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

LEGISLATIVE AND REGULATORY 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.

2015 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, 2015
2016 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, 2016
2016 Q2 Form 10-Q	PG&E Corporation and Pacific Gas and Electric Company's combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2016
AFUDC	allowance for funds used during construction
ALJ	Administrative Law Judge
ARO(s)	asset retirement obligation(s)
ASU	Accounting Standards Update issued by the FASB (see below)
Cal Fire	California Department of Forestry and Fire Protection
CAISO	California Independent System Operator Corporation
Central Coast Water Board	Central Coast Regional Water Quality Control Board
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DER	distributed energy resources
Diablo Canyon	Diablo Canyon nuclear power plant
DOI	U.S. Department of the Interior
DTSC	California Department of Toxic Substances Control
EMANI	European Mutual Association for Nuclear Insurance
Energy Division	CPUC’s Energy Division
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)
MOD POD	modified presiding officer's decision
NAV	net asset value
NDCTP	Nuclear Decommissioning Cost Triennial Proceedings
NEIL	Nuclear Electric Insurance Limited
NEM	Net Energy Metering
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
OII	order instituting investigation
ORA	Office of Ratepayer Advocates
POD	presiding officer's decision
PSEP	pipeline safety enhancement plan
PV	photovoltaic
Regional Board	California Regional Water Control Board, Lahontan Region
RPS	Renewable Portfolio Standards
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or the CPSD
TO	transmission owner

TURN	The Utility Reform Network
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions, except per share amounts)	2016		2015		2016		2015
Operating Revenues
Electric	$	3,994	$	3,868	$	10,590	$	10,344
Natural gas		816		682		2,363		2,322
Total operating revenues		4,810		4,550		12,953		12,666
Operating Expenses
Cost of electricity		1,613		1,681		3,719		3,958
Cost of natural gas		80		50		377		442
Operating and maintenance		1,783		1,621		5,631		5,028
Depreciation, amortization, and decommissioning		694		653		2,090		1,935
Total operating expenses		4,170		4,005		11,817		11,363
Operating Income		640		545		1,136		1,303
Interest income		8		2		17		6
Interest expense		(211)		(194)		(621)		(575)
Other income, net		24		24		74		100
Income Before Income Taxes		461		377		606		834
Income tax provision (benefit)		70		67		(105)		84
Net Income		391		310		711		750
Preferred stock dividend requirement of subsidiary		3		3		10		10
Income Available for Common Shareholders	$	388	$	307	$	701	$	740
Weighted Average Common Shares Outstanding, Basic		501		486		497		481
Weighted Average Common Shares Outstanding, Diluted		503		489		500		484
Net Earnings Per Common Share, Basic	$	0.77	$	0.63	$	1.41	$	1.54
Net Earnings Per Common Share, Diluted	$	0.77	$	0.63	$	1.40	$	1.53
Dividends Declared Per Common Share	$	0.49	$	0.46	$	1.44	$	1.37

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2016		2015		2016		2015
Net Income	$	391	$	310	$	711	$	750
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $0, $0 and $0, at respective dates)		-		-		-		-
Net change in investments
(net of taxes of $0, $0, $0 and $12, at respective dates)		-		-		-		(17)
Total other comprehensive income (loss)		-		-		-		(17)
Comprehensive Income		391		310		711		733
Preferred stock dividend requirement of subsidiary		3		3		10		10
Comprehensive Income Attributable to
Common Shareholders	$	388	$	307	$	701	$	723

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Balance At
	September 30,		December 31,
(in millions)	2016		2015
ASSETS
Current Assets
Cash and cash equivalents	$	71	$	123
Restricted cash		168		234
Accounts receivable:
Customers (net of allowance for doubtful accounts of $53 and $54
at respective dates)		1,233		1,106
Accrued unbilled revenue		956		855
Regulatory balancing accounts		1,475		1,760
Other		475		286
Regulatory assets		370		517
Inventories:
Gas stored underground and fuel oil		134		126
Materials and supplies		343		313
Income taxes receivable		218		155
Other		306		338
Total current assets		5,749		5,813
Property, Plant, and Equipment
Electric		51,532		48,532
Gas		17,384		16,749
Construction work in progress		2,117		2,059
Other		2		2
Total property, plant, and equipment		71,035		67,342
Accumulated depreciation		(21,605)		(20,619)
Net property, plant, and equipment		49,430		46,723
Other Noncurrent Assets
Regulatory assets		7,534		7,029
Nuclear decommissioning trusts		2,597		2,470
Income taxes receivable		70		135
Other		1,185		1,064
Total other noncurrent assets		11,386		10,698
TOTAL ASSETS	$	66,565	$	63,234

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	September 30,		December 31,
(in millions, except share amounts)	2016		2015
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,145	$	1,019
Long-term debt, classified as current		160		160
Accounts payable:
Trade creditors		1,370		1,414
Regulatory balancing accounts		764		715
Other		496		398
Disputed claims and customer refunds		233		454
Interest payable		144		206
Other		1,958		1,997
Total current liabilities		6,270		6,363
Noncurrent Liabilities
Long-term debt		16,528		15,925
Regulatory liabilities		6,613		6,321
Pension and other postretirement benefits		2,632		2,622
Asset retirement obligations		4,672		3,643
Deferred income taxes		9,850		9,206
Other		2,394		2,326
Total noncurrent liabilities		42,689		40,043
Commitments and Contingencies (Note 9)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares;
505,183,752 and 492,025,443 shares outstanding at respective dates		12,083		11,282
Reinvested earnings		5,278		5,301
Accumulated other comprehensive loss		(7)		(7)
Total shareholders' equity		17,354		16,576
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252
Total equity		17,606		16,828
TOTAL LIABILITIES AND EQUITY	$	66,565	$	63,234

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Nine Months Ended September 30,
(in millions)	2016		2015
Cash Flows from Operating Activities
Net income	$	711	$	750
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		2,090		1,935
Allowance for equity funds used during construction		(84)		(80)
Deferred income taxes and tax credits, net		644		260
Disallowed capital expenditures		517		270
Other		293		247
Effect of changes in operating assets and liabilities:
Accounts receivable		(546)		(322)
Inventories		(38)		5
Accounts payable		189		95
Income taxes receivable/payable		(63)		42
Other current assets and liabilities		254		(87)
Regulatory assets, liabilities, and balancing accounts, net		(634)		78
Other noncurrent assets and liabilities		(85)		(251)
Net cash provided by operating activities		3,248		2,942
Cash Flows from Investing Activities
Capital expenditures		(4,128)		(3,662)
Decrease in restricted cash		66		11
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,019		1,023
Purchases of nuclear decommissioning trust investments		(1,050)		(1,124)
Other		10		18
Net cash used in investing activities		(4,083)		(3,734)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $5
and $2 at respective dates		(128)		545
Short-term debt financing		250		-
Short-term debt matured		-		(300)
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $6 and $14 at respective dates		594		486
Common stock issued		727		689
Common stock dividends paid		(678)		(638)
Other		18		13
Net cash provided by financing activities		783		795
Net change in cash and cash equivalents		(52)		3
Cash and cash equivalents at January 1		123		151
Cash and cash equivalents at September 30	$	71	$	154

