PG&amp;E Corp - Quarter Report: 2016 June (Form 10-Q)

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
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
EPS	earnings per common share
EV	electric vehicle
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	U.S. Generally Accepted Accounting Principles
GHG	greenhouse gas
GRC	general rate case
GT&S	gas transmission and storage
GWH	gigawatt-hours
IOU(s)	investor-owned utility(ies)
IRS	Internal Revenue Service
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				Six Months Ended
	June 30,				June 30,
(in millions, except per share amounts)	2016		2015		2016		2015
Operating Revenues
Electric	$	3,465	$	3,463	$	6,596	$	6,476
Natural gas		704		754		1,547		1,640
Total operating revenues		4,169		4,217		8,143		8,116
Operating Expenses
Cost of electricity		1,156		1,277		2,106		2,277
Cost of natural gas		75		118		297		392
Operating and maintenance		1,838		1,484		3,848		3,407
Depreciation, amortization, and decommissioning		699		651		1,396		1,282
Total operating expenses		3,768		3,530		7,647		7,358
Operating Income		401		687		496		758
Interest income		5		3		9		4
Interest expense		(207)		(192)		(410)		(381)
Other income, net		23		18		50		76
Income Before Income Taxes		222		516		145		457
Income tax provision (benefit)		12		110		(175)		17
Net Income		210		406		320		440
Preferred stock dividend requirement of subsidiary		4		4		7		7
Income Available for Common Shareholders	$	206	$	402	$	313	$	433
Weighted Average Common Shares Outstanding, Basic		497		480		495		479
Weighted Average Common Shares Outstanding, Diluted		498		483		497		483
Net Earnings Per Common Share, Basic	$	0.41	$	0.84	$	0.63	$	0.90
Net Earnings Per Common Share, Diluted	$	0.41	$	0.83	$	0.63	$	0.90
Dividends Declared Per Common Share	$	0.49	$	0.46	$	0.95	$	0.91

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions)	2016		2015		2016		2015
Net Income	$	210	$	406	$	320	$	440
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		210		406		320		423
Preferred stock dividend requirement of subsidiary		4		4		7		7
Comprehensive Income Attributable to
Common Shareholders	$	206	$	402	$	313	$	416

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions)	2016		2015
ASSETS
Current Assets
Cash and cash equivalents	$	189	$	123
Restricted cash		235		234
Accounts receivable:
Customers (net of allowance for doubtful accounts of $53 and $54
at respective dates)		1,039		1,106
Accrued unbilled revenue		957		855
Regulatory balancing accounts		1,697		1,760
Other		567		286
Regulatory assets		464		517
Inventories:
Gas stored underground and fuel oil		123		126
Materials and supplies		346		313
Income taxes receivable		234		155
Other		284		338
Total current assets		6,135		5,813
Property, Plant, and Equipment
Electric		50,872		48,532
Gas		17,123		16,749
Construction work in progress		2,096		2,059
Other		2		2
Total property, plant, and equipment		70,093		67,342
Accumulated depreciation		(21,496)		(20,619)
Net property, plant, and equipment		48,597		46,723
Other Noncurrent Assets
Regulatory assets		7,315		7,029
Nuclear decommissioning trusts		2,546		2,470
Income taxes receivable		147		135
Other		1,187		1,064
Total other noncurrent assets		11,195		10,698
TOTAL ASSETS	$	65,927	$	63,234

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions, except share amounts)	2016		2015
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,529	$	1,019
Long-term debt, classified as current		160		160
Accounts payable:
Trade creditors		1,313		1,414
Regulatory balancing accounts		654		715
Other		527		398
Disputed claims and customer refunds		461		454
Interest payable		214		206
Other		1,793		1,997
Total current liabilities		6,651		6,363
Noncurrent Liabilities
Long-term debt		16,525		15,925
Regulatory liabilities		6,547		6,321
Pension and other postretirement benefits		2,631		2,622
Asset retirement obligations		4,612		3,643
Deferred income taxes		9,556		9,206
Other		2,407		2,326
Total noncurrent liabilities		42,278		40,043
Commitments and Contingencies (Note 9)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares;
498,143,219 and 492,025,443 shares outstanding at respective dates		11,616		11,282
Reinvested earnings		5,137		5,301
Accumulated other comprehensive loss		(7)		(7)
Total shareholders' equity		16,746		16,576
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252
Total equity		16,998		16,828
TOTAL LIABILITIES AND EQUITY	$	65,927	$	63,234

