GLOSSARY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

NOTE 4: DEBT

NOTE 5: EQUITY

NOTE 6: EARNINGS PER SHARE

NOTE 7: DERIVATIVES

NOTE 8: FAIR VALUE MEASUREMENTS

NOTE 9: CONTINGENCIES AND COMMITMENTS

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

OVERVIEW

LIQUIDITY AND FINANCIAL RESOURCES

ENFORCEMENT AND LITIGATION MATTERS

REGULATORY MATTERS

STATE AND FEDERAL INITIATIVES

ENVIRONMENTAL MATTERS

CONTRACTUAL COMMITMENTS

RISK MANAGEMENT ACTIVITIES

CRITICAL ACCOUNTING POLICIES

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

FORWARD-LOOKING STATEMENTS

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4. CONTROLS AND PROCEDURES

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

ITEM 5. OTHER INFORMATION

ITEM 6. EXHIBITS

SIGNATURES

GLOSSARY

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

2016 Form 10-K	PG&E Corporation and Pacific Gas and Electric Company's combined Annual Report on Form 10-K for the year ended December 31, 2016
2017 Q1 Form 10-Q	PG&E Corporation and Pacific Gas and Electric Company's combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2017
AB	Assembly Bill
AFUDC	allowance for funds used during construction
ALJ	administrative law judge
ARO	asset retirement obligation
ASU	accounting standard update issued by the FASB (see below)
CAISO	California Independent System Operator
Cal Fire	California Department of Forestry and Fire Protection
CARB	California Air Resources Board
CCA	Community Choice Aggregator
Central Coast Board	Central Coast Regional Water Quality Control Board
CEC	California Energy Resources Conservation and Development Commission
CO2	carbon dioxide
CP	cathodic protection
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DER	distributed energy resources
DIDF	Distribution Investment Deferral Framework
Diablo Canyon	Diablo Canyon nuclear power plant
DOE	U.S. Department of Energy
DOGGR	Division of Oil, Gas, and Geothermal Resources
DOI	U.S. Department of the Interior
DRP	electric distribution resources plan
DTSC	Department of Toxic Substances Control
EDA	equity distribution agreement
EMANI	European Mutual Association for Nuclear Insurance
EPA	Environmental Protection Agency
EPS	earnings per common share
EV	electric vehicle
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	U.S. Generally Accepted Accounting Principles
GHG	greenhouse gas
GRC	general rate case
GT&S	gas transmission and storage
GWH	gigawatt-hours
IOU(s)	investor-owned utility(ies)
IRS	Internal Revenue Service
LTIP	long-term incentive plan
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 2, of this Form 10-Q
MOU	memorandum of understanding
NAV	net asset value
NDCTP	Nuclear Decommissioning Cost Triennial Proceedings
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering

NERC	North American Electric Reliability Corporation
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
OEM	original equipment manufacturer
OES	State of California Office of Emergency Services
OII	order instituting investigation
OIR	order instituting rulemaking
ORA	Office of Ratepayer Advocates
PCIA	Power Charge Indifference Adjustment
PD	proposed decision
PFM	petition for modification
PHMSA	Pipeline and Hazardous Materials Safety Administration
QF	qualifying facility
Regional Board	California Regional Water Quality Control Board, Lahontan Region
RFO	requests for offers
ROE	return on equity
RPS	renewable portfolio standards
SB	Senate Bill
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC
TE	transportation electrification
TO	transmission owner
TURN	The Utility Reform Network
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)
WECC	Western Electricity Coordinating Council
WEMA	Wildfire Expense Memorandum Account
Westinghouse	Westinghouse Electric Company, LLC

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions, except per share amounts)	2017		2016		2017		2016
Operating Revenues
Electric	$	3,323	$	3,465	$	6,388	$	6,596
Natural gas		927		704		2,130		1,547
Total operating revenues		4,250		4,169		8,518		8,143
Operating Expenses
Cost of electricity		1,123		1,156		1,970		2,106
Cost of natural gas		121		75		446		297
Operating and maintenance		1,546		1,838		3,050		3,848
Depreciation, amortization, and decommissioning		712		699		1,424		1,396
Total operating expenses		3,502		3,768		6,890		7,647
Operating Income		748		401		1,628		496
Interest income		8		5		13		9
Interest expense		(225)		(207)		(443)		(410)
Other income, net		13		23		34		50
Income Before Income Taxes		544		222		1,232		145
Income tax provision (benefit)		134		12		243		(175)
Net Income		410		210		989		320
Preferred stock dividend requirement of subsidiary		4		4		7		7
Income Available for Common Shareholders	$	406	$	206	$	982	$	313
Weighted Average Common Shares Outstanding, Basic		511		497		510		495
Weighted Average Common Shares Outstanding, Diluted		513		498		512		497
Net Earnings Per Common Share, Basic	$	0.79	$	0.41	$	1.93	$	0.63
Net Earnings Per Common Share, Diluted	$	0.79	$	0.41	$	1.92	$	0.63
Dividends Declared Per Common Share	$	0.53	$	0.49	$	1.02	$	0.95

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions)	2017		2016		2017		2016
Net Income	$	410	$	210	$	989	$	320
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $0, $0 and $0, at respective dates)		1		-		1		-
Total other comprehensive income (loss)		1		-		1		-
Comprehensive Income		411		210		990		320
Preferred stock dividend requirement of subsidiary		4		4		7		7
Comprehensive Income Attributable to
Common Shareholders	$	407	$	206	$	983	$	313

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions)	2017		2016
ASSETS
Current Assets
Cash and cash equivalents	$	178	$	177
Restricted cash		7		7
Accounts receivable:
Customers (net of allowance for doubtful accounts of $60 and $58
at respective dates)		1,208		1,252
Accrued unbilled revenue		988		1,098
Regulatory balancing accounts		1,565		1,500
Other		760		801
Regulatory assets		522		423
Inventories:
Gas stored underground and fuel oil		132		117
Materials and supplies		369		346
Income taxes receivable		93		160
Other		249		283
Total current assets		6,071		6,164
Property, Plant, and Equipment
Electric		53,692		52,556
Gas		18,555		17,853
Construction work in progress		2,311		2,184
Other		2		2
Total property, plant, and equipment		74,560		72,595
Accumulated depreciation		(22,924)		(22,014)
Net property, plant, and equipment		51,636		50,581
Other Noncurrent Assets
Regulatory assets		8,311		7,951
Nuclear decommissioning trusts		2,733		2,606
Income taxes receivable		70		70
Other		1,234		1,226
Total other noncurrent assets		12,348		11,853
TOTAL ASSETS	$	70,055	$	68,598

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions, except share amounts)	2017		2016
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,180	$	1,516
Long-term debt, classified as current		700		700
Accounts payable:
Trade creditors		1,389		1,495
Regulatory balancing accounts		871		645
Other		423		433
Disputed claims and customer refunds		238		236
Interest payable		220		216
Other		1,927		2,323
Total current liabilities		6,948		7,564
Noncurrent Liabilities
Long-term debt		16,616		16,220
Regulatory liabilities		7,125		6,805
Pension and other postretirement benefits		2,687		2,641
Asset retirement obligations		4,675		4,684
Deferred income taxes		10,753		10,213
Other		2,360		2,279
Total noncurrent liabilities		44,216		42,842
Commitments and Contingencies (Note 9)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares;
512,220,726 and 506,891,874 shares outstanding at respective dates		12,442		12,198
Reinvested earnings		6,205		5,751
Accumulated other comprehensive loss		(8)		(9)
Total shareholders' equity		18,639		17,940
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252
Total equity		18,891		18,192
TOTAL LIABILITIES AND EQUITY	$	70,055	$	68,598