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(611)	$	(569)
Income taxes, net		154		-
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	248	$	223
Capital expenditures financed through accounts payable		325		245
Noncash common stock issuances		15		15

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2016		2015		2016		2015
Operating Revenues
Electric	$	3,993	$	3,868	$	10,590	$	10,344
Natural gas		816		682		2,363		2,322
Total operating revenues		4,809		4,550		12,953		12,666
Operating Expenses
Cost of electricity		1,613		1,681		3,719		3,958
Cost of natural gas		80		50		377		442
Operating and maintenance		1,782		1,622		5,630		5,028
Depreciation, amortization, and decommissioning		694		653		2,090		1,935
Total operating expenses		4,169		4,006		11,816		11,363
Operating Income		640		544		1,137		1,303
Interest income		8		2		16		6
Interest expense		(209)		(191)		(614)		(567)
Other income, net		23		22		68		68
Income Before Income Taxes		462		377		607		810
Income tax provision (benefit)		73		72		(99)		95
Net Income		389		305		706		715
Preferred stock dividend requirement		3		3		10		10
Income Available for Common Stock	$	386	$	302	$	696	$	705

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in millions)	2016		2015			2016	2015
Net Income	$	389	$	305	$	706	$	715
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $0, $0 and $0, at respective dates )		-		-		1		-
Total other comprehensive income (loss)		-		-		1		-
Comprehensive Income	$	389	$	305	$	707	$	715

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Balance At
	September 30,		December 31,
(in millions)	2016		2015
ASSETS
Current Assets
Cash and cash equivalents	$	68	$	59
Restricted cash		168		234
Accounts receivable:
Customers (net of allowance for doubtful accounts of $53 and $54
at respective dates)		1,233		1,106
Accrued unbilled revenue		956		855
Regulatory balancing accounts		1,475		1,760
Other		473		284
Regulatory assets		370		517
Inventories:
Gas stored underground and fuel oil		134		126
Materials and supplies		343		313
Income taxes receivable		194		130
Other		306		338
Total current assets		5,720		5,722
Property, Plant, and Equipment
Electric		51,532		48,532
Gas		17,384		16,749
Construction work in progress		2,117		2,059
Total property, plant, and equipment		71,033		67,340
Accumulated depreciation		(21,603)		(20,617)
Net property, plant, and equipment		49,430		46,723
Other Noncurrent Assets
Regulatory assets		7,534		7,029
Nuclear decommissioning trusts		2,597		2,470
Income taxes receivable		70		135
Other		1,066		958
Total other noncurrent assets		11,267		10,592
TOTAL ASSETS	$	66,417	$	63,037

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	September 30,		December 31,
(in millions, except share amounts)	2016		2015
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	981	$	1,019
Long-term debt, classified as current		160		160
Accounts payable:
Trade creditors		1,370		1,414
Regulatory balancing accounts		764		715
Other		765		418
Disputed claims and customer refunds		233		454
Interest payable		144		203
Other		1,681		1,750
Total current liabilities		6,098		6,133
Noncurrent Liabilities
Long-term debt		16,179		15,577
Regulatory liabilities		6,613		6,321
Pension and other postretirement benefits		2,540		2,534
Asset retirement obligations		4,672		3,643
Deferred income taxes		10,135		9,487
Other		2,350		2,282
Total noncurrent liabilities		42,489		39,844
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		7,955		7,215
Reinvested earnings		8,291		8,262
Accumulated other comprehensive income		4		3
Total shareholders' equity		17,830		17,060
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	66,417	$	63,037

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

	(Unaudited)
	Nine Months Ended September 30,
(in millions)	2016		2015
Cash Flows from Operating Activities
Net income	$	706	$	715
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		2,090		1,935
Allowance for equity funds used during construction		(84)		(80)
Deferred income taxes and tax credits, net		648		245
Disallowed capital expenditures		517		270
Other		234		200
Effect of changes in operating assets and liabilities:
Accounts receivable		(546)		(321)
Inventories		(38)		5
Accounts payable		194		148
Income taxes receivable/payable		(64)		14
Other current assets and liabilities		258		(45)
Regulatory assets, liabilities, and balancing accounts, net		(634)		78
Other noncurrent assets and liabilities		(75)		(232)
Net cash provided by operating activities		3,206		2,932
Cash Flows from Investing Activities
Capital expenditures		(4,128)		(3,662)
Decrease in restricted cash		66		11
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,019		1,023
Purchases of nuclear decommissioning trust investments		(1,050)		(1,124)
Other		10		18
Net cash used in investing activities		(4,083)		(3,734)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $5
and $2 at respective dates		(293)		545
Short-term debt financing		250		-
Short-term debt matured		-		(300)
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $6 and $14 at respective dates		594		486
Preferred stock dividends paid		(10)		(10)
Common stock dividends paid		(423)		(537)
Equity contribution from PG&E Corporation		740		605
Other		28		20
Net cash provided by financing activities		886		809
Net change in cash and cash equivalents		9		7
Cash and cash equivalents at January 1		59		55
Cash and cash equivalents at September 30	$	68	$	62

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(602)	$	(561)
Income taxes, net		151		-
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	244	$	-
Capital expenditures financed through accounts payable		325		245

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 operate in one segment, as the companies assess financial performance and allocate resources on a consolidated basis.

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 and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2015 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2015 Form 10-K. This quarterly report should be read in conjunction with the 2015 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, environmental remediation liabilities, asset retirement obligations, 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 2015 Form 10-K.

Variable Interest Entities

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

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2016, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 2016, 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 yearsin conjunction with the Nuclear Decommissioning Cost Triennial Proceedings. In the first quarter of 2016, the Utility submitted its updated decommissioning cost estimate with the CPUC, which reflects an increase of approximately $1.4 billion in the estimated undiscounted cost to decommission the Utility’s nuclear power plants. The change in total estimated cost resulted in an $818 million adjustment to the ARO recognized on the Condensed Consolidated Balance Sheets. The adjustment relates to spent fuel storage, staffing, and out-of-state waste disposal costs. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The Utility requested that the CPUC authorize the collection of increased annual revenue requirements beginning on January 1, 2017 based on these updated cost estimates.

On June 20, 2016, the Utility entered into a joint proposalwith certain parties to retire Diablo Canyon nuclear power plant at the expiration of its current operating licenses in 2024 (Unit 1) and 2025 (Unit 2), subject to certain approvals, resulting in an additional $115 million increase to the ARO recognized on the Condensed Consolidated Balance Sheets in the second quarter of 2016.

The estimated total nuclear decommissioning cost of $4.8 billion 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 $3.5 billion at September 30,2016 and $2.5 billion at December 31, 2015. Changes in these estimates could materially affect the amount of the recorded ARO for these assets.