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Six Months Ended June 30,
(in millions)	2016		2015
Cash Flows from Operating Activities
Net income	$	320	$	440
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,396		1,282
Allowance for equity funds used during construction		(54)		(53)
Deferred income taxes and tax credits, net		350		219
Disallowed capital expenditures		425		128
Other		179		149
Effect of changes in operating assets and liabilities:
Accounts receivable		(338)		(241)
Inventories		(30)		20
Accounts payable		179		78
Income taxes receivable/payable		(79)		6
Other current assets and liabilities		308		77
Regulatory assets, liabilities, and balancing accounts, net		(769)		(62)
Other noncurrent assets and liabilities		(106)		(184)
Net cash provided by operating activities		1,781		1,859
Cash Flows from Investing Activities
Capital expenditures		(2,651)		(2,410)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		721		779
Purchases of nuclear decommissioning trust investments		(762)		(879)
Other		6		24
Net cash used in investing activities		(2,686)		(2,486)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $3
and $2 at respective dates		257		681
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		289		252
Common stock dividends paid		(440)		(424)
Other		21		30
Net cash provided by financing activities		971		725
Net change in cash and cash equivalents		66		98
Cash and cash equivalents at January 1		123		151
Cash and cash equivalents at June 30	$	189	$	249

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(357)	$	(334)
Income taxes, net		54		-
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	244	$	219
Capital expenditures financed through accounts payable		309		177
Noncash common stock issuances		10		10

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions)	2016		2015		2016		2015
Operating Revenues
Electric	$	3,465	$	3,462	$	6,597	$	6,476
Natural gas		704		754		1,547		1,640
Total operating revenues		4,169		4,216		8,144		8,116
Operating Expenses
Cost of electricity		1,156		1,277		2,106		2,277
Cost of natural gas		75		118		297		392
Operating and maintenance		1,837		1,483		3,848		3,406
Depreciation, amortization, and decommissioning		700		651		1,396		1,282
Total operating expenses		3,768		3,529		7,647		7,357
Operating Income		401		687		497		759
Interest income		4		3		8		4
Interest expense		(204)		(189)		(405)		(376)
Other income, net		21		20		45		46
Income Before Income Taxes		222		521		145		433
Income tax provision (benefit)		13		115		(172)		23
Net Income		209		406		317		410
Preferred stock dividend requirement		4		4		7		7
Income Available for Common Stock	$	205	$	402	$	310	$	403

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Three Months Ended					Six Months Ended
	June 30,					June 30,
(in millions)	2016		2015			2016	2015
Net Income	$	209	$	406	$	317	$	410
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $0, $0 and $0, at respective dates )		1		-		1		-
Total other comprehensive income (loss)		1		-		1		-
Comprehensive Income	$	210	$	406	$	318	$	410

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions)	2016		2015
ASSETS
Current Assets
Cash and cash equivalents	$	120	$	59
Restricted cash		235		234
Accounts receivable:
Customers (net of allowance for doubtful accounts of $53 and $54
at respective dates)		1,039		1,106
Accrued unbilled revenue		957		855
Regulatory balancing accounts		1,697		1,760
Other		566		284
Regulatory assets		464		517
Inventories:
Gas stored underground and fuel oil		123		126
Materials and supplies		346		313
Income taxes receivable		208		130
Other		283		338
Total current assets		6,038		5,722
Property, Plant, and Equipment
Electric		50,872		48,532
Gas		17,123		16,749
Construction work in progress		2,096		2,059
Total property, plant, and equipment		70,091		67,340
Accumulated depreciation		(21,494)		(20,617)
Net property, plant, and equipment		48,597		46,723
Other Noncurrent Assets
Regulatory assets		7,315		7,029
Nuclear decommissioning trusts		2,546		2,470
Income taxes receivable		147		135
Other		1,072		958
Total other noncurrent assets		11,080		10,592
TOTAL ASSETS	$	65,715	$	63,037

