |||||
Other current assets and liabilities | (156 | ) | 36 | ||||
Regulatory assets, liabilities, and balancing accounts, net | (128 | ) | (30 | ) | |||
Other noncurrent assets and liabilities | (194 | ) | 69 | ||||
Net cash provided by operating activities | 4,184 | 4,692 | |||||
Cash Flows from Investing Activities | |||||||
Capital expenditures | (4,592 | ) | (3,938 | ) | |||
Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,121 | 1,043 | |||||
Purchases of nuclear decommissioning trust investments | (1,165 | ) | (1,071 | ) | |||
Other | 19 | 16 | |||||
Net cash used in investing activities | (4,617 | ) | (3,950 | ) | |||
Cash Flows from Financing Activities | |||||||
Borrowings under revolving credit facilities | 650 | — | |||||
Repayments under revolving credit facilities | (650 | ) | — | ||||
Net issuances (repayments) of commercial paper, net of discount of $0 and $4 at respective dates | (50 | ) | (652 | ) | |||
Short-term debt financing | 250 | 250 | |||||
Short-term debt matured | (250 | ) | (250 | ) | |||
Proceeds from issuance of long-term debt, net of discount and issuance costs of $7 and $11 at respective dates | 793 | 734 | |||||
Long-term debt matured or repurchased | (400 | ) | (345 | ) | |||
Preferred stock dividends paid | — | (10 | ) | ||||
Common stock dividends paid | — | (784 | ) | ||||
Equity contribution from PG&E Corporation | — | 405 | |||||
Other | 14 | (91 | ) | ||||
Net cash provided by (used in) financing activities | 357 | (743 | ) | ||||
Net change in cash and cash equivalents | (76 | ) | (1 | ) | |||
Cash and cash equivalents at January 1 | 447 | 71 | |||||
Cash and cash equivalents at September 30 | $ | 371 | $ | 70 |
Supplemental disclosures of cash flow information | |||||||
Cash received (paid) for: | |||||||
Interest, net of amounts capitalized | $ | (640 | ) | $ | (636 | ) | |
Income taxes, net | (59 | ) | 158 | ||||
Supplemental disclosures of noncash investing and financing activities | |||||||
Capital expenditures financed through accounts payable | $ | 348 | $ | 301 | |||
Terminated capital leases | 161 | — | |||||
See accompanying Notes to the Condensed Consolidated Financial Statements. |
Pension Benefits | Other Benefits | ||||||||||||||
Three Months Ended September 30, | |||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Service cost for benefits earned (1) | $ | 128 | $ | 118 | $ | 16 | $ | 14 | |||||||
Interest cost | 171 | 178 | 17 | 20 | |||||||||||
Expected return on plan assets | (255 | ) | (193 | ) | (33 | ) | (24 | ) | |||||||
Amortization of prior service cost | (1 | ) | (1 | ) | 4 | 4 | |||||||||
Amortization of net actuarial loss | 1 | 6 | (1 | ) | 1 | ||||||||||
Net periodic benefit cost | 44 | 108 | 3 | 15 | |||||||||||
Regulatory account transfer (2) | 41 | (23 | ) | — | — | ||||||||||
Total | $ | 85 | $ | 85 | $ | 3 | $ | 15 | |||||||
Pension Benefits | Other Benefits | ||||||||||||||
Nine Months Ended September 30, | |||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Service cost for benefits earned (1) | $ | 385 | $ | 354 | $ | 49 | $ | 44 | |||||||
Interest cost | 515 | 535 | 52 | 58 | |||||||||||
Expected return on plan assets | (766 | ) | (578 | ) | (98 | ) | (73 | ) | |||||||
Amortization of prior service cost | (4 | ) | (5 | ) | 11 | 12 | |||||||||
Amortization of net actuarial loss | 4 | 17 | (4 | ) | 3 | ||||||||||
Net periodic benefit cost | 134 | 323 | 10 | 44 | |||||||||||
Regulatory account transfer (2) | 118 | (69 | ) | — | — | ||||||||||
Total | $ | 252 | $ | 254 | $ | 10 | $ | 44 | |||||||
Pension Benefits | Other Benefits | Total | |||||||||
(in millions, net of income tax) | Three Months Ended September 30, 2018 | ||||||||||
Beginning balance | $ | (30 | ) | $ | 17 | $ | (13 | ) | |||
Amounts reclassified from other comprehensive income: | |||||||||||
Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) | (1 | ) | 3 | 2 | |||||||
Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) (1) | 1 | (1 | ) | — | |||||||
Regulatory account transfer (net of taxes of $0 and $1, respectively) (1) | 1 | (2 | ) | (1 | ) | ||||||
Net current period other comprehensive gain (loss) | 1 | — | 1 | ||||||||
Ending balance | $ | (29 | ) | $ | 17 | $ | (12 | ) | |||
Pension Benefits | Other Benefits | Total | |||||||||
(in millions, net of income tax) | Three Months Ended September 30, 2017 | ||||||||||
Beginning balance | $ | (25 | ) | $ | 17 | $ | (8 | ) | |||
Amounts reclassified from other comprehensive income: (1) | |||||||||||
Amortization of prior service cost (net of taxes of $0 and $2, respectively) | (1 | ) | 2 | 1 | |||||||
Amortization of net actuarial loss (net of taxes of $2 and $0, respectively) | 4 | 1 | 5 | ||||||||
Regulatory account transfer (net of taxes of $2 and $2, respectively) | (3 | ) | (3 | ) | (6 | ) | |||||
Net current period other comprehensive gain (loss) | — | — | — | ||||||||
Ending balance | $ | (25 | ) | $ | 17 | $ | (8 | ) | |||
Pension Benefits | Other Benefits | Total | |||||||||
(in millions, net of income tax) | Nine Months Ended September 30, 2018 | ||||||||||
Beginning balance | $ | (25 | ) | $ | 17 | $ | (8 | ) | |||
Amounts reclassified from other comprehensive income: | |||||||||||
Amortization of prior service cost (net of taxes of $1 and $3, respectively) (1) | (3 | ) | 8 | 5 | |||||||
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1) | 3 | (3 | ) | — | |||||||
Regulatory account transfer (net of taxes of $0 and $2, respectively) (1) | 1 | (5 | ) | (4 | ) | ||||||
Reclassification of stranded income tax to retained earnings | (5 | ) | — | (5 | ) | ||||||
Net current period other comprehensive gain (loss) | $ | (4 | ) | $ | — | $ | (4 | ) | |||
Ending balance | (29 | ) | 17 | (12 | ) | ||||||
Pension Benefits | Other Benefits | Total | |||||||||
(in millions, net of income tax) | Nine Months Ended September 30, 2017 | ||||||||||
Beginning balance | $ | (25 | ) | $ | 16 | $ | (9 | ) | |||
Amounts reclassified from other comprehensive income: (1) | |||||||||||
Amortization of prior service cost (net of taxes of $2 and $5, respectively) | (3 | ) | 7 | 4 | |||||||
Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) | 10 | 2 | 12 | ||||||||
Regulatory account transfer (net of taxes of $5 and $6, respectively) | (7 | ) | (8 | ) | (15 | ) | |||||
Net current period other comprehensive gain (loss) | $ | — | $ | 1 | $ | 1 | |||||
Ending balance | (25 | ) | 17 | (8 | ) | ||||||
(in millions) | Three Months Ended September 30, 2018 | Nine Months Ended September 30, 2018 | |||||
Electric | |||||||
Revenue from contracts with customers | |||||||
Residential | $ | 1,649 | $ | 4,023 | |||
Commercial | 1,430 | 3,737 | |||||
Industrial | 448 | 1,126 | |||||
Agricultural | 523 | 966 | |||||
Public street and highway lighting | 18 | 55 | |||||
Other (1) | (273 | ) | (388 | ) | |||
Total revenue from contracts with customers - electric | 3,795 | 9,519 | |||||
Regulatory balancing accounts (2) | (328 | ) | 211 | ||||
Total electric operating revenue | $ | 3,467 | $ | 9,730 | |||
Natural gas | |||||||
Revenue from contracts with customers | |||||||
Residential | $ | 242 | $ | 1,652 | |||
Commercial | 87 | 402 | |||||
Transportation service only | 287 | 847 | |||||
Other (1) | 30 | (149 | ) | ||||
Total revenue from contracts with customers - gas | 646 | 2,752 | |||||
Regulatory balancing accounts (2) | 269 | 190 | |||||
Total natural gas operating revenue | 915 | 2,942 | |||||
Total operating revenues | $ | 4,382 | $ | 12,672 | |||
Asset Balance at | |||||||
(in millions) | September 30, 2018 | December 31, 2017 | |||||
Pension benefits | $ | 1,837 | $ | 1,954 | |||
Environmental compliance costs | 851 | 837 | |||||
Utility retained generation | 285 | 319 | |||||
Price risk management | 67 | 65 | |||||
Unamortized loss, net of gain, on reacquired debt | 80 | 79 | |||||
Catastrophic event memorandum account (1) | 760 | 274 | |||||
Wildfire expense memorandum account (2) | 77 | — | |||||
Fire hazard prevention memorandum account (3) | 65 | 1 | |||||
Other | 407 | 264 | |||||
Total long-term regulatory assets | $ | 4,429 | $ | 3,793 | |||
Liability Balance at | |||||||
(in millions) | September 30, 2018 | December 31, 2017 | |||||
Cost of removal obligations | $ | 5,888 | $ | 5,547 | |||
Deferred income taxes | 437 | 1,021 | |||||
Recoveries in excess of AROs | 489 | 624 | |||||
Public purpose programs | 660 | 590 | |||||
Other | 1,133 | 897 | |||||
Total long-term regulatory liabilities | $ | 8,607 | $ | 8,679 |
Receivable Balance at | |||||||
(in millions) | September 30, 2018 | December 31, 2017 | |||||
Electric distribution | $ | 31 | $ | — | |||
Electric transmission | 109 | 139 | |||||
Gas distribution and transmission | 624 | 486 | |||||
Energy procurement | 131 | 71 | |||||
Public purpose programs | 120 | 103 | |||||
Other | 311 | 423 | |||||
Total regulatory balancing accounts receivable | $ | 1,326 | $ | 1,222 |
Payable Balance at | |||||||
(in millions) | September 30, 2018 | December 31, 2017 | |||||
Electric distribution | $ | — | $ | 72 | |||
Electric transmission | 132 | 120 | |||||
Utility generation | 70 | 14 | |||||
Gas distribution and transmission | 9 | — | |||||
Energy procurement | 69 | 149 | |||||
Public purpose programs | 588 | 452 | |||||
Other | 362 | 313 | |||||
Total regulatory balancing accounts payable | $ | 1,230 | $ | 1,120 |
(in millions) | Termination Date | Facility Limit | Letters of Credit Outstanding | Borrowings | Facility Availability | ||||||||||||
PG&E Corporation | April 2022 | $ | 300 | (1) | $ | — | $ | — | $ | 300 | |||||||
Utility | April 2022 | 3,000 | (2) | 87 | — | 2,913 | |||||||||||
Total revolving credit facilities | $ | 3,300 | $ | 87 | $ | — | $ | 3,213 | |||||||||
PG&E Corporation | Utility | ||||||
(in millions) | Total Equity | Total Shareholders' Equity | |||||
Balance at December 31, 2017 | $ | 19,472 | $ | 19,747 | |||
Comprehensive income | 33 | 48 | |||||
Common stock issued | 137 | — | |||||
Share-based compensation | 64 | — | |||||
Preferred stock dividend requirement | — | (10 | ) | ||||
Preferred stock dividend requirement of subsidiary | (10 | ) | — | ||||
Balance at September 30, 2018 | $ | 19,696 | $ | 19,785 |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions, except per share amounts) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Income available for common shareholders | $ | 564 | $ | 550 | $ | 22 | $ | 1,532 | |||||||
Weighted average common shares outstanding, basic | 517 | 513 | 516 | 511 | |||||||||||
Add incremental shares from assumed conversions: | |||||||||||||||
Employee share-based compensation | — | 3 | 1 | 3 | |||||||||||
Weighted average common shares outstanding, diluted | 517 | 516 | 517 | 514 | |||||||||||
Total earnings per common share, diluted | $ | 1.09 | $ | 1.07 | $ | 0.04 | $ | 2.98 |
Contract Volume at | ||||||||
Underlying Product | Instruments | September 30, 2018 | December 31, 2017 | |||||
Natural Gas (1) (MMBtus (2)) | Forwards, Futures and Swaps | 250,021,802 | 228,768,745 | |||||
Options | 29,534,224 | 60,736,806 | ||||||
Electricity (Megawatt-hours) | Forwards, Futures and Swaps | 3,939,691 | 2,872,013 | |||||
Congestion Revenue Rights (3) | 316,451,690 | 312,272,177 | ||||||
Commodity Risk | |||||||||||||||
(in millions) | Gross Derivative Balance | Netting | Cash Collateral | Total Derivative Balance | |||||||||||
Current assets – other | $ | 34 | $ | (2 | ) | $ | 5 | $ | 37 | ||||||
Other noncurrent assets – other | 88 | — | — | 88 | |||||||||||
Current liabilities – other | (39 | ) | 2 | 12 | (25 | ) | |||||||||
Noncurrent liabilities – other | (67 | ) | — | 4 | (63 | ) | |||||||||
Total commodity risk | $ | 16 | $ | — | $ | 21 | $ | 37 |
Commodity Risk | |||||||||||||||
(in millions) | Gross Derivative Balance | Netting | Cash Collateral | Total Derivative Balance | |||||||||||
Current assets – other | $ | 30 | $ | (3 | ) | $ | 10 | $ | 37 | ||||||
Other noncurrent assets – other | 103 | (1 | ) | — | 102 | ||||||||||
Current liabilities – other | (47 | ) | 3 | 13 | (31 | ) | |||||||||
Noncurrent liabilities – other | (66 | ) | 1 | 8 | (57 | ) | |||||||||
Total commodity risk | $ | 20 | $ | — | $ | 31 | $ | 51 |
• | 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. |
Fair Value Measurements | |||||||||||||||||||
September 30, 2018 | |||||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Netting (1) | Total | ||||||||||||||
Assets: | |||||||||||||||||||
Short-term investments | $ | 377 | — | — | — | $ | 377 | ||||||||||||
Nuclear decommissioning trusts | |||||||||||||||||||
Short-term investments | 14 | — | — | — | 14 | ||||||||||||||
Global equity securities | 1,970 | — | — | — | 1,970 | ||||||||||||||
Fixed-income securities | 738 | 631 | — | — | 1,369 | ||||||||||||||
Assets measured at NAV | — | — | — | — | 19 | ||||||||||||||
Total nuclear decommissioning trusts (2) | 2,722 | 631 | — | — | 3,372 | ||||||||||||||
Price risk management instruments (Note 7) | |||||||||||||||||||
Electricity | 1 | 5 | 110 | 2 | 118 | ||||||||||||||
Gas | — | 6 | — | 1 | 7 | ||||||||||||||
Total price risk management instruments | 1 | 11 | 110 | 3 | 125 | ||||||||||||||
Rabbi trusts | |||||||||||||||||||
Fixed-income securities | — | 75 | — | — | 75 | ||||||||||||||
Life insurance contracts | — | 68 | — | — | 68 | ||||||||||||||
Total rabbi trusts | — | 143 | — | — | 143 | ||||||||||||||
Long-term disability trust | |||||||||||||||||||
Short-term investments | 8 | — | — | — | 8 | ||||||||||||||
Assets measured at NAV | — | — | — | — | 112 | ||||||||||||||
Total long-term disability trust | 8 | — | — | — | 120 | ||||||||||||||
TOTAL ASSETS | $ | 3,108 | $ | 785 | $ | 110 | $ | 3 | $ | 4,137 | |||||||||
Liabilities: | |||||||||||||||||||
Price risk management instruments (Note 7) | |||||||||||||||||||
Electricity | $ | 5 | $ | 12 | $ | 86 | $ | (17 | ) | $ | 86 | ||||||||
Gas | — | 3 | — | (1 | ) | 2 | |||||||||||||
TOTAL LIABILITIES | $ | 5 | $ | 15 | $ | 86 | $ | (18 | ) | $ | 88 | ||||||||
Fair Value Measurements | |||||||||||||||||||
December 31, 2017 | |||||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Netting (1) | Total | ||||||||||||||
Assets: | |||||||||||||||||||
Short-term investments | $ | 385 | $ | — | $ | — | $ | — | $ | 385 | |||||||||
Nuclear decommissioning trusts | |||||||||||||||||||
Short-term investments | 23 | — | — | — | 23 | ||||||||||||||
Global equity securities | 1,967 | — | — | — | 1,967 | ||||||||||||||
Fixed-income securities | 733 | 562 | — | — | 1,295 | ||||||||||||||
Assets measured at NAV | — | — | — | — | 18 | ||||||||||||||
Total nuclear decommissioning trusts (2) | 2,723 | 562 | — | — | 3,303 | ||||||||||||||
Price risk management instruments (Note 7) | |||||||||||||||||||
Electricity | — | 3 | 129 | 6 | 138 | ||||||||||||||
Gas | — | 1 | — | — | 1 | ||||||||||||||
Total price risk management instruments | — | 4 | 129 | 6 | 139 | ||||||||||||||
Rabbi trusts | |||||||||||||||||||
Fixed-income securities | — | 72 | — | — | 72 | ||||||||||||||
Life insurance contracts | — | 71 | — | — | 71 | ||||||||||||||
Total rabbi trusts | — | 143 | — | — | 143 | ||||||||||||||
Long-term disability trust | |||||||||||||||||||
Short-term investments | 8 | — | — | — | 8 | ||||||||||||||
Assets measured at NAV | — | — | — | — | 167 | ||||||||||||||
Total long-term disability trust | 8 | — | — | — | 175 | ||||||||||||||
TOTAL ASSETS | $ | 3,116 | $ | 709 | $ | 129 | $ | 6 | $ | 4,145 | |||||||||
Liabilities: | |||||||||||||||||||
Price risk management instruments (Note 7) | |||||||||||||||||||
Electricity | $ | 10 | $ | 15 | $ | 87 | $ | (25 | ) | $ | 87 | ||||||||
Gas | — | 1 | — | — | 1 | ||||||||||||||
TOTAL LIABILITIES | $ | 10 | $ | 16 | $ | 87 | $ | (25 | ) | $ | 88 | ||||||||
Fair Value at | ||||||||||||||
(in millions) | September 30, 2018 | |||||||||||||
Fair Value Measurement | Assets | Liabilities | Valuation Technique | Unobservable Input | Range (1) | |||||||||
Congestion revenue rights | $ | 110 | $ | 44 | Market approach | CRR auction prices | $ (18.61) - 32.26 | |||||||
Power purchase agreements | $ | — | $ | 42 | Discounted cash flow | Forward prices | $ 19.81 - 38.80 | |||||||
Fair Value at | ||||||||||||||
(in millions) | December 31, 2017 | |||||||||||||
Fair Value Measurement | Assets | Liabilities | Valuation Technique | Unobservable Input | Range (1) | |||||||||
Congestion revenue rights | $ | 129 | $ | 24 | Market approach | CRR auction prices | $ (16.03) - 11.99 | |||||||
Power purchase agreements | $ | — | $ | 63 | Discounted cash flow | Forward prices | $ 18.81 - 38.80 | |||||||
Price Risk Management Instruments | |||||||
(in millions) | 2018 | 2017 | |||||
Asset (liability) balance as of July 1 | $ | 34 | $ | 48 | |||
Net realized and unrealized gains: | |||||||
Included in regulatory assets and liabilities or balancing accounts (1) | (10 | ) | — | ||||
Asset (liability) balance as of September 30 | $ | 24 | $ | 48 | |||
Price Risk Management Instruments | |||||||
(in millions) | 2018 | 2017 | |||||
Asset (liability) balance as of January 1 | $ | 42 | $ | 55 | |||
Net realized and unrealized gains: | |||||||
Included in regulatory assets and liabilities or balancing accounts (1) | (18 | ) | (7 | ) | |||
Asset (liability) balance as of September 30 | $ | 24 | $ | 48 | |||
At September 30, 2018 | At December 31, 2017 | ||||||||||||||
(in millions) | Carrying Amount | Level 2 Fair Value | Carrying Amount | Level 2 Fair Value | |||||||||||
PG&E Corporation(1) | $ | 350 | $ | 350 | $ | 350 | $ | 350 | |||||||
Utility | 17,491 | 16,413 | 17,090 | 19,128 | |||||||||||
(in millions) | |||||||||||||||
As of September 30, 2018 | Amortized Cost | Total Unrealized Gains | Total Unrealized Losses | Total Fair Value | |||||||||||
Nuclear decommissioning trusts | |||||||||||||||
Short-term investments | $ | 14 | $ | — | $ | — | $ | 14 | |||||||
Global equity securities | 478 | 1,513 | (2 | ) | 1,989 | ||||||||||
Fixed-income securities | 1,369 | 28 | (28 | ) | 1,369 | ||||||||||
Total (1) | $ | 1,861 | $ | 1,541 | $ | (30 | ) | $ | 3,372 | ||||||
As of December 31, 2017 | |||||||||||||||
Nuclear decommissioning trusts | |||||||||||||||
Short-term investments | $ | 23 | $ | — | $ | — | $ | 23 | |||||||
Global equity securities | 524 | 1,463 | (2 | ) | 1,985 | ||||||||||
Fixed-income securities | 1,252 | 51 | (8 | ) | 1,295 | ||||||||||
Total (1) | $ | 1,799 | $ | 1,514 | $ | (10 | ) | $ | 3,303 | ||||||
As of | |||
(in millions) | September 30, 2018 | ||
Less than 1 year | $ | 69 | |
1–5 years | 401 | ||
5–10 years | 386 | ||
More than 10 years | 513 | ||
Total maturities of fixed-income securities | $ | 1,369 |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Proceeds from sales and maturities of nuclear decommissioning trust investments | $ | 319 | $ | 249 | $ | 1,121 | $ | 1,043 | |||||||
Gross realized gains on securities | 3 | 8 | 51 | 50 | |||||||||||
Gross realized losses on securities | (5 | ) | — | (14 | ) | (8 | ) |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Butte fire | |||||||||||||||
Third-Party Claims | $ | — | $ | 350 | $ | — | $ | 350 | |||||||
Insurance recoveries | — | (297 | ) | (7 | ) | (350 | ) | ||||||||
Total Butte fire | — | 53 | (7 | ) | — | ||||||||||
Northern California wildfires | |||||||||||||||
Third-Party Claims | — | — | 2,500 | — | |||||||||||
Insurance recoveries | (10 | ) | — | (385 | ) | — | |||||||||
Total Northern California wildfires | (10 | ) | — | 2,115 | — | ||||||||||
Total wildfire-related claims, net of insurance recoveries | $ | (10 | ) | $ | 53 | $ | 2,108 | $ | — |
