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 | ||||||||||
PG&E Corporation: |
| 517,151,337 | ||||||||
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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| 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 |
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| 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 |
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 |
ORA | Office of Ratepayer Advocates |
PCIA | Power Charge Indifference Adjustment |
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| petition for modification |
| Risk Assessment Mitigation Phase |
return on equity | |
| Senate Bill |
| SEC | U.S. Securities and Exchange Commission |
SED | Safety and Enforcement Division of the CPUC |
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| transportation electrification |
| TO | transmission owner |
| TURN | The Utility Reform Network |
Utility | Pacific Gas and Electric Company |
VIE(s) | variable interest entity(ies) |
WEMA | Wildfire Expense Memorandum Account |
Westinghouse | Westinghouse Electric Company, LLC |
(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 June 30, Six Months Ended
June 30,(in millions, except per share amounts) 2018 2017 2018 2017 Operating Revenues Electric $ 3,312 $ 3,323 $ 6,263 $ 6,388 Natural gas 922 927 2,027 2,130 Total operating revenues 4,234 4,250 8,290 8,518 Operating Expenses Cost of electricity 963 1,123 1,782 1,970 Cost of natural gas 79 121 368 446 Operating and maintenance 1,786 1,605 3,390 3,129 Wildfire-related claims, net of insurance recoveries 2,125 (46 ) 2,118 (53 ) Depreciation, amortization, and decommissioning 746 712 1,498 1,424 Total operating expenses 5,699 3,515 9,156 6,916 Operating Income (Loss) (1,465 ) 735 (866 ) 1,602 Interest income 12 8 21 13 Interest expense (226 ) (225 ) (446 ) (443 ) Other income, net 106 26 214 60 Income (Loss) Before Income Taxes (1,573 ) 544 (1,077 ) 1,232 Income tax provision (benefit) (593 ) 134 (542 ) 243 Net Income (Loss) (980 ) 410 (535 ) 989 Preferred stock dividend requirement of subsidiary 4 4 7 7 Income (Loss) Available for Common Shareholders $ (984 ) $ 406 $ (542 ) $ 982 Weighted Average Common Shares Outstanding, Basic 516 511 516 510 Weighted Average Common Shares Outstanding, Diluted 516 513 517 512 Net Earnings (Loss) Per Common Share, Basic $ (1.91 ) $ 0.79 $ (1.05 ) $ 1.93 Net Earnings (Loss) Per Common Share, Diluted $ (1.91 ) $ 0.79 $ (1.05 ) $ 1.92 Dividends Declared Per Common Share $ — $ 0.53 $ — $ 1.02 (Unaudited) Three Months Ended June 30, Six Months Ended
June 30,(in millions) 2018 2017 2018 2017 Net Income (Loss) $ (980 ) $ 410 $ (535 ) $ 989 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 (loss) — 1 — 1 Comprehensive Income (Loss) (980 ) 411 (535 ) 990 Preferred stock dividend requirement of subsidiary 4 4 7 7 $ (984 ) $ 407 $ (542 ) $ 983 See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Balance At (in millions) June 30,
2018 December 31,
2017ASSETS Current Assets Cash and cash equivalents $ 517 $ 449 Accounts receivable: 1,169 1,243 Accrued unbilled revenue 995 946 Regulatory balancing accounts 1,563 1,222 Other 1,027 861 Regulatory assets 194 615 Inventories: Gas stored underground and fuel oil 107 115 Materials and supplies 380 366 Other 415 464 Total current assets 6,367 6,281 Property, Plant, and Equipment Electric 56,410 55,133 Gas 20,387 19,641 Construction work in progress 2,643 2,471 Other 2 3 Total property, plant, and equipment 79,442 77,248 Accumulated depreciation (24,288 ) (23,459 ) Net property, plant, and equipment 55,154 53,789 Other Noncurrent Assets Regulatory assets 4,121 3,793 Nuclear decommissioning trusts 2,828 2,863 Income taxes receivable 66 65 Other 1,353 1,221 Total other noncurrent assets 8,368 7,942 TOTAL ASSETS $ 69,889 $ 68,012 See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Balance At (in millions, except share amounts) June 30,
2018 December 31,
2017LIABILITIES AND EQUITY Short-term borrowings $ 1,450 $ 931 Long-term debt, classified as current 193 445 Accounts payable: Trade creditors 1,477 1,646 Regulatory balancing accounts 1,303 1,120 Other 541 517 Disputed claims and customer refunds 215 243 Interest payable 209 217 Wildfire-related claims 2,860 561 Other 1,538 1,449 Total current liabilities 9,786 7,129 Noncurrent Liabilities Long-term debt 17,612 17,753 Regulatory liabilities 8,498 8,679 Pension and other post-retirement benefits 2,054 2,128 Asset retirement obligations 4,964 4,899 Deferred income taxes 5,667 5,822 Other 2,247 2,130 Total noncurrent liabilities 41,042 41,411 Contingencies and Commitments (Note 9) Equity Shareholders' Equity 12,765 12,632 Reinvested earnings 6,057 6,596 Accumulated other comprehensive loss (13 ) (8 ) 18,809 19,220 Noncontrolling Interest - Preferred Stock of Subsidiary 252 252 Total equity 19,061 19,472 TOTAL LIABILITIES AND EQUITY $ 69,889 $ 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)The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. 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 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 $ $ $ Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows. 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 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 $100 million in insurance reimbursements. In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations continue discussions. The PG&E Corporation and the Utility are subject to various claims, lawsuits, and regulatory proceedings that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled 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 rates. Utility’s contractors. Tax Act required PG&E Corporation and the Utility incremental increases to rate base of approximately $271 million for 2018 (including the impact of the private letter ruling advice letter approved by the CPUC on July 18, 2018), and $613 million for 2019. The incremental increases to rate base are due primarily to the elimination of bonus depreciation. The Utility also expects to reflect an annual revenue requirement reduction, starting in 2018, of approximately $125 million from other rate cases, including the TO19 rate case. 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. The associated rate base increases are approximately $100 million in 2018 and $200 million in 2019. The Utility is unable to predict the timing and outcome of the CPUC and FERC decisions in connection with these submittals. The 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. 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. 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 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 $ $ 2018. GRC. Interest Expense ASU 2016-09, 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), and the cost-effectiveness of each source of electricity. 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. $350 million. 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 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 $ $ also have an impact on the Utility's financing needs. The Utility cannot predict the timing and outcome of this PFM. the timing of its filing on October 15, 2018. In August 2016 and January 2017, TURN, ORA and Indicated Shippers filed applications for rehearing of the phase one and phase two issued a scoping memo and ruling establishing a procedural schedule. ORA submitted testimony on June 29, 2018 and TURN and other parties submitted testimony on July 20, 2018. Evidentiary hearings are scheduled to begin on September 17, 2018. 10-K. (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 % % A settlement conference was held at FERC on July 12, 2018. end of 2018. 10-K. community impact mitigation settlement of $85 million, originally proposed in the joint settlement agreement; Appeals issued a decision affirming the Superior Court ruling, thereby denying the appeal filed by the World Business Academy. On June 28, 2018, World Business Academy filed a petition for rehearing. On July 10, 2018, the Court of Appeals denied the petition for rehearing and modified the decision to strengthen its findings. Appellants may appeal this ruling to the California Supreme Court. The Utility expects to file its 2018 NDCTP application in December 2018. For more information, see the California electric utilities. On response costs in a manner that protects ratepayers; and 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 2017 Form 10-K. counterparty credit. PG&E Corporation and the Utility this proceeding. The Butte Fire through ratemaking mechanisms, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially materially affected. PR Utility. 12.2 12.3 31.1 31.2 **32.1 **32.2 101.INS XBRL Instance Document 101.SCH XBRL Taxonomy Extension Schema Document 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document 101.LAB XBRL Taxonomy Extension Labels Linkbase Document 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document 101.DEF XBRL Taxonomy Extension Definition Linkbase Document /s/ JASON P. WELLS /s/ (Unaudited) Six Months Ended June 30, (in millions) 2018 2017 Cash Flows from Operating Activities Net income (loss) $ (535 ) $ 989 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning 1,498 1,424 Allowance for equity funds used during construction (63 ) (34 ) Deferred income taxes and tax credits, net (145 ) 516 Disallowed capital expenditures — 47 Other 104 121 Effect of changes in operating assets and liabilities: Accounts receivable (11 ) 111 Wildfire-related insurance receivable (144 ) 54 Inventories (6 ) (38 ) Accounts payable 39 19 Wildfire-related claims 2,299 (116 ) Income taxes receivable/payable — 67 Other current assets and liabilities (103 ) (92 ) Regulatory assets, liabilities, and balancing accounts, net (12 ) (353 ) Other noncurrent assets and liabilities (168 ) 41 Net cash provided by operating activities 2,753 2,756 Cash Flows from Investing Activities Capital expenditures (2,897 ) (2,474 ) Proceeds from sales and maturities of nuclear decommissioning trust investments 802 794 Purchases of nuclear decommissioning trust investments (815 ) (817 ) Other 15 8 (2,895 ) (2,489 ) Cash Flows from Financing Activities Borrowings under revolving credit facilities 700 — Net issuances (repayments) of commercial paper, net of discount of $1 and $3 at respective dates (182 ) (339 ) 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 $0 and $11 at respective dates 350 734 Long-term debt matured or repurchased (750 ) (345 ) Common stock issued 82 247 Common stock dividends paid — (488 ) Other 10 (75 ) Net cash provided by (used in) financing activities 210 (266 ) Net change in cash and cash equivalents 68 1 Cash and cash equivalents at January 1 449 177 Cash and cash equivalents at June 30 $ 517 $ 178 Supplemental disclosures of cash flow information Cash received (paid) for: Interest, net of amounts capitalized $ (394 ) $ (395 ) Income taxes, net — 68 Common stock dividends declared but not yet paid $ — $ 271 Capital expenditures financed through accounts payable 317 268 Noncash common stock issuances — 10 Terminated capital leases 137 — See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Three Months Ended June 30, Six Months Ended
June 30,(in millions) 2018 2017 2018 2017 Operating Revenues Electric $ 3,312 $ 3,324 $ 6,263 $ 6,391 Natural gas 922 926 2,027 2,130 Total operating revenues 4,234 4,250 8,290 8,521 Operating Expenses Cost of electricity 963 1,123 1,782 1,970 Cost of natural gas 79 121 368 446 Operating and maintenance 1,786 1,604 3,390 3,129 Wildfire-related claims, net of insurance recoveries 2,125 (46 ) 2,118 (53 ) Depreciation, amortization, and decommissioning 746 712 1,498 1,424 Total operating expenses 5,699 3,514 9,156 6,916 Operating Income (Loss) (1,465 ) 736 (866 ) 1,605 Interest income 11 7 20 12 Interest expense (222 ) (222 ) (439 ) (438 ) Other income, net 108 24 217 55 Income (Loss) Before Income Taxes (1,568 ) 545 (1,068 ) 1,234 Income tax provision (benefit) (592 ) 136 (544 ) 256 Net Income (Loss) (976 ) 409 (524 ) 978 Preferred stock dividend requirement 4 4 7 7 Income (Loss) Available for Common Stock $ (980 ) $ 405 $ (531 ) $ 971 See accompanying Notes to the Condensed Consolidated Financial Statements. OFOF COMPREHENSIVE INCOME (Unaudited) Three Months Ended June 30, Six Months Ended
June 30,(in millions) 2018 2017 2018 2017 Net Income (Loss) $ (976 ) $ 409 $ (524 ) $ 978 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 (loss) 1 — 1 1 Comprehensive Income (Loss) $ (975 ) $ 409 $ (523 ) $ 979 See accompanying Notes to the Condensed Consolidated Financial Statements. 13 (Unaudited) Balance At June 30,
2018 December 31, 2017 (in millions) ASSETS Current Assets Cash and cash equivalents $ 484 $ 447 Accounts receivable: 1,169 1,243 Accrued unbilled revenue 995 946 Regulatory balancing accounts 1,563 1,222 Other 1,028 862 Regulatory assets 194 615 Inventories: Gas stored underground and fuel oil 107 115 Materials and supplies 380 366 Other 414 465 Total current assets 6,334 6,281 Property, Plant, and Equipment Electric 56,410 55,133 Gas 20,387 19,641 Construction work in progress 2,643 2,471 Total property, plant, and equipment 79,440 77,245 Accumulated depreciation (24,285 ) (23,456 ) Net property, plant, and equipment 55,155 53,789 Other Noncurrent Assets Regulatory assets 4,121 3,793 Nuclear decommissioning trusts 2,828 2,863 Income taxes receivable 64 64 Other 1,226 1,094 Total other noncurrent assets 8,239 7,814 TOTAL ASSETS $ 69,728 $ 67,884 See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Balance At June 30,
