Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E Corporation

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year ended December 31,
	2018				2017				2016
Operating Revenues
Electric	$	12,713			$	13,124			$	13,864
Natural gas	4,046				4,011				3,802
Total operating revenues	16,759				17,135				17,666
Operating Expenses
Cost of electricity	3,828				4,309				4,765
Cost of natural gas	671				746				615
Operating and maintenance	7,153				6,321				7,326
Wildfire-related claims, net of insurance recoveries	11,771				—				125
Depreciation, amortization, and decommissioning	3,036				2,854				2,755
Total operating expenses	26,459				14,230				15,586
Operating Income (Loss)	(9,700		)		2,905				2,080
Interest income	76				31				23
Interest expense	(929		)		(888		)		(829		)
Other income, net	424				123				188
Income (Loss) Before Income Taxes	(10,129		)		2,171				1,462
Income tax provision (benefit)	(3,292		)		511				55
Net Income (Loss)	(6,837		)		1,660				1,407
Preferred stock dividend requirement of subsidiary	14				14				14
Income (Loss) Available for Common Shareholders	$	(6,851	)		$	1,646			$	1,393
Weighted Average Common Shares Outstanding, Basic	517				512				499
Weighted Average Common Shares Outstanding, Diluted	517				513				501
Net Earnings (Loss) Per Common Share, Basic	$	(13.25	)		$	3.21			$	2.79
Net Earnings (Loss) Per Common Share, Diluted	$	(13.25	)		$	3.21			$	2.78

See accompanying Notes to the Consolidated Financial Statements.

PG&E Corporation

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2018				2017				2016
Net Income (Loss)	$	(6,837	)		$	1,660			$	1,407
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $2, $0, and $1, at respective dates)	4				1				(2		)
Total other comprehensive income (loss)	4				1				(2		)
Comprehensive Income (Loss)	(6,833		)		1,661				1,405
Preferred stock dividend requirement of subsidiary	14				14				14
Comprehensive Income (Loss) Attributable to Common Shareholders	$	(6,847	)		$	1,647			$	1,391

See accompanying Notes to the Consolidated Financial Statements.

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2018				2017
ASSETS
Current Assets
Cash and cash equivalents	$	1,668			$	449
Accounts receivable
Customers (net of allowance for doubtful accounts of $56 and $64 at respective dates)	1,148				1,243
Accrued unbilled revenue	1,000				946
Regulatory balancing accounts	1,435				1,222
Other	2,686				861
Regulatory assets	233				615
Inventories
Gas stored underground and fuel oil	111				115
Materials and supplies	443				366
Income taxes receivable	23				—
Other	448				464
Total current assets	9,195				6,281
Property, Plant, and Equipment
Electric	59,150				55,133
Gas	21,556				19,641
Construction work in progress	2,564				2,471
Other	2				3
Total property, plant, and equipment	83,272				77,248
Accumulated depreciation	(24,715		)		(23,459		)
Net property, plant, and equipment	58,557				53,789
Other Noncurrent Assets
Regulatory assets	4,964				3,793
Nuclear decommissioning trusts	2,730				2,863
Income taxes receivable	69				65
Other	1,480				1,221
Total other noncurrent assets	9,243				7,942
TOTAL ASSETS	$	76,995			$	68,012

See accompanying Notes to the Consolidated Financial Statements.

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2018				2017
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	3,435			$	931
Long-term debt, classified as current	18,559				445
Accounts payable
Trade creditors	1,975				1,646
Regulatory balancing accounts	1,076				1,120
Other	464				517
Disputed claims and customer refunds	220				243
Interest payable	228				217
Wildfire-related claims	14,226				561
Other	1,512				1,449
Total current liabilities	41,695				7,129
Noncurrent Liabilities
Long-term debt	—				17,753
Regulatory liabilities	8,539				8,679
Pension and other postretirement benefits	2,119				2,128
Asset retirement obligations	5,994				4,899
Deferred income taxes	3,281				5,822
Other	2,464				2,130
Total noncurrent liabilities	22,397				41,411
Contingencies and Commitments (Notes 13 and 14)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares; 520,338,710 and 514,755,845 shares outstanding at respective dates	12,910				12,632
Reinvested earnings	(250		)		6,596
Accumulated other comprehensive loss	(9		)		(8		)
Total shareholders' equity	12,651				19,220
Noncontrolling Interest - Preferred Stock of Subsidiary	252				252
Total equity	12,903				19,472
TOTAL LIABILITIES AND EQUITY	$	76,995			$	68,012

See accompanying Notes to the Consolidated Financial Statements.

PG&E Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2018				2017				2016
Cash Flows from Operating Activities
Net income (loss)	$	(6,837	)		$	1,660			$	1,407
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,036				2,854				2,755
Allowance for equity funds used during construction	(129		)		(89		)		(112		)
Deferred income taxes and tax credits, net	(2,532		)		1,254				1,030
Disallowed capital expenditures	(45		)		47				507
Other	332				307				379
Effect of changes in operating assets and liabilities:
Accounts receivable	(121		)		67				(473		)
Wildfire-related insurance receivable	(1,698		)		(21		)		(575		)
Inventories	(73		)		(18		)		(24		)
Accounts payable	409				173				180
Wildfire-related claims	13,665				(129		)		690
Income taxes receivable/payable	(23		)		160				(5		)
Other current assets and liabilities	(281		)		42				83
Regulatory assets, liabilities, and balancing accounts, net	(800		)		(387		)		(1,214		)
Other noncurrent assets and liabilities	(151		)		57				(219		)
Net cash provided by operating activities	4,752				5,977				4,409
Cash Flows from Investing Activities
Capital expenditures	(6,514		)		(5,641		)		(5,709		)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,412				1,291				1,295
Purchases of nuclear decommissioning trust investments	(1,485		)		(1,323		)		(1,352		)
Other	23				23				13
Net cash used in investing activities	(6,564		)		(5,650		)		(5,753		)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities	3,960				—				—
Repayments under revolving credit facilities	(775		)		—				—
Net issuances (repayments) of commercial paper, net of discount of $1, $5, and $6 at respective dates	(182		)		(840		)		(9		)
Short-term debt financing	600				750				500
Short-term debt matured	(750		)		(500		)		—
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $7, $32, and $17 at respective dates	793				2,713				983
Long-term debt matured or repurchased	(795		)		(1,445		)		(160		)
Common stock issued	200				395				822
Common stock dividends paid	—				(1,021		)		(921		)
Other	(20		)		(107		)		(44		)
Net cash provided by (used in) financing activities	3,031				(55		)		1,171
Net change in cash, cash equivalents, and restricted cash	1,219				272				(173		)
Cash, cash equivalents, and restricted cash at January 1	456				184				357
Cash, cash equivalents, and restricted cash at December 31	$	1,675			$	456			$	184
Less: Restricted cash and restricted cash equivalents	(7		)		(7		)		(7		)
Cash and cash equivalents at December 31	$	1,668			$	449			$	177

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(786	)		$	(790	)		$	(726	)
Income taxes, net	(49		)		162				231
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	—			$	—			$	248
Capital expenditures financed through accounts payable	368				501				403
Noncash common stock issuances	—				21				20

See accompanying Notes to the Consolidated Financial Statements.

PG&E Corporation

CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)

	Common Stock Shares			Common Stock Amount				Reinvested Earnings				Accumulated Other Comprehensive Income (Loss)				Total Shareholders' Equity				Non controlling Interest - Preferred Stock of Subsidiary				Total Equity
Balance at December 31, 2015	492,025,443			$	11,282			$	5,301			$	(7	)		$	16,576			$	252			$	16,828
Cumulative effect of change in accounting principle	—			—				29				—				29				—				29
Net income	—			—				1,407				—				1,407				—				1,407
Other comprehensive income	—			—				—				(2		)		(2		)		—				(2		)
Common stock issued, net	14,866,431			842				—				—				842				—				842
Stock-based compensation amortization	—			74				—				—				74				—				74
Common stock dividends declared	—			—				(972		)		—				(972		)		—				(972		)
Preferred stock dividend requirement of subsidiary	—			—				(14		)		—				(14		)		—				(14		)
Balance at December 31, 2016	506,891,874			$	12,198			$	5,751			$	(9	)		$	17,940			$	252			$	18,192
Net income	—			—				1,660				—				1,660				—				1,660
Other comprehensive loss	—			—				—				1				1				—				1
Common stock issued, net	7,863,971			416				—				—				416				—				416
Stock-based compensation amortization	—			18				—				—				18				—				18
Common stock dividends declared	—			—				(801		)		—				(801		)		—				(801		)
Preferred stock dividend requirement of subsidiary	—			—				(14		)		—				(14		)		—				(14		)
Balance at December 31, 2017	514,755,845			$	12,632			$	6,596			$	(8	)		$	19,220			$	252			$	19,472
Net income (loss)	—			—				(6,837		)		—				(6,837		)		—				(6,837		)
Other comprehensive loss	—			—				5				(1		)		4				—				4
Common stock issued, net	5,582,865			200				—				—				200				—				200
Stock-based compensation amortization	—			78				—				—				78				—				78
Preferred stock dividend requirement of subsidiary	—			—				(14		)		—				(14		)		—				(14		)
Balance at December 31, 2018	520,338,710			$	12,910			$	(250	)		$	(9	)		$	12,651			$	252			$	12,903

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

	Year ended December 31,
	2018				2017				2016
Operating Revenues
Electric	$	12,713			$	13,127			$	13,865
Natural gas	4,047				4,011				3,802
Total operating revenues	16,760				17,138				17,667
Operating Expenses
Cost of electricity	3,828				4,309				4,765
Cost of natural gas	671				746				615
Operating and maintenance	7,153				6,383				7,327
Wildfire-related claims, net of insurance recoveries	11,771				—				125
Depreciation, amortization, and decommissioning	3,036				2,854				2,754
Total operating expenses	26,459				14,292				15,586
Operating Income (Loss)	(9,699		)		2,846				2,081
Interest income	74				30				22
Interest expense	(914		)		(877		)		(819		)
Other income, net	426				119				188
Income (Loss) Before Income Taxes	(10,113		)		2,118				1,472
Income tax provision (benefit)	(3,295		)		427				70
Net Income (Loss)	(6,818		)		1,691				1,402
Preferred stock dividend requirement	14				14				14
Income (Loss) Available for Common Stock	$	(6,832	)		$	1,677			$	1,388

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2018				2017				2016
Net Income (Loss)	$	(6,818	)		$	1,691			$	1,402
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $2, $3, and $1, at respective dates)	(5		)		4				(1		)
Total other comprehensive income (loss)	(5		)		4				(1		)
Comprehensive Income (Loss)	$	(6,823	)		$	1,695			$	1,401

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2018				2017
ASSETS
Current Assets
Cash and cash equivalents	$	1,295			$	447
Accounts receivable
Customers (net of allowance for doubtful accounts of $56 and $64 at respective dates)	1,148				1,243
Accrued unbilled revenue	1,000				946
Regulatory balancing accounts	1,435				1,222
Other	2,688				862
Regulatory assets	233				615
Inventories
Gas stored underground and fuel oil	111				115
Materials and supplies	443				366
Income taxes receivable	5				—
Other	448				465
Total current assets	8,806				6,281
Property, Plant, and Equipment
Electric	59,150				55,133
Gas	21,556				19,641
Construction work in progress	2,564				2,471
Total property, plant, and equipment	83,270				77,245
Accumulated depreciation	(24,713		)		(23,456		)
Net property, plant, and equipment	58,557				53,789
Other Noncurrent Assets
Regulatory assets	4,964				3,793
Nuclear decommissioning trusts	2,730				2,863
Income taxes receivable	66				64
Other	1,348				1,094
Total other noncurrent assets	9,108				7,814
TOTAL ASSETS	$	76,471			$	67,884

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2018				2017
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	3,135			$	799
Long-term debt, classified as current	18,209				445
Accounts payable
Trade creditors	1,972				1,644
Regulatory balancing accounts	1,076				1,120
Other	498				538
Disputed claims and customer refunds	220				243
Interest payable	227				214
Wildfire-related claims	14,226				561
Other	1,497				1,457
Total current liabilities	41,060				7,021
Noncurrent Liabilities
Long-term debt	—				17,403
Regulatory liabilities	8,539				8,679
Pension and other postretirement benefits	2,026				2,026
Asset retirement obligations	5,994				4,899
Deferred income taxes	3,405				5,963
Other	2,492				2,146
Total noncurrent liabilities	22,456				41,116
Contingencies and Commitments (Notes 13 and 14)
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	8,550				8,505
Reinvested earnings	2,826				9,656
Accumulated other comprehensive (loss) income	(1		)		6
Total shareholders' equity	12,955				19,747
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	76,471			$	67,884

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2018				2017				2016
Cash Flows from Operating Activities
Net income (loss)	$	(6,818	)		$	1,691			$	1,402
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,036				2,854				2,754
Allowance for equity funds used during construction	(129		)		(89		)		(112		)
Deferred income taxes and tax credits, net	(2,548		)		1,103				1,042
Disallowed capital expenditures	(45		)		47				507
Other	258				283				306
Effect of changes in operating assets and liabilities:
Accounts receivable	(122		)		66				(475		)
Wildfire-related insurance receivable	(1,698		)		(21		)		(575		)
Inventories	(73		)		(18		)		(24		)
Accounts payable	421				173				179
Wildfire-related claims	13,665				(129		)		690
Income taxes receivable/payable	(5		)		159				(29		)
Other current assets and liabilities	(301		)		59				112
Regulatory assets, liabilities, and balancing accounts, net	(800		)		(390		)		(1,214		)
Other noncurrent assets and liabilities	(137		)		128				(219		)
Net cash provided by operating activities	4,704				5,916				4,344
Cash Flows from Investing Activities
Capital expenditures	(6,514		)		(5,641		)		(5,709		)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,412				1,291				1,295
Purchases of nuclear decommissioning trust investments	(1,485		)		(1,323		)		(1,352		)
Other	23				23				13
Net cash used in investing activities	(6,564		)		(5,650		)		(5,753		)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities	3,535				—				—
Repayments under revolving credit facilities	(650		)		—				—
Net issuances (repayments) of commercial paper, net of discount of $0, $5, and $6 at respective dates	(50		)		(972		)		(9		)
Short-term debt financing	250				750				500
Short-term debt matured	(750		)		(500		)		—
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $7, $32, and $17 at respective dates	793				2,713				983
Long-term debt matured or repurchased	(445		)		(1,445		)		(160		)
Preferred stock dividends paid	—				(14		)		(14		)
Common stock dividends paid	—				(784		)		(911		)
Equity contribution from PG&E Corporation	45				455				835
Other	(20		)		(93		)		(30		)
Net cash provided by financing activities	2,708				110				1,194
Net change in cash, cash equivalents, and restricted cash	848				376				(215		)
Cash, cash equivalents, and restricted cash at January 1	454				78				293
Cash, cash equivalents, and restricted cash at December 31	$	1,302			$	454			$	78
Less: Restricted cash and restricted cash equivalents	(7		)		(7		)		(7		)
Cash and cash equivalents at December 31	$	1,295			$	447			$	71

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(773	)		$	(781	)		$	(717	)
Income taxes, net	(59		)		162				244
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	368			$	501			$	403

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in millions)

	Preferred Stock				Common Stock				Additional Paid-in Capital				Reinvested Earnings				Accumulated Other Comprehensive Income (Loss)				Total Shareholders' Equity
Balance at December 31, 2015	$	258			$	1,322			$	7,215			$	8,262			$	3			$	17,060
Cumulative effect of change in accounting principle	—				—				—				24				—				24
Net income	—				—				—				1,402				—				1,402
Other comprehensive income	—				—				—				—				(1		)		(1		)
Equity contribution	—				—				835				—				—				835
Common stock dividend	—				—				—				(911		)		—				(911		)
Preferred stock dividend	—				—				—				(14		)		—				(14		)
Balance at December 31, 2016	$	258			$	1,322			$	8,050			$	8,763			$	2			$	18,395
Net income	—				—				—				1,691				—				1,691
Other comprehensive loss	—				—				—				—				4				4
Equity contribution	—				—				455				—				—				455
Common stock dividend	—				—				—				(784		)		—				(784		)
Preferred stock dividend	—				—				—				(14		)		—				(14		)
Balance at December 31, 2017	$	258			$	1,322			$	8,505			$	9,656			$	6			$	19,747
Net income (loss)	—				—				—				(6,818		)		—				(6,818		)
Other comprehensive loss	—				—				—				2				(7		)		(5		)
Equity contribution	—				—				45				—				—				45
Preferred stock dividend	—				—				—				(14		)		—				(14		)
Balance at December 31, 2018	$	258			$	1,322			$	8,550			$	2,826			$	(1	)		$	12,955

See accompanying Notes to the Consolidated Financial Statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

Organization and Basis of Presentation

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).