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Six Months Ended June 30,
(in millions)	2017		2016
Cash Flows from Operating Activities
Net income	$	989	$	320
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,424		1,396
Allowance for equity funds used during construction		(34)		(54)
Deferred income taxes and tax credits, net		516		350
Disallowed capital expenditures		47		425
Other		121		179
Effect of changes in operating assets and liabilities:
Accounts receivable		111		(75)
Butte-related insurance receivable		54		(263)
Inventories		(38)		(30)
Accounts payable		19		179
Butte-related third-party claims		(116)		349
Income taxes receivable/payable		67		(79)
Other current assets and liabilities		(92)		(7)
Regulatory assets, liabilities, and balancing accounts, net		(353)		(769)
Other noncurrent assets and liabilities		41		(106)
Net cash provided by operating activities		2,756		1,815
Cash Flows from Investing Activities
Capital expenditures		(2,474)		(2,651)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		794		721
Purchases of nuclear decommissioning trust investments		(817)		(762)
Other		8		6
Net cash used in investing activities		(2,489)		(2,686)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of
$3 at respective dates		(339)		257
Short-term debt financing		250		250
Short-term debt matured		(250)		-
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $11 and $6 at respective dates		734		594
Long-term debt matured or repurchased		(345)		-
Common stock issued		247		289
Common stock dividends paid		(488)		(440)
Other		(75)		(13)
Net cash provided by (used in) financing activities		(266)		937
Net change in cash and cash equivalents		1		66
Cash and cash equivalents at January 1		177		123
Cash and cash equivalents at June 30	$	178	$	189

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(395)	$	(357)
Income taxes, net		68		54
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	271	$	244
Capital expenditures financed through accounts payable		268		309
Noncash common stock issuances		10		10

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions)	2017		2016		2017		2016
Operating Revenues
Electric	$	3,324	$	3,465	$	6,391	$	6,597
Natural gas		926		704		2,130		1,547
Total operating revenues		4,250		4,169		8,521		8,144
Operating Expenses
Cost of electricity		1,123		1,156		1,970		2,106
Cost of natural gas		121		75		446		297
Operating and maintenance		1,545		1,837		3,049		3,848
Depreciation, amortization, and decommissioning		712		700		1,424		1,396
Total operating expenses		3,501		3,768		6,889		7,647
Operating Income		749		401		1,632		497
Interest income		7		4		12		8
Interest expense		(222)		(204)		(438)		(405)
Other income, net		11		21		28		45
Income Before Income Taxes		545		222		1,234		145
Income tax provision (benefit)		136		13		256		(172)
Net Income		409		209		978		317
Preferred stock dividend requirement		4		4		7		7
Income Available for Common Stock	$	405	$	205	$	971	$	310

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Three Months Ended					Six Months Ended
	June 30,					June 30,
(in millions)	2017		2016			2017	2016
Net Income	$	409	$	209	$	978	$	317
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $0, $0 and $0, at respective dates )		-		1		1		1
Total other comprehensive income (loss)		-		1		1		1
Comprehensive Income	$	409	$	210	$	979	$	318

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions)	2017		2016
ASSETS
Current Assets
Cash and cash equivalents	$	57	$	71
Restricted cash		7		7
Accounts receivable:
Customers (net of allowance for doubtful accounts of $60 and $58
at respective dates)		1,208		1,252
Accrued unbilled revenue		988		1,098
Regulatory balancing accounts		1,565		1,500
Other		758		801
Regulatory assets		522		423
Inventories:
Gas stored underground and fuel oil		132		117
Materials and supplies		369		346
Income taxes receivable		84		159
Other		248		282
Total current assets		5,938		6,056
Property, Plant, and Equipment
Electric		53,692		52,556
Gas		18,555		17,853
Construction work in progress		2,311		2,184
Total property, plant, and equipment		74,558		72,593
Accumulated depreciation		(22,922)		(22,012)
Net property, plant, and equipment		51,636		50,581
Other Noncurrent Assets
Regulatory assets		8,311		7,951
Nuclear decommissioning trusts		2,733		2,606
Income taxes receivable		70		70
Other		1,111		1,110
Total other noncurrent assets		12,225		11,737
TOTAL ASSETS	$	69,799	$	68,374

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions, except share amounts)	2017		2016
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	1,180	$	1,516
Long-term debt, classified as current		700		700
Accounts payable:
Trade creditors		1,389		1,494
Regulatory balancing accounts		871		645
Other		468		453
Disputed claims and customer refunds		238		236
Interest payable		218		214
Other		1,664		2,072
Total current liabilities		6,728		7,330
Noncurrent Liabilities
Long-term debt		16,267		15,872
Regulatory liabilities		7,125		6,805
Pension and other postretirement benefits		2,592		2,548
Asset retirement obligations		4,675		4,684
Deferred income taxes		11,063		10,510
Other		2,306		2,230
Total noncurrent liabilities		44,028		42,649
Commitments and Contingencies (Note 9)
Shareholders' Equity
Preferred stock		258		258
Common stock, $5 par value, authorized 800,000,000 shares;
264,374,809 shares outstanding at respective dates		1,322		1,322
Additional paid-in capital		8,240		8,050
Reinvested earnings		9,220		8,763
Accumulated other comprehensive income		3		2
Total shareholders' equity		19,043		18,395
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	69,799	$	68,374

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

	(Unaudited)
	Six Months Ended June 30,
(in millions)	2017		2016
Cash Flows from Operating Activities
Net income	$	978	$	317
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,424		1,396
Allowance for equity funds used during construction		(34)		(54)
Deferred income taxes and tax credits, net		534		352
Disallowed capital expenditures		47		425
Other		127		144
Effect of changes in operating assets and liabilities:
Accounts receivable		113		(76)
Butte-related insurance receivable		54		(263)
Inventories		(38)		(30)
Accounts payable		45		190
Butte-related third-party claims		(116)		349
Income taxes receivable/payable		75		(78)
Other current assets and liabilities		(72)		(5)
Regulatory assets, liabilities, and balancing accounts, net		(353)		(769)
Other noncurrent assets and liabilities		40		(95)
Net cash provided by operating activities		2,824		1,803
Cash Flows from Investing Activities
Capital expenditures		(2,474)		(2,651)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		794		721
Purchases of nuclear decommissioning trust investments		(817)		(762)
Other		8		6
Net cash used in investing activities		(2,489)		(2,686)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of
$3 at respective dates		(339)		257
Short-term debt financing		250		250
Short-term debt matured		(250)		-
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $11 and $6 at respective dates		734		594
Long-term debt matured or repurchased		(345)		-
Preferred stock dividends paid		(7)		(7)
Common stock dividends paid		(514)		(423)
Equity contribution from PG&E Corporation		190		280
Other		(68)		(7)
Net cash provided by (used in) financing activities		(349)		944
Net change in cash and cash equivalents		(14)		61
Cash and cash equivalents at January 1		71		59
Cash and cash equivalents at June 30	$	57	$	120

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(390)	$	(352)
Income taxes, net		76		54
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	268	$	309

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2016 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2016 Form 10-K. This quarterly report should be read in conjunction with the 2016 Form 10-K.

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K.

Variable Interest Entities

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

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility has a controlling interest or was the primary beneficiary of any of these VIEs at June 30, 2017, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at June 30, 2017, it did not consolidate any of them.

Asset Retirement Obligations

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. On May 25, 2017, the CPUC issued a final decision in the 2015 NDCTP adopting a nuclear decommissioning cost estimate of $1.1 billion for Humboldt Bay, corresponding to the Utility’s request, and $2.4 billion for Diablo Canyon, compared to the Utility’s request of $3.8 billion, or 64 percent of its request. On an aggregate basis, the final decision adopted a $3.5 billion total nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s estimated cost to decommission Diablo Canyon, the final decision adopts assumptions which lower costs for large component removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility can seek recovery of these costs in the 2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ARO on the Condensed Consolidated Balance Sheets related to the assumed length of the wet cooling period of spent nuclear fuel after plant shut down.