2018 December 31, 2017 (in millions. except share amounts) LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ 1,400 $ 799 Long-term debt, classified as current 193 445 Accounts payable: Trade creditors 1,477 1,644 Regulatory balancing accounts 1,303 1,120 Other 561 538 Disputed claims and customer refunds 215 243 Interest payable 208 214 Wildfire-related claims 2,860 561 Other 1,551 1,457 Total current liabilities 9,768 7,021 Noncurrent Liabilities Long-term debt 17,262 17,403 Regulatory liabilities 8,498 8,679 Pension and other post-retirement benefits 1,950 2,026 Asset retirement obligations 4,964 4,899 Deferred income taxes 5,806 5,963 Other 2,263 2,146 Total noncurrent liabilities 40,743 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 9,127 9,656 Accumulated other comprehensive income 5 6 Total shareholders' equity 19,217 19,747 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 69,728 $ 67,884 See accompanying Notes to the Condensed Consolidated Financial Statements. (Unaudited) Six Months Ended June 30, (in millions) 2018 2017 Cash Flows from Operating Activities Net income (loss) $ (524 ) $ 978 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning 1,498 1,424 Allowance for equity funds used during construction (63 ) (34 ) Deferred income taxes and tax credits, net (149 ) 534 Disallowed capital expenditures — 47 Other 57 127 Effect of changes in operating assets and liabilities: Accounts receivable (11 ) 113 Wildfire-related insurance receivable (144 ) 54 Inventories (6 ) (38 ) Accounts payable 40 45 Wildfire-related claims 2,299 (116 ) Income taxes receivable/payable — 75 Other current assets and liabilities (95 ) (72 ) Regulatory assets, liabilities, and balancing accounts, net (12 ) (353 ) Other noncurrent assets and liabilities (168 ) 40 Net cash provided by operating activities 2,722 2,824 Cash Flows from Investing Activities Capital expenditures (2,897 ) (2,474 ) Proceeds from sales and maturities of nuclear decommissioning trust investments 802 794 Purchases of nuclear decommissioning trust investments (815 ) (817 ) Other 15 8 (2,895 ) (2,489 ) Cash Flows from Financing Activities Borrowings under revolving credit facilities 650 — Net issuances (repayments) of commercial paper, net of discount of $0 and $3 at respective dates (50 ) (339 ) 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 $0 and $11 at respective dates — 734 Long-term debt matured or repurchased (400 ) (345 ) Preferred stock dividends paid — (7 ) Common stock dividends paid — (514 ) Equity contribution from PG&E Corporation — 190 Other 10 (68 ) Net cash provided by (used in) financing activities 210 (349 ) Net change in cash and cash equivalents 37 (14 ) 447 71 Cash and cash equivalents at June 30 $ 484 $ 57 Supplemental disclosures of cash flow information Cash received (paid) for: Interest, net of amounts capitalized $ (387 ) $ (390 ) Income taxes, net — 76 Supplemental disclosures of noncash investing and financing activities Capital expenditures financed through accounts payable $ 317 $ 268 Terminated capital leases 137 — 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.resulted in 43 fatalities, and destroyed an estimated 8,900 structures. The causes of these fireswildfires also resulted in 44 fatalities. The Northern California wildfires are being investigatedunder investigation by Cal Fire and the CPUC,CPUC's SED. Cal Fire issued its determination on the causes of 16 of the Northern California wildfires and the remaining wildfires remain under Cal Fire’s investigation, including the possible role of the Utility’s power lines and other facilities. 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.SeptemberJune 30, 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 SeptemberJune 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 Benefitsninesix months ended SeptemberJune 30, 20172018 and 20162017 were as follows: Pension Benefits Other Benefits Three Months Ended June 30, (in millions) 2018 2017 2018 2017 Service cost for benefits earned $ 129 $ 118 $ 17 $ 15 Interest cost 172 178 18 19 Expected return on plan assets (256 ) (192 ) (32 ) (25 ) Amortization of prior service cost (2 ) (2 ) 3 4 Amortization of net actuarial loss 2 5 (2 ) 1 Net periodic benefit cost 45 107 4 14 39 (23 ) — — Total $ 84 $ 84 $ 4 $ 14 Pension Benefits Other Benefits Six Months Ended June 30, (in millions) 2018 2017 2018 2017 Service cost for benefits earned $ 257 $ 236 $ 33 $ 30 Interest cost 344 357 35 38 Expected return on plan assets (511 ) (385 ) (65 ) (49 ) Amortization of prior service cost (3 ) (4 ) 7 8 Amortization of net actuarial loss 3 11 (3 ) 2 Net periodic benefit cost 90 215 7 29 77 (46 ) — — Total $ 167 $ 169 $ 7 $ 29 Pension
Benefits Other
Benefits Total (in millions, net of income tax) Three Months Ended June 30, 2018 Beginning balance $ (30 ) $ 17 $ (13 ) Amounts reclassified from other comprehensive income: (1 ) 2 1 1 (1 ) — — (1 ) (1 ) Reclassification of stranded income tax to retained earnings (net of taxes of $0 and $0, respectively) — — — Net current period other comprehensive gain (loss) — — — Ending balance $ (30 ) $ 17 $ (13 ) 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 June 30, 2017 Beginning balance $ (25 ) $ 16 $ (9 ) Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1 ) 3 2 Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) 3 — 3 Regulatory account transfer (net of taxes of $1 and $2, respectively) (2 ) (2 ) (4 ) 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.) Pension Benefits Other Benefits Total (in millions, net of income tax) Six Months Ended June 30, 2018 Beginning balance $ (25 ) $ 17 $ (8 ) (2 ) 5 3 2 (2 ) — — (3 ) (3 ) Reclassification of stranded income tax to retained earnings (net of taxes of $0, and $0, respectively) (5 ) — (5 ) Net current period other comprehensive gain (loss) $ (5 ) $ — $ (5 ) Ending balance (30 ) 17 (13 ) 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) Six Months Ended June 30, 2017 Beginning balance $ (25 ) $ 16 $ (9 ) Amortization of prior service cost (net of taxes of $2 and $3, respectively) (2 ) 5 3 Amortization of net actuarial loss (net of taxes of $5 and $1, respectively) 6 1 7 Regulatory account transfer (net of taxes of $3 and $4, respectively) (4 ) (5 ) (9 ) 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 quarteradoption date or for the three and six months ended June 30, 2018. A majority of 2016. ASU 2016-09 requires,the Utility’s revenue from contracts with customers continues to be recognized on a retrospectivemonthly basis based on applicable tariffs and customers' monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that employee taxes paiddirectly corresponds to the value transferred to the customer.withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities. As such,the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Condensed Consolidated StatementsBalance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of Cash Flowsseasonality, weather, and customer usage patterns.PG&E Corporationamounts billed and unbilled, net of revenues subject to refund.prior periods presented were retrospectively adjusted. This change resulted in an increasetime the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to cash flows from operating activities andrecover those costs, to the extent that these differences are probable of recovery or refund. As a decrease to cash flows from financing activities of $35 million for the nine months ended September 30, 2016.result, these differences have no impact on net income.(in millions) Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 Electric Revenue from contracts with customers Residential $ 1,039 $ 2,375 Commercial 1,234 2,307 Industrial 354 678 Agricultural 318 443 Public street and highway lighting 18 38 84 (118 ) Total revenue from contracts with customers - electric 3,047 5,723 265 540 Total electric operating revenue $ 3,312 $ 6,263 Natural gas Revenue from contracts with customers Residential $ 452 $ 1,410 Commercial 119 315 Transportation service only 264 560 (128 ) (179 ) Total revenue from contracts with customers - gas 707 2,106 215 (79 ) Total natural gas operating revenue 922 2,027 Total operating revenues $ 4,234 $ 8,290 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 $13 million for PG&E Corporation and the Utility, respectively, for the three months ended June 30, 2017 and $26 million and $27 million for PG&E Corporation and the Utility, respectively, for the six months ended June 30, 2017.ASU will be effective for PG&E CorporationFERC has allowed and the Utility onhas made a one-time election to adopt the new FASB guidance for regulatory filing purposes. In January 1, 2018, with early adoption permitted. Although PG&E Corporationthe CPUC approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the service cost component determined by a plan’s actuary. The capitalization of service costs only results in higher rate base and leads to a reduction in the Utility are currently evaluating the impact the guidance will have on the Condensed Consolidated Financial Statements and related disclosures, it isUtility’s 2018 revenues. The changes in capitalization of retirement benefits did not expected to have a material impact to financial results.Restricted CashIn November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230), which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. The ASU will be effective for PG&E CorporationCorporation’s and the Utility on January 1, 2018, with early adoption permitted. PG&E Corporation and the Utility will adopt this ASU in the first quarter of 2018 and do not expect a material impact to theUtility’s Condensed Consolidated Statements of Cash Flows and related disclosures as a result of this ASU.Financial Statements. Recognition of Lease Assets and LiabilitiesIn February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the 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. PG&E Corporation and the Utility plan to early adopt this guidance in the fourth 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. 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 impact the guidance will have on the Condensed Consolidated Statements of Income, Statements of Cash Flows and lease disclosures. existing 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. These investments are classified as “available-for-sale”trusts and gains or losses are refundable or recoverable, respectively, from customers through rates. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 and did not have a material impact on the Condensed Consolidated Financial Statements and related disclosures.2018.2019, with early adoption permitted.expect a material impactintend to the Condensed Consolidated Financial Statements and related disclosures as a result of this ASU.Revenue Recognition StandardIn May 2014, the FASB issued ASU No. 2014-09, 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 model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. 