The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s wildfire-related liabilities, legal and regulatory contingencies, environmental remediation liabilities, insurance receivables, regulatory assets and liabilities, AROs, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.

Chapter 11 Filing and Going Concern

The accompanying Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. However, as a result of the challenges that are further described below, such realization of assets and satisfaction of liabilities are subject to uncertainty. PG&E Corporation and the Utility are facing extraordinary challenges relating to a series of catastrophic wildfires that occurred in Northern California in 2017 and 2018. See Note 13 below. Uncertainty regarding these matters raises substantial doubt about PG&E Corporation's and the Utility's abilities to continue as going concerns. PG&E Corporation and the Utility have determined that commencing reorganization cases under Chapter 11 is necessary to restore PG&E Corporation's and the Utility's financial stability to fund ongoing operations and provide safe service to customers. However, there can be no assurance that such proceedings will restore PG&E Corporation's and the Utility's financial stability. On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. See Note 15 below. The Consolidated Financial Statements do not include any adjustments that might be necessary should PG&E Corporation and the Utility be unable to continue as going concerns.

Pursuant to Chapter 11, PG&E Corporation and the Utility retain control of their assets and are authorized to operate their business as debtors in possession while being subject to the jurisdiction of the Bankruptcy Court. While operating as debtors in possession under Chapter 11, PG&E Corporation and the Utility may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business and subject to restrictions in PG&E Corporation's and the Utility's DIP Credit Agreement (see Note 4 and Note 15 below) and applicable orders of the Bankruptcy Court, for amounts other than those reflected in the accompanying Consolidated Financial Statements. Any such actions occurring during the Chapter 11 Cases confirmed by the Bankruptcy Court could materially impact the amounts and classifications of assets and liabilities reported in PG&E Corporation's and the Utility's Consolidated Financial Statements.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Loss Contingencies

A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred.

Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. See “Revenue Recognition” below.

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

Revenue Recognition

Revenue from Contracts with Customers

The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

The FERC authorizes the Utility’s revenue requirements in periodic TO rate cases. The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled, net of a reserve for revenues subject to refund.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three or four years. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year.

The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.

The following table presents the Utility’s revenues disaggregated by type of customer:

(in millions)	Year Ended December 31, 2018
Electric
Revenue from contracts with customers
Residential	$	5,051
Commercial	4,908
Industrial	1,532
Agricultural	1,234
Public street and highway lighting	72
Other (1)	(720		)
Total revenue from contracts with customers - electric	12,077
Regulatory balancing accounts (2)	636
Total electric operating revenue	$	12,713
Natural gas
Revenue from contracts with customers
Residential	$	2,042
Commercial	537
Transportation service only	1,151
Other (1)	75
Total revenue from contracts with customers - gas	3,805
Regulatory balancing accounts (2)	242
Total natural gas operating revenue	4,047
Total operating revenues	$	16,760

(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.

(2) These amounts represent revenues authorized to be billed or refunded to customers.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value.

Allowance for Doubtful Accounts Receivable

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.

Inventories

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.

Emission Allowances

The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.

Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:

	Estimated Useful		Balance at December 31,
(in millions, except estimated useful lives)	Lives (years)		2018				2017
Electricity generating facilities (1)	5 to 120		$	13,047			$	11,843
Electricity distribution facilities	15 to 65		32,926				31,110
Electricity transmission facilities	15 to 75		13,177				12,180
Natural gas distribution facilities	20 to 60		13,296				12,312
Natural gas transmission and storage facilities	5 to 62		8,260				7,329
Construction work in progress			2,564				2,471
Total property, plant, and equipment			83,270				77,245
Accumulated depreciation			(24,713		)		(23,456		)
Net property, plant, and equipment			$	58,557			$	53,789

(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 14 below.)

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.82% in 2018, 3.83% in 2017, and 3.73% in 2016. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.

AFUDC

AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt and equity, respectively, of $53 million and $129 million during 2018, $38 million and $89 million during 2017, and $51 million and $112 million during 2016.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2018 and 2017, including nuclear decommissioning obligations:

(in millions)	2018				2017
ARO liability at beginning of year	$	4,899			$	4,684
Revision in estimated cash flows	993				128
Accretion	211				207
Liabilities settled	(109		)		(120		)
ARO liability at end of year	$	5,994			$	4,899

The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements.

Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC. In December 2018, the Utility submitted its updated decommissioning cost estimate to the CPUC and correspondingly increased its ARO liabilities by $1.1 billion. The adjustment was a result of increased estimated costs based on a site-specific decommissioning analysis. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The total nuclear decommissioning obligation accrued was $4.7 billion and $3.5 billion at December 31, 2018 and 2017, respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion and $7.0 billion at December 31, 2018 and 2017, respectively.

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. See “Enforcement and Litigation Matters” in Note 14 below.

Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.

The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification.

Variable Interest Entities

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2018, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2018, it did not consolidate any of them.

Other Accounting Policies

For other accounting policies impacting PG&E Corporation’s and the Utility’s consolidated financial statements, see “Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies and Commitments” in Notes 13 and 14 herein.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2018 consisted of the following:

(in millions, net of income tax)	Pension Benefits				Other Benefits				Total
Beginning balance	$	(25	)		$	17			$	(8	)
Other comprehensive income before reclassifications:
Unrecognized net actuarial loss (net of taxes of $41 and $9, respectively)	(104		)		(23		)		(127		)
Regulatory account transfer (net of taxes of $41 and $9, respectively)	107				23				130
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)	(4		)		10				6
Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) (1)	3				(4		)		(1		)
Regulatory account transfer (net of taxes of $1 and $3, respectively) (1)	2				(6		)		(4		)
Net current period other comprehensive loss	4				—				4
Ending balance	$	(21	)		$	17			$	(4	)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2017 consisted of the following:

(in millions, net of income tax)	Pension Benefits				Other Benefits				Total
Beginning balance	$	(25	)		$	16			$	(9	)
Other comprehensive income before reclassifications:
Unrecognized prior service cost (net of taxes of $4 and $0, respectively)	(6		)		—				(6		)
Unrecognized net actuarial loss (net of taxes of $229 and $97, respectively)	333				141				474
Regulatory account transfer (net of taxes of $225 and $97, respectively)	(327		)		(141		)		(468		)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $3 and $6, respectively) (1)	(4		)		9				5
Amortization of net actuarial loss (net of taxes of $9 and $2, respectively) (1)	13				2				15
Regulatory account transfer (net of taxes of $6 and $8, respectively) (1)	(9		)		(10		)		(19		)
Net current period other comprehensive loss	—				1				1
Ending balance	$	(25	)		$	17			$	(8	)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)

Recently Adopted Accounting Standards

Revenue Recognition Standard

In May 2014, the FASB issued ASU No. 2014-9, Revenue from Contracts with Customers (Topic 606), which amends the previous revenue recognition guidance. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. PG&E Corporation and the Utility applied the requirements using the modified retrospective method when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the year ended December 31, 2018. A majority of the Utility’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customers' monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer. See "Revenue Recognition" above.

Restricted Cash

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230), which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning and end of period total amounts shown on the statement of cash flows. Previously, changes in restricted cash were reported within cash flows from investing activities. PG&E Corporation and the Utility applied the requirements on a retrospective basis when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the year ended December 31, 2018.

The retrospective adjustments to the Consolidated Statements of Cash Flows for PG&E Corporation and the Utility resulted in an increase to Net cash used in investing activities of $227 million, an increase to Cash, cash equivalents and restricted cash at January 1 by $234 million, and an increase to Cash, cash equivalents and restricted cash at December 31 by $7 million for the year ended December 31, 2016.

Presentation of Net Periodic Pension and Post-Retirement Benefit Costs

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715), which amends the guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. PG&E Corporation and the Utility applied the requirements when the ASU became effective on January 1, 2018.

On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. As a result, the 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 $51 million and $54 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2017 and $97 million and $100 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2016.

On a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The FERC has allowed and the Utility has made a one-time election to adopt the new FASB guidance for regulatory filing purposes. In January 2018, the CPUC approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the service cost component determined by a plan’s actuary. The capitalization of service costs only results in higher rate base and a reduction in the Utility’s 2018 revenues. The changes in capitalization of retirement benefits did not have a material impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which amends the guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income. The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts and gains or losses are refundable or recoverable, respectively, from customers through rates, therefore gains and losses are deferred and recognized as regulatory assets or liabilities. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 and did not have a material impact on the Consolidated Financial Statements and related disclosures.

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Act. When amounts are reclassified from accumulated other comprehensive income to the Consolidated Statement of Income, PG&E Corporation and the Utility recognize the related income tax expense at the tax rate in effect at that time. The ASU is effective for PG&E Corporation and the Utility on January 1, 2019, and early adoption is permitted. PG&E Corporation and the Utility early adopted this ASU on January 1, 2018, resulting in an immaterial reclassification.

Accounting Standards Issued But Not Yet Adopted

Recognition of Lease Assets and Liabilities

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the guidance relating to the definition of a lease, recognition of ROU 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 ROU asset and lease liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU became effective for PG&E Corporation and the Utility on January 1, 2019.

PG&E Corporation and the Utility elected certain practical expedients and will carry forward historical conclusions related to (1) contracts that contain leases, (2) existing lease and easement classification, and (3) initial direct costs. Additionally, PG&E Corporation and the Utility do not intend to restate comparative periods upon adoption.

PG&E Corporation and the Utility plan to adopt this guidance in the first quarter of 2019. PG&E Corporation and the Utility will apply the requirements using the modified retrospective method. PG&E Corporation and the Utility expect this standard to increase ROU assets and liabilities by approximately $2.5 billion to $3.0 billion on the Consolidated Balance Sheets and will result in additional footnote disclosures, but do not expect the guidance will have a material impact on the Consolidated Statements of Income and Statements of Cash Flows. The majority of PG&E Corporation and the Utility's leases are power purchase agreements.

Fair Value Measurement

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurements, which amends the existing guidance relating to the disclosure requirements for fair value measurements. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

Intangibles-Goodwill and Other

In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at December 31,								Recovery Period
(in millions)	2018				2017
Pension benefits (1)	$	1,947			$	1,954			Indefinitely
Environmental compliance costs	1,013				837				32 years
Utility retained generation (2)	274				319				8 years
Price risk management	90				65				10 years
Unamortized loss, net of gain, on reacquired debt	76				79				25 years
Catastrophic event memorandum account (3)	790				274				TBD years
Wildfire expense memorandum account (4)	94				—				TBD years
Fire hazard prevention memorandum account (5)	263				1				TBD years
Other	417				264				Various
Total long-term regulatory assets	$	4,964			$	3,793

(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.

(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.

(3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. Recovery of CEMA costs are subject to CPUC review and approval.

(4) Includes specific incremental wildfire liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are subject to CPUC review and approval.

(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs are subject to CPUC review and approval.

In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2018				2017
Cost of removal obligations (1)	$	5,981			$	5,547
Deferred income taxes (2)	283				1,021
Recoveries in excess of AROs (3)	356				624
Public purpose programs (4)	674				590
Retirement Plan (5)	421				418
Other	824				479
Total long-term regulatory liabilities	$	8,539			$	8,679

(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

(2) Represents the net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of deferred taxes subject to flow-through treatment. (See Note 8 below.)

(3) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 10 below.)

(4) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.

(5) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long Term Disability Plans.

Regulatory Balancing Accounts

The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets. These differences do not have an impact on net income. Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.

Current regulatory balancing accounts receivable and payable are comprised of the following:

	Receivable Balance at December 31,
(in millions)	2018				2017
Electric distribution	$	160			$	—
Electric transmission	128				139
Utility generation	79				—
Gas distribution and transmission	462				486
Energy procurement	168				71
Public purpose programs	111				103
Other	327				423
Total regulatory balancing accounts receivable	$	1,435			$	1,222

	Payable Balance at December 31,
(in millions)	2018				2017
Electric distribution	$	—			$	72
Electric transmission	134				120
Utility generation	—				14
Gas distribution and transmission	9				—
Energy procurement	59				149
Public purpose programs	587				452
Other	287				313
Total regulatory balancing accounts payable	$	1,076			$	1,120

The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case. Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency.

NOTE 4: DEBT

Debtor In Possession ("DIP") Facilities

In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into a Senior Secured Superpriority Debtor in Possession Credit, Guaranty and Security Agreement, dated as of February 1, 2019 (the “DIP Credit Agreement”), among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto (together with such other financial institutions from time to time party thereto, the "DIP Lenders"). The DIP Credit Agreement provides for $5.5 billion in senior secured superpriority debtor in possession credit facilities in the form of (i) a revolving credit facility in an aggregate amount of $3.5 billion (the “DIP Revolving Facility”), including a $1.5 billion letter of credit subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term loan facility in an aggregate principal amount of $500 million (the “DIP Delayed Draw Term Loan Facility”, together with the DIP Revolving Facility and the DIP Initial Term Loan Facility, the “DIP Facilities”), subject to the terms and conditions set forth therein.

On the Petition Date, PG&E Corporation and the Utility filed a motion seeking, among other things, interim and final approval of the DIP Facilities, which motion was granted on an interim basis by the Bankruptcy Court following a hearing on January 31, 2019. As a result of the Bankruptcy Court’s interim approval of the DIP Facilities and the satisfaction of the other conditions thereof, the DIP Credit Agreement became effective on February 1, 2019 and a portion of the DIP Revolving Facility in the amount of $1.5 billion (including $750 million of the letter of credit subfacility) was made available to PG&E Corporation and the Utility. As of February 28, 2019, the remainder of the DIP Revolving Facility (including the remainder of the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility are unavailable for borrowing and will remain unavailable until and unless the Bankruptcy Court approves the availability thereof following a final hearing. PG&E Corporation and the Utility are unable to predict the date of the final hearing, but it is currently scheduled for March 13, 2019. There can be no assurances that the Bankruptcy Court will grant final approval of the DIP Facilities at the final hearing, or at all.

Borrowings under the DIP Facilities are senior secured obligations of the Utility, secured by substantially all of the Utility’s assets and entitled to superpriority administrative expense claim status in the Utility’s Chapter 11 Case. The Utility’s obligations under the DIP Facilities are guaranteed by PG&E Corporation, and such guarantee is a senior secured obligation of PG&E Corporation, secured by substantially all of PG&E Corporation’s assets and entitled to superpriority administrative expense claim status in PG&E Corporation’s Chapter 11 Case.

The DIP Facilities mature on December 31, 2020, subject to the Utility’s option to extend the maturity to December 31, 2021 if certain terms and conditions are satisfied, including the payment of an extension fee equal to 0.25% of the then-outstanding loans and available commitments. Borrowings under the DIP Facilities will bear interest based, at the Utility’s election, on (1) LIBOR plus an applicable margin or (2) ABR plus an applicable margin. ABR will equal the highest of the following: (i) the administrative agent’s announced base rate, (ii) 0.50% above the (x) federal funds effective rate or (y) the overnight federal funds rate, whichever is higher, (iii) one-month LIBOR plus 1.00% and (iv) zero. With respect to the DIP Revolving Facility, the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, the applicable margin is 2.25% for LIBOR loans and 1.25% for ABR loans.

The Utility is also required to pay unused fees of (i) 0.375% per annum in respect of the average daily unutilized commitments under the DIP Revolving Facility and (ii) 1.125% per annum, which amount shall increase to 2.25% per annum after six months, in respect of the average daily unutilized commitments under the DIP Delayed Draw Term Loan Facility. The Utility must also pay (x) a fee equal to the applicable margin with respect to LIBOR loans under the DIP Revolving Facility on the aggregate drawable amount of all outstanding letters of credit under the DIP Revolving Facility and (y) a fronting fee to the relevant issuing DIP Lender equal to 0.125% per annum of the aggregate drawable amount of outstanding letters of credit issued by such issuing DIP Lender.