The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Condensed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $3.4 billion at June 30, 2017, and $3.5 billion at December 31, 2016. These estimates are based on decommissioning cost studies, prepared in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets.

Pension and Other Post-retirement Benefits

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

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2017 and 2016 were as follows:

	Pension Benefits				Other Benefits
	Three Months Ended June 30,
(in millions)	2017		2016		2017		2016
Service cost for benefits earned	$	118	$	113	$	15	$	13
Interest cost		178		179		19		19
Expected return on plan assets		(192)		(207)		(25)		(27)
Amortization of prior service cost		(2)		2		4		4
Amortization of net actuarial loss		5		6		1		1
Net periodic benefit cost		107		93		14		10
Regulatory account transfer (1)		(23)		(8)		-		-
Total	$	84	$	85	$	14	$	10

(1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

	Pension Benefits				Other Benefits
	Six Months Ended June 30,
(in millions)	2017		2016		2017		2016
Service cost for benefits earned	$	236	$	226	$	30	$	26
Interest cost		357		358		38		38
Expected return on plan assets		(385)		(414)		(49)		(54)
Amortization of prior service cost		(4)		4		8		8
Amortization of net actuarial loss		11		12		2		2
Net periodic benefit cost		215		186		29		20
Regulatory account transfer (1)		(46)		(17)		-		-
Total	$	169	$	169	$	29	$	20

(1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

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

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss)

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below:

	Pension		Other
	Benefits		Benefits		Total
(in millions, net of income tax)	Three Months Ended June 30, 2017
Beginning balance	$	(25)	$	16	$	(9)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $1 and $1, respectively)		(1)		3		2
Amortization of net actuarial loss
(net of taxes of $2 and $1, respectively)		3		-		3
Regulatory account transfer
(net of taxes of $1 and $2, respectively)		(2)		(2)		(4)
Net current period other comprehensive gain (loss)		-		1		1
Ending balance	$	(25)	$	17	$	(8)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.)

	Pension		Other
	Benefits		Benefits		Total
(in millions, net of income tax)	Three Months Ended June 30, 2016
Beginning balance	$	(23)	$	16	$	(7)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $1 and $1, respectively)		1		3		4
Amortization of net actuarial loss
(net of taxes of $2, and $1, respectively)		4		-		4
Regulatory account transfer
(net of taxes of $3 and $2, respectively)		(5)		(3)		(8)
Net current period other comprehensive gain (loss)		-		-		-
Ending balance	$	(23)	$	16	$	(7)

	Pension		Other
	Benefits		Benefits		Total
(in millions, net of income tax)	Six Months Ended June 30, 2017
Beginning balance	$	(25)	$	16	$	(9)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $2 and $3, respectively)		(2)		5		3
Amortization of net actuarial loss
(net of taxes of $5 and $1, respectively)		6		1		7
Regulatory account transfer
(net of taxes of $3 and $4, respectively)		(4)		(5)		(9)
Net current period other comprehensive gain (loss)		-		1		1
Ending balance	$	(25)	$	17	$	(8)

	Pension		Other
	Benefits		Benefits		Total
(in millions, net of income tax)	Six Months Ended June 30, 2016
Beginning balance	$	(23)	$	16	$	(7)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $2 and $3, respectively)		2		5		7
Amortization of net actuarial loss
(net of taxes of $4 and $1, respectively)		8		1		9
Regulatory account transfer
(net of taxes of $6 and $4, respectively)		(10)		(6)		(16)
Net current period other comprehensive gain (loss)		-		-		-
Ending balance	$	(23)	$	16	$	(7)

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

Recently Adopted Accounting Guidance

Share-Based Payment Accounting

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718), which amends the existing guidance relating to the accounting for share-based payment awards issued to employees, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statements of cash flows. PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016.

ASU 2016-09 requires, on a retrospective basis, that employee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities. As such, the Condensed Consolidated Statements of Cash Flows for PG&E Corporation and the Utility for the prior periods presented were retrospectively adjusted. This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $34 million for the six months ended June 30, 2016.

Accounting Standards Issued But Not Yet Adopted

Presentation of Net Periodic Pension Cost

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715), which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The amendment requires an employer to disaggregate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted. Although PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on the Condensed Consolidated Financial Statements and related disclosures, it is not expected to have a material impact to financial results.

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. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted. As of June 30, 2017, PG&E Corporation and the Utility held immaterial balances within restricted cash. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on the Condensed Consolidated Statements of Cash Flows and related disclosures.

Recognition of Lease Assets and Liabilities

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing guidance relating to the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheet, which were previously not recognized. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019 and will be applied on a modified retrospective basis. PG&E Corporation and the Utility are still evaluating the impact the guidance will have on the Condensed Consolidated Financial Statements and related disclosures.

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 existing guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income. The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts. These investments are classified as “available-for-sale” and gains or losses are refundable, or recoverable, from customers through rates. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018. PG&E Corporation and the Utility do not anticipate a material impact to the Condensed Consolidated Financial Statements and related disclosures as a result of this ASU.

Revenue Recognition Standard

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance, effective January 1, 2018. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. PG&E Corporation and the Utility intend to use the modified retrospective method when adopting the new standard on January 1, 2018. PG&E Corporation and the Utility are currently reviewing all revenue streams and evaluating the impact the guidance will have on the Condensed Consolidated Financial Statements and related disclosures.

While the Utility expects that most of its revenue will be included in the scope of ASU 2014-09, it has not yet fully completed its evaluation. The majority of the Utility’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Utility generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue recognition for such sales. The Utility continues to consider the impacts of outstanding industry-related issues being addressed by the American Institute of CPAs’ Revenue Recognition Working Group and the FASB’s Transition Resource Group. Additionally, the Utility expects more detailed revenue disclosures related to the nature, timing and uncertainty in revenues upon adoption of ASU 2014-09.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets and Liabilities

Long-term regulatory assets and liabilities are comprised of the following:

	Asset Balance at
(in millions)	June 30, 2017		December 31, 2016
Deferred income taxes	$	4,195	$	3,859
Pension benefits		2,467		2,429
Environmental compliance costs		770		778
Utility retained generation		342		364
Price risk management		84		92
Unamortized loss, net of gain, on reacquired debt		69		76
Other		384		353
Total long-term regulatory assets	$	8,311	$	7,951

	Liability Balance at
(in millions)	June 30, 2017		December 31, 2016
Cost of removal obligations	$	5,342	$	5,060
Recoveries in excess of AROs		661		626
Public purpose programs		554		567
Other		568		552
Total long-term regulatory liabilities	$	7,125	$	6,805

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.

Regulatory Balancing Accounts

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

	Receivable
	Balance at
(in millions)	June 30, 2017		December 31, 2016
Electric distribution	$	285	$	132
Electric transmission		212		244
Utility generation		117		48
Gas distribution and transmission		433		541
Energy procurement		-		132
Public purpose programs		129		106
Other		389		297
Total regulatory balancing accounts receivable	$	1,565	$	1,500

	Payable
	Balance at
(in millions)	June 30, 2017		December 31, 2016
Electric transmission	$	171	$	99
Gas distribution and transmission		-		48
Energy procurement		86		13
Public purpose programs		376		264
Other		238		221
Total regulatory balancing accounts payable	$	871	$	645

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.

NOTE 4: DEBT

Revolving Credit Facilities and Commercial Paper Program

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at June 30, 2017:

					Letters of
	Termination	Facility			Credit		Commercial		Facility
(in millions)	Date	Limit			Outstanding		Paper		Availability
PG&E Corporation	April 2022	$	300	(1)	$	-	$	-	$	300
Utility	April 2022		3,000	(2)		42		681		2,277
Total revolving credit facilities		$	3,300		$	42	$	681	$	2,577

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

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

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.