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 result in a significant shift in the timing of revenue recognition for such sales.intendplan to useadopt this guidance in the modified retrospective method when adopting the new standard on January 1, 2018.first quarter of 2019. PG&E Corporation and the Utility expect that the impact of the new guidance will be immaterialthis standard to increase lease assets and lease liabilities on the Condensed Consolidated Financial Statements. Upon adoptionBalance Sheets and do not expect the guidance will have a material impact on the Condensed Consolidated Statements of ASU 2014-09, the Utility plans to disclose revenues from contracts with customers separately from regulatory balancing account revenueIncome, Statements of Cash Flows 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) June 30, 2018 December 31, 2017 Pension benefits $ 1,877 $ 1,954 Environmental compliance costs 784 837 Utility retained generation 297 319 Price risk management 63 65 Unamortized loss, net of gain, on reacquired debt 84 79 654 274 69 — Other 293 265 Total long-term regulatory assets $ 4,121 $ 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) June 30, 2018 December 31, 2017 Cost of removal obligations $ 5,775 $ 5,547 Deferred income taxes 611 1,021 Recoveries in excess of AROs 467 624 Public purpose programs 636 590 Other 1,009 897 Total long-term regulatory liabilities $ 8,498 $ 8,679 20162017 Form 10-K. Receivable Balance at (in millions) June 30, 2018 December 31, 2017 Electric distribution $ 323 $ — Electric transmission 110 139 Utility generation 120 — Gas distribution and transmission 397 486 Energy procurement 95 71 Public purpose programs 32 103 Other 486 423 Total regulatory balancing accounts receivable $ 1,563 $ 1,222 Payable Balance at (in millions) June 30, 2018 December 31, 2017 Electric distribution $ — $ 72 Electric transmission 120 120 Utility generation — 14 Energy procurement 151 149 Public purpose programs 513 452 Other 519 313 Total regulatory balancing accounts payable $ 1,303 $ 1,120 20162017 Form 10-K.SeptemberJune 30, 2017:(in millions) Termination Date Borrowings PG&E Corporation April 2022 $ 300 $ — $ 50 $ 250 Utility April 2022 3,000 48 650 2,302 Total revolving credit facilities $ 3,300 $ 48 $ 700 $ 2,552 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 inwhich satisfied and discharged its remaining obligation of $350 million.2017, the Utility remarketed three series of pollution control bonds, previously held in treasury, totaling $145 million in principal amount. Series 2008 F 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.At September 30, 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%1.46% to 0.95%1.65%. At SeptemberJune 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%1.65%.ninesix months ended SeptemberJune 30, 20172018 were as follows:In February 2017, PG&E Corporation amended its February 2015 EDA providing 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. PG&E Corporation Utility (in millions) Balance at December 31, 2017 $ 19,472 $ 19,747 Comprehensive income (loss) (535 ) (523 ) Common stock issued 82 — Share-based compensation 49 — Preferred stock dividend requirement — (7 ) Preferred stock dividend requirement of subsidiary (7 ) — Balance at June 30, 2018 $ 19,061 $ 19,217 EDAequity distribution agreement for the threesix months ended SeptemberJune 30, 2017.2018. As of SeptemberJune 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 ninesix months ended SeptemberJune 30, 2017, 6.42018, 2.3 million shares were issued for cash proceeds of $316$82.3 million under these plans. Three Months Ended June 30, Six Months Ended June 30, (in millions, except per share amounts) 2018 2017 2018 2017 Income (loss) available for common shareholders $ (984 ) $ 406 $ (542 ) $ 982 Weighted average common shares outstanding, basic 516 511 516 510 Add incremental shares from assumed conversions: Employee share-based compensation — 2 1 2 Weighted average common shares outstanding, diluted 516 513 517 512 Total earnings (loss) per common share, diluted $ (1.91 ) $ 0.79 $ (1.05 ) $ 1.92 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. Contract Volume at Underlying Product Instruments June 30,
2018 December 31,
2017 Forwards, Futures and Swaps 268,296,840 228,768,745 Options 36,205,752 60,736,806 Electricity (Megawatt-hours) Forwards, Futures and Swaps 2,570,861 2,872,013 304,977,376 312,272,177 SeptemberJune 30, 2018, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Netting Cash Collateral Current assets – other $ 30 $ (2 ) $ 4 $ 32 Other noncurrent assets – other 89 — — 89 Current liabilities – other (42 ) 2 16 (24 ) Noncurrent liabilities – other (64 ) — 8 (56 ) Total commodity risk $ 13 $ — $ 28 $ 41 At December 31, 2016, the Utility’s outstanding derivative balances were as follows: 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 Commodity Risk Three Months Ended June 30, Six Months Ended June 30, (in millions) 2018 2017 2018 2017 $ 5 $ (4 ) $ (7 ) $ (52 ) (10 ) 1 (28 ) (4 ) — (3 ) (1 ) (4 ) Net commodity risk $ (5 ) $ (6 ) $ (36 ) $ (60 ) SeptemberJune 30, 2017,2018, the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions. Balance at (in millions) June 30,
2018 December 31,
2017$ (1 ) $ (1 ) Related derivatives in an asset position — — — — $ (1 ) $ (1 ) Fair Value Measurements June 30, 2018 (in millions) Level 1 Level 2 Level 3 Total Assets: Short-term investments $ 473 — — — $ 473 Nuclear decommissioning trusts Short-term investments 22 — — — 22 Global equity securities 1,873 — — — 1,873 Fixed-income securities 767 584 — — 1,351 Assets measured at NAV — — — — 18 2,662 584 — — 3,264 Price risk management instruments (Note 7) Electricity 1 2 113 1 117 Gas — 3 — 1 4 Total price risk management instruments 1 5 113 2 121 Rabbi trusts Fixed-income securities — 74 — — 74 Life insurance contracts — 68 — — 68 Total rabbi trusts — 142 — — 142 Long-term disability trust Short-term investments 4 — — — 4 Assets measured at NAV — — — — 155 Total long-term disability trust 4 — — — 159 TOTAL ASSETS $ 3,140 $ 731 $ 113 $ 2 $ 4,159 Liabilities: Price risk management instruments (Note 7) Electricity $ 6 $ 20 $ 79 $ (26 ) $ 79 Gas — 1 — — 1 TOTAL LIABILITIES $ 6 $ 21 $ 79 $ (26 ) $ 80 $387$436 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.ninesix months ended SeptemberJune 30, 20172018 and 2016.2017. Fair Value at (in millions) June 30, 2018 Fair Value Measurement Assets Liabilities Valuation
Technique Unobservable
Input Congestion revenue rights $ 113 $ 32 Market approach CRR auction prices $ (18.61) - 32.26 Power purchase agreements $ — $ 47 Discounted cash flow Forward prices $ 18.81 - 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 ninesix months ended SeptemberJune 30, 20172018 and 2016: Price Risk Management Instruments (in millions) 2018 2017 Asset (liability) balance as of April 1 $ 40 $ 49 Net realized and unrealized gains: (6 ) (1 ) Asset (liability) balance as of June 30 $ 34 $ 48 Price Risk Management Instruments (in millions) 2018 2017 Asset (liability) balance as of January 1 $ 42 $ 55 Net realized and unrealized gains: (8 ) (7 ) Asset (liability) balance as of June 30 $ 34 $ 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 SeptemberJune 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 June 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 16,696 16,413 17,090 19,128 investments:(in millions) As of June 30, 2018 Amortized
Cost Total
Unrealized
Gains Total
Unrealized
Losses Total Fair
ValueNuclear decommissioning trusts Short-term investments $ 22 $ — $ — $ 22 Global equity securities 482 1,412 (3 ) 1,891 Fixed-income securities 1,338 36 (23 ) 1,351 $ 1,842 $ 1,448 $ (26 ) $ 3,264 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$436 million and $333$440 million at Septemberfor the periods ended June 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) June 30, 2018 Less than 1 year $ 66 1–5 years 405 5–10 years 360 More than 10 years 520 Total maturities of fixed-income securities $ 1,351 Three Months Ended June 30, Six Months Ended June 30, (in millions) 2018 2017 2018 2017 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 308 $ 324 $ 802 $ 794 Gross realized gains on securities 11 13 48 42 Gross realized losses on securities (5 ) (3 ) (9 ) (8 ) 34lossliability has been incurred and the amount of the lossliability can be reasonably estimated. A gain contingencyPG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses, and record a charge that is recorded in the period inamount within the range that is a better estimate than any other amount or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. PG&E Corporation's and Utility'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 June 30, Six months ended June 30, (in millions) 2018 2017 2018 2017 Butte fire Insurance recoveries $ — $ (46 ) $ (7 ) $ (53 ) Total Butte fire — (46 ) (7 ) (53 ) Northern California wildfires Claims 2,500 — 2,500 — Insurance recoveries (375 ) — (375 ) — Total Northern California wildfires 2,125 — 2,125 — Total wildfire-related claims, net of insurance recoveries $ 2,125 $ (46 ) $ 2,118 $ (53 ) Balance At (in millions) June 30, 2018 December 31, 2017 Butte fire $ 360 $ 561 Northern California wildfires 2,500 — Total wildfire-related claims $ 2,860 $ 561 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 September 30, 2017, 77July 20, 2018, 81 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 3,7703,780 individual plaintiffs representing approximately 2,0802,000 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 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 number of individual complaints and plaintiffs may still increase in the future.future, because the statute of limitations for property damage in connection with the Butte fire has not yet expired. The statute of limitations for personal injury has expired. The Utility continues mediatingto mediate and settlingsettle cases.In 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. Courtcourt 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 AppealsAppeal of the State of California, Third Appellate District, challenging this novel theory ofthe trial court's ruling on punitive damages, liability. The Court of Appealswhich was accepted the writ on September 15, 20172017. After briefing, the Court of Appeal heard oral argument on June 22, 2018 and orderedgranted the Utility's writ petition on July 2, 2018, directing the trial court and plaintiffs to show cause why the relief requested byenter summary adjudication in favor of 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 withand to deny plaintiffs' claim for punitive damages under California Civil Code Section 3294. On July 17, 2018, 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 bypetition for rehearing in the Court of AppealsAppeal, which must be ruled upon by August 1, 2018. Plaintiffs have also indicated that, if the petition is denied, they intend to ask the California Supreme Court to review the Court of Appeal's decision. Neither the trial nor appellate courts addressed whether plaintiffs can seek punitive damages at trial under Public Utilities Code Section 2106. Based on the pending writJuly 2, 2018 Court of mandate regarding punitive damages. A hearing on the stay motion is calendared for December 1, 2017.Estimated Losses from Third-Party ClaimsIn connection with this matter,Appeal's ruling, the Utility may be liable for propertybelieves a loss related to punitive damages interest, and attorneys’ fees without having been found negligent, through the theory of inverse condemnation. is remote.for theof California, County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnation applies to the Utility is liable forwith respect to the Butte fire. The court held, among other things, that the Utility had failed to put forth any evidence to support its contention that the CPUC would not allow the Utility to pass on its inverse condemnation.condemnation liability through rate increases. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding at the time of the ruling, others could file lawsuits and make similar claims. On January 4, 2018, the Utility filed with the court a renewed motion for a legal determination of inverse condemnation liability, citing the November 30, 2017 CPUC decision denying the San Diego Gas & Electric Company application to recover wildfire costs in excess of insurance, and the CPUC declaration that it will not automatically allow utilities to spread inverse condemnation losses through rate increases.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’sUtility's early 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 — (201 ) Balance at June 30, 2018 $ 360 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 SeptemberJune 30, 20172018, the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $515$783 million, of which $398$740 million has been paid by the Utility.$72$109 million in connection with the Butte fire. For the three and ninesix months ended SeptemberJune 30, 2017,2018, the Utility has incurred legal expenses in connection with the Butte fire of $18$10 million and $45$22 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 six months ended June 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 (231 ) Balance at June 30, 2018 $ 365 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, the 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 administrative law judge 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 openadministrative law judge. On June 15, 2018, the parties submitted a second phase ofjoint status report requesting that further procedural steps be suspended in order to allow 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.statutory deadline for this proceeding previously was extendedparties expect to December 29, 2017.submit their next status report no later than July 31, 2018. The Utility is unable to predict the timing and outcome of the second phase in this proceeding.SeptemberJune 30, 2017,2018, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $24$16 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 Instituting an Investigation into the Utility’s Safety CultureOn August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation 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 metrics in relation to the Utility’s record of operations, including its record of safety incidents. The CPUC authorized the SED to engage a consultant to assist in the SED’s investigation and 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 phase in this OII in which the CPUC will evaluate the safety recommendations of the 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 reduction of the Utility’s return on equity until any recommendations adopted by the CPUC are implemented. 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 outcome 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 define in this proceeding. The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. There are a number of audit findings, as well as other potential violations identified through various investigations and the Utility’s self-reported non-compliance with laws and regulations, on which the SED has yet to act. This includes 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 impose 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 by the SED with respect to these matters given the wide discretion 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 it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000, with an administrative limit of $8 million per citation issued. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED also has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The SED also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged. 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 after the SED has issued a citation. 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, 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, the SED 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. The Utility may incur material costs, including as a result of these investigations or any proceedings that could be commenced in connection with this incident. Other Matters$39$100 million at SeptemberJune 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. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.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 June 30, December 31, (in millions) 2018 2017 Topock natural gas compressor station $ 339 $ 334 Hinkley natural gas compressor station 153 147 350 320