The DIP Credit Agreement includes usual and customary covenants for debtor in possession loan agreements of this type, including covenants limiting PG&E Corporation’s and the Utility’s ability to, among other things, incur additional indebtedness, create liens on assets, make investments, loans or advances, engage in mergers, consolidations, sales of assets and acquisitions, pay dividends and distributions and make payments in respect of junior or pre-petition indebtedness, in each case subject to customary exceptions for debtor in possession loan agreements of this type.

The DIP Credit Agreement also includes customary and usual representations and warranties and affirmative covenants, including an obligation to deliver 13-week cash flow forecasts and reports showing variances from such forecasts, in each case on a rolling 4-week basis. PG&E Corporation’s and the Utility’s obligations under the DIP Credit Agreement may be accelerated following certain events of default, including payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to post-petition or unstayed indebtedness of PG&E Corporation and the Utility and their subsidiaries in excess of $200 million, certain events under ERISA, unstayed judgments in respect of post-petition obligations involving an aggregate liability in excess of $200 million, change of control, specified governmental actions having a material adverse effect or condemnation or damage to a material portion of the collateral. Certain bankruptcy-related events are also events of default, including, but not limited to, the dismissal by the Bankruptcy Court of any of the Chapter 11 Cases, the conversion of any of the Chapter 11 Cases to a case under chapter 7 of the Bankruptcy Code, the appointment of a trustee pursuant to Chapter 11, any order authorizing the DIP Facilities being stayed, vacated, reversed or amended in a manner adverse to the DIP Lenders, the final order approving the DIP Facilities failing to have been entered by April 15, 2019, and certain other events related to the impairment of the DIP Lenders’ rights or liens granted under the DIP Credit Agreement.

The proceeds of the borrowings under the DIP Facilities will be used for working capital and general corporate purposes and to pay fees, costs and expenses incurred in connection with the transactions contemplated by the DIP Credit Agreement and professional and other fees and costs of administration incurred in connection with the Chapter 11 Cases.

Long-Term Debt

Debt Obligations Previously Classified as Long Term

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:

		December 31,
(in millions)		2018				2017
PG&E Corporation
Term Loan:
Stated Maturity	Interest Rates
2020	variable rate (2)	350				350
Less: Current Portion (1)		(350		)		—
Total PG&E Corporation long-term debt		—				350
Utility
Senior notes:
Stated Maturity	Interest Rates
2018	8.25%	—				400
2020	3.50%	800				800
2021	3.25% to 4.25%	550				550
2022	2.45%	400				400
2023 through 2046	2.95% to 6.35%	15,775				14,975
Unamortized discount, net of premium and debt issuance costs		(178		)		(185		)
Less: current portion (1)		(17,347		)		(400		)
Total senior notes, net of current portion		—				16,540
Pollution control bonds:
Stated Maturity	Interest Rates
Series 2008 G, due 2018	1.05%	—				45
Series 2008 F and 2010 E, due 2026 (3)	1.75%	100				100
Series 2009 A-B, due 2026 (4)	variable rate (5)	149				149
Series 1996 C, E, F, 1997 B due 2026 (4)	variable rate (6)	614				614
Less: current portion (1)		(863		)		(45		)
Total pollution control bonds		—				863
Total Utility long-term debt, net of current portion		—				17,403
Total consolidated long-term debt, net of current portion		$	—			$	17,753

(1) On January 29, 2019, PG&E Corporation and the Utility commenced reorganization under Chapter 11 of the U.S. Bankruptcy Code. The commencement of the Chapter 11 Cases constituted an event of default or termination event under the above-referenced debt of PG&E Corporation and the Utility. With the exception of Pollution Control Bonds series 2008F and 2010E, where a trustee notice is required to trigger acceleration, the commencement of the Chapter 11 Cases caused an automatic and immediate acceleration of such debt, and the possibility of cure is uncertain. Therefore, all long-term debt is classified as current as of December 31, 2018.

(2) At December 31, 2018, the interest rate on the Term Loan was 3.66%.

(3) Pollution Control Bonds series 2008F and 2010E were remarketed and issued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 31, 2022.

(4) Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent. Series 2009 A-B bonds have a maturity date of June 5, 2019. In December 2015, Series 1996 C, E, F, 1997 B bonds the letters of credit were extended to December 1, 2020. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.

(5) At December 31, 2018, the interest rate on these bonds was 2.08%.

(6) At December 31, 2018, the interest rate on these bonds ranged from 2.05% to 2.15%.

Pollution Control Bonds

The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility. Substantially all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant. In 1999, the Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sales agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding. Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.

Repayment Schedule

PG&E Corporation's and the Utility's long-term debt is in default, and the Accelerated Direct Financial Obligations became immediately due and payable upon the commencement of the Chapter 11 Cases. PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2018 are reflected in the table below:

(in millions,
except interest rates)	2019				2020				2021				2022				2023				Thereafter				Total
PG&E Corporation
Variable interest rate as of December 31, 2018	—		%		3.51		%		—		%		—		%		—		%		—		%		3.51		%
Variable rate obligations	$	—			$	350			$	—			$	—			$	—			$	—			$	350
Utility
Average fixed interest rate	—		%		3.50		%		3.80		%		2.31		%		3.83		%		4.74		%		4.52		%
Fixed rate obligations	$	—			$	800			$	550			$	500			$	1,175			$	14,600			$	17,625
Variable interest rate as of December 31, 2018	1.78		%		1.59		%		—		%		—		%		—		%		—		%		1.63		%
Variable rate obligations (1)	$	149			$	614			$	—			$	—			$	—			$	—			$	763
Total consolidated debt	$	149			$	1,764			$	550			$	500			$	1,175			$	14,600			$	18,738

(1) The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019, or December 1, 2020.

Short-term Borrowings

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their revolving credit facilities and commercial paper programs at December 31, 2018:

(in millions)	Termination Date		Credit Facility Limit					Borrowings Against Revolver					Commercial Paper Outstanding				Facility Availability
PG&E Corporation	April 2022		$	300		(1)		$	300				$	—			$	—
Utility	April 2022		$	3,000		(2)		$	2,965		(3)		$	—			$	35
Total revolving credit facilities			$	3,300				$	3,265				$	—			$	35

(1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

(2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans.

(3) Includes $80 million of letters of credit.

For the year ended December 31, 2018, PG&E Corporation’s average outstanding commercial paper balance was $29 million and the maximum outstanding balance during the year was $137 million. For the year ended December 31, 2018, the Utility’s average outstanding commercial paper balance was $9 million and the maximum outstanding balance during the year was $205 million. As of December 31, 2018, PG&E Corporation and the Utility each had no commercial paper borrowings outstanding. PG&E Corporation and the Utility do not expect to be able to access the commercial paper market for the duration of the Chapter 11 Cases.

The commencement of the Chapter 11 Cases constituted an event of default or termination event, and caused an automatic and immediate acceleration of the Accelerated Direct Financial Obligations. However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation's term loan facility, as well as short-term borrowings under PG&E Corporation's and the Utility's revolving credit facilities and the Utility's term loan facility. See Note 15 below for more information.

Revolving Credit Facilities

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. As previously disclosed, PG&E Corporation's and the Utility's revolving credit facilities have been subject to an automatic and immediate acceleration as a result of the Chapter 11 Cases. Prior to the Chapter 11 Cases, proceeds from the revolving credit facilities were used for working capital, the repayment of commercial paper, and other corporate purposes.

Borrowings under each credit agreement (other than swingline loans) previously bore interest based on the borrower’s credit rating and on each borrower’s election of either (1) LIBOR plus an applicable margin or (2) the base rate plus an applicable margin. The base rate equaled the higher of the following: the administrative agent’s announced base rate, 0.5% above the overnight federal funds rate, and the one-month LIBOR plus an applicable margin. The borrower’s credit rating at the time of borrowing determined the applicable rate within the following ranges. The applicable margin for LIBOR loans ranged between 0.9% and 1.475% under PG&E Corporation’s credit agreement and between 0.8% and 1.275% under the Utility’s credit agreement. The applicable margin for base rate loans ranged between 0% and 0.475% under PG&E Corporation’s credit agreement and between 0% and 0.275% under the Utility’s credit agreement. In addition, the facility fee under PG&E Corporation’s and the Utility’s credit agreements ranged between 0.1% and 0.275% and between 0.075% and 0.225%, respectively.

PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes. In addition, the respective revolving credit facilities required that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. PG&E Corporation’s revolving credit facility agreement also required that PG&E Corporation own, directly or indirectly, at least 80% of the outstanding common stock and at least 70% of the outstanding voting capital stock of the Utility.

Commercial Paper Programs

The borrowings from PG&E Corporation’s and the Utility’s commercial paper programs were used primarily to fund temporary financing needs. PG&E Corporation and the Utility could issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, respectively. PG&E Corporation and the Utility treated the amount of outstanding commercial paper as a reduction to the amount available under their respective revolving credit facilities. The commercial paper had maturities up to 365 days and ranked equally with PG&E Corporation’s and the Utility’s other unsubordinated and unsecured indebtedness. Commercial paper notes were sold at an interest rate dictated by the market at the time of issuance. For 2018, the average yield on outstanding PG&E Corporation and Utility commercial paper was 1.85% and 1.91%, respectively.

Other Short-term Borrowings

In February 2018, the Utility’s $250 million floating rate unsecured term loan, issued in February 2017, matured and was repaid. In February 2018, the Utility entered into a $250 million floating rate unsecured term loan. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. As a result of the Chapter 11 Cases, repayment of this loan, which was scheduled to mature on February 22, 2019, has been stayed.

As of December 31, 2018, PG&E Corporation and the Utility each had no commercial paper borrowings. PG&E Corporation and the Utility do not expect to be able to access the commercial paper market for the duration of the Chapter 11 Cases.

In November 2018, the Utility's $500 million floating rate unsecured term loan, issued in November 2017, matured and was repaid.

NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 520,338,710 shares of common stock outstanding at December 31, 2018. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2018.

During 2018, PG&E Corporation sold no shares of common stock under the February 2017 EDA.

In addition, during 2018, PG&E Corporation sold 5.6 million shares of common stock under its 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans for total cash proceeds of $199 million. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E common stock to cash.

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of and potential liabilities associated with wildfires. See Wildfire-related contingencies in Note 13 below.

Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. Under their respective credit agreements, PG&E Corporation and the Utility are each required to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%. Based on the calculation of this ratio for each company, no amount of PG&E Corporation's retained earnings and $1.4 billion of the Utility's retained earnings was subject to this restriction at December 31, 2018. Additionally, the Utility's net assets, and therefore its ability to pay dividends, are restricted by the CPUC-authorized capital structure, which requires the Utility to maintain, on average, at least 52% equity. Based on the calculation of this ratio, none of the Utility's net assets were restricted at December 31, 2018. Additionally, as a result of this requirement, the Utility's ability to pay dividends in the future could be impacted by future potential liabilities. PG&E Corporation does not expect to pay any cash dividends for the foreseeable future.

Long-Term Incentive Plan

The PG&E Corporation LTIP permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries. Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards. A maximum of 17 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the 2014 LTIP, of which 15,150,532 shares were available for future awards at December 31, 2018.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2018:

(in millions)	2018				2017				2016
Stock Options	$	10			$	—			$	—
Restricted stock units	43				40				53
Performance shares	36				45				55
Total compensation expense (pre-tax)	$	89			$	85			$	108
Total compensation expense (after-tax)	$	63			$	50			$	64

Share-based compensation costs are generally not capitalized. There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Stock Options

The exercise price of stock options granted under the 2014 LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant. Stock options generally have a 10-year term and vest over four years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2018, $1.5 million of total unrecognized compensation costs related to nonvested stock options were expected to be recognized over a weighted average period of a year and a half for PG&E Corporation.

The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. The weighted average grant date fair value of options granted using the Black-Scholes valuation method was $10.24 per share in 2018. The significant assumptions used for shares granted in 2018 were:

	2018
Expected stock price volatility	23.00	%
Expected annual dividend payment	3.10	%
Risk-free interest rate	2.58	%
Expected life (years)	6

Expected volatilities are based on historical volatility of PG&E Corporation’s common stock. The expected dividend payment is the dividend yield at the date of grant. The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant. The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior.

There was no tax benefit recognized from stock options for the year ended December 31, 2018.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2018:

	Number of Stock Option			Weighted Average Grant- Date Fair Value				Weighted Average Remaining Contractual Term			Aggregate Intrinsic Value
Outstanding at January 1	—			N/A				N/A			N/A
Granted	1,571,876			$	10.24			—			—
Vested	—			N/A				—			—
Forfeited	(49,739	)		10.23				—			—
Outstanding at December 31	1,522,137			10.24				9.17			0
Expected to vest at December 31	1,430,407			$	10.24			9.17			0
Exercisable at December 31	—			N/A				N/A			N/A

Restricted Stock Units

Restricted stock units granted after 2014 generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units. Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value. The weighted average grant-date fair value for restricted stock units granted during 2018, 2017, and 2016 was $40.92, $66.95, and $56.68, respectively. The total fair value of restricted stock units that vested during 2018, 2017, and 2016 was $41 million, $57 million, and $36 million, respectively. The tax benefit from restricted stock units that vested during each period was not material. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2018, $43 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.79 years.

The following table summarizes restricted stock unit activity for 2018:

	Number of Restricted Stock Units			Weighted Average Grant- Date Fair Value
Nonvested at January 1	1,379,235			$	60.93
Granted	1,415,627			40.92
Vested	(691,408	)		58.78
Forfeited	(123,642	)		56.38
Nonvested at December 31	1,979,812			$	47.66

Performance Shares

Performance shares generally will vest three years after the grant date. Upon vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period or, for a small number of awards, an internal PG&E Corporation metric. Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled.

Compensation expense attributable to performance share is generally recognized ratably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the total shareholder return based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards. The weighted average grant-date fair value for performance shares granted during 2018, 2017, and 2016 was $36.92, $77.00, and $53.61 respectively. There was no tax benefit associated with performance shares during each of these periods. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2018, $31 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.68 years.

The following table summarizes activity for performance shares in 2018:

	Number of Performance Shares			Weighted Average Grant- Date Fair Value
Nonvested at January 1	1,748,028			$	63.40
Granted	763,392			36.92
Vested	(156,747	)		56.24
Forfeited (1)	(916,582	)		53.68
Nonvested at December 31	1,438,091			$	56.32

(1) Includes performance shares that expired with zero value as performance targets were not met.

NOTE 6: PREFERRED STOCK

PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value preferred stock, which may be issued as redeemable or nonredeemable preferred stock. PG&E Corporation does not have any preferred stock outstanding.

The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock. At December 31, 2018 and December 31, 2017, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share. The Utility’s preferred stock outstanding are not subject to mandatory redemption. All outstanding preferred stock has a $25 par value.

At December 31, 2018, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share. The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2018, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.

Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The Utility paid no dividends on preferred stock in 2018 (See "Dividends" in Note 5, above). The Utility paid $14 million of dividends on preferred stock in 2017 and 2016.

NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2018, 2017, and 2016.

	Year Ended December 31,
(in millions, except per share amounts)	2018				2017				2016
Income available for common shareholders	$	(6,851	)		$	1,646			$	1,393
Weighted average common shares outstanding, basic	517				512				499
Add incremental shares from assumed conversions:
Employee share-based compensation	—				1				2
Weighted average common share outstanding, diluted	517				513				501
Total earnings per common share, diluted	$	(13.25	)		$	3.21			$	2.78

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

NOTE 8: INCOME TAXES

PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes. The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities. Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit.

Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.

PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more. PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.

The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:

	PG&E Corporation												Utility
	Year Ended December 31,
(in millions)	2018				2017				2016				2018				2017				2016
Current:
Federal	$	(5	)		$	(10	)		$	(105	)		$	5			$	61			$	(105	)
State	(8		)		48				(70		)		(7		)		50				(66		)
Deferred:
Federal	(2,264		)		481				218				(2,278		)		326				229
State	(1,009		)		6				16				(1,009		)		4				16
Tax credits	(6		)		(14		)		(4		)		(6		)		(14		)		(4		)
Income tax provision (benefit)	$	(3,292	)		$	511			$	55			$	(3,295	)		$	427			$	70

The following table describes net deferred income tax liabilities:

	PG&E Corporation								Utility
	Year Ended December 31,
(in millions)	2018				2017				2018				2017
Deferred income tax assets:
Tax carryforwards	$	740			$	830			$	650			$	736
Compensation	173				274				121				205
Income tax regulatory liability(1)	79				286				79				286
Wildfire-related Reserve (2)	3,433				34				3,433				34
Other (3)	87				151				93				160
Total deferred income tax assets	$	4,512			$	1,575			$	4,376			$	1,421
Deferred income tax liabilities:
Property related basis differences	7,672				7,269				7,660				7,256
Other (4)	121				128				121				128
Total deferred income tax liabilities	$	7,793			$	7,397			$	7,781			$	7,384
Total net deferred income tax liabilities	$	3,281			$	5,822			$	3,405			$	5,963

(1) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. (For more information see Note 3 above).

