Indicate the numberof shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. | ||||||||||
Common stock outstanding as of October | ||||||||||
PG&E Corporation: |
| 518,674,276 | ||||||||
PacificGas and Electric Company: | 264,374,809 | |||||||||
2018
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
CONDENSED CONSOLIDATED BALANCE SHEETS
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
CONDENSED CONSOLIDATED BALANCE SHEETS
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
NOTE 2: SIGNIFICANT ACCOUNTING POLICIES
NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
NOTE 8: FAIR VALUE MEASUREMENTS
NOTE 9: CONTINGENCIES AND COMMITMENTS
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
LIQUIDITY AND FINANCIAL RESOURCES
ENFORCEMENT AND LITIGATION MATTERS
ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 4. CONTROLS AND PROCEDURES
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
| 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, |
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| 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 |
| Public Advocates Office of the California |
CCA | Community Choice Aggregator |
CEC | California Energy Resources Conservation and Development Commission |
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| Catastrophic Event Memorandum Account |
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| California Public Utilities Commission |
CRRs | congestion revenue rights |
DER | distributed energy resources |
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Diablo Canyon | Diablo Canyon nuclear power plant |
DOGGR | Division of Oil, Gas, and Geothermal Resources of the California Department of Conservation |
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| Department of Toxic Substances Control |
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| earnings per common share |
EV | electric vehicle |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
| 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 |
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MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 2 of this Form 10-Q |
| manufactured gas plants |
| NAV | net asset value |
NDCTP | Nuclear Decommissioning Cost Triennial Proceedings |
NEIL | Nuclear Electric Insurance Limited |
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| Nuclear Regulatory Commission |
OES | State of California Office of Emergency Services |
OII | order instituting investigation |
OIR | order instituting rulemaking |
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| Power Charge Indifference Adjustment |
PD | proposed decision |
PFM | petition for modification |
| Risk Assessment Mitigation Phase |
| SEC | U.S. Securities and Exchange Commission |
SED | Safety and Enforcement Division of the CPUC |
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| transmission owner |
| TURN | The Utility Reform Network |
Utility | Pacific Gas and Electric Company |
VIE(s) | variable interest entity(ies) |
WEMA | Wildfire Expense Memorandum Account |
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(Unaudited) Three Months Ended Nine Months Ended September 30, September 30, (in millions, except per share amounts) 2017 2016 2017 2016 Operating Revenues Electric $ $ $ $ Natural gas Total operating revenues Operating Expenses Cost of electricity Cost of natural gas Operating and maintenance Depreciation, amortization, and decommissioning Total operating expenses Operating Income Interest income Interest expense Other income, net Income Before Income Taxes Income tax provision (benefit) Net Income Preferred stock dividend requirement of subsidiary Income Available for Common Shareholders $ $ $ $ Weighted Average Common Shares Outstanding, Basic Weighted Average Common Shares Outstanding, Diluted Net Earnings Per Common Share, Basic $ $ $ $ Net Earnings Per Common Share, Diluted $ $ $ $ Dividends Declared Per Common Share $ $ $ $ See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, (in millions) 2017 2016 2017 2016 Net Income $ $ $ $ Other Comprehensive Income Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0 and $0, at respective dates) Total other comprehensive income (loss) Comprehensive Income Preferred stock dividend requirement of subsidiary Comprehensive Income Attributable to Common Shareholders $ $ $ $ See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Balance At September 30, December 31, (in millions) 2017 2016 ASSETS Current Assets Cash and cash equivalents $ $ Restricted cash Accounts receivable: Customers (net of allowance for doubtful accounts of $58 at both periods) Accrued unbilled revenue Regulatory balancing accounts Other Regulatory assets Inventories: Gas stored underground and fuel oil Materials and supplies Income taxes receivable Other Total current assets Property, Plant, and Equipment Electric Gas Construction work in progress Other Total property, plant, and equipment Accumulated depreciation Net property, plant, and equipment Other Noncurrent Assets Regulatory assets Nuclear decommissioning trusts Income taxes receivable Other Total other noncurrent assets TOTAL ASSETS $ $ See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Balance At September 30, December 31, (in millions, except share amounts) 2017 2016 LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ $ Long-term debt, classified as current Accounts payable: Trade creditors Regulatory balancing accounts Other Disputed claims and customer refunds Interest payable Other Total current liabilities Noncurrent Liabilities Long-term debt Regulatory liabilities Pension and other postretirement benefits Asset retirement obligations Deferred income taxes Other Total noncurrent liabilities Commitments and Contingencies (Note 9) Equity Shareholders' Equity Common stock, no par value, authorized 800,000,000 shares; 513,773,072 and 506,891,874 shares outstanding at respective dates Reinvested earnings Accumulated other comprehensive loss Total shareholders' equity Noncontrolling Interest - Preferred Stock of Subsidiary Total equity TOTAL LIABILITIES AND EQUITY $ $ See accompanying Notes to the Condensed Consolidated Financial Statements. (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 (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 $ 565 $ 550 $ 23 $ 1,533 See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Balance At (in millions) September 30,
2018 December 31,
2017ASSETS Current Assets Cash and cash equivalents $ 430 $ 449 Accounts receivable: 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,
2017LIABILITIES AND EQUITY 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 12,833 12,632 Reinvested earnings 6,623 6,596 Accumulated other comprehensive loss (12 ) (8 ) 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. 9
(Unaudited) Nine Months Ended September 30, (in millions) 2017 2016 Cash Flows from Operating Activities Net income $ $ Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning �� Allowance for equity funds used during construction Deferred income taxes and tax credits, net Disallowed capital expenditures Other Effect of changes in operating assets and liabilities: Accounts receivable Butte-related insurance receivable Inventories Accounts payable Butte-related third-party claims Income taxes receivable/payable Other current assets and liabilities Regulatory assets, liabilities, and balancing accounts, net Other noncurrent assets and liabilities Net cash provided by operating activities Cash Flows from Investing Activities Capital expenditures Decrease in restricted cash Proceeds from sales and maturities of nuclear decommissioning trust investments Purchases of nuclear decommissioning trust investments Other Net cash used in investing activities Cash Flows from Financing Activities Net issuances (repayments) of commercial paper, net of discount of $4 and $5 at respective dates Short-term debt financing Short-term debt matured Proceeds from issuance of long-term debt, net of discount and issuance costs of $11 and $6 at respective dates Long-term debt matured or repurchased Common stock issued Common stock dividends paid Other Net cash provided by (used in) financing activities Net change in cash and cash equivalents Cash and cash equivalents at January 1 Cash and cash equivalents at September 30 $ $ Cash received (paid) for: Interest, net of amounts capitalized $ $ Income taxes, net Supplemental disclosures of noncash investing and financing activities Common stock dividends declared but not yet paid $ $ Capital expenditures financed through accounts payable Noncash common stock issuances See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, (in millions) 2017 2016 2017 2016 Operating Revenues Electric $ $ $ $ Natural gas Total operating revenues Operating Expenses Cost of electricity Cost of natural gas Operating and maintenance Depreciation, amortization, and decommissioning Total operating expenses Operating Income Interest income Interest expense Other income, net Income Before Income Taxes Income tax provision (benefit) Net Income Preferred stock dividend requirement Income Available for Common Stock $ $ $ $ See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, (in millions) 2017 2016 2017 2016 Net Income $ 513 $ 389 $ 1,491 $ 706 Other Comprehensive Income Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0 and $0, at respective dates ) Total other comprehensive income (loss) Comprehensive Income $ 513 $ 389 $ 1,492 $ 707 See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Balance At September 30, December 31, (in millions) 2017 2016 ASSETS Current Assets Cash and cash equivalents $ $ Restricted cash Accounts receivable: Customers (net of allowance for doubtful accounts of $58 at both periods) Accrued unbilled revenue Regulatory balancing accounts Other Regulatory assets Inventories: Gas stored underground and fuel oil Materials and supplies Income taxes receivable Other Total current assets Property, Plant, and Equipment Electric Gas Construction work in progress Total property, plant, and equipment Accumulated depreciation Net property, plant, and equipment Other Noncurrent Assets Regulatory assets Nuclear decommissioning trusts Income taxes receivable Other Total other noncurrent assets TOTAL ASSETS $ $ See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Balance At September 30, December 31, (in millions, except share amounts) 2017 2016 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Short-term borrowings $ $ Long-term debt, classified as current Accounts payable: Trade creditors Regulatory balancing accounts Other Disputed claims and customer refunds Interest payable Other Total current liabilities Noncurrent Liabilities Long-term debt Regulatory liabilities Pension and other postretirement benefits Asset retirement obligations Deferred income taxes Other Total noncurrent liabilities Commitments and Contingencies (Note 9) Shareholders' Equity Preferred stock Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates Additional paid-in capital Reinvested earnings Accumulated other comprehensive income Total shareholders' equity TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ $ See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Nine Months Ended September 30, (in millions) 2017 2016 Cash Flows from Operating Activities Net income $ $ Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning Allowance for equity funds used during construction Deferred income taxes and tax credits, net Disallowed capital expenditures Other Effect of changes in operating assets and liabilities: Accounts receivable Butte-related insurance receivable Inventories Accounts payable Butte-related third-party claims Income taxes receivable/payable Other current assets and liabilities Regulatory assets, liabilities, and balancing accounts, net Other noncurrent assets and liabilities Net cash provided by operating activities Cash Flows from Investing Activities Capital expenditures Decrease in restricted cash Proceeds from sales and maturities of nuclear decommissioning trust investments Purchases of nuclear decommissioning trust investments Other Net cash used in investing activities Cash Flows from Financing Activities Net issuances (repayments) of commercial paper, net of discount of $4 and $5 at respective dates Short-term debt financing Short-term debt matured Proceeds from issuance of long-term debt, net of discount and issuance costs of $11 and $6 at respective dates Long-term debt matured or repurchased Preferred stock dividends paid Common stock dividends paid Equity contribution from PG&E Corporation Other Net cash provided by (used in) financing activities Net change in cash and cash equivalents Cash and cash equivalents at January 1 Cash and cash equivalents at September 30 Cash received (paid) for: Interest, net of amounts capitalized $ $ Income taxes, net Supplemental disclosures of noncash investing and financing activities Common stock dividends declared but not yet paid $ $ Capital expenditures financed through accounts payable See accompanying Notes to the Condensed Consolidated Financial Statements. Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2017 2016 2017 2016 Service cost for benefits earned $ Interest cost Expected return on plan assets Amortization of prior service cost Amortization of net actuarial loss Net periodic benefit cost Regulatory account transfer (1) Total Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Service cost for benefits earned $ Interest cost Expected return on plan assets Amortization of prior service cost Amortization of net actuarial loss Net periodic benefit cost Regulatory account transfer (1) Total (1)A portion of service costs are capitalized pursuant to ASU 2017-07. Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2017 Beginning balance $ $ $ Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $2, respectively) Amortization of net actuarial loss (net of taxes of $2 and $0, respectively) Regulatory account transfer (net of taxes of $2 and $2, respectively) Net current period other comprehensive gain (loss) Ending balance Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2016 Beginning balance $ $ $ Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $2, respectively) Amortization of net actuarial loss (net of taxes of $3, and $0, respectively) Regulatory account transfer (net of taxes of $3 and $2, respectively) Net current period other comprehensive gain (loss) Ending balance $ Pension Other Benefits Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2017 Beginning balance $ $ $ Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $5, respectively) Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) Regulatory account transfer (net of taxes of $5 and $6, respectively) Net current period other comprehensive gain (loss) Ending balance $ $ $ Pension Other Benefits Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2016 Beginning balance $ $ $ Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $5, respectively) Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) Regulatory account transfer (net of taxes of $9 and $6, respectively) Net current period other comprehensive gain (loss) Ending balance $ $ and Post-Retirement Benefit Costs PG&E Corporation and the Utility related disclosures. Asset Balance at (in millions) September 30, 2017 December 31, 2016 Deferred income taxes $ Pension benefits Environmental compliance costs Utility retained generation Price risk management Unamortized loss, net of gain, on reacquired debt Other Total long-term regulatory assets $ $ recovery. For more information, see Note 9 below. Liability Balance at (in millions) September 30, 2017 December 31, 2016 Cost of removal obligations $ $ Recoveries in excess of AROs Public purpose programs Other Total long-term regulatory liabilities $ $ Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) September 30, 2017 December 31, 2016 Electric distribution $ $ Electric transmission Utility generation Gas distribution and transmission Energy procurement Public purpose programs Other Total regulatory balancing accounts receivable $ $ Payable Balance at (in millions) September 30, 2017 December 31, 2016 Electric distribution $ $ Utility generation Electric transmission Gas distribution and transmission Energy procurement Public purpose programs Other Total regulatory balancing accounts payable $ $ Letters of Termination Facility Credit Commercial Facility (in millions) Date Limit Outstanding Paper Availability PG&E Corporation April 2022 $ (1) $ $ $ Utility April 2022 (2) Total revolving credit facilities $ $ $ $ 2018: Additionally, in February for general corporate purposes. PG&E Corporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2016 $ $ Comprehensive income Equity contributions Common stock issued Share-based compensation Common stock dividends declared Preferred stock dividend requirement Preferred stock dividend requirement of subsidiary Balance at September 30, 2017 $ $ Three Months Ended Nine Months Ended September 30, September 30, (in millions, except per share amounts) 2017 2016 2017 2016 Income available for common shareholders $ $ $ $ Weighted average common shares outstanding, basic Add incremental shares from assumed conversions: Employee share-based compensation Weighted average common shares outstanding, diluted Total earnings per common share, diluted $ $ $ $ Contract Volume at September 30, December 31, Underlying Product Instruments 2017 2016 Natural Gas (1) (MMBtus (2)) Forwards, Futures and Swaps 300,594,593 323,301,331 Options 79,640,435 96,602,785 Electricity (Megawatt-hours) Forwards, Futures and Swaps 3,505,504 3,287,397 Congestion Revenue Rights (3) 249,876,873 278,143,281 Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ $ $ $ Other noncurrent assets – other Current liabilities – other Noncurrent liabilities – other Total commodity risk $ $ $ $ Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ $ $ $ Other noncurrent assets – other Current liabilities – other Noncurrent liabilities – other Total commodity risk $ $ $ $ Commodity Risk Three Months Ended Nine Months Ended September 30, September 30, (in millions) 2017 2016 2017 2016 Unrealized gain (loss) - regulatory assets and liabilities (1) $ $ $ Realized loss - cost of electricity (2) Realized loss - cost of natural gas (2) Net commodity risk $ $ $ Balance at September 30, December 31, (in millions) 2017 2016 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ $ Related derivatives in an asset position Collateral posting in the normal course of business related to these derivatives Net position of derivative contracts/additional collateral posting requirements (1) $ $ Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements At September 30, 2017 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ $ $ $ $ Nuclear decommissioning trusts Short-term investments Global equity securities Fixed-income securities Assets measured at NAV Total nuclear decommissioning trusts (2) Price risk management instruments (Note 7) Electricity Gas Total price risk management instruments Rabbi trusts Fixed-income securities Life insurance contracts Total rabbi trusts Long-term disability trust Short-term investments Assets measured at NAV Total long-term disability trust TOTAL ASSETS $ $ $ $ $ Liabilities: Price risk management instruments (Note 7) Electricity $ $ $ $ $ Gas TOTAL LIABILITIES $ $ $ $ $ Fair Value Measurements At December 31, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ $ $ $ $ Nuclear decommissioning trusts Short-term investments Global equity securities Fixed-income securities Assets measured at NAV Total nuclear decommissioning trusts (2) Price risk management instruments (Note 9 in the 2016 Form 10-K) Electricity Gas Total price risk management instruments Rabbi trusts Fixed-income securities Life insurance contracts Total rabbi trusts Long-term disability trust Short-term investments Assets measured at NAV Total long-term disability trust TOTAL ASSETS $ $ $ $ $ Liabilities: Price risk management instruments (Note 9 in the 2016 Form 10-K) Electricity $ $ $ $ $ Gas TOTAL LIABILITIES $ $ $ $ $ (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. Fair Value at (in millions) At September 30, 2017 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ Market approach CRR auction prices $ (11.88) - 6.93 Power purchase agreements $ Discounted cash flow Forward prices $ 18.81 - 38.80 Represents price per megawatt-hour. Fair Value at (in millions) At December 31, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ $ Market approach CRR auction prices $ (11.88) - 6.93 Power purchase agreements $ $ Discounted cash flow Forward prices $ 18.07 - 38.80 Price Risk Management Instruments (in millions) 2017 2016 Asset (liability) balance as of July 1 $ $ Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) Asset (liability) balance as of September 30 $ $ 2017: Price Risk Management Instruments (in millions) 2017 2016 Asset (liability) balance as of January 1 $ $ Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) Asset (liability) balance as of September 30 $ $ At September 30, 2017 At December 31, 2016 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ $ $ $ Utility Total Total Amortized Unrealized Unrealized Total Fair (in millions) Cost Gains Losses Value As of September 30, 2017 Nuclear decommissioning trusts Short-term investments $ $ $ $ Global equity securities Fixed-income securities Total (1) $ $ $ $ As of December 31, 2016 Nuclear decommissioning trusts Short-term investments $ $ $ $ Global equity securities Fixed-income securities Total (1) $ $ $ $ debt securities: Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ $ $ $ Gross realized gains on securities held as available-for-sale Gross realized losses on securities held as available-for-sale 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 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 $45 million in insurance reimbursements. findings. In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations these proceedings. potential violations of electric and natural gas laws and regulations. Balance at September 30, December 31, (in millions) 2017 2016 Topock natural gas compressor station (1) $ Hinkley natural gas compressor station (1) Former manufactured gas plant sites owned by the Utility or third parties Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites Fossil fuel-fired generation facilities and sites Total environmental remediation liability $ flows during the period in which they are recorded. At September 30, The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the rates. December 31, 2019. Tax Act. The wildfires resulted in 44 fatalities. Statements in Item 1. Three Months Ended September 30, Nine Months Ended September 30, Earnings per Earnings per Common Share Common Share (in millions, Earnings (Diluted) Earnings (Diluted) except per share amounts) 2017 2016 2017 2016 2017 2016 2017 2016 PG&E Corporation’s Earnings on a GAAP basis $ $ $ $ $ $ $ 2.98 $ 1.40 Items Impacting Comparability: (1) Pipeline related expenses (2) Legal and regulatory related expenses (3) Fines and penalties (4) Butte fire-related costs, net of insurance (5) Net benefit from derivative litigation settlement (6) GT&S revenue timing impact (7) Diablo Canyon settlement-related disallowance (8) GT&S capital disallowance PG&E Corporation’s Earnings from Operations (9) $ $ $ $ $ $ $ $ for certain fines and penalties in 2017. Amounts may not sum due to rounding. Three Months Ended September 30, Nine Months Ended September 30, Earnings per Earnings per Common Share Common Share (in millions, except per share amounts) Earnings (Diluted) Earnings (Diluted) 2016 Earnings from Operations (1) $ $ $ $ Timing of taxes (2) Timing of operational spend (3) Growth in rate base earnings (4) Timing of 2015 GT&S revenue impact (5) Tax benefit on stock compensation (6) Miscellaneous Impact of 2017 GRC decision (7) Increase in shares outstanding 2017 Earnings from Operations (1) $ $ $ $ Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Consolidated Total PG&E Corporation Utility 2017: taxes in 2017. Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 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 $ $ $ $ $ $ Natural gas operating revenues Total operating revenues Cost of electricity Cost of natural gas Operating and maintenance Depreciation, amortization, and decommissioning Total operating expenses Operating income Interest income (1) Interest expense (1) Other income, net (1) Income before income taxes Income tax provision (1) Net income Preferred stock dividend requirement (1) Income Available for Common Stock $ $ (1)These items impacted earnings for the three months ended September 30, Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016 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 $ $ $ $ $ $ Natural gas operating revenues Total operating revenues Cost of electricity Cost of natural gas Operating and maintenance Depreciation, amortization, and decommissioning Total operating expenses Operating income Interest income (1) Interest expense (1) Other income, net (1) Income before income taxes Income tax provision (benefit) (1) Net income Preferred stock dividend requirement (1) Income Available for Common Stock $ $ Interest Expense Tax Act. Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Cost of purchased power $ $ $ $ Fuel used in own generation facilities Total cost of electricity $ $ $ $ Average cost of purchased power per kWh (1) $ $ $ $ Total purchased power (in millions of kWh) (2) The Utility’s total purchased power is driven by customer demand, the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Cost of natural gas sold $ $ $ $ Transportation cost of natural gas sold Total cost of natural gas $ $ $ $ Average cost per Mcf (1) of natural gas sold $ $ $ $ Total natural gas sold (in millions of Mcf) (2) The proceeds from these sales were used for general corporate $400 million aggregate principal amount of the 8.25% Senior Notes due October 15, 2018. for general corporate purposes. paper. Item 1.) Nine Months Ended September 30, (in millions) 2017 2016 Net cash provided by operating activities $ $ Net cash used in investing activities Net cash provided by (used in) financing activities Net change in cash and cash equivalents $ $ During the nine months ended September 30, 10-K. Increase/ Amounts (Decrease) (in millions) Approved in 2016 vs. Line of Business: Final Decision (1) Final Decision Electric distribution $ $ Gas distribution Electric generation Total revenue requirements $ $ Cost Category: (in millions) Operations and maintenance $ $ Customer services Administrative and general Less: Revenue credits Franchise fees, taxes other than income, and other adjustments Depreciation (including costs of asset removal), return, and income taxes Total revenue requirements $ $ 2017 GRC revenue requirement and rate base. December 20, 2018. In August 2016 and January 2017, TURN, FERC’s decision. (the “TO18” rate case) Amounts Amounts requested by proposed by the (in millions) the Utility FERC trial staff Revenue Requirement $ $ Return on Equity % % Composite Depreciation Rate % % On May 14, 2018, the Utility filed a proposal to reflect the impact of the Tax Act on its TO tariff rates effective March 1, 2018, in the resolution of the TO19 rate case. The tax impact reduces the TO19 requested revenue requirement from $1.79 billion to $1.66 billion. TO19 proceeding. following year, consistent with the formula rate. key remaining goals of the Diablo Canyon joint proposal agreement, including: Appeals affirmed the Superior Court ruling. On August 29, 2018, the California Supreme Court denied a petition for review filed by the World Business Academy, rendering the California State Lands Commission's approval of the new lands lease for Diablo Canyon final and non-appealable. The Utility expects to file its 2018 NDCTP application in December 2018. For more information, see March 2016. On in consultation with the California Air Resources Board and the CEC, to direct electrical corporations to file applications for programs and investments to accelerate widespread TE. In September 2016, the CPUC directed the Utility and the other large IOUs to file TE applications that include both short-term projects (of up to $20 million in total) and two- to five-year programs with a requested revenue requirement determined by the Utility. Integrated Distributed Energy Resources 2017 Form 10-K. counterparty credit. PG&E Corporation and the Utility this PD is November 29, 2018. The Utility’s insurance coverage. Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates. A loss which is not fully insured or cannot be recovered in customer rates could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. covered by insurance or recoverable in rates. new programs will increase fast charging options for consumers as well as electric charging infrastructure for non-light-duty fleet vehicles. The industry change, costs associated with complying with new regulatory developments and initiatives and with technological advancements, or the Utility’s inability to successfully adapt to changes in the electric industry, could materially affect the Utility’s operations, financial condition, and results of operations. ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS Utility. 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 /s/ JASON P. WELLS /s/ (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 (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 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. OFOF COMPREHENSIVE INCOME (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. 13 (Unaudited) Balance At September 30,