other facilities, and third-party disposal sites (2)112 115 142 123 Total environmental remediation liability $ 1,096 $ 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. SeptemberJune 30, 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.SeptemberJune 30, 2017,2018, the Utility expected to recover $698$751 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 are scheduled to begin in the fourth quarter of 2018 and continue for several years. The DTSC conducted an additionalUtility’s undiscounted future costs associated with the Topock site may increase by as much as $293 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)$136 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 able to contribute to these costs.be recovered through rates.incur actualcontinue to experience coverage reductions and/or significantly increased insurance costs in future years. No assurance can be given that future losses will not exceed the future that are materially different than this estimatelimits of PG&E Corporation and such costs could have a material impact on resultsthe Utility’s insurance coverage or the insurance coverage 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 June 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.June 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$215 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.SeptemberJune 30, 2017,2018, it is reasonably possible that unrecognized tax benefits will decrease by approximately $70$20 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, 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 obligations to re-measure all existing deferred income tax assets and liabilities to reflect the Individual Defendants, to pay $18.3 million ofreduction in 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 through December 31, 2016.In addition, pursuant to the settlement agreement,federal tax rate. PG&E Corporation and the Utility will implement certain corporate governance therapeuticsrecorded reasonable estimates to reflect the impacts of the Tax Act and recorded provisional amounts, in accordance with rules issued by the SEC staff in Staff Accounting Bulletin No. 118, for five years,the re-measurement of deferred tax balances as of December 31, 2017. As a result of updated estimates used in PG&E Corporation and the Utility's 2017 tax returns, during the three and six months ended June 30, 2018, the Utility will implement certain gas operations therapeutics and maintain certain of themrecorded a $13 million tax benefit to adjust provisional tax expense recorded at December 31, 2017, for three years, atthe Tax Act. For the six months ended June 30, 2018, the Utility recorded an estimated cost of up to approximately $32 million. The Court also directed PG&E Corporation to provide at least quarterly reports$80 million reduction to the Court andregulatory liability recorded at December 31, 2017, for the Tax Act.City of San Bruno summarizing the progressCPUC PFMs of the implementationCPUC’s final decisions in the Utility’s 2017 GRC, and the 2015 GT&S rate case. Additionally, the Utility submitted updated testimony in connection with the 2019 GT&S rate case. These submittals reflect the effects of the corporate governanceTax Act on these rate cases. On an aggregate basis from these submittals, the Utility anticipates an annual reduction to revenue requirements of approximately $325 million starting in 2018, 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 ninesix months ended SeptemberJune 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.resulted in 43 fatalities, and destroyed an estimated 8,900 structures.causes of these fireswildfires also resulted in 44 fatalities.being investigatedunder investigation by Cal Fire and the CPUC,CPUC's SED. Cal Fire issued its determination on the causes of 16 of the Northern California wildfires and the remaining wildfires remain under Cal 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 sourcesFor more information, see Note 9 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. 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.”ninesix months ended SeptemberJune 30, 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 ninesix months ended SeptemberJune 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 June 30, Six Months Ended June 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 (Loss) on a GAAP basis $ (984 ) $ 406 $ (1.91 ) $ 0.79 $ (542 ) $ 982 $ (1.05 ) $ 1.92 1,592 — 3.08 — 1,608 — 3.11 — 9 17 0.02 0.03 16 33 0.03 0.06 7 (17 ) 0.01 (0.03 ) 11 (15 ) 0.02 (0.03 ) (23 ) — (0.04 ) — (23 ) — (0.04 ) — — 32 — 0.06 — 32 — 0.06 — 2 — 0.01 — 4 — 0.01 — — — — — 36 — 0.07 — — — — — (88 ) — (0.17 ) $ 601 $ 440 $ 1.16 $ 0.86 $ 1,070 $ 984 $ 2.07 $ 1.92 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 $2.2 billion (before the tax impact of $619 million) and $2.2 billion (before the tax impact of $625 million) during the three and six months ended June 30, 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 three and six months ended June 30, 2018, related to estimated third-party claims in connection with 14 of the Northern California wildfires. The Utility also recorded $46 million (before the tax impact of $8$13 million) and $76$68 million (before the tax impact of $31$19 million) during the three and ninesix months ended SeptemberJune 30, 2017,2018, 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 three and six months ended June 30, 2018 for Utility clean-up and repair costs. These costs were partially offset by $375 million (before the tax impact of $105 million) recorded during the three and six months ended June 30, 2018 for probable insurance recoveries.(3) (4)The Utility incurred costs, net of $2insurance, of $10 million (before the tax impact of $1$3 million) and $9$15 million (before the tax impact of $4 million) during the three and ninesix months ended SeptemberJune 30, 2018, respectively, associated with the Butte fire. The Utility incurred charges of $10 million (before the tax impact of $3 million) and $22 million (before the tax impact of $6 million) during the three and six months ended June 30, 2018, respectively, for legal costs. These costs were partially offset by $7 million (before the tax impact of $2 million) recorded during the six months ended June 30, 2018 for contractor insurance recoveries.(4) (8)The Utility incurred costs of $11 million (not tax deductible) and $71$60 million (before the tax impact of $24 million) during the three and ninesix months ended SeptemberJune 30, 2017, respectively, for fines and penalties. This includes disallowed expensesincluded costs of $32 million (before the tax impact of $13 million) during the ninesix months ended SeptemberJune 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 ninesix months ended SeptemberJune 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$12 million (before the tax impact of $5 million) and $1 million (which was not tax deductible) during the three and ninesix months ended SeptemberJune 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) (9)The Utility incurred costsrecorded revenues of $71$150 million (before the tax impact of $29 million) and $46 million (before the tax impact of $19 million), during the three and nine months ended September 30, 2017, respectively, associated with the Butte fire, net of insurance. This includes accrued charges of $350 million (before the tax impact of $143 million), during the three and nine months ended September 30, 2017, related to estimated third-party claims. The Utility also incurred charges of $18 million (before the tax impact of $7 million) and $46 million (before the tax impact of $19 million), during the three and nine months ended September 30, 2017, respectively, for legal costs. These costs were partially offset by insurance recoveries of $297 million (before the tax impact of $121 million) and $350 million (before the tax impact of $143 million) recorded during the three and nine months ended September 30, 2017, respectively.(6) PG&E Corporation recorded proceeds from insurance, net of plaintiff payments, of $65 million (before the tax impact of $27$62 million) during the three and ninesix months ended SeptemberJune 30, 2017 associated within excess of the settlement agreement in connection with2017 authorized revenue requirement, which included the shareholder derivative litigation that was approved by the Superior Courtfinal component of California, County of San Mateo on July 18, 2017. This includes $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) Asunder-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, 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.case.(8) (10)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. Second 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) $ 440 $ 0.86 $ 984 $ 1.92 Timing and duration of nuclear refueling outages 43 0.08 12 0.02 29 0.06 29 0.06 27 0.05 27 0.05 26 0.05 1 — 23 0.04 65 0.12 Miscellaneous 38 0.07 10 0.02 (18 ) (0.03 ) — — (7 ) (0.01 ) (14 ) (0.02 ) Increase in shares outstanding — (0.01 ) — (0.02 ) — — (44 ) (0.08 ) $ 601 $ 1.16 $ 1,070 $ 2.07 benefits onimpact of stock compensation. See Footnote 68 below.variancevariances in the percentage of quarterly earnings to annual earnings.(3) Represents the timing of operational expense spending during the three months ended September 30, 2017 as compared to the same period in 2016.(4) (5) Represents the impact of the increase in rate base as authorized in various rate cases, including the 2017 GRC, during the three and ninesix months ended SeptemberJune 30, 20172018, as compared to the same periodsperiod in 2016.(5) Represents the impact in 2016 of the delay in the Utility’s 2015 GT&S rate case.2017. 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 benefit related to share-based compensation awards that vested during the nine months ended September 30, 2017. Pursuant to ASU 2016-09, Compensation – Stock Compensation (Topic 718), which PG&E Corporation and the Utility adopted in 2016, excess tax benefits associated with vested awards are reflected in net income.