(2) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to the 2018 Camp fire, 2017 Northern California wildfires, and the 2015 Butte fire.

(3) Amounts include benefits, environmental reserve, and customer advances for construction.

(4) Amounts primarily relate to regulatory balancing accounts.

The following table reconciles income tax expense at the federal statutory rate to the income tax provision:

	PG&E Corporation									Utility
	Year Ended December 31,
	2018			2017			2016			2018			2017			2016
Federal statutory income tax rate	21.0	%		35.0	%		35.0	%		21.0	%		35.0	%		35.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	7.9			1.5			(2.5	)		7.9			1.6			(2.2	)
Effect of regulatory treatment of fixed asset differences (2)	3.6			(16.5	)		(23.7	)		3.6			(16.8	)		(23.4	)
Tax credits	0.1			(1.1	)		(0.8	)		0.1			(1.1	)		(0.8	)
Benefit of loss carryback	—			—			(1.1	)		—			—			(1.1	)
Compensation Related (3)	(0.2	)		(1.0	)		(0.1	)		(0.1	)		(0.9	)		(0.2	)
Tax Reform Adjustment (4)	0.1			6.8			—			0.1			3.0			—
Other, net (5)	—			(1.1	)		(3.0	)		—			(0.7	)		(2.5	)
Effective tax rate	32.5	%		23.6	%		3.8	%		32.6	%		20.1	%		4.8	%

(1) Includes the effect of state flow-through ratemaking treatment. In 2016, amounts reflect a settlement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions.

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 2014 GRC decision (impacting the twelve months ended December 31, 2017), the 2017 GRC decision (impacting the twelve months ended December 31, 2018), and by the 2015 GT&S decision which impacted all periods presented. All amounts are impacted by the level of income before income taxes. The 2014 GRC, 2017 GRC, and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2018, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.

(3) Primarily represents adjustments to compensation as a result of the enactment of the Tax Act.

(4) Represents adjustments to deferred tax balances under Staff Accounting Bulletin No. 118 reflecting the tax rate reduction required by the Tax Act.

(5) These amounts primarily represents the impact of tax audit settlements.

Unrecognized tax benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation												Utility
(in millions)	2018				2017				2016				2018				2017				2016
Balance at beginning of year	$	349			$	388			$	468			$	349			$	382			$	462
Reductions for tax position taken during a prior year	(27		)		(71		)		(77		)		(27		)		(71		)		(77		)
Additions for tax position taken during the current year	55				48				56				55				48				56
Settlements	—				(14		)		(59		)		—				(8		)		(59		)
Expiration of statute	—				(3		)		—				—				(3		)		—
Balance at end of year	$	377			$	349			$	388			$	377			$	349			$	382

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2018 for PG&E Corporation and the Utility was $5 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of several matters, including audits. As of December 31, 2018, it is reasonably possible that unrecognized tax benefits will decrease by approximately $50 million within the next 12 months.

Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income. For the years ended December 31, 2018, 2017, and 2016, these amounts were immaterial.

Tax Cuts and Jobs Act of 2017

On December 22, 2017, the U.S. government enacted expansive tax legislation commonly referred to as the Tax Act. Among other provisions, the Tax Act reduces the federal income tax rate from 35% to 21% beginning on January 1, 2018 and eliminated bonus depreciation for utilities. At December 31, 2017, PG&E Corporation and the Utility recorded estimated provisional amounts to reflect the effect of the Tax Act in accordance with Staff Accounting Bulletin No. 118. In 2018, PG&E Corporation and the Utility recorded an approximately $13 million tax benefit to adjust the amount recorded in 2017 for the Tax Act upon obtaining, preparing, and analyzing additional information regarding facts and circumstances that existed as of the enactment date that, if known, would have affected the income tax effects initially reported as provisional amounts.

Although the accounting under ASC 740 to reflect the Tax Act is now complete, the Treasury is still issuing interpretive guidance on various aspects of the Tax Act. If future guidance requires a change in the recorded tax amounts, any necessary change will be reflected in the period such guidance is issued.

In addition, the Utility filed the estimated revenue impact of the Tax Act with the CPUC and FERC in March and May of 2018, respectively. As of December 31, 2018, the Utility still has not received final regulatory decisions. Depending on the final regulatory outcome, an adjustment may need to be made in the period the final decisions are issued.

Tax settlements

PG&E Corporation’s tax returns have been accepted through 2015 except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the Penalty Decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. In February 2017, the Joint Committee of Taxation approved PG&E Corporation’s settlement with the IRS related to deductible electric transmission and distribution repairs for the 2011 and 2012 tax years. The agreement provided that the methodology used in determining the deductible amount should be followed for all subsequent periods, absent any material change in facts. In November 2017, PG&E Corporation reached an agreement with the IRS on deductible generation repairs for the 2013 and 2014 tax years.

Tax years after 2007 remain subject to examination by the state of California.

Carryforwards

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:

(in millions)	December 31, 2018				Expiration Year
Federal:
Net operating loss carryforward	$	3,880			2031 - 2036
Tax credit carryforward	118				2029 - 2037
Charitable contribution loss carryforward	10				2020
State:
Net operating loss carryforward	$	58			2038
Tax credit carryforward	79				Various
Charitable contribution loss carryforward	10				2020 - 2021

PG&E Corporation believes it is more likely than not the tax benefits associated with the federal and California net operating losses, charitable contributions and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of December 31, 2018 for these tax attributes.

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status during the pendency of the Chapter 11 Cases.

NOTE 9: DERIVATIVES

Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Derivatives are presented in the Utility’s Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counter-party. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.

Price risk management instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Consolidated Balance Sheets at fair value.

Volume of Derivative Activity

At December 31, 2018 and 2017, respectively, the volumes of the Utility’s outstanding derivatives were as follows:

				Contract Volume
Underlying Product		Instruments		2018			2017
Natural Gas (1) (MMBtus (2))		Forwards and Swaps		177,750,349			228,768,745
		Options		13,735,405			60,736,806
Electricity (Megawatt-hours)		Forwards and Swaps		3,833,490			2,872,013
		Congestion Revenue Rights (3)		340,783,089			312,272,177

(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units.

(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

At December 31, 2018, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance				Netting				Cash Collateral				Total Derivative Balance
Current assets – other	$	44			$	(1	)		$	89			$	132
Other noncurrent assets – other	165				—				—				165
Current liabilities – other	(29		)		1				7				(21		)
Noncurrent liabilities – other	(90		)		—				2				(88		)
Total commodity risk	$	90			$	—			$	98			$	188

At December 31, 2017, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance				Netting				Cash Collateral				Total Derivative Balance
Current assets – other	$	30			$	(3	)		$	10			$	37
Other noncurrent assets – other	103				(1		)		—				102
Current liabilities – other	(47		)		3				13				(31		)
Noncurrent liabilities – other	(66		)		1				8				(57		)
Total commodity risk	$	20			$	—			$	31			$	51

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows.

The majority of the Utility’s derivatives instruments, including certain power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. In January 2019, multiple credit rating agencies downgraded the Utility below investment grade, resulting in the Utility posting $6.2 million to fully collateralize its net liability derivative positions.

NOTE 10: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

•	Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

•	Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

•	Level 3 – Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.

	Fair Value Measurements
	At December 31, 2018
(in millions)	Level 1				Level 2				Level 3				Netting (1)				Total
Assets:
Short-term investments	$	1,593			$	—			$	—			$	—			$	1,593
Nuclear decommissioning trusts
Short-term investments	29				—				—				—				29
Global equity securities	1,793				—				—				—				1,793
Fixed-income securities	661				639				—				—				1,300
Assets measured at NAV	—				—				—				—				16
Total nuclear decommissioning trusts (2)	2,483				639				—				—				3,138
Price risk management instruments (Note 9)
Electricity	—				5				203				51				259
Gas	—				1				—				37				38
Total price risk management instruments	—				6				203				88				297
Rabbi trusts
Fixed-income securities	—				93				—				—				93
Life insurance contracts	—				67				—				—				67
Total rabbi trusts	—				160				—				—				160
Long-term disability trust
Short-term investments	7				—				—				—				7
Assets measured at NAV	—				—				—				—				155
Total long-term disability trust	7				—				—				—				162
TOTAL ASSETS	$	4,083			$	805			$	203			$	88			$	5,350
Liabilities:
Price risk management instruments (Note 9)
Electricity	$	4			$	5			$	108			$	(10	)		$	107
Gas	—				2				—				—				2
TOTAL LIABILITIES	$	4			$	7			$	108			$	(10	)		$	109

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $408 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2017
(in millions)	Level 1				Level 2				Level 3				Netting (1)				Total
Assets:
Short-term investments	$	385			$	—			$	—			$	—			$	385
Nuclear decommissioning trusts
Short-term investments	23				—				—				—				23
Global equity securities	1,967				—				—				—				1,967
Fixed-income securities	733				562				—				—				1,295
Assets measured at NAV	—				—				—				—				18
Total nuclear decommissioning trusts (2)	2,723				562				—				—				3,303
Price risk management instruments (Note 9)
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 9)
Electricity	10				15				87				(25		)		87
Gas	—				1				—				—				1
TOTAL LIABILITIES	$	10			$	16			$	87			$	(25	)		$	88

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $440 million, primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the years ended December 31, 2018 and 2017.

Trust Assets

Assets Measured at Fair Value

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1.

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Assets Measured at NAV Using Practical Expedient

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

Level 3 Measurements and Sensitivity Analysis

The Utility’s market and credit risk management function, which reports to the Chief Financial Officer, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. See Note 9 above.

		Fair Value at
(in millions)		At December 31, 2018								Valuation Technique		Unobservable Input
Fair Value Measurement		Assets				Liabilities						Range (1)
Congestion revenue rights		$	203			$	75			Market approach		CRR auction prices		$ (18.61) - 32.26
Power purchase agreements		$	—			$	33			Discounted cash flow		Forward prices		$ 19.81 - 38.80

(1) Represents price per megawatt-hour

		Fair Value at
(in millions)		At December 31, 2017								Valuation Technique		Unobservable Input
Fair Value Measurement		Assets				Liabilities						Range (1)
Congestion revenue rights		$	129			$	24			Market approach		CRR auction prices		$ (16.03) - 11.99
Power purchase agreements		$	—			$	63			Discounted cash flow		Forward prices		$ 18.81 - 38.80

(1) Represents price per megawatt-hour

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2018 and 2017, respectively:

	Price Risk Management Instruments
(in millions)	2018				2017
Asset (liability) balance as of January 1	$	42			$	55
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	53				(13		)
Asset (liability) balance as of December 31	$	95			$	42

(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2018 and 2017, as they are short-term in nature or have interest rates that reset daily.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments, excluding pollution control bonds, were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

	At December 31,
	2018								2017
(in millions)	Carrying Amount				Level 2 Fair Value				Carrying Amount				Level 2 Fair Value
Debt (Note 4)
PG&E Corporation(1)	$	350			$	350			$	350			$	350
Utility	17,450				14,747				17,090				19,128

(1) On April 26, 2018, PG&E Corporation early redeemed its outstanding $350 million principal amount of 2.40% Senior Notes. Also, in April 2018, PG&E

Corporation entered into a $350 million floating rate unsecured term loan. For more information, see Note 4.

Nuclear Decommissioning Trust Investments

The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions)	Amortized Cost				Total Unrealized Gains				Total Unrealized Losses				Total Fair Value
As of December 31, 2018
Nuclear decommissioning trusts
Short-term investments	$	29			$	—			$	—			$	29
Global equity securities	568				1,246				(5		)		1,809
Fixed-income securities	1,288				30				(18		)		1,300
Total (1)	$	1,885			$	1,276			$	(23	)		$	3,138
As of December 31, 2017
Nuclear decommissioning trusts
Short-term investments	$	23			$	—			$	—			$	23
Global equity securities	524				1,463				(2		)		1,985
Fixed-income securities	1,252				51				(8		)		1,295
Total (1)	$	1,799			$	1,514			$	(10	)		$	3,303

(1) Represents amounts before deducting $408 million and $440 million at December 31, 2018 and 2017, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows:

	As of
(in millions)	December 31, 2018
Less than 1 year	$	60
1–5 years	391
5–10 years	341
More than 10 years	508
Total maturities of fixed-income securities	$	1,300

The following table provides a summary of activity for the fixed-income and equity securities:

(in millions)	2018				2017				2016
Proceeds from sales and maturities of nuclear decommissioning investments	$	1,412			$	1,291			$	1,295
Gross realized gains on securities	54				53				18
Gross realized losses on securities	(24		)		(11		)		(26		)

NOTE 11: EMPLOYEE BENEFIT PLANS

Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”). Certain trusts underlying these plans are qualified trusts under the Internal Revenue Code of 1986, as amended. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations. PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. On an annual basis, the Utility funds the pension plans up to the amount it is authorized to recover in rates, $327 million for both 2018 and 2017.

PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.

On February 27, 2019, PG&E Corporation and the Utility received approval from the Bankruptcy Court to maintain existing pension and other benefit plans during the pendency of the Chapter 11 Cases. (For more information see "Chapter 11 Proceedings" in Note 15 below.)

Change in Plan Assets, Benefit Obligations, and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2018 and 2017:

Pension Plan

(in millions)	2018				2017
Change in plan assets:
Fair value of plan assets at beginning of year	$	16,652			$	14,729
Actual return on plan assets	(923		)		2,380
Company contributions	334				335
Benefits and expenses paid	(751		)		(792		)
Fair value of plan assets at end of year	$	15,312			$	16,652
Change in benefit obligation:
Benefit obligation at beginning of year	$	18,757			$	17,305
Service cost for benefits earned	514				472
Interest cost	687				714
Actuarial (gain) loss	(1,800		)		1,048
Plan amendments	—				10
Benefits and expenses paid	(751		)		(792		)
Benefit obligation at end of year (1)	$	17,407			$	18,757
Funded Status:
Current liability	$	(8	)		$	(7	)
Noncurrent liability	(2,087		)		(2,098		)
Net liability at end of year	$	(2,095	)		$	(2,105	)

(1) PG&E Corporation’s accumulated benefit obligation was $15.8 billion and $16.8 billion at December 31, 2018 and 2017, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2018				2017
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,420			$	2,173
Actual return on plan assets	(108		)		298
Company contributions	31				33
Plan participant contribution	81				87
Benefits and expenses paid	(166		)		(171		)
Fair value of plan assets at end of year	$	2,258			$	2,420
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,897			$	1,877
Service cost for benefits earned	66				59
Interest cost	69				77
Actuarial (gain) loss	(221		)		(49		)
Benefits and expenses paid	(150		)		(157		)
Federal subsidy on benefits paid	3				3
Plan participant contributions	81				87
Benefit obligation at end of year	$	1,745			$	1,897
Funded Status: (1)
Noncurrent asset	$	545			$	553
Noncurrent liability	(32		)		(30		)
Net asset at end of year	$	513			$	523

(1) At December 31, 2018 and 2017, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Components of Net Periodic Benefit Cost

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below.

Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:

Pension Plan

(in millions)	2018				2017				2016
Service cost for benefits earned (1)	$	514			$	472			$	453
Interest cost	687				714				715
Expected return on plan assets	(1,021		)		(770		)		(828		)
Amortization of prior service cost	(6		)		(7		)		8
Amortization of net actuarial loss	5				22				24
Net periodic benefit cost	179				431				372
Less: transfer to regulatory account (2)	157				(92		)		(34		)
Total expense recognized	$	336			$	339			$	338

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.

Postretirement Benefits Other than Pensions

(in millions)	2018				2017				2016
Service cost for benefits earned (1)	$	66			$	59			$	52
Interest cost	69				77				76
Expected return on plan assets	(130		)		(97		)		(107		)
Amortization of prior service cost	14				15				15
Amortization of net actuarial loss	(5		)		4				4
Net periodic benefit cost	$	14			$	58			$	40

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

Non-service costs are reflected in Other income, net on the Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Consolidated Statements of Income.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Components of Accumulated Other Comprehensive Income

PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax. In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions. For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).