Balance At | |||||||
(in millions) | September 30, 2018 | December 31, 2017 | |||||
Butte fire | $ | 294 | $ | 561 | |||
Northern California wildfires | 2,500 | — | |||||
Total wildfire-related claims | $ | 2,794 | $ | 561 |
Insurance Receivable (in millions) | |||
Accrued insurance recoveries | $ | 385 | |
Reimbursements | (13 | ) | |
Balance at September 30, 2018 | $ | 372 |
Loss Accrual (in millions) | |||
Balance at December 31, 2015 | $ | — | |
Accrued losses | 750 | ||
Payments (1) | (60 | ) | |
Balance at December 31, 2016 | 690 | ||
Accrued losses | 350 | ||
Payments (1) | (479 | ) | |
Balance at December 31, 2017 | 561 | ||
Accrued losses | — | ||
Payments (1) | (267 | ) | |
Balance at September 30, 2018 | $ | 294 | |
Insurance Receivable (in millions) | |||
Balance at December 31, 2015 | $ | — | |
Accrued insurance recoveries | 625 | ||
Reimbursements | (50) | ||
Balance at December 31, 2016 | 575 | ||
Accrued insurance recoveries | 297 | ||
Reimbursements | (276) | ||
Balance at December 31, 2017 | 596 | ||
Accrued insurance recoveries | — | ||
Reimbursements | (436 | ) | |
Balance at September 30, 2018 | $ | 160 |
Balance at | |||||||
September 30, | December 31, | ||||||
(in millions) | 2018 | 2017 | |||||
Topock natural gas compressor station | $ | 362 | $ | 334 | |||
Hinkley natural gas compressor station | 151 | 147 | |||||
Former manufactured gas plant sites owned by the Utility or third parties (1) | 375 | 320 | |||||
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) | 116 | 115 | |||||
Fossil fuel-fired generation facilities and sites (3) | 136 | 123 | |||||
Total environmental remediation liability | $ | 1,140 | $ | 1,039 | |||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||
Earnings | Earnings per Common Share (Diluted) | Earnings | Earnings per Common Share (Diluted) | ||||||||||||||||||||||||||||
(in millions, except per share amounts) | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | |||||||||||||||||||||||
PG&E Corporation’s Earnings on a GAAP basis | $ | 564 | $ | 550 | $ | 1.09 | $ | 1.07 | $ | 22 | $ | 1,532 | $ | 0.04 | $ | 2.98 | |||||||||||||||
Items Impacting Comparability: (1) | |||||||||||||||||||||||||||||||
Northern California wildfire-related costs, net of insurance (2) | 31 | — | 0.06 | — | 1,639 | — | 3.17 | — | |||||||||||||||||||||||
Pipeline-related expenses (3) | 9 | 12 | 0.02 | 0.02 | 25 | 45 | 0.05 | 0.09 | |||||||||||||||||||||||
Butte fire-related costs, net of insurance (4) | 6 | 42 | 0.01 | 0.08 | 17 | 27 | 0.03 | 0.05 | |||||||||||||||||||||||
Reduction in gas-related capital disallowances (5) | (27 | ) | — | (0.05 | ) | — | (27 | ) | — | (0.05 | ) | — | |||||||||||||||||||
2017 insurance premiums cost recoveries (6) | — | — | — | — | (23 | ) | — | (0.05 | ) | — | |||||||||||||||||||||
Fines and penalties (7) | — | 11 | — | 0.02 | — | 47 | — | 0.09 | |||||||||||||||||||||||
Diablo Canyon settlement-related disallowance (8) | — | — | — | — | — | 32 | — | 0.06 | |||||||||||||||||||||||
Legal and regulatory-related expenses (9) | — | 1 | — | — | — | 5 | — | 0.01 | |||||||||||||||||||||||
GT&S revenue timing impact (10) | — | — | — | — | — | (88 | ) | — | (0.17 | ) | |||||||||||||||||||||
Net benefit from derivative litigation settlement (11) | — | (38 | ) | — | (0.07 | ) | — | (38 | ) | — | (0.07 | ) | |||||||||||||||||||
PG&E Corporation’s Non- GAAP Earnings from Operations (12) | $ | 582 | $ | 578 | $ | 1.13 | $ | 1.12 | $ | 1,652 | $ | 1,562 | $ | 3.19 | $ | 3.04 | |||||||||||||||
Third Quarter 2018 vs. 2017 | Year to Date 2018 vs. 2017 | ||||||||||||||
(in millions, except per share amounts) | Earnings | Earnings per Common Share (Diluted) | Earnings | Earnings per Common Share (Diluted) | |||||||||||
2017 Non- GAAP Earnings from Operations (1) | $ | 578 | $ | 1.12 | $ | 1,562 | $ | 3.04 | |||||||
Growth in rate base earnings | 32 | 0.06 | 97 | 0.18 | |||||||||||
Timing of taxes (2) | 12 | 0.02 | 13 | 0.02 | |||||||||||
Insurance premium cost recoveries (3) | 6 | 0.01 | 33 | 0.06 | |||||||||||
Resolution of regulatory items (4) | — | — | 29 | 0.06 | |||||||||||
Timing and duration of nuclear refueling outages | — | — | 12 | 0.02 | |||||||||||
Timing of 2017 operational spend (5) | (31 | ) | (0.06 | ) | (31 | ) | (0.06 | ) | |||||||
Decrease in authorized return on equity (6) | (7 | ) | (0.01 | ) | (21 | ) | (0.03 | ) | |||||||
Tax impact of stock compensation (7) | — | — | (44 | ) | (0.08 | ) | |||||||||
Increase in shares outstanding | — | — | — | (0.02 | ) | ||||||||||
Miscellaneous | (8 | ) | (0.01 | ) | 2 | — | |||||||||
2018 Non-GAAP Earnings from Operations (1) | $ | 582 | $ | 1.13 | $ | 1,652 | $ | 3.19 | |||||||
• | The Impact of the Northern California Wildfires. PG&E Corporation and the Utility face several uncertainties in connection with the Northern California wildfires, related to: the amount of additional possible loss related to third party claims (the Utility recorded a charge of $2.5 billion, which reflects the low end of the range of loss); recoverability of clean-up and repair costs (the Utility incurred costs of $308 million for clean-up and repair of the Utility’s facilities through September 30, 2018); fines or penalties, which could be material, if the CPUC or any law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations; the applicability of the doctrine of inverse condemnation in the Northern California wildfires litigation, which the Utility continues challenging in courts; the recoverability of the above mentioned costs even if a court decision imposes liability under the doctrine of inverse condemnation, and the maximum amount that the CPUC is expected to determine, as a result of SB 901, that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. (See Notes 3 and 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Item 1A. Risk Factors” in the 2017 Form 10-K and in Part II below under “Item 1A. Risk Factors.”) |
• | The Utility's Compliance with the CPUC Capital Structure. The CPUC’s capital structure decisions require the Utility to maintain a 52% equity ratio on average over the period that the authorized capital structure is in place, and to file an application for a waiver to the capital structure condition if an adverse financial event reduces its equity ratio below 51%. The capital structure condition waiver would be subject to CPUC approval. The net charges the Utility recorded in connection with the Northern California wildfires to date, and described herein, did not result in noncompliance by the Utility with its authorized capital structure. However, in the future, maintaining compliance with the Utility’s authorized capital structure may require PG&E Corporation to issue a significant amount of equity, depending on the timing and amount of any claims payments and whether additional charges are recorded. If the Utility submits an application to the CPUC for a waiver to its capital structure condition, the Utility shall not be considered in violation of the condition during the period the waiver application is pending resolution. |
• | The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19, and TO20 rate cases, future cost of capital proceedings, as well as the remand decision by the Ninth Circuit regarding an ROE incentive adder for transmission facilities, and its ability to timely recover costs not in rates already incurred and to be incurred in the future, including those tracked in its 2018 CEMA filing, WEMA and FHPMA, and insurance premiums in excess of the Utility’s currently authorized revenue requirements. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors. (See Notes 3 and 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below.) |
• | The Amount and Timing of the Utility's Financing Needs. PG&E Corporation’s and the Utility’s ability to access the capital markets, ability to borrow under their loan financing arrangements, and the terms and rates of future financings could be materially affected by the outcome of, or market perception of, the matters discussed in Note 9 of the Notes to the Condensed Consolidated Financial Statements. PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. For the nine months ended September 30, 2018, PG&E Corporation issued $137 million of common stock and made no equity contributions to the Utility. PG&E Corporation may seek to issue additional equity to pay claims, losses, fines, and penalties that may be required by the outcome of litigation and enforcement matters. Additional issuances of equity, if any, could have a material dilutive impact on PG&E Corporation’s EPS. |
• | The Outcome of Enforcement, Litigation, and Regulatory Matters. The Utility’s financial results may continue to be impacted by the outcome of current and future enforcement, litigation, and regulatory matters, including the impact of the Butte fire, the safety culture OII and any related fines, penalties, or other ratemaking tools that could be imposed by the CPUC, including the outcome of phase two of the ex parte OII, the potential recommendations that the third-party monitor (retained by the Utility in the first quarter of 2017 as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction) may make, and potential penalties in connection with the Utility’s safety and other self-reports. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) |
• | The Changes in the Utility Industry. The Utility is committed to delivering safe, reliable, sustainable, and affordable electric and gas services to its customers. Increasing demands from state laws and policies relating to increased renewable energy resources, the reduction of GHG emissions, the expansion of energy efficiency goals, the development and widespread deployment of distributed generation and self-generation resources, and the development of energy storage technologies have increased pressure on the Utility to achieve efficiencies in its operations while continuing to provide customers with safe, reliable, and affordable service. (See “Other Regulatory Proceedings” below.) |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Consolidated Total | $ | 564 | $ | 550 | $ | 22 | $ | 1,532 | |||||||
PG&E Corporation | (4 | ) | 40 | (15 | ) | 51 | |||||||||
Utility | $ | 568 | $ | 510 | $ | 37 | $ | 1,481 |
Three Months Ended September 30, 2018 | Three Months Ended September 30, 2017 | ||||||||||||||||||||||
Revenues/Costs: | Revenues/Costs: | ||||||||||||||||||||||
(in millions) | That Impacted Earnings | That Did Not Impact Earnings | Total Utility | That Impacted Earnings | That Did Not Impact Earnings | Total Utility | |||||||||||||||||
Electric operating revenues | $ | 1,996 | $ | 1,471 | $ | 3,467 | $ | 2,002 | $ | 1,645 | $ | 3,647 | |||||||||||
Natural gas operating revenues | 778 | 137 | 915 | 722 | 147 | 869 | |||||||||||||||||
Total operating revenues | 2,774 | 1,608 | 4,382 | 2,724 | 1,792 | 4,516 | |||||||||||||||||
Cost of electricity | — | 1,256 | 1,256 | — | 1,466 | 1,466 | |||||||||||||||||
Cost of natural gas | — | 69 | 69 | — | 78 | 78 | |||||||||||||||||
Operating and maintenance | 1,247 | 364 | 1,611 | 1,127 | 262 | 1,389 | |||||||||||||||||
Wildfire-related claims, net of insurance recoveries | (10 | ) | — | (10 | ) | 53 | — | 53 | |||||||||||||||
Depreciation, amortization, and decommissioning | 759 | — | 759 | 710 | — | 710 | |||||||||||||||||
Total operating expenses | 1,996 | 1,689 | 3,685 | 1,890 | 1,806 | 3,696 | |||||||||||||||||
Operating income (loss) | 778 | (81 | ) | 697 | 834 | (14 | ) | 820 | |||||||||||||||
Interest income | 14 | — | 14 | 10 | — | 10 | |||||||||||||||||
Interest expense | (229 | ) | — | (229 | ) | (217 | ) | — | (217 | ) | |||||||||||||
Other income, net | 22 | 81 | 103 | 24 | 14 | 38 | |||||||||||||||||
Income before income taxes | $ | 585 | $ | — | $ | 585 | $ | 651 | $ | — | $ | 651 | |||||||||||
Income tax provision (1) | 14 | 138 | |||||||||||||||||||||
Net income | 571 | 513 | |||||||||||||||||||||
Preferred stock dividend requirement (1) | 3 | 3 | |||||||||||||||||||||
Income Available for Common Stock | $ | 568 | $ | 510 | |||||||||||||||||||
Nine Months Ended September 30, 2018 | Nine Months Ended September 30, 2017 | ||||||||||||||||||||||
Revenues/Costs: | Revenues/Costs: | ||||||||||||||||||||||
(in millions) | That Impacted Earnings | That Did Not Impact Earnings | Total Utility | That Impacted Earnings | That Did Not Impact Earnings | Total Utility | |||||||||||||||||
Electric operating revenues | $ | 5,911 | $ | 3,819 | $ | 9,730 | $ | 5,933 | $ | 4,105 | $ | 10,038 | |||||||||||
Natural gas operating revenues | 2,268 | 674 | 2,942 | 2,261 | 738 | 2,999 | |||||||||||||||||
Total operating revenues | 8,179 | 4,493 | 12,672 | 8,194 | 4,843 | 13,037 | |||||||||||||||||
Cost of electricity | — | 3,038 | 3,038 | — | 3,436 | 3,436 | |||||||||||||||||
Cost of natural gas | — | 437 | 437 | — | 524 | 524 | |||||||||||||||||
Operating and maintenance | 3,742 | 1,260 | 5,002 | 3,594 | 924 | 4,518 | |||||||||||||||||
Wildfire-related claims, net of insurance recoveries | 2,108 | — | 2,108 | — | — | — | |||||||||||||||||
Depreciation, amortization, and decommissioning | 2,257 | — | 2,257 | 2,134 | — | 2,134 | |||||||||||||||||
Total operating expenses | 8,107 | 4,735 | 12,842 | 5,728 | 4,884 | 10,612 | |||||||||||||||||
Operating income (loss) | 72 | (242 | ) | (170 | ) | 2,466 | (41 | ) | 2,425 | ||||||||||||||
Interest income | 34 | — | 34 | 22 | — | 22 | |||||||||||||||||
Interest expense | (668 | ) | — | (668 | ) | (655 | ) | — | (655 | ) | |||||||||||||
Other income, net | 79 | 242 | 321 | 52 | 41 | 93 | |||||||||||||||||
Income (loss) before income taxes | $ | (483 | ) | $ | — | $ | (483 | ) | $ | 1,885 | $ | — | $ | 1,885 | |||||||||
Income tax provision (benefit) (1) | (530 | ) | 394 | ||||||||||||||||||||
Net income | 47 | 1,491 | |||||||||||||||||||||
Preferred stock dividend requirement (1) | 10 | 10 | |||||||||||||||||||||
Income Available for Common Stock | $ | 37 | $ | 1,481 | |||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Federal statutory income tax rate | 21.0 | % | 35.0 | % | 21.0 | % | 35.0 | % | |||
Increase (decrease) in income tax rate resulting from: | |||||||||||
State income tax (net of federal benefit) (1) | 2.1 | % | 2.6 | % | 22.8 | % | 2.4 | % | |||
Effect of regulatory treatment of fixed asset differences (2) | (15.9 | )% | (13.0 | )% | 56.4 | % | (12.9 | )% | |||
Tax credits | (0.5 | )% | (0.5 | )% | 1.9 | % | (1.1 | )% | |||
Other, net | (4.2 | )% | (2.9 | )% | 7.7 | % | (2.5 | )% | |||
Effective tax rate | 2.5 | % | 21.2 | % | 109.8 | % | 20.9 | % | |||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Cost of purchased power | $ | 1,174 | $ | 1,392 | $ | 2,846 | $ | 3,255 | |||||||
Fuel used in own generation facilities | 82 | 74 | 192 | 181 | |||||||||||
Total cost of electricity | $ | 1,256 | $ | 1,466 | $ | 3,038 | $ | 3,436 | |||||||
Average cost of purchased power per kWh (1) | $ | 0.252 | $ | 0.151 | $ | 0.157 | $ | 0.126 | |||||||
Total purchased power (in millions of kWh) (2) | 4,658 | 9,189 | 18,101 | 25,905 | |||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Cost of natural gas sold | $ | 45 | $ | 50 | $ | 355 | $ | 436 | |||||||
Transportation cost of natural gas sold | 24 | 28 | 82 | 88 | |||||||||||
Total cost of natural gas | $ | 69 | $ | 78 | $ | 437 | $ | 524 | |||||||
Average cost per Mcf (1) of natural gas sold | $ | 1.55 | $ | 1.85 | $ | 2.25 | $ | 2.71 | |||||||
Total natural gas sold (in millions of Mcf) | 29 | 27 | 158 | 161 | |||||||||||
Nine Months Ended September 30, | |||||||
(in millions) | 2018 | 2017 | |||||
Net cash provided by operating activities | $ | 4,184 | $ | 4,692 | |||
Net cash used in investing activities | (4,617 | ) | (3,950 | ) | |||
Net cash provided by (used in) financing activities | 357 | (743 | ) | ||||
Net change in cash and cash equivalents | $ | (76 | ) | $ | (1 | ) |
• | the timing and amount of costs in connection with the Northern California wildfires (and the timing and amount of related insurance recoveries), as well as additional potential liabilities in connection with third-party claims and fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations; |
• | the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see "Enforcement and Litigation Matters" in Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part II, Item 1. Legal Proceedings for more information); |
• | the timing and amount of premium payments related to wildfire insurance (see “Wildfire Insurance” in Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information); |
• | the Tax Act, which is expected to accelerate the timing of federal tax payments and reduce revenue requirements, resulting in lower operating cash flows (see “Overview” above and “Regulatory Matters” below for more information); |
• | the timing and outcomes of the 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19 and TO20 rate cases, 2018 CEMA filing, and other ratemaking and regulatory proceedings; |
• | the timing and amount of substantially increasing costs in connection with fire hazard prevention work (see "Overview" above and "Regulatory Matters" below for more information); and |
• | the timing of the resolution of the Chapter 11 disputed claims and the amount of principal and interest on these claims that the Utility will be required to pay. |
• | deferred consideration of replacement resources to the CPUC’s Integrated Resource Planning proceeding; |
• | authorized rate recovery for up to $211.3 million (compared with the $352.1 million requested by the Utility) for an employee retention program; |
• | authorized rate recovery for an employee retraining program of $11.3 million requested by the Utility; |
• | rejected rate recovery of the proposed $85 million for the community impacts mitigation program on the grounds that rate recovery for such a program requires legislative authorization; |
• | authorized rate recovery of $18.6 million of the total Diablo Canyon license renewal cost of $53 million and rate recovery of cancelled project costs equal to 100% of direct costs incurred prior to June 30, 2016, and 25% of direct costs incurred after June 30, 2016, based on a settlement agreement among the Utility, the Joint Parties, and certain other parties that the Utility filed with the CPUC in May 2017; and |
• | approved the amortization of the book value for Diablo Canyon consistent with the Diablo Canyon closure schedule. |
• | approving the community impact mitigation settlement of $85 million, originally proposed in the joint settlement agreement; |
• | deferring implementation to its Integrated Resource Planning to ensure that there is no increase in GHG emissions as a result of the Diablo Canyon retirement; and |
• | approving full funding of the $352.1 million Diablo Canyon employee retention program, originally proposed in the joint settlement agreement. |
• | imposing more restrictive forest management practices and providing support and incentives to facilitate that work; |
• | providing factors that the CPUC should consider when it conducts a review of the reasonableness of costs and expenses arising from a catastrophic wildfire occurring on or after January 1, 2019; |