(7) Represents the impact of lower tax repair benefits as a result of the CPUC’s May 2017 final decision in the 2017 GRC proceeding.delayed recognition of the 2017 revenue increase until the second quarter of 2017, resulting in a smaller revenue increase in the second quarter of 2018 as compared to the first quarter of 2018.adversely affected by potential losses resulting from the impactNorthern California wildfires. Following accounting rules, PG&E Corporation and the Utility recorded a pre-tax charge in the amount of $2.5 billion for the quarter ended June 30, 2018 ($1.8 billion after-tax) for claims in connection with 14 of the Northern California wildfires. The Utility estimates that it will incur costs inThis charge corresponds to the lower end of 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. PG&E Corporation’sCorporation's and the Utility’s financial condition, results of operations, liquidity,Utility's reasonably estimated losses, and cash flows could be materially adversely affected if the Utility were unableis subject to recover such costs through CEMA.change based on additional information. If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the substantial cause of one or more remaining fires, and the theorydoctrine of inverse condemnation applies, the Utility could be liable for property damages,damage, business interruption, interest, and attorneys’ fees without having been found negligent, which liability, in the aggregate, could be substantial.substantial and have a material adverse effect on PG&E Corporation and the Utility. In addition to such claims as well as claims under other theories of liability,for property damage, business interruption, interest and attorneys' fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, and other damages under other theories of liability, including if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial. Thesubstantial and have a material adverse effect on PG&E Corporation and the Utility. In addition, the Utility alsoincurred costs of $274 million for clean-up and repair of the Utility’s facilities (including $116 million in capital expenditures) through June 30, 2018, in connection with these wildfires. At June 30, 2018, the CEMA balance related to the Northern California wildfires was $96 million and reflects an approximately $40 million reduction to the regulatory asset that was recorded in the three months ended June 30, 2018 for costs that are no longer probable of recovery. Failure to obtain a substantial or full recovery of these costs or any conclusion that such recovery is no longer probable, could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Further, the Utility 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. If(See Notes 3 and 9 of 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 consistent with the principles discussed in Note 9 to 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 and the Utility. (See Note 10 to Notes to the Condensed Consolidated Financial Statements in Item 1.)1A. Risk Factors in this Form 10-Q.1.) 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 Northern California wildfires, 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 Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1A. Risk Factors in the 2016 Form 10-K and Item 1A. in this Form 10-Q.1.)Proceedings. Proceedings. The Utility’s futurefinancial results may be impacted by the timing and outcome of its 2019 GT&S rate case, 2020 GRC, FERC TO18 and TO19 rate cases. (See “Transmission Owner Rate Cases” in “Regulatory Matters” belowcases, as well as the remand decision by the Ninth Circuit regarding an ROE incentive adder for more information.)transmission facilities, and the 2018 CEMA filing. 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.“Regulatory Matters" below.)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 theirPG&E Corporation’s and the Utility’s 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 ninesix months ended SeptemberJune 30, 2017,2018, PG&E Corporation issued $361$82 million of common stock and made no 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 Statestate 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.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.ninesix months ended SeptemberJune 30, 20172018 and 2016: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2018 2017 2018 2017 Consolidated Total $ (984 ) $ 406 $ (542 ) $ 982 PG&E Corporation (4 ) 1 (11 ) 11 Utility $ (980 ) $ 405 $ (531 ) $ 971 increasedecreases in PG&E Corporation’s net income for the three and ninesix months ended SeptemberJune 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, partially offset by additional income tax expense and interest expense.ninesix months ended SeptemberJune 30, 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 June 30, 2018 Three Months Ended June 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 $ 1,979 $ 1,333 $ 3,312 $ 1,948 $ 1,376 $ 3,324 Natural gas operating revenues 752 170 922 760 166 926 Total operating revenues 2,731 1,503 4,234 2,708 1,542 4,250 Cost of electricity — 963 963 — 1,123 1,123 Cost of natural gas — 79 79 — 121 121 1,244 542 1,786 1,293 311 1,604 Wildfire-related claims, net of insurance recoveries 2,125 — 2,125 (46 ) — (46 ) Depreciation, amortization, and decommissioning 746 — 746 712 — 712 Total operating expenses 4,115 1,584 5,699 1,959 1,555 3,514 Operating income (loss) (1,384 ) (81 ) (1,465 ) 749 (13 ) 736 11 — 11 7 — 7 (222 ) — (222 ) (222 ) — (222 ) 27 81 108 11 13 24 Income (loss) before income taxes $ (1,568 ) $ — $ (1,568 ) $ 545 $ — $ 545 (592 ) 136 Net income (loss) (976 ) 409 4 4 Income (Loss) Available for Common Stock $ (980 ) $ 405 SeptemberJune 30, 20172018 and 2016.2017. Six Months Ended June 30, 2018 Six Months Ended June 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 $ 3,915 $ 2,348 $ 6,263 $ 3,930 $ 2,461 $ 6,391 Natural gas operating revenues 1,490 537 2,027 1,539 591 2,130 Total operating revenues 5,405 2,885 8,290 5,469 3,052 8,521 Cost of electricity — 1,782 1,782 — 1,970 1,970 Cost of natural gas — 368 368 — 446 446 Operating and maintenance 2,494 896 3,390 2,466 663 3,129 Wildfire-related claims, net of insurance recoveries 2,118 — 2,118 (53 ) — (53 ) Depreciation, amortization, and decommissioning 1,498 — 1,498 1,424 — 1,424 Total operating expenses 6,110 3,046 9,156 3,837 3,079 6,916 Operating income (loss) (705 ) (161 ) (866 ) 1,632 (27 ) 1,605 Interest income 20 — 20 12 — 12 Interest expense (439 ) — (439 ) (438 ) — (438 ) Other income, net 56 161 217 28 27 55 Income (loss) before income taxes $ (1,068 ) $ — $ (1,068 ) $ 1,234 $ — $ 1,234 (544 ) 256 Net income (loss) (524 ) 978 7 7 Income (Loss) Available for Common Stock $ (531 ) $ 971 ninesix months ended SeptemberJune 30, 20172018 and 2016.2017.ninesix months ended SeptemberJune 30, 20172018 and 2016,2017, focusing on revenues and expenses that impacted earnings for these periods. $17$23 million, or 1%, and by $528 million, or 7%, in the three and nine months ended SeptemberJune 30, 2017, respectively,2018, compared to the same periodsperiod in 20162017. The Utility’s electric and natural gas operating revenues that impacted earnings decreased by $64 million, or 1%, in the six months ended June 30, 2018, compared to the same period in 2017, primarily due to additional$102 million in retroactive base revenues authorized by the CPUC in the 2015 GT&S rate case and the 2017 GRC, and by the FERCrecognized in the TO rate case. The final 2015 GT&S rate case decision authorizedsix months ended June 30, 2017, with no similar revenues recorded in the Utility to collect, over a 36-monthsame 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.$193$49 million, or 14%4%, in the three months ended SeptemberJune 30, 20172018, compared to the same period in 2016. During2017, primarily due to the expected cost recovery of insurance premiums incurred above authorized levels of $69 million recorded in the three months ended SeptemberJune 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,2018, 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, 2017,2017. Additionally, 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 capitalin the three months ended June 30, 2017, with no corresponding charges related to the San Bruno Penalty Decision and 2015 GT&S rate case decision during the same period in 2016)2018. These decreases were partially offset by Northern California wildfire-related legal and $51other costs of $46 million and clean-up and repair costs of $40 million in lowerthe three months ended June 30, 2018, with no similar charges in the same period in 2017, as well as additional costs related to higher premiums for liability insurance incurred during the three months ended June 30, 2018, as compared to the same period in 2017.(in the nine months ended September 30, 2017, the Utility recorded $395 million in charges as compared to $446 million in the same periodperiods in 2016) (see2017.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 millionStatements 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 reinstatementItem 1 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.this Form 10-Q.) 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.$16$34 million, or 2%5%, and by $44$74 million, or 2%5%, in the three and ninesix months ended SeptemberJune 30, 20172018, respectively, compared to the same periods in 20162017, primarily due to capital additions and 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$728 million and $800 million, in the three and six months ended SeptemberJune 30, 20172018, respectively, as compared to the same periodperiods in 2016.2017. The effective tax rates for the three months ended SeptemberJune 30, 2018 and 2017 were 37.9% and 2016 were 21% and 16%25.1%, respectively. The increases in the income tax provision and the effective tax rate primarily resulted from higher pre-tax income in 2017 as compared to 2016 and lower repairs deductions in the three months ended September 30, 2017 compared to the same period in 2016.The income tax provision increased by $493 million in the nine months ended September 30, 2017 as compared to the same period in 2016. The effective tax rates for the ninesix months ended SeptemberJune 30, 2018 and 2017 were 51.0% and 2016 were 21% and (16%)20.7%, respectively. The increasedecreases in the income tax provisionprovisions and increases in the effective tax raterates were primarily resulted from higherthe result of pre-tax incomelosses in 2018 versus pre-tax incomes 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 June 30, Six Months Ended June 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: 8.6 % 3.0 % 11.5 % 2.3 % 6.2 % (12.6 )% 16.8 % (12.9 )% Tax credits 0.2 % (2.5 )% 0.6 % (1.3 )% 1.9 % 2.2 % 1.1 % (2.4 )% Effective tax rate 37.9 % 25.1 % 51.0 % 20.7 % audit settlements during the nineamortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December of 2017. SeptemberJune 30, 20162018 primarily represent the impact of income taxes related to share-based compensation adjustments associated with no similar settlements during the same period in 2017.Statements.Statements in Item 1.) Three Months Ended June 30, Six Months Ended June 30, (in millions) 2018 2017 2018 2017 Cost of purchased power $ 919 $ 1,079 $ 1,672 $ 1,863 Fuel used in own generation facilities 44 44 110 107 Total cost of electricity $ 963 $ 1,123 $ 1,782 $ 1,970 $ 0.125 $ 0.114 $ 0.124 $ 0.111 7,333 9,425 13,443 16,716 due to their departuredriven by customer departures 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“Legislative and Regulatory Initiatives - Power Charge Indifference Adjustment OIR”,OIR,” below. ninesix months ended SeptemberJune 30, 20172018 compared to the same periodsperiod in 20162017 was primarily due to lower Utility electric customer demand and an increase in generation from hydroelectric facilities. demand.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), regulatory requirements to procure certain types of energy, and the cost-effectiveness of each source of electricity.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 June 30, Six Months Ended June 30, (in millions) 2018 2017 2018 2017 Cost of natural gas sold $ 53 $ 93 $ 310 $ 386 Transportation cost of natural gas sold 26 28 58 60 Total cost of natural gas $ 79 $ 121 $ 368 $ 446 $ 1.20 $ 2.27 $ 2.40 $ 2.88 Total natural gas sold (in millions of Mcf) 44 41 129 134 (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 the first quarter of 2018, Fitch Ratings, S&P Global Ratings, and Moody’s Investors Service, Inc. downgraded PG&E Corporation forecasts thatCorporation’s and the Utility’s credit ratings. During the second quarter of 2018, S&P Global Ratings further downgraded PG&E Corporation’s and the Utility’s credit ratings. At June 30, 2018, PG&E Corporation’s and the Utility’s credit ratings remained at investment grade levels. If the Utility’s credit rating were to fall 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. If both S&P Global Ratings and Moody's Investors Service, Inc. downgraded the endUtility below investment grade or if the Utility were downgraded further, the Utility could be required to post additional collateral for other obligations. (See Note 7 and Note 9 of 2017, primarily to fund equity contributionsthe Notes 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”.)In February 2017, PG&E Corporation amended its February 2015 EDA providing for the sale of PG&E Corporation common stock having an aggregate gross 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. EDAequity distribution agreement for the threesix months ended SeptemberJune 30, 2017.2018. As of SeptemberJune 30, 2017,2018, the remaining gross 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 ninesix months ended SeptemberJune 30, 2017, 6.42018, 2.3 million shares were issued for cash proceeds of $316$82.3 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, the Utility remarketed three serieswhich satisfied and discharged its remaining obligation of pollution control bonds, previously held in treasury, totaling $145 million in principal amount. Series 2008 F 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. SeptemberJune 30, 2017,2018, PG&E Corporation and the Utility had $300$250 million and $2.6$2.3 billion available under their respective $300 million and $3.0 billion revolving credit facilities. For the six months ended June 30, 2018, the average outstanding borrowings under PG&E Corporation’s and the Utility’s revolving credit facilities were $62 million and $281 million, respectively, and the maximum outstanding borrowings were $125 million