2018 December 31, 2017 (in millions) ASSETS Current Assets Cash and cash equivalents $ 371 $ 447 Accounts receivable: 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 (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 ) 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. 1720162017 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 20162017 Form 10-K. This quarterly report should be read in conjunction with the 20162017 Form 10-K. postretirementpost-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. Del Norte, 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 resulted in 43 fatalities, and destroyed an estimated 8,900 structures. The wildfires resulted in 44 fatalities.are being investigated byinvolved the Utility's equipment. The remaining wildfires remain under Cal Fire and the CPUC,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 109 below.Theare discussed insee Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 20162017 Form 10-K.2017,2018, 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, 2017,2018, it did not consolidate any of them.Asset Retirement ObligationsDetailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. On May 25, 2017, the CPUC issued a final decision in the 2015 NDCTP adopting a nuclear decommissioning cost estimate of $1.1 billion for Humboldt Bay, corresponding to the Utility’s request, and $2.4 billion for Diablo Canyon, compared to the Utility’s request of $3.8 billion, or 64 percent of its request. On an aggregate basis, the final decision adopted a $3.5 billion total nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s estimated cost to decommission Diablo Canyon, the final decision adopts assumptions which lower costs for large component removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility can seek recovery of these costs in the 2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ARO on the Condensed Consolidated Balance Sheets related to the assumed length of the wet cooling period of spent nuclear fuel after plant shut down. The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Condensed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $3.4 billion at September 30, 2017, and $3.5 billion at December 31, 2016. These estimates are based on decommissioning cost studies, prepared in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets.Post-retirementPost-Retirement Benefits20172018 and 20162017 were as follows: Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2018 2017 2018 2017 $ 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 41 (23 ) — — Total $ 85 $ 85 $ 3 $ 15 rates.rates Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2018 2017 2018 2017 $ 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 44 118 (69 ) — — Total $ 252 $ 254 $ 10 $ 44 rates.rates 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: (1 ) 3 2 1 (1 ) — 1 (2 ) (1 ) Net current period other comprehensive gain (loss) 1 — 1 Ending balance $ (29 ) $ 17 $ (12 ) postretirementpost-retirement benefit costs. (See the “Pension and Other PostretirementPost-Retirement Benefits” table above for additional details.) Pension Benefits Other
Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2017 Beginning balance $ (25 ) $ 17 $ (8 ) 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 ) postretirementpost-retirement benefit costs. (See the “Pension and Other PostretirementPost-Retirement Benefits” table above for additional details.) Pension Benefits Other Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2018 Beginning balance $ (25 ) $ 17 $ (8 ) (3 ) 8 5 3 (3 ) — 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 ) postretirementpost-retirement benefit costs. (See the “Pension and Other PostretirementPost-Retirement Benefits” table above for additional details.) Pension Benefits Other Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2017 Beginning balance $ (25 ) $ 16 $ (9 ) 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 ) postretirementpost-retirement benefit costs. (See the “Pension and Other PostretirementPost-Retirement Benefits” table above for additional details.)March 2016,May 2014, the FASB issued ASU No. 2016-09,2014-9, Compensation – Stock CompensationRevenue from Contracts with Customers (Topic 718)606), which amends the existing guidance relatingprevious revenue recognition guidance. The objective of the new standard is to the accountingprovide a single, comprehensive revenue recognition model for share-based payment awards issuedall contracts with customers to employees, including the income tax consequences, classificationimprove comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of awards as either equity or liabilities,financial statements through improved and classification on the statements of cash flows.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 adopted this standarda material impact on the Condensed Consolidated Financial Statements as of the fourth quarter of 2016. ASU 2016-09 requires, on a retrospective basis, that employee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities. As such, the Condensed Consolidated Statements of Cash Flows for PG&E Corporation and the Utilityadoption date or for the prior periods presented were retrospectively adjusted. This change resulted in an increase to cash flows from operating activitiesthree and a decrease to cash flows from financing activities of $35 million for the nine months ended September 30, 2016.(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 (273 ) (388 ) Total revenue from contracts with customers - electric 3,795 9,519 (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 30 (149 ) Total revenue from contracts with customers - gas 646 2,752 269 190 Total natural gas operating revenue 915 2,942 Total operating revenues $ 4,382 $ 12,672 Accounting Standards Issued But Not Yet AdoptedCostexisting guidance relating to the presentation of net periodic pension cost and net periodic postretirementother post-retirement benefit cost. costs. PG&E Corporation and the Utility applied the requirements when the ASU became effective on January 1, 2018.disaggregateseparate 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. In addition, onAs 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.willNo. 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 with early adoption permitted. Although PG&E Corporation and the Utility are currently evaluating thedid not have a material impact the guidance will have on the Condensed Consolidated Financial Statements and related disclosures, it is not expected to have a material impact to financial results.disclosures.Restricted CashNovember 2016,February 2018, the FASB issued ASU No. 2016-18,2018-02, 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 Cash Flows – Restricted Cash (Topic 230), which amendsIncome, PG&E Corporation and the existing guidance relating toUtility recognize the disclosure of restricted cash and restricted cash equivalents onrelated income tax expense at the statement of cash flows.tax rate in effect at that time. The ASU will beis effective for PG&E Corporation and the Utility on January 1, 2018, with2019, and early adoption is permitted. PG&E Corporation and the Utility will adoptearly adopted this ASU on January 1, 2018, resulting in the first quarter of 2018 and do not expect a material impact to the Condensed Consolidated Statements of Cash Flows and related disclosures as a result of this ASU.an immaterial reclassification. existing 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.early adopt this guidance in the fourthfirst quarter of 2018 using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply.2019. PG&E Corporation and the Utility expect this standard to increase lease assets and lease liabilities on the Condensed Consolidated Balance Sheets and are still evaluating the impactdo not expect the guidance will have a material impact on the Condensed Consolidated Statements of Income, Statements of Cash Flows and leaserelated disclosures.Recognition and of Financial Assets and Financial LiabilitiesJanuary 2016,August 2018, the FASB issued ASU No. 2016-01,2018-13, Financial Instruments – Overall (Subtopic 825-10)Fair Value Measurement (Topic 820): Recognition and Measurement of Financial Assets and Financial LiabilitiesDisclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurements, which amends the existing guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accountedrequirements 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. These investments are classified as “available-for-sale” and gains or losses are refundable, or recoverable, from customers through rates.measurements. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018.2020 with early adoption permitted. PG&E Corporation and the Utility do not expect a materialare currently evaluating the impact to the Condensedguidance will have on their Consolidated Financial Statements and related disclosures as a result of this ASU.disclosures.Revenue Recognition StandardMay 2014,August 2018, the FASB issued ASU No. 2014-09,2018-15, Revenue from Contracts with Customers (Topic 606), which amends existing revenue recognition guidance, effective January 1, 2018. The objective of the new standard is to provide a single, comprehensive revenue recognition modelIntangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting 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. The majority of the Utility’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Utility generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not resultImplementation Costs Incurred in a significant shift in the timing of revenue recognitionCloud Computing Arrangement that is a Service Contract. This ASU will be effective for such sales.intend to use the modified retrospective method when adopting the new standard on January 1, 2018.2020 with early adoption permitted. PG&E Corporation and the Utility expect thatare currently evaluating the impact of the new guidance will be immaterial to the Condensedhave on their Consolidated Financial Statements. Upon adoption of ASU 2014-09, the Utility plans to disclose revenues from contracts with customers separately from regulatory balancing account revenueStatements and disaggregate customer contract revenue by customer class.REGULATORY ASSETS,SSETS, LIABILITIES, AND BALANCING ACCOUNTSCurrent Regulatory AssetsAt September 30, 2017, the Utility had current regulatory assets of $573 million, which included $392 million of costs related to CEMA fire prevention and vegetation management. In 2014, the CPUC directed the Utility to perform additional vegetation management work in response to the severe drought in California.At September 30, 2017, other long-term regulatory assets included $189 million of 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 79 760 274 77 — 65 1 Other 407 264 Total long-term regulatory assets $ 4,429 $ 3,793 event-related costs incurred 2012 through 2017events that the Utility believes is recoverable through CEMA based on historical experience in recoveringare probable of recovery. For more information, see Note 9 below.for these typesrelated to insurance premiums that the Utility believes are probable of events. 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 20162017 Form 10-K. 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 20162017 Form 10-K.2017:(in millions) Termination Date Borrowings PG&E Corporation April 2022 $ 300 $ — $ — $ 300 Utility April 2022 3,000 87 — 2,913 Total revolving credit facilities $ 3,300 $ 87 $ — $ 3,213 In May 2017, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2021 to April 27, 2022.2017,2018, the Utility’s $250 million floating rate unsecured term loan, issued in March 2016,February 2017, matured and was repaid.2017,2018, the Utility entered into a $250 million floating rate unsecured term loan that matureswill mature on February 22, 2018.2019. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.Senior NotesIn March 2017, and Redemptionsissuedsatisfied and discharged its remaining obligation of $400 million aggregate principal amount of 3.30%the 8.25% Senior Notes due MarchOctober 15, 2027 and $2002018.principal amountfloating rate unsecured term loan. The term loan will mature on April 16, 2020, unless extended by PG&E Corporation pursuant to the terms of 4.00% Senior Notes due December 1, 2046.the term loan agreement. The proceeds were used for general corporate purposes, including the repaymentearly redemption of a portion of the Utility’sPG&E Corporation’s outstanding commercial paper.Pollution Control BondsIn June 2017, the Utility repurchased and retired $345$350 million principal amount of pollution control2.40% Senior Notes due March 1, 2019. On April 26, 2018, PG&E Corporation completed the early redemption of these bonds, Series 2004 A through D. Additionally in June 2017,which satisfied and discharged its remaining obligation of $350 million.remarketed three seriesissued $500 million principal amount of pollution control bonds, previously held in treasury, totaling $1454.25% Senior Notes due August 1, 2023 and $300 million in principal amount. Series 2008 Famount 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 2010 E bear interest at 1.75% per annum and mature on November 1, 2026. Series 2008 G bears interest at 1.05% per annum and matures on December 1, 2018.2017,2018, 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 0.88%1.55% to 0.95%1.68%. At September 30, 2017,2018, the interest rates on the $149 million principal amount of pollution control bonds Series 2009 A and B, and the related loan agreements, were 0.89%1.60%.20172018 were as follows:In PG&E Corporation Utility (in millions) 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 PG&E Corporation amended its February 2015 EDA providingequity distribution agreement for the sale of PG&E Corporation common stock having an aggregate price of up to $275 million. During the nine months ended September 30, 2017, PG&E Corporation sold 0.4 million shares of its common stock under the February 2017 EDA for cash proceeds of $28.4 million, net of commissions paid of $0.2 million. There were no issuances under the February 2017 EDA for the three months ended September 30, 2017.2018. As of September 30, 2017,2018, the remaining salesamount available under this agreement werewas $246.3 million. also issued common stock under the PG&E Corporation 401(k) plan the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the nine months ended September 30, 2017, 6.42018, 3.6 million shares were issued for cash proceeds of $316$136.7 million under these plans.26isare calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended 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 counterparty.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. PG&E Corporation’s and the Utility’s 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.Sheets at fair value. Eligible derivatives are accounted for under the accrual method of accounting.Sheets. Contract Volume at Underlying Product Instruments September 30,
2018 December 31,
2017 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 2,872,013 316,451,690 312,272,177 Commodity Risk (in millions) Netting Cash Collateral 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 At December 31, 2016, the Utility’s outstanding derivative balances were as follows:Gains and losses associated with price risk management activities were recorded as follows:(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. Commodity Risk (in millions) Netting Cash Collateral 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 agencies. At September 30, 2017, theagencies, also known as a credit-risk-related contingent feature. The Utility’s credit rating wasremains investment grade. If the Utility’sUtility 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.additional cash collateral thatUtility 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 ifadditional collateral immediately in the credit risk-related contingency features were triggered was as follows:(1) This calculation excludes the impactamount of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies. Fair Value Measurements September 30, 2018 (in millions) Level 1 Level 2 Level 3 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 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 $387$455 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements December 31, 2017 (in millions) Level 1 Level 2 Level 3 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 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 $333$440 million, primarily related to deferred taxes on appreciation of investment value.20172018 and 2016.2017. Fair Value at (in millions) September 30, 2018 Fair Value Measurement Assets Liabilities Valuation
Technique Unobservable
Input 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 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 megawatt-hourmegawatt-hour.(1) Represents price per megawatt-hourtable presentstables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 20172018 and 2016: Price Risk Management Instruments (in millions) 2018 2017 Asset (liability) balance as of July 1 $ 34 $ 48 Net realized and unrealized gains: (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: (18 ) (7 ) Asset (liability) balance as of September 30 $ 24 $ 48 The the fair values of cash, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at September 30, 20172018 and December 31, 2016,2017, as they are short-term in nature or have interest rates that reset daily. The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at September 30, 2017 and December 31, 2016. 33Available for Sale At September 30, 2018 At December 31, 2017 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value $ 350 $ 350 $ 350 $ 350 Utility 17,491 16,413 17,090 19,128 investments:(in millions) As of September 30, 2018 Amortized
Cost Total
Unrealized
Gains Total
Unrealized
Losses Total Fair
ValueNuclear 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 $ 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 $ 1,799 $ 1,514 $ (10 ) $ 3,303 $387$455 million and $333$440 million atfor the periods ended September 30, 20172018 and December 31, 2016,2017, respectively, primarily related to deferred taxes on appreciation of investment value.As of(in millions)September 30, 2017Less than 1 year$1–5 years5–10 yearsMore than 10 yearsTotal maturities of fixed-income securities$ 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 ) 34lossliability 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 can beis probable or reasonably estimated. A gain contingencypossible, and whether the loss or a range of losses is recorded inestimable, often involves a series of complex judgments about future events. PG&E Corporation's and the period inUtility's provision for loss and expense excludes anticipated legal costs, which all uncertainties have been resolved. are expensed as incurred.For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. Litigation and Regulatory Citations in Connection 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 for Sacramento County.County of Sacramento. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council previously had previously authorized the coordination of all cases in Sacramento County. As of SeptemberOctober 30, 2017, 772018, 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 3,7704,000 individual plaintiffs representing approximately 2,0802,100 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints. coordinated proceeding. Plaintiffs seek to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theoriestheory 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 mayto increase significantly in the future.future, because the statute of limitations for property damage and personal injury in connection with the Butte fire has expired. The Utility continues mediatingto mediate and settlingsettle cases.onto 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.the State 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. in the approximate amount ofto 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. Also, inThe Utility has not received any information or documentation from OES since its May 2017 statement. In June 2017, the County of Calaveras indicatedUtility entered into an agreement with the OES that it intendsextends their deadline to bringfile a claim against the Utility that it estimates in the approximate amount of $85 million. This claim would include costs that the County of Calaveras incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire. On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages. On August 10, 2017, the Court denied the Utility’s motion on the grounds that plaintiffs might be able to show conscious disregard for public safety based on the fact that the Utility relied on contractors to fulfill their contractual obligation to hire and train qualified employees. On August 16, 2017, the Utility filed a writ with the Court of Appeals challenging this novel theory of punitive damages liability. The Court of Appeals accepted the writ on September 15, 2017 and ordered the trial court and plaintiffs to show cause why the relief requested by the Utility should not be granted. Briefing on the writ should be completed by early 2018.In the third quarter of 2017, the Utility reached settlements with plaintiffs in the “preference” trial involving six households and with the plaintiffs in the representative trial that had been scheduled for August 2017 and October 2017, respectively. While there are no trials related to the Butte fire currently scheduled, one plaintiff has moved for a preference trial involving one household. The motion is set for hearing on December 1, 2017.On October 25, 2017, the Utility filed a motion to stay the trial court proceedings pending a decision by the Court of Appeals on the pending writ of mandate regarding punitive damages. A hearing on the stay motion is calendared for December 1, 2017.theorydoctrine of inverse condemnation. On June 22, 2017, the Superior Court for the County of Sacramento ruled on a motion of several plaintiffs and found that the Utility is liable for inverse condemnation. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding, others could file lawsuits and make similar claims. wereis 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. Utility currently believes that it is probable that it will incur aUtility’s assessment of the estimated loss of at least $1.1 billion, increased from the $750 million previously estimated as of December 31, 2016, in connection withrelated to the Butte fire. The Utility’s updated estimate resulted primarily from an increase in the number of claims filed against the Utility and experience to date in resolving claims. This amountfire is based on updated 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, but does notdamages.punitive damages for which the Utility could be liable. In addition, while this amount includes the Utility’s earlyUtility's assumptions about fire suppression costs (including its assessment of the Cal Fire loss), it doesand the County of Calaveras claim, they do not include any significant portion of the estimated claimsclaim from the OES and the County of Calaveras.OES. The Utility still does not have sufficient information to reasonably estimate any liability it may have for thesethat additional claims.The Utility currently is unable to reasonably estimate the upper end of the range of losses because it has insufficient information on the claims of over 1,000 households, including all of the recently filed claims, as well as the claims from the OES and the County of Calaveras. claimsclaim from the OES, and the County of Calaveras, outcomes of future court or jury decisions, and information about damages, including punitive damages, thatfor which the Utility could be liable, for, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued.Other current liabilitiesWildfire-related claims in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:Loss Accrual (in millions) Balance at December 31, 2015 $ — Accrued losses 750 (60 ) Balance at December 31, 2016 690 Accrued losses 350 (479 ) Balance at December 31, 2017 561 Accrued losses — (267 ) Balance at September 30, 2018 $ 294 Loss Accrual (in millions)Balance at December 31, 2015$Accrued lossesPayments(1)Balance at December 31, 2016$Accrued lossesPayments(1)Balance at September 30, 2017$(1) As of September 30, 20172018, the Utility entered into settlement agreementshas paid $806 million of the $832 million in settlements to date in connection with the Butte fire corresponding to approximately $515 million of which $398 million has been paid by the Utility.fire.