The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2019 are as follows:

(in millions)	Pension Plan				PBOP Plans
Unrecognized prior service cost	$	(6	)		$	14
Unrecognized net loss	3				(3		)
Total	$	(3	)		$	11

There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation and the Utility.

Valuation Assumptions

The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs. The following weighted average year-end assumptions were used in determining the plans’ projected benefit obligations and net benefit cost.

	Pension Plan									PBOP Plans
	December 31,									December 31,
	2018			2017			2016			2018		2017		2016
Discount rate	4.35	%		3.64	%		4.11	%		4.29 - 4.37%		3.60 - 3.67 %		4.05 - 4.19 %
Rate of future compensation increases	3.90	%		3.90	%		4.00	%		—		—		—
Expected return on plan assets	6.00	%		6.20	%		5.30	%		3.60 - 6.80%		3.30 - 7.10%		2.80 - 6.00%

The assumed health care cost trend rate as of December 31, 2018 was 6.5%, decreasing gradually to an ultimate trend rate in 2027 and beyond of approximately 4.5%. A one-percentage-point change in assumed health care cost trend rate would have the following effects:

(in millions)	One-Percentage-Point Increase				One-Percentage-Point Decrease
Effect on postretirement benefit obligation	$	112			$	(113	)
Effect on service and interest cost	9				(10		)

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the pension plan, the assumed return of 6.0% compares to a ten-year actual return of 10.0%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 1,101 Aa-grade non-callable bonds at December 31, 2018. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

Investment Policies and Strategies

The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended. PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility.

The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings. Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields. To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return. Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include commodities futures, global REITS, global listed infrastructure equities, and private real estate funds. Absolute return investments include hedge fund portfolios.

Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non U.S. dollar exposure of global equity investments.

The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:

	Pension Plan									PBOP Plans
	2019			2018			2017			2019			2018			2017
Global equity securities	29	%		29	%		27	%		33	%		33	%		32	%
Absolute return	5	%		5	%		5	%		3	%		3	%		3	%
Real assets	8	%		8	%		10	%		6	%		6	%		7	%
Fixed-income securities	58	%		58	%		58	%		58	%		58	%		58	%
Total	100	%		100	%		100	%		100	%		100	%		100	%

PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.

Fair Value Measurements

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2018 and 2017.

	Fair Value Measurements
	At December 31,
	2018																2017
(in millions)	Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Pension Plan:
Short-term investments	$	333			$	22			$	—			$	355			$	287			$	424			$	—			$	711
Global equity securities	1,145				—				—				1,145				1,292				—				—				1,292
Real assets	461				—				—				461				499				—				—				499
Fixed-income securities	1,897				5,216				8				7,121				1,916				5,520				4				7,440
Assets measured at NAV	—				—				—				6,202				—				—				—				6,818
Total	$	3,836			$	5,238			$	8			$	15,284			$	3,994			$	5,944			$	4			$	16,760
PBOP Plans:
Short-term investments	$	33			$	—			$	—			$	33			$	31			$	—			$	—			$	31
Global equity securities	115				—				—				115				141				—				—				141
Real assets	50				—				—				50				55				—				—				55
Fixed-income securities	153				857				—				1,010				163				757				—				920
Assets measured at NAV	—				—				—				1,056				—				—				—				1,281
Total	$	351			$	857			$	—			$	2,264			$	390			$	757			$	—			$	2,428
Total plan assets at fair value													$	17,548															$	19,188

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $22 million and other net assets of $116 million at December 31, 2018 and 2017, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above. All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days.

Short-Term Investments

Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.

Global Equity securities

The global equity category includes investments in common stock and equity-index futures. Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets. These equity investments are generally valued based on unadjusted prices in active markets for identical securities. Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.

Real Assets

The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds. The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets.

Fixed-Income securities

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Assets Measured at NAV Using Practical Expedient

Investments in the trusts that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, asset-backed securities, and private real estate funds. There are no restrictions on the terms and conditions upon which the investments may be redeemed.

Transfers Between Levels

Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. No material transfers between levels occurred in the years ended December 31, 2018 and 2017.

Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2018 and 2017:

(in millions)
For the year ended December 31, 2018	Fixed-Income
Balance at beginning of year	$	4
Actual return on plan assets:
Relating to assets still held at the reporting date	(3		)
Relating to assets sold during the period	—
Purchases, issuances, sales, and settlements:
Purchases	6
Settlements	1
Balance at end of year	$	8
(in millions)
For the year ended December 31, 2017	Fixed-Income
Balance at beginning of year	$	5
Actual return on plan assets:
Relating to assets still held at the reporting date	(1		)
Relating to assets sold during the period	—
Purchases, issuances, sales, and settlements:
Purchases	3
Settlements	(3		)
Balance at end of year	$	4

There were no material transfers out of Level 3 in 2018 and 2017.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $334 million to the pension benefit plans and $31 million to the other benefit plans in 2018. These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2018. The Utility’s pension benefits met all the funding requirements under Employee Retirement Income Security Act. PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $24 million to the pension plan and other postretirement benefit plans, respectively, for 2019.

Benefits Payments and Receipts

As of December 31, 2018, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:

(in millions)	Pension Plan			PBOP Plans			Federal Subsidy
2019	778			88			(8	)
2020	855			91			(9	)
2021	891			94			(9	)
2022	925			99			(3	)
2023	957			102			(3	)
Thereafter in the succeeding five years	5,136			507			(12	)

There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above. There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.

Retirement Savings Plan

PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants. Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $105 million, $103 million, and $97 million in 2018, 2017, and 2016, respectively.

There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

NOTE 12: RELATED PARTY AGREEMENTS AND TRANSACTIONS

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

The Utility’s significant related party transactions were:

	Year Ended December 31,
(in millions)	2018				2017				2016
Utility revenues from:
Administrative services provided to PG&E Corporation	$	4			$	8			$	7
Utility expenses from:
Administrative services received from PG&E Corporation	$	94			$	65			$	74
Utility employee benefit due to PG&E Corporation	76				73				91

At December 31, 2018 and 2017, the Utility had receivables of $33 million and $20 million, respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $38 million and $22 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

NOTE 13: WILDFIRE-RELATED CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation's and the Utility's provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Wildfire-Related Claims

Wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.

For the years ended December 31, 2018, 2017 and 2016, the Utility’s Consolidated Income Statements include estimated losses offset by insurance recoveries as follows:

	Year Ended December 31,
(in millions)	2018				2017				2016
2015 Butte fire
Third-Party Claims	$	—			$	350			$	750
Insurance recoveries	(7		)		(350		)		(625		)
Total 2015 Butte fire	(7		)		—				125
2017 Northern California wildfires
Third-Party Claims	3,500				—				—
Insurance recoveries	(842		)		—				—
Total 2017 Northern California wildfires	2,658				—				—
2018 Camp fire
Third-Party Claims	10,500				—				—
Insurance recoveries	(1,380		)		—				—
Total 2018 Camp fire	9,120				—				—
Total wildfire-related claims, net of insurance recoveries	$	11,771			$	—			$	125

In addition to the amounts shown in the table above, during the year ended December 31, 2018, the Utility incurred $245 million of legal and other costs related to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire.

At December 31, 2018 and 2017, the Utility's Consolidated Balance Sheets include estimated liabilities as follows:

	Balance At
(in millions)	December 31, 2018				December 31, 2017
2015 Butte fire	$	226			$	561
2017 Northern California wildfires	3,500				—
2018 Camp fire	10,500				—
Total wildfire-related claims	$	14,226			$	561

2018 Camp Fire Background

On November 8, 2018, a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire's Camp Fire Incident Information Website as of January 4, 2019, (the “Cal Fire website”), indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 86 fatalities and the destruction of 13,972 residences, 528 commercial structures and 4,293 other buildings resulting from the 2018 Camp fire. On February 7, 2019, the Butte County Sheriff's Office reported that the number of fatalities resulting from the 2018 Camp fire had been reduced from 86 to 85.

Although the cause of the 2018 Camp fire is still under investigation, based on the information currently known to PG&E Corporation and the Utility and reported to the CPUC and other agencies, including the facts described below, PG&E Corporation and the Utility believe it is probable that the Utility’s equipment will be determined to be an ignition point of the 2018 Camp fire.

The Utility submitted two Electric Incident Reports (the “EIRs”) to the CPUC: one on November 8, 2018 and one on November 16, 2018. On December 11, 2018, the Utility publicly released a letter to the CPUC supplementing the EIRs (the “20-Day Electric Incident Report”), which stated:

•	On Cal Fire’s website, Cal Fire has identified coordinates for the 2018 Camp fire near Tower :27/222 on the Utility’s Caribou-Palermo 115 kV Transmission Line and has identified the start time of the 2018 Camp fire as 6:33 a.m. on November 8, 2018.

•

On November 8, 2018, at approximately 6:15 a.m., the Utility’s Caribou-Palermo 115kV Transmission Line relayed and deenergized. At approximately 6:30 a.m. that day, a Utility employee observed fire in the vicinity of Tower :27/222, and this observation was reported to 911 by Utility employees. In the afternoon of November 8, the Utility observed damage on the line at Tower :27/222. Specifically, an aerial patrol identified that a suspension insulator supporting a transposition jumper had separated from an arm on Tower :27/222.

•	On November 14, 2018, the Utility observed a broken C-hook attached to the separated suspension insulator that had connected the suspension insulator to a tower arm, along with wear at the connection point. In addition, the Utility observed a flash mark on Tower :27/222 near where the transposition jumper was suspended and damage to the transposition jumper and suspension insulator.

•

In addition to the events on the Caribou-Palermo 115kV Transmission Line, on November 8, 2018, at approximately 6:45 a.m., the Utility’s Big Bend 1101 12 kV Circuit experienced an outage. On November 9, 2018, a Utility employee on patrol arrived at the location of the pole with Line Recloser (“LR”) 1704 on the Big Bend 1101 Circuit and observed that the pole and other equipment were on the ground with bullets and bullet holes at the break point of the pole and on the equipment. On November 12, 2018, a Utility employee was patrolling Concow Road north of LR 1704 when he observed wires down and damaged and downed poles at the intersection of Concow Road and Rim Road. At this location, the employee observed several snapped trees, with some on top of the downed wires.

The information contained in the EIRs and the 20-Day Electric Incident Report is factual and preliminary and does not reflect a determination of the causes of the 2018 Camp fire. These incidents remain under investigation by Cal Fire and the CPUC. With respect to the potential ignition point on the Utility’s Big Bend 1101 12 kV Circuit, although Cal Fire has identified this location as a potential ignition point, based on the condition of the site, PG&E Corporation and the Utility have not been able to determine whether the Big Bend 1101 12 kV Circuit may be a probable ignition point for the 2018 Camp fire. Neither Cal Fire nor the CPUC has publicly issued any news releases or other determinations for the 2018 Camp fire. The timing and outcome of the investigations are uncertain. PG&E Corporation and the Utility are cooperating with Cal Fire and the CPUC.

Further, 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. Various other entities, including fire departments, may also be investigating the fire. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete.

2017 Northern California Wildfires Background

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities.

Cal Fire has issued its determination on the causes of 19 of the 2017 Northern California wildfires, and alleged that all of these fires, with the exception of the Tubbs fire, involved the Utility's equipment. The remaining wildfires remain under Cal Fire's investigation, including the possible role of the Utility's power lines and other facilities.

During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires, located in Mendocino, Lake, Butte, Sonoma, Humboldt, Nevada and Napa counties). According to the Cal Fire news releases, the first four fires “were caused by trees coming into contact with power lines” and the remaining 12 fires “were caused by electric power and distribution lines, conductors and the failure of power poles.” Cal Fire has not yet released its investigation reports related to the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires and stated in its news releases that these investigations have been referred to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” The Butte County District Attorney's office has entered into a settlement agreement with the Utility, resolving the Honey, Cherokee and LaPorte fire allegations without criminal or civil charges. The timing and outcome for resolution of the remaining referrals are uncertain.

Also during the second quarter of 2018, Cal Fire released its investigation reports related to the Redwood, Cherokee, 37, Nuns and La Porte fires. Cal Fire did not refer these fires to District Attorney offices for investigation.

On October 9, 2018, Cal Fire issued a news release announcing the results of its investigation into the Cascade fire, located in Yuba County, concluding that the Cascade fire “was started by sagging power lines coming into contact during heavy winds” and that “the power line in question was owned by Pacific Gas and Electric Company.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire.

On January 24, 2019, Cal Fire issued a news release and its investigation report into the cause of the Tubbs fire. Cal Fire has determined that the Tubbs fire was caused by a private electrical system adjacent to a residential structure.

Cal Fire has not publicly issued any news releases or other determinations for the Maacama, Pressley and Point wildfires. The timing and outcome of the Cal Fire investigation into these fires is uncertain.

Further, the SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. Various other entities, including fire departments, may also be investigating certain of the fires. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete.

The Utility has submitted 23 electric incident reports to the CPUC associated with the 2017 Northern California wildfires where Cal Fire or the Utility has identified a site as potentially involving the Utility’s facilities in its investigation and the property damage associated with each incident exceeded $50,000. The information contained in these reports is factual and preliminary and does not reflect a determination of the causes of the fires.

Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires

If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the substantial cause of one or more fires, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries-Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires, including in connection with SB 901.)

In addition to claims for property damage, business interruption, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if the Utility were found to have been negligent.

Further, the Utility could be subject to material fines or penalties if the CPUC or any law enforcement agency brought an enforcement action, including a criminal proceeding, and determined that the Utility failed to comply with applicable laws and regulations.

As of January 28, 2019, PG&E Corporation and the Utility are aware of approximately 100 complaints on behalf of at least 4,200 plaintiffs related to the 2018 Camp fire, nine of which seek to be certified as class actions. The pending civil litigation against PG&E Corporation and the Utility related to the 2018 Camp fire, which is currently stayed as a result of the commencement of the Chapter 11 Cases, includes claims under multiple theories of liability, including inverse condemnation, trespass, private nuisance, public nuisance, negligence, negligence per se, negligent interference with prospective economic advantage, negligent infliction of emotional distress, premises liability, violations of the Public Utilities Code, violations of the Health & Safety Code, malice and false advertising in violation of the California Business and Professions Code. The plaintiffs principally assert that PG&E Corporation's and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2018 Camp fire. The plaintiffs seek damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, establishment of a class action medical monitoring fund, punitive damages, attorneys’ fees and other damages. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process.

As of January 28, 2019, PG&E Corporation and the Utility are aware of approximately 750 complaints on behalf of at least 3,800 plaintiffs related to the 2017 Northern California wildfires, five of which seek to be certified as class actions. These cases have been coordinated in the San Francisco County Superior Court. As of the Petition Date, the coordinated litigation was in the early stages of discovery. A trial with respect to the Atlas fire was scheduled to begin on September 23, 2019. The pending civil litigation against PG&E Corporation and the Utility related to the 2017 Northern California wildfires, includes claims under multiple theories of liability, including inverse condemnation, trespass, private nuisance and negligence. This litigation, including the trial date with respect to the Atlas fire, currently is stayed as a result of the commencement of the Chapter 11 Cases. The plaintiffs principally assert that PG&E Corporation's and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2017 Northern California wildfires. The plaintiffs seek damages that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees and other damages. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process.

Insurance carriers who have made payments to their insureds for property damage arising out of the 2017 Northern California wildfires have filed 48 subrogation complaints in the San Francisco County Superior Court as of January 28, 2019. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations are similar to the ones made by individual plaintiffs. As of January 28, 2019, insurance carriers have filed 37 similar subrogation complaints with respect to the 2018 Camp fire in the Sacramento County Superior Court. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process.

Various government entities, including Yuba, Nevada, Lake, Mendocino, Napa and Sonoma Counties and the Cities of Santa Rosa and Clearlake, also have asserted claims against PG&E Corporation and the Utility based on the damages that these government entities allegedly suffered as a result of the 2017 Northern California wildfires. Such alleged damages include, among other things, loss of natural resources, loss of public parks, property damages and fire suppression costs. The causes of action and allegations are similar to the ones made by individual plaintiffs and the insurance carriers. With respect to the 2018 Camp fire, Butte County has filed similar claims against PG&E Corporation and the Utility, and PG&E Corporation and the Utility expect additional similar claims to be made by other government entities. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process.