and $650 million, respectively. At June 30, 2018, PG&E Corporation and the Utility had outstanding borrowings of $50 million and $650 million, respectively, 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 ninesix months ended SeptemberJune 30, 2017,2018, PG&E Corporation and the Utility had an average outstanding commercial paper balance of $70$58 million and $552$16 million, respectively, and a maximum outstanding balance of $161$137 million and $1.1 billion,$205 million, respectively. At SeptemberJune 30, 2017, the Utility had an outstanding commercial paper balance of $369 million and2018, PG&E Corporation and the Utility did not have any outstanding commercial paper outstanding.SeptemberJune 30, 2017,2018, PG&E Corporation’s and the Utility’s total consolidated debt to total consolidated capitalization was 49%51% and 48%50%, 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 SeptemberJune 30, 2017,2018, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.In MayOn December 20, 2017, the BoardBoards 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. Six Months Ended June 30, (in millions) 2018 2017 Net cash provided by operating activities $ 2,722 $ 2,824 Net cash used in investing activities (2,895 ) (2,489 ) Net cash provided by (used in) financing activities 210 (349 ) Net change in cash and cash equivalents $ 37 $ (14 ) 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.ninesix months ended SeptemberJune 30, 2017,2018, net cash provided by operating activities increaseddecreased by $1.5 billion$102 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 phase two of the proceeding, the outcome of phase two of the ex parte OII, and the related proposed decision, costs associated with potential recommendations that the third-party monitor 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;the timing and amount of costs the Utility incurs, but does not recover, associated with its electric and natural gas systems, including amounts related to cancelled projects 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; andDuring the nine months ended September 30, 2017, netdecreasedincreased by $133$406 million during the six months ended June 30, 2018 as compared to the same period in 2016.2017 primarily due to an increase in capital expenditures of approximately $420 million. 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$6.3 billion in capital expenditures in 2017, $6.3 billion in 2018, and $6.0 billion in 2019.decreasedincreased by $1.6 billion from $851$559 million forduring the ninesix months ended SeptemberJune 30, 20162018 as compared to $743the same period in 2017. This increase was primarily due to $650 million in borrowings under the Utility’s revolving credit facility and the suspension of net cash useddividend payments (see “Dividends” section above), partially offset by a decrease in financing activities for the nine months ended September 30, 2017. long-term debt proceeds.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 these 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.Modifications fromConsistent 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, in line with 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.what, if any, actionsthe timing and outcome of this compliance filing.take regarding these submissions.PG&E Corporation’sthe 2017 Form 10-K.2016 Form 10-K and2020 GRC.subsequent quarterly reports2020 GRC application. The Utility requested this extension due to extraordinary uncertainties related to the 2017 Northern California wildfires that could significantly impact the content of the rate case application. On June 29, 2018, the CPUC granted the Utility’s extension request to file its 2020 GRC application no later than January 1, 2019. The extension also requires that the Utility provide an update to the CPUC on Form 10-Q.phasephases 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 the 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. 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 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. The PFM, if adopted, would 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 approved by the CPUC on July 18, 2018). The Utility has proposed to work with the CPUC instaff to implement rate changes under a schedule that minimizes rate volatility, which could defer some rate impacts beyond 2018. The timing of rate changes will also have an impact on the fourth quarterUtility’s financing needs. The Utility cannot predict the timing 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.decisions, respectively.decisions. 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 June 2017, the Utility filed a PFM of the phase one decision to eliminate the requirement that the Utility install new CP systems in 2018 because the Utility is not in a position to identify the optimal location for such new systems in 2018. Instead, the Utility requested to be allowed to continue its current CP program. As directedcathodic protection program rather than install a new system. On April 26, 2018, the CPUC issued a final decision granting the Utility’s PFM.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. In the event the PFM is not adopted andUtility’s future rate base. The Utility’s request also excludes rate base adjustments that the Utility failsrequested with the CPUC 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 based on capital expenditure forecasts of $971 million for 2019, $963 million for 2020, and $804 million for 2021 (which exclude common capital allocations).performincreased infrastructure investment and costs related to new natural gas storage safety and environmental regulations. Such new regulations were issued by: (1) DOGGR, which issued emergency safety and reliability natural gas storage measures in 2016 in response to the mandated2015 Southern California natural gas storage leak in Aliso Canyon. The final rulemaking on new CP systems,gas storage safety rules was adopted on June 28, 2018 and will be effective as of October 1, 2018; (2) the Pipeline and Hazardous Materials Safety Administration, which issued interim final rules, effective January 18, 2017, that address pipeline safety issues and mandate certain reporting requirements for operators of underground natural gas storage facilities; and (3) the CPUC, which issued General Order 112-F that became effective on January 1, 2017, and requires additional expenditures in the areas of gas leak repair, leak survey, and high consequence area identification, among other things. In its application, the Utility could incur finesproposes a new two-way gas storage balancing account to address uncertainty around the anticipated DOGGR regulations, and penalties,also proposes a new memorandum account to track costs related to other anticipated new regulations.amount of whichexisting gas storage safety requirements, the Utility is unable to predict. With the addition of a third attrition year, the Utility’s next GT&S cycle will begindeveloped and proposed in 2019. The Utility is required to file its 2019 GT&S rate case in 2017.application a natural gas storage strategy that includes the discontinuation (through closure or sale) of operations at two gas storage fields. The discontinuation is expected to reduce long-term costs for customers and to reduce safety and environmental risks. The Utility planscannot predict the timing and outcome of this submittal.file itsthe CPUC. The updated testimony, including the private letter ruling advice letter, reduces the Utility's previously forecasted revenue requirement by $25 million for 2019, GT&S$30 million for 2020, $22 million for 2021, and $5 million for 2022, and increases rate case withbase by $188 million for 2019, $254 million for 2020, $378 million for 2021, and $469 million for 2022.in the fourth quarter of 2017.PG&E Corporation’s and the Utility’s 20162017 Form 10-K and its subsequent quarterly reports on Form 10-Q.aits 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,submitted testimony. The table below summarizes the differences between the amount of revenue requirement increases included in the Utility’s requestaddressed questions relating to return on equity, capital structure, depreciation rates, capital additions, rate base, operating and maintenance expense, administrative and general expense, and the testimony submitted byallocation of common, general and intangible costs. On April 11, 2018, the FERC trial staff:Additionally, intervenors provided testimony on July 5, 2017 andextended the Utility submitted rebuttal testimony on October 9, 2017. Hearings are scheduled to take place starting January 9, 2018, with andeadline for the administrative law judge's initial decision expected on or beforefrom June 1, 2018, to October 1, 2018.Also, The Utility expects a FERC decision 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.for hearing, settlement judge procedures, and consolidation with the TO19 proceeding. is unable tocannot predict whenthe timing and howoutcome of the FERC’s response.will respond toby the complaint.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.On September 29, 2017, the Utility submitted an advice letter to the CPUC, updating its cost of capital and the estimated revenue requirement impacts with an effective date of January 1, 2018. The long-term debt cost reset reflects actual embedded costs as of the end of August 2017 and forecasted interest rates for the new long-term debt expected to be issued for the remainder of 2017 and all of 2018. The Utility estimates that its annual revenue requirement will be reduced by approximately $120 million, beginning in 2018. This estimate is based on the updated cost of capital inTO rate cases, see the September 29, 2017 advice letter and current rate base. In the fourth quarter 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 cost of the Utility’s future financings, but will not affect the authorized cost of capital in 2018.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.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 beforeapplication.NRC. PG&E Corporation andkey remaining goals of the Utility are unableDiablo Canyon joint proposal agreement. SB 1090 was approved by members of the Senate on May 29, 2018. If SB 1090 is approved by the California Assembly, then the bill will be submitted to predict whetherthe Governor for signature. SB 1090 seeks to:willto approve 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 on 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 issuedUtility expects will continue until those costs are fully recovered.final decision insite-specific decommissioning study to update the 2015 NDCTP adopting a nuclear decommissioning cost estimate of $1.1 billion for Humboldt Bay, correspondingforecast and to submit the study 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 authorized 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 Note 9 of the Notes to file an applicationthe Condensed Consolidated Financial Statements in Item 1.)seek approvalrecover the reasonable, incremental costs of responding to catastrophic events through a CEMA. The CEMA tariff authorizes the utilities to recover costs incurred in connection with a catastrophic event that has been declared a disaster or state of emergency by competent federal or state authorities. In 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. The costs associated with this work are tracked in WEMA.the CEMA. While the Utility believes such costs are recoverable through CEMA, its CEMA applications are subject to CPUC approval.has setapproved the settlement agreement authorizing the Utility to recover $117 million in connection with its 2016 CEMA application.this matter for December 8, 2017. TheJuly 10, 2018, which covered issues related to schedule, scope of costs, interim rate relief, and the engagement of an independent auditor to review tree mortality mitigation costs.cannotare unable to predict the outcome of this proceeding.GasElectric Safety Citation ProgramThe SED periodically audits utility operating practicesthe CEC, to direct electrical corporations to file applications for programs and conducts investigationsinvestments 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.potential violations of lawsTE demonstration projects and regulations applicable topilot programs.safetyCPUC approved, with modifications, four of the five short-term projects proposed by the Utility for a total of approximately $8 million.utilities’law, on July 1, 2015, the Utility filed its proposed electric 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 natural gas facilities and operations. affordable electric service. delegated authorityplanned using the CEC forecast and will have the opportunity to adjust forecasts for EV, photovoltaic, and energy storage, if needed during the SEDplanning cycle.issue citationsdevelop and impose penaltiessubmit an annual grid needs assessment and an annual distribution deferral opportunity report to identify proposed electric distribution investments that could be deferred by deploying DERs. The decision also extends the 4% pre-tax regulatory incentive mechanism, being