$72$118 million in connection with the Butte fire. For the three and nine months ended September 30, 2017,2018, the Utility has incurred legal expenses in connection with the Butte fire of $18$9 million and $45$31 million, respectively.Loss RecoveriesThe Utility has liability insurance from various insurers, which 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, 2017, 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, in the three and nine months ended September 30, 2017, the Utility received $21 million and $53 million, respectively, of reimbursements from the insurance policies of one of its vegetation management contractors (excluded from the table below). Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain.The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:Balance at December 31, 2015$Accrued insurance recoveriesReimbursementsBalance at December 31, 2016$Accrued insurance recoveriesReimbursementsBalance at September 30, 2017$depending on whether$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 able to record or collectlisted as an additional insured, are uncertain.recoveriesreceivable since December 31, 2015. The balance for the insurance receivable is included in amounts sufficient to offset suchOther accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets: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 accruals.SED’sSED's investigation found that neither the Utility nor its vegetation management contractors took appropriate steps to prevent thea gray pine tree from leaning and contacting the Utility’sUtility'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.“Ghost Ship” FireOn December 2, 2016, 36 people died in a fire that occurred in the “Ghost Ship” warehouse in Oakland, California, during a music event. The families of 34 people who died in the fire have filed lawsuits against the property owner, the master tenant and neighboring tenants, and others, alleging defective electrical wiring and violations of fire safety codes. On May 16, 2017, a master complaint was filed, and added both PG&E Corporation and the Utility as defendants. The master complaint alleges that the Utility violated the California Labor Code and various electric rules in that it (1) should have inspected the premises to evaluate potential workplace hazards to Utility employees installing/maintaining its meters there, (2) should not have permitted sub-meters in the buildingwithout admitting liability or should have inspected those sub-meters, and (3) should have known that the building’s sub-meters and electrical system as a whole were dangerous and should have terminated service. The Utility filed a demurrer to the master complaint on June 30, 2017, on multiple grounds, including that the Utility has no duty to inspect its customers’ electrical equipment. On September 12, 2017, Alameda County Superior Court (the “court”) denied the Utility’s demurrer and on October 6, 2017, the Utility filed its answeragreeing with the court. The governmental entities (City of Oakland, County of Alameda and State of California) filed demurrers on September 12, 2017. On October 9, 2017, the plaintiffs dismissed, without prejudice, the State of California as a party to the case. On October 13, 2017, the plaintiffs filed opposition briefs to the demurrers filed by the City of Oakland and the County of Alameda. A hearing is scheduled for November 7, 2017.Several investigations regarding the origin and cause of the fire were conducted, including by the City of Oakland and the County of Alameda, the CPUC, and a third-party consulting and engineering firm. In June 2017, the City of Oakland released Oakland Fire Department’s report of the investigation stating that the cause of the fire was undetermined. The other investigations remain underway.PG&E Corporation and the Utility are uncertain when and how the Ghost Ship Fire lawsuit will be resolved and believe there is a remote possibility a material loss will occur.Valero Refinery OutageOn June 30, 2017, Valero Energy Corp. filed a lawsuit against the Utility after an electric outage occurred in its Benicia refinery in May 2017. Valero’s complaint alleges causes of action for breach of contract, breach of implied contract, breach of implied warranty, breach of covenant of good faith and fair dealing, negligence and gross negligence and seeks $75 million in damages from the Utility, resulting from refinery equipment damage, lost revenue and punitive damages. The Utility retained a third-party consulting and engineering firm to perform a causal evaluation of this outage. On September 11, 2017, Valero filed a first amended complaint removing its gross negligence and punitive damage claims. On October 23, 2017, the Utility filed with the court its response to Valero’s amended complaint. On October 27, 2017, Valero served the Utility with initial disclosures stating Valero’s total claim is $114 million in damages associated with equipment damage and lost profits.PG&E Corporation and the Utility believe it is reasonably possible that they will incur a material loss as a result of this lawsuit, but is unable to reasonably estimate the amount or range because it is in early stages of litigation. Federal InvestigationsIn addition, in October 2016, the Utility received a grand jury subpoena and letter from the U.S. Attorney for the Northern DistrictThe status of California advising that the Utilitythese investigations is a target of a federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act. The investigation involves a removal by the Utility of a hazardous tree that contained an osprey nest and egg in Inverness, California, on March 18, 2016.uncertain. The Utility is cooperating with this investigation. It is uncertainunable to predict whether any charges will be brought against the Utility as a result of these investigations.CPUC MattersSeptember 1, 2017,April 26, 2018, the assigned ALJCPUC approved the revised proposed decision issued a PD in this proceedingon April 3, 2018, adopting with one modification, 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 ORA,Office of Ratepayer Advocates or ORA), the SED, and TURN.If adopted, the PD would increase the payment to the California General Fund from $1 million to $12 million resultingGRC following the 20172020 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.On September 21, 2017, the Utility submittedmotionsecond phase in this proceeding to the CPUC accepting the proposed modificationdetermine if any of the settlement agreement to increase the Utility’s payment to the California General Fund from $1 million to $12 million. Further, the Utility also reported that it has identified several communications that appear to raise issues similar to other communications that are part of this proceeding.On November 1, 2017, the Utility filed a status report advising the CPUC that the Utility and the parties to the settlement agreement were unable to reach an agreement with respect to how to proceed regardingadditional communications that the Utility reported to the CPUC on September 21, 2017. Also on November 1, 2017, violate the non-UtilityCPUC 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 settlement requested that the CPUC approve the settlement, as modifiedissues identified by the PD, and openALJ. On September 17, 2018, the parties submitted a second phase ofjoint status report indicating a settlement in principle could not be reached. The ALJ will hold a prehearing conference with the OIIparties to investigate and consider appropriate sanctions for the new communications reported by the Utility on September 21, 2017, and others that may be discovered.The statutory deadline for this proceeding previously was extended to December 29, 2017.determine if evidentiary hearings are required. The Utility is unable to predict the timing and outcome of the second phase in this proceeding.2017,2018, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $24 million accrual for a portion of the amounts payable to the California General Fund and the Cities of San Bruno and San Carlos.2018 GT&S revenue requirement reduction. In accordance with accounting rules, adjustments related to revenue requirements would beare recorded in the periods in which they are incurred.“Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in Item 8 of the 20162017 Form 10-K.Order InstitutingInvestigation intoinitial decision in the Utility’s Safety CultureOn August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E CorporationTO18 rate case and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards. The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metricsfiled initial briefs on October 31, 2018, in relationresponse to the Utility’s record of operations, including its record of safety incidents.ALJ's recommendations. The CPUC authorizedUtility expects the SEDFERC to engageissue a consultant to assistfinal decision in the SED’s investigation andTO18 rate case by mid-2019. On September 21, 2018, the preparation of a report containing the SED’s assessment. On May 8, 2017, the CPUC President released the consultant’s report, accompanied by a scoping memo and ruling. The scoping memo establishes a second phaseUtility filed an all-party settlement with FERC in this OII in which the CPUC will evaluate the safety recommendationsconnection with TO19. As part of the consultant that may lead tosettlement, the CPUC’s adoptionTO19 revenue requirement will be set at 98.85% of the recommendationsrevenue requirement for TO18 that will be determined in the report, in whole or in part. This phase of the proceeding will also consider all necessary measures, including, but not limited to, a reduction of the Utility’s return on equity until any recommendations adopted by the CPUC are implemented.TO18 final decision. The Utility plans to adopt and implement the vast majority of the consultant’s recommendations by the middle of 2018. A workshop took place in September 2017 at which the consultant presented its report and answered stakeholders’ questions. The Utility’s testimony is expected to be filed with the CPUC in the fourth quarter of 2017 with other parties’ testimony and evidentiary hearings expected in the first quarter of 2018.PG&E Corporation and the Utility are unable to predict the outcomeoutcomes of this proceeding, including whether additional fines, penalties, or other ratemaking tools will ultimately be adopted by the CPUC, and whether the CPUC will require that a portion of return on equity for the Utility be dependent on making safety progress as the CPUC may defineFERC’s decisions in this proceeding. act. This includesact, and the Utility’s February 2017 self-report related to customer service representatives who handle gas emergency calls that was not timely submitted to the CPUC. The Utility believes it is probable that the SED will imposeoutcome of which could result in material fines and other penalties or take other enforcement action with respect to some or all of these violations. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed byon the SED with respect to these matters givenUtility. Under both the wide discretiongas and electric programs, the SED and other CPUC staff have in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines. The SED has discretion whether to issue a penalty for each violation, but if itviolation.TheHistorically, the SED historically has exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. The CPUC can also issue an OII and possible additional fines even afterIn the SED has issued a citation. Thepast, 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.On January 12, 2017, a residential structure fire occurred in Yuba City, California resulting in the collapse of the house and injuries to two persons inside the house. The CPUC a third-party engineering firm engaged by the Utility,can also open an OII and local fire and police officials have investigated the incident. Following SED’s investigation which included a review of the third-party engineering firm’s report, on October 20, 2017,levy additional fines even after the SED has issued a notice of probable violations against the Utility. The SED found two violations, for which the SED could issue a penalty of up to $8 million per violation. citation.may incur material costs, includingis unable to reasonably estimate the amount or range of future charges as a result of theseSED investigations or any proceedings that could be commenced in connection with this incident. $39$94 million at September 30, 2017,2018, and $45$86 million at December 31, 2016.2017. These amounts are included in Other current liabilities in the Condensed Consolidated Balance Sheets. ThePG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters is not expected towill have a material impact on PG&E Corporation’s and the Utility’stheir financial condition, results of operations, or cash flows.In May 2017,filedmay seek recovery in a settlement agreement with the CPUC related to the recovery of license renewal costs and cancelled project costs within its pending application to retire Diablo Canyon Power Plant. The settlement agreement allows for recovery from customers of $18.6 million of the total license renewal project cost of $53 million evenly over an 8-year period beginning January 1, 2018. Related to cancelled project costs, the settlement allows for recovery from customers of 100% of the direct costs incurred prior to June 30, 2016 and 25% recovery of direct costs incurred after June 30, 2016. During the nine months ended September 30, 2017, the Utility incurredfuture proceeding. Additional charges of $47 million related to settlement agreement, of which $24 million is for cancelled projects and $23 million is for disallowed license renewal costs.In addition, the Utility is subject to various cost caps within its rate cases that increase the risk of overspend throughout the rate case cycles. Charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending related to its 2015 GT&S rate case. PG&E Corporation and the Utility would record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates and the amount of disallowance can be reasonably estimated.spending. Capital disallowances are reflected in operating and maintenance expenses in the Condensed Consolidated Statements of Income. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in Item 8 of the 20162017 Form 10-K.composedcomprised of the following: Balance at September 30, December 31, (in millions) 2018 2017 Topock natural gas compressor station $ 362 $ 334 Hinkley natural gas compressor station 151 147 375 320
other facilities, and third-party disposal sites (2)116 115 136 123 Total environmental remediation liability $ 1,140 $ 1,039 See “Natural Gas Compressor Station Sites” below.Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, and San Francisco North Beach. measures that may be necessary to comply with these laws and regulations 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 records an environmental remediation liability when site assessments indicate remediation is probable and the Utility can reasonably estimate the loss or a range of possible losses. Key factors in estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. 20172018, reflects its best estimate of probable future costs associated with itsfor remediation plans.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. Future changesThe Utility may incur actual costs in cost estimatesthe future that are materially different than this estimate and the assumptions on which they are based maysuch costs could have a material impact on the Utility’s futureresults of operations, financial condition, and cash flows.2017,2018, the Utility expected to recover $698$797 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. Some of the Utility’s environmental remediation costs, such as the remediation costs associated with the Hinkley natural gas compressor site, fossil fuel-fired generation sites, and certain facilities formerly owned by the Utility, are not recoverable through rates.20162017 Form 10-K.One of these stations is located near Needles, California and is referred to below as the “Topock site.” Another station is located near Hinkley, California and is referred to below as the “Hinkley site.” The Utility is also required to take measures to abate the effects of the contamination on the environment.DOI. In November 2015,U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility submitted its final remediation design to the agencies for approval. The Utility’s design proposes that the Utility constructbuild 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 DTSC conducted an additionalUtility’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 reviewremediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the proposed design and issued a draft environmental impact report for public commentcosts are recovered in January 2017. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report by the end of 2017. After the Utility modifies its design in response to the final report, the Utility will seek approval to begin construction of the new in-situ treatment system in 2018. interim 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 final 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 requires settingsets plume capture requirements, requires establishing a monitoring and reporting program, and finalizesincludes deadlines for the Utility to meet interim cleanup targets.Reasonably Possible Environmental ContingenciesAlthough The United States Geological Survey team is currently conducting a background study on the Utility has provided for known environmental obligations that are probable and reasonably estimable,site to better define the chromium plume boundaries. The background study is expected to be finalized in 2019. The Utility’s undiscounted future costs couldassociated with the Hinkley site may increase by as much as $1.0 billion (including amounts related to the Topock and Hinkley sites described above)$138 million if the extent of contamination or necessary remediation is greater than anticipated oranticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.other potentially responsible partiesextent 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.financially ablebe recovered through rates.contributean 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 these costs. The Utility may incur actualdifferent insurance layers could result in substantial uninsured costs in the future depending on the amount and type of damages.are materially different than this estimate and suchthe Utility is currently recovering through rates through December 31, 2019. The Utility intends to seek recovery for the full amount of premium costs could have a material impactpaid in excess of the amount the Utility currently is recovering from customers through the end of the current GRC period, which ends on results of operations, financial condition, and cash flows during the period in which they are recorded.the European Mutual Association for Nuclear Insurance, covering nuclear or non- nuclearnon-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 offor the Utility would be approximately $58$47 million. TheIf European Mutual Association for Nuclear Insurance provides $200losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $3 million, for any one accident and in the annual aggregate the excessas of the combined amount recoverable under the Utility’s NEIL policies.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 20162017 Form 10-K. and continues to pursue, 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.2016,2017, respectively, the Condensed Consolidated Balance Sheets reflected $236$217 million and $243 million in net claims within Disputed claims and customer refunds. There were no significant changes to this balance during the nine months ended September 30, 2017. The Utility is uncertain when or how the remaining net disputed claims liability will be resolved.2017,2018, it is reasonably possible that unrecognized tax benefits will decrease by approximately $70$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. Gain ContingenciesSan Bruno Derivative LitigationJuly 18,December 22, 2017, the Superior CourtU.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 California, Countythe 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 San Mateo (the “Court”) approved the settlement agreement reachedTax Act and recorded provisional amounts, in accordance with rules issued by the partiesSEC staff in Staff Accounting Bulletin No. 118, for the San Bruno Fire Derivative Cases to resolve the consolidated shareholder derivative lawsuit and certain additional claims against certain current and former officers and directors (the “Individual Defendants”). Also,re-measurement of deferred tax balances as of July 19, 2017, the three cases, Tellardin v. Anthony F. Earley, Jr., et al.,Iron Workers Mid-South Pension Fund v. Johns, et al., and Bushkin v. Rambo, et al (the “Additional Derivative Cases”) were dismissed. The settlement will become effective when all procedural conditions specifiedDecember 31, 2017. As a result of updated amounts used in the settlement stipulation are satisfied. PG&E Corporation recorded $65 million in proceeds from insurance, net of plaintiff costs to its Condensed Consolidated Income Statement forand the three andUtility's 2017 tax returns, during the nine months ended September 30, 2017.PG&E Corporation and2018, the Utility also agreed, under their indemnification obligationsrecorded 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 Individual Defendants, to pay $18.3 million of the Individual Defendants’ costs, fees, and expenses incurred in connection with responding to, defending and settling the San Bruno Fire Derivative Cases and the Additional Derivative Cases, including certain fees and expenses for investigating these claims. The $18.3 million has been paid, with the majority reflected in PG&E Corporation’s and the Utility’s financial statements throughregulatory liability recorded at December 31, 2016.In addition, pursuant to2017 for the settlement agreement, PG&E Corporation and the Utility will implement certain corporate governance therapeutics for five years, and the Utility will implement certain gas operations therapeutics and maintain certain of them for three years, at an estimated cost of up to approximately $32 million. The Court also directed PG&E Corporation to provide at least quarterly reports to the Court and to the City of San Bruno summarizing the progress of the implementation of the corporate governance and gas operations therapeutics. 2016,2017, the Utility had undiscounted future expected obligations of approximately $47$44 billion. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 20162017 Form 10-K.) The Utility has not entered into any new material commitments during the nine months ended September 30, 2017.Investigation of Recent Northern California wildfiresBeginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Del Norte, 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 California that, in total, burned over 245,000 acres, resulted in 43 fatalities, and destroyed an estimated 8,900 structures.The causes of these fires are being investigated by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities. The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the way that they progressed. The CPUC’s 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. It is uncertain when the investigations will be complete and whether Cal Fire will release preliminary findings before its investigation is complete. As of October 31, 2017, the Utility had submitted 20 electric incident reports to the CPUC involving the Utility’s facilities in and around the areas impacted by the Northern California wildfires. Electric utilities must report to the CPUC incidents that are attributable or allegedly attributable to utility-owned facilities and (1) result in fatality or personal injury rising to the level of in-patient hospitalization; or (2) are the subject of significant public attention or media coverage; or (3) involve damage to property of the Utility or others estimated to exceed $50,000. The information contained in these reports is factual and does not include a determination of the causes of the fires. The investigations into the causes of the fires are ongoing.The Utility estimates that it will incur costs in the range of $160 million to $200 million for service restoration and repairs to the Utility’s facilities (including an estimated $60 million to $80 million in capital expenditures) in connection with these fires. 