Pension and Other Postretirement Benefits

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

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2016 and 2015 were as follows:

	Pension Benefits				Other Benefits
	Three Months Ended September 30,
(in millions)	2016		2015		2016		2015
Service cost for benefits earned	$	113	$	123	$	13	$	14
Interest cost		179		168		19		18
Expected return on plan assets		(207)		(219)		(26)		(28)
Amortization of prior service cost		2		4		3		4
Amortization of net actuarial loss		6		1		1		1
Net periodic benefit cost		93		77		10		9
Regulatory account transfer (1)		(8)		8		-		-
Total	$	85	$	85	$	10	$	9

(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
	Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015
Service cost for benefits earned	$	339	$	360	$	39	$	41
Interest cost		537		505		57		54
Expected return on plan assets		(621)		(655)		(80)		(84)
Amortization of prior service cost		6		11		11		14
Amortization of net actuarial loss		18		7		3		3
Net periodic benefit cost		279		228		30		28
Regulatory account transfer (1)		(25)		26		-		-
Total	$	254	$	254	$	30	$	28

(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 September 30, 2016
Beginning balance	$	(23)	$	16	$	(7)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $0 and $2, respectively)		2		1		3
Amortization of net actuarial loss
(net of taxes of $3 and $0, respectively)		3		1		4
Regulatory account transfer
(net of taxes of $3 and $2, respectively)		(5)		(2)		(7)
Net current period other comprehensive gain (loss)		-		-		-
Ending balance	$	(23)	$	16	$	(7)

(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 September 30, 2015
Beginning balance	$	(21)	$	15	$	(6)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $1 and $2, respectively)		3		2		5
Amortization of net actuarial loss
(net of taxes of $0, and $0, respectively)		1		1		2
Regulatory account transfer
(net of taxes of $3 and $3, respectively)		(4)		(3)		(7)
Net current period other comprehensive gain (loss)		-		-		-
Ending balance	$	(21)	$	15	$	(6)

	Pension		Other
	Benefits		Benefits		Total
(in millions, net of income tax)	Nine Months Ended September 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 $5, respectively)		4		6		10
Amortization of net actuarial loss
(net of taxes of $7 and $1, respectively)		11		2		13
Regulatory account transfer
(net of taxes of $9 and $6, respectively)		(15)		(8)		(23)
Net current period other comprehensive gain (loss)		-		-		-
Ending balance	$	(23)	$	16	$	(7)

	Pension		Other		Other
	Benefits		Benefits		Investments		Total
(in millions, net of income tax)	Nine Months Ended September 30, 2015
Beginning balance	$	(21)	$	15	$	17	$	11
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $4, $6, and $0, respectively) (1)		7		8		-		15
Amortization of net actuarial loss
(net of taxes of $3, $1, and $0, respectively) (1)		4		2		-		6
Regulatory account transfer
(net of taxes of $7, $7, and $0, respectively) (1)		(11)		(10)		-		(21)
Change in investments
(net of taxes of $0, $0, and $12, respectively)		-		-		(17)		(17)
Net current period other comprehensive gain (loss)		-		-		(17)		(17)
Ending balance	$	(21)	$	15	$	-	$	(6)

There was no material difference between PG&E Corporation and the Utility for the information disclosed above, with the exception of other investments which are held by PG&E Corporation.

Recently Adopted Accounting Guidance

Fair Value Measurement

In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which standardizes reporting practices related to the fair value hierarchy for all investments for which fair value is measured using the net asset value per share. PG&E Corporation and the Utility adopted this guidance effectiveJanuary 1, 2016 and applied the requirements retrospectively for all periods presented. The adoption of this standard did not impact their Condensed Consolidated Financial Statements. All prior periods presented in these Condensed Consolidated financial statements reflect the retrospective adoption of this guidance. (See Note 8 below.)

Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued ASU No. 2015-05, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement, which adds guidance to help entities evaluate the accounting treatment for cloud computing arrangements. PG&E Corporation and the Utility adopted this guidance effective January 1, 2016. The adoption of this guidance did not have a material impact on their Condensed Consolidated Financial Statements.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which amends the existing guidance relating to the presentation of debt issuance costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. PG&E Corporation and the Utility adopted this guidance effective January 1, 2016 and applied the requirements retrospectively for all periods presented. The adoption of this guidance did not have a material impact on their Condensed Consolidated Financial Statements. PG&E Corporation and the Utility reclassified $105 million and $103 million, respectively, of debt issuance costs as of December 31, 2015 with no impact to net income or total shareholders’ equity previously reported. All prior periods presented in these Condensed Consolidated Financial Statements reflect the retrospective adoption of this guidance.

Accounting Standards Issued But Not Yet Adopted

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 statement of cash flows. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2017. PG&E Corporation and the Utility will early adopt this guidance in the fourth quarter of 2016 and do not expect this ASU to have a material impact on their Condensed Consolidated Financial Statements 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 disclosing key information about leasing arrangements. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019 with retrospective application. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their 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 and measurement of financial instruments. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

Revenue Recognition Standard

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends the existing revenue recognition guidance. In August 2015, the FASB deferred the effective date of this amendment for public companies by one year to January 1, 2018, with early adoption permitted as of the original effective date of January 1, 2017. (See ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.) PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
	September 30,		December 31,
(in millions)	2016		2015
Pension benefits	$	2,416	$	2,414
Deferred income taxes		3,649		3,054
Utility retained generation		376		411
Environmental compliance costs		760		748
Price risk management		96		138
Unamortized loss, net of gain, on reacquired debt		81		94
Other		156		170
Total long-term regulatory assets	$	7,534	$	7,029

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K.

Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
	September 30,		December 31,
(in millions)	2016		2015
Cost of removal obligations	$	4,939	$	4,605
Recoveries in excess of asset retirement obligations		656		631
Public purpose programs		539		600
Other		479		485
Total long-term regulatory liabilities	$	6,613	$	6,321

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K.

Regulatory Balancing Accounts

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

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

	Receivable
	Balance at
	September 30,		December 31,
(in millions)	2016		2015
Electric distribution	$	43	$	380
Utility generation		-		122
Gas distribution		583		493
Energy procurement		174		262
Public purpose programs		122		155
Other		553		348
Total regulatory balancing accounts receivable	$	1,475	$	1,760

	Payable
	Balance at
	September 30,		December 31,
(in millions)	2016		2015
Utility generation	$	47	$	-
Energy procurement		109		112
Public purpose programs		289		244
Other		319		359
Total regulatory balancing accounts payable	$	764	$	715

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

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 September 30, 2016:

					Letters of
	Termination	Facility			Credit		Commercial		Facility
(in millions)	Date	Limit			Outstanding		Paper		Availability
PG&E Corporation	April 2021	$	300	(1)	$	-	$	165	$	135
Utility	April 2021		3,000	(2)		31		731		2,238
Total revolving credit facilities		$	3,300		$	31	$	896	$	2,373

(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 June 2016, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2020 to April 27, 2021.