• | in applications for cost recovery in connection with the 2017 wildfires, directing the CPUC to consider the electric corporation's financial status and determine the maximum amount a utility can pay without harming customers or materially impacting its ability to provide adequate and safe service, and ensuring that the costs or expenses that are disallowed for recovery in rates assessed for the wildfires, in the aggregate, do not exceed that amount; |
• | authorizing the CPUC to issue a financing order that permits recovery, through issuance of recovery bonds (securitization), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 wildfires, any amounts in excess of the maximum disallowance (see above). Securitization is available, for prudently incurred costs, for the 2017 wildfires and catastrophic wildfires occurring on or after January 1, 2019; |
• | requiring electric corporations to prepare and submit to the CPUC a wildfire mitigation plan. Among other things, the plan will include a description of the preventive strategies and programs of electric corporations that are designed to minimize the risk of their electrical lines and equipment causing catastrophic wildfires and protocols related to plan activities. Failure to substantially comply with such plan will result in penalties. The CPUC will consider whether the cost of implementing the plan is just and reasonable in each electric corporation's GRC; |
• | establishing a Commission on Catastrophic Wildfire Cost and Recovery to evaluate wildfire reforms, including inverse condemnation reform, a potential state wildfire insurance fund, and other wildfire mitigation measures; and |
• | prohibiting an electric or gas corporation from recovering expenses for any annual salary, bonus, benefits, or other consideration of any value, paid to an officer of such utility from customers. |
• | adopting benchmark values used to set the PCIA rate that more closely resemble actual market prices for resource adequacy and renewable energy credits; |
• | allowing legacy utility-owned generation costs to be recovered from CCA customers; |
• | eliminating the 10-year limit on PCIA cost recovery for post-2002 utility owned generation and certain storage costs; and |
• | adding an annual true-up to the PCIA rate based on market sales for brown power, with further discussion in phase 2 of the PCIA proceeding regarding true-up of resource adequacy, and renewable energy credits. |
• | how to define climate change adaption for the IOUs; |
• | the climate-driven risks facing the IOUs; |
• | data, tools, resources, and guidance to instruct utilities on how to incorporate adaption in their existing planning and operational processes; and |
• | strategies to address climate change in CPUC proceedings, including impacts on disadvantaged communities. |
• | the impact of the Northern California wildfires, including whether the Utility will be able to timely recover costs incurred in connection with the Northern California wildfires in excess of the Utility's currently authorized revenue requirements; the timing and outcome of the remaining wildfire investigations and the extent to which the Utility will have liability associated with these fires; the timing and amount of insurance recoveries; and potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency were to bring an enforcement action and determined that the Utility failed to comply with applicable laws and regulations; |
• | the timing and outcome of the Butte fire litigation, the timing and outcome of any proceeding to recover costs in excess of insurance through rates; the effect, if any, that the SED’s $8.3 million citations issued in connection with the Butte fire may have on the Butte fire litigation; and whether additional investigations and proceedings in connection with the Butte fire will be opened and any additional fines or penalties imposed on the Utility; |
• | whether PG&E Corporation and the Utility are able to successfully challenge the application of the doctrine of inverse condemnation to the Northern California wildfires and the Butte fire; |
• | the timing and outcome of future regulatory and legislative developments in connection with SB 901, including the customer harm threshold in connection with the Northern California wildfires, future wildfire reforms, including inverse condemnation reform, a potential state wildfire insurance fund, and other wildfire mitigation measures; |
• | the outcome of the Utility's community wildfire safety program that the Utility has developed in coordination with first responders, civic and community leaders, and customers, to help reduce wildfire threats and improve safety as a result of climate-driven wildfires and extreme weather; and the cost of the program, and the timing and outcome of any proceeding to recover such cost through rates; |
• | the amount and timing of additional common stock and debt issuances by PG&E Corporation, including the dilutive impact of common stock issuances to fund PG&E Corporation's equity contributions to the Utility as the Utility incurs charges and costs, including fines, that it cannot recover through rates; |
• | the timing and outcome of CPUC decision(s) related to the Utility’s March 2018 submissions to the CPUC and May 2018 submission to the FERC in connection with the impact of the Tax Act on the Utility’s rate cases and its implementation plan; |
• | the timing and outcomes of the 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19, and TO20 rate cases, 2018 CEMA, WEMA, FHPMA, future cost of capital proceeding, and other ratemaking and regulatory proceedings; |
• | the outcome of the probation and the monitorship imposed by the federal court after the Utility’s conviction in the federal criminal trial in 2017, the timing and outcomes of the debarment proceeding, potential reliability penalties or sanctions from the North American Electric Reliability Corporation, the SED’s unresolved enforcement matters relating to the Utility’s compliance with natural gas-related laws and regulations, and other investigations that have been or may be commenced relating to the Utility’s compliance with natural gas- and electric- related laws and regulations, ex parte communications, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes; |
• | the effects on PG&E Corporation and the Utility’s reputations caused by the CPUC's investigations of natural gas and electric incidents, the Northern California wildfires, improper communications between the CPUC and the Utility, and the Utility’s ongoing work to remove encroachments from transmission pipeline rights-of-way; |
• | the outcome of the safety culture OII, including its phase two PD issued on October 25, 2018, and future legislative or regulatory actions that may be taken, such as requiring the Utility to separate its electric and natural gas businesses, or restructure into separate entities, or undertake some other corporate restructuring, or implement corporate governance changes; |
• | whether the Utility can control its costs within the authorized levels of spending, and timely recover its costs through rates; whether the Utility can continue implementing a streamlined organizational structure and achieve project savings, the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons; |
• | whether the Utility and its third-party vendors and contractors are able to protect the Utility’s operational networks and information technology systems from cyber- and physical attacks, or other internal or external hazards; |
• | the timing and outcome of the October 1, 2018 request for rehearing of FERC's denial of the complaint filed by the CPUC and certain other parties that the Utility provide an open and transparent planning process for its capital transmission projects that do not go through the CAISO’s Transmission Planning Process to allow for greater participation and input from interested parties; and the timing and ultimate outcome of the Ninth Circuit Court of Appeals decision on January 8, 2018, to reverse FERC’s decision granting the Utility a 50 basis point ROE incentive adder for continued participation in the CAISO and remanding the case to FERC for further proceedings; |
• | the outcome of current and future self-reports, investigations, or other enforcement proceedings that could be commenced or notices of violation that could be issued relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to its operations, including the construction, expansion, or replacement of its electric and gas facilities, electric grid reliability, inspection and maintenance practices, customer billing and privacy, physical and cybersecurity, environmental laws and regulations; and the outcome of existing and future SED notices of violations; |
• | the timing and outcome of any CPUC action in connection with the Utility’s SmartMeter™ Upgrade cost-benefit analysis; |
• | the impact of environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; and the extent to which the Utility is able to recover environmental costs in rates or from other sources; |
• | the impact of SB 100, which was signed into law on September 10, 2018, that increases the percentage from 50 percent to 60 percent of California’s electricity portfolio that must come from renewables by 2030; and the requirement that 100 percent of all retail electricity sales must come from RPS-eligible or carbon-free resources by 2045; |
• | how the CPUC and the California Air Resources Board implement state environmental laws relating to GHG, renewable energy targets, energy efficiency standards, DERs, EVs, and similar matters, including whether the Utility is able to continue recovering associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations; and whether the Utility is able to timely recover its associated investment costs; |
• | the impact of the California governor's executive order issued on January 26, 2018, to implement a new target of five million zero-emission vehicles on the road in California by 2030; |
• | the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California and the Utility's fossil fuel-fired generation sites; |
• | the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, cooling water intake, or other issues; the impact of potential actions, such as legislation, taken by state agencies that may affect the Utility’s ability to continue operating Diablo Canyon until its planned retirement; |
• | the impact of wildfires, droughts, floods, or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, vandalism (including cyber-attacks), downed power lines, and other events, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events; and whether the Utility’s insurance coverage is available for these types of claims and sufficient to cover the Utility’s liability; |
• | whether the Utility’s climate change adaptation strategies are successful; |
• | the breakdown or failure of equipment that can cause damages, including fires, and unplanned outages; and whether the Utility will be subject to investigations, penalties, and other costs in connection with such events; |
• | the impact that reductions in customer demand for electricity and natural gas have on the Utility’s ability to make and recover its investments through rates and earn its authorized return on equity, and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources, changing customer demand for natural gas and electric services, and an increasing number of customers departing the Utility’s procurement service for CCAs; |
• | the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through rates, including its renewable energy procurement costs; |
• | the amount and timing of charges reflecting probable liabilities for third-party claims; the extent to which costs incurred in connection with third-party claims or litigation can be recovered through insurance, rates, or from other third parties; and whether the Utility can continue to obtain adequate insurance coverage for future losses or claims, especially following a major event that causes widespread third-party losses; |
• | the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms; |
• | changes in credit ratings which could, among other things, result in cash collateral postings, higher borrowing costs and fewer financing options, especially if PG&E Corporation or the Utility were to lose their investment grade credit ratings; |
• | the impact of the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the uncertainty in connection with the Northern California wildfires, the ultimate outcomes of the CPUC’s pending investigations, and other enforcement matters will impact the Utility’s ability to make distributions to PG&E Corporation, and whether they will continue impacting PG&E Corporation's and the Utility's ability to pay dividends; |
• | the outcome of federal or state tax audits and the impact of any changes in federal or state tax laws, policies, regulations, or their interpretation; |
• | changes in the regulatory and economic environment, including potential changes affecting renewable energy sources and associated tax credits, as a result of the current federal administration; and |
• | the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application. |
• | the breakdown or failure of equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines, that can cause explosions, fires, or other catastrophic events; |
• | an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that results in the failure of downstream transmission pipelines or distribution assets and uncontained natural gas flow; |
• | the failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled/uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life; |
• | a prolonged statewide electrical black-out that results in damage to the Utility’s equipment or damage to property owned by customers or other third parties; |
• | the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees or the public, environmental damage, or reputational damage; |
• | the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act; |
• | the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built; |
• | the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wild land fire or natural gas explosion); |
• | inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages; |
• | operator or other human error; |
• | an ineffective records management program that results in the failure to construct, operate and maintain |
• | construction performed by third parties that damages the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines; |
• | the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; releases of greenhouse gases; flaking lead-based paint from the Utility’s facilities, and leaking or spilled insulating fluid from electrical equipment; and |
• | attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war. |
3.1 | |
4.1 | |
4.2 | |
4.3 | |
10.1 | |
*10.2 | |
*10.3 | |
*10.4 | |
31.1 | |
31.2 | |
**32.1 | |
**32.2 | |
101.INS | XBRL Instance Document |
101.SCH | XBRL Taxonomy Extension Schema Document |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document |
101.LAB | XBRL Taxonomy Extension Labels Linkbase Document |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document |
PG&E CORPORATION |
/s/ JASON P. WELLS |
Jason P. Wells Senior Vice President and Chief Financial Officer (duly authorized officer and principal financial officer) |
PACIFIC GAS AND ELECTRIC COMPANY |
/s/ DAVID S. THOMASON |
David S. Thomason Vice President, Chief Financial Officer and Controller (duly authorized officer and principal financial officer) |
• | “Retirement-I” provisions apply to awards granted to recipients who were in a director level or higher position on May 5, 2017 and who also received an LTIP award prior to 2017. |
• | “Retirement -II” provisions apply to all other recipients. |
The LTIP and Other Agreements | This Agreement and the above cover sheet constitute the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP. Any prior agreements, commitments, or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement or the above cover sheet and the LTIP, the LTIP will govern. Capitalized terms that are not defined in this Agreement or the above cover sheet are defined in the LTIP. In the event of any conflict between the provisions of this Agreement or the above cover sheet and the PG&E Corporation 2012 Officer Severance Policy, this Agreement or the above cover sheet will govern, as applicable. For purposes of this Agreement, employment with PG&E Corporation means employment with any member of the Participating Company Group. |
Grant of Restricted Stock Units | PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement. The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP. |
Vesting of Restricted Stock Units | As long as you remain employed with PG&E Corporation, the total number of Restricted Stock Units originally subject to this Agreement, as shown on the cover sheet, will vest in accordance with the below vesting schedule (the “Normal Vesting Schedule”). 6,382 on September 04, 2020 The amounts payable upon each vesting date are hereby designated separate payments for purposes of Section 409A of the Internal Revenue Code of 1986, as amended (“Code”). Except as described below, all Restricted Stock Units subject to this Agreement which have not vested upon termination of your employment will then be cancelled. As set forth below, the Restricted Stock Units may vest earlier upon the occurrence of certain events. |
Dividends | Restricted Stock Units will accrue Dividend Equivalents in the event that cash dividends are paid with respect to PG&E Corporation common stock having a record date prior to the date on which the RSUs are settled. Such Dividend Equivalents will be converted into cash and paid, if at all, upon settlement of the underlying Restricted Stock Units. |
Settlement | Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. PG&E Corporation will issue shares as soon as practicable after the Restricted Stock Units vest in accordance with the Normal Vesting Schedule (but not later than sixty (60) days after the applicable vesting date); provided, however, that such issuance will, if earlier, be made with respect to all of your outstanding vested Restricted Stock Units (after giving effect to the vesting provisions described below) as soon as practicable after (but not later than sixty (60) days after) the earliest to occur of your (1) Disability (as defined under Code Section 409A), (2) death, or (3) “separation from service,” within the meaning of Code Section 409A within 2 years following a Change in Control. |
Voluntary Termination | In the event of your voluntary termination (other than Retirement), all unvested Restricted Stock Units will be cancelled on the date of termination. |
Retirement - I (2) | In the event of your Retirement, unvested Restricted Stock Units will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement; provided, however that in the event of your Retirement within 2 years following a Change in Control, all of your Restricted Stock Units will vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such Retirement. Your termination of employment will be considered Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least five consecutive years ending on the date of termination of your employment. |