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 adversely affected if the Utility were unable to recover such costs.If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the cause of one or more fires, and the theory of inverse condemnation applies, the Utility could be liable for property damages, interest, and attorneys’ fees without having been found negligent, which liability, in the aggregate, could be substantial. Courts have imposed liability under inverse condemnation policy to actions 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 benefitted from such undertaking and based on the assumption that utilities have the ability to recover these costs from their customers. In addition to such claims for property damage, interest and attorneys’ fees, as well as claims under other theories of liability, the Utility could be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial. The Utility also could be subject to material fines or penalties 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. PG&E Corporation and the Utility are unable to reasonably estimate the amount of possible losses (or range of amounts) given the preliminary stages of the investigations and uncertainty as to the causes of the fires and the extent and magnitude of damages. As of October 31, 2017, the Utility is aware of nine lawsuits, one of which seeks to be designated as a class action, that have been filed against PG&E Corporation and the Utility in Sonoma, Napa and San Francisco Counties' Superior Courts. The lawsuits allege, among other things, negligence, inverse condemnation, trespass, and private nuisance. They principally assert that PG&E Corporation and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the cause of the fires. The plaintiffs seek damages that include personal injury, property damage, evacuation costs, medical expenses, and other damages. PG&E Corporation and the Utility may be subject of additional lawsuits in connection with the Northern California wildfires.The Utility has approximately $800 million in liability insurance for potential losses that may result from the Northern California wildfires. If the Utility were held liable for one or more fires and the Utility’s insurance were insufficient to cover that liability or the Utility were unable to recover costs in excess of insurance through regulatory mechanisms, either of which could take a number of years to resolve, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected. Following the Northern California wildfires, PG&E Corporation reinstated its liability insurance in the amount of approximately $630 million for any potential future event.20162017 Form 10-K. Del Norte, 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 resulted in 43 fatalities, and destroyed an estimated 8,900 structures.are being investigated byinvolved the Utility's equipment. The remaining wildfires remain under Cal Fire and the CPUC,Fire's investigation, including the possible role of the Utility's power lines and other facilities. The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the way that they progressed. The CPUC’s 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. It is uncertain when the investigations will be complete and whether Cal Fire will release preliminary findings before its investigation is complete. As of October 31, 2017, the Utility had submitted 20 electric incident reports to the CPUC involving the Utility’s facilities in and around the areas impacted byAdditionally, the Northern California wildfires. Electric utilities must report towildfires are under investigation by the CPUC incidents that are attributable or allegedly attributable to utility-owned facilities and (1) result in fatality or personal injury rising to the levelCPUC's SED. For more information, see Note 9 of in-patient hospitalization; or (2) are the subject of significant public attention or media coverage; or (3) involve damage to property of the Utility or others estimated to exceed $50,000. The information contained in these reports is factual and does not include a determination of the causes of the fires. The investigations into the causes of the fires are ongoing. See Note 10 in the Notes to the Condensed Consolidated Financial Statements. adversely affected by additional potential losses resulting from the impact of the Northern California wildfires. See Item“Item 1A. Risk FactorsFactors” in thisthe 2017 Form 10-Q.10-K and in Part II below under “Item 1A. Risk Factors.”20172018 as compared to the same periods in 20162017 and a summary reconciliation of the key drivers of PG&E Corporation’s earnings from operations and EPS based on earnings from operations for the three and nine months ended September 30, 20172018 as compared to the same periodsperiod in 2016.2017. “Earnings from operations” is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability. “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods. PG&E Corporation uses earnings from operations to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short and long-term operating plans,planning, and employee incentive compensation. PG&E Corporation believes that non-GAAP earnings from operations provide additional insight into the underlying trends of the business allowing for a better comparison against historical results and expectations for future performance. EarningsNon-GAAP earnings from operations are not a substitute or alternative for GAAP measures such as income available for common shareholders and may not be comparable to similarly titled measures used by other companies. 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 31 — 0.06 — 1,639 — 3.17 — 9 12 0.02 0.02 25 45 0.05 0.09 6 42 0.01 0.08 17 27 0.03 0.05 (27 ) — (0.05 ) — (27 ) — (0.05 ) — — — — — (23 ) — (0.05 ) — — 11 — 0.02 — 47 — 0.09 — — — — — 32 — 0.06 — 1 — — — 5 — 0.01 — — — — — (88 ) — (0.17 ) — (38 ) — (0.07 ) — (38 ) — (0.07 ) $ 582 $ 578 $ 1.13 $ 1.12 $ 1,652 $ 1,562 $ 3.19 $ 3.04 as indicated below.“Items “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods.$20insurance, of $43 million (before the tax impact of $8$12 million) and $76 million$2.3 billion (before the tax impact of $31$637 million) during the three and nine months ended September 30, 2017,2018, respectively, associated with the Northern California wildfires. This includes accrued charges of $2.5 billion (before the tax impact of $700 million) during the nine months ended September 30, 2018, related to estimated third-party claims in connection with 14 of the Northern California wildfires. The Utility also recorded $53 million (before the tax impact of $15 million) and $120 million (before the tax impact of $34 million) during the three and nine months ended September 30, 2018, respectively for pipeline relatedlegal and other costs. In addition, the Utility incurred costs of $40 million (before the tax impact of $11 million) during the nine months ended September 30, 2018 for Utility clean-up and repair costs. These costs were partially offset by $10 million (before the tax impact of $3 million) and $385 million (before the tax impact of $108 million) recorded during the three and nine months ended September 30, 2018, respectively, for probable insurance recoveries. (3) (4)The Utility incurred costs, net of $2 million (before the tax impactinsurance, of $1 million) and $9 million (before the tax impact of $4$3 million) and $24 million (before the tax impact of $7 million) during the three and nine months ended September 30, 2017,2018, respectively, associated with legal costs for legalthe Butte fire. These costs were partially offset by $7 million (before the tax impact of $2 million) recorded during the nine months ended September 30, 2018 for contractor insurance recoveries.regulatory related expensesnine months ended September 30, 2018. The Utility had previously recorded $85 million (before the tax impact of $35 million) in 2016 for probable capital disallowances in the 2015 GT&S rate case. From 2012 through 2014, the Utility had recorded cumulative charges of $665 million (before the tax impact of $271 million) for disallowed Pipeline Safety Enhancement Plan-related capital expenditures.connection with various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.2017 above amounts included in authorized revenue requirements.(4) (7)The Utility incurred costs of $11 million (not tax deductible) and $71 million (before the tax impact of $24 million) during the three and nine months ended September 30, 2017, respectively, for fines and penalties. This includesincluded disallowed expenses of $32 million (before the tax impact of $13 million) during the nine months ended September 30, 2017, associated with safety-related cost disallowances imposed by the CPUC in its April 9, 2015 decision (“San Bruno Penalty Decision”) in the gas transmission pipeline investigations. The Utility also recorded $15 million (before the tax impact of $6 million) during the nine months ended September 30, 2017, for disallowances imposed by the CPUC in its final phase two decision of the 2015 GT&S rate case for prohibited ex parte communications. In addition, the Utility recorded $11 million (not tax deductible) and $24 million (before the tax impact of $5 million) during the three and nine months ended September 30, 2017, respectively,for financial remedies in connection with the proposed decision andsettlement filed with the settlement inCPUC on March 28, 2017, related to the Order Instituting an Investigationorder instituting investigation into Compliancecompliance with Ex Parte Communication Rules. Future fines or penalties may be imposed in connection with other enforcement, regulatory, and litigation activities regarding regulatory communications.ex parte communication rules.(5) (8)The Utility incurred costsrecorded a disallowance of $71$47 million (before the tax impact of $29$15 million) and $46during the nine months ended September 30, 2017, comprised of cancelled projects of $24 million (before the tax impact of $19$6 million), during the three and nine months ended September 30, 2017, respectively, associated with the Butte fire, netdisallowed license renewal costs of insurance. This includes accrued charges of $350$23 million (before the tax impact of $143$9 million), duringas a result of the three and nine months ended September 30, 2017, relatedsettlement agreement submitted to estimated third-party claims.the CPUC in connection with the Utility’s joint proposal to retire the Diablo Canyon Power Plant.also incurred chargescosts of $18$2 million (before the tax impact of $7$1 million) and $46$9 million (before the tax impact of $19$4 million), during the three and nine months ended September 30, 2017, respectively, for legal costs. These costs were partially offset by insurance recoveriesand regulatory related expenses incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.$297$150 million (before the tax impact of $121$62 million) and $350 million (before the tax impact of $143 million) recorded during the three and nine months ended September 30, 2017 respectively.in excess of the 2017 authorized revenue requirement, which included the final component of under-collected revenues retroactive to January 1, 2015, as a result of the CPUC’s final phase two decision in the 2015 GT&S rate case.(6) (11)PG&E Corporation recorded proceeds from insurance, net of plaintiff payments, of $65 million (before the tax impact of $27 million) during the three and nine months ended September 30, 2017, associated with the settlement agreement in connection with the San Bruno shareholder derivative litigation that was approved by the Superior Court of California, County of San Mateo, on July 18, 2017. This includesincluded $90 million (before the tax impact of $37 million) during the three and nine months ended September 30, 2017, for proceeds from insurance, partially offset by $25 million (before the tax impact of $10 million) during the three and nine months ended September 30, 2017, for plaintiff legal fees paid in connection with the settlement.(7) (12)As a result of the CPUC’s final phase two decision in the 2015 GT&S rate case, during the nine months ended September 30, 2017, the Utility recorded revenues of $150 million (before the tax impact of $62 million) in excess of the 2017 authorized revenue requirement, which includes the final component of under-collected revenues retroactive to January 1, 2015.(8) As a result of the settlement agreement submitted to the CPUC in connection with the Utility’s pending joint proposal to retire the Diablo Canyon Power Plant, the Utility recorded a total disallowance of $47 million (before the tax impact of $15 million) during the nine months ended September 30, 2017, comprised of cancelled projects of $24 million (before the tax impact of $6 million) and disallowed license renewal costs of $23 million (before the tax impact of $9 million), with no corresponding charges during the same periods in 2016. A portion of the cancelled projects and disallowed license renewal costs currently is not tax deductible. (9) “Earnings “Non-GAAP earnings from operations” is a non-GAAP financial measure. 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) $ 578 $ 1.12 $ 1,562 $ 3.04 Growth in rate base earnings 32 0.06 97 0.18 12 0.02 13 0.02 6 0.01 33 0.06 — — 29 0.06 Timing and duration of nuclear refueling outages — — 12 0.02 (31 ) (0.06 ) (31 ) (0.06 ) (7 ) (0.01 ) (21 ) (0.03 ) — — (44 ) (0.08 ) Increase in shares outstanding — — — (0.02 ) Miscellaneous (8 ) (0.01 ) 2 — $ 582 $ 1.13 $ 1,652 $ 3.19 benefits onimpact of stock compensation. See Footnote 67 below. Amounts may not sum due to rounding.variancevariances in the percentage of quarterly earnings to annual earnings.20172018, as compared to the same period in 2016.2017.(4) (7) Represents the impact of the increase in rate base as authorized in various rate cases, including the 2017 GRC, during the three and nine months ended September 30, 2017 as compared to the same periods in 2016.(5) Represents the impact in 2016 of the delay in the Utility’s 2015 GT&S rate case. The CPUC issued its final phase two decision on December 1, 2016, delaying recognition of the full 2016 revenue increase until the fourth quarter of 2016.(6) Represents the incremental tax benefitincome taxes related to share-based compensation awards under the Long-Term Incentive Plan that vested during the nine months ended September 30, 2017. Pursuant2018, as compared to ASU 2016-09, Compensation – Stock Compensation (Topic 718), which PG&E Corporation and the Utility adoptedsame period in 2016, excess tax benefits associated with vested awards are reflected in net income.2017.(7) Represents the impact of lower tax repair benefits as a result of the CPUC’s final decision in the 2017 GRC proceeding.Corporation’sCorporation and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected by potential losses resulting from the impact ofUtility face several uncertainties in connection with the Northern California wildfires. Thewildfires, related to: the amount of additional possible loss related to third party claims (the Utility estimates that it will incur costs inrecorded a charge of $2.5 billion, which reflects the low end of the range of $160 million to $200loss); recoverability of clean-up and repair costs (the Utility incurred costs of $308 million for service restorationclean-up and repairs torepair of the Utility’s facilities (including an estimated $60 million to $80 million in capital expenditures) in connection with these fires. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flowsthrough September 30, 2018); fines or penalties, which could be materially adversely affected if the Utility were unable to recover such costs through CEMA. If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the cause of one or more fires, and the theory of inverse condemnation applies, the Utility could be liable for property damages, interest, and attorneys’ fees without having been found negligent, which liability, in the aggregate, could be substantial. In addition to such claims, as well as claims under other theories of liability, the Utility could be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial. The Utility also could be subject to material, fines or penalties 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.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.”)weresubmits an application to determine that itthe 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 both probable that a material loss has occurredpending resolution.amountUtility’s ability to access the capital markets, ability to borrow under their loan financing arrangements, and the terms and rates of loss canfuture financings could be reasonably estimated, a liability would be recorded consistent withmaterially affected by the principlesoutcome of, or market perception of, the matters discussed in Note 9 toof the Notes to the Condensed Consolidated Financial Statements. To the extent not offset by insurance recoveries determined to be similarly probable and estimable, the liability would affect the balance sheet equity of 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. (See Note 10PG&E Corporation may seek to Notesissue additional equity to pay claims, losses, fines, and penalties that may be required by the Condensed Consolidated Financial Statementsoutcome of litigation and Item 1A. Risk Factors in this Form 10-Q.) enforcement matters. Additional issuances of equity, if any, could have a material dilutive impact on PG&E Corporation’s EPS. future 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 as a resultthe outcome of the phase two of the proceeding, the ex parte OII, and the related proposed decision, the potential recommendations that the third-party monitor (appointed(retained by the Utility in the first quarter of 2017 as a resultpart of its compliance with the sentencing terms of the Utility’s conviction in theJanuary 27, 2017 federal criminal trial)conviction) may make, related to the Utility’s conviction in the federal criminal trial, and potential penalties in connection with the Utility’s safety and other self-reports. (See Item 1A. Risk Factors in the 2016 Form 10-K and Item 1A. in this Form 10-Q.)The Timing and Outcome of Ratemaking Proceedings. The Utility’s future results may be impacted by the timing and outcome of its FERC TO18 and TO19 rate cases. (See “Transmission Owner Rate Cases” in “Regulatory Matters” below for more information.) 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.The Ability of the Utility to Control and Recover Operating Costs and Capital Expenditures. In any given year the Utility’s ability to earn its authorized rate of return depends on its ability to manage costs within the amounts authorized in rate case decisions. The Utility also forecasts that in 2017 it will incur unrecovered pipeline-related expenses of approximately $90 million which primarily relate to costs to identify and remove encroachments from transmission pipeline rights-of-way. Also, the CPUC decision in the Utility’s 2015 GT&S rate case establishes various cost caps that will increase the risk of overspend over the rate case cycle through 2018. (See “Disallowance of Plant Costs” in Note 9 of the Notes to the Condensed Consolidated Financial Statements.Statements in Item 1.)Amount and Timing of the Utility's Financing Needs. PG&E Corporation’s and the Utility’s ability to access the capital markets, to borrow under its loan financing arrangements and the terms and rates of future financings could be materially adversely affected by the outcome of or market perception of the matters discussed in Note 9 and Note 10 of the Notes to the Condensed Consolidated Financial Statements, including liabilities, if any, incurred in relation to the recent Northern California wildfires, adverse effects on their ability to comply with consolidated debt to total capitalization ratio covenants in their financing arrangements and regulatory capital structure requirements resulting therefrom, adverse changes in their respective credit ratings, general economic and market conditions, and other factors. 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, 2017, PG&E Corporation issued $361 million of common stock and made equity contributions of $405 million to the Utility. PG&E Corporation forecasts that it will need to continue to issue a material amount of equity in future years, primarily to support the Utility’s capital expenditures. PG&E Corporation may seek to issue additional equity to fund unrecoverable pipeline-related expenses and 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.programs,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. The utility industry is also undergoing a transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy. California’s environmental policy objectives are accelerating the pace and scope of the industry change. The electric grid is a critical enabler of the adoption of new energy technologies that support California's climate change and GHG reduction objectives, which continue to be publicly supported by California policy makers notwithstanding a recent change in the federal approach to such matters. In order to enable the California clean energy economy, sustained investments are required in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, EV infrastructure and State infrastructure modernization (e.g. rail and water projects). The Utility forecasts over $1 billion in grid investments through 2020, that would include increased remote control and sensor technology of the grid, integration investments in connection with DER bi-directional energy flows and voltage fluctuations, advanced grid data analytics, grid storage that enables renewable integration, expanded infrastructure for light, medium, and heavy-duty EVs, transmission integration for renewables, and energy efficiency and demand response programs. In addition, these changes brought about by technological advancements and climate policy may cause a reduction in natural gas usage and increase natural gas costs. The combination of reduced natural gas load and increased costs could result in higher natural gas customer bills and potential cost recovery risk.(See “Other Regulatory Proceedings” below.)20162017 Form 10-K and in Part II below under “Item 1A. Risk Factors.” In addition, this quarterly report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. See the section entitled “Forward-Looking Statements” below for a list of some of the factors that may cause actual results to differ materially. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.20172018 and 2016: 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 increasedecreases in PG&E Corporation’s net income for the three and nine months ended September 30, 2017, respectively,2018 as compared to the same periods in 2016 is2017 are primarily due to the impact of the San Bruno Derivative Litigation in 2017 with no corresponding activity in 2018, partially offset by additional income tax expense and interest expense.20172018 and 2016.2017. The tables separately identify the revenues and costs that impacted earnings from those that did not impact earnings. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs), and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings. In addition, expenses that have been specifically authorized (such as the payment of pension costs) and the corresponding revenues the Utility is authorized to collect to recover such costs do not impact earnings. 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 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 14 — 14 10 — 10 (229 ) — (229 ) (217 ) — (217 ) 22 81 103 24 14 38 Income before income taxes $ 585 $ — $ 585 $ 651 $ — $ 651 14 138 Net income 571 513 3 3 Income Available for Common Stock $ 568 $ 510 20172018 and 2016.2017. 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 (530 ) 394 Net income 47 1,491 10 10 Income Available for Common Stock $ 37 $ 1,481 20172018 and 2016.2017.20172018 and 2016,2017, focusing on revenues and expenses that impacted earnings for these periods. $17$50 million, or 1%2%, in the three months ended September 30, 2018, compared to the same period in 2017, primarily due to increased base revenues authorized in the 2017 GRC.