Other Short-term Borrowings

In February 2017, the Utility’s $250 million floating rate unsecured term loan, issued in March 2016, matured and was repaid.

Additionally, in February 2017, the Utility entered into a $250 million floating rate unsecured term loan that matures on February 22, 2018. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

Senior Notes Issuances

In March 2017, the Utility issued $400 million principal amount of 3.30% Senior Notes due March 15, 2027 and $200 million principal amount of 4.00% Senior Notes due December 1, 2046. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

Pollution Control Bonds

In June 2017, the Utility repurchased and retired $345 million principal amount of pollution control bonds Series 2004 A through D. Additionally in June 2017, the Utility remarketed three series of pollution control bonds, previously held in treasury, totaling $145 million in principal amount. Series 2008 F and 2010 E bear interest at 1.75% per annum and mature on November 1, 2026. Series 2008 G bears interest at 1.05% per annum and matures on December 1, 2018.

At June 30, 2017, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.84% to 0.95%. At June 30, 2017, the interest rates on the $149 million principal amount of pollution control bonds Series 2009 A and B, and the related loan agreements, were 0.88%.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the six months ended June 30, 2017 were as follows:

	PG&E Corporation		Utility
	Total		Total
(in millions)	Equity		Shareholders' Equity
Balance at December 31, 2016	$	18,192	$	18,395
Comprehensive income		990		979
Equity contributions		-		190
Common stock issued		257		-
Share-based compensation		(13)		-
Common stock dividends declared		(528)		(514)
Preferred stock dividend requirement		-		(7)
Preferred stock dividend requirement of subsidiary		(7)		-
Balance at June 30, 2017	$	18,891	$	19,043

In February 2017, PG&E Corporation amended its February 2015 EDA providing for the sale of PG&E Corporation common stock having an aggregate price of up to $275 million. During the six months ended June 30, 2017, PG&E Corporation sold 0.4 million shares of its common stock under the February 2017 EDA for cash proceeds of $28.4 million, net of commissions paid of $0.2 million. There were no issuances under the February 2017 EDA for the three months ended June 30, 2017. As of June 30, 2017, the remaining sales available under this agreement were $246.3 million.

PG&E Corporation also issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the six months ended June 30, 2017, 4.9 million shares were issued for cash proceeds of $218 million under these plans.

NOTE 6: 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:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions, except per share amounts)	2017		2016		2017		2016
Income available for common shareholders	$	406	$	206	$	982	$	313
Weighted average common shares outstanding, basic		511		497		510		495
Add incremental shares from assumed conversions:
Employee share-based compensation		2		1		2		2
Weighted average common shares outstanding, diluted		513		498		512		497
Total earnings per common share, diluted	$	0.79	$	0.41	$	1.92	$	0.63

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 7: DERIVATIVES

Use of Derivative Instruments

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

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

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

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

		Contract Volume at
		June 30,	December 31,
Underlying Product	Instruments	2017	2016
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	288,947,618	323,301,331
	Options	76,490,259	96,602,785
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	3,706,674	3,287,397
	Congestion Revenue Rights (3)	254,357,332	278,143,281

(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 June 30, 2017, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative						Total Derivative
(in millions)	Balance		Netting		Cash Collateral		Balance
Current assets – other	$	56	$	(10)	$	16	$	62
Other noncurrent assets – other		123		(4)		-		119
Current liabilities – other		(52)		10		7		(35)
Noncurrent liabilities – other		(88)		4		9		(75)
Total commodity risk	$	39	$	-	$	32	$	71

At December 31, 2016, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative						Total Derivative
(in millions)	Balance		Netting		Cash Collateral		Balance
Current assets – other	$	91	$	(10)	$	1	$	82
Other noncurrent assets – other		149		(9)		-		140
Current liabilities – other		(48)		10		-		(38)
Noncurrent liabilities – other		(101)		9		3		(89)
Total commodity risk	$	91	$	-	$	4	$	95

Gains and losses associated with price risk management activities were recorded as follows:

	Commodity Risk
	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions)	2017		2016		2017		2016
Unrealized gain (loss) - regulatory assets and liabilities (1)	$	(4)	$	66	$	(52)	$	59
Realized gain (loss) - cost of electricity (2)		1		(12)		(4)		(41)
Realized loss - cost of natural gas (2)		(3)		(5)		(4)		(6)
Net commodity risk	$	(6)	$	49	$	(60)	$	12

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.

(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

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

The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At June 30, 2017, the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions.

The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:

	Balance at
	June 30,		December 31,
(in millions)	2017		2016
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(1)	$	(24)
Related derivatives in an asset position		-		19
Collateral posting in the normal course of business related to
these derivatives		-		4
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(1)	$	(1)

(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies.

NOTE 8: 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 June 30, 2017
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	121	$	-	$	-	$	-	$	121
Nuclear decommissioning trusts
Short-term investments		10		-		-		-		10
Global equity securities		1,786		-		-		-		1,786
Fixed-income securities		740		571		-		-		1,311
Assets measured at NAV		-		-		-		-		16
Total nuclear decommissioning trusts (2)		2,536		571		-		-		3,123
Price risk management instruments
(Note 7)
Electricity		5		9		158		3		175
Gas		2		5		-		(1)		6
Total price risk management
instruments		7		14		158		2		181
Rabbi trusts
Fixed-income securities		-		63		-		-		63
Life insurance contracts		-		71		-		-		71
Total rabbi trusts		-		134		-		-		134
Long-term disability trust
Short-term investments		5		-		-		-		5
Assets measured at NAV		-		-		-		-		156
Total long-term disability trust		5		-		-		-		161
TOTAL ASSETS	$	2,669	$	719	$	158	$	2	$	3,720
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	12	$	17	$	110	$	(30)	$	109
Gas		-		1		-		-		1
TOTAL LIABILITIES	$	12	$	18	$	110	$	(30)	$	110

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

(2) Represents amount before deducting $390 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	105	$	-	$	-	$	-	$	105
Nuclear decommissioning trusts
Short-term investments		9		-		-		-		9
Global equity securities		1,724		-		-		-		1,724
Fixed-income securities		665		527		-		-		1,192
Assets measured at NAV		-		-		-		-		14
Total nuclear decommissioning trusts (2)		2,398		527		-		-		2,939
Price risk management instruments
(Note 9 in the 2016 Form 10-K)
Electricity		30		18		181		(18)		211
Gas		-		11		-		-		11
Total price risk management
instruments		30		29		181		(18)		222
Rabbi trusts
Fixed-income securities		-		61		-		-		61
Life insurance contracts		-		70		-		-		70
Total rabbi trusts		-		131		-		-		131
Long-term disability trust
Short-term investments		8		-		-		-		8
Assets measured at NAV		-		-		-		-		170
Total long-term disability trust		8		-		-		-		178
TOTAL ASSETS	$	2,541	$	687	$	181	$	(18)	$	3,575
Liabilities:
Price risk management instruments
(Note 9 in the 2016 Form 10-K)
Electricity	$	9	$	12	$	126	$	(21)	$	126
Gas		-		2		-		(1)		1
TOTAL LIABILITIES	$	9	$	14	$	126	$	(22)	$	127

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

(2) Represents amount before deducting $333 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 six months ended June 30, 2017 and 2016.

Trust Assets

Assets Measured at Fair Value

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1.

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

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

Assets Measured at NAV Using Practical Expedient

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

Price Risk Management Instruments

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

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

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

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

Level 3 Measurements and Sensitivity Analysis

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

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 7 above.)