On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the 2017 Northern California wildfires litigation. On May 21, 2018, the court overruled the motion. On July 20, 2018, PG&E Corporation and the Utility filed a writ in the Court of Appeal requesting appellate review of the trial court's decision, which was denied on September 17, 2018. On September 27, 2018, PG&E Corporation and the Utility filed a petition for review to the California Supreme Court. On November 14, 2018, the California Supreme Court denied PG&E Corporation's and the Utility's petition for review.

PG&E Corporation and the Utility expect to be the subject of numerous additional claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process.

PG&E Corporation and the Utility also are the subject of criminal investigations or other actions by the county District Attorneys to whom Cal Fire has referred its investigations into the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires. Although the Honey fire was referred to the Butte County District Attorney’s Office, in October 2018, the Utility reached an agreement to settle any civil claims or criminal charges that could have been brought by the Butte County District Attorney in connection with the Honey fire, as well as the La Porte and Cherokee fires (which were not referred). The settlement provides for funding by the Utility for at least four years of an enhanced fire prevention and communication program, in the amount of up to $1.5 million, not recoverable in rates. On October 9, 2018, the District Attorney of Yuba County announced his decision not to pursue criminal charges at such time against PG&E Corporation or the Utility pertaining to the Cascade fire. The Office of the District Attorney of Yuba County also indicated that it “reserves the right to review any additional information or evidence that may be submitted to it prior to the expiration of the criminal statute of limitations.”

Also in October 2018, the Utility and the Sonoma, Napa, Lake, Humboldt and Nevada County District Attorneys entered into agreements under which the Utility agreed to waive any applicable statutes of limitation related to the 2017 Northern California wildfires that started in these counties for a period of six months, until April 8, 2019. PG&E Corporation and the Utility anticipate further discussions with the District Attorneys in these counties relating to the 2017 Northern California wildfires and whether any criminal or civil charges should be brought. In addition, the Butte County District Attorney’s Office and the California Attorney General’s Office have opened a criminal investigation of the 2018 Camp fire. Additional investigations and other actions may arise out of the other 2017 Northern California wildfires and the 2018 Camp fire. Such proceedings are not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigations or to the many investigation reports prepared by Cal Fire. PG&E Corporation and the Utility and plaintiffs are in discussions with Cal Fire about access to the evidence and the remaining reports. No schedule on gaining access has been set.

Regardless of any determinations of cause by Cal Fire with respect to any pre-petition fire, ultimately PG&E Corporation’s and the Utility’s liability will be resolved through the Chapter 11 process, regulatory proceedings and any potential enforcement proceedings, all of which could take a number of years to resolve. The timing and outcome of these and other potential proceedings are uncertain.

Potential Losses in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires

On January 28, 2019, the California Department of Insurance issued a news release announcing an update on property losses in connection with the 2018 wildfires in Southern California (which are not in the Utility’s service territory) and the 2018 Camp fire, stating that, as of such date, “more than $11.4 billion in insured losses have been reported from the November 2018 fires,” of which approximately $8.4 billion relates to statewide claims from the 2018 Camp fire. On September 6, 2018, the California Department of Insurance issued a news release announcing that insurers have received nearly 55,000 insurance claims totaling more than $12.28 billion in losses, of which approximately $10 billion relates to statewide claims from the 2017 Northern California wildfires.

The dollar amounts announced by the California Department of Insurance represent an aggregate amount of approximately $18.4 billion of insurance claims made as of the above dates related to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation and the Utility expect that additional claims have been submitted and will continue to be submitted to insurers, particularly with respect to the 2018 Camp fire. These claims reflect insured property losses only. The $18.4 billion of insurance claims made as of the above dates does not account for uninsured or underinsured property losses, interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses or other costs, such as potential punitive damages, fines or penalties, or losses related to claims that have not manifested yet ("future claims"), each of which could be significant. The scope of all claims related to the 2018 Camp fire and 2017 Northern California wildfires is not known at this time because of the applicable statutes of limitations under California law.

Potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires depend on various factors, including but not limited to the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties or fines that may be imposed by governmental entities.

There are a number of unknown facts and legal considerations that may impact the amount of any potential liability. Among other things, it is uncertain at this time as to the number of wildfire-related claims that will be filed in the Chapter 11 Cases, the number of current and future claims that will be allowed by the Bankruptcy Court, how claims for punitive damages and claims by variously situated persons will be treated and whether such claims will be allowed, and the impact that historical settlement values for wildfire claims may have on the estimation of wildfire liability in the Chapter 11 Cases. If PG&E Corporation and the Utility were to be found liable for certain or all of the costs, expenses and other losses described above with respect to the 2018 Camp fire and 2017 Northern California wildfires, the amount of such liability could exceed $30 billion, which amount does not include potential punitive damages, fines and penalties or damages related to future claims. This estimate is based on a wide variety of data and other information available to PG&E Corporation and the Utility and their advisors, including various precedents involving similar claims, and accounts for property losses (including insured, uninsured and underinsured property losses), interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses and certain other costs. This estimate is not intended to provide an upper end of the range of potential liability arising from the 2018 Camp fire and 2017 Northern California wildfires. In certain circumstances, PG&E Corporation’s and the Utility’s liability could be substantially greater than such amount.

If PG&E Corporation and the Utility were to be found liable for any punitive damages or subject to fines or penalties, the amount of such punitive damages, fines and penalties could be significant. PG&E Corporation and the Utility have received significant fines and penalties in connection with past incidents. For example, in 2015, the CPUC approved a decision that imposed penalties on the Utility totaling $1.6 billion in connection with the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010 (the “San Bruno explosion”). These penalties represented nearly three times the underlying liability for the San Bruno explosion of approximately $558 million incurred for third-party claims, exclusive of shareholder derivative lawsuits and legal costs incurred. The amount of punitive damages, fines and penalties imposed on PG&E Corporation and the Utility could likewise be a significant amount in relation to the underlying liabilities with respect to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process. Such proceedings are not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge

Following accounting rules, PG&E Corporation and the Utility record a liability when a loss is probable and reasonably estimable. In accordance with U.S. generally accepted accounting principles, PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses, and record a charge that is the amount 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.

2018 Camp Fire

In light of the current state of the law and the information currently available to the Utility, including, among other things, the facts described in the EIRs and the 20-Day Electric Incident Report, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with the 2018 Camp fire, and accordingly PG&E Corporation and the Utility recorded a charge in the amount of $10.5 billion for the year ended December 31, 2018. This charge corresponds to the lower end of the range of PG&E Corporation's and the Utility’s reasonably estimated losses, and is subject to change based on additional information.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2018 Camp fire and 2017 Northern California wildfires will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2018 Camp fire may change, which could result in material increases to the loss accrued.

The $10.5 billion charge does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant.

2017 Northern California Wildfires

In light of the current state of the law on inverse condemnation and the information currently available to the Utility, including, among other things, the Cal Fire determinations of cause as stated in Cal Fire’s press releases and their released reports, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with 17 of the 2017 Northern California wildfires referred to as the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket, Atlas, Cascade, Point and Sonoma/Napa merged fires (which include the Nuns, Norrbom, Adobe, Partrick and Pythian fires). Accordingly, PG&E Corporation and the Utility recorded a charge in the amount of $2.5 billion during the quarter ended June 30, 2018 and a charge in the amount of $1.0 billion during the quarter ended December 31, 2018, for a total charge in the amount of $3.5 billion for the year ended December 31, 2018. This charge corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimated losses and is subject to change based on additional information. The additional charge recorded in the quarter ended December 31, 2018 resulted from additional information obtained by the Utility during that period about the fires.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2017 Northern California wildfires and the 2018 Camp fire will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2017 Northern California wildfires may change, which could result in material increases to the loss accrued.

The $3.5 billion charge does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant.

The $3.5 billion charge also does not include any amounts in connection with the 37, Tubbs, Maacama and Pressley fires because at this time PG&E Corporation and the Utility have not concluded that a loss arising from those fires is probable. However, in the future it is possible that facts could emerge that lead PG&E Corporation and the Utility to believe that a loss is probable, resulting in the accrual of a liability at that time, the amount of which could be significant.

Loss Recoveries

PG&E Corporation and the Utility had insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to the 2018 Camp fire and 2017 Northern California wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

PG&E Corporation and the Utility had $842 million of insurance coverage for liabilities, including wildfire events, for the period from August 1, 2017 through July 31, 2018, subject to an initial self-insured retention of $10 million per occurrence and further retentions of approximately $40 million per occurrence. During the third quarter of 2018, PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general liability (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for property damages only, which property damage coverage includes an aggregate amount of approximately $200 million through the reinsurance market where a catastrophe bond was utilized. PG&E Corporation and the Utility expect to face increasing difficulty securing liability insurance in future years due to availability and to face significantly increased insurance costs.

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through December 31, 2018, PG&E Corporation and the Utility recorded $1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire and $842 million for probable insurance recoveries in connection with the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. The amount of the receivable is subject to change based on additional information. PG&E Corporation and the Utility intend to seek full recovery for all insured losses and believe it is reasonably possible that they will record a receivable for the full amount of the insurance limits in the future.

If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. Even if PG&E Corporation and the Utility were to recover the full amount of their insurance, PG&E Corporation and the Utility expect their losses in connection with the 2018 Camp fire and 2017 Northern California wildfires will greatly exceed their available insurance.

The following table presents changes in the insurance receivable for the year ended December 31, 2018. The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation's and the Utility's Consolidated Balance Sheets:

(in millions)	Insurance Receivable
2018 Camp fire
Accrued insurance recoveries	$	1,380
Reimbursements	—
Balance at December 31, 2018	$	1,380
2017 Northern California wildfires
Accrued insurance recoveries	$	842
Reimbursements	(13		)
Balance at December 31, 2018	$	829

Regulatory Recovery

On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all. Rate recovery is uncertain, therefore the Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect.

In addition, SB 901, signed into law on September 21, 2018, requires the CPUC to establish a customer harm threshold, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service (the “Customer Harm Threshold”). SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the Customer Harm Threshold. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs, as the bill does not address fires that occurred in 2018.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the Customer Harm Threshold in future applications under Section 451.2(a) of the Public Utilities Code for cost recovery of 2017 wildfire costs. In the OIR, the CPUC stated that “consistent with Section 451.2(a), the determination of what costs and expenses are just and reasonable must be made in the context of an application for the recovery of specific costs related to the 2017 wildfires.” Following the CPUC’s interpretation of Section 451.2 as outlined in the OIR, PG&E Corporation and the Utility believe that any securitization of costs relating to the 2017 Northern California wildfires would not occur, if at all, until (a) the Utility has paid claims relating to the 2017 Northern California wildfires, (b) the Utility has filed application for recovery of such costs and (c) the CPUC makes a determination that such costs are just and reasonable or in excess of the Customer Harm Threshold. PG&E Corporation and the Utility therefore do not expect the CPUC to permit the Utility to securitize costs relating to the 2017 Northern California wildfires on an expedited or emergency basis unless the CPUC alters the position expressed in the OIR.

On February 11, 2019, PG&E Corporation and the Utility filed opening comments in response to the OIR in which they argued, among other things, the CPUC should (1) promptly set a Customer Harm Threshold, or at least define the methodology for setting the Customer Harm Threshold with sufficient specificity to enable PG&E Corporation and the Utility and potential investors to anticipate that amount; (2) determine the Customer Harm Threshold based on the capital needed to resolve claims arising from both the 2018 Camp fire and 2017 Northern California wildfires to be provided for in a plan of reorganization; (3) define how the Customer Harm Threshold will be applied to any future wildfires; and (4) establish the Customer Harm Threshold based on the amount of debt PG&E Corporation and the Utility can raise. Based on assumptions set forth in the comments, PG&E Corporation and the Utility indicated that they could borrow up to approximately $3 billion to fund wildfire claims costs as part of a plan of reorganization.

Failure to obtain a substantial or full recovery of costs related to the 2018 Camp fire and 2017 Northern California wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows.

Wildfire-Related Derivative Litigation

Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants current and certain former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018, and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay is subject to certain conditions regarding the plaintiffs' access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire.

On August 3, 2018, a third purported derivative lawsuit, entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al., was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation's and the Utility's 2017 proxy statement contained misrepresentations regarding the companies' risk management and safety programs. On October 15, 2018, PG&E Corporation filed a motion to stay the litigation. The hearing on this motion, previously set for January 31, 2019, was moved by stipulation of the parties and order of the court to March 7, 2019.

On October 23, 2018, a fourth purported derivative lawsuit, entitled City of Warren Police and Fire Retirement System v. Chew, et al., was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It names as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and names PG&E Corporation as a nominal defendant. Plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019.

On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al., was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action.

On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. The court scheduled an initial case management conference for March 21, 2019.

On January 25, 2019, a seventh purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants.

On January 28, 2019, an eighth purported derivative lawsuit, entitled Blackburn v. Meserve, et al., was filed in federal court alleging claims for breach of fiduciary duty, unjust enrichment, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these proceedings on February 1, 2019, reflecting that the proceedings are automatically stayed pursuant to Section 362(a) of the Bankruptcy Code. On February 5, 2019, the plaintiff in Bowlinger v. Chew, et al. filed a response to the notice asserting that the automatic stay did not apply to his claims. The court has not yet acted on the plaintiff’s response.

Wildfire-Related Securities Class Action Litigation

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys' fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In Re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico as lead plaintiff. The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend their complaint to add allegations regarding the 2018 Camp fire, the plaintiff filed a second amended consolidated complaint on December 14, 2018.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that the proceedings are automatically stayed pursuant to Section 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants.

On February 22, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. The complaint names as defendants certain current and former officers and directors, as well as the underwriters of 4 public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the federal Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. If necessary, PG&E Corporation and the Utility intend to file a complaint in Bankruptcy Court against the plaintiffs seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer and director defendants.

Clean-up and Repair Costs

The Utility incurred costs of $354 million for clean-up and repair of the Utility’s facilities (including $183 million in capital expenditures) through December 31, 2018, in connection with the 2018 Camp fire. The Utility also incurred costs of $327 million for clean-up and repair of the Utility’s facilities (including $157 million in capital expenditures) through December 31, 2018, in connection with the 2017 Northern California wildfires. The Utility is authorized to track and seek recovery of clean-up and repair costs through CEMA. (CEMA requests are subject to CPUC approval.) The Utility capitalizes and records as regulatory assets costs that are probable of recovery. At December 31, 2018, the CEMA balance related to the 2017 Northern California wildfires was $82 million and is included in long-term regulatory assets on the Consolidated Balance Sheets. Additionally, the capital expenditures for clean-up and repair are included in property, plant and equipment at December 31, 2018.

Should PG&E Corporation and the Utility conclude that recovery of any clean-up and repair costs included in the CEMA is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached. Failure to obtain a substantial or full recovery of these costs or any conclusion that such recovery is no longer probable, could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows.

2015 Butte Fire

In September 2015, a wildfire (the “2015 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 2015 Butte fire. According to Cal Fire’s report, the 2015 Butte 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 2015 Butte fire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.

Third-Party Claims

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California, County of Sacramento. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council previously had authorized the coordination of all cases in Sacramento County. As of January 31, 2019, 95 known complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador. The complaints involve approximately 3,900 individual plaintiffs representing approximately 2,000 households and their insurance companies. These complaints are part of, or were in the process of being added to, the coordinated proceeding. Plaintiffs seek to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability. Plaintiffs also seek punitive damages. Several plaintiffs dismissed the Utility's two vegetation management contractors from their complaints. The Utility does not expect the number of claimants to increase significantly in the future, because the statute of limitations for property damage and personal injury in connection with the 2015 Butte fire has expired. Further, due to the commencement of the Chapter 11 Cases, these plaintiffs have been stayed from continuing to prosecute pending litigation and from commencing new lawsuits against PG&E Corporation or the Utility on account of pre-petition obligations. On January 30, 2019, the Court in the coordinated proceeding issued an order staying the action.

On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages. The court denied the Utility’s motion and the Utility filed a writ with the Court of Appeal of the State of California, Third Appellate District. The writ was granted on July 2, 2018, directing the trial court to enter summary adjudication in favor of the Utility and to deny plaintiffs' claim for punitive damages under California Civil Code Section 3294. Plaintiffs sought rehearing and asked the California Supreme Court to review the Court of Appeal's decision. Both requests were denied. Neither the trial nor appellate courts originally addressed whether plaintiffs can seek punitive damages at trial under Public Utilities Code Section 2106. However, the trial court, in November 2018, denied a motion filed by the Utility that would have confirmed that punitive damages under Public Utilities Code Section 2106 are unavailable. The Utility believes a loss related to punitive damages is unlikely, but possible.