$528$15 million in the nine months ended September 30, 2018, compared to the same period in 2017, primarily due to $102 million in retroactive base revenues authorized in the 2015 GT&S rate case recognized in the nine months ended September 30, 2017, partially offset by an increase in base revenues as authorized in the 2017 GRC in the same period in 2018.2017,2018, respectively, compared to the same periods in 20162017, primarily due to additional base revenues authorized by the CPUC in the 2015 GT&S rate case and the 2017 GRC, and by the FERC in the TO rate case. The final 2015 GT&S rate case decision authorized the Utility to collect, over a 36-month period, the difference between adopted revenue requirements and amounts previously collected in rates, retroactive to January 1, 2015, beginning August 1, 2016. Accounting rules allow the Utility to recognize revenues in a given year only if they will be collected from customers within 24 months of the end of that year. As a result, the Utility recognized $102 million in January 2017 related to remaining retroactive revenues that had not previously been recognized.Operating and MaintenanceThe Utility’s operating and maintenance expenses that impacted earnings decreased by $193 million, or 14%, in the three months ended September 30, 2017 compared to the same period in 2016. During the three months ended September 30, 2016, the Utility recorded $241 million in disallowed charges related to the 2015 GT&S rate case and the San Bruno Penalty Decision with no similar charges in the same period of 2017. The Utility also recorded $297 million in insurance recoveries for the three months ended September 30, 2017 related to the Butte fire, with no similar recoveries for the same period in 2016. These decreases were partially offset by $352 million in higher charges related to the Butte fire (in the three months ended September 30, 2017, the Utility recorded $368 million in charges as compared to $16 million in the same period in 2016). The Utility’s operating and maintenance expenses that impacted earnings decreased by $845 million, or 19%, in the nine months ended September 30, 2017 compared to the same period in 2016. For the nine months ended September 30, 2017, the Utility recorded $429 million fewer disallowed charges (in the nine months ended September 30, 2017, the Utility incurred a $47 million disallowance related to the Diablo Canyon settlement as compared to $476 million of disallowed capital charges related to the San Bruno Penalty Decision and 2015 GT&S rate case decision during the same period in 2016) and $51 million in lower charges related to the Butte fire (in the nine months ended September 30, 2017, the Utility recorded $395 million in charges as compared to $446 million in the same period in 2016) (see Note 9 of the Notes to the Condensed Consolidated Financial Statements). Additionally, insurance recoveries related to the Butte fire increased by approximately $90 million (in the nine months ended September 30, 2017, the Utility recorded $350 million in insurance recoveries as compared to approximately $260 million in the same period in 2016).The Utility’s future financial statements will continue to be impacted by unrecoverable pipeline-related expenses. Additionally, the Utility expects to incur approximately $100 million in 2017 related to reinstatement of a portion of its liability insurance and legal costs related to the Northern California wildfires. (See “Key Factors Affecting Financial Results” above and Note 9 of the Notes to the Condensed Consolidated Financial Statements.) Additionally, the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected by potential losses resulting from the impact of the Northern California wildfires (See Item 1A. Risk Factors below and Note 10 of the Notes to the Condensed Consolidated Financial Statements) and any additional charges associated with the costs related to the Butte fire.Depreciation, Amortization, and DecommissioningThe Utility’s depreciation, amortization, and decommissioning expenses increased by $16 million, or 2%, and by $44 million, or 2%, in the three and nine months ended September 30, 2017 compared to the same periods in 2016 primarily due to higher depreciation rates as authorized in the 2017 GRC and capital additions.Interest ExpenseThe Utility’s interest expense for the periods presented increased by $8 million, or 4%, and by $41 million, or 7%, in the three and nine months ended September 30, 2017, respectively, as compared to the same periods in 2016. These increases were primarily due to higher levels of long term debt and short term borrowings in 2017 compared to 2016.Other Income, Netother income, netinterest expense that impacted earnings for the periods presented.increaseddecreased by $65$124 million in the three months ended September 30, 20172018, as compared to the same period in 2016.2017. The effective tax rates for the three months ended September 30, 2018 and 2017 were 2.5% and 2016 were 21% and 16%21.2%, respectively. The increasesdecrease in the income tax provisionprovisions and in the effective tax raterates were primarily resulted from higher pre-tax income in 2017 as compared to 2016 and lower repairs deductionsthe result of a decrease in the three months ended September 30, 2017 comparedcorporate income tax rate from 35% to 21% as a result of the same period in 2016.increaseddecreased by $493$924 million in the nine months ended September 30, 20172018, as compared to the same period in 2016.2017. The effective tax rates for the nine months ended September 30, 2018 and 2017 were 109.8% and 2016 were 21% and (16%)20.9%, respectively. The increasedecrease in the income tax provisionprovisions and increases in the effective tax rate were primarily resulted from higherthe result of pre-tax losses in 2018 versus pre-tax income in 2017, partially offset by a decrease in the corporate income tax rate from 35% to 21% as compareda result of the Tax Act.2016the income tax provision: 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: 2.1 % 2.6 % 22.8 % 2.4 % (15.9 )% (13.0 )% 56.4 % (12.9 )% Tax credits (0.5 )% (0.5 )% 1.9 % (1.1 )% (4.2 )% (2.9 )% 7.7 % (2.5 )% Effective tax rate 2.5 % 21.2 % 109.8 % 20.9 % the impact of audit settlements during the nine months ended September 30, 2016 with no similar settlements during2017) and the same2017 GRC decision (impacting the three and nine months ended September 30, 2018), and by the 2015 GT&S decision (impacting the three and nine months ended September 30, 2017, and 2018, respectively). All amounts are impacted by the level of income before income taxes. The 2014 GRC, 2017 GRC, and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. The amounts for the three and nine months ended September 30, 2018 also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.Statements.Statements in Item 1.) (1) Average cost of purchased power was impacted primarily by lower Utility electric customer demand due to their departure to CCAs or direct access providers and a larger percentage of higher cost renewable energy resources being allocated to the fewer remaining Utility electric customers. See further discussion in MD&A, “Regulatory Matters - Power Charge Indifference Adjustment OIR”, below. (2) The decrease in purchased power for the three and nine months ended September 30, 2017 compared to the same periods in 2016 was primarily due to lower Utility electric customer demand and an increase in generation from hydroelectric facilities. regulatory requirements to procure certain types of energy, and the cost-effectiveness of each source of electricity. 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 $ 0.252 $ 0.151 $ 0.157 $ 0.126 4,658 9,189 18,101 25,905 Statements.Statements in Item 1.) The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand. 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 $ 1.55 $ 1.85 $ 2.25 $ 2.71 Total natural gas sold (in millions of Mcf) 29 27 158 161 (2) The increase in natural gas sold for the nine months ended September 30, 2017, compared to the same period in 2016, was primarily due to cooler temperatures and resulted in additional customer heating demand.alsothat did not impact earnings include certain recoverable costs that the Utility incursis authorized to recover as part of its operationsincurred such as pension contributions and public purpose programs costs. If the Utility were to spend overmore than authorized amounts, these expenses could have an impact onto earnings. dividend payments, and issuances and repayments under its revolving credit facility and commercial paper program. PG&E Corporation relies on short-term debt, including commercial paper, to fund temporary financing needs. equity contributionsand the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters, including the outcome of the uncertainties and potential liabilities associated with the Northern California wildfires. Credit rating downgrades may increase the cost and availability of short-term borrowing, including commercial paper, the costs associated with credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility are funded primarily through common stock issuances.Utility’s credit rating from each of the major credit rating agencies. During 2018, PG&E Corporation forecasts thatCorporation's and the Utility's credit ratings were subject to multiple downgrades by Fitch Ratings, S&P Global Ratings, and Moody’s Investors Service, Inc. At September 30, 2018, PG&E Corporation’s and the Utility’s credit ratings remained at investment grade levels. If S&P Global Ratings and Moody's Investors Service, Inc. downgraded the Utility below investment grade, the Utility estimates it will have issued between $400 million and $500would be required to fully collateralize up to $800 million in common stock bynet liability positions. (See Note 7 and Note 9 of the end of 2017, primarily to fund equity contributionsNotes to the Utility.Condensed Consolidated Financial Statements in Item 1.) outcomeamount of unrecoverable pipeline-related expenses,disallowed capital expenditures, and by fines, penalties and claims that may be imposed in connection with the matters described in “EnforcementNote 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1, “Part II. Other Information, Item 1. Legal Proceedings,” and Litigation Matters” below.in the 2017 Form 10-K. In addition, PG&E Corporation’s and the Utility’s equity needs could be materially increased and its liquidity and cash flows materially adversely affected by potential costs and other liabilities in connection with the Northern California wildfires. PG&E Corporation’s and the Utility’s ability to access the capital markets in a manner consistent with its past practices, if at all, could be adversely affected by such matters. (See Item“Item 1A. Risk FactorsFactors” in thisthe 2017 Form 10-Q.10-K and in Part II below under “Item 1A. Risk Factors”.)PG&E Corporation amended its February 2015 EDA providingequity distribution agreement for the salenine months ended September 30, 2018. As of PG&E Corporation common stock having an aggregate gross price of up to $275September 30, 2018, the remaining amount available under this agreement was $246.3 million.2017,2018, PG&E Corporation sold 0.4issued 3.6 million shares of its common stock under the February 2017 EDA for cash proceeds of $28.4$136.7 million net of commissions paid of $0.2 million. There were no issuances under the February 2017 EDA for the three months ended September 30, 2017. As of September 30, 2017, the remaining gross sales available under this agreement were $246.3 million.PG&E Corporation also issued common stock under the PG&E Corporation 401(k) plan the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the nine months ended September 30, 2017, 6.4 million shares were issued for cash proceeds of $316 million under these plans.purposes, includingpurposes.contributionfirst quarter of equity to the Utility. For the nine months ended September 30, 2017, PG&E Corporation made equity contributions to2018, the Utility satisfied and discharged its remaining obligation of $405 million.2017,2018, the Utility’s $250 million floating rate unsecured term loan, issued in March 2016,February 2017, matured and was repaid. Additionally, in February 2017,2018, the Utility entered into a $250 million floating rate unsecured term loan that matureswill mature on February 22, 2018. In March 2017, the Utility issued $400 million principal amount of 3.30% Senior Notes due March 15, 2027 and $200 million principal amount of 4.00% Senior Notes due December 1, 2046.2019. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.Pollution Control BondsJune 2017,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 Utility repurchased and retired $345terms 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 pollution control2.40% Senior Notes due March 1, 2019. On April 26, 2018, PG&E Corporation completed the early redemption of these bonds, Series 2004 A through D. Additionally, in June 2017,which satisfied and discharged its remaining obligation of $350 million.remarketed three seriesissued $500 million principal amount of pollution control bonds, previously held in treasury, totaling $1454.25% senior notes due August 1, 2023 and $300 million in principal amount. Series 2008 Famount 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 $250 million term loan maturing on February 22, 2019 and 2010 E bear interest at 1.75% per annum and mature on November 1, 2026. Series 2008 G bears interest at 1.05% per annum and matures on December 1, 2018.In May 2017, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2021 to April 27, 2022. 2017,2018, PG&E Corporation and the Utility had $300 million and $2.6$2.9 billion available under their respective $300 million and $3.0 billion revolving credit facilities. During the quarter ended September 30, 2018, PG&E Corporation and the Utility repaid in full borrowings under their respective revolving credit facilities of $50 million and $650 million, respectively. At September 30, 2018, PG&E Corporation and the Utility did not have any borrowings outstanding under their respective revolving credit facilities. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements.Statements in Item 1.)are permitted under the terms of its facilities tocan issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, respectively. For the nine months ended September 30, 2017,2018, PG&E Corporation and the Utility had an average outstanding commercial paper balance of $70$39 million and $552$11 million, respectively, and a maximum outstanding balance of $161$137 million and $1.1 billion,$205 million, respectively. At September 30, 2017,2018, PG&E Corporation and the Utility had an outstanding commercial paper balance of $369 million and PG&E Corporation did not have any outstanding commercial paper outstanding.2017,2018, PG&E Corporation’s and the Utility’s total consolidated debt to total consolidated capitalization was 49%49.9% and 48%49%, respectively. PG&E Corporation’s revolving credit facility agreement also requires that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility. In addition, the revolving credit facilities include usual and customary provisions regarding events of default and covenants including covenants limiting liens to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, and imposing conditions on the sale of all or substantially all of PG&E Corporation’s and the Utility’s assets and other fundamental changes. At September 30, 2017,2018, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.In MayBoardBoards of Directors of PG&E Corporation approved a new annualand the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, cash dividendbeginning the fourth quarter of $2.12 per share ($0.53 per share quarterly), an increase from2017, as well as the previous annual cash dividendUtility’s preferred stock, beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of $1.96 per share ($0.49 per share quarterly), and potential liabilities associated with the Board of DirectorsNorthern California wildfires. (See Note 9 of the Utility approved a new annual common stock cash dividend of $1.08 billion ($270 million quarterly), an increase fromNotes to the previous annual cash dividend of $976 million ($244 million quarterly).In September 2017, the Board of Directors of PG&E Corporation declared quarterly dividends of $0.53 per share, totaling $272 million, of which approximately $267 million was paid on October 15, 2017, to shareholders of record on September 29, 2017. Additionally,Condensed Consolidated Financial Statements in September 2017, the Board of Directors of the Utility declared a common stock dividend of $270 million that was paid to PG&E Corporation on September 21, 2017 and declared dividends on its outstanding series of preferred stock, payable on November 15, 2017, to shareholders of record on October 31, 2017. 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 ) These items fluctuate within the normal course of business due to the timing and amount of customer billings and collections and vendor billings and payments.2017,2018, net cash provided by operating activities increaseddecreased by $1.5 billion$508 million compared to the same period in 2016.2017. This increasedecrease was primarily due to additional electric and natural gas operating revenues collected as authorized by the CPUC in the 2015 GT&S rate case and by the FERC in the TO rate case and the $400 million refund to natural gas customers in the second quarter of 2016, as required by the San Bruno Penalty Decision, with no corresponding activity in 2017. The remaining increase was primarily due to fluctuations in activities within the normal course of business such as the timing and amount of customer billings and collections and vendor billings and payments.including costs in connection with restoration(and the timing and amount of service to customers and repairs of the Utility’s facilities,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 current and future enforcement, litigation, and regulatory matters including the impact(see "Enforcement and Litigation Matters" in Note 9 of the Butte fireNotes to the Condensed Consolidated Financial Statements in Item 1 and Part II, Item 1. Legal Proceedings for more information);recoveries, the safety culture OII, including other ratemaking tools that could be imposed by the CPUC as a result(see “Wildfire Insurance” in Note 9 of the phase two of the proceeding, the ex parte OII and the related proposed decision, costs associated with potential recommendations that the third-party monitor may make relatedNotes to the Utility’s convictionCondensed Consolidated Financial Statements in Item 1 for more information);criminal trial,tax payments and potential penaltiesreduce revenue requirements, resulting in connection with the Utility’s safetylower operating cash flows (see “Overview” above and other self-reports;“Regulatory Matters” below for more information);TO19TO20 rate cases, 2018 CEMA filing, and other ratemaking and regulatory proceedings;the Utility incurs, but does not recover, associatedin connection with its electricfire hazard prevention work (see "Overview" above and natural gas systems, including amounts related to cancelled projects"Regulatory Matters" below for more information); and relicensing;the timing and amount of tax payments (including the bonus depreciation), tax refunds, net collateral payments, and interest payments, as well as changes in tax regulations that could be adopted by Congress as a result of the new federal administration and other proposals; andDuring2017, net cash used in investing activities decreased by $133 million2018 as compared to the same period in 2016.2017 primarily due to an increase in capital expenditures. The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.$5.7$6.5 billion in capital expenditures in 2017, $6.32018, and $6.4 billion in 2018 and $6.0 billion 2019.decreasedincreased by $1.6$1.1 billion from $851 million forduring the nine months ended September 30, 20162018 as compared to $743 millionthe same period in 2017. This increase was primarily due to the suspension of dividend payments (see “Dividends” section above) and a reduction in net cash used in financing activities for the nine months ended September 30, 2017. repayments of commercial paper of approximately $600 million.and subsequent events described in Note 10 of the Notes to the Condensed Consolidated Financial Statements.Statements in Item 1. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s future financial results. condition, results of operations, and cash flows. In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the 20162017 Form 10-K and “Part II. Other Information, Item 1. Legal Proceedings.”Department of Interior InquiryIn September 2015, the Utility was notified that the DOI had initiated an inquiry into whether the Utility should be suspended or debarred from entering into federal procurement and non-procurement contracts and programs citing the San Bruno explosion and indicating, as the basis for the inquiry, alleged poor record-keeping, poor identification and evaluation of threats to gas lines and obstruction of the National Transportation Safety Board’s investigation. The Utility filed its initial response on November 2, 2015, to demonstrate that it is a “presently responsible” contractor under federal procurement regulations and that it believes suspension or debarment is not appropriate. On December 21, 2016, the Utility and the DOI entered into an interim administrative agreement that reflects the DOI’s determination that the Utility remains eligible to contract with federal government agencies while the DOI determines whether any further action is necessary to protect the federal government’s business interests. On May 8, 2017, DOI sent a series of follow-up questions to the Utility seeking clarification regarding gas operational matters, the Utility’s risk assessment process, and the Utility’s compliance and ethics framework. The Utility responded to the questions on August 18, 2017. DOI also has indicated that before making any final determination in its debarment inquiry it will meet in person with Utility executives to discuss the Utility’s compliance and ethics programs. That meeting has not yet been scheduled. The Utility could incur material costs, not recoverable through rates, to implement any remedial and other measures that could be imposed, the amount of which the Utility is currently unable to estimate.For more information, see PG&E Corporation’s and the Utility’s 2016 Form 10-K.SignificantThe resolutions of the proceedings described below and other proceedings may affect PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows. Discussed below are significant regulatory developments that have occurred since filing the 20162017 Form 10-K was filed with the SEC are discussed below.the ORA,Cal PA, TURN, and 12 other intervening parties jointly submitted to the CPUC on August 3, 2016 (the “settlement agreement”). Modifications from2016. Consistent with the amounts proposed in the settlement agreement, to the final decision included a tax memorandum account and approval of a stand-alone application with the CPUC or a filing in the CPUC’s ongoing residential rate reform proceeding to recover customer outreach and other costs incurred as a result of residential rate reform implementation. The new tax memorandum account will track any revenue differences resulting from changes in income tax expense caused by net revenue changes, mandatory or elective tax law changes, tax accounting changes, tax procedural changes, or tax policy changes during the 2017 through 2019 GRC period. The account will remain open and the balance in the account will be reviewed in every subsequent GRC proceeding until a CPUC decision closes the account.The final decision approved a revenue requirement increase of $88 million for 2017, with additional increases of $444 million in 2018 and $361 million in 2019,2019.line withresponse to the amounts proposed in the settlement agreement. The following table shows the revenue requirement amounts approved in the final decision based on line of business and cost category as well as the differences between the 2016 authorized revenue requirements and the amounts approved in the final decision:(1) Amounts approved in the final decision are the same as the amounts that were proposed in the settlement agreement.As required by the final decision, the Utility has submitted a variety of compliance filings, including a filing on June 12, 2017, which provides an accounting for the January 2017Utility's $300 million expense reduction announcement in January 2017.on July 10, 2017, providing$296 million for 2018 and 2019 respectively, and increase rate base by $199 million and $425 million for 2018 and 2019, respectively. The Utility cannot predict the timing and outcome of this PFM.SmartMeter™SmartMeterTM Upgrade project.project to the CPUC on July 10, 2017. On August 9, 2018, the CPUC extended the statutory deadline for the 2017 GRC to February 9, 2019, in order to allow for comments and CPUC action on any PD on the SmartMeterTM upgrade cost effectiveness study. The Utility is unable tocannot predict what, ifthe timing and outcome of any actionsCPUC action in connection with this study and its impact on the CPUC will take regarding these submissions.PG&E Corporation’sthe 2017 Form 10-K.2016 Form 10-K2020 GRC.its subsequent quarterly reports on Form 10-Q.During 2016, the CPUC issuedphase one and phase two of the Utility’s 2015 GT&S rate case. The phase one decision adopted the revenue requirements that the Utility is authorized to collect through rates beginning August 1, 2016, to recover its costs of gas transmission and storage services for theUtility's 2015 GT&S rate case, period (2015 through 2018). The phase two decision determined the allocation of the $850 million penalty assessed in the San Bruno Penalty Decision and the revenue requirement reduction for the five-month delay caused by the Utility’s violation of the CPUC ex parte communication rules in this proceeding. The phase one decision excluded from rate base $696 million of capital spending in 2011 through 20142014. This was the amount recorded in excess of the amount adopted.adopted in the 2011 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. A draft of the audit report is expectedThe Utility would be required to take a charge in the first quarterfuture if the CPUC’s audit of 2018.2011 through 2014 capital spending resulted in additional permanent disallowance. The audit is still in process. The decision also established new one-way balancing accounts to track certain costs, as well as various cost caps that will increase the risk of overspenddisallowance over the current rate case cycle including new one-way balancing accounts. Additional charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending.The final phase two decision adopted total weighted average rate base of $2.8 billion in 2015, $2.8 billion in 2016, $3.0 billion in 2017, and $3.5 billion in 2018. The final phase two decision reduced rate base by the full amount of the disallowed capital expenditures but did not remove the associated deferred taxes, which the Utility believes constitutes a normalization violation. In the final decision, the CPUC authorized the Utility to establish a Tax Normalization Memorandum Account to track relevant costs and clarified that it is the CPUC’s intention that the Utility comply with normalization rules and avoid the potential adverse consequences of a normalization violation. The CPUC allowed the Utility to seek a ruling from the IRS and the Utility filed the ruling request with the IRS on April 10, 2017. On October 5, 2017, the IRS issued a private letter ruling indicating the final phase two decision rate base reduction was inconsistent with the IRS tax normalization requirements. cycle.IRSTax Act, on March 30, 2018, the Utility submitted to the CPUC a PFM of the CPUC's final decision in the 2015 GT&S rate case proposing to reduce revenue requirements by $58 million and increase rate base by $12 million for 2018 (excluding the impacts of an approximately $7 million increase in revenue requirement and a $60 million increase in rate base associated with the Utility's private letter ruling the Utility will file an advice letter withapproved by the CPUC inon July 18, 2018). The Utility cannot predict the fourth quartertiming and outcome of 2017, requesting a rate base adjustment of $7 million, $28 million, $49 million, and $61 million, in 2015, 2016, 2017, and 2018, respectively.ORACal PA and Indicated Shippers filed applications for rehearing of the phase one and phase twoCPUC decisions respectively.in the Utility's 2015 GT&S rate case. The Utility cannot predict when or ifwhether the CPUC will grant the rehearingsapplications for rehearing or if it will adopt the parties’ recommendations. Additionally, in Junea PFM ofits 2019 GT&S rate case application with the phase one decision to eliminateCPUC for the requirement thatyears 2019 through 2021. While the Utility install new CP systemshas not formally proposed a fourth year for this rate case, it provided a revenue requirement and rates for 2022, in the event the CPUC adopts an additional year. On October 1, 2018, because the Utility is not inentered into a position to identifystipulation with Cal PA that, if approved, would extend the optimal location for such new systems in 2018. Instead,rate case cycle through 2022 as recommended by Cal PA.be allowedrecover anticipated costs of providing natural gas transmission and storage services beginning on January 1, 2019. This corresponds to continue its current CP program. As directedan increase of $289 million over the Utility’s 2018 authorized revenue requirement of $1.30 billion. The Utility’s request also includes proposed revenue requirements of $1.73 billion for 2020, $1.91 billion for 2021, and $1.91 billion for 2022 if the CPUC orders a