	Fair Value at
(in millions)	At June 30, 2017				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	158	$	37	Market approach	CRR auction prices	$	(11.88) - 10.54
Power purchase agreements	$	-	$	73	Discounted cash flow	Forward prices	$	18.81 - 38.80

(1) Represents price per megawatt-hour

	Fair Value at
(in millions)	At December 31, 2016				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	181	$	35	Market approach	CRR auction prices	$	(11.88) - 6.93
Power purchase agreements	$	-	$	91	Discounted cash flow	Forward prices	$	18.07 - 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 three and six months ended June 30, 2017 and 2016:

	Price Risk Management Instruments
(in millions)	2017		2016
Asset (liability) balance as of April 1	$	49	$	75
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(1)		(9)
Asset (liability) balance as of June 30	$	48	$	66

(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.

	Price Risk Management Instruments
(in millions)	2017		2016
Asset (liability) balance as of January 1	$	55	$	89
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(7)		(23)
Asset (liability) balance as of June 30	$	48	$	66

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, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at June 30, 2017 and December 31, 2016, as they are short-term in nature or have interest rates that reset daily.

The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at June 30, 2017 and December 31, 2016.

	At June 30, 2017				At December 31, 2016
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
PG&E Corporation	$	348	$	352	$	348	$	352
Utility		16,208		18,583		15,813		17,790

Available for Sale Investments

The following table provides a summary of available-for-sale investments:

				Total		Total
	Amortized			Unrealized		Unrealized		Total Fair
(in millions)	Cost			Gains		Losses		Value
As of June 30, 2017
Nuclear decommissioning trusts
Short-term investments	$	10	$	-	$	-	$	10
Global equity securities		527		1,277		(2)		1,802
Fixed-income securities		1,260		57		(6)		1,311
Total (1)	$	1,797	$	1,334	$	(8)	$	3,123
As of December 31, 2016
Nuclear decommissioning trusts
Short-term investments	$	9	$	-	$	-	$	9
Global equity securities		584		1,157		(3)		1,738
Fixed-income securities		1,156		48		(12)		1,192
Total (1)	$	1,749	$	1,205	$	(15)	$	2,939

(1) Represents amounts before deducting $390 million and $333 million at June 30, 2017 and December 31, 2016, 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)	June 30, 2017
Less than 1 year	$	6
1–5 years		452
5–10 years		308
More than 10 years		545
Total maturities of fixed-income securities	$	1,311

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016			2017	2016
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
trust investments	$	324	$	282	$	794	$	721
Gross realized gains on securities held as available-for-sale		13		4		42		9
Gross realized losses on securities held as available-for-sale		(3)		(1)		(8)		(3)

NOTE 9: 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. A gain contingency is recorded in the period in which all uncertainties have been resolved. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters.

Butte Fire Litigation and Regulatory Citations

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. Cal Fire’s report concluded that the wildfire was caused when a gray pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.

Third-Party Claims

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of June 30, 2017, approximately 60 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 involving approximately 2,050 individual plaintiffs representing approximately 1,180 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints. Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability. Plaintiffs also seek punitive damages. The number of individual complaints and plaintiffs may increase in the future. The Utility continues mediating and settling cases.

In addition, on April 13, 2017, Cal Fire filed a complaint with the Superior Court of the State of California, County of Calaveras, seeking to recover $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, among other claims.

Also, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $190 million. This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the Butte fire. Also, in June 2017, the County of Calaveras indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $85 million. This claim would include costs that the County of Calaveras incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire.

Two trials have been scheduled in connection with the Butte fire. On April 14, 2017, the Superior Court of California for Sacramento County found that six “preference” households (households that include individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling) are entitled to a trial. The trial has been scheduled to commence on August 14, 2017 in Sacramento.

The court also set a representative trial date for October 30, 2017 in Sacramento. A representative trial is a trial where the parties agree, or the court decides, on plaintiffs who are “representative” of broader groups of plaintiffs such that the trial may assist the parties in settling other cases after obtaining verdicts in the representative trial.

Estimated Losses from Third-Party Claims

In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the theory of inverse condemnation. On June 22, 2017, the Superior Court for the County of Sacramento ruled on a motion of several plaintiffs and found that the Utility is liable for inverse condemnation. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding, others could file lawsuits and make similar claims. In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent. While the Utility believes it was not negligent, there can be no assurance that a court or jury would agree with the Utility.

The Utility believes that it is probable that it will incur a loss of at least $750 million in connection with the Butte fire. This amount 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, but does not include punitive damages for which the Utility could be liable. In addition, while this amount includes the Utility’s early assumptions about fire suppression costs (including its assessment of the Cal Fire loss), it does not include any significant portion of the estimated claims from the OES and the County of Calaveras. The Utility currently does not have sufficient information to reasonably estimate any liability it may have for these additional claims.

The Utility currently is unable to reasonably estimate the upper end of the range of losses because it is still in an early stage of the evaluation of claims, the mediation and settlement process, and discovery. The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs, results from the ongoing mediation and settlement process, review of potential claims from the OES and the County of Calaveras, outcomes of future court or jury decisions, and information about damages, including punitive damages, that the Utility could be liable for, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued.

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 Other current liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

Loss Accrual (in millions)
Balance at December 31, 2015	$	-
Accrued losses		750
Payments (1)		(60)
Balance at December 31, 2016	$	690
Accrued losses		-
Payments (1)		(116)
Balance at June 30, 2017	$	574

(1) As of June 30, 2017 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $380 million of which $176 million has been paid by the Utility.

In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $54 million in connection with the Butte fire. For the three months and six months ended June 30, 2017, the Utility has incurred legal expenses in connection with the Butte fire of $17 and $27 million, respectively.

Loss Recoveries

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of approximately $900 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 June 30, 2017, the Utility recorded $646 million for probable insurance recoveries in connection with losses related to the Butte fire. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. In addition, in the second quarter of 2017, the Utility received $32 million of reimbursements from the insurance policies of one of its vegetation management contractors (excluded from the table below). Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain.

The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

Insurance Receivable (in millions)
Balance at December 31, 2015	$	-
Accrued insurance recoveries		625
Reimbursements		(50)
Balance at December 31, 2016	$	575
Accrued insurance recoveries		21
Reimbursements		(75)
Balance at June 30, 2017	$	521

If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded, depending on whether the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals.

If the Utility’s ultimate liability were to exceed amounts recoverable under its liability insurance coverage and from third parties, the Utility would expect to seek authorization from the CPUC to recover any excess amounts from customers. On July 26, 2017, the Utility filed an application with the CPUC requesting to establish a Wildfire Expense Memorandum Account to track wildfire expenses and to preserve the opportunity for the Utility to request recovery of wildfire costs in excess of insurance at a future date. The resolution of claims, the recoveries from other potentially responsible parties, and future regulatory proceedings, if any, could extend over a number of years.

Regulatory Citations

On April 25, 2017, the SED issued two citations to the Utility in connection with the Butte fire, totaling $8.3 million. The SED’s investigation found that neither the Utility nor its vegetation management contractors took appropriate steps to prevent the gray pine from leaning and contacting the Utility’s electric line, which created an unsafe and dangerous condition that resulted in that tree leaning and making contact with the electric line, thus causing a fire. The Utility paid the citations in June 2017.

CPUC Matters

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

On March 28, 2017, the Utility, the Cities of San Bruno and San Carlos, the ORA, the SED, and TURN (together, the “parties”) jointly submitted to the CPUC a settlement agreement in connection with the order instituting an investigation into the Utility’s compliance with the CPUC’s ex parte communication rules and jointly moved for its approval. As previously disclosed, the Utility has already incurred a disallowance of $72 million imposed by the CPUC in connection with certain ex parte communications in the Utility’s 2015 GT&S rate case. Of the $72 million total GT&S ex parte disallowance, $57 million was recognized in 2016 and the remaining $15 million was recognized in the first quarter of 2017.

Pursuant to the settlement agreement, the Utility agreed to a total financial remedy of $86.5 million comprised of: (1) a $1 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 its next GRC cycle (i.e., the GRC following the 2017 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above.