On June 22, 2017, the Superior Court of California, County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnation applies to the Utility with respect to the 2015 Butte fire. The court held, among other things, that the Utility had failed to put forth any evidence to support its contention that the CPUC would not allow the Utility to pass on its inverse condemnation liability through rate increases. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding at the time of the ruling, others could make similar claims. On January 4, 2018, the Utility filed with the court a renewed motion for a legal determination of inverse condemnation liability, citing the November 30, 2017 CPUC decision denying the San Diego Gas & Electric Company application to recover wildfire costs in excess of insurance, and the CPUC declaration that it will not automatically allow utilities to spread inverse condemnation losses through rate increases.

On May 1, 2018, the Superior Court of California, County of Sacramento issued its ruling on the Utility’s renewed motion in which the court affirmed, with minor changes, its tentative ruling dated April 25, 2018. The court determined that it is bound by earlier holdings of two appellate courts decisions, Barham and Pacific Bell. Further, the court stated that the Utility's constitutional arguments should be made to the appellate courts and suggested that, to the extent the Utility raises the public policy implications of the November 30, 2017 CPUC decision in the San Diego Gas & Electric Company cost recovery proceeding, these arguments should be addressed to the Legislature or CPUC. The Utility filed a writ with the Court of Appeal seeking immediate review of the court's decision. On June 18, 2018, after the writ was summarily denied, the Utility filed a Petition for Review with the California Supreme Court, which also was denied. On September 6, 2018, the court set a trial for some individual plaintiffs to begin on April 1, 2019. The Utility reached agreement with two plaintiffs in the litigation to stipulate to judgment against the Utility on inverse condemnation grounds. The court granted the Utility's stipulated judgment motion on November 29, 2018 and the Utility filed its appeal on December 11, 2018. As a result of the filing of the Chapter 11 Cases, these lawsuits, including the trial and the appeal from the stipulated judgment, are stayed.

In addition to the coordinated plaintiffs, Cal Fire, the California Office of Emergency Services (the “OES”), the County of Calaveras, and five smaller public entities (three fire districts, one water district and the California Department of Veterans Affairs) have brought suit or indicated that they intend to do so. The five smaller public entities filed their complaints in August 2018 and September 2018. They have been added to the coordinated proceedings. The Utility has settled the claims of the three fire protection districts.

On April 13, 2017, Cal Fire filed a complaint with the Superior Court of California, County of Calaveras, seeking to recover over $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, or violated the law, among other claims. On July 31, 2017, Cal Fire dismissed its complaint against Trees, Inc., one of the Utility's vegetation contractors. Cal Fire had requested that a trial of its claims be set in 2019, following any trial of the claims of the individual plaintiffs. On October 19, 2018, the Utility filed a motion for summary judgment arguing that Cal Fire cannot recover any fire suppression costs under the Third District Court of Appeal's decision in Dep't of Forestry & Fire Prot. v. Howell (2017) 18 Cal. App. 5th 154. The hearing on that motion was set for January 31, 2019, but the hearing and Cal Fire’s case against the Utility are now stayed. Prior to the stay, the Utility and Cal Fire were also engaged in a mediation process.

Also, on February 20, 2018, the County of Calaveras filed suit against the Utility and the Utility’s vegetation management contractors to recover damages and other costs, based on the doctrine of inverse condemnation and negligence theory of liability. The County also sought punitive damages. On March 2, 2018, the County served a mediation demand seeking in excess of $167 million, having previously indicated that it intended to bring an approximately $85 million claim against the Utility. This claim included costs that the County of Calaveras allegedly incurred or expected to incur for infrastructure damage, erosion control, and other costs. The Utility and the County of Calaveras settled the County's claims in November 2018 for $25.4 million.

Further, in May 2017, the OES indicated that it intended to bring a claim against the Utility that it estimated to be approximately $190 million. This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the 2015 Butte fire. The Utility has not received any information or documentation from OES since its May 2017 statement. In June 2017, the Utility entered into an agreement with the OES that extends their deadline to file a claim to December 2020.

PG&E Corporation's and the Utility's obligations with respect to such outstanding claims are expected to be determined through the Chapter 11 process.

Estimated Losses from Third-Party Claims

In connection with the 2015 Butte fire, the Utility may be liable for property damages, business interruption, interest, and attorneys’ fees without having been found negligent, through the doctrine of inverse condemnation.

In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility is found to have been negligent. While the Utility believes it was not negligent, there can be no assurance that a court would agree with the Utility.

The Utility’s assessment of the estimated loss related to the 2015 Butte fire is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and certain other damages.

The Utility has determined that it is probable that it will incur a loss of $1.1 billion in connection with the 2015 Butte fire. While this amount includes the Utility's assumptions about fire suppression costs (including its assessment of the Cal Fire loss), it does not include any portion of the estimated claim from the OES. The Utility still does not have sufficient information to reasonably estimate any liability it may have for that additional claim.

The process for estimating costs associated with claims relating to the 2015 Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, management estimates and assumptions regarding the financial impact of the 2015 Butte fire may result in material increases to the loss accrued.

The following table presents changes in the third-party claims liability since December 31, 2015. The balance for the third-party claims liability is included in Wildfire-related claims in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Loss Accrual (in millions)
Balance at December 31, 2015	$	—
Accrued losses	750
Payments (1)	(60		)
Balance at December 31, 2016	690
Accrued losses	350
Payments (1)	(479		)
Balance at December 31, 2017	561
Accrued losses	—
Payments (1)	(335		)
Balance at December 31, 2018	$	226

(1) As of December 31, 2018, the Utility has paid $874 million of the $904 million in settlements to date in connection with the 2015 Butte fire.

If the Utility records losses in connection with claims relating to the 2015 Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected in the reporting periods during which additional charges are recorded.

Loss Recoveries

The Utility has liability insurance from various insurers, that provides coverage for third-party liability attributable to the 2015 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 December 31, 2018, the Utility recorded $922 million for probable insurance recoveries in connection with losses related to the 2015 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 year ended December 31, 2018. Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain.

The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s 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	(511		)
Balance at December 31, 2018	$	85

In January and February 2019, the Utility received an additional $25 million in insurance reimbursements.

NOTE 14: OTHER CONTINGENCIES AND COMMITMENTS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation has financial commitments described in “Other Commitments” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Enforcement Matters

In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. It is uncertain whether any charges will be brought against the Utility. Such proceedings are not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

CPUC and FERC Matters

Order Instituting an Investigation and Order to Show Cause into the Utility's Locate and Mark practices

On December 14, 2018, the CPUC issued an OII and order to show cause (the "OII") to assess the Utility's practices and procedures related to the locating and marking of natural gas facilities. The OII directs the Utility to show cause as to why the Commission should not find violations in this matter, and why the Commission should not impose penalties, and/or any other forms of relief, if any violations are found. The Utility also is directed in the OII to provide a report on specific matters, including that it is conducting locate and mark programs in a safe manner.

The OII cites a report by the SED dated December 6, 2018, which alleges that the Utility violated the law pertaining to the locating and marking of its gas facilities and falsified records related to its locate and mark activities between 2012 and 2017. As described in the OII, the SED cites reports issued in this matter by two consultants retained by the Utility, that (i) included certain facts and conclusions about the extent of inaccuracies in the Utility’s late tickets and the reasons for the inaccuracies, and (ii) provided the Utility’s late tickets counts, and identification of associated dig-ins. As a result, the OII will determine whether the Utility violated any provision of the Public Utilities Code, general orders, federal law adopted by California, other rules, or requirements, and/or other state or federal law, by its locate and mark policies, practices, and related issues, and the extent to which the Utility’s practices with regard to locate and mark may have diminished system safety.

The CPUC indicates that it has not concluded that the Utility has violated the law in any instance pertaining to late tickets, locating and marking, or any matter related to either, or to any other matter raised in this OII. However, if violations are found, the CPUC will consider what monetary fines and other remedies are appropriate, will review the duration of violations and, if supported by the evidence, it will consider ordering daily fines.

On January 14, 2019, the Utility submitted responses to preliminary questions raised in the OII and separately filed an affidavit regarding the safety of the locate and mark program. On March 14, 2019, as directed by the CPUC, the Utility expects to submit a report that addresses the SED report and respond to the order to show cause. A schedule for future proceedings is expected to be established at an April 5, 2019 pre-hearing conference.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties, including fines or other remedies, on the Utility. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC's wide discretion and the number of factors that can be considered in determining penalties. The Utility is unable to predict the timing and outcome of this proceeding.

Such proceedings are likely not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

During 2014 and 2015, the Utility filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte communications that either should not have occurred or that should have been timely reported to the CPUC. Ex parte communications include communications between a decision maker and interested persons concerning substantive issues in certain formal proceedings. Certain communications are prohibited and others are permissible with proper noticing and reporting.

On November 23, 2015, the CPUC issued an OII into whether the Utility should be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the CPUC’s Rules of Practice and Procedure governing the conduct of those appearing before the CPUC. The OII cites some of the communications the Utility reported to the CPUC. The OII also cites the ex parte violations alleged in the City of San Bruno’s July 2014 motion, which it filed in CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.

On April 26, 2018, the CPUC approved the revised proposed decision issued on April 3, 2018, adopting the settlement agreement jointly submitted to the CPUC on March 28, 2017, as modified (the "settlement agreement") by the Utility, the Cities of San Bruno and San Carlos, Cal PA, the SED, and TURN.

The decision results in a total penalty of $97.5 million comprised of: (1) a $12 million payment to the California General Fund,

(2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ($31.75 million) and 2019 ($31.75 million), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over the Utility’s next GRC cycle (i.e., the 2020 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above.

As a result of the CPUC's April 26, 2018 decision, on May 17, 2018, the Utility made a $12 million payment to the California General Fund and $6 million payments to each of the Cities of San Bruno and San Carlos. At December 31, 2018, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $32 million accrual for a portion of the 2018 GT&S revenue requirement reduction. In accordance with accounting rules, adjustments related to revenue requirements are recorded in the periods in which they are incurred.

The CPUC also ordered a second phase in this proceeding to determine if any of the additional communications that the Utility reported to the CPUC on September 21, 2017, violate the CPUC ex parte rules. On May 22, 2018, the assigned ALJ issued a ruling requiring the parties to meet and confer to determine if an agreement can be reached on the issues identified by the ALJ. On September 17, 2018, the parties submitted a joint status report indicating a settlement in principle could not be reached. The ALJ will hold a prehearing conference with the parties to determine if evidentiary hearings are required. The Utility is unable to predict the timing and outcome of the second phase in this proceeding.

Such proceedings are likely not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

Transmission Owner Rate Case Revenue Subject to Refund

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, and March 1, 2018, for TO18 and TO19, respectively. Rates subject to refund for TO20 will go into effect on May 1, 2019.

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ's recommendations. The Utility expects the FERC to issue a decision in the TO18 rate case by mid-2019, however, that decision will likely be the subject of requests for rehearing and appeal. The Utility is unable to predict the timing of when a final decision will be issued. On September 21, 2018, the Utility filed an all-party settlement with FERC in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined in the TO18 final decision. The Utility is unable to predict the timing or outcome of FERC’s decisions in these proceedings.

Natural Gas Transmission Pipeline Rights-of-Way

In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey had been completed and that remediation work, including removal of the encroachments, was expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties.

Other Matters

PG&E Corporation and the Utility are subject to various claims, lawsuits and regulatory proceedings that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed in Note 13 and above under “Enforcement and Litigation Matters”) totaled $98 million at December 31, 2018 and $86 million at December 31, 2017. These amounts are included in Other current liabilities in the Consolidated Balance Sheets. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material effect on their financial condition, results of operations, liquidity, and cash flows.

2015 GT&S Rate Case Disallowance of Capital Expenditures

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The decision also established various cost caps that will increase the risk of overspend over the current rate case cycle including new one-way balancing accounts. As a result, in 2016, the Utility incurred charges of $219 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This included $134 million for 2011 through 2014 capital expenditures in excess of adopted amounts and $44 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. The Utility would be required to take a charge in the future if the CPUC's audit of 2011 through 2014 capital spending resulted in additional permanent disallowance. The audit is still in process.

Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of 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. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:

	Balance at
(in millions)	December 31, 2018				December 31, 2017
Topock natural gas compressor station	$	369			$	334
Hinkley natural gas compressor station	146				147
Former manufactured gas plant sites owned by the Utility or third parties (1)	520				320
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	111				115
Fossil fuel-fired generation facilities and sites (3)	137				123
Total environmental remediation liability	$	1,283			$	1,039

(1) Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, and San Francisco North Beach.

(2) Primarily driven by Geothermal landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the EPA under the Federal Resource Conservation and Recovery Act in addition to other state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis, and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at December 31, 2018, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans and the Utility's time frame for remediation. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material effect on results of operations, financial condition, liquidity, and cash flows during the period in which they are recorded. At December 31, 2018, the Utility expected to recover $930 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

Natural Gas Compressor Station Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $303 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates.

Hinkley Site

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. The background study is expected to be finalized in 2019. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $141 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has undertaken a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $518 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $135 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates.

Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $105 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

Insurance

Wildfire Insurance

In 2018, PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general liability (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for property damages only, which property damage coverage includes an aggregate amount of approximately $200 million through the reinsurance market where a catastrophe bond was utilized. Various coverage limitations applicable to different insurance layers could result in substantial uninsured costs in the future depending on the amount and type of damages.

PG&E Corporation’s and the Utility’s cost of obtaining wildfire insurance coverage has increased to $360 million, compared to the adopted approximately $50 million that the Utility is currently recovering through rates through December 31, 2019. The Utility intends to seek recovery for the full amount of premium costs paid in excess of the amount the Utility currently is recovering from customers through the end of the current GRC period, which ends on December 31, 2019.

Nuclear Insurance

The Utility is a member of NEIL, which is a mutual insurer owned by utilities with nuclear facilities. NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.6 billion per non-nuclear incident for Diablo Canyon. Humboldt Bay Unit 3 has up to $131 million of coverage for nuclear and non-nuclear property damages.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Certain acts of terrorism may be “certified” by the Secretary of the Treasury. If damages are caused by certified acts of terrorism, NEIL can obtain reimbursement from the federal government up to a shared limit of $3.2 billion for each insured loss for NEIL members. In contrast, for acts of terrorism not deemed "certified" by the Secretary of the Treasury, NEIL treats all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share a $3.2 billion policy limit amount.

In addition to the nuclear insurance the Utility maintains through the NEIL, the Utility also is a member of the EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. EMANI provides $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies

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 December 31, 2018, the current maximum aggregate annual retrospective premium obligation for the Utility would be approximately $47 million. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $3 million, as of December 31, 2018.

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $14.1 billion. The Utility purchased the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $14.1 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $275 million per nuclear incident under this program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.

Resolution of Remaining 2001 Chapter 11 Disputed Claims

Various electricity suppliers filed claims in the Utility’s 2001 prior proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While the FERC and judicial proceedings are pending, the Utility pursued settlements with electricity suppliers and 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, in some instances, would be subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods.

At December 31, 2018 and December 31, 2017, respectively, the Consolidated Balance Sheets reflected $220 million and $243 million in net claims within Disputed claims and customer refunds related to the 2001 Chapter 11 proceeding. The Utility's obligations with respect to such claims (all of which arose prior to the initiation of the Utility's pending Chapter 11 Case on January 29, 2019), including pursuant to any prior settlements relating thereto, are expected to be determined through the proceedings of the Chapter 11 Cases.

Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2018:

	Power Purchase Agreements
(in millions)	Renewable Energy				Conventional Energy				Other				Natural Gas				Nuclear Fuel				Total
2019	$	2,221			$	642			$	108			$	412			$	108			$	3,491
2020	2,183				639				83				153				151				3,209
2021	2,174				582				65				93				64				2,978
2022	1,984				511				61				93				54				2,703
2023	1,914				223				61				93				49				2,340
Thereafter	24,217				435				162				264				47				25,125
Total purchase commitments	$	34,693			$	3,032			$	540			$	1,108			$	473			$	39,846

Subject to certain exceptions, under the Bankruptcy Code, PG&E Corporation and the Utility may assume, assign or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and satisfaction of certain other conditions. (For more information see "Chapter 11 Proceedings" in Note 15 below.)