fourth year for the rate case period.on August 23, 2017,related to 2011 through 2014 expenditures in excess of amounts adopted in the Utility provided supplemental information to the CPUC regarding the PFM.2011 GT&S rate case. The Utility is unable to predict if and whenwhether the $576 million, or a portion thereof, will ultimately be authorized by the CPUC would adoptand included in the PFM. InUtility’s future rate base. The Utility’s request also excludes rate base adjustments that the eventUtility requested with the PFMCPUC on November 14, 2017, resulting from the Internal Revenue Service’s October 5, 2017 private letter ruling issued in connection with the CPUC’s final phase two decision in the 2015 GT&S rate case. The Utility’s request is not adoptedbased on capital expenditure forecasts of $971 million for 2019, $963 million for 2020, and $804 million for 2021 (which exclude common capital allocations).Utility fails to performCPUC.mandated new CP systems,Tax Act, on March 30, 2018, the Utility couldsubmitted updated testimony to the CPUC. The updated testimony, including the private letter ruling advice letter, reduces the Utility's previously forecasted revenue requirement by $25 million for 2019, $30 million for 2020, $22 million for 2021, and $5 million for 2022, and increases rate base by $188 million for 2019, $254 million for 2020, $378 million for 2021, and $469 million for 2022.finesa refund obligation of $1 million and penalties,$8.5 million for TO16 and TO17, respectively. Alternatively, if FERC again concludes that the amount of whichUtility should receive the 50 basis point ROE incentive adder and provides the additional explanation that the Ninth Circuit found the FERC’s prior decisions lacked, then the Utility would not owe any refunds for this issue for TO16 or TO17.predict. Withpredict the additiontiming and outcome of a third attrition year, the Utility’s next GT&S cycle will begin in 2019. The Utility is required to file its 2019 GT&S rate case in 2017. The Utility plans to file its 2019 GT&S rate case with the CPUC in the fourth quarter of 2017.For more information, see PG&E Corporation’s and the Utility’s 2016 Form 10-K and its subsequent quarterly reports on Form 10-Q.Transmission Owner Rate Casesaits TO18 rate case (the “TO18 rate case”) at the FERC requesting a 2017 retail electric transmission revenue requirement of $1.718$1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.331$1.33 billion. The forecasted network transmission rate base for 2017 iswas $6.7 billion. The Utility is also seeking a return on equity of 10.9%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted that it willwould make investments of $1.296$1.30 billion in 2017 in various capital projects. chief judge issued an order terminating the settlement procedures due to an impasse in the settlement negotiations reported by the parties. On August 22, 2017,During the hearings held in January 2018, the Utility, intervenors, and the FERC trial staff, submitted testimony. The table below summarizesaddressed questions relating to return on equity, capital structure, depreciation rates, capital additions, rate base, operating and maintenance expense, administrative and general expense, and the differences betweenallocation of common, general and intangible costs.amountALJ issued an initial decision in the TO18 rate case proposing an ROE of revenue requirement increases included in9.13% compared to the Utility’s request of 10.90%, and an estimated composite depreciation rate of 2.96% compared to the testimony submitted byUtility’s request of 3.25%. The ALJ also rejected the Utility's method of allocating common plant between CPUC and FERC trial staff:Additionally,jurisdiction. In addition, the ALJ proposed to reduce forecasted capital and expense spending to actual costs incurred for the rate case period. Further, the ALJ proposed to remove certain items from the Utility's rate base and revenue requirement. The Utility and intervenors provided testimony on July 5, 2017 and the Utility submitted rebuttal testimonyfiled initial briefs on October 9, 2017. Hearings are scheduled31, 2018, in response to take place starting January 9, 2018, with an initialthe ALJ's recommendations. The Utility expects FERC to issue a final decision expected on or before June 1, 2018.Also,in mid-2019.several of the parties that had already intervenedintervenors in the TO18 rate case filed a complaint at the FERC and requestedalleging that the complaint be consolidated withUtility failed to justify its proposed rate increase in the TO18 rate case. The complaint asserts that the Utility’s revenue requirement request in TO18 is unreasonably high and should be reduced. The complaint asks that, if the outcome of the litigation in TO18 is that the Utility’s revenue requirement should be set at a lower level than the settled revenue requirement from the TO17 settlement, thatOn November 16, 2017, the FERC order refunds to that lower level determined in TO18 litigation.dismissed the complaint. On April 20,December 18, 2017, the Utility answered the complaint, requestingcomplainants filed a request for a rehearing of that FERC dismiss it. The Utility is unable to predict when and howorder, which the FERC will respond to the complaint.denied on May 17, 2018.aits TO19 rate case (the “TO19 rate case”) at the FERC requesting a 2018 retail electric transmission revenue requirement of $1.792$1.79 billion, a $74 million increase over the proposed 2017 revenue requirement of $1.718$1.72 billion. The forecasted network transmission rate base for 2018 is $6.9 billion. The Utility is also seeking an ROE of 10.75%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted capital expenditures of approximately $1.4 billion. On September 28, 2017, the FERC issued an order accepting the Utility’s July 2017 filing, subject to hearing and refund, and established March 1, 2018, as the effective date for rate changes. FERC also ordered that the hearings will be held in abeyance pending settlement discussion among the parties.several of the parties that have intervenedintervenors in the TO18TO19 rate case filed a complaint at the FERC and requestedalleging that the complaint be consolidated withUtility failed to justify its proposed rate increase in the TO19 rate case. The TO19 complaint asserts that the Utility’s revenue requirement request in TO19 is unreasonably high and should be reduced. The complaint asks that, if the outcome of the litigation in TO18 is that the Utility’s revenue requirement should be set at a lower level than the settled revenue requirement approved by FERC in TO17, FERC order refunds to that lower level determined in the TO18 litigation. On October 17, 2017, the Utility answeredrequested that the FERC dismiss the complaint. On May 17, 2018, the FERC issued an order setting the complaint requesting that FERC dismiss it. The Utility is unable to predict whenfor hearing, settlement judge procedures, and howconsolidation with the FERC will respond to the complaint.For more information, see PG&E Corporation’s and the Utility’s 2016 Form 10-K and its subsequent quarterly reports on Form 10-Q.Cost of CapitalOn July 13, 2017, the CPUC issued a final decision adopting, with no modifications, the PFM filed in February 2017 by San Diego Gas & Electric Company, Southern California Gas Company, Southern California Edison, the ORA, TURN, and the Utility.The final decision extends the Utility’s next cost of capital application filing deadline by two years to April 22, 2019, for the year 2020. The final decision also reduces the Utility’s authorized ROE from 10.40% to 10.25%, effective January 1, 2018, and resets the Utility’s authorized cost of long-term debt and preferred stock effective January 1, 2018. In addition, the decision suspends the cost of capital adjustment mechanism to adjust cost of capital for 2018, but allows the adjustment mechanism to operate for 2019 if triggered. The Utility’s current capital structure of 52% common equity, 47% long-term debt, and 1% preferred equity remains unchanged.The final decision also leaves the proceeding open to facilitate gathering of information to inform the next cost of capital proceeding, as well as to provide a possible venue in which to consider whether the Utility’s ROE should be reduced until any recommendations that the CPUC may adopt in the second phase of its safety culture investigation are implemented, as described in the assigned Commissioner’s May 8, 2017 Scoping Memo and Ruling issued in the Safety Culture OII.29, 2017,21, 2018, the Utility submittedfiled an advice letter to the CPUC, updating its cost of capital and the estimated revenue requirement impactsall-party settlement with an effective date of January 1, 2018. The long-term debt cost reset reflects actual embedded costs asFERC in connection with TO19. As part of the end of August 2017 and forecasted interest rates for settlement,new long-term debt expected to be issued for the remainder of 2017 and all of 2018. The Utility estimates that its annualTO19 revenue requirement will be reduced byset at 98.85% of the revenue requirement for TO18 that will be determined in the TO18 final decision. Additionally, if FERC determines that the Utility is not entitled to the 50 basis point incentive adder for the Utility's continued CAISO participation, than the Utility would be obligated to make a refund to customers of approximately $120 million, beginning$25 million.This estimate is basedThe Utility has requested that FERC approve a 12.5% return on equity (which includes an incentive component of 50 basis points for the Utility's continuing participation in the CAISO), an increase from the 10.75% (also including a 50 basis point CAISO incentive adder) requested in its TO19 rate case.updated costeffective date through the end of capital in2019.September 29, 2017 advice lettertiming and current rate base. In the fourth quarteroutcome of 2017, the Utility’s final advice letters for authorized 2018 revenue requirements will be filed using the cost of capital authorized pursuant to the September 29, 2017 advice letter. Changes in market interest rates may have material effects on the costFERC’s response. Following FERC’s acceptance of the Utility’s future financings, but will not affectformula rate request, the authorized costUtility expects to file an annual update to its TO tariff on or before December 1 of capitaleach year beginning in 2018.For more information, see PG&E Corporation’s2019, for rates and charges to become effective January 1 of the Utility’s 2016 Form 10-K and its subsequent quarterly reports on Form 10-Q.Responsibility. PG&E subsequently modified its testimonyResponsibility (together, the “Joint Parties”).moveretire Diablo Canyon Unit 1 by 2024 and Unit 2 by 2025. The CPUC also:two tranches of post-2025 replacement procurementresources to the CPUC’s Integrated Resource Plan proceeding.Planning proceeding;More than 40 parties have submitted responses and protests torejected rate recovery of the Utility’s application. Rebuttal testimony and commentsproposed $85 million for the community impacts mitigation program on the community impact mitigationgrounds that rate recovery for such a program settlement agreement were submitted to the CPUC on March 17, 2017. Evidentiary hearings took place in April 2017. Certain intervenors argued that a portion of or the entire community impact mitigation program and employee retention plan be funded by shareholders. On May 23, 2017, the Utility filed a settlement agreement that was reached with the parties listed above as well as TURN, ORA, and San Luis Obispo Mothers for Peace, related to therequires legislative authorization; of license renewal costs and cancelled project costs. The settlement agreement would allow for recovery from customers of $18.6 million of the total Diablo Canyon license renewal project cost of $53 million evenly over an 8-year period beginning January 1, 2018. Related toand rate recovery of cancelled project costs the settlement agreement would allow for recovery from customers ofequal to 100% of the direct costs incurred prior to June 30, 2016, and 25% recovery of direct costs incurred after June 30, 2016. On June 22, 2017, the Green Power Institute filed comments2016, based on thea settlement agreement recommendingamong the Utility, the Joint Parties, and certain other parties that only $9.3 millionthe Utility filed with the CPUC in May 2017; andproject costs be recovered from customers. Duringapplication. On April 16, 2018, the nine months ended September 30, 2017,NRC granted the Utility incurred charges of $47 million relatedUtility’s request to the settlement agreement, of which $24 million is for cancelled projects and $23 million is for disallowed license renewal costs.Opening and reply briefs were filed on May 26, 2017, and June 16, 2017, respectively, in which no new issues were raised. On September 14, 2017, the CPUC hosted two public participation hearings in San Luis Obispo, California. Final oral arguments are scheduled to take place on November 28, 2017. The Utility expects that a final decision will be issued by the end of 2017. Upon CPUC approval of the application and such approval becoming final and non-appealable, the Utility will withdraw its license renewal application currently pending before the NRC. PG&E Corporation and the Utility are unableapplication.predict whetherSB 1090, the CPUC will approveissued a proposed decision addressing the application.willintends to submit a future lease extension request to address the period of time required for plant decommissioning, which under NRC regulations can take as long as 60 years. On August 28, 2016, the World Business Academy filed a writ in the Los Angeles Superior Court asserting that the State Lands Commission committed legal error when it determined that the short termshort-term lease extension for an existing facility was exempt from review under the California Environmental Quality Act, andas well as alleging that the State Lands Commission should be required to perform an environmental review of the new lands lease. The trial took place onOn July 11, 2017, in Los Angeles Superior Court, and the judge dismissed the petition on all grounds, ruling that the State Lands Commission properly determined the short termshort-term lease extension was subject to the existing facilities exemption under the California Environmental Quality Act. The World Business Academy had 60 days from entry of judgement to appeal the decision toappealed this decision. On June 13, 2018, the California Court of Appeals.On May 25, 2017,Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the CPUC issued aUtility expects will continue until those costs are fully recovered.adopting a nuclear decommissioning cost estimate of $1.1 billion for Humboldt Bay, correspondingforecast and to submit the study, along with the NDCTP application, to the Utility’s request, and $2.4 billion for Diablo Canyon, compared to the Utility’s request of $3.8 billion, or 64 percent of its request. On an aggregate basis, the final decision adopted a $3.5 billion total nuclear decommissioning cost estimate, compared to $4.8 billion requestedCPUC by the Utility. Compared to the Utility’s estimated cost to decommission Diablo Canyon, the final decision adopts assumptions which lower costs for large component removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility can seek recoveryend of these costs in the 2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ARO on the Condensed Consolidated Balance Sheets related to the assumed length of the wet cooling period of spent nuclear fuel after plant shut-down. The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Condensed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $3.4 billion at September 30, 2017, and $3.5 billion at December 31, 2016. These estimates are based on decommissioning cost studies, prepared in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets.As of September 30, 2017, the nuclear decommissioning trust accounts’ total fair value was $3.2 billion. Changes in the estimated costs, the timing of decommissioning or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission.late 2018 or early 2019.PG&E Corporation’s and"Asset Retirement Obligations" in Note 2 of the Utility’s 2016Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K and its subsequent quarterly reports on Form 10-Q.Application to Establish a 10-K.July 26, 2017, the Utility filed an application withJune 21, 2018, the CPUC requestingissued a decision granting the Utility’s request to establish a WEMA to track wildfire expenses and to preserve the opportunity for the Utility to request recoverypurpose of tracking specific incremental wildfire liability costs in excess of insurance at a future date. Concurrently with this application, the Utility also submitted a motion to the CPUC requesting that the WEMA be deemed effective as of July 26, 2017, such that2017. In the WEMA, the Utility may begin recording costs to the account while the application is pending before the CPUC. Under the WEMA as proposed, the Utility wouldcan record incremental costs related to wildfire,wildfires, including: (1) payments to satisfy wildfire claims, including any deductibles, co-insurance and other insurance expense paid by the Utility but excluding costs that have already been authorizedforecasted and adopted in the Utility’s GRC; (2) outside legal costs incurred in the defense of wildfire claims; (3) insurance premium costs not in rates; and (4) the cost of financing these amounts. Insurance proceeds, as well as any payments received from third parties, wouldor through FERC authorized rates, will be credited to the WEMA as they are received. The WEMA wouldwill not include the Utility’s costs for fire response and infrastructure costs which are tracked in the CEMA. The decision does not grant the Utility rate recovery of any wildfire related costs. Any such rate recovery would be requiredrequire CPUC authorization in a separate proceeding. (See Notes 3 and 9 of the Notes to file an application to seek approvalthe Condensed Consolidated Financial Statements in Item 1.)WEMA. Thethe CEMA. While the Utility believes such costs are recoverable through CEMA, its CEMA applications are subject to CPUC has setapproval.prehearing conference on this matter for December 8, 2017. The Utility cannot predict the outcome of this proceeding.Gas and Electric Safety Citation ProgramThe SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicablerequest to the safetyCPUC to authorize recovery under the CEMA tariff for a revenue requirement increase of the California utilities’ electricapproximately $146 million for recorded capital and natural gas facilities and operations. The CPUC has delegated authorityexpense costs related to the SED to issue citations2015 drought mitigations and impose penaltiesemergency response activities for violations identifieddeclared disasters that occurred from December 2012 through audits, investigations, or self-reports. Under both the gas and electric programs, the SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day.September 29, 2016, the CPUC issued a final decision adopting improvements and refinements to its gas and electric safety citation programs. Specifically, the final decision refines the criteria for the SED to use in determining whether to issue a citationJanuary 4, 2018, Cal PA, TURN, and the amount of penalty, setsUtility filed an administrative limit of $8 million per citation issued, makes self-reporting voluntary in both gas and electric programs, adopts detailed criteria for the utilities to use to voluntarily self-report a potential violation, and refines other issues in the programs. The decision also merges the rules applicable to its gas and electric safety citation programs into a single set of rules that replace the previous safety citation programs and adopts non-substantive changes to these programs so that the programs can be similar in structure and process where appropriate.On February 21, 2017, California State Senator Jerry Hill filed a petition for modification of the CPUC’s September 29, 2016 decision regarding the safety citation program. The petition for modification requests that the decision be modified to reinstate mandatory self-reporting for gas safety potential violations and require gas utilities to notify local governments within 30 days when a self-report is submitted to SED. Under the request, electric utilities would keep the voluntary self-reporting regime and would not be required to notify local governments, but the CPUC has discretion to direct notification within ten days on a case-by-case basis. The CPUC’s Office of Safety Advocates filed a response suggesting additional potential modification to the gas and electric safety citation programs. The Utility cannot predict when or how the CPUC will act on the petition of modification. Other Regulatory Proceedings and InitiativesPower Charge Indifference Adjustment OIROn April 25, 2017, the Utility, along with Southern California Edison Company and San Diego Gas & Electric Company, filed a joint applicationall-party motion with the CPUC on howseeking approval of an all-party settlement agreement. The settlement agreement proposed that the Utility’s total CEMA revenue requirement request be reduced by $29 million, from $146 million to allocate costs associated with long-term power commitments in a manner that ensures all customers are treated equally. At issue is how customers within communities that choose to implement CCA power arrangements and those served under direct access pay for their share of$117 million. On June 21, 2018, the costs. The utilities believe that these customers are not paying their full share of costs associated withCPUC approved the long-term commitments, which results in other customers paying more, which is inconsistent with state law. The Utility is committed to helping create a cost allocation method that treats all customers fairly and equally, whether they continue to receive service fromsettlement agreement authorizing the Utility or choose a CCA or direct access provider. The Utility projects that approximately 50 percent ofto recover $117 million in connection with its customers will purchase electricity from a CCA or direct access provider by 2020. Without changes to the current cost allocation system, a portion of the contract and facilities costs will be shifted to customers who remain with2016 CEMA application.or live in areas that do not have access to alternative electricity providers. The utilities’ joint proposed approach would replace the current system, which is known as the PCIA, with an updated system known as the Portfolio Allocation Methodology.On June 29, 2017, the CPUC dismissed the Utility’s joint Portfolio Allocation Methodology application without prejudice and instead approved an OIR to review, revise, and consider alternatives to the PCIA. The OIR will focus on PCIA within the larger context of consumer choice in energy services, and should not be considered a follow-upsubmitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and Energy Commission Joint En Bancstorm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. Also, the 2018 CEMA application originally sought cost recovery of $555 million on Customer Choicea forecast basis, subject to true-up if actual costs were greater or less than the forecast, for additional tree mortality and fire risk mitigation work anticipated in California.2018 and 2019. On SeptemberOctober 12, 2018, the Utility notified the CPUC and other parties that $180 million of the forecasted 2018 and 2019 fire risk mitigation costs would be removed fromruling establishingprocedural schedule. As directed in the scoping memo, opening and reply briefs on the Utility's request related to recovery of costs on a procedural schedule and a new overall goal to mitigate cost increases for both bundled and departing load customers. Testimony is scheduled for the first quarter of 2018. Evidentiary hearings are scheduled for the second quarter offorecast basis were filed on August 31, 2018, and a proposed decision is expected bySeptember 14, 2018, respectively. On November 2, 2018, the third quarter of 2018.Customer ChoiceOn May 19, 2017, California energy companies, along with other stakeholders discussed customer choiceassigned ALJ denied the Utility's request for interim rate relief.future of California’s electric industry at a CPUC “en banc” meeting. Specifically, the goal of the meeting was to frame a discussion on the trends thatUtility are driving change within California’s electricity sector and overall clean-energy economy and to lay out elements of a path forward to ensure that California achieves its reliability, affordability, equity, and carbon reduction imperatives while recognizing the important role that technology and customer preferences will play in shaping this future. On October 11, 2017, the CPUC announced the formation of the California Customer Choice Project to examine the issues and produce a report evaluating regulatory framework options in early 2018. The Commission held an informal public workshop on October 31, 2017, to gather stakeholder input on global and national electric market choice models, including California’s 2020 market. The project will produce a white paper that will provide a framework to evaluate customer choice models. The white paper will not present a recommendation nor is it intended to provide the basis for instituting a rulemaking. The white paper is expected in early 2018 with a final version expected by the second quarter of 2018. While the CPUC had indicated intent to open an OIR related to customer choice, the Utility is unable to predict ifthe timing and whenoutcome of this proceeding.may open an OIR.DRPelectric distribution resources plan for approval by the CPUC. The Utility’s plan identifies optimal locations on its electric distribution system for deployment of DERs. The Utility’s proposal is designed to allow energy technologies to be integrated into the larger grid while continuing to provide customers with safe, reliable, and affordable electric service. On February 27, 2017, theruling that seeksdecision on February 15, 2018, requiring the development of a process for incorporating DER forecasts into the DRP that takes into consideration the coordination with other statewide planning and forecasting processes such as the CEC’s Integrated Energy Policy Report. This ruling mandated the Utility, along with the other California IOUs, to develop a draft joint proposal for the CPUC and stakeholder consideration on the process for developing