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions, except share amounts)	2016		2015
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	1,529	$	1,019
Long-term debt, classified as current		160		160
Accounts payable:
Trade creditors		1,313		1,414
Regulatory balancing accounts		654		715
Other		558		418
Disputed claims and customer refunds		461		454
Interest payable		211		203
Other		1,522		1,750
Total current liabilities		6,408		6,133
Noncurrent Liabilities
Long-term debt		16,177		15,577
Regulatory liabilities		6,547		6,321
Pension and other postretirement benefits		2,540		2,534
Asset retirement obligations		4,612		3,643
Deferred income taxes		9,839		9,487
Other		2,364		2,282
Total noncurrent liabilities		42,079		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		7,495		7,215
Reinvested earnings		8,149		8,262
Accumulated other comprehensive income		4		3
Total shareholders' equity		17,228		17,060
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	65,715	$	63,037

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

	(Unaudited)
	Six Months Ended June 30,
(in millions)	2016		2015
Cash Flows from Operating Activities
Net income	$	317	$	410
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,396		1,282
Allowance for equity funds used during construction		(54)		(53)
Deferred income taxes and tax credits, net		352		219
Disallowed capital expenditures		425		128
Other		144		119
Effect of changes in operating assets and liabilities:
Accounts receivable		(339)		(242)
Inventories		(30)		20
Accounts payable		190		134
Income taxes receivable/payable		(78)		8
Other current assets and liabilities		310		67
Regulatory assets, liabilities, and balancing accounts, net		(769)		(62)
Other noncurrent assets and liabilities		(95)		(170)
Net cash provided by operating activities		1,769		1,860
Cash Flows from Investing Activities
Capital expenditures		(2,651)		(2,410)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		721		779
Purchases of nuclear decommissioning trust investments		(762)		(879)
Other		6		24
Net cash used in investing activities		(2,686)		(2,486)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $3
and $2 at respective dates		257		676
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		(7)		(7)
Common stock dividends paid		(423)		(358)
Equity contribution from PG&E Corporation		280		185
Other		27		37
Net cash provided by financing activities		978		719
Net change in cash and cash equivalents		61		93
Cash and cash equivalents at January 1		59		55
Cash and cash equivalents at June 30	$	120	$	148

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(352)	$	(330)
Income taxes, net		54		-
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	309	$	177

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 operating in 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. Actual results could differ materially from those estimates.

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 was the primary beneficiary of any of these VIEs at June 30, 2016, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at June 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. On March 1, 2016, the Utility submitted its updated decommissioning cost estimate with the CPUC. As a result, the estimated undiscounted cost to decommission the Utility’s nuclear power plants increased by approximately $1.4 billion at March 30, 2016. The change in total estimated cost resulted in an $818 million adjustment to the ARO recognized on the Condensed Consolidated Balance Sheets. The adjustment was a result of increased estimated costs related to spent fuel storage, staffing, and out-of-state waste disposal. 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 a $115 million increase to the ARO recognized on the Condensed Consolidated Balance Sheets at June 30, 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 $3.4 billion at June 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 six months ended June 30, 2016 and 2015 were as follows:

	Pension Benefits				Other Benefits
	Three Months Ended June 30,
(in millions)	2016		2015		2016		2015
Service cost for benefits earned	$	113	$	118	$	13	$	14
Interest cost		179		169		19		18
Expected return on plan assets		(207)		(218)		(27)		(28)
Amortization of prior service cost		2		3		4		5
Amortization of net actuarial loss		6		3		1		1
Net periodic benefit cost		93		75		10		10
Regulatory account transfer (1)		(8)		9		-		-
Total	$	85	$	84	$	10	$	10