On June 19, 2017, the assigned ALJ issued a ruling requesting that the Utility file a supplemental briefing on the number of admitted violations and whether or not those violations were continuing. The Utility filed the brief on June 23, 2017, admitting that 12 communications were violations of the CPUC’s ex parte rules and noting that the additional communications at issue in the proceeding had been included by other parties and the Utility did not agree they constituted violations. The Utility did not admit that any particular violation was continuing, which would be decided by the CPUC if there were no settlement.

The CPUC may accept, reject, or modify the terms of the settlement agreement, including imposing additional penalties on the Utility. The statutory deadline for this proceeding was extended from May 17, 2017 to December 29, 2017. The Utility is unable to predict the outcome of this proceeding.

At June 30, 2017, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $13 million accrual for the portions of the settlement agreement that would be payable to the California General Fund and the Cities of San Bruno and San Carlos. In accordance with accounting rules, adjustments related to revenue requirements would be recorded in the periods in which they are incurred.

For more information about the proceeding, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K.

Order Instituting an Investigation into the Utility’s Safety Culture

On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards. The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents. The CPUC authorized the SED to engage a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment.

On May 8, 2017, the CPUC President released the consultant's report, accompanied by a scoping memo and ruling. The scoping memo establishes a second phase in this OII in which the CPUC will evaluate the safety recommendations of the consultant which may lead to the CPUC’s adoption of the recommendations in the report, in whole or in part. This phase of the proceeding will also consider all necessary measures, including, but not limited to, a reduction of the Utility’s return on equity until any recommendations adopted by the CPUC are implemented. The Utility plans to adopt the vast majority of the consultant's recommendations and to have completed most of the agreed-upon recommendations by the middle of 2018. A prehearing conference has been scheduled for August 1, 2017. Under the current schedule, the Utility’s testimony is expected to occur in the fourth quarter of 2017 with other parties’ testimony and evidentiary hearings expected in the first quarter of 2018.

PG&E Corporation and the Utility are unable to predict the outcome of this proceeding, including whether additional fines, penalties, or other ratemaking tools will ultimately be adopted by the CPUC, and whether the CPUC will require that a portion of return on equity for the Utility be dependent on making safety progress as the CPUC may define in this proceeding.

Natural Gas Transmission Pipeline Rights-of-Way

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

Potential Safety Citations

The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. There are a number of audit findings, as well as other potential violations identified through various investigations and the Utility’s self-reported non-compliance with laws and regulations, on which the SED has yet to act. This includes the Utility’s February 2017 self-report related to customer service representatives who handle gas emergency calls that was not timely submitted to the CPUC. The Utility believes it is probable that the SED will impose penalties or take other enforcement action with respect to some or all of these violations. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed by the SED with respect to these matters given the wide discretion the SED and other CPUC staff has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

The SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000, with an administrative limit of $8 million per citation issued. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED also has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The SED also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The SED historically has exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. The CPUC can also issue an OII and possible additional fines even after the SED has issued a citation. The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations.

Federal Investigations

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. In addition, in October 2016, the Utility received a grand jury subpoena and letter from the U.S. Attorney for the Northern District of California advising that the Utility is a target of a federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act. The investigation involves a removal by the Utility of a hazardous tree that contained an osprey nest and egg in Inverness, California, on March 18, 2016. The utility is cooperating with this investigation. It is uncertain whether any charges will be brought against the Utility as a result of these investigations.

Other Matters

PG&E Corporation and the Utility are subject to various claims, lawsuits, and regulatory proceedings that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $43 million at June 30, 2017 and $45 million at December 31, 2016. These amounts are included in Other current liabilities in the Condensed Consolidated Balance Sheets. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

Disallowance of Plant Costs

In May 2017, the Utility filed a settlement agreement with the CPUC related to the recovery of license renewal costs and cancelled project costs within its pending application to retire Diablo Canyon Power Plant. The settlement agreement allows for recovery from customers of $18.6 million of the total license renewal project cost of $53 million evenly over an 8-year period beginning January 1, 2018. Related to cancelled project costs, the settlement allows for recovery from customers of 100% of the direct costs incurred prior to June 30, 2016 and 25% recovery of direct costs incurred after June 30, 2016. During the three and six months ended June 30, 2017, the Utility incurred charges of $47 million related to settlement agreement, of which $24 million is for cancelled projects and $23 million is for disallowed license renewal costs.

In addition, the Utility is subject to various cost caps within its rate cases that increase the risk of overspend throughout the rate case cycles. Charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending related to its 2015 GT&S rate case. PG&E Corporation and the Utility would record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates and the amount of disallowance can be reasonably estimated. Capital disallowances are reflected in operating and maintenance expenses in the Condensed Consolidated Statements of Income. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K.

Environmental Remediation Contingencies

The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is composed of the following:

	Balance at
	June 30,		December 31,
(in millions)	2017		2016
Topock natural gas compressor station (1)	$	313	$	299
Hinkley natural gas compressor station (1)		128		135
Former manufactured gas plant sites owned by the Utility or third parties		319		285
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		131		131
Fossil fuel-fired generation facilities and sites		124		108
Total environmental remediation liability	$	1,015	$	958

(1) See “Natural Gas Compressor Station Sites” below.

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 Conversation and Recovery Act as well as 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, on an ongoing basis, measures that may be necessary to comply with these laws and regulations and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at June 30, 2017 reflects its best estimate of probable future costs associated with its final remediation plans. Future costs will depend on many factors, including the extent of work to implement final remediation plans and the Utility’s required time frame for remediation. Future changes in cost estimates and the assumptions on which they are based may have a material impact on the Utility’s future financial condition and cash flows.

At June 30, 2017, the Utility expected to recover $718 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. Some of the Utility’s environmental remediation liability, such as the environmental remediation costs associated with the Hinkley site discussed below, will not be recovered in rates.

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. One of these stations is located near Needles, California and is referred to below as the “Topock site.” Another station is located near Hinkley, California and is referred to below as the “Hinkley site.” The Utility is also required to take measures to abate the effects of the contamination on the environment.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the DOI. In November 2015, the Utility submitted its final remediation design to the agencies for approval. The Utility’s design proposes that the Utility construct an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The DTSC conducted an additional environmental review of the proposed design and issued a draft environmental impact report for public comment in January 2017. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in late 2017. After the Utility modifies its design in response to the final report, the Utility will seek approval to begin construction of the new in-situ treatment system in 2018.

Hinkley Site

The Utility has been implementing interim remediation measures at the Hinkley site to reduce the mass of the chromium plume 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 Regional Board. In November 2015, the Regional Board adopted a final clean-up and abatement order to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order requires setting plume capture requirements, requires establishing a monitoring and reporting program, and finalizes deadlines for the Utility to meet interim cleanup targets.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility’s undiscounted future costs could increase by as much as $1.0 billion (including amounts related to the Topock and Hinkley sites described above) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non- nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a maximum aggregate annual retrospective premium obligation of approximately $58 million. EMANI provides $200 million for any one accident and in the annual aggregate the excess of the combined amount recoverable under the Utility’s NEIL policies. For more information about the Utility’s nuclear insurance coverage, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.

Resolution of Remaining Chapter 11 Disputed Claims

Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. The Utility has entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. Under these settlement agreements, amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods.

At December 31, 2016, the Consolidated Balance Sheets reflected $236 million in net claims within Disputed claims and customer refunds. There were no significant changes to this balance during the six months ended June 30, 2017. The Utility is uncertain when or how the remaining net disputed claims liability will be resolved.

Tax Matters

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of audits. As of June 30, 2017, it is reasonably possible that unrecognized tax benefits will decrease by approximately $70 million within the next 12 months. PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income.