DER forecasts. On June 9, 2017, the utilities submitted a draft joint proposal for CPUC and stakeholder consideration. Comments were submitted by stakeholders on the draft proposal on July 10, 2017. On August 9, 2017, the CPUC issued a ruling directing all California IOUs to use the CEC’s Integrated Energy Policy reportDER forecast for the 2017-20182018-2019 distribution planning cycle. The August 9, 2017 rulingdecision also requires the Energy DivisionIOUs to work withdevelop an alternative planning forecast scenario in 2018 to better inform DER sourcing policies by establishing a method for calculating costs and benefits for DER grid integration. Historically, the Utility has planned using the CEC forecast and will have the opportunity to adjust forecasts for EV, photovoltaic, and energy storage, if needed during the planning cycle.preliminary proposal for DER growth scenarios.grid needs assessment and distribution deferral opportunity report to identify proposed electric distribution investments that could be deferred by deploying DERs. The CPUC will begin workshops to discussdecision also extends the proposals4% pre-tax regulatory incentive mechanism, being piloted in the fourth quarter of 2017 and a final decision is expected by the end of the first quarter of 2018.On May 16, 2017, the CPUC issued a ruling requiring stakeholder responses to questions posed in a CPUC staff white paper on grid modernization. The white paper is aimed at informing the development of a CPUC framework to evaluate grid-modernization investments. A workshop took place and comments were submitted by stakeholders in June 2017.On June 30, 2017, the CPUC issued another ruling soliciting stakeholder responses on questions set forth in a CPUC staff white paper on proposing a DIDF. The DIDF aims to establish a future process for identifying distribution deferral opportunities for DERs. Stakeholder comments on DIDF were submitted on August 7, 2017, with reply comments submitted on August 18, 2017. The CPUC may issue a combined proposed decision on DIDF and grid-modernization in the fourth quarter of 2017. The Utility is unable to predict when a final CPUC decision approving, disapproving, or modifying the Utility’s DRP will be issued.Proceeding – Regulatory Incentives Pilot ProgramOn April 4, 2016,(IDER) proceeding, to all DER distribution deferral projects. The Utility filed its first grid needs assessment with the CPUC issuedon June 1, 2018, and its first distribution deferral opportunity report on September 4, 2018. The Utility has convened a ruling proposingdistribution planning advisory group, comprised of CPUC staff, ratepayer and environmental advocates, DER market participants, and Utility staff, to establish, on a pilot basis, an interim program offering regulatory incentives toreview the UtilityUtility's grid needs assessment, distribution deferral opportunity report, and the other two large California IOUspotential distribution deferral locations where DER solutions or non-wire alternatives can be considered for the deployment of cost-effective DERs. The ruling stated that it did not intend for this phase to adopt a new regulatory framework or business model for the California electric utilities. competitive solicitations.December 22, 2016,March 26, 2018, the CPUC issued a final decision in the proceeding which authorizes a pilot to test a regulatory incentive mechanism through which the Utility will earn a 4% pre-tax incentive on annual payments for DERs, as well as test a regulatory process that will allowrequiring the Utility to competitively solicitinclude a grid modernization plan in the Utility's GRC to address distribution system upgrades required to deploy DERs. The grid modernization plan must include a narrative 10-year vision for investments needed to support DER servicesgrowth, safety, and reliability, and a status update of previously funded DER-related grid modernization GRC projects. On June 25, 2018, the Utility hosted a grid modernization workshop to defer distribution infrastructure. Each utilityprovide a high-level overview of its grid integration platform and 10-year plan. The Utility is required to conduct at least one pilot, but may conduct upsubmit a grid modernization plan with each GRC application starting with its 2020 GRC application.three additional pilots.In Junestrengthen California's ability to prevent and recover from catastrophic wildfires, including SB 901. Some of the significant highlights of SB 901 include:Utility submittedCPUC to consider the electric corporation's financial status and determine the maximum amount a pilot project proposalutility 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;for approvala 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 begin solicitations.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 pilot aimsCPUC will consider whether the cost of implementing the plan is just and reasonable in each electric corporation's GRC;effectivenessCPUC opened an OIR to implement the wildfire mitigation plan provisions in SB 901. This OIR will only focus on the wildfire mitigation plan of an earnings opportunitySB 901 implementation, and will not address utility cost recovery. Cost recovery associated with SB 901 wildfire mitigation plans will be addressed in motivatingutilities' GRCs.source DERs. recover their above market costs from departing customers as compared to the current methodology, by:17, 2017, the Utility notified the CPUC of potential changes to its pilot project proposal due to the uncertain condition of the Utility’s facilities in the area of the Northern California wildfires. On October 27, 2017,10, 2018, the CPUC issued a draft resolution that proposed modifications to the Utility’s pilot program. The CPUCscoping memo and established a procedural schedule for IOUs. A final decision is expected to issue a final resolution by the end of 2017.Transportation Electrification ApplicationCalifornia Law (Senate Bill 350) requires the CPUC,be issued in consultation with the CARB and the CEC, to direct the Utility and electrical corporations to file applications for programs and investments to accelerate widespread TE. In September 2016, the CPUC directed the Utility and the other large IOUs to file TE applications which include both short-term projects (of up to $20 million in total) and two- to five-year programs with a requested revenue requirement determined by the Utility. On January 20, 2017, the Utility filed its TE application with the CPUC requesting a total of up to $253 million (approximately $211 million in capital expenditures) in program funding over five years (2018 - 2022) primarilylate 2019.make-ready infrastructure for TE in medium to heavy-duty vehicle sectors. The CPUC may issue a proposed decision on this requestthe Utility's climate change resiliency strategies see Item 1 in the first quarter of 2018.FEDERAL INITIATIVESStrengthening the Cybersecurity of Federal Networks and Critical Infrastructure Executive OrderOn May 11, 2017, President Donald J. Trump signed Executive Order “Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure” that includes provisions, among other things, for the executive branch to use its authorities and capabilities to support the cybersecurity risk management efforts of the owners and operators of critical infrastructure. Among other things, it requires heads of appropriate sector-specific agencies to identify authorities and capabilities that agencies could employ to support the cybersecurity efforts of critical infrastructure entities identified to be at greatest risk of attacks that could reasonably result in catastrophic regional or national effects on public health or safety, economic security, or national security. It also requires within 180 days of the cybersecurity order, before November 7, 2017, a classified report detailing the findings and recommendations for better supporting the cybersecurity risk management efforts of such entities. The Utility is unable to predict the impact that the executive order will have on the Utility until the report is released and the federal administration takes steps to implement some or all of the report’s recommendations.CO2carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q, as well as “Item 1A. Risk Factors” and Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 20162017 Form 10-K.)COMMITMENTSCOMMITMENTSStatements)Statements in Item 1). Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing. For more in-depth discussion about PG&E Corporation’s and the Utility’s contractual commitments, see “Liquidity and Financial Resources” above and Management’s Discussion and AnalysisMD&A "Contractual Commitments" in Item 7 of Financial Condition and Results of Operations – Contractual Commitments in the 20162017 Form 10-K.20162017 Form 10-K (the Utility’s commodity purchase agreements).market risk, which is the risk thatrisks associated with adverse changes in market conditions will adversely affect net income or cash flows. PG&E Corporationcommodity prices, interest rates, and the Utility face market risk associated with their operations; their financing arrangements; the marketplace for electricity, natural gas, electric transmission, natural gas transportation, and storage, emissions allowances and offset credits, other goods and services, and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as “commodity price risk” and “interest rate risk.” The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations. 20162017 Form 10-K. There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the nine months ended September 30, 2017.2018.
accounting policies for insurance recoveries, AROs, and pension and other postretirementpost-retirement benefits plans to be critical accounting policies. These policies are considered critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates. These accounting policies and their key characteristics are discussed in detail in the 20162017 Form 10-K.Statements. 65whichthat are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations and proceedings; forecasts of pipeline-related expenses that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to regulatory assets and liabilities, environmental remediation, litigation, third-party claims, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:the costs of restoration of service to customers and repairs to the Utility’s facilities, and whether the Utility iswill be able to timely recover such costs through CEMA;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 by Cal Fire and the CPUC, including into the causes of the wildfires; and whetherextent to which the Utility maywill have liability associated with these fires; the timing and if liable for one or more fires, whether the Utility would be able to recover all or partamount of such costs through insurance or through regulatory mechanisms, to the extent insurance is not available or exhausted; as well asrecoveries; 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 broughtwere to bring an enforcement action and determined that the Utility failed to comply with applicable laws and regulations;the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within the authorized levels of spending and timely recover its costs through rates, and the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs;the timing and outcomes of the TO18 and TO19 rate cases and other ratemaking and regulatory proceedings;from customers, if any;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;the CPUC approves the Utility’s application to establish a WEMA to track wildfire expensesPG&E Corporation and to preserve the opportunity for the Utility are able to request recoverysuccessfully challenge the application of the doctrine of inverse condemnation to the Northern California wildfires and the Butte fire;costs in excess ofreforms, including inverse condemnation reform, a potential state wildfire insurance at a future date,fund, and other wildfire mitigation measures;potential requestproceeding to recover such costs. Whilecost through rates;previously approvedand 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;tracking accounts for San Diego Gas & Electric Company in 2010, the CPUC currently is considering whether to approve recoveryFHPMA, future cost of costs recorded by San Diego Gas & Electric Company in its WEMA. On August 22, 2017, the CPUC issued a PD denying San Diego Gas & Electric Company’s cost recovery request; as a result ofby 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, and ex parte communications, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes;the timing and outcomes of the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office investigations in connection with communications between the Utility’s personnel and CPUC officials, whether additional criminal or regulatory investigations or enforcement actions are commenced with respect to allegedly improper communications, and the extent to which such matters negatively affect the final decisions to be issued in the Utility’s ratemaking proceedings, and the timing and outcome of the federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act;Utility’s conviction in the federal criminal trial, the state and federalCPUC's investigations of natural gas and electric incidents, matters relating to the criminal federal trial,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;successfully implementtimely 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,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 is able to successfully adapt its business model to significant change that the electric industry is undergoing and the impact such change will have on the natural gas industry;the impact of increased costs to comply with natural gas regulations, including the Senate Bill 887 directing DOGGR and CARB to develop permanent regulations for gas storage facility operations in California to comply with new safety and reliability measures, the PHMSA rules effective January 18, 2017 regulating gas storage facilities at the federal level; and the CPUC General Order 112-F that went into effect on January 1, 2017, that requires additional expenditures in the areas of gas leak repair, leak survey, high consequences area identification, and operator qualifications, and could impact the Utility’s ability to timely recover such costs; with the FERC on February 2, 2017 that requests 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 in order to allow for greater participation and input from interested parties;amounttiming 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;theultimate outcome of the safety culture OII, includingNinth Circuit Court of its phase two proceeding openedAppeals decision on MayJanuary 8, 2017 and future legislative or regulatory actions that may be taken2018, to requirereverse FERC’s decision granting the Utility a 50 basis point ROE incentive adder for continued participation in the CAISO and remanding the case to separate its electric and natural gas businesses, restructure into separate entities, undertake some other corporate restructuring, or implement corporate governance changes;cyber security,cybersecurity, environmental laws and regulations; and the outcome of existing and future SED notices of violations;notices of violations in connection with the Yuba City incident;the outcomes of the CPUC’s data requests, includingany CPUC action in connection with the Utility’s SmartMeter™ Upgrade cost-benefit analysis, and of the Utility’s PFMs, including in connection with the installation of new CP systems in 2018;the timing and outcomes of the “Ghost Ship” and Valero refinery outage lawsuits;California;California and the Utility's fossil fuel-fired generation sites;Canyon; whether the CPUC approves the joint proposal that will phase out the Utility’s Diablo Canyon nuclear units at the expiration of their licenses in 2024 and 2025; and whether the Utility will be able to successfully implementuntil its retention and retraining and development programs for Diablo Canyon employees, and whether these programs will be recovered in rates;potential inadequacyadequacy 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;outages (such as the power outage on April 21, 2017 in San Francisco, that initial information suggests was due to an equipment failure that led to a fire at Larkin Street substation, and that impacted approximately 88,000 customers);outages; and whether the Utility will be subject to investigations, penalties, and other costs in connection with such events;how the CPUC and the CARB 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;whether the Utility’s climate change adaptation strategies are successful;PG&E’sthe Utility’s procurement service for CCAs;whether, as a result of Westinghouse’s Chapter 11 proceeding, the Utility will experience issues with nuclear fuel supply, nuclear fuel inventory, and related services and products that Westinghouse supplies, and whether such proceeding will affect the Utility’s contracts with Westinghouse;increasedcash 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; federal or state laws or regulations, or their interpretation, on energy policy and 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, the Utility’s conviction in the federal criminal trial, and other enforcement matters will impact the Utility’s ability to make distributions to PG&E Corporation, and in turn,whether they will continue impacting PG&E Corporation’sCorporation's and the Utility's ability to pay dividends;the impact of the corporate tax reform considered by the new federal administration and newcurrent federal administration; and20162017 Form 10-K, including the “Risk Factors” section. Forward-looking statements speak only as of the date they are made. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise. , under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “News & Events: Events & Presentations” tab and links to certain documents and information related to the Northern California wildfires and the Butte fire which may be of interest to investors, at http://investor.pgecorp.com, under the “Wildfire Updates” tab, in order to publicly disseminate such information. It is possible that any of these regulatory filings or information included therein could be deemed to be material information. The information contained on this website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “News & Events: Events & Presentations” tab, in order to publicly disseminate such information.2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.1.)2017, 2018, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms, and (ii) accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.2017,2018, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting. legal proceedings, PG&E Corporation and the Utility are involved inparties to various legallawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s contingencies, see Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,MD&A: “Enforcement and Litigation Matters.”Butte Fire LitigationIn September 2015, a wildfire (known as the “Butte fire”) ignited 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.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 for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of September 30, 2017, 77 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 3,770 individual plaintiffs representing approximately 2,080 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints. Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability. Plaintiffs also seek punitive damages. The number of individual complaints and plaintiffs may increase in the future. The Utility continues mediating and settling casesIn addition, on April 13, 2017, Cal Fire filed a complaint with the Superior Court of the State of California, County of Calaveras, seeking to recover $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, among other claims. Also, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $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. Also, in June 2017, the County of Calaveras indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $85 million. This claim would include costs that the County of Calaveras incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire. On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages. 10, 2017,27, 2015, the Court deniedCPUC began a formal investigation into whether the Utility’s motion on the grounds that plaintiffs might be able to show conscious disregard for public safety based on the fact that the Utility relied on contractors to fulfill their contractual obligation to hireorganizational culture and train qualified employees. On August 16, 2017, the Utility filed a writ with the Courtgovernance of Appeals challenging this novel theory of punitive damages liability. The Court of Appeals accepted the writ on September 15, 2017 and ordered the trial court and plaintiffs to show cause why the relief requested by the Utility should not be granted. Briefing on the writ should be completed by early 2018.In the third quarter of 2017, the Utility reached settlements with plaintiffs in the “preference” trial involving six households and with the plaintiffs in the representative trial that had been scheduled for August 2017 and October 2017, respectively. While there are no trials related to the Butte fire currently scheduled, one plaintiff has moved for a preference trial involving one household. The motion is set for hearing on December 1, 2017.On October 25, 2017, the Utility filed a motion to stay the trial court proceedings pending a decision by the Court of Appeals on the pending writ of mandate regarding punitive damages. A hearing on the stay motion is calendared for December 1, 2017.For more information regarding the Butte fire, see Note 9 of the Notes to the Condensed Consolidated Financial Statements. San Bruno Derivative LitigationAs previously disclosed, on July 18, 2017, the Superior Court of California, County of San Mateo (the “Court”) approved the settlement agreement reached by the parties in the San Bruno Fire Derivative Cases to resolve the consolidated shareholder derivative lawsuit and certain additional claims against certain current and former officers and directors (the “Individual Defendants”). Also, as of July 19, 2017, the three cases, Tellardin v. Anthony F. Earley, Jr., et al., Iron Workers Mid-South Pension Fund v. Johns, et al., and Bushkin v. Rambo, et al (the “Additional Derivative Cases”) were dismissed. The settlement will become effective when all procedural conditions specified in the settlement stipulation are satisfied. PG&E Corporation recorded $65 million in proceeds from insurance, net of plaintiff costs to its Condensed Consolidated Income Statement for the three and nine months ended September 30, 2017.also agreed, under their indemnification obligationsprioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards. The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Individual Defendants,Utility’s record of operations, including its record of safety incidents. The CPUC authorized the SED to pay $18.3 millionengage a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment.Individual Defendants’ costs, fees,consultant that may lead to the CPUC’s adoption of the recommendations in the report, in whole or in part. This phase of the proceeding will also consider all necessary measures, including, but not limited to, a potential reduction of the Utility’s return on equity until any recommendations adopted by the CPUC are implemented.expenses incurredprocedural schedule. The scoping memo directed the Utility to file testimony addressing a number of issues including: adoption of the safety recommendations from the consultant, the Utility’s implementation process for the safety recommendations of the consultant, the Utility’s Board of Director’s actions and initiatives related to safety culture and the consultant’s recommendations, the Utility’s corrective action program, and the Utility’s response to certain specified safety incidents that occurred in 2013 through 2015.respondingthis proceeding. If adopted, the Utility would be required to defendingimplement the recommendations set forth in the May 2017 consultant report no later than July 1, 2019, and settlingto submit quarterly reports on the San Bruno Fire Derivative Casesstatus of their implementation beginning in the fourth quarter of 2018. The PD, if adopted, would not result in the adoption of safety performance metrics and targets at this time, but they could be considered in the future. Additionally, the PD directs the assigned CPUC commissioner and the Additional Derivative Cases, including certain feesALJ to develop a process for a remedial phase and expenses for investigating these claims. The $18.3 million has been paid, with the majority reflected in PG&E Corporation’s and the Utility’s financial statements through December 31, 2016.In addition, pursuant to the settlement agreement, issue a scoping memo.will implement certain corporate governance therapeutics for five years, and the Utility will implement certain gas operations therapeutics and maintain certain of them for three years, at an estimated cost of upare unable to approximately $32 million. The Court also directed PG&E Corporation to provide at least quarterly reports to the Court and to the City of San Bruno summarizing the progresspredict whether additional fines, penalties, or other ratemaking tools such as a potential reduction of the implementation ofUtility's return on equity will be adopted by the corporate governance and gas operations therapeutics.For additional information regarding these matters, see “Part I, Item 3. Legal Proceedings” inCPUC.2016 Form 10-K and subsequent quarterly reportsCPUC could vote on Form 10-Q and Note 9 of the Notes to the Condensed Consolidated Financial Statements.Other Enforcement MattersFines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to the Utility’s self-reports of non-compliance with electric and natural gas safety regulations and other enforcement matters. See the discussion entitled “Enforcement and Litigation Matters” above in Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 9 of the Notes to the Condensed Consolidated Financial Statements. In addition, see “Part I, Item 3. Legal Proceedings” in the 2016 Form 10-K.