Retirement - II (3) | In the event of your Retirement, any unvested Restricted Stock Units that would have vested within the 12 months following such Retirement had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement; provided, however, that in the event of your Retirement within 2 years following a Change in Control, those Restricted Stock Units that would have vested within 12 months following such Retirement will be vested and settled as soon as practicable after (but not later than 60 days after) the date of such Retirement. All other unvested Restricted Stock Units will be cancelled. Your termination of employment will be considered Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least eight consecutive years ending on the date of termination of your employment. |
Termination for Cause | If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause, all unvested Restricted Stock Units will be cancelled on the date of termination. In general, termination for “cause” means termination of employment because of dishonesty, a criminal offense, or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation. For the avoidance of doubt, you will not be eligible to retire if your employment is being or is terminated for cause. |
Termination other than for Cause | If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause or Retirement, any unvested Restricted Stock Units that would have vested within the 12 months following such termination had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement. All other unvested Restricted Stock Units will be cancelled unless your termination of employment was in connection with a Change in Control as provided below. |
Death/Disability | In the event of your death or Disability (as defined in Code Section 409A) while you are employed, all of your Restricted Stock Units will vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event. If your death or Disability occurs following the termination of your employment and your Restricted Stock Units are then outstanding under the terms hereof, then all of your vested Restricted Stock Units plus any Restricted Stock Units that would have otherwise vested during any continued vesting period hereunder will be settled as soon as practicable after (but not later than sixty (60) days after) the date of your death or Disability. |
Termination Due to Disposition of Subsidiary | If your employment is terminated (other than for cause, or your voluntary termination, or your Retirement) (1) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Code Section 424(f), or (2) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your Restricted Stock Units will vest and be settled in the same manner as for a “Termination other than for Cause” described above. |
(2) “Retirement -I” provisions apply to any recipients who were in a director level or higher position on May 5, 2017 and who received an LTIP award prior to 2017. (3) “Retirement - II” provisions apply to all other recipients. |
Change in Control | In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without your consent, either assume or continue PG&E Corporation’s rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Restricted Stock Units subject to this Agreement. If the Restricted Stock Units are neither so assumed nor so continued by the Acquiror, and the Acquiror does not provide a substantially equivalent award in substitution for the Restricted Stock Units, all of your unvested Restricted Stock Units will vest immediately preceding and contingent on, the Change in Control and be settled in accordance with the Normal Vesting Schedule, subject to the earlier settlement provisions of this Agreement. |
Termination In Connection with a Change in Control | If you separate from service (other than termination for cause, or your voluntary termination, or your Retirement) in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Restricted Stock Units (including Restricted Stock Units that you would have otherwise forfeited after the end of the continued vesting period) will vest on the date of the Change in Control and will be settled in accordance with the Normal Vesting Schedule (without regard to the requirement that you be employed) subject to the earlier settlement provisions of this Agreement. In the event of such a separation in connection with a Change in Control within two years following the Change in Control, your Restricted Stock Units (to the extent they did not previously vest upon, for example, failure of the Acquiror to assume or continue this award) will vest on the date of such separation and will be settled as soon as practicable after (but not later than sixty (60) days after) the date of such separation. PG&E Corporation has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control. |
Delay | PG&E Corporation will delay the issuance of any shares of common stock to the extent it is necessary to comply with Code Section 409A(a)(2)(B)(i) (relating to payments made to certain “key employees” of certain publicly-traded companies); in such event, any shares of common stock to which you would otherwise be entitled during the six (6) month period following the date of your “separation from service” under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period. |
Withholding Taxes | The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Restricted Stock Units will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Restricted Stock Units determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax (“Withholding Taxes”). If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above. |
Leaves of Absence | For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed. If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment. See above under “Voluntary Termination.” Notwithstanding the foregoing, if the leave of absence exceeds six (6) months, and a return to service upon expiration of such leave is not guaranteed by statute or contract, then you will be deemed to have had a “separation from service” for purposes of any Restricted Stock Units that are settled hereunder upon such separation. To the extent an authorized leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of at least six (6) months and such impairment causes you to be unable to perform the duties of your position of employment or any substantially similar position of employment, the six (6) month period in the prior sentence will be twenty-nine (29) months. PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement. |
Voting and Other Rights | You will not have voting rights with respect to the Restricted Stock Units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent). No Restricted Stock Units and no shares of Stock that have not been issued hereunder may be sold, assigned, transferred, pledged, or otherwise encumbered, other than by will or the laws of decent and distribution, and the Restricted Stock Units may be exercised during the life of the Recipient only by the Recipient or the Recipient’s guardian or legal representative. |
No Retention Rights | This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation. Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason. |
Recoupment of Awards | Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time, including the PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy, as last revised on February 21, 2018 and available on the PG&E@Work internet site for the Long-Term Incentive Plan (the policy and location may be changed from time to time by PG&E Corporation). |
Applicable Law | This Agreement will be interpreted and enforced under the laws of the State of California. |
• | “Retirement-I” provisions apply to awards granted to recipients who were in a director level or higher position on May 5, 2017 and who also received an LTIP award prior to 2017. |
• | “Retirement -II” provisions apply to all other recipients. |
The LTIP and Other Agreements | This Agreement and the above cover sheet constitute the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP. Any prior agreements, commitments, or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement or the above cover sheet and the LTIP, the LTIP will govern. Capitalized terms that are not defined in this Agreement or the above cover sheet are defined in the LTIP. In the event of any conflict between the provisions of this Agreement or the above cover sheet and the PG&E Corporation 2012 Officer Severance Policy, this Agreement or the above cover sheet will govern, as applicable. For purposes of this Agreement, employment with PG&E Corporation means employment with any member of the Participating Company Group. |
Grant of Restricted Stock Units | PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement. The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP. |
Vesting of Restricted Stock Units | As long as you remain employed with PG&E Corporation, the total number of Restricted Stock Units originally subject to this Agreement, as shown on the cover sheet, will vest in accordance with the below vesting schedule (the “Normal Vesting Schedule”). 886 on September 04, 2019 887 on September 04, 2020 887 on September 04, 2021 The amounts payable upon each vesting date are hereby designated separate payments for purposes of Section 409A of the Internal Revenue Code of 1986, as amended (“Code”). Except as described below, all Restricted Stock Units subject to this Agreement which have not vested upon termination of your employment will then be cancelled. As set forth below, the Restricted Stock Units may vest earlier upon the occurrence of certain events. |
Dividends | Restricted Stock Units will accrue Dividend Equivalents in the event that cash dividends are paid with respect to PG&E Corporation common stock having a record date prior to the date on which the RSUs are settled. Such Dividend Equivalents will be converted into cash and paid, if at all, upon settlement of the underlying Restricted Stock Units. |
Settlement | Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. PG&E Corporation will issue shares as soon as practicable after the Restricted Stock Units vest in accordance with the Normal Vesting Schedule (but not later than sixty (60) days after the applicable vesting date); provided, however, that such issuance will, if earlier, be made with respect to all of your outstanding vested Restricted Stock Units (after giving effect to the vesting provisions described below) as soon as practicable after (but not later than sixty (60) days after) the earliest to occur of your (1) Disability (as defined under Code Section 409A), (2) death, or (3) “separation from service,” within the meaning of Code Section 409A within 2 years following a Change in Control. |
Voluntary Termination | In the event of your voluntary termination (other than Retirement), all unvested Restricted Stock Units will be cancelled on the date of termination. |
Retirement - I (2) | In the event of your Retirement, unvested Restricted Stock Units will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement; provided, however that in the event of your Retirement within 2 years following a Change in Control, all of your Restricted Stock Units will vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such Retirement. Your termination of employment will be considered Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least five consecutive years ending on the date of termination of your employment. |
Retirement - II (3) | In the event of your Retirement, any unvested Restricted Stock Units that would have vested within the 12 months following such Retirement had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement; provided, however, that in the event of your Retirement within 2 years following a Change in Control, those Restricted Stock Units that would have vested within 12 months following such Retirement will be vested and settled as soon as practicable after (but not later than 60 days after) the date of such Retirement. All other unvested Restricted Stock Units will be cancelled. Your termination of employment will be considered Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least eight consecutive years ending on the date of termination of your employment. |
Termination for Cause | If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause, all unvested Restricted Stock Units will be cancelled on the date of termination. In general, termination for “cause” means termination of employment because of dishonesty, a criminal offense, or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation. For the avoidance of doubt, you will not be eligible to retire if your employment is being or is terminated for cause. |
Termination other than for Cause | If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause or Retirement, any unvested Restricted Stock Units that would have vested within the 12 months following such termination had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement. All other unvested Restricted Stock Units will be cancelled unless your termination of employment was in connection with a Change in Control as provided below. |
Death/Disability | In the event of your death or Disability (as defined in Code Section 409A) while you are employed, all of your Restricted Stock Units will vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event. If your death or Disability occurs following the termination of your employment and your Restricted Stock Units are then outstanding under the terms hereof, then all of your vested Restricted Stock Units plus any Restricted Stock Units that would have otherwise vested during any continued vesting period hereunder will be settled as soon as practicable after (but not later than sixty (60) days after) the date of your death or Disability. |
Termination Due to Disposition of Subsidiary | If your employment is terminated (other than for cause, or your voluntary termination, or your Retirement) (1) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Code Section 424(f), or (2) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your Restricted Stock Units will vest and be settled in the same manner as for a “Termination other than for Cause” described above. |
(2) “Retirement -I” provisions apply to any recipients who were in a director level or higher position on May 5, 2017 and who received an LTIP award prior to 2017. (3) “Retirement - II” provisions apply to all other recipients. |
Change in Control | In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without your consent, either assume or continue PG&E Corporation’s rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Restricted Stock Units subject to this Agreement. If the Restricted Stock Units are neither so assumed nor so continued by the Acquiror, and the Acquiror does not provide a substantially equivalent award in substitution for the Restricted Stock Units, all of your unvested Restricted Stock Units will vest immediately preceding and contingent on, the Change in Control and be settled in accordance with the Normal Vesting Schedule, subject to the earlier settlement provisions of this Agreement. |
Termination In Connection with a Change in Control | If you separate from service (other than termination for cause, or your voluntary termination, or your Retirement) in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Restricted Stock Units (including Restricted Stock Units that you would have otherwise forfeited after the end of the continued vesting period) will vest on the date of the Change in Control and will be settled in accordance with the Normal Vesting Schedule (without regard to the requirement that you be employed) subject to the earlier settlement provisions of this Agreement. In the event of such a separation in connection with a Change in Control within two years following the Change in Control, your Restricted Stock Units (to the extent they did not previously vest upon, for example, failure of the Acquiror to assume or continue this award) will vest on the date of such separation and will be settled as soon as practicable after (but not later than sixty (60) days after) the date of such separation. PG&E Corporation has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control. |
Delay | PG&E Corporation will delay the issuance of any shares of common stock to the extent it is necessary to comply with Code Section 409A(a)(2)(B)(i) (relating to payments made to certain “key employees” of certain publicly-traded companies); in such event, any shares of common stock to which you would otherwise be entitled during the six (6) month period following the date of your “separation from service” under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period. |
Withholding Taxes | The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Restricted Stock Units will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Restricted Stock Units determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax (“Withholding Taxes”). If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above. |
Leaves of Absence | For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed. If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment. See above under “Voluntary Termination.” Notwithstanding the foregoing, if the leave of absence exceeds six (6) months, and a return to service upon expiration of such leave is not guaranteed by statute or contract, then you will be deemed to have had a “separation from service” for purposes of any Restricted Stock Units that are settled hereunder upon such separation. To the extent an authorized leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of at least six (6) months and such impairment causes you to be unable to perform the duties of your position of employment or any substantially similar position of employment, the six (6) month period in the prior sentence will be twenty-nine (29) months. PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement. |
Voting and Other Rights | You will not have voting rights with respect to the Restricted Stock Units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent). No Restricted Stock Units and no shares of Stock that have not been issued hereunder may be sold, assigned, transferred, pledged, or otherwise encumbered, other than by will or the laws of decent and distribution, and the Restricted Stock Units may be exercised during the life of the Recipient only by the Recipient or the Recipient’s guardian or legal representative. |
No Retention Rights | This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation. Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason. |
Recoupment of Awards | Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time, including the PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy, as last revised on February 21, 2018 and available on the PG&E@Work internet site for the Long-Term Incentive Plan (the policy and location may be changed from time to time by PG&E Corporation). |
Applicable Law | This Agreement will be interpreted and enforced under the laws of the State of California. |
1. | if either Company restates financial statements that were filed with the Securities and Exchange Commission for any of the past three completed fiscal years, and the individual was a Section 16 Officer of either Company during the fiscal year for which the financial statements were restated, or |
2. | if, during any of the past three completed fiscal years, a material miscalculation occurred with respect to the amount of any Payment made to an individual who was a Section 16 Officer at the time of such Payment, or |