Other Short-term Borrowings

In March 2016, the Utility entered into a $250 million floating rate unsecured term loan that matures on February 2, 2017. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

Senior Notes Issuances

Variable Rate Interest

AtSeptember 30, 2016, 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 0.89% to 0.92%. At September 30, 2016, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.77% to 0.85%. Pollution control bonds Series 2009 C and D will mature on December 1, 2016.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2016were as follows:

	PG&E Corporation		Utility
	Total		Total
(in millions)	Equity		Shareholders' Equity
Balance at December 31, 2015	$	16,828	$	17,060
Comprehensive income		711		707
Equity contributions		-		740
Common stock issued		742		-
Share-based compensation		59		-
Common stock dividends declared		(724)		(667)
Preferred stock dividend requirement		-		(10)
Preferred stock dividend requirement of subsidiary		(10)		-
Balance at September 30, 2016	$	17,606	$	17,830

During the three and nine months ended September 30, 2016, PG&E Corporation sold 0.4 million and 2.6 million shares of its common stock under the February 2015 equity distribution agreement for cash proceeds of $26 million and $149 million, respectively, net of commissions paid of $0.2 million and $1.3 million, respectively. As of September 30, 2016, the remaining gross sales available under this agreement were $275 million.

In August 2016, PG&E Corporation sold 4.9 million shares of its common stock in an underwritten public offering for net cash proceeds of $309 million.

PG&E Corporation also issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the nine months ended September 30, 2016, 5.7 million shares were issued for cash proceeds of $269 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				Nine Months Ended
	September 30,				September 30,
(in millions, except per share amounts)	2016		2015		2016		2015
Income available for common shareholders	$	388	$	307	$	701	$	740
Weighted average common shares outstanding, basic		501		486		497		481
Add incremental shares from assumed conversions:
Employee share-based compensation		2		3		3		3
Weighted average common shares outstanding, diluted		503		489		500		484
Total earnings per common share, diluted	$	0.77	$	0.63	$	1.40	$	1.53

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 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.

Derivatives are recorded at fair value and are presented in the Utility’sCondensed Consolidated Balance Sheets 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.

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 as long as the current ratemaking mechanism remains in place and 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.

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:

		Contract Volume at
		September 30,	December 31,
Underlying Product	Instruments	2016	2015
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	376,296,893	333,091,813
	Options	118,017,176	111,550,004
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	3,128,038	3,663,512
	Congestion Revenue Rights (3)	172,756,395	216,383,389

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

(2) Million British Thermal Units.

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

Presentation of Derivative Instruments in the Financial Statements

At September 30, 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	$	100	$	(8)	$	14	$	106
Other noncurrent assets – other		128		(8)		-		120
Current liabilities – other		(67)		8		10		(49)
Noncurrent liabilities – other		(104)		8		7		(89)
Net commodity risk	$	57	$	-	$	31	$	88

At December 31, 2015, 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	$	97	$	(4)	$	25	$	118
Other noncurrent assets – other		172		(2)		-		170
Current liabilities – other		(102)		4		44		(54)
Noncurrent liabilities – other		(140)		2		21		(117)
Net commodity risk	$	27	$	-	$	90	$	117

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

	Commodity Risk
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2016		2015		2016		2015
Unrealized gain (loss) - regulatory assets and liabilities (1)	$	(29)	$	(45)	$	30	$	(69)
Realized gain (loss) - cost of electricity (2)		(7)		1		(48)		4
Realized loss - cost of natural gas (2)		(9)		(3)		(15)		(8)
Net commodity risk	$	(45)	$	(47)	$	(33)	$	(73)

(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 September 30, 2016, 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
	September 30,		December 31,
(in millions)	2016		2015
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(8)	$	(2)
Related derivatives in an asset position		4		-
Collateral posting in the normal course of business related to
these derivatives		2		-
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(2)	$	(2)

(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, price risk management instruments, and other investments 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 September 30, 2016
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	-	$	-	$	-	$	-	$	-
Nuclear decommissioning trusts
Short-term investments		1		-		-		-		1
Global equity securities		1,678		-		-		-		1,678
Fixed-income securities		720		530		-		-		1,250
Assets measured at NAV		-		-		-		-		14
Total nuclear decommissioning trusts (2)		2,399		530		-		-		2,943
Price risk management instruments
(Note 7)
Electricity		10		16		192		(2)		216
Gas		-		10		-		-		10
Total price risk management instruments		10		26		192		(2)		226
Rabbi trusts
Fixed-income securities		-		59		-		-		59
Life insurance contracts		-		77		-		-		77
Total rabbi trusts		-		136		-		-		136
Long-term disability trust
Short-term investments		4		-		-		-		4
Assets measured at NAV		-		-		-		-		138
Total long-term disability trust		4		-		-		-		142
Total assets	$	2,413	$	692	$	192	$	(2)	$	3,447
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	25	$	8	$	136	$	(33)	$	136
Gas		-		2		-		-		2
Total liabilities	$	25	$	10	$	136	$	(33)	$	138

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

(2) Represents amount before deducting $346 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	64	$	-	$	-	$	-	$	64
Nuclear decommissioning trusts
Short-term investments		36		-		-		-		36
Global equity securities		1,520		-		-		-		1,520
Fixed-income securities		694		521		-		-		1,215
Assets measured at NAV		-		-		-		-		13
Total nuclear decommissioning trusts (2)		2,250		521		-		-		2,784
Price risk management instruments
(Note 9 in the 2015 Form 10-K)
Electricity		-		9		259		18		286
Gas		-		1		-		1		2
Total price risk management instruments		-		10		259		19		288
Rabbi trusts
Fixed-income securities		-		57		-		-		57
Life insurance contracts		-		70		-		-		70
Total rabbi trusts		-		127		-		-		127
Long-term disability trust
Short-term investments		7		-		-		-		7
Assets measured at NAV		-		-		-		-		158
Total long-term disability trust		7		-		-		-		165
Total assets	$	2,321	$	658	$	259	$	19	$	3,428
Liabilities:
Price risk management instruments
(Note 9 in the 2015 Form 10-K)
Electricity	$	69	$	1	$	170	$	(70)	$	170
Gas		-		2		-		(1)		1
Total liabilities	$	69	$	3	$	170	$	(71)	$	171

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

(2) Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the nine months ended September 30, 2016 and 2015.