piloted in the Integrated Distributed Energy Resources (IDER) proceeding, to all DER distribution deferral projects. The Utility filed its first grid needs assessment with the CPUC on June 1, 2018.violations identified through audits, investigations, or self-reports. Under bothinvestments needed to support DER growth, safety, and reliability, and a status update of previously funded DER-related grid modernization GRC projects. On June 25, 2018, the gasUtility hosted a grid modernization workshop to provide a high-level overview of its grid integration platform and electric programs, the SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it10-year plan. The Utility is required to imposesubmit a grid modernization plan with each GRC application starting with its 2020 GRC application.maximum statutory penalty of $50,000. The SED may, at its discretion, impose penaltiesCPUC issued a ruling proposing to establish, on a dailypilot basis, an interim program offering regulatory incentives to the California IOUs 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 on less than a daily basis,business model for violations that continued for more than one day.September 29,December 22, 2016, the CPUC issued a final decision adopting improvements and refinementsin the proceeding that authorizes a pilot to its gas andtest 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 allow the Utility to competitively solicit DER services to defer electric safety citation programs. Specifically,distribution infrastructure. Each IOU is required to conduct at least one pilot, but may conduct up to three additional pilots.final decision refinesUtility submitted a pilot project proposal to the criteriaCPUC for approval to begin solicitations. The pilot aims to evaluate the SED to useeffectiveness of an earnings opportunity in determining whether to issue a citation and the amount of penalty, sets an administrative limit of $8 million per citation issued, makes self-reporting voluntary in both gas and electric programs, adopts detailed criteria for themotivating utilities to usesource DERs. In December 2017, the CPUC granted the Utility’s request to voluntarily self-report a potential violation, and refines other issuescancel the current pilot project proposal due to the damage of the Utility’s facilities 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 modificationarea of the CPUC’s September 29, 2016 decision regardingNorthern California wildfires. On May 1, 2018, the safety citation program. The petition for modification requests thatUtility submitted an advice letter seeking approval of an alternative pilot project at 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.Gonzales Substation. The Utility cannot predict when or howthe timing and outcome of this proposal.will actissued an amended scoping memo and ruling to investigate DER sourcing mechanisms beyond the existing competitive solicitations for DERs. The scope now includes: (1) the design, for CPUC consideration and adoption, of alternative sourcing mechanisms or approaches that satisfy distribution planning objectives; and (2) the consideration of how existing programs, incentives, and tariffs can be coordinated to maximize locational benefits and minimize DER costs. The IOUs and other parties filed opening and reply comments on March 29, 2018 and April 13, 2018, respectively, in response to the petitionCPUC's ruling to further investigate sourcing mechanisms beyond the existing competitive solicitations framework.modification. Other Regulatory Proceedingswildfire prevention and Initiativeson how to allocateregarding the allocation of costs associated with long-term power purchase commitments in a manner that ensurestreats 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 the costs. The utilities believe that these CCA and direct access customers are not paying their full share of costs associated with the long-term power purchase commitments, which resultsresulting in other customerscustomers 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 from the Utility or choose a CCA or direct access provider. The Utility projects that approximately 50 percentmore than half of 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 with the Utility 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.will focusis focused on PCIA within the larger context of consumer choice in energy services, and should not be considered a follow-up to the CPUC and Energy Commission Joint En Banc on Customer Choice in California.services. On September 25, 2017, the CPUC issued a scoping memo and ruling establishing a procedural schedule and a new overall goal to mitigate cost increases for both bundled and departing loadCCA and direct access customers. Testimony is scheduled forOn April 2, 2018, the first quarter ofUtility served joint testimony with Southern California Edison and San Diego Gas & Electric to the CPUC along with nine other parties including ORA, TURN, and California Community Choice Association. The Utility, Southern California Edison, and San Diego Gas & Electric served joint rebuttal testimony on April 23, 2018. Evidentiary hearings are scheduled for the second quarter ofbegan on May 7, 2018, and opening and reply briefs were filed on June 1, 2018 and June 15, 2018, respectively. The Utility expects the CPUC to issue a proposed decision is expected byPD in the third quarter of 2018.Customer ChoiceMay 19, 2017, California energy companies, along with other stakeholders discussed customer choiceApril 26, 2018, the CPUC opened an OIR to consider strategies for integrating climate change adaptation matters into relevant CPUC proceedings. Phase one will focus on how to integrate climate change adaptation into the IOUs’ existing planning and the 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 that are driving change within California’s electricity sector and overall clean-energy economy and to lay out elements of a path forwardoperations to ensure that California achieves its reliability, affordability, equity,utility safety and carbon reduction imperatives while recognizingreliability.important role that technologyIOUs;customer preferencesguidance to instruct utilities on how to incorporate adaption in their existing planning and operational processes; andplay in shaping this future. On October 11, 2017, the CPUC announced the formation of the California Customer Choice Projecttake place on August 6, 2018, to examinescope the issues and produceset a report evaluating regulatory framework options in early 2018.procedural schedule. 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 basisscope for instituting a rulemaking. The white paper is expected in early 2018 with a final version expected by the second quarterfuture phases of 2018. While the CPUC had indicated intent to open an OIR related to customer choice, the Utility is unable to predict if and when the CPUC may open an OIR.Electric Distribution Resources PlanAs required by California law, on July 1, 2015, the Utility filed its proposed DRP 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, the CPUC issued a ruling that seeks 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 report forecast for the 2017-2018 distribution planning cycle. The August 9, 2017 ruling also requires the Energy Division to work with the CEC to develop a preliminary proposal for DER growth scenarios. The CPUC will begin workshops to discuss the proposals 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 DRPthis proceeding will be issued.Integrated Distributed Energy Resources Proceeding – Regulatory Incentives Pilot ProgramOn April 4, 2016, the CPUC issuedconsidered at a ruling proposinglater time, but they are anticipated to establish, on a pilot basis, an interim program offering regulatory incentives to the Utility and the other two large California IOUs for the deployment of cost-effective DERs.impact non-energy utilities. 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. On December 22, 2016, 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 allow the Utility to competitively solicit DER services to defer distribution infrastructure. Each utility is required to conduct at least one pilot, but may conduct up to three additional pilots.In June 2017, the Utility submitted a pilot project proposal to the CPUC for approval to begin solicitations. The pilot aims to evaluate the effectiveness of an earnings opportunity in motivating utilities to source DERs. On October 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, the CPUC issued a draft resolution that proposed modifications to the Utility’s pilot program. The CPUC is expected to issue a final resolution by the end of 2017.Transportation Electrification ApplicationCalifornia Law (Senate Bill 350) requires the CPUC, 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) primarily related to make-ready infrastructure for TE in medium to heavy-duty vehicle sectors. The CPUC may issueCPUC's preliminary schedule anticipates a proposed decision on this requestphase one by April 2019.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 ninesix months ended SeptemberJune 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 recover suchany costs for clean-up and repair of the Utility's facilities through CEMA; the timing and outcome of the remaining wildfire investigations, by Cal Fire and the CPUC, including into the causes of the wildfires;wildfires and whetherthe extent to which the Utility maywill have liability associated with these fires; the timing and if liable for one or more fires,amount of insurance recoveries; whether the Utility wouldwill be able to recover all or partcosts in excess of such costs through insurance or through regulatory mechanisms toand the extent insurance is not available or exhausted; as well astiming of such recovery; 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, and the timing and outcome of pending wildfire costs in excesslegislation;insurance at a future date, and pending wildfire legislation;potential requestproceeding to recover such costs. Whilecost through rates;previously approved WEMA tracking accounts for San Diego Gas & Electric Companyand May 2018 submission to the FERC in 2010,connection with the CPUC currently is consideringimpact of the Tax Act on the Utility’s rate cases and its implementation plan;approveobtain full recovery of costs recorded by San Diego Gas & Electric Company in its WEMA. On August 22, 2017,significantly increased insurance premiums and 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;state and federalCPUC's investigations of natural gas and electric incidents, matters relating toand 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;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, 20172018, to reverse FERC’s decision granting PG&E a 50 basis point ROE incentive adder for continued participation in the CAISO and future legislative or regulatory actions that may be takenremanding the case to require the Utility 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 timing and outcome of existing and future SED notices of violations in connection with violations;Yuba City incident;the outcomesimpact of the CPUC’s data requests, includingcomments and 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;until its planned retirement; and whether the Utility will be able to successfully implement its retention and retraining and development programs for Diablo Canyon employees as a result of its planned retirement by 2024 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;CARBCalifornia Air Resources Board implement state environmental laws relating to GHG, renewable energy targets, energy efficiency standards, DERs, EVs, and similar matters, including whether the Utility is able to continue recovering associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations; and whether the Utility is able to timely recover its associated investment costs;whether the Utility’s climate change adaptation strategies are successful;PG&E’sthe Utility’s procurement service for CCAs;such proceedingthe implementation of the plan or reorganization 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.) September June 30, 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.SeptemberJune 30, 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 and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. Cal Fire’s report concluded that the wildfire was caused when a gray pine tree contactedelectric 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 incurred in connection with respondingprocedural schedule. The scoping memo directed the Utility to defendingfile 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 settling the San Bruno Fire Derivative Casesinitiatives related to safety culture and the Additional Derivative Cases, including certain fees and expenses for investigating these claims. The $18.3 million has been paid, withconsultant’s recommendations, the majority reflected in PG&E Corporation’sUtility’s corrective action program, and the Utility’s financial statementsresponse to certain specified safety incidents that occurred in 2013 through December 31, 2016.In