3. | if any individual who served as a Section 16 Officer during the past three years engaged in fraud or other intentional misconduct, and such fraud or intentional misconduct caused material financial or reputational harm to either Company, as determined by the Compensation Committee or the Board of a Company. |
• | For Triggering Event 1 or 2: the difference between (i) the amount of any Payment made as a result of the erroneous financial statements or the material miscalculations, as applicable, and (ii) the lower Payment that would have been advanced based on the restated financial statement or in the absence of the material miscalculation, as applicable, or |
• | For Triggering Event 3: the full amount of Payments during the fiscal year in which the fraud or misconduct occurred. |
1. | I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 of PG&E Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: November 5, 2018 | /s/ GEISHA J. WILLIAMS |
Geisha J. Williams | |
Chief Executive Officer and President |
1. | I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 of PG&E Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: November 5, 2018 | /s/ JASON P. WELLS |
Jason P. Wells | |
Senior Vice President and Chief Financial Officer |
1. | I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 of Pacific Gas and Electric Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: November 5, 2018 | /s/ PATRICK M. HOGAN |
Patrick M. Hogan | |
Senior Vice President, Electric Operations |
1. | I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 of Pacific Gas and Electric Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: November 5, 2018 | /s/ STEVEN E. MALNIGHT |
Steven E. Malnight | |
Senior Vice President, Energy Supply and Policy |
1. | I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 of Pacific Gas and Electric Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: November 5, 2018 | /s/ JESUS SOTO, Jr. |
Jesus Soto, Jr. | |
Senior Vice President, Electric Operations |
1. | I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 of Pacific Gas and Electric Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: November 5, 2018 | /s/ DAVID S. THOMASON |
David S. Thomason | |
Vice President, Chief Financial Officer and Controller |
(1) | the Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation. |
/s/ GEISHA J. WILLIAMS | |
Geisha J. Williams | |
Chief Executive Officer and President |
(1) | the Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation. |
/s/ JASON P. WELLS | |
Jason P. Wells | |
Senior Vice President and | |
Chief Financial Officer |
(1) | the Form 10-Q fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company. |
/s/ PATRICK M. HOGAN | |
Patrick M. Hogan | |
Senior Vice President, Electric Operations |
(1) | the Form 10-Q fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company. |
/s/ STEVEN E. MALNIGHT | |
Steven E. Malnight | |
Senior Vice President, Energy Supply and Policy |
(1) | the Form 10-Q fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company. |
/s/ JESUS SOTO, Jr. | |
Jesus Soto, Jr. | |
Senior Vice President, Gas Operations |
(1) | the Form 10-Q fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company. |
/s/ DAVID S. THOMASON | |
David S. Thomason | |
Vice President, Chief Financial Officer and Controller |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Net Income | $ 567 | $ 553 | $ 32 | $ 1,542 |
Other Comprehensive Income | ||||
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates) | 1 | 0 | 1 | 1 |
Total other comprehensive income | 1 | 0 | 1 | 1 |
Comprehensive Income | 568 | 553 | 33 | 1,543 |
Preferred stock dividend requirement of subsidiary | 3 | 3 | 10 | 10 |
Comprehensive Income Attributable to Common Shareholders | 565 | 550 | 23 | 1,533 |
Pacific Gas & Electric Co | ||||
Net Income | 571 | 513 | 47 | 1,491 |
Other Comprehensive Income | ||||
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates) | 0 | 0 | 1 | 1 |
Total other comprehensive income | 0 | 0 | 1 | 1 |
Comprehensive Income | $ 571 | $ 513 | $ 48 | $ 1,492 |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Pension and other postretirement benefit plans obligations tax | $ 0 | $ 0 | $ 0 | $ 0 |
Pacific Gas & Electric Co | ||||
Pension and other postretirement benefit plans obligations tax | $ 0 | $ 0 | $ 0 | $ 0 |
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions |
Sep. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Allowance for doubtful accounts | $ 58 | $ 64 |
Common stock, shares authorized (in shares) | 800,000,000 | 800,000,000 |
Common stock, shares outstanding (in shares) | 517,102,983 | 514,755,845 |
Pacific Gas & Electric Co | ||
Allowance for doubtful accounts | $ 58 | $ 64 |
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 |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions |
9 Months Ended | |
---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Discount on net issuances of commercial paper | $ 1 | $ 4 |
Premium, discount, and issuance costs on proceeds from long-term debt | 7 | 11 |
Pacific Gas & Electric Co | ||
Discount on net issuances of commercial paper | 0 | 4 |
Premium, discount, and issuance costs on proceeds from long-term debt | $ 7 | $ 11 |
ORGANIZATION AND BASIS OF PRESENTATION |
9 Months Ended |
---|---|
Sep. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
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 quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed 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 Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2017 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2017 Form 10-K. This quarterly report should be read in conjunction with the 2017 Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, and pension and other post-retirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed 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 impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred. 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 “Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in Northern California that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The wildfires resulted in 44 fatalities. Cal Fire issued its determination on the causes of 17 of the Northern California wildfires, and alleged that each of these fires involved the Utility's equipment. The remaining wildfires remain under Cal Fire’s investigation, including the possible role of the Utility’s power lines and other facilities. Additionally, the Northern California wildfires are under investigation by the CPUC’s SED. See “Northern California Wildfires” in Note 9 below. |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES For a summary of the significant accounting policies used by PG&E Corporation and the Utility, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. 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 has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2018, the Utility 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 September 30, 2018, it did not consolidate any of them. Pension and Other Post-Retirement Benefits 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. The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2018 and 2017 were as follows:
(1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates
(1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss) The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below:
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Recently Adopted Accounting Standards Revenue Recognition Standard In May 2014, the FASB issued ASU No. 2014-9, Revenue from Contracts with Customers (Topic 606), which amends the previous revenue recognition guidance. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. PG&E Corporation and the Utility applied the requirements using the modified retrospective method when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Condensed Consolidated Financial Statements as of the adoption date or for the three and nine months ended September 30, 2018. A majority of the Utility’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customers' monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer. 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 Condensed 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. The FERC authorizes the Utility’s revenue requirements in periodic TO rate cases. The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled, net of revenues subject to refund. 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:
(1) This activity is primarily related to the change in unbilled revenue, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. Presentation of Net Periodic Pension and Post-Retirement Benefit Costs In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715), which amends the guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. PG&E Corporation and the Utility applied the requirements when the ASU became effective on January 1, 2018. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. As a result, the Condensed Consolidated Statements of Income for PG&E Corporation and the Utility were restated. This change resulted in increases to Operating and maintenance expenses and Other income, net, of $13 million and $14 million for PG&E Corporation and the Utility, respectively, for the three months ended September 30, 2017 and $39 million and $41 million for PG&E Corporation and the Utility, respectively, for the nine months ended September 30, 2017. On a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The FERC has allowed and the Utility has made a one-time election to adopt the new FASB guidance for regulatory filing purposes. In January 2018, the CPUC approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the service cost component determined by a plan’s actuary. The capitalization of service costs only results in higher rate base and a reduction in the Utility’s 2018 revenues. The changes in capitalization of retirement benefits did not have a material impact on PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which amends the guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income. The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts and gains or losses are refundable or recoverable, respectively, from customers through rates, therefore gains and losses are deferred and recognized as regulatory assets or liabilities. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 and did not have a material impact on the Condensed Consolidated Financial Statements and related disclosures. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Act. When amounts are reclassified from accumulated other comprehensive income to the Condensed Consolidated Statement of Income, PG&E Corporation and the Utility recognize the related income tax expense at the tax rate in effect at that time. The ASU is effective for PG&E Corporation and the Utility on January 1, 2019, and early adoption is permitted. PG&E Corporation and the Utility early adopted this ASU on January 1, 2018, resulting in an immaterial reclassification. Accounting Standards Issued But Not Yet Adopted Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the guidance relating to the definition of a lease, recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements. Under the new standard, all lessees must recognize an asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019, with early adoption permitted. PG&E Corporation and the Utility intend to elect 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. Additionally, PG&E Corporation and the Utility do not intend to restate comparative periods upon adoption. PG&E Corporation and the Utility plan to adopt this guidance in the first quarter of 2019. PG&E Corporation and the Utility expect this standard to increase lease assets and lease liabilities on the Condensed Consolidated Balance Sheets and do not expect the guidance will have a material impact on the Condensed Consolidated Statements of Income, Statements of Cash Flows and related disclosures. 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. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. 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 will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. |
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS |
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Regulated Operations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS | REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets and Liabilities Long-Term Regulatory Assets Long-term regulatory assets are comprised of the following:
(1) Represents costs related to certain catastrophic events that the Utility believes are probable of recovery. For more information, see Note 9 below. (2) Represents costs related to insurance premiums that the Utility believes are probable of recovery. For more information, see Note 9 below. (3) Represents costs related to wildfire prevention vegetation management work that the Utility believes are probable of recovery. Long-Term Regulatory Liabilities Long-term regulatory liabilities are comprised of the following:
For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. Regulatory Balancing Accounts Current regulatory balancing accounts receivable and payable are comprised of the following:
For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. |
DEBT |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
DEBT | DEBT Revolving Credit Facilities and Commercial Paper Program The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, 2018:
(1) Includes a $50 million lender commitment to the letter of credit sublimit and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 million lender commitment to the letter of credit sublimit and a $75 million commitment for swingline loans. Other Short-term Borrowings In February 2018, the Utility’s $250 million floating rate unsecured term loan, issued in February 2017, matured and was repaid. Additionally, in February 2018, the Utility entered into a $250 million floating rate unsecured term loan that will mature on February 22, 2019. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. Long-term Debt Issuances and Redemptions During the first quarter of 2018, the Utility satisfied and discharged its remaining obligation of $400 million aggregate principal amount of the 8.25% Senior Notes due October 15, 2018. In April 2018, PG&E Corporation entered into a $350 million floating rate unsecured term loan. The term loan will mature on April 16, 2020, unless extended by PG&E Corporation pursuant to the terms of the term loan agreement. The proceeds were used for general corporate purposes, including the early redemption of PG&E Corporation’s outstanding $350 million principal amount of 2.40% Senior Notes due March 1, 2019. On April 26, 2018, PG&E Corporation completed the early redemption of these bonds, which satisfied and discharged its remaining obligation of $350 million. In August 2018, the Utility issued $500 million principal amount of 4.25% Senior Notes due August 1, 2023 and $300 million principal amount of 4.65% Senior Notes due August 1, 2028. The proceeds will be used to repay $500 million floating rate Senior Notes due November 28, 2018, to repay a $250 million term loan maturing on February 22, 2019 and for general corporate purposes. Variable Rate Interest At September 30, 2018, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 1.55% to 1.68%. At September 30, 2018, the interest rates on the $149 million principal amount of pollution control bonds Series 2009 A and B, and the related loan agreements, were 1.60%. |
EQUITY |
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EQUITY | EQUITY PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2018 were as follows:
There were no issuances under the PG&E Corporation February 2017 equity distribution agreement for the nine months ended September 30, 2018. As of September 30, 2018, the remaining amount available under this agreement was $246.3 million. PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan and share-based compensation plans. During the nine months ended September 30, 2018, 3.6 million shares were issued for cash proceeds of $136.7 million under these plans. 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 the Northern California wildfires. The dividends declared per share on PG&E Corporation's common stock were $0 and $0.53, for the three months ended September 30, 2018 and 2017, respectively, and $0 and $1.55 for the nine months ended September 30, 2018 and 2017, respectively. |
EARNINGS PER SHARE |
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EARNINGS PER SHARE | EARNINGS PER SHARE PG&E Corporation’s basic EPS are calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:
For 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. |
DERIVATIVES |
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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. Derivatives are presented in the Utility’s Condensed 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 Condensed 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 Condensed 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 Condensed Consolidated Balance Sheets. Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows:
(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 September 30, 2018, the Utility’s outstanding derivative balances were as follows:
At December 31, 2017, the Utility’s outstanding derivative balances were as follows:
Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows. The majority of the Utility’s derivatives instruments, including certain power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. The Utility’s credit rating remains investment grade. If the Utility credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions. The Utility held derivatives with a net liability fair value of $44 million and $1 million at September 30, 2018 and December 31, 2017, respectively, offset by an immaterial amount from related derivatives in an asset position. If the credit-risk-related contingency feature were triggered, at September 30, 2018, the Utility would be required to post additional collateral immediately in the amount of $12 million. |
FAIR VALUE MEASUREMENTS |
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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:
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.
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $455 million, primarily related to deferred taxes on appreciation of investment value.
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $440 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. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the nine months ended September 30, 2018 and 2017. 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 Condensed 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 Sensitivity Analysis The Utility’s market and credit risk management function, which reports to PG&E Corporation’s Chief Financial Officer, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used 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 7 above.)
(1) Represents price per megawatt-hour.
(1) Represents price per megawatt-hour. Level 3 Reconciliation The following tables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2018 and 2017:
(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.