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 debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Assets Measured at NAV Using Practical Expedient

On January 1, 2016, PG&E Corporation and the Utility adopted FASB ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)and applied it retrospectively for the periods presented in their Condensed Consolidated Financial Statements. (See Note 2 above.) In accordance with this guidance, 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 the Chief Risk and Audit Officer of the Utility, 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 September 30, 2016				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	192	$	43	Market approach	CRR auction prices	$	(23.81) - 8.76
Power purchase agreements	$	-	$	93	Discounted cash flow	Forward prices	$	18.07 - 38.80

(1) Represents price per megawatt-hour

	Fair Value at
(in millions)	At December 31, 2015				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	259	$	63	Market approach	CRR auction prices	$	(161.36) - 8.76
Power purchase agreements	$	-	$	107	Discounted cash flow	Forward prices	$	15.08 - 37.27

(1) Represents price per megawatt-hour

Level 3 Reconciliation

The following tables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2016 and 2015:

	Price Risk Management Instruments
(in millions)	2016		2015
Asset (liability) balance as of July 1	$	66	$	48
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(10)		(27)
Asset (liability) balance as of September 30	$	56	$	21

(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)	2016		2015
Asset (liability) balance as of January 1	$	89	$	69
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(33)		(48)
Asset (liability) balance as of September 30	$	56	$	21

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 September 30, 2016 and December 31, 2015, as they are short-term in nature or have interest rates that reset daily.

The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at September 30, 2016 and December 31, 2015.

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

	At September 30, 2016				At December 31, 2015
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
PG&E Corporation	$	350	$	356	$	350	$	354
Utility		15,417		18,440		14,918		16,422

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 September 30, 2016
Nuclear decommissioning trusts
Short-term investments	$	1	$	-	$	-	$	1
Global equity securities		579		1,116		(3)		1,692
Fixed-income securities		1,164		89		(3)		1,250
Total (1)	$	1,744	$	1,205	$	(6)	$	2,943
As of December 31, 2015
Nuclear decommissioning trusts
Short-term investments	$	36	$	-	$	-	$	36
Global equity securities		508		1,034		(9)		1,533
Fixed-income securities		1,165		58		(8)		1,215
Total (1)	$	1,709	$	1,092	$	(17)	$	2,784

(1) Represents amounts before deducting $346 million and $314 million at September 30, 2016 and December 31, 2015, 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)	September 30, 2016
Less than 1 year	$	33
1–5 years		443
5–10 years		271
More than 10 years		503
Total maturities of fixed-income securities	$	1,250

The following table provides a summary of activity for the investments:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015			2016	2015
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
trust investments	$	257	$	244	$	1,019	$	1,023
Gross realized gains on securities held as available-for-sale		6		3		15		50
Gross realized losses on securities held as available-for-sale		(14)		(12)		(17)		(25)

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

Enforcement and Litigation Matters

CPUC Matters

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

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

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

On July 12, 2016, the assigned commissioner and ALJ issued a ruling that adopted recommendations included in a process report jointly submitted by the Cities of San Bruno and San Carlos, ORA, the SED, TURN (together, the “other parties”), and the Utility in April 2016. The approved framework for resolving the proceeding included a total of 159 communications (the 46 communications already included in the OII and 113 additional communications) in the scope of the proceeding, a procedure for moving undisputed facts into the evidentiary record and a diligence process for providing additional factual information. The Utility and the other parties disagreed on the inclusion of an additional 21 communications in the scope and filed briefs on the issue. The ruling confirmed that these additional 21 communications were not included within the scope of the OII and do not, in themselves, appear to be ex parte violations, but granted the other parties’ request to seek additional information regarding these communications.

In a status report jointly submitted to the CPUC on October 14, 2016, the parties proposed an update to the framework for resolving the proceeding. The revised framework includes a total of 165 communications (159 communications previously included in the proceeding, reduced by two communications the other parties agreed not to pursue, plus 8 additional communications out of 21 communications previously in disagreement). The parties also proposed to begin settlement discussions on November 30, 2016, followed by a joint status report proposed for January 13, 2017. In the event a settlement cannot be reached, the parties proposed to submit their opening briefs on January 27, 2017, and reply briefs on February 17, 2017. On October 31, 2016, the CPUC issued a proposed decision adopting the schedule proposed by the parties in the October 14, 2016 status report. The proposed decision extends the statutory deadline for this proceeding to May 17, 2017 in order to allow the parties to complete settlement discussions or file briefs, and for the ALJ to prepare and file a proposed decision.

The Utility expects that the other parties may argue that the number of violations exceeds the 165 communications referenced in the October 14, 2016 joint status report either because a single communication may have violated more than one rule or because they believe some of the material provided during discovery constitutes impermissible ex parte communications. The Utility expects to contest many of these assertions. If the matter does not settle, the CPUC will determine which communications included within the scope of the proceeding were in violation of its rules. The CPUC will also determine whether to impose penalties or other remedies, as a result of a potential settlement or otherwise. The CPUC can impose fines up to $50,000 for each violation, and up to $50,000 per day if the CPUC determines that the violation was continuing. The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as how many days each violation continued; 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 CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The CPUC has historically exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the OII but are unable to reasonably estimate the amount or range of future charges that could be incurred, because it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations.

Finally, the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office also have been investigating matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility is cooperating with these investigations. It is uncertain whether any charges will be brought against the Utility.

CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping

On November 20, 2014, the CPUC began an investigation into whether the Utility violated applicable laws pertaining to record-keeping practices with respect to maintaining safe operation of its natural gas distribution service and facilities. The order also required the Utility to show cause why (1) the CPUC should not find that the Utility violated provisions of the California Public Utilities Code, CPUC general orders or decisions, other rules, or requirements, and/or engaged in unreasonable and/or imprudent practices related to these matters, and (2) the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. In particular, the order cited the SED’s investigative reports alleging that the Utility violated rules regarding safety record-keeping in connection with six natural gas distribution incidents, including the natural gas explosion that occurred in Carmel, California on March 3, 2014.

On August 18, 2016, the CPUC unanimously approved a modified presiding officer’s decision (the “MOD POD”) issued on August 17, 2016 in this investigation. In accordance with the MOD POD, the amount of the fine increased from $24.3 million to $25.6 million, to include a $50,000 fine omitted from the June 1, 2016 presiding officer’s decision (the “POD”) and $1.3 million resulting from the per-day fine increase for the missing leak repair records for the De Anza division. With the $10.85 million citation previously paid in 2015 for the City of Carmel-by-the-Sea (“Carmel”) incident, the total fine imposed on the Utility was $36.5 million. The remaining $25.6 million was paid in September 2016.

In accordance with the MOD POD, the decision denies the appeals previously filed by the SED and Carmel from the POD, and closes this proceeding but allows the parties an opportunity to request that this proceeding be reopened if needed to ensure proper implementation of a compliance plan to be developed by the parties.

On September 26, 2016, the SED filed an application for rehearing of the CPUC’s decision. Specifically, the application indicates that the CPUC erred in certain of its determinations (including those related to maximum allowable operating pressure documentation that, if adopted, could result in an additional fine of $7 million), calculations (including thoserelated to the missing DeAnza records violations) and certain other findings, and requests that the CPUC adopt its recommendations. On October 11, 2016, the Utility submitted its response to the CPUC in which it opposed the SED’s application for rehearing arguing that the application failed to identify a legal error warranting rehearing by the CPUC. The Utility cannot predict when or if the CPUC will grant the rehearing or if it will adopt the SED’s recommendations.