addition, pursuant2015. The Utility submitted its testimony to the CPUC on January 8, 2018, indicating that it agrees with all of the recommendations from the consultant and supports their adoption by the CPUC. The parties submitted their reply testimonies on February 16, 2018, and on March 9, 2018, the parties submitted joint comments to the CPUC. The parties were not able to reach a settlement, agreement, and the proceeding continues following its procedural schedule.implement certain corporate governance therapeuticsultimately be adopted by the CPUC, and whether the CPUC will require that a portion of return on equity 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 tobe dependent on making safety progress as the Court and to the City of San Bruno summarizing the progress of the implementation of the corporate governance and gas operations therapeutics.For additional information regarding these matters, see “Part I, Item 3. Legal Proceedings”CPUC may define in the 2016 Form 10-K and subsequent quarterly reports 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, Del Norte, 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 also 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 derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court in November 2017, naming as defendants current and certain former members of the Board of Directors, and certain current and former officers, of PG&E Corporation and the Utility, mayand naming PG&E Corporation and the Utility as nominal defendants. In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California naming as defendants PG&E Corporation and certain current and former officers, and alleging material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety information in various PG&E Corporation public disclosures, respectively. PG&E Corporation and the Utility expect 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. Further, SB 819, introduced in the California Senate in January 2018, if it becomes law, would prohibit utilities from recovering costs in excess of insurance resulting from damages caused by such utilities’ facilities, if the CPUC determines that the utility did not reasonably construct, maintain, manage, control, or operate the facilities. 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 risks that PG&E Corporationthe Northern California wildfires, see Note 9 of the Notes to Condensed Consolidated Financial Statements in Item 1.Utility face with respect to wildfires, see “The Utility’s electricity and natural gas operations are inherently hazardous and involve significant risks which, if they materialize, can adversely affect PG&E Corporation’s and the Utility’s financial results. The Utility’s insurance may not be sufficient to cover losses caused by an operating failure or catastrophic event, or may not become available at a reasonable cost, or available at all” in Item 1A. Risk Factors of the 2016 Form 10-K.affected by the ultimate amount of third-party liability that the Utility incurs in connections with 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 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.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 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 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. 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 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. While the Utility filed an application withOn June 21, 2018, the CPUC requesting approvalapproved the Utility’s application to establish a WEMA to track wildfire expenses and to preserve the opportunity for the Utility to request recovery of wildfire costs that have not otherwise been recovered through in insurance or other mechanisms, the Utility cannot predict the outcome of this proceeding. If the Utility is unablemechanisms. (See “Regulatory Matters - Application to recover all orEstablish a significant portion of such excess costs, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected.The electric power industry is undergoing significant change driven by technological advancements and a decarbonized economy, which could materially impact the Utility’s operations, financial condition, and results of operations.The electric power industry is 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 changeWildfire Expense Memorandum Account” in the federal approach to such matters. California utilities 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 growth 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.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).To this end, the CPUC is conducting proceedings to: evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of DERs; 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 creation of a shared database or statewide census of utility poles 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. The Utility is unable to predict the outcome of these proceedings. In addition, the CPUC has recently opened 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. While the CPUC had indicated intent to open an OIR related to customer choice, the Utility is unable to predict if and when the CPUC may open an OIR. 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.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, thereThere can be no assurance that the Utility will be ableallowed to preventrecover costs recorded in WEMA in the unauthorized accessfuture. While the CPUC previously approved WEMA tracking accounts for San Diego Gas & Electric Company in 2010, in December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it incurred as a result of the doctrine of inverse condemnation, holding that the inverse condemnation principles of strict liability are not relevant to its operational networks, information technology systems or data, or the disruption of its operations. Such events could subjectCPUC’s prudent manager standard. San Diego Gas & Electric, the Utility, to significant expenses, claimsand Southern California Edison filed requests for rehearing of that decision. On July 12, 2018, the CPUC voted out a decision denying the requests for rehearing. customerssuch utilities’ facilities, if the CPUC determines that the Utility did not reasonably construct, maintain, manage, control, or third parties, government inquiries, investigations,operate the facilities.regulatorythe Utility have considered certain actions that could resultmight be taken to attempt to address liquidity needs of the business in finessuch circumstances, but the inability to recover all or a significant portion of costs in excess of insurance through increases in rates and penalties,by collecting such rates in a timely manner, or any negative assessment by the Utility of the likelihood or timeliness of such recovery and loss of customers, any of whichcollection, 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 ratesoperations, liquidity, and cash flows.Utility believes are reasonable or that the costs of responding to and recovering from a cyber incidentUtility’s financial results will be coveredaffected by insurance or recoverable in rates.their ability to continue accessing the capital markets and by the terms of debt and equity financings.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 will continue to seek funds in the capital and credit markets to enable the Utility to make capital investments, and to pay fines that may be imposed in the future, as well as legal and regulatory costs. PG&E Corporation’s and the Utility’s ability to access the capital and credit markets and the costs and terms of available financing depend primarily on PG&E Corporation’s and the Utility’s credit ratings and outlook. Their credit ratings and outlook can be affected by many factors, including pending or anticipated litigation, the pending Cal Fire and CPUC investigations and CPUC ratemaking proceedings, substantial legislative or judicial changes to the application of inverse condemnation, and by the December 20, 2017 decision of the Boards of Directors of PG&E Corporation and the Utility to suspend dividends, as well as the perceived impact of all such matters on PG&E Corporation’s and the Utility’s financial condition, whether or not such perception is accurate.experienceaffect the stock price.including decreased electricity market revenues,to PG&E Corporation and the Utility. Any such event could have a material effect on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, liquidity, and cash flows. Any of such events also could lead to significant claims against the Utility. Further, these events could result 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 ratesregulatory penalties and disallowances, particularly if the Utility is permittedencounters difficulties in restoring power 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 reliescustomers on a limited numbertimely basis or if the related losses are found to be the result of suppliersthe Utility’s practices and/or the failure of electric and in some cases, sole suppliers. Inother equipment of 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. AlthoughUtility.long-term agreements with such suppliers, ifbeen studying the suppliers are unablepotential effects of climate change (increased temperatures, changing precipitation patterns, rising sea levels) on the Utility’s operations and is developing contingency plans to deliver these technologies, products or services,adapt to those events and conditions that the Utility could experience delaysbelieves are most significant. Scientists project that climate change will increase electricity demand due to more extreme, persistent and disruptions while it implements alternative plans and makes arrangements with acceptable substitute suppliers.hot weather. As a result, the Utility’s business,hydroelectric generation could change and the Utility would need to consider managing or acquiring additional generation. If the Utility increases its reliance on conventional generation resources to replace hydroelectric generation and to meet increased customer demand, it may become more costly for the Utility to comply with GHG emissions limits. In addition, flooding caused by rising sea levels could damage the Utility’s facilities, including generation and electric transmission and distribution assets. The Utility could incur substantial costs to repair or replace facilities, restore service, or compensate customers and other third parties for damages or injuries. The Utility anticipates that the increased costs would be recovered through rates, but as rate pressures increase, the likelihood of disallowance or non-recovery may increase. and results of operations, liquidity, and cash flows could be significantlymaterially 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 electricusage dataoperations are inherently hazardous and involve significant risks which, if they materialize, can adversely affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. customers. Ifnatural gas storage facilities; releases of greenhouse gases; flaking lead-based paint from the Utility’s facilities, and leaking or spilled insulating fluid from electrical equipment; andsuppliers encounter performanceevents could interrupt fuel supplies; affect demand for electricity or natural gas; cause unplanned outages or reduce generating output; damage the Utility’s assets or operations; damage the assets or operations of third parties on which the Utility relies; damage property owned by customers or others; and cause personal injury or death. As a result, the Utility could incur costs to purchase replacement power, to repair assets and restore service, and to compensate third parties. Any of such incidents also could lead to significant claims against the Utility.arein obtaining 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 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.supply these devicespredict whether it would be allowed to recover in rates the increased costs of insurance or maintainthe costs of any uninsured losses. update their software, or provide other services to maintain these systems, the Utility’s metering, billing,financial condition, results of operations, liquidity, and electric network operationscash flows could be impacted and disrupted.PROCEEDSSeptemberJune 30, 2017,2018, 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.SeptemberJune 30, 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 SeptemberJune 30, 2017,2018, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.OTHEROTHER INFORMATIONEarningsEarnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividendsninesix months ended SeptemberJune 30, 20172018 was 2.60.(0.41). The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the ninesix months ended SeptemberJune 30, 20172018 was 2.58.(0.40). 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.ninesix months ended SeptemberJune 30, 20172018 was 2.62.(0.40). 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*10.110.1 *10.2 12.1*10.4 12.1 PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY DAVIDDAVID S. THOMASON
(duly authorized officer and principal financial officer)