(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 September 30, 2018 and December 31, 2017, as they are short-term in nature or have interest rates that reset daily. The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
(1) On April 26, 2018, PG&E Corporation early redeemed its outstanding $350 million principal amount of 2.40% Senior Note. Also, in April 2018, PG&E Corporation entered into a $350 million floating rate unsecured term loan. For more information, see Note 4. Nuclear Decommissioning Trust Investments The following table provides a summary of equity securities and available-for-sale debt securities:
(1) Represents amounts before deducting $455 million and $440 million for the periods ended September 30, 2018 and December 31, 2017, respectively, primarily related to deferred taxes on appreciation of investment value. The fair value of fixed-income securities by contractual maturity is as follows:
The following table provides a summary of activity for fixed income and equity securities:
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CONTINGENCIES AND COMMITMENTS |
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
CONTINGENCIES AND COMMITMENTS | CONTINGENCIES AND COMMITMENTS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a 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. PG&E Corporation's and the Utility's provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters. Enforcement and Litigation Matters Wildfire-Related Claims Wildfire-related claims on the Condensed Consolidated Financial Statements include amounts associated with the Northern California wildfires and the Butte fire. For the three and nine months ended September 30, 2018 and 2017, the Utility’s Condensed Consolidated Income Statements include estimated losses offset by insurance recoveries as follows:
In addition to the amounts shown in the table above, during the three and nine months ended September 30, 2018, the Utility incurred $53 million and $120 million, respectively, of legal and other costs related to the Northern California wildfires. See "Butte Fire" below for legal expenses related to the Butte Fire. At September 30, 2018 and December 31, 2017, the Utility's Condensed Consolidated Balance Sheets include estimated losses as follows:
Northern California Wildfires 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. According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in Northern California that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The wildfires resulted in 44 fatalities. Cal Fire issued its determination on the causes of 17 of the Northern California wildfires, and alleged that each of these fires involved the Utility's equipment. The remaining wildfires remain under Cal Fire’s investigation, including the possible role of the Utility’s power lines and other facilities. Additionally, the Northern California wildfires are under investigation by the CPUC’s SED. During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires, located in Mendocino, Lake, Butte, Sonoma, Humboldt, Nevada and Napa counties). According to the Cal Fire news releases, the first four fires "were caused by trees coming into contact with power lines" and the remaining 12 fires "were caused by electric power and distribution lines, conductors and the failure of power poles." Cal Fire has not yet released its investigation reports related to the McCourtney, Lobo, Honey, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires and stated in its news releases that these investigations have been referred to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” The Butte County District Attorney's office has entered into a settlement agreement with the Utility, resolving the Honey, Cherokee and LaPorte fire allegations without criminal or civil charges. The timing and outcome for resolution of the remaining referrals are uncertain. Also, during the second quarter of 2018, Cal Fire released its investigation reports related to the Redwood, Cherokee, 37, Nuns and La Porte fires. Cal Fire did not refer these fires to District Attorney offices for investigation. On October 9, 2018, Cal Fire issued a news release announcing the results of its investigation into the Cascade fire, located in Yuba County, concluding the Cascade fire "was started by sagging power lines coming into contact during heavy winds" and that "the power line in question was owned by Pacific Gas and Electric Company." Also on October 9, 2018, the Office of the District Attorney of Yuba County issued a news release indicating that no criminal charges would be filed in relation to the Cascade fire. The Office of the District Attorney of Yuba County also indicated that it “reserves the right to review any additional information or evidence that may be submitted to it prior to the expiration of the criminal statute of limitations.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire. Cal Fire has not publicly issued any news releases or other determinations for the Tubbs, Maacama, Pressley, and Point wildfires. The timing and outcome of the Cal Fire investigation into the remaining fires is uncertain. Further, the SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. Various other entities, including fire departments, may also be investigating certain of the fires. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete. As of October 30, 2018, the Utility had submitted 23 electric incident reports to the CPUC associated with the Northern California wildfires where Cal Fire or the Utility has identified a site as potentially involving the Utility’s facilities in its investigation and the property damage associated with each incident exceeded $50,000. The information contained in these reports is factual and preliminary and does not reflect a determination of the causes of the fires. Third-Party Claims 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, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility. 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, courts could determine that the doctrine of inverse condemnation applies even in the absence of an open CPUC proceeding for cost recovery, or before a potential cost recovery decision is issued by the CPUC. There is no guarantee that the CPUC would authorize cost recovery even if a court decision were to determine that the doctrine of inverse condemnation applies. In addition to such 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, and other damages under other theories of liability, including if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility. Further, the Utility could be subject to material fines or penalties if the CPUC or any law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations. As of October 30, 2018, PG&E Corporation and the Utility are aware of approximately 500 complaints on behalf of at least 3,100 plaintiffs related to the Northern California wildfires, five of which seek to be certified as class actions. These cases have been coordinated in the San Francisco Superior Court. The coordinated litigation is in the early stages of discovery. The litigation pending against PG&E Corporation and the Utility includes claims under multiple theories of liability, including inverse condemnation and negligence. Plaintiffs also seek punitive damages. PG&E Corporation and the Utility also are the subject of investigations or other actions by the county District Attorneys to whom Cal Fire has referred its investigations into the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires. Although the Honey fire was referred to the Butte County District Attorney's Office, in October 2018, the Utility reached an agreement to settle any civil claims or criminal charges that could have been brought by the Butte County District Attorney in connection with the Honey fire, as well as the La Porte and Cherokee fires (which were not referred). The settlement provides for funding by the Utility for at least four years of an enhanced fire prevention and communication program, in the amount of up to $1.5 million, not recoverable in rates. On October 9, 2018, the District Attorney of Yuba County announced his decision not to pursue criminal charges at this time against PG&E Corporation or the Utility pertaining to the Cascade fire. Also in October 2018, the Utility and the Sonoma, Napa, Lake, Humboldt and Nevada County District Attorneys entered into agreements under which the Utility agreed to waive any applicable statutes of limitation related to the Northern California wildfires that started in these counties for a period of six months, until April 8, 2019. PG&E Corporation and the Utility anticipate further discussions with the District Attorneys in these counties relating to the Northern California wildfires and whether any criminal or civil charges should be brought. Regardless of any determinations of cause by Cal Fire, ultimately PG&E Corporation and the Utility’s liability will be resolved through litigation, regulatory proceedings and any potential enforcement proceedings, all of which could take a number of years to resolve. The timing and outcome of these and other potential proceedings are uncertain. PG&E Corporation and the Utility are continuing to review the evidence concerning the causes of the Northern California wildfires. 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 many investigation reports prepared by Cal Fire. PG&E Corporation and the Utility and plaintiffs are in discussions with Cal Fire about access to the evidence and the remaining reports. No schedule on gaining access has been set. In addition, insurance carriers who have made payments to their insureds for property damage arising out of the fires have filed 36 subrogation complaints in the San Francisco County Superior Court. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations are similar to the ones made by individual plaintiffs. Further, various government entities, including Mendocino, Napa and Sonoma Counties and the City of Santa Rosa, also asserted claims against PG&E Corporation and the Utility based on the damages that these public entities allegedly suffered as a result of the fires. Such alleged damages include, 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. On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the Northern California wildfires litigation. On May 21, 2018, the court overruled the motion. On July 20, 2018, PG&E Corporation and the Utility filed a writ in the Court of Appeal requesting appellate review of the trial court's decision, which was denied on September 17, 2018. On September 27, 2018, PG&E Corporation and the Utility filed a petition for review to the California Supreme Court. PG&E Corporation and the Utility expect to be the subject of additional lawsuits in connection with the Northern California wildfires. The wildfire litigation could take a number of years to be resolved because of the complexity of the matters, including the ongoing investigation into the causes of the fires and the growing number of parties and claims involved. Estimated Losses from Third-Party Claims Potential liabilities related to the Northern California wildfires depend on various factors, including but not limited to the cause of each fire, contributing causes of the fires (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties or fines that may be imposed by governmental entities. In light of the current state of the law on inverse condemnation and the information currently available to the Utility, including, among other things, the Cal Fire determinations of cause as stated in Cal Fire's press releases and their released reports, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with 14 of the Northern California wildfires referred to as the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket and Sonoma/Napa merged fires (which include the Nuns, Norrbom, Adobe, Partrick and Pythian fires), and accordingly, PG&E Corporation and the Utility recorded a charge in the amount of $2.5 billion during the quarter ended June 30, 2018. This charge corresponds to the lower end of the range of PG&E Corporation and the Utility’s reasonably estimated losses and is subject to change based on additional information. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss will be greater than the amount accrued but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the Northern California wildfires may change, which could result in material increases to the loss accrued. The $2.5 billion charge does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any. It also does not include any amounts in connection with the Atlas, 37, Tubbs, Cascade, Maacama, Pressley and Point fires because at this time PG&E Corporation and the Utility have not concluded that a loss arising from those fires is probable. However, in the future it is possible that facts could emerge that lead PG&E Corporation and the Utility to believe that a loss is probable, resulting in the accrual of a liability at that time, the amount of which could be significant. On September 6, 2018, the California Department of Insurance issued a news release announcing an update on property losses in connection with the October and December 2017 wildfires in California. As of that date, insurers have received nearly 55,000 insurance claims totaling more than $12.28 billion in losses, of which approximately $10 billion relates to statewide claims from the Northern California wildfires. The balance relates to claims from the Southern California December 2017 wildfires. That news release reflected insured property losses only. Also, that amount did not account for uninsured losses, interest, attorneys’ fees, fire suppression and clean-up costs, personal injury and wrongful death damages or other costs. If PG&E Corporation and the Utility were to be found liable for certain or all of such other costs and expenses, including the potential liabilities outlined above, the amount of the liability could significantly exceed the approximately $10 billion in estimated insured property losses with respect to the Northern California wildfires. Loss Recoveries PG&E Corporation and the Utility have liability insurance from various insurers, which provides coverage for third-party liability attributable to the Northern California wildfires in an aggregate amount of approximately $840 million, subject to an initial self-insured retention of $10 million per occurrence and further retentions of approximately $40 million per occurrence. In addition, coverage limits within these wildfire insurance policies could result in further material self-insured costs in the event each fire were deemed to be a separate occurrence under the terms of the insurance policies. PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through September 30, 2018, PG&E Corporation and the Utility recorded $385 million for probable insurance recoveries in connection with the Northern California wildfires. This amount reflects an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. The amount of the receivable is subject to change based on additional information. PG&E Corporation and the Utility intend to seek full recovery for all insured losses and believe it is reasonably possible that they will record a receivable for the full amount of the insurance limits in the future. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected. Even if PG&E Corporation and the Utility were to recover the full amount of their insurance, the potential losses arising out of the Northern California wildfires could significantly exceed the coverage limits of the insurance. The following table presents changes in the insurance receivable for the nine months ended September 30, 2018. The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets:
In addition, it could take a number of years before the extent of the Utility’s liability is known and the Utility could apply for recovery of costs in excess of insurance. On June 21, 2018, the CPUC issued a decision granting the Utility's request to establish a WEMA for the purpose of tracking specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all, and even if such recovery is possible, it could take a number of years to resolve and a number of years to collect. As of September 30, 2018, the Condensed Consolidated Financial Statements include long-term regulatory assets of $77 million, consisting of insurance premium costs that are probable of recovery. Should PG&E Corporation and the Utility conclude in future periods that recovery of insurance premiums in excess of amounts included in authorized revenue requirements is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached. Failure to obtain a substantial or full recovery of costs related to the Northern California wildfires or any conclusion that such recovery is no longer probable could have a material adverse effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. Recently adopted Senate Bill 901 establishes a customer harm threshold, directing the CPUC to limit disallowances in the aggregate, so that they do not exceed the maximum amount that PG&E Corporation can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service. It is uncertain how the new legislation will affect the Utility's ability to recover costs related to the Northern California wildfires. PG&E Corporation and the Utility have considered actions that might be taken to attempt to address liquidity needs of the business should the Utility be unable to recover costs related to the Northern California wildfires, but the inability to recover costs in excess of insurance through increases in rates or to collect such rates in a timely manner could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Derivative Litigation Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants current and certain former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018, and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay is subject to certain conditions regarding the plaintiffs' access to discovery in other actions. The parties submitted a joint status report on October 24, 2018. On August 3, 2018, a third purported derivative lawsuit entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al., was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation's and the Utility's 2017 proxy statement contained misrepresentations regarding the companies' risk management and safety programs. PG&E Corporation's motion to stay the litigation was filed on October 15, 2018. Plaintiffs' opposition to that motion currently is due November 29, 2018, and defendants' reply brief in support of that motion currently is due December 24, 2018. The hearing on PG&E Corporation's motion to stay currently is set for January 31, 2019. On October 23, 2018, a fourth purported derivative lawsuit entitled City of Warren Police and Fire Retirement System v. Chew, et al. was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It names as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and names PG&E Corporation as a nominal defendant. PG&E Corporation and the Utility are unable to predict the timing and outcome of these proceedings. Securities Class Action Litigation In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints allege material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints assert claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and seek unspecified monetary relief, interest, attorneys' fees and other costs. Both complaints identify a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In Re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico as lead plaintiff. Plaintiffs currently have until November 9, 2018 to file an amended consolidated complaint and defendants currently have until January 8, 2019 to move to dismiss, answer or otherwise respond to that complaint. PG&E Corporation and the Utility are unable to predict the timing and outcome of these proceedings. Clean-up and Repair Costs The Utility incurred costs of $308 million for clean-up and repair of the Utility’s facilities (including $145 million in capital expenditures) through September 30, 2018, in connection with the Northern California wildfires. While the Utility believes that such costs are recoverable through CEMA, its CEMA requests are subject to CPUC approval. The Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to recover such costs. The Utility capitalizes and records as regulatory assets costs that are probable of recovery in rates. At September 30, 2018, the CEMA balance related to the Northern California wildfires was $101 million and reflects an approximately $40 million reduction to the regulatory asset that was recorded in the three months ended June 30, 2018, for costs that are no longer probable of recovery. Should PG&E Corporation and the Utility conclude that recovery of any clean-up and repair costs included in the CEMA is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached. Failure to obtain a substantial or full recovery of these costs or any conclusion that such recovery is no longer probable, could have a material adverse effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. Butte Fire In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. Cal Fire’s report concluded that the wildfire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. Third-Party Claims On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California, County of Sacramento. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council previously had authorized the coordination of all cases in Sacramento County. As of October 30, 2018, 95 known complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador. The complaints involve approximately 4,000 individual plaintiffs representing approximately 2,100 households and their insurance companies. These complaints are part of or are in the process of being added to the coordinated proceeding. Plaintiffs seek to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability. Plaintiffs also seek punitive damages. Several plaintiffs have dismissed the Utility's two vegetation management contractors from their complaints. The Utility does not expect the number of individual complaints and plaintiffs to increase significantly in the future, because the statute of limitations for property damage and personal injury in connection with the Butte fire has expired. The Utility continues to mediate and settle cases. On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages. The court denied the Utility’s motion and the Utility filed a writ with the Court of Appeal of the State of California, Third Appellate District. The writ was granted on July 2, 2018, directing the trial court to enter summary adjudication in favor of the Utility and to deny plaintiffs' claim for punitive damages under California Civil Code Section 3294. Plaintiffs sought rehearing and asked the California Supreme Court to review the Court of Appeal's decision. Both requests were denied. Neither the trial nor appellate courts addressed whether plaintiffs can seek punitive damages at trial under Public Utilities Code Section 2106. Based on the July 2, 2018 Court of Appeal's ruling, the Utility believes a loss related to punitive damages is remote. On June 22, 2017, the Superior Court of California, County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnation applies to the Utility with respect to the Butte fire. The court held, among other things, that the Utility had failed to put forth any evidence to support its contention that the CPUC would not allow the Utility to pass on its inverse condemnation liability through rate increases. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding at the time of the ruling, others could file lawsuits and make similar claims. On January 4, 2018, the Utility filed with the court a renewed motion for a legal determination of inverse condemnation liability, citing the November 30, 2017 CPUC decision denying the San Diego Gas & Electric Company application to recover wildfire costs in excess of insurance, and the CPUC declaration that it will not automatically allow utilities to spread inverse condemnation losses through rate increases. On May 1, 2018, the Superior Court of California, County of Sacramento issued its ruling on the Utility's renewed motion in which the court affirmed, with minor changes, its tentative ruling dated April 25, 2018. The court determined that it is bound by earlier holdings of two appellate courts decisions, Barham and Pacific Bell. Further, the court stated that the Utility's constitutional arguments should be made to the appellate courts and suggested that, to the extent the Utility raises the public policy implications of the November 30, 2017 CPUC decision in the San Diego Gas & Electric Company cost recovery proceeding, these arguments should be addressed to the Legislature or CPUC. The Utility filed a writ with the Court of Appeal seeking immediate review of the court's decision. On June 18, 2018, after the writ was summarily denied, the Utility filed a Petition for Review with the California Supreme Court, which also was denied. On September 6, 2018, the court set a trial for some individual plaintiffs to begin on April 1, 2019. The Utility reached agreement with two plaintiffs in the litigation to stipulate to judgment against the Utility on inverse condemnation grounds. If the court grants the motion on November 29, 2018, the Utility will have the right to an appellate court hearing on inverse condemnation. In addition to the coordinated plaintiffs, Cal Fire, the California Office of Emergency Services (OES), the County of Calaveras, and five smaller public entities (three fire districts, one water district and the California Department of Veterans Affairs) have brought suit or indicated that they intend to do so. These five public entities filed their complaints in August 2018 and September 2018. They are being added to the coordinated proceedings. On April 13, 2017, Cal Fire filed a complaint with the Superior Court of California, County of Calaveras, seeking to recover over $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, or violated the law, among other claims. On July 31, 2017, Cal Fire dismissed its complaint against Trees, Inc., one of the Utility's vegetation contractors. Cal Fire has requested that a trial of its claims be set in 2019, following any trial of the claims of the individual plaintiffs. On October 19, 2018, the Utility filed a motion for summary judgment arguing that Cal Fire cannot recover any fire suppression costs under the Third District Court of Appeal's decision in Dep't of Forestry & Fire Prot. v. Howell (2017) 18 Cal. App. 5th 154. The hearing on that motion is set for January 31, 2019. The Utility and Cal Fire are also engaged in a mediation process. Also, on February 20, 2018, the County of Calaveras filed suit against the Utility and the Utility’s vegetation management contractors to recover damages and other costs, based on the doctrine of inverse condemnation and negligence theory of liability. The County also seeks punitive damages. On March 2, 2018, the County served a mediation demand seeking in excess of $167 million, having previously indicated that it intended to bring an approximately $85 million claim against the Utility. This claim included costs that the County of Calaveras allegedly incurred or expected to incur for infrastructure damage, erosion control, and other costs. The Utility and the County of Calaveras currently are engaged in a mediation process. The County has also requested a trial to take place no later than summer 2019. Based on statements by the court, the Utility anticipates that trial would take place, if at all, after a trial of individual plaintiffs' claims and the separate trial of Cal Fire claims. Further, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates to be approximately $190 million. This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the Butte fire. The Utility has not received any information or documentation from OES since its May 2017 statement. In June 2017, the Utility entered into an agreement with the OES that extends their deadline to file a claim to December 2020. Estimated Losses from Third-Party Claims In connection with this matter, the Utility may be liable for property damages, business interruption, interest, and attorneys’ fees without having been found negligent, through the doctrine of inverse condemnation. In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility is found to have been negligent. While the Utility believes it was not negligent, there can be no assurance that a court or jury would agree with the Utility. The Utility’s assessment of the estimated loss related to the Butte fire is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and certain other damages. The Utility has determined that it is probable that it will incur a loss of at least $1.1 billion in connection with the Butte fire. The Utility estimates it is reasonably possible that it may incur an additional $200 million, for a total loss of $1.3 billion. While these amounts include the Utility's assumptions about fire suppression costs (including its assessment of the Cal Fire loss), and the County of Calaveras claim, they do not include any portion of the estimated claim from the OES. The Utility still does not have sufficient information to reasonably estimate any liability it may have for that additional claim. The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs, results from the ongoing mediation and settlement process, review of the potential claim from the OES, outcomes of future court or jury decisions, and information about damages, for which the Utility could be liable, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued. The following table presents changes in the third-party claims liability since December 31, 2015. The balance for the third-party claims liability is included in Wildfire-related claims in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:
(1) As of September 30, 2018, the Utility has paid $806 million of the $832 million in settlements to date in connection with the Butte fire. In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $118 million in connection with the Butte fire. For the three and nine months ended September 30, 2018, the Utility incurred legal expenses in connection with the Butte fire of $9 million and $31 million, respectively. If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded. Loss Recoveries The Utility has liability insurance from various insurers, that provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of $922 million. The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range. Through September 30, 2018, the Utility recorded $922 million for probable insurance recoveries in connection with losses related to the Butte fire. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. In addition, the Utility has received $60 million in cumulative reimbursements from the insurance policies of its vegetation management contractors (excluded from the table below), including $7 million received in the nine months ended September 30, 2018. Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain. The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:
In October 2018, the Utility received an additional $45 million in insurance reimbursements. Regulatory Citations On April 25, 2017, the SED issued two citations to the Utility in connection with the Butte fire, totaling $8.3 million. The SED's investigation found that neither the Utility nor its vegetation management contractors took appropriate steps to prevent a gray pine tree from leaning and contacting the Utility's electric line, which created an unsafe and dangerous condition that resulted in that tree leaning and making contact with the electric line, thus causing a fire. The Utility paid the citations in June 2017, without admitting liability or agreeing with the findings. Enforcement Matters In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. The status of these investigations is uncertain. The Utility is unable to predict whether any charges will be brought against the Utility as a result of these investigations. Regulatory Proceedings Order Instituting an Investigation into Compliance with Ex Parte Communication Rules On April 26, 2018, the CPUC approved the revised proposed decision issued on April 3, 2018, adopting the settlement agreement jointly submitted to the CPUC on March 28, 2017, as modified (the "settlement agreement") by the Utility, the Cities of San Bruno and San Carlos, Cal PA (formerly known as the Office of Ratepayer Advocates or ORA), the SED, and TURN. The decision results in a total penalty of $97.5 million comprised of: (1) a $12 million payment to the California General Fund, (2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ($31.75 million) and 2019 ($31.75 million), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over the Utility’s next GRC cycle (i.e., the 2020 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above. The CPUC also ordered a second phase in this proceeding to determine if any of the additional communications that the Utility reported to the CPUC on September 21, 2017, violate the CPUC ex parte rules. On May 22, 2018, the assigned ALJ issued a ruling requiring the parties to meet and confer to determine if an agreement can be reached on the issues identified by the ALJ. On September 17, 2018, the parties submitted a joint status report indicating a settlement in principle could not be reached. The ALJ will hold a prehearing conference with the parties to determine if evidentiary hearings are required. The Utility is unable to predict the timing and outcome of the second phase in this proceeding. As a result of the CPUC's April 26, 2018 decision, on May 17, 2018, the Utility made a $12 million payment to the California General Fund and $6 million payments to each of the Cities of San Bruno and San Carlos. At September 30, 2018, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $24 million accrual for a portion of the 2018 GT&S revenue requirement reduction. In accordance with accounting rules, adjustments related to revenue requirements are recorded in the periods in which they are incurred. For more information about the proceeding, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. Transmission Owner Rate Case Revenue Subject to Refund The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, and March 1, 2018, for TO18 and TO19, respectively. On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ's recommendations. The Utility expects the FERC to issue a final decision in the TO18 rate case by mid-2019. On September 21, 2018, the Utility filed an all-party settlement with FERC in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined in the TO18 final decision. The Utility is unable to predict the outcomes of FERC’s decisions in these proceedings. Natural Gas Transmission Pipeline Rights-of-Way In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey had been completed and that remediation work, including removal of the encroachments, was expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties. Potential Safety Citations The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. There are a number of audit findings, as well as other potential violations identified through various investigations and the Utility’s self-reported non-compliance with laws and regulations, on which the SED has yet to act, and the outcome of which could result in material fines and other penalties that could be imposed on the Utility. Under both the gas and electric programs, the SED has discretion whether to issue a penalty for each violation. If the SED assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000, with an administrative limit of $8 million per citation issued. Effective January 1, 2019, the maximum statutory penalty increases to $100,000. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED also has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The SED also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged. Historically, the SED has exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. In the past, the SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The CPUC can also open an OII and levy additional fines even after the SED has issued a citation. The Utility is unable to reasonably estimate the amount or range of future charges as a result of SED investigations or any proceedings that could be commenced in connection with potential violations of electric and natural gas laws and regulations. Other Matters PG&E Corporation and the Utility are subject to various claims, lawsuits, and regulatory proceedings that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $94 million at September 30, 2018, and $86 million at December 31, 2017. These amounts are included in Other current liabilities in the Condensed Consolidated Balance Sheets. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. Disallowance of Plant Costs 2015 GT&S Rate Case Capital Disallowance On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. Additional charges may be required in the future based on the outcome of the CPUC’s audit of 2011 through 2014 capital spending. Capital disallowances are reflected in operating and maintenance expenses in the Condensed Consolidated Statements of Income. For more information, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. Environmental Remediation Contingencies The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:
(1) Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, and San Francisco North Beach. (2) Primarily driven by the Geothermal landfill and Shell Pond site. (3) Primarily driven by the San Francisco Potrero Power Plant. The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the federal Resource Conservation and Recovery Act and/or other federal and state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis, and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies. The Utility’s environmental remediation liability at September 30, 2018, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans and the Utility's time frame for remediation. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. At September 30, 2018, the Utility expected to recover $797 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. For more information, see remediation site descriptions below and see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. Natural Gas Compressor Station Sites The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment. Topock Site The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $299 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates. Hinkley Site The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. The background study is expected to be finalized in 2019. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $138 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates. Former Manufactured Gas Plants Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has undertaken a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $508 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates. Utility-Owned Generation Facilities and Third-Party Disposal Sites Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $136 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates. Fossil Fuel-Fired Generation Sites In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $88 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates. Wildfire Insurance During the third quarter of 2018, PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general liability (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for property damages only, which property damage coverage includes an aggregate amount of approximately $200 million through the reinsurance market where a catastrophe bond was utilized. Various coverage limitations applicable to different insurance layers could result in substantial uninsured costs in the future depending on the amount and type of damages. PG&E Corporation’s and the Utility’s cost of obtaining wildfire insurance coverage has increased to $360 million, compared to the adopted approximately $50 million that the Utility is currently recovering through rates through December 31, 2019. The Utility intends to seek recovery for the full amount of premium costs paid in excess of the amount the Utility currently is recovering from customers through the end of the current GRC period, which ends on December 31, 2019. Nuclear Insurance The Utility maintains multiple insurance policies through NEIL and European Mutual Association for Nuclear Insurance, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, as of September 30, 2018, the current maximum aggregate annual retrospective premium obligation for the Utility would be approximately $47 million. If European Mutual Association for Nuclear Insurance losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $3 million, as of September 30, 2018. For more information about the Utility’s nuclear insurance coverage, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. Resolution of Remaining Chapter 11 Disputed Claims Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While the FERC and judicial proceedings are pending, the Utility has pursued settlements with electricity suppliers. The Utility has entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. Under these settlement agreements, amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods. At September 30, 2018 and December 31, 2017, respectively, the Condensed Consolidated Balance Sheets reflected $217 million and $243 million in net claims within Disputed claims and customer refunds. The Utility is uncertain when or how the remaining net disputed claims liability will be resolved. Tax Matters PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of audits. As of September 30, 2018, it is reasonably possible that unrecognized tax benefits will decrease by approximately $10 million within the next 12 months. PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income. 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 reduced the federal income tax rate from 35% to 21% beginning on January 1, 2018 and eliminated bonus depreciation for utilities. Passage of the Tax Act required PG&E Corporation and the Utility to re-measure all existing deferred income tax assets and liabilities to reflect the reduction in the federal tax rate. PG&E Corporation and the Utility recorded reasonable estimates to reflect the impacts of the Tax Act and recorded provisional amounts, in accordance with rules issued by the SEC staff in Staff Accounting Bulletin No. 118, for the re-measurement of deferred tax balances as of December 31, 2017. As a result of updated amounts used in PG&E Corporation and the Utility's 2017 tax returns, during the nine months ended September 30, 2018, the Utility recorded a $12 million tax benefit to adjust provisional tax expense recorded at December 31, 2017, for the Tax Act. For the nine months ended September 30, 2018, the Utility recorded an $80 million reduction to the regulatory liability recorded at December 31, 2017 for the Tax Act. Purchase Commitments In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. At December 31, 2017, the Utility had undiscounted future expected obligations of approximately $44 billion. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.) The Utility has not entered into any new material commitments during the nine months ended September 30, 2018. |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Basis of Presentation | This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed 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 Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2017 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2017 Form 10-K. This quarterly report should be read in conjunction with the 2017 Form 10-K. |
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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 regulatory assets and liabilities, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, and pension and other post-retirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed 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 impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred. |
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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 has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2018, the Utility 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 September 30, 2018, it did not consolidate any of them. |
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Pension and Other Post-Retirement Benefits | Pension and Other Post-Retirement Benefits 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. |
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Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted | Recently Adopted Accounting Standards Revenue Recognition Standard In May 2014, the FASB issued ASU No. 2014-9, Revenue from Contracts with Customers (Topic 606), which amends the previous revenue recognition guidance. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. PG&E Corporation and the Utility applied the requirements using the modified retrospective method when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Condensed Consolidated Financial Statements as of the adoption date or for the three and nine months ended September 30, 2018. A majority of the Utility’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customers' monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer. 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 Condensed 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. The FERC authorizes the Utility’s revenue requirements in periodic TO rate cases. The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled, net of revenues subject to refund. 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:
(1) This activity is primarily related to the change in unbilled revenue, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. Presentation of Net Periodic Pension and Post-Retirement Benefit Costs In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715), which amends the guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. PG&E Corporation and the Utility applied the requirements when the ASU became effective on January 1, 2018. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. As a result, the Condensed Consolidated Statements of Income for PG&E Corporation and the Utility were restated. This change resulted in increases to Operating and maintenance expenses and Other income, net, of $13 million and $14 million for PG&E Corporation and the Utility, respectively, for the three months ended September 30, 2017 and $39 million and $41 million for PG&E Corporation and the Utility, respectively, for the nine months ended September 30, 2017. On a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The FERC has allowed and the Utility has made a one-time election to adopt the new FASB guidance for regulatory filing purposes. In January 2018, the CPUC approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the service cost component determined by a plan’s actuary. The capitalization of service costs only results in higher rate base and a reduction in the Utility’s 2018 revenues. The changes in capitalization of retirement benefits did not have a material impact on PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which amends the guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income. The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts and gains or losses are refundable or recoverable, respectively, from customers through rates, therefore gains and losses are deferred and recognized as regulatory assets or liabilities. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 and did not have a material impact on the Condensed Consolidated Financial Statements and related disclosures. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Act. When amounts are reclassified from accumulated other comprehensive income to the Condensed Consolidated Statement of Income, PG&E Corporation and the Utility recognize the related income tax expense at the tax rate in effect at that time. The ASU is effective for PG&E Corporation and the Utility on January 1, 2019, and early adoption is permitted. PG&E Corporation and the Utility early adopted this ASU on January 1, 2018, resulting in an immaterial reclassification. Accounting Standards Issued But Not Yet Adopted Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the guidance relating to the definition of a lease, recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements. Under the new standard, all lessees must recognize an asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019, with early adoption permitted. PG&E Corporation and the Utility intend to elect 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. Additionally, PG&E Corporation and the Utility do not intend to restate comparative periods upon adoption. PG&E Corporation and the Utility plan to adopt this guidance in the first quarter of 2019. PG&E Corporation and the Utility expect this standard to increase lease assets and lease liabilities on the Condensed Consolidated Balance Sheets and do not expect the guidance will have a material impact on the Condensed Consolidated Statements of Income, Statements of Cash Flows and related disclosures. 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. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. 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 will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. |
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Earnings Per Share | PG&E Corporation’s basic EPS are calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. |
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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. Derivatives are presented in the Utility’s Condensed 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 Condensed 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 Condensed 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 Condensed Consolidated Balance Sheets. |
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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:
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. |
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Fair Value of Financial Instruments | 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 Condensed 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 |
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Contingencies and Commitments | PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a 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. PG&E Corporation's and the Utility's provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters. |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) |
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Sep. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Components of Net Periodic Benefit Cost | The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2018 and 2017 were as follows:
(1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates
(1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates |
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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) are summarized below:
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) |
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Summary of Revenues Disaggregated by Type of Customer | The following table presents the Utility’s revenues disaggregated by type of customer:
(1) This activity is primarily related to the change in unbilled revenue, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. |
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables) |
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Sep. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulated Operations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Regulatory Assets | Long-term regulatory assets are comprised of the following:
(1) Represents costs related to certain catastrophic events that the Utility believes are probable of recovery. For more information, see Note 9 below. (2) Represents costs related to insurance premiums that the Utility believes are probable of recovery. For more information, see Note 9 below. (3) Represents costs related to wildfire prevention vegetation management work that the Utility believes are probable of recovery. |
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Long-Term Regulatory Liabilities | Long-term regulatory liabilities are comprised of the following:
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Regulatory Balancing Accounts Receivable | Current regulatory balancing accounts receivable and payable are comprised of the following:
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Regulatory Balancing Accounts Payable |
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DEBT (Tables) |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Debt | The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, 2018:
(1) Includes a $50 million lender commitment to the letter of credit sublimit and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 million lender commitment to the letter of credit sublimit and a $75 million commitment for swingline loans. |
EQUITY (Tables) |
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Sep. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stockholders' Equity Note [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Changes in Equity | PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2018 were as follows:
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EARNINGS PER SHARE (Tables) |
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reconciliation of PG&E Corporation's Income Available for Common Shareholders and Weighted Average Common Shares Outstanding for Calculating Diluted | The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:
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DERIVATIVES (Tables) |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Volumes Of Outstanding Derivative Contracts | The volumes of the Utility’s outstanding derivatives were as follows:
(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. |
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Schedule of Offsetting Assets | At September 30, 2018, the Utility’s outstanding derivative balances were as follows:
At December 31, 2017, the Utility’s outstanding derivative balances were as follows:
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Schedule of Offsetting Liabilities | At September 30, 2018, the Utility’s outstanding derivative balances were as follows:
At December 31, 2017, the Utility’s outstanding derivative balances were as follows:
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FAIR VALUE MEASUREMENTS (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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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.
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $455 million, primarily related to deferred taxes on appreciation of investment value.
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $440 million, primarily related to deferred taxes on appreciation of investment value. |
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Level 3 Measurements and Sensitivity Analysis |
(1) Represents price per megawatt-hour.
(1) Represents price per megawatt-hour. |
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Level 3 Reconciliation | The following tables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2018 and 2017:
(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.