On October 24, 2016, the Utility held a meet and confer with parties to develop remedial measures necessary to address the issues identified in the CPUC decision with the objective of establishing a compliance plan that includes all feasible and cost-effective measures necessary to improve the Utility’s natural gas distribution system record-keeping. Under the current schedule, the parties are expected to submit a compliance plan to the CPUC on or before December 16, 2016.

Natural Gas Transmission Pipeline Rights-of-Way

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

Potential Safety Citations

The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. The CPUC has delegated authority to the SED to issue citations and impose fines for violations identified through audits, investigations, or self-reports. The SED can impose fines up to $50,000 for each violation, per day, and can consider the discretionary factors discussed above (see “Order Instituting an Investigation into Compliance with Ex Parte Communication Rules” above) in determining the number of violations and whether to impose daily fines for continuing violations. On September 29, 2016, the CPUC issued a final decision adopting improvements and refinements to its gas and electric safety citation programs. Specifically, the final decision refines the criteria for the SED to use in determining whether to issue a citation and the amount of penalty, sets an administrative limit of $8 million per citation issued, makes self-reporting voluntary in both gas and electric programs, adopts detailed criteria for the utilities to use to voluntarily self-report a potential violation, and refines other issues in the programs. The decision also merges the rules applicable to its gas and electric safety citation programs into a single set of rules that replace the previous safety citation programs and adopts non-substantive changes to these programs so that the programs can be similar in structure and process where appropriate. The decision closes the proceeding.

The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The Utility believes it is probable that the SED will impose fines or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits. 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 has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

In September 2016, the Utility reported that it discovered in November 2015 that approximately 550,000 atmospheric corrosion inspections on above-ground gas distribution meters completed in 2014, which constituted 35% of such inspections in 2014, were performed by non-operator qualified personnel. The Utility did not provide timely notification of such non-compliance to the CPUC. The SED is investigating the Utility’s self-report.

The SED could impose fines on the Utility of up to $50,000 per inspection, and also for failure to timely file a self-report in connection with such inspections. The SED has the authority to issue more than one citation for a series of related incidents, and the CPUC can issue an OII and possible additional fines even after the SED has issued a citation. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines that could be imposed with respect to this self-report, for the reasons indicated above, or to predict whether the CPUC will open a formal proceeding as a result of the SED’s investigation.

Federal Matters

Federal Criminal Trial

On June 14, 2016, a federal criminal trial against the Utilitybegan in the United States District Court for the Northern District of California, in San Francisco, on 12 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats, and one felony count charging that the Utility illegally obstructed the NTSB investigation into the cause of the San Bruno accident. On July 26, 2016, the court granted the government’s motion to dismiss Count 13 alleging that the Utility knowingly and willfully failed to retain a strength test pressure record with respect to a distribution feeder main, thereby reducing the total number of counts from 13 to 12.

On August 2, 2016, the remaining Alternative Fines Act sentencing allegations in the case were dismissed. The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.” (The remaining allegations related to $281 million of gross gains that the government alleged the Utility derived. As previously disclosed, in December 2015, the court dismissed the government’s allegations regarding the amount of losses.)

On August 9, 2016, the jury returned its verdict. The jury acquitted the Utility on all six of the record-keeping allegations but found the Utility guilty on six felony counts that include one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act.

On August 16, 2016, the Utility filed a motion under Federal Rule of Criminal Procedure 29 for a judgment of acquittal, arguing that the evidence was insufficient to sustain a conviction for the six counts on which the jury returned a guilty verdict. The court indicated that it will decide on this motion based on briefs filed by the parties, without oral argument. The Utility is not able to predict when the court will decide on the motion. A sentencing hearing is currently scheduled for January 23, 2017.

The maximum statutory fine for each felony count is $500,000, for total potential maximum statutory fines of $3 million. At September 30, 2016, the Utility’s Condensed Consolidated Balance Sheets include a $3 million accrual in connection with the jury verdict. The Utility also could incur material costs, not recoverable through rates, to implement remedial and other measures that could be imposed, such as a requirement that the Utility’s natural gas operations and/or compliance and ethics programs be supervised by an independent third-party monitor. If appointed, the Utility expects a monitor would serve for a period of time and report periodically to the court or a department or agency of the government.

Other Federal Matters

In July 2014, the Utility was informed that the U.S. Attorney’s Office is investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the criminal trial discussed above. 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. It is uncertain whether any charges will be brought against the Utility as a result of these investigations.

Other Litigation Matters

Butte Fire Litigation

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, and destroyed 549 homes, 368 outbuildings and four commercial properties. 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 its vegetation management contractors to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. In a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility.

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its vegetation management contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of September 30, 2016, approximately 50 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,850 individual plaintiffs representing approximately 800 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. The number of individual complaints and plaintiffs may increase in the future.

The Utility continues mediating and settling preference cases (presented by individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling). The Utility also has begun scheduling mediation of other cases. Case management conferences were held on July 14, 2016 and September 1, 2016. The next case management conference is scheduled for December 1, 2016.

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. 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. The Utility believes it was not negligent; however, there can be no assurance that a court or jury would agree with the Utility.

Based on the evidence described in the Cal Fire report that the Gray Pine tree contacted an electric line of the Utility, the Utility believes that it is probable that it will incur a loss of $350 million for property damages (including estimated damages to structures and their contents, and to trees) in connection with this matter, which corresponds to the lower end of the range of its reasonably estimable losses. This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the extent of damage to such structures and contents, and other property damage. The estimate does not include fire suppression costs, personal injury damages and other damages that the Utility could be liable for if it were found to have been negligent.

The Utility believes that it is reasonably possible that it will incur losses related to Butte fire claims in excess of the $350 million accrued through September 30, 2016. The Utility believes that $90 million is a reasonable estimate of fire suppression costs (this amount is not included in the $350 million accrued through September 30, 2016). The Utility currently is unable to reasonably estimate the upper end of the range because it is still at 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, including for estimated property damages, requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including discovery from the plaintiffs and results from the ongoing mediation and settlement process, management estimates and assumptions regarding the financial impact of the Butte fire may change, including management’s ability to reasonably estimate a range of loss.

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire. 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. In the second quarter of 2016, the Utility recorded $260 million for probable insurance recoveries in connection with recovery of losses related to the Butte fire, included in Other accounts receivable in the Condensed Consolidated Balance Sheets. The Utility plans to seek recovery of all insured losses, and while the Utility believes that a significant portion of costs incurred for third-party claims (and associated legal expenses) relating to Butte fire will ultimately be recovered through its insurance, it is unable to predict the amount and timing of such insurance recoveries.

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 during such reporting periods.

Other Contingencies

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 $84 million at September 30, 2016 and $63 million at December 31, 2015. 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

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates 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. Disallowances as a result of the CPUC’s June 23, 2016 final phase one decision in the Utility’s 2015 GT&S rate case, the April 9, 2015 Penalty Decision and the Utility’s Pipeline Safety Enhancement Plan are discussed below.