Gain Contingencies

Litigation Related to the San Bruno Accident

As of June 30, 2017, there were seven shareholder derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by certain current and former officers and directors (the “Individual Defendants”), among other claims. Four of the cases were consolidated as the San Bruno Fire Derivative Cases and are pending in the Superior Court of California, County of San Mateo (the “Court”). The remaining three cases are Tellardin v. Anthony F. Earley, Jr., et al., Iron Workers Mid-South Pension Fund v. Johns, et al., and Bushkin v. Rambo, et al. (the “Additional Derivative Cases”).

On March 15, 2017, the parties in the San Bruno Fire Derivative Cases filed with the Court a settlement that they reached to resolve the consolidated shareholder derivative lawsuit and certain additional claims against the Individual Defendants. Pursuant to the settlement stipulation, subject to certain conditions: (1) the Individual Defendants’ directors and officers liability insurance carriers will pay $90 million to PG&E Corporation within 11 business days of the entry of the judgment approving settlement in the San Bruno Fire Derivative Cases, (2) PG&E Corporation and the Utility will implement certain corporate governance therapeutics for five years, and (3) the Utility will implement certain gas operations therapeutics and maintain certain of them for three years, at an estimated cost of up to approximately $32 million.

In addition, PG&E Corporation agreed to pay any fee and expense award that the Court may grant to counsel for the plaintiffs in the San Bruno Fire Derivative Cases in an amount not to exceed $25 million for fees and $500,000 for expenses. PG&E Corporation and the Utility also agreed, under their indemnification obligations to the Individual Defendants, to pay $18.3 million of the Individual Defendants’ costs, fees, and expenses incurred in connection with responding to, defending and settling the San Bruno Fire Derivative Cases and the Additional Derivative Cases, including certain fees and expenses for investigating these claims. The $18.3 million has been paid, with the majority reflected in PG&E Corporation’s and the Utility’s financial statements through December 31, 2016.

The settlement is expressly conditioned on, among other things, the Additional Derivative Cases being dismissed with prejudice, which condition can only be waived by PG&E Corporation and a majority of the Individual Defendants.

The preliminary settlement approval hearing took place on April 21, 2017. At this hearing, PG&E Corporation and the Utility agreed that notwithstanding the expiration of the five-year and three-year periods applicable to the corporate and gas operations therapeutics described above, neither entity will make any material changes to such therapeutics unless those changes are reported in PG&E Corporation’s Corporate Responsibility and Sustainability Report or another suitable report at least three months prior to their taking effect. With this modification, the Court preliminarily approved the settlement, preliminarily finding it fair, reasonable, adequate, and in the best interests of PG&E Corporation, the Utility, and the shareholders of PG&E Corporation.

Pursuant to the settlement, plaintiffs in the San Bruno Fire Derivative Cases filed an amended complaint on May 16, 2017 designed to capture the broadest range of claims to be dismissed as part of the overall settlement. The parties have stipulated that defendants need not respond to the amended complaint unless the settlement fails.

On July 18, 2017, the Court issued a judgment approving the settlement. The Court also directed PG&E Corporation to provide at least quarterly reports to the Court and to the City of San Bruno summarizing the progress of the implementation of the corporate governance and gas operations therapeutics. Also, as of July 19, 2017, the Additional Derivative Cases were dismissed. The settlement will become effective when all remaining conditions specified in the settlement stipulation are satisfied.

There was no impact on PG&E Corporation or the Utility’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2017. PG&E Corporation estimates it will record $65 million in the period when the insurance proceeds are received.

Purchase Commitments

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. At December 31, 2016, the Utility had undiscounted future expected obligations of approximately $47 billion. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.) The Utility has not entered into any new material commitments during the six months ended June 30, 2017.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

The Utility is regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction over the rates, terms, and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and interstate natural gas transportation contracts. The NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The Utility is also subject to the jurisdiction of other federal, state, and local governmental agencies.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report. It also should be read in conjunction with the 2016 Form 10-K.

Summary of Changes in Net Income and Earnings per Share

The tables below include a summary reconciliation of the key changes in PG&E Corporation’s consolidated income available for common shareholders and EPS to earnings from operations and EPS based on earnings from operations for three and six months ended June 30, 2017 as compared to the same periods in 2016 and a summary reconciliation of the key drivers of PG&E Corporation’s earnings from operations and EPS based on earnings from operations for the three and six months ended June 30, 2017 as compared to the same periods in 2016. “Earnings from operations” is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability. “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods. PG&E Corporation uses earnings from operations to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short and long-term operating plans, and employee incentive compensation. PG&E Corporation believes that earnings from operations provide additional insight into the underlying trends of the business allowing for a better comparison against historical results and expectations for future performance. Earnings from operations are not a substitute or alternative for GAAP measures such as income available for common shareholders and may not be comparable to similarly titled measures used by other companies.

	Three Months Ended June 30,								Six Months Ended June 30,
					Earnings per								Earnings per
					Common Share								Common Share
(in millions,	Earnings				(Diluted)				Earnings				(Diluted)
except per share amounts)	2017		2016		2017		2016		2017		2016		2017		2016
PG&E Corporation’s
Earnings on a GAAP basis	$	406	$	206	$	0.79	$	0.41	$	982	$	313	$	1.92	$	0.63
Items Impacting
Comparability: (1)
Pipeline related expenses (2)		17		16		0.03		0.03		33		29		0.06		0.06
Legal and regulatory
related expenses (3)		2		8		0.01		0.02		4		18		0.01		0.04
Fines and penalties (4)		-		112		-		0.22		36		163		0.07		0.32
Butte fire related insurance
recoveries, net of legal costs (5)		(17)		(125)		(0.03)		(0.25)		(15)		101		(0.03)		0.20
GT&S revenue timing impact (6)		-		-		-		-		(88)		-		(0.17)		-
Diablo Canyon settlement-related
disallowance (7)		32		-		0.06		-		32		-		0.06		-
GT&S capital disallowance		-		113		-		0.23		-		113		-		0.23
PG&E Corporation’s
Earnings from Operations (8)	$	440	$	330	$	0.86	$	0.66	$	984	$	737	$	1.92	$	1.48

All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 40.75 percent, except as indicated below.

(1) “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods.

(2) The Utility incurred costs of $29 million (before the tax impact of $12 million) and $56 million (before the tax impact of $23 million) during the three and six months ended June 30, 2017, respectively, for pipeline related expenses incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline rights-of-way.

(3) The Utility incurred costs of $3 million (before the tax impact of $1 million) and $7 million (before the tax impact of $3 million) during the three and six months ended June 30, 2017, respectively, for legal and regulatory related expenses incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

(4) The Utility incurred costs of $60 million (before the tax impact of $24 million) during the six months ended June 30, 2017, for fines and penalties. This includes costs of $32 million (before the tax impact of $13 million) during the six months ended June 30, 2017, associated with safety-related cost disallowances imposed by the CPUC in its April 9, 2015 decision (“San Bruno Penalty Decision”) in the gas transmission pipeline investigations. The Utility also recorded $15 million (before the tax impact of $6 million) during the six months ended June 30, 2017, for disallowances imposed by the CPUC in its final phase two decision of the 2015 GT&S rate case for prohibited ex parte communications. In addition, the Utility recorded $12 million (before the tax impact of $5 million) and $1 million (which is not tax deductible) during the six months ended June 30, 2017, for financial remedies in connection with the settlement filed with the CPUC on March 28, 2017, related to the Order Instituting an Investigation into Compliance with Ex Parte Communication Rules. Future fines or penalties may be imposed in connection with other enforcement, regulatory, and litigation activities regarding regulatory communications.

(5) The Utility recorded insurance recoveries, net of legal costs, of $29 million (before the tax impact of $12 million) and $26 million (before the tax impact of $11 million) during the three and six months ended June 30, 2017, respectively, associated with the Butte fire. This includes $46 million (before the tax impact of $19 million) and $53 million (before the tax impact of $22 million) during the three and six months ended June 30, 2017, respectively, for insurance recoveries, partially offset by $17 million (before the tax impact of $7 million) and $27 million (before the tax impact of $11 million) recorded during the three and six months ended June 30, 2017, respectively, for legal costs associated with the Butte fire.