(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. |
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Carrying Amount and Fair Value of Financial Instruments | The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
(1) On April 26, 2018, PG&E Corporation early redeemed its outstanding $350 million principal amount of 2.40% Senior Note. Also, in April 2018, PG&E Corporation entered into a $350 million floating rate unsecured term loan. For more information, see Note 4. |
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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:
(1) Represents amounts before deducting $455 million and $440 million for the periods ended September 30, 2018 and December 31, 2017, respectively, primarily related to deferred taxes on appreciation of investment value. |
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Schedule of Maturities on Debt Instruments | The fair value of fixed-income securities by contractual maturity is as follows:
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Schedule of Activity for Debt and Equity Securities | The following table provides a summary of activity for fixed income and equity securities:
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CONTINGENCIES AND COMMITMENTS (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Wildfire-Related Claims | For the three and nine months ended September 30, 2018 and 2017, the Utility’s Condensed Consolidated Income Statements include estimated losses offset by insurance recoveries as follows:
In addition to the amounts shown in the table above, during the three and nine months ended September 30, 2018, the Utility incurred $53 million and $120 million, respectively, of legal and other costs related to the Northern California wildfires. See "Butte Fire" below for legal expenses related to the Butte Fire. At September 30, 2018 and December 31, 2017, the Utility's Condensed Consolidated Balance Sheets include estimated losses as follows:
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Change in Accruals Related to Third-Party Claims | The following table presents changes in the third-party claims liability since December 31, 2015. The balance for the third-party claims liability is included in Wildfire-related claims in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:
(1) As of September 30, 2018, the Utility has paid $806 million of the $832 million in settlements to date in connection with the Butte fire. |
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Changes in Insurance Receivable | The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:
The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets:
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Schedule of Environmental Remediation Liability | The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:
(1) Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, and San Francisco North Beach. (2) Primarily driven by the Geothermal landfill and Shell Pond site. (3) Primarily driven by the San Francisco Potrero Power Plant. |
ORGANIZATION AND BASIS OF PRESENTATION (Narrative) (Details) a in Thousands |
9 Months Ended | |
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Sep. 30, 2018
segment
wildfire
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Oct. 30, 2017
a
wildfire
fatality
structure
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Organization And Basis Of Presentation [Line Items] | ||
Number of operating segments (segment) | segment | 1 | |
Nothern California Wild Fire | ||
Organization And Basis Of Presentation [Line Items] | ||
Number wildfires (wildfire) | wildfire | 17 | 21 |
Number of acres burned (acre) | a | 245 | |
Number of structures destroyed (structure) | structure | 8,900 | |
Number of fatalities (fatality) | fatality | 44 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
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Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
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Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service cost for benefits earned | $ 128 | $ 118 | $ 385 | $ 354 |
Interest cost | 171 | 178 | 515 | 535 |
Expected return on plan assets | (255) | (193) | (766) | (578) |
Amortization of prior service cost | (1) | (1) | (4) | (5) |
Amortization of net actuarial loss | 1 | 6 | 4 | 17 |
Net periodic benefit cost | 44 | 108 | 134 | 323 |
Regulatory account transfer | 41 | (23) | 118 | (69) |
Total | 85 | 85 | 252 | 254 |
Other Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service cost for benefits earned | 16 | 14 | 49 | 44 |
Interest cost | 17 | 20 | 52 | 58 |
Expected return on plan assets | (33) | (24) | (98) | (73) |
Amortization of prior service cost | 4 | 4 | 11 | 12 |
Amortization of net actuarial loss | (1) | 1 | (4) | 3 |
Net periodic benefit cost | 3 | 15 | 10 | 44 |
Regulatory account transfer | 0 | 0 | 0 | 0 |
Total | $ 3 | $ 15 | $ 10 | $ 44 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Period for probable revenue recovery | 24 months | |||
Increase in operating and maintenance expense | $ 1,611 | $ 1,324 | $ 5,001 | $ 4,453 |
Increase in other income | $ 104 | 38 | $ 318 | 98 |
Accounting Standards Update 2017-07 | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Increase in operating and maintenance expense | 13 | 39 | ||
Increase in other income | $ 14 | $ 41 |
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions |
Sep. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 8,607 | $ 8,679 |
Cost of removal obligations | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 5,888 | 5,547 |
Deferred income taxes | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 437 | 1,021 |
Recoveries in excess of AROs | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 489 | 624 |
Public purpose programs | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 660 | 590 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 1,133 | $ 897 |
DEBT (Schedule of Line of Credit) (Details) |
9 Months Ended |
---|---|
Sep. 30, 2018
USD ($)
| |
Debt [Line Items] | |
Letters of credit sublimit | $ 50,000,000 |
Swingline loans sublimit | $ 100,000,000 |
Swingline loan repay term | 7 days |
Utility | |
Debt [Line Items] | |
Letters of credit sublimit | $ 500,000,000 |
Swingline loans sublimit | 75,000,000 |
Revolving Credit Facility | |
Debt [Line Items] | |
Facility Limit | 300,000,000 |
Letters of Credit Outstanding | 0 |
Borrowings | 0 |
Facility Availability | 300,000,000 |
Revolving Credit Facility | Credit Facilities | |
Debt [Line Items] | |
Facility Limit | 3,300,000,000 |
Letters of Credit Outstanding | 87,000,000 |
Borrowings | 0 |
Facility Availability | 3,213,000,000 |
Revolving Credit Facility | Utility | |
Debt [Line Items] | |
Facility Limit | 3,000,000,000 |
Letters of Credit Outstanding | 87,000,000 |
Borrowings | 0 |
Facility Availability | $ 2,913,000,000 |
EQUITY (Changes in Equity) (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Beginning balance | $ 19,472 | |||
Comprehensive income | $ 568 | $ 553 | 33 | $ 1,543 |
Common stock issued | 137 | |||
Share-based compensation | 64 | |||
Preferred stock dividend requirement | 0 | |||
Preferred stock dividend requirement of subsidiary | (3) | (3) | (10) | (10) |
Ending balance | 19,696 | 19,696 | ||
Pacific Gas & Electric Co | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Beginning balance | 19,747 | |||
Comprehensive income | 571 | 513 | 48 | 1,492 |
Common stock issued | 0 | |||
Share-based compensation | 0 | |||
Preferred stock dividend requirement | (3) | $ (3) | (10) | $ (10) |
Preferred stock dividend requirement of subsidiary | 0 | |||
Ending balance | $ 19,785 | $ 19,785 |
EQUITY (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Schedule Of Changes In Equity [Line Items] | ||||
Common stock dividends declared (in dollars per share) | $ 0 | $ 0.53 | $ 0 | $ 1.55 |
Equity Contract | ||||
Schedule Of Changes In Equity [Line Items] | ||||
Remaining equity distribution agreement amount | $ 246.3 | $ 246.3 | ||
401K Plan, DRSPP, and Shared Based Compensation Plans | ||||
Schedule Of Changes In Equity [Line Items] | ||||
Stock issued during period for stock options exercised and under 401(K) plan and DRSPP (in shares) | 3.6 | |||
Proceeds from stock issuance | $ 136.7 |
EARNINGS PER SHARE (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted EPS) (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Earnings Per Share [Abstract] | ||||
Income available for common shareholders | $ 564 | $ 550 | $ 22 | $ 1,532 |
Weighted average common shares outstanding, basic (in shares) | 517 | 513 | 516 | 511 |
Add incremental shares from assumed conversions: | ||||
Employee share-based compensation (in shares) | 0 | 3 | 1 | 3 |
Weighted average common shares outstanding, diluted (in shares) | 517 | 516 | 517 | 514 |
Total earnings per common share, diluted (in dollars per share) | $ 1.09 | $ 1.07 | $ 0.04 | $ 2.98 |
DERIVATIVES (Volumes of Outstanding Derivative Contracts, in Megawatt Hours Unless Otherwise Specified) (Details) |
Sep. 30, 2018
MWh
MMBTU
|
Dec. 31, 2017
MWh
MMBTU
|
---|---|---|
Forwards, Futures and Swaps | Natural gas | ||
Derivative [Line Items] | ||
Contract Volume | MMBTU | 250,021,802 | 228,768,745 |
Forwards, Futures and Swaps | Electric | ||
Derivative [Line Items] | ||
Contract Volume | MWh | 3,939,691 | 2,872,013 |
Options | Natural gas | ||
Derivative [Line Items] | ||
Contract Volume | MMBTU | 29,534,224 | 60,736,806 |
Congestion Revenue Rights | Electric | ||
Derivative [Line Items] | ||
Contract Volume | MWh | 316,451,690 | 312,272,177 |
DERIVATIVES (Narrative) (Details) - Utility - USD ($) $ in Millions |
Sep. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Derivative [Line Items] | ||
Derivative liabilities offset by asset position | $ 44 | $ 1 |
Net position of derivative contracts/additional collateral posting requirements | $ 12 |
FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price Risk Management Instruments - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning asset (liability) balance | $ 34 | $ 48 | $ 42 | $ 55 |
Included in regulatory assets and liabilities or balancing accounts | (10) | 0 | (18) | (7) |
Ending asset (liability) balance | $ 24 | $ 48 | $ 24 | $ 48 |
FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains (Losses) Related to Available-for-Sale Investments) (Details) - USD ($) $ in Millions |
Sep. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | $ 1,861 | $ 1,799 |
Total Unrealized Gains | 1,541 | 1,514 |
Total Unrealized Losses | (30) | (10) |
Total Fair Value | 3,372 | 3,303 |
Amount primarily related to deferred taxes on appreciation of investment value | 455 | 440 |
Short-term investments | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 14 | 23 |
Total Unrealized Gains | 0 | 0 |
Total Unrealized Losses | 0 | 0 |
Total Fair Value | 14 | 23 |
Global equity securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 478 | 524 |
Total Unrealized Gains | 1,513 | 1,463 |
Total Unrealized Losses | (2) | (2) |
Total Fair Value | 1,989 | 1,985 |
Fixed-income securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 1,369 | 1,252 |
Total Unrealized Gains | 28 | 51 |
Total Unrealized Losses | (28) | (8) |
Total Fair Value | $ 1,369 | $ 1,295 |
FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions |
Sep. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Debt Securities, Available-for-sale [Line Items] | ||
Total maturities of fixed-income securities | $ 3,372 | $ 3,303 |
Fixed-income securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Less than 1 year | 69 | |
1–5 years | 401 | |
5–10 years | 386 | |
More than 10 years | 513 | |
Total maturities of fixed-income securities | $ 1,369 | $ 1,295 |
FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Fair Value Disclosures [Abstract] | ||||
Proceeds from sales and maturities of nuclear decommissioning trust investments | $ 319 | $ 249 | $ 1,121 | $ 1,043 |
Gross realized gains on securities | 3 | 8 | 51 | 50 |
Gross realized losses on securities | $ (5) | $ 0 | $ (14) | $ (8) |
CONTINGENCIES AND COMMITMENTS (Wildfire-Related Claims Narrative) (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended |
---|---|---|
Sep. 30, 2018 |
Sep. 30, 2018 |
|
Pacific Gas & Electric Co | Nothern California Wild Fire | ||
Loss Contingencies [Line Items] | ||
Legal and other costs | $ 53 | $ 120 |
CONTINGENCIES AND COMMITMENTS (Summary of Wildfire-Related Claims Reported on Consolidated Balance Sheets) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions |
Sep. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Butte Fire And Northern California Wildfires | ||
Loss Contingencies [Line Items] | ||
Total wildfire-related claims | $ 2,794 | $ 561 |
Butte Fire | ||
Loss Contingencies [Line Items] | ||
Total wildfire-related claims | 294 | 561 |
Nothern California Wild Fire | ||
Loss Contingencies [Line Items] | ||
Total wildfire-related claims | $ 2,500 | $ 0 |
CONTINGENCIES AND COMMITMENTS (Summary of Insurance Receivables Related to California Wildfires) (Details) - USD ($) $ in Millions |
9 Months Ended | |
---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Loss Contingencies [Line Items] | ||
Reimbursements | $ (64) | $ 166 |
Nothern California Wild Fire | ||
Loss Contingencies [Line Items] | ||
Accrued insurance recoveries | 385 | |
Reimbursements | 13 | |
Insurance receivable | $ 372 |
CONTINGENCIES AND COMMITMENTS (Schedule of Loss Accrual) (Details) - Butte Fire - USD ($) $ in Millions |
9 Months Ended | 12 Months Ended | |
---|---|---|---|
Sep. 30, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Loss Contingency Accrual [Roll Forward] | |||
Loss accrual, beginning balance | $ 561 | $ 690 | $ 0 |
Accrued losses | 0 | 350 | 750 |
Payments | (267) | (479) | (60) |
Loss accrual, ending balance | 294 | $ 561 | $ 690 |
Settlement agreements entered | 832 | ||
Settlement agreement paid | $ 806 |
CONTINGENCIES AND COMMITMENTS (Schedule of Insurance Receivable) (Details) - USD ($) $ in Millions |
9 Months Ended | 12 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Insurance Receivable [Roll Forward] | ||||
Reimbursements | $ (64) | $ 166 | ||
Butte Fire | ||||
Insurance Receivable [Roll Forward] | ||||
Insurance Receivable, Beginning Balance | 596 | $ 575 | $ 575 | $ 0 |
Accrued insurance recoveries | 0 | 297 | 625 | |
Reimbursements | (436) | (276) | (50) | |
Insurance Receivable, Ending Balance | $ 160 | $ 596 | $ 575 |
CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Pacific Gas & Electric Co | ||
Loss Contingencies [Line Items] | ||
Accrued legal liabilities | $ 94 | $ 86 |
CONTINGENCIES AND COMMITMENTS (Disallowance of Plant Costs) (Details) - Disallowance of Plant Costs $ in Millions |
Jun. 23, 2016
USD ($)
|
---|---|
Loss Contingencies [Line Items] | |
Gas transmission and storage capital disallowance | $ 696 |
Permanently disallowed capital | 120 |
Amount subject to audit | $ 576 |
CONTINGENCIES AND COMMITMENTS (Schedule of Environmental Remediation Liability) (Details) - USD ($) $ in Millions |
Sep. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Commitments and Contingencies Disclosure [Abstract] | ||
Topock natural gas compressor station | $ 362 | $ 334 |
Hinkley natural gas compressor station | 151 | 147 |
Former manufactured gas plant sites owned by the Utility or third parties | 375 | 320 |
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites | 116 | 115 |
Fossil fuel-fired generation facilities and sites | 136 | 123 |
Total environmental remediation liability | $ 1,140 | $ 1,039 |
CONTINGENCIES AND COMMITMENTS (Wildfire Insurance) (Details) - USD ($) |
3 Months Ended | 6 Months Ended |
---|---|---|
Sep. 30, 2018 |
Jun. 30, 2018 |
|
Loss Contingencies [Line Items] | ||
Costs for insurance coverage | $ 360,000,000 | $ 50,000,000 |
Insurance Coverage for Wildfire Events | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | 1,400,000,000.0 | |
Insurance Coverage for Wildfire Liabilities | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | 700,000,000 | |
Catastrophic bond reinsurance instrument | 10,000,000 | |
Insurance Coverage for Property Damages | ||
Loss Contingencies [Line Items] | ||
Liability insurance coverage | 700,000,000 | |
Catastrophic bond reinsurance instrument | $ 200,000,000 |
CONTINGENCIES AND COMMITMENTS (Nuclear Insurance) (Details) $ in Millions |
6 Months Ended | 9 Months Ended |
---|---|---|
Jun. 30, 2018
nuclear_generating_unit
|
Sep. 30, 2018
USD ($)
|
|
Long-term Purchase Commitment [Line Items] | ||
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit | 2 | |
Nuclear Electric Insurance Limited | ||
Long-term Purchase Commitment [Line Items] | ||
Potential premium obligation | $ 47 | |
European Mutual Association for Nuclear Insurance | ||
Long-term Purchase Commitment [Line Items] | ||
Potential premium obligation | $ 3 |
CONTINGENCIES AND COMMITMENTS (Resolution of Remaining Chapter 11 Disputed Claims) (Details) - USD ($) $ in Millions |
Sep. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Commitments and Contingencies Disclosure [Abstract] | ||
Disputed claims and customer refunds | $ 217 | $ 243 |
CONTINGENCIES AND COMMITMENTS (Tax Matters and Tax Cuts and Jobs Act of 2017) (Details) $ in Millions |
9 Months Ended |
---|---|
Sep. 30, 2018
USD ($)
| |
Disaggregation of Revenue [Line Items] | |
Unrecognized tax benefits, decrease resulting from Settlements with taxing authorities | $ 10 |
Adjustment of provisional tax expense | 12 |
Reduction to regulatory liability | $ 80 |
CONTINGENCIES AND COMMITMENTS (Purchase Commitments) (Details) $ in Billions |
Dec. 31, 2017
USD ($)
|
---|---|
Commitments and Contingencies Disclosure [Abstract] | |
Recorded unconditional purchase obligation | $ 44 |
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