2015 GT&S Rate Case Disallowance of Capital Expenditures

On June 23, 2016, the CPUC approved a final decision in phase one of the Utility’s 2015 GT&S rate case. The decision permanently disallowed a portion of the 2011 through 2014 capital spending in excess of the amount adopted and established various cost caps that will increase the risk of overspend over the current rate case cycle, including new one-way capital balancing accounts. As a result, in the second quarter of 2016, the Utility incurred charges of $190 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This included $134 million to the net plant balance for 2011 through 2014 capital expenditures in excess of adopted amounts and $56 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. Additional charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the third party audit of 2011 through 2014 capital spending.

Penalty Decision’s Disallowance of Natural Gas Capital Expenditures

On April 9, 2015, the CPUC issued a decision in its investigative enforcement proceedings pending against the Utility to impose total penalties of $1.6 billion on the Utility after determining that the Utility had committed numerous violations of laws and regulations related to its natural gas transmission operations (the “Penalty Decision”). In January 2016, the CPUC closed the investigative proceedings. The total penalty includes (1) a $300 million fine, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.

On November 1, 2016, the assigned ALJ issued a phase two proposed decision in the Utility’s 2015 GT&S rate case, which applies $689 million of the $850 million penalty to capital expenditures. The decision also approves the Utility’s list of programs and projects that meet the CPUC’s definition of “safety related,” the costs of which are to be funded through the $850 million penalty. The Utility expects a final CPUC decision to be voted in December 2016.

For the three and nine months ended September 30, 2016, the Utility recorded charges for disallowed capital spending of $51 million and $286 million, respectively, as a result of the Penalty Decision. The cumulative charges at September 30, 2016, and the additional future charges to reach the $1.6 billion total are shown in the following table:


	Nine Months		Cumulative		Future
	Ended		Charges		Charges
		September 30,		September 30,	and		Total
(in millions)	2016		2016		Costs		Amount
Fine paid to the state	$	-	$	300	$	-	$	300
Customer bill credit paid		-		400		-		400
Charge for disallowed capital (1)		286		692		-		692
Disallowed revenue for pipeline safety
expenses (2)		8		8		150		158
CPUC estimated cost of other remedies (3)		-		-		-		50
Total Penalty Decision fines and remedies	$	294	$	1,400	$	150	$	1,600

(1)The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs that the CPUC will finalize in a final phase two decision to be issued in the Utility’s 2015 GT&S rate case. The CPUC recommended in its May 5, 2016 phase one proposed decision in the Utility’s 2015 GT&S rate case that at least $692 million of the $850 million cost disallowance be allocated to capital expenditures. On November 1, 2016, the CPUC issued a phase two proposed decision in the 2015 GT&S rate case which allocates $689 million to capital expenditures.

(2) Future GT&S revenues will be reduced for these unrecovered expenses.

(3)In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs would be expensed as incurred.

Capital Expenditures Relating to Pipeline Safety Enhancement Plan

The CPUC has authorized the Utility to collect $766 million for recovery of PSEP capital costs. As of September 30, 2016, the Utility has spent $1.3 billion on PSEP-related capital costs, of which $665 million was expensed in previous years for costs that are expected to exceed the authorized amount. The Utility expects the remaining PSEP work to continue beyond 2016. The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected.

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
	September 30,		December 31,
(in millions)	2016		2015
Topock natural gas compressor station (1)	$	300	$	300
Hinkley natural gas compressor station (1)		140		140
Former manufactured gas plant sites owned by the Utility or third parties		305		271
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		143		164
Fossil fuel-fired generation facilities and sites		104		94
Total environmental remediation liability	$	992	$	969

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

The Utility’s environmental remediation liability at September 30, 2016 reflects its best estimate of probable future costs associated with its final remediation plan. 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 future financial condition and cash flows.

At September 30, 2016, the Utility expected to recover $704 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 Hinkley, California and is referred to below as the “Hinkley site.” Another station is located near Needles, California and is referred to below as the “Topock site.” The Utility also is required to take measures to abate the effects of the contamination on the environment.

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. On November 4, 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.

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 is conducting an additional environmental review of the proposed design, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in early 2017. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in mid-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 late 2017 or early 2018.

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 to as much as $2.0 billion (including amounts related to the Hinkley and Topock 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

In addition to the nuclear insurance the Utility maintains through the NEIL, the Utility also is a member of the EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non- nuclear event were to occur at Diablo Canyon.

If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the current maximum aggregate annual retrospective premium obligation for the Utility is approximately $60 million. EMANI provides $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $2.1 million. For more information about the Utility’s NEIL coverage, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 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. 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. 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.

On September 2, 2016, the Utility’s settlement became effective resolving, among other matters, the Utility’s claim against the CAISO for $165 million, which includes receivables and interest. Additionally, the Utility agreed to release $66 million of cash from escrow to the California Power Exchange. The settlement resulted in a $231 million reduction to the Disputed claims and customer refunds balance onthe Condensed Consolidated Balance Sheets. The settlement agreement did not result in a refund to customers or an impact to net income.

At September 30, 2016 and December 31, 2015, respectively, the Consolidated Balance Sheets reflected $233 million and $454 million in net claims within Disputed claims and customer refunds as well as $161 million and $228 million of cash in escrow within Restricted cash. On October 13, 2016, the Utility received approval from the bankruptcy court to release the remaining cash held in escrow to unrestricted cash for use by the Utility.

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 several matters, including audits. As of September 30, 2016, 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.

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, 2015, the Utility hadundiscounted future expected obligations of approximately $50 billion. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K.) During the nine months ended September 30, 2016, the Utility entered into several renewable energy power purchase agreements that were approved by the CPUC and completed major milestones with respect to construction, resulting in additional commitments of approximately $406 million over the next 20 years.

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

OVERVIEW

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 alsosubject 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 should also be read in conjunction with the 2015 Form 10-K.