(6)As a result of the CPUC’s final phase two decision in the 2015 GT&S rate case, during the six months ended June 30, 2017, the Utility recorded revenues of $150 million (before the tax impact of $62 million) in excess of the 2017 authorized revenue requirement, which includes the final component of under-collected revenues retroactive to January 1, 2015.

(7) As a result of the settlement agreement submitted to the CPUC in connection with the Utility’s pending joint proposal to retire the Diablo Canyon Power Plant, the Utility recorded a total disallowance of $47 million (before the tax impact of $15 million) during the three and six months ended June 30, 2017, comprised of cancelled projects of $24 million (before the tax impact of $6 million) and disallowed license renewal costs of $23 million (before the tax impact of $9 million), with no corresponding charges during the same periods in 2016. A portion of the cancelled projects and disallowed license renewal costs currently is not tax deductible.

(8) “Earnings from operations” is a non-GAAP financial measure.

Reconciliation of Key Drivers of PG&E Corporation’s EPS from Operations (Non-GAAP):

	Three Months Ended June 30,				Six Months Ended June 30,
				Earnings per				Earnings per
				Common Share				Common Share
(in millions, except per share amounts)		Earnings		(Diluted)		Earnings		(Diluted)
2016 Earnings from Operations (1)	$	330	$	0.66	$	737	$	1.48
Timing of 2015 GT&S revenue impact (2)		75		0.15		150		0.29
Growth in rate base earnings (3)		34		0.07		51		0.10
Miscellaneous		22		0.04		51		0.10
Tax benefit on stock compensation (4)		-		-		31		0.06
Impact of 2017 GRC decision (5)		(21)		(0.04)		(36)		(0.07)
Increase in shares outstanding		-		(0.02)		-		(0.04)
2017 Earnings from Operations (1)	$	440	$	0.86	$	984	$	1.92

(1) See first table above for a reconciliation of EPS on a GAAP basis to EPS from Operations. All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 40.75 percent, except for tax benefits on stock compensation. See Footnote 4 below.

(2) Represents the impact in 2016 of the delay in the Utility’s 2015 GT&S rate case. The CPUC issued its final phase two decision on December 1, 2016, delaying recognition of the full 2016 revenue increase until the fourth quarter of 2016.

(3) Represents the impact of the increase in rate base as authorized in various rate cases, including the 2017 GRC, during the three and six months ended June 30, 2017 as compared to the same periods in 2016. As the final decision in the 2017 GRC was approved by the CPUC in May 2017, this amount includes revenues authorized for the three months ended March 31, 2017 that were not recorded until the second quarter of 2017.

(4) Represents the incremental tax benefit related to share-based compensation awards that vested during the six months ended June 30, 2017. Pursuant to ASU 2016-09, Compensation – Stock Compensation (Topic 718), which PG&E Corporation and the Utility adopted in 2016, excess tax benefits associated with vested awards are reflected in net income.

(5) Represents the impact of lower tax repair benefits as a result of the CPUC’s final decision in the 2017 GRC proceeding, partially offset by the delayed revenue recognition of 2017 GRC-related capital costs (depreciation and interest) until the second quarter of 2017 when the CPUC issued its final decision in the 2017 GRC.

Key Factors Affecting Financial Results

PG&E Corporation and the Utility believe that their future results of operations, financial condition, and cash flows will be materially affected by the following factors:

The Outcome of Enforcement, Litigation, and Regulatory Matters. The Utility’s future financial results may continue to be impacted by the outcome of current and future enforcement, litigation, and regulatory matters, including the impact of the Butte fire, the safety culture OII and any related fines, penalties, or other ratemaking tools that could be imposed by the CPUC, including as a result of the phase two of the proceeding, the ex parte OII and the related settlement agreement that is subject to the CPUC approval, the potential recommendations that the third-party monitor may make related to the Utility’s conviction in the federal criminal trial, and potential penalties in connection with the Utility’s safety and other self-reports. (See Item 1A. Risk Factors in the 2016 Form 10-K.)

The Timing and Outcome of Ratemaking Proceedings. The Utility’s results may be impacted by the timing and outcome of its FERC TO18 and TO19 rate cases. (See “Transmission Owner Rate Cases” in “Regulatory Matters” below for more information.) Additionally, the Utility plans to file its 2019 GT&S rate case in the fourth quarter of 2017. The outcome of regulatory proceedings can be affected by many factors, including arguments made by intervening parties, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors.

The Ability of the Utility to Control and Recover Operating Costs and Capital Expenditures. The Utility is committed to delivering safe, reliable, sustainable, and affordable electric and gas services to its customers. Increasing demands from state laws and policies relating to increased renewable energy resources, the reduction of GHG emissions, the expansion of energy efficiency programs, the development and widespread deployment of distributed generation and self-generation resources, and the development of energy storage technologies have increased pressure on the Utility to achieve efficiencies in its operations in order to maintain the affordability of its service. In any given year the Utility’s ability to earn its authorized rate of return depends on its ability to manage costs within the amounts authorized in rate case decisions. The Utility forecasts that in 2017 it will incur unrecovered pipeline-related expenses ranging from $80 million to $125 million which primarily relate to costs to identify and remove encroachments from transmission pipeline rights-of-way. Also, the CPUC decision in the Utility’s 2015 GT&S rate case establishes various cost caps that will increase the risk of overspend over the rate case cycle through 2018. (See “Disallowance of Plant Costs” in Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

The Amount and Timing of the Utility’s Financing Needs. PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. For the six months ended June 30, 2017, PG&E Corporation issued $257 million of common stock and used $190 million of the cash proceeds to make equity contributions to the Utility. PG&E Corporation forecasts that it will continue issuing a material amount of equity in future years, including $400 million to $500 million in 2017, primarily to support the Utility’s capital expenditures. PG&E Corporation may issue additional equity to fund unrecoverable pipeline-related expenses and to pay fines and penalties that may be required by the final outcomes of pending enforcement matters. These additional issuances could have a material dilutive impact on PG&E Corporation’s EPS. PG&E Corporation’s and the Utility’s ability to access the capital markets and the terms and rates of future financings could be affected by the outcome of the matters discussed in Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1, changes in their respective credit ratings, general economic and market conditions, and other factors.

Changes in the Utility Industry. The utility industry is undergoing transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy. California’s environmental policy objectives are accelerating the pace and scope of the industry change. The electric grid is a critical enabler of the adoption of new energy technologies that support California's climate change and GHG reduction objectives, which continue to be publicly supported by California policy makers notwithstanding a recent change in the federal approach to such matters. In order to enable the California clean energy economy, sustained investments are required in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, electric vehicle infrastructure and State infrastructure modernization (e.g. rail and water projects). The Utility forecasts over $1 billion in grid investments through 2020, that would include increased remote control and sensor technology of the grid, integration investments in connection with DER bi-directional energy flows and voltage fluctuations, advanced grid data analytics, grid storage that enables renewable integration, expanded infrastructure for light, medium, and heavy-duty EVs, transmission integration for renewables, and energy efficiency and demand response programs. In addition, these changes brought about by technological advancements and climate policy may cause a reduction in natural gas usage and increase natural gas costs. The combination of reduced natural gas load and increased costs could result in higher natural gas customer bills and potential cost recovery risk.

For more information about the factors and risks that could affect future results of operations, financial condition, and cash flows, or that could cause future results to differ from historical results, see “Item 1A. Risk Factors” in the 2016 Form 10-K and in Part II below under “Item 1A. Risk Factors.” In addition, this quarterly report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. See the section entitled “Forward-Looking Statements” below for a list of some of the factors that may cause actual results to differ materially. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.