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.

Renewable Energy Power Purchase Agreements. In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate. The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow. As of December 31, 2018, renewable energy contracts expire at various dates between 2019 and 2043.

Conventional Energy Power Purchase Agreements. The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements. The Utility’s obligation under a portion of these agreements is contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. As of December 31, 2018, these power purchase agreements expire at various dates between 2019 and 2033.

Other Power Purchase Agreements. The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. Two of these agreements are treated as capital leases. At December 31, 2018 and 2017, net capital leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $11 million and $18 million including accumulated amortization of $8 million and $143 million, respectively. The present value of the future minimum lease payments due under these agreements included $2 million and $11 million in Current Liabilities and $9 million and $7 million in Noncurrent Liabilities on the Consolidated Balance Sheet, respectively. As of December 31, 2018, QF contracts in operation expire at various dates between 2019 and 2049. In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The costs incurred for all power purchases and electric capacity amounted to $3.1 billion in 2018, $3.3 billion in 2017, and $3.5 billion in 2016.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. These agreements expire at various dates between 2019 and 2026. In addition, the Utility has contracted for natural gas storage services in northern California to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.6 billion in 2018, $0.9 billion in 2017, and $0.7 billion in 2016.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between 2019 and 2024 and are intended to ensure long-term nuclear fuel supply. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

Payments for nuclear fuel amounted to $73 million in 2018, $83 million in 2017, and $100 million in 2016.

Other Commitments

PG&E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and land), which expire at various dates between 2019 and 2052. At December 31, 2018, the future minimum payments related to these commitments were as follows:

(in millions)	Operating Leases
2019	$	44
2020	41
2021	36
2022	28
2023	19
Thereafter	121
Total minimum lease payments	$	289

Payments for other commitments related to operating leases amounted to $43 million in 2018, $45 million in 2017, and $43 million in 2016. Certain leases on office facilities contain escalation clauses requiring annual increases in rent. The rentals payable under these leases may increase by a fixed amount each year, a percentage of increase over base year, or the consumer price index. Most leases contain extension operations ranging between one and five years.

NOTE 15: SUBSEQUENT EVENTS

Chapter 11 Proceedings

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation's and the Utility’s Chapter 11 Cases are being jointly administered under the caption In re: PG&E Corporation and Pacific Gas and Electric Company, Case No. 19-30088 (DM).

PG&E Corporation and the Utility continue to operate their businesses as debtors in possession under the jurisdiction of the Bankruptcy Court and in accordance with applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. As debtors in possession, PG&E Corporation and the Utility are authorized to continue to operate as ongoing businesses, and may pay all debts and honor all obligations arising in the ordinary course of their businesses after the Petition Date. However, PG&E Corporation and the Utility may not pay third-party claims or creditors on account of obligations arising before the Petition Date or engage in transactions outside the ordinary course of business without approval of the Bankruptcy Court.

Under the Bankruptcy Code, third-party actions to collect pre-petition indebtedness owed by PG&E Corporation or the Utility, as well as most litigation pending against PG&E Corporation and the Utility (including the third-party matters described in Note 13 above), are subject to an automatic stay. Absent an order of the Bankruptcy Court providing otherwise, substantially all pre-petition liabilities will be administered under a Chapter 11 plan of reorganization to be voted upon by creditors and other stakeholders, and approved by the Bankruptcy Court. However, under the Bankruptcy Code, regulatory or criminal proceedings are generally not subject to an automatic stay, and PG&E Corporation and the Utility expect these proceedings to continue during the pendency of the Chapter 11 Cases.

To assure ordinary course operations, on January 31, 2019, PG&E Corporation and the Utility received interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions that authorize them to maintain their existing cash management system, to continue wage and salary payments and other benefits to their employees, to secure debtor in possession financing and other customary relief. On February 27, 2019, PG&E Corporation and the Utility received final approval of the first day motion to continue wage and salary payments and other benefits to their employees (with one limited objection with respect to a discrete matter having been preserved by the Bankruptcy Court) and certain other first day motions for customary relief. Hearings on certain other first day motions, including a hearing to consider final approval of PG&E Corporation’s and the Utility’s motions to continue their existing cash management system and to approve their debtor in possession financing, have not been held and no assurances can be given that the Bankruptcy Court will approve such motions on a final basis. PG&E Corporation and the Utility are unable to predict the date of the final hearing with respect to such motions, but there are hearings currently scheduled for March 12, March 13 and March 27, 2019.

In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement. See Note 4 above for a description of the DIP Credit Agreement.

The commencement of the Chapter 11 Cases constituted an event of default or termination event, and caused an automatic and immediate acceleration of the Accelerated Direct Financial Obligations. Accordingly, as a result of the commencement of the Chapter 11 Cases, the principal amount of the Accelerated Direct Financial Obligations, together with accrued interest thereon, and in case of certain indebtedness, premium, if any, thereon, immediately became due and payable. However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation's term loan facility, as well as short-term borrowings under PG&E Corporation's and the Utility's revolving credit facilities and the Utility's term loan facility disclosed in Note 4 above. The filing of the Chapter 11 Cases may also provide the counterparties under certain commodity and related agreements with the right to declare an event of default and to seek termination of such rights subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Under the priority scheme established by the Bankruptcy Code, certain post-petition and secured or “priority” pre-petition liabilities need to be satisfied before general unsecured creditors and holders of PG&E Corporation's and the Utility’s equity are entitled to receive any distribution. No assurance can be given as to what values, if any, will be ascribed in the Chapter 11 Cases to the claims and interests of each of these constituencies. Additionally, no assurance can be given as to whether, when or in what form unsecured creditors and holders of PG&E Corporation’s or the Utility’s equity may receive a distribution on such claims or interests.

Under the Bankruptcy Code, PG&E Corporation and the Utility may assume, assume and assign, or reject certain executory contracts and unexpired leases, including, without limitation, leases of real property and equipment, subject to the approval of the Bankruptcy Court and to certain other conditions. Any description of an executory contract or unexpired lease in this Annual Report on Form 10-K, including, where applicable, the express termination rights thereunder or a quantification of their obligations, must be read in conjunction with, and is qualified by, any overriding rejection rights PG&E Corporation and the Utility have under the Bankruptcy Code.

As of February 28, 2019, the Utility had outstanding borrowings of $350 million under the DIP Revolving Facility and $30 million in face amount of outstanding letters of credit, with remaining availability of $1.12 billion under the DIP Revolving Facility.

US District Court Matters and Probation

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On January 26, 2017, the court issued a judgment of conviction against the Utility. The court sentenced the Utility to a 5-year corporate probation period, oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after 3 years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.

The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained a third-party monitor at the Utility’s expense. The goal of the third-party monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

On November 27, 2018, the court overseeing the Utility’s probation, issued an order requiring that the Utility, the United States Attorney’s Office for the Northern District of California (the “USAO”) and the third-party monitor provide written answers to a series of questions regarding the Utility’s compliance with the terms of its probation, including what requirements of the Utility’s probation “might be implicated were any wildfire started by reckless operation or maintenance of PG&E power lines” or “might be implicated by any inaccurate, slow, or failed reporting of information about any wildfire by PG&E.” The court also ordered the Utility to provide “an accurate and complete statement of the role, if any, of PG&E in causing and reporting the recent 2018 Camp fire in Butte County and all other wildfires in California” since January 2017 (“Question 4 of the November 27 Order”). On December 5, 2018, the court issued an order requesting that the Office of the California Attorney General advise the court of its view on “the extent to which, if at all, the reckless operation or maintenance of PG&E power lines would constitute a crime under California law.” The responses of the Attorney General were submitted on December 28, 2018, and the responses of the Utility, the USAO and the third-party monitor were submitted on December 31, 2018.

On January 3, 2019, the court issued a new order requiring that the Utility provide further information regarding the Atlas fire. The court noted that “[t]his order postpones the question of the adequacy of PG&E’s response” to Question 4 of the November 27 Order. On January 4, 2019, the court issued another order requiring that the Utility provide “with respect to each of the eighteen October 2017 Northern California wildfires that [Cal Fire] has attributed to [the Utility’s] facilities,” information regarding the wind conditions in the vicinity of each fire’s origin and information about the equipment allegedly involved in each fire’s ignition. The responses of the Utility were submitted on January 10, 2019.

On January 9, 2019, the court ordered the Utility to appear in court on January 30, 2019, as a result of the court’s finding that “there is probable cause to believe there has been a violation of the conditions of supervision” with respect to reporting requirements related to the 2017 Honey fire. In addition, on January 9, 2019, the court issued an order (the “January 9 Order”) proposing to add new conditions of probation that would require the Utility, among other things, to:

•

prior to June 21, 2019, “re-inspect all of its electrical grid and remove or trim all trees that could fall onto its power lines, poles or equipment in high-wind conditions, . . . identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions[,] identify and fix damaged or weakened poles, transformers, fuses and other connectors [and] identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires”,

•	“document the foregoing inspections and the work done and . . . rate each segment’s safety under various wind conditions” and

•	at all times from and after June 21, 2019, “supply electricity only through those parts of its electrical grid it has determined to be safe under the wind conditions then prevailing.”

The Utility was ordered to show cause by January 23, 2019, as to why the Utility’s conditions of probation should not be modified as proposed. The Utility's response was submitted on January 23, 2019. The court requested that Cal Fire file a public statement, and invited the CPUC to comment, by January 25, 2019. On January 30, 2019, the court found that the Utility had violated a condition of its probation with respect to reporting requirements related to the 2017 Honey fire. The court issued an order stating that a sentencing hearing on the probation violation will be set at a later date. The court also invited parties to comment by February 20, 2019, on the 2019 Wildfire Safety Plan that the Utility submitted to the CPUC on February 6, 2019.

QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

	Quarter ended
(in millions, except per share amounts)	December 31				September 30				June 30				March 31
2018
PG&E CORPORATION
Operating revenues (1)	$	4,088			$	4,381			$	4,234			$	4,056
Operating income (loss)	(9,530		)		696				(1,465		)		599
Income tax provision (benefit) (2)	(2,765		)		15				(593		)		51
Net income (loss) (3)	(6,869		)		567				(980		)		445
Income (loss) available for common shareholders	(6,873		)		564				(984		)		442
Comprehensive income (loss)	(6,866		)		568				(980		)		445
Net earnings (loss) per common share, basic	(13.24		)		1.09				(1.91		)		0.86
Net earnings (loss) per common share, diluted	(13.24		)		1.09				(1.91		)		0.86
UTILITY
Operating revenues (1)	$	4,088			$	4,382			$	4,234			$	4,056
Operating income (loss)	(9,530		)		697				(1,465		)		599
Income tax provision (benefit) (2)	(2,765		)		14				(592		)		48
Net income (loss) (3)	(6,865		)		571				(976		)		452
Income (loss) available for common stock	(6,869		)		568				(980		)		449
Comprehensive income (loss)	(6,871		)		571				(975		)		452
2017
PG&E CORPORATION
Operating revenues (4)	$	4,100			$	4,517			$	4,250			$	4,268
Operating income	429				899				748				880
Income tax provision (5)	108				160				134				109
Net income (6)	118				553				410				579
Income available for common shareholders	114				550				406				576
Comprehensive income	118				553				411				579
Net earnings per common share, basic	0.22				1.07				0.79				1.13
Net earnings per common share, diluted	0.22				1.07				0.79				1.13
UTILITY
Operating revenues (4)	$	4,101			$	4,516			$	4,250			$	4,271
Operating income	434				834				749				883
Income tax provision (5)	33				138				136				120
Net income (6)	200				513				409				569
Income available for common stock	196				510				405				566
Comprehensive income	203				513				409				570

(1) In the first quarter of 2018, the Utility recorded $81 million as provisions for rate refunds for the 2017 GRC and 2015 GT&S rate case as a result of the Tax Act.

(2) In the second and fourth quarters of 2018, the Utility had an income tax benefit as a result of pre-tax losses.

(3) In the second quarter of 2018, the Utility recorded a pre-tax charge of $2.5 billion as a result of the 2017 Northern California wildfires. In the fourth quarter of 2018, the Utility recorded a pre-tax charge of $10.5 billion as a result of the 2018 Camp fire and an additional $1.0 billion pre-tax charge for the 2017 Northern California wildfires.

(4) In the first quarter of 2017, the Utility recorded the remaining retroactive revenues related to the 2015 GT&S rate case decision authorized by the CPUC.

(5) In the fourth quarter of 2017, the Utility had lower income tax expense primarily due to lower operating income, which was partially offset by the impact of the Tax Act.

(6) In the second quarter of 2017, the Utility recorded a $47 million disallowance related to the Diablo Canyon settlement. Also, in the third quarter of 2017, the Utility recorded a $350 million charge related to 2015 Butte fire third-party claims. In the first, second, and third quarters of 2017, the Utility recorded $7 million, $14 million, and $276 million, respectively, for probable insurance recoveries in connection with recovery of losses related to the 2015 Butte fire. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of PG&E Corporation and the Utility is responsible for establishing and maintaining adequate internal control over financial reporting. PG&E Corporation’s and the Utility’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, or GAAP. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of PG&E Corporation and the Utility, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures are being made only in accordance with authorizations of management and directors of PG&E Corporation and the Utility, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of internal control over financial reporting as of December 31, 2018, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment and those criteria, management has concluded that PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, 2018.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

PG&E Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the "Company") as of December 31, 2018 and 2017, the Company’s related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2019 expressed an unqualified opinion on the Company's internal control over financial reporting.

Going Concern

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Notes 1 and 13 to the financial statements, the 2017 Northern California wildfires and the 2018 Camp wildfire may result in material losses to the Company, which contributed to the Company’s decision to voluntarily file for bankruptcy as discussed below. These circumstances raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Bankruptcy Proceedings

As discussed in Note 1 to the financial statements, on January 29, 2019, the Company has voluntarily filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The accompanying financial statements do not purport to reflect or provide for the consequences of the bankruptcy proceedings. In particular, such financial statements do not purport to show (1) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (2) as to pre-petition liabilities, the settlement amounts for allowed claims, or the status and priority thereof; (3) as to shareholder accounts, the effect of any changes that may be made in the capitalization of the Company; or (4) as to operations, the effect of any changes that may be made in its business.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

February 28, 2019

We have served as the Company’s auditor since 1999.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Pacific Gas and Electric Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2018 and 2017, and the Utility’s related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Utility as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Utility’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2019 expressed an unqualified opinion on the Utility’s internal control over financial reporting.

Going Concern

The accompanying financial statements have been prepared assuming that the Utility will continue as a going concern. As discussed in Notes 1 and 13 to the financial statements, the 2017 Northern California wildfires and the 2018 Camp wildfire may result in material losses to the Utility, which contributed to the Utility’s decision to voluntarily file for bankruptcy as discussed below. These circumstances and uncertainties inherent in the bankruptcy proceedings raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Bankruptcy Proceedings

As discussed in Note 1 to the financial statements, on January 29, 2019, the Utility has voluntarily filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The accompanying financial statements do not purport to reflect or provide for the consequences of the bankruptcy proceedings. In particular, such financial statements do not purport to show (1) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (2) as to pre-petition liabilities, the settlement amounts for allowed claims, or the status and priority thereof; (3) as to shareholder accounts, the effect of any changes that may be made in the capitalization of the Company; or (4) as to operations, the effect of any changes that may be made in its business.

Basis for Opinion

These financial statements are the responsibility of the Utility’s management. Our responsibility is to express an opinion on the Utility’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Utility in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

February 28, 2019

We have served as the Utility’s auditor since 1999.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

PG&E Corporation

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of PG&E Corporation and subsidiaries (the "Company") as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2018, of the Company and our report dated February 28, 2019, expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph regarding certain conditions that give rise to substantial doubt about the Company’s ability to continue as a going concern and an emphasis of matter paragraph concerning the bankruptcy proceedings.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

February 28, 2019

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Pacific Gas and Electric Company

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Pacific Gas and Electric Company and subsidiaries (the "Utility") as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2018, of the Utility and our report dated February 28, 2019, expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph regarding certain conditions that give rise to substantial doubt about the Utility’s ability to continue as a going concern and an emphasis of matter paragraph concerning the bankruptcy proceedings.

Basis for Opinion

The Utility’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Utility’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Utility in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

February 28, 2019