Summary of Changes in Net Income and Earnings per Share

The following table is a summary reconciliation of the key changes, after-tax, in PG&E Corporation’s income available for common shareholders and EPS (as well as earnings from operations and EPS on an earnings from operations basis) compared to the same period in the prior year (see “Results of Operations” below). “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, including certain pipeline related expenses, certain legal and regulatory related expenses, fines and penalties, Butte fire related costs, and impacts of the 2015 GT&S rate case. 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 planning, 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				Nine Months Ended
	September 30,				September 30,
			EPS				EPS
(in millions, except per share amounts)	Earnings (1)		(Diluted)		Earnings (1)		(Diluted)
Income Available for Common Shareholders - September 30, 2015	$	307	$	0.63	$	740	$	1.53
Fines and penalties		84		0.16		497		1.03
Pipeline-related expenses		19		0.04		38		0.08
Legal and regulatory related expenses		8		0.02		26		0.05
Natural gas matters insurance recoveries		(6)		(0.01)		(29)		(0.06)
Earnings from Operations - September 30, 2015 (2)	$	412	$	0.84	$	1,272	$	2.63
Timing of 2015 GT&S revenue collection (3)		58		0.11		58		0.11
Growth in rate base earnings		25		0.05		76		0.15
Timing of taxes (4)		(22)		(0.04)		(103)		(0.20)
Nuclear refueling outage		-		-		(30)		(0.06)
Regulatory and legal matters		23		0.05		-		-
Gain on disposition of SolarCity stock (5)		-		-		(14)		(0.03)
Increase in shares outstanding		-		(0.03)		-		(0.08)
Miscellaneous		(25)		(0.04)		(50)		(0.10)
Earnings from Operations - September 30, 2016 (2)	$	471	$	0.94	$	1,209	$	2.42
Butte fire related costs (net of insurance) (6)		(9)		(0.02)		(110)		(0.22)
Fines and penalties (7)		(42)		(0.08)		(206)		(0.41)
Pipeline-related expenses (8)		(18)		(0.04)		(47)		(0.10)
Legal and regulatory related expenses (9)		(14)		(0.03)		(32)		(0.06)
GT&S capital disallowance (10)		-		-		(113)		(0.23)
Income Available for Common Shareholders - September 30, 2016	$	388	$	0.77	$	701	$	1.40

(1) All amounts presented in the table above are tax-adjusted at PG&E Corporation’s tax rate of 40.75% except for fines, which are not tax deductible. See footnote (7) below.

(2) “Earnings from operations” is not calculated in accordance with GAAP and excludes the items impacting comparability shown in footnotes (6) through (10).

(3) Represents the incremental authorized revenue collected through rates beginning August 1, 2016 in accordance with the final phase one decision in the Utility’s 2015 GT&S rate case during the three and nine months ended September 30, 2016.

(4) Represents the timing of taxes reportable in quarterly financial statements.

(5) Represents the gain recognized during the nine months ended September 30, 2015. No comparable gain was recognized in 2016.

(6)The Utility accrued charges of $350 million (before the tax impact of $143 million) for the nine months ended September 30, 2016, related to estimated property damages in connection with the Butte fire, partially offset by $260 million (before the tax impact of $106 million) recorded as probable insurance recoveries recognized during the nine months ended September 30, 2016. No additional charges or recoveries were recognized in the three months ended September 30, 2016 related to third-party claims. The Utility also incurred charges of $16 million (before the tax impact of $7 million) and $96 million (before the tax impact of $39 million) for the three and nine months ended September 30, 2016, respectively, for Utility clean-up, repair, and legal costs associated with the Butte fire.

(7) Represents the impact of the Penalty Decision and other enforcement and litigation matters (see Note 9 of the Notes to the Condensed Consolidated Financial Statements). For the three and nine months ended September 30, 2016, the Utility incurred costs of $59 million (before the tax impact of $23 million) and $294 million (before the tax impact of $119 million), respectively, associated with estimated safety-related cost disallowances imposed by the CPUC in its April 9, 2015 decision in the gas transmission pipeline investigations. Specific projects to be disallowed will be determined in the phase two decision of the 2015 GT&S rate case. In addition, for the three and nine months ended September 30, 2016, the Utility accrued fines, which are not deductible for tax purposes, of $1 million and $26 million, respectively, in connection with the MOD POD in the CPUC’s investigation regarding natural gas distribution facilities record-keeping practices and of $3 million for the three and nine months ended September 30, 2016 as a result of the federal criminal trial. In the three and nine months ended September 30, 2016, the Utility also recorded $4 million (before the tax impact of $2 million), for probable disallowance that will be imposed for prohibited ex parte communications.

(8)The Utility incurred costs of $31 million (before the tax impact of $13 million) and $80 million (before the tax impact of $33 million) during the three and nine months ended September 30, 2016, respectively, for pipeline related expenses incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline rights of way.

(9) The Utility incurred costs of $23 million (before the tax impact of $9 million) and $54 million (before the tax impact of $22 million) during the three and nine months ended September 30, 2016, respectively, for legal and regulatory related expenses incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

(10)Represents charges of $190 million (before the tax impact of $77 million) of probablecapitaldisallowancesas a result of the finalphase one 2015 GT&S rate case decision that the Utility incurred in the nine months ended September 30, 2016, including $134 million (before the tax impact of $54 million) for 2011 through 2014 capital expenditures in excess of adopted amounts and $56 million (before the tax impact of $23 million) for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. No additional charges or recoveries were recognized in the three months ended September 30, 2016. (See “Regulatory Matters” below for more information.)

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 current and future enforcement, litigation and regulatory matters and their outcome, including potential remedial and other measures or designation of one or more independent third-party monitor(s)as a result of the federal criminal trial and debarment proceeding, potential fines associated with the alleged violations of the CPUC’s ex parte communication rules, litigation claims related to the Butte fire, and a number of investigations and/or requests for information by government agencies, including in connection with the Utility’s self-report related to its atmospheric corrosion inspections. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

The Timing and Outcome of Ratemaking Proceedings. There are several rate cases that are currently pending at the CPUC and the FERC.The CPUC approved 2015 GT&S “interim” revenue requirements in its final phase one decision dated June 23, 2016. The authorized revenue requirements are effective retroactive to January 1, 2015. However, the Utility will not be able to record the full revenue requirement increase since January 1, 2015 until after the final phase two decision is issued. On November 1, 2016, the assigned ALJ issued a phase two proposed decision in the 2015 GT&S rate case that applies $689 million of the $850 million San Bruno Penalty disallowance to capital expenditures. (See “Regulatory Matters – 2015 Gas Transmission and Storage Rate Case” below for more information.) Additionally, on August 3, 2016, the Utility and other intervening parties filed a motion with the CPUC seeking approval of a settlement agreement in the Utility’s 2017 GRC. The settlement agreement proposes a revenue requirement increase of $88 million for 2017. Under the current schedule, a final CPUC decision is expected in February 2017. (See “Regulatory Matters − 2017 General Rate Case” below for more information.) In addition, on July 29, 2016, the Utility filed a rate case at the FERC requesting a 2017 retail electric transmission revenue requirement. The FERC accepted the Utility’s filing on September 30, 2016 and set the proceeding for settlement negotiations. (See “Regulatory Matters−FERC Transmission Owner Rate Cases” below for more information.) The outcome of regulatory proceedings can be affected by many factors, including the level of opposition 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 2016 it will incur unrecovered pipeline-related expenses ranging from $100 million to $150 million which primarily relate to costs to identify and remove encroachments from transmission pipeline rights-of-way. Also, the June 23, 2016 final phase one 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. The ultimate amount of unrecovered costs also could be affected by how the CPUC determines in its final phase two decision of the 2015 GT&S rate case which costs are included in determining whether the $850 million shareholder-funded obligation under the Penalty Decision has been met. (See 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 nine months ended September 30, 2016, PG&E Corporation issued $742 million of common stock and used $740 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 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 would 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, Financial Statements and Supplementary Data, changes in their respective credit ratings, general economic and market conditions, and other factors.

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 2015 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 which 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.