“PartPart I, Item 3. Legal"Legal Proceedings” in the 20162017 Form 10-K.20162017 Form 10-K entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled “Cautionary Language Forward-Looking“Forward-Looking Statements.”adversely affected by potential losses resulting from the impact of the Northern California wildfires. ThePG&E Corporation and the Utility also expect to be the subject of additional lawsuits and could be the subject of lawsuits, additional investigations, citations, fines or enforcement actions.adversely affected by potential losses resulting from the impact of the multiple wildfires that spread through Northern California, wildfires. The Utility estimates that it will incur costsincluding Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the range of $160 million to $200 million for service restoration and repairsarea surrounding Yuba City, beginning on October 8, 2017 (the “Northern California wildfires”). According to the Utility’s facilities (includingCal 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 $60 million to $80 million8,900 structures. The wildfires resulted in capital expenditures) in44 fatalities. these fires. 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 adversely affectedNorthern California wildfires, if the Utility were unable to recover such costs.If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the cause of one or more fires, and the theorydoctrine of inverse condemnation applies, the Utility could be liable for property damages,damage, interest, and attorneys’ fees without having been found negligent, which liability, in the aggregate, could be substantial. Courtssubstantial and have imposed liability undera material adverse effect on PG&E Corporation and the Utility. (See “The doctrine of inverse condemnation, policyif applied by courts in litigation to actions by property holders against utilities onwhich PG&E Corporation or the grounds that losses borne byUtility are subject, could significantly expand the person whose property was damaged through a public use undertaking should be spread across the community that benefittedpotential liabilities from such undertakinglitigation and based onmaterially negatively affect PG&E Corporation’s and the assumption that utilities haveUtility’s financial condition, results of operations, and cash flows” in PG&E Corporation and the ability to recover these costs from their customers.Utility’s 2017 Form 10-K, Item 1A, Risk Factors.) In addition to such claims for property damage, interest, and attorneys’ fees, as well as claims under other theories of liability, 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. Thesubstantial and have a material adverse effect on PG&E Corporation and the Utility. Further, the Utility also could be subject to material fines or penalties if the CPUC or any other law enforcement agency brought an enforcement action, including as a result of the referral by Cal Fire of certain investigation reports to the appropriate county District Attorney's offices, and determined that the Utility failed to comply with applicable laws and regulations.are unablewere to reasonably estimatebe found liable for certain or all of such other costs and expenses, including the potential liabilities outlined above, the amount of possiblethe liability could significantly exceed the approximately $10 billion in estimated insured property losses (or range of amounts) given the preliminary stages of the investigations and uncertainty aswith respect to the causes of the firesNorthern California wildfires. As a result, PG&E Corporation’s and the extentUtility’s financial condition, results of operations, liquidity and magnitude of damages.cash flows could be materially affected.As of October 31, 2017,PG&E Corporation and the Utility is awarealso are the subject of ninea still increasing number of lawsuits one of which seeks to be designated as a class action, that have been filed against PG&E Corporation and the Utility in Sonoma, Napa and San Francisco Counties’ Superior Courts. The lawsuits allege, among other things, negligence, inverse condemnation, trespass, and private nuisance. They principally assert that PG&E Corporation and the Utility’s alleged failureCourts, several of which seek to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the cause of the fires. The plaintiffs seekbe certified as class actions, asserting damages that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees, and other damages. In addition, two 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. Further, several derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court and two purported securities class actions were filed in the United States District Court for the Northern District of California. PG&E Corporation and the Utility mayexpect to be the subject of additional lawsuits in connection with the Northern California wildfires.Utility has approximately $800 million in liability insurance for potential losses that may result from these fires. Ifwildfire litigation could take a number of years to be resolved because of the Utility were held liable for one or morecomplexity of the matters, including the ongoing investigation into the causes of the fires and the Utility’s insurance were insufficient to cover that liability orgrowing number of parties and claims involved. either of whichand, even if such recovery is possible, it could take a number of years to resolve and a number of years to collect. adversely affected. If the Utility were to determine that it is both probable that a material loss has occurred and the amount of loss can be reasonably estimated, a liability would be recorded consistentaffected” below.)principles discussed in Note 9 in the Notes to the Condensed Consolidated Financial Statements. To the extent not offset by insurance recoveries determined to be similarly probable and estimable, the liabilitywildfires would affect the balance sheet equity oflikely require PG&E Corporation and the Utility to seek financing, which could adversely impactmay not be available on terms acceptable to PG&E Corporation’s andCorporation or the Utility’s credit ratings and their ability to declare and pay dividends, efficiently raise capital, comply with financial covenants, and meet financial obligations.Utility, or at all, when required. (See “Risks Related to Liquidity and Capital Requirements” in the 2016Item 1A Risk Factors in 2017 Form 10-K.)lead tocontinue or increase volatility in the market for PG&E Corporation’s common stock and other securities, and for the securities of the Utility, and could materially affect the price of such securities.additionalmore information about risksthe Northern California wildfires, see Note 9 of the Notes to Condensed Consolidated Financial Statements in Item 1.facehave considered certain actions that might be taken to attempt to address liquidity needs of the business in such circumstances, but the inability to recover all or a significant portion of costs in excess of insurance through increases in rates and by collecting such rates in a timely manner, or any negative assessment by the Utility of the likelihood or timeliness of such recovery and collection, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.respectthe 2017 wildfires, the CPUC is expected to consider the Utility’s financial status and determine the maximum amount the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service, and ensure that the costs or expenses that are disallowed for recovery in rates assessed for the wildfires, see “in the aggregate, do not exceed that amount. The Utility is unable to predict the timing or outcome of such future determination by the CPUC and its impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.results.condition, results of operations, liquidity, and cash flows. event,events, including severe weather events, or may not becomebe available at a reasonable cost, or available at all”all.Item 1A. Risk Factorsobtaining insurance coverage for wildfires that could arise from the Utility’s ordinary operations. PG&E Corporation, the Utility or its contractors and customers could continue to experience coverage reductions and/or increased wildfire insurance costs in future years. No assurance can be given that future losses will not exceed the limits of the 2016 Form 10-K.affectedaffected.ultimate amountNorth American Electric Reliability Corporation, and U.S. Government Departments, including the Departments of third-party liabilityDefense, Homeland Security and Energy, and the White House, have noted that cyber-attacks targeting utility systems are increasing in sophistication, magnitude, and frequency. The Utility’s operational networks also may face new cyber security risks due to modernizing and interconnecting the existing infrastructure with new technologies and control systems. Any failure or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in the most safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties. incurs in connections withoften relies on third-party vendors to host, maintain, modify, and update its systems, and to provide other services to the 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. Cal Fire’s report concluded that the wildfire was caused when a gray pine tree contactedUtility or the Utility’s electric line which ignited portions ofcustomers. These third-party vendors could cease to exist, fail to establish adequate processes to protect the tree,Utility’s systems and determined thatinformation, or experience security incidents or inadequate security measures. Any incidents or disruptions in the failure byUtility’s information technology systems could impact the Utility and/Utility’s ability to track or its vegetation management contractors, ACRT Inc.collect revenues and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.As of September 30, 2017, 77 known complaints have been filed against themaintain effective internal controls over financial reporting.two vegetation management contractorsthird-party vendors have been subject to, and will likely continue to be subject to breaches and attempts to gain unauthorized access to the Utility’s information technology systems or confidential data (including information about customers and employees), or to disrupt the Utility’s operations. None of these breaches or attempts has individually or in the Superior Court of Californiaaggregate resulted in the Counties of Calaveras, San Francisco, Sacramento, and Amador. The complaints involve approximately 3,770 individual plaintiffs representing approximately 2,080 households and their insurance companies. These complaints are part of or are in the process of being added to two master complaints. Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability. Plaintiffs also seek punitive damages. The number of individual complaints and plaintiffs may increase in the future. The Utility continues mediating and settling cases.In addition, on April 13, 2017, Cal Fire filed a complaintsecurity incident with the Superior Court of the State of California, County of Calaveras, seeking to recover $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, among other claims. Also, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $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. Also, in June 2017, the County of Calaveras indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $85 million. This claim would include costs that the County of Calaveras incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire. The Utility currently believes that it is probable that it will incur a loss of at least $1.1 billion, increased from the $750 million previously estimated as of December 31, 2016, in connection with the Butte fire. In addition, while this amount includes the Utility’s early assumptions about fire suppression costs (including its assessment of the Cal Fire loss), it does not include any significant portion of the estimated claims from the OES and the County of Calaveras. The Utility still does not have sufficient information to reasonably estimate any liability it may have for these additional claims.The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs and results from the ongoing mediation and settlement process, management estimates and assumptions regarding the financial impact of the Butte fire may change. A change in management’s estimates or assumptions could result in an adjustment that could have a material impact on PG&E Corporation’s and the Utility’s financial condition and the results of operations during the period such change occurred. Through September 30, 2017, the amounts accrued in connection with claims relating to the Butte fire have exceeded the Utility’s liability insurance coverage. Whileoperations. Despite implementation of security and control measures, there can be no assurance that the Utility filed an application withwill be able to prevent the CPUC requesting approvalunauthorized access to establish a WEMA to track wildfire expenses and to preserveits operational networks, information technology systems or data, or the opportunity fordisruption of its operations. Such events could subject the Utility to request recoverysignificant expenses, claims by customers or third parties, government inquiries, penalties for violation of wildfire costsapplicable privacy laws, investigations, and regulatory actions that could result in material fines and penalties, loss of customers and harm to PG&E Corporation’s and the Utility’s reputation, any of which could have not otherwise been recovered through in insurance or other mechanisms, the Utility cannot predict the outcome of this proceeding. If the Utility is unable to recover all or a significant portion of such excess costs,material adverse effect on PG&E Corporation’s and the Utility’s financial condition and results of operations,operations.cash flows couldthat the costs of responding to and recovering from a cyber incident will be materially affected. a transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy. California's environmental policy objectives are accelerating the pace and scope of the industry change. The electric grid is a critical enabler of the adoption of new energy technologies that support California's climate change and GHG reduction objectives, which continue to be publicly supported by California policymakers. California's environmental policy makers notwithstandingobjectives are accelerating the pace and scope of the industry change. For instance, Senate Bill 100, which was signed into law on September 10, 2018, increases from 50 percent to 60 percent, the percentage of California’s electricity portfolio that must come from renewables by 2030. SB 100 establishes a recent change in the federal approachfurther goal to such matters.have an electric grid that is entirely powered by clean energy by 2045. California utilities also are experiencing increasing deployment by customers and third parties of DERs, such as on-site solar generation, energy storage, fuel cells, energy efficiency, and demand response technologies. This growthThese developments will require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity, increase the grid's capacity, and interconnect DERs.Statestate infrastructure modernization (e.g.(e.g.. rail and water projects).DERs;DERs and, consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by DERs, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator. The CPUC has also recently opened proceedings regarding the creationauthorized development of a shared database or statewide census of utility polestwo new, five-year programs aimed at accelerating widespread electric vehicle adoption and conduits in California and increased access by communications providers to utility rights-of-way. This proceeding could require utilities to invest significant resources into inspecting poles and conduits, limit available capacity in existing rights-of-way, or impose other requirements on utilities facilities.combating climate change. The Utility is unable to predict the outcome of these proceedings. recently openedheld discussions on potential changes to California’s electricity market. On May 19, 2017, California energy companies, along with other stakeholders, discussed customer choice and the future of the state’s electricity industry at a CPUC “en banc” meeting. Specifically, the goal of the “en banc” was to frame a discussion on the trends that are driving change within California’s electricity sector and overall clean-energy economy and to lay out elements of a path forward to ensure that California achieves its reliability, affordability, equity, and carbon reduction imperatives while recognizing the important role that technology and customer preferences will play in shaping this future. After the “en banc,” the CPUC formed the California Customer Choice Project to examine the issues and develop a report evaluating choice in California’s current market. On August 7, 2018, the California Customer Choice Project released its report which includes an expanded discussion of policy implementation, procurement, resource adequacy, and information on a central buyer. The CPUC intends to issue a gap analysis to examine the questions raised by the Choice Paper to identify critical issues requiring solutions. The gap analysis will be accompanied by a draft action plan. The CPUC held an additional "en banc" on October 29, 2018, to discuss gap analysis and the draft action plan. While the CPUC had indicated its intent to open an OIRa proceeding related to customer choice, the Utility is unable to predict if and whenwhether that remains the CPUC may open an OIR. CPUC’s intent or the timing of any such proceeding.State climate policy requires reductions in greenhouse gases of 40% by 2030 and 80% by 2050. Various proposals for addressing these reductions have the potential to reduce natural gas usage and increase natural gas costs. The future recovery of the increased costs associated with compliance is uncertain.The CARB is the state’s primary regulator for GHG emission reduction programs. Natural gas providers have been subject to compliance with CARB’s Cap-and-Trade Program since 2015, and natural gas end-use customers have an increasing exposure to carbon costs under the Program through 2030 when the full cost will be reflected in customer bills. CARB’s Scoping Plan also proposes various methods of reducing GHG emissions from natural gas. These include more aggressive energy efficiency programs to reduce natural gas end use, increased renewable portfolio standards generation in the electric sector reducing noncore gas load, and replacement of natural gas appliances with electric appliances, leading to further reduced demand. These natural gas load reductions may be partially offset by CARB’s proposals to deploy natural gas to replace wood fuel in home heating and diesel in transportation applications. CARB also proposes a displacement of some conventional natural gas with above-market renewable natural gas. The combination of reduced load and increased costs could result in higher natural gas customer bills and a potential mandate to deliver renewable natural gas could lead to cost recovery risk.A cyber incident, cyber security breach or physical attack on the Utility’s operational networks and information technology systems could have a material effect on its business and results of operations.Private and public entities, such as the NERC, and U.S. Government Departments, including the Departments of Defense, Homeland Security and Energy, and the White House, have noted that cyber-attacks targeting utility systems are increasing in sophistication, magnitude, and frequency. The Utility’s electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events—such as severe weather or seismic events—and by malicious events, such as cyber and physical attacks. The Utility’s operational networks also may face new cyber security risks due to modernizing and interconnecting the existing infrastructure with new technologies and control systems. Any failure or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas, or otherwise operate in the most safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties. The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals. In addition, the Utility often relies on third-party vendors to host, maintain, modify, and update its systems and these third-party vendors could cease to exist, fail to establish adequate processes to protect the Utility’s systems and information, or experience security incidents. Any incidents or disruptions in the Utility’s information technology systems could impact our ability to track or collect revenues and to maintain effective internal controls over financial reporting.The Utility and its third party vendors have been subject to, and will likely continue to be subject to attempts to gain unauthorized access to the Utility’s information technology systems, or confidential data, or to disrupt the Utility’s operations. None of these attempts or breaches has individually or in the aggregate resulted in a security incident with a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations. Despite implementation of security and control measures, there can be no assurance that the Utility will be able to prevent the unauthorized access to its operational networks, information technology systems or data, or the disruption of its operations. Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, investigations, and regulatory actions that could result in fines and penalties, and loss of customers, any of which could have a material effect on PG&E Corporation’s and the Utility’s financial condition and results of operations.The Utility maintains cyber liability insurance that covers certain damages caused by cyber incidents. However, there is no guarantee that adequate insurance will continue to be available at rates the Utility believes are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable in rates.The Utility purchases its nuclear fuel assemblies from a sole source, Westinghouse. If Westinghouse experiences business disruptions as a result of Chapter 11 proceedings, the Utility could experience disruptions in nuclear fuel supply, delays in connection with its Diablo Canyon outages and refuelings, and rejection in bankruptcy of its contracts with Westinghouse.The Utility purchases its nuclear fuel assemblies for Diablo Canyon from a sole source, Westinghouse. The Utility also stores nuclear fuel inventory at the Westinghouse fuel fabrication facility. In addition, Westinghouse provides the Utility with Diablo Canyon outage support services, nuclear fuel analysis, original equipment manufacturer engineering and parts support. On March 29, 2017, Westinghouse filed for Chapter 11 protection in the United States Bankruptcy Court, Southern District of New York. In the event that Westinghouse experiences business disruptions in its nuclear fuel business as a result of bankruptcy proceedings or otherwise, the Utility could experience issues with its nuclear fuel supply and delays in connection with Diablo Canyon refueling outages. The Utility also could experience losses in connection with its nuclear fuel inventory and Westinghouse could seek to reject in bankruptcy its contracts with the Utility. Diablo Canyon’s Unit 2 refueling outage is expected to occur in the first quarter of 2018. If Westinghouse were to reject the Utility’s contracts or fail to deliver nuclear fuel or provide outage support to the Utility, the Utility’s operation of Diablo Canyon would be adversely affected. PG&E Corporation and the Utility also could experience additional costs, including decreased electricity market revenues, in the event that one or both Diablo Canyon units are unable to operate. There can be no assurance that any such additional costs would be recoverable in the rates the Utility is permitted to recover from its customers. Furthermore, the Utility currently is not able to estimate the nature or amount of additional costs and expenses that it might incur in connection with the uncertainties surrounding Westinghouse but such costs and expenses could be material.For certain critical technologies, products and services, the Utility relies on a limited number of suppliers and, in some cases, sole suppliers. In the event these suppliers are unable to perform, the Utility could experience delays and disruptions in its business operations while it transitions to alternative plans or suppliers.The Utility relies on a limited number of sole source suppliers for certain of its technologies, products and services. Although the Utility has long-term agreements with such suppliers, if the suppliers are unable to deliver these technologies, products or services, the Utility could experience delays and disruptions while it implements alternative plans and makes arrangements with acceptable substitute suppliers. As a result, the Utility’s business, financial condition, and results of operations could be significantly affected. As an example, the Utility relies on Silver Spring Networks, Inc. and Aclara Technologies LLC as suppliers of proprietary SmartMeter™ devices and software, and of managed services, utilized in its advanced metering system that collects electric and natural gas usage data from customers. If these suppliers encounter performance difficulties, are unable to supply these devices or maintain and update their software, or provide other services to maintain these systems, the Utility’s metering, billing, and electric network operations could be impacted and disrupted.PROCEEDS2017,2018, PG&E Corporation madedid not make any equity contributions totaling $215 million to the Utility in order to maintain the 52% common equity component of the Utility’s CPUC-authorized capital structure. Neither PG&E Corporation nor the Utility made any sales of unregistered equity securities during the quarter ended September 30, 2017.2017,2018, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. PG&E Corporation does not have any preferred stock outstanding. During the quarter ended September 30, 2017,2018, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.ITEM 5. OTHER INFORMATIONRatio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock DividendsThe Utility’s earnings to fixed charges ratio for the nine months ended September 30, 2017 was 2.60. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the nine months ended September 30, 2017 was 2.58. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility’s Registration Statement No. 333-215427.PG&E Corporation’s earnings to fixed charges ratio for the nine months ended September 30, 2017 was 2.62. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-215425.77*10.13.1 4.1 4.2 4.3 10.1 *10.2 12.1*10.4 12.212.3Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation31.1PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY DAVIDDAVID S. THOMASON
(duly authorized officer and principal financial officer)