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

	Pension Benefits				Other Benefits
	Six Months Ended June 30,
(in millions)	2016		2015		2016		2015
Service cost for benefits earned	$	226	$	237	$	26	$	27
Interest cost		358		337		38		36
Expected return on plan assets		(414)		(436)		(54)		(56)
Amortization of prior service cost		4		7		8		10
Amortization of net actuarial loss		12		6		2		2
Net periodic benefit cost		186		151		20		19
Regulatory account transfer (1)		(17)		18		-		-
Total	$	169	$	169	$	20	$	19

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

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

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

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

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

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

	Pension		Other
	Benefits		Benefits		Total
(in millions, net of income tax)	Three Months Ended June 30, 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)		2		3		5
Amortization of net actuarial loss
(net of taxes of $2, and $1, respectively)		1		1		2
Regulatory account transfer
(net of taxes of $3 and $3, respectively)		(3)		(4)		(7)
Net current period other comprehensive gain (loss)		-		-		-
Ending balance	$	(21)	$	15	$	(6)

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

	Pension		Other		Other
	Benefits		Benefits		Investments		Total
(in millions, net of income tax)	Six Months Ended June 30, 2015
Beginning balance	$	(21)	$	15	$	17	$	11
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $3, $4, and $0, respectively) (1)		4		6		-		10
Amortization of net actuarial loss
(net of taxes of $3, $1, and $0, respectively) (1)		3		1		-		4
Regulatory account transfer
(net of taxes of $6, $5, and $0, respectively) (1)		(7)		(7)		-		(14)
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
	June 30,		December 31,
(in millions)	2016		2015
Pension benefits	$	2,415	$	2,414
Deferred income taxes		3,433		3,054
Utility retained generation		388		411
Environmental Compliance Costs		738		748
Price risk management		103		138
Unamortized loss, net of gain, on reacquired debt		85		94
Other		153		170
Total long-term regulatory assets	$	7,315	$	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
	June 30,		December 31,
(in millions)	2016		2015
Cost of removal obligations	$	4,832	$	4,605
Recoveries in excess of asset retirement obligations		643		631
Public purpose programs		569		600
Other		503		485
Total long-term regulatory liabilities	$	6,547	$	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
	June 30,		December 31,
(in millions)	2016		2015
Electric distribution	$	469	$	380
Utility generation		177		122
Gas distribution		380		493
Energy procurement		40		262
Public purpose programs		151		155
Other		480		348
Total regulatory balancing accounts receivable	$	1,697	$	1,760

	Payable
	Balance at
	June 30,		December 31,
(in millions)	2016		2015
Energy procurement	$	108	$	112
Public purpose programs		245		244
Other		301		359
Total regulatory balancing accounts payable	$	654	$	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 June 30, 2016:

					Letters of
	Termination	Facility			Credit		Commercial		Facility
(in millions)	Date	Limit			Outstanding		Paper		Availability
PG&E Corporation	April 2021	$	300	(1)	$	-	$	-	$	300
Utility	April 2021		3,000	(2)		33		1,280		1,687
Total revolving credit facilities		$	3,300		$	33	$	1,280	$	1,987

(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

At June 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 0.39% to 0.42%. At June 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 0.38% to 0.44%. 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 six months ended June 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		320		318
Equity contributions		-		280
Common stock issued		299		-
Share-based compensation		35		-
Common stock dividends declared		(477)		(423)
Preferred stock dividend requirement		-		(7)
Preferred stock dividend requirement of subsidiary		(7)		-
Balance at June 30, 2016	$	16,998	$	17,228

During the three and six months ended June 30, 2016, PG&E Corporation sold 0.8 million and 2.2 million shares under the February 2015 equity distribution agreement for cash proceeds of $49 million and $123 million, respectively, net of commissions paid of $0.4 million and $1 million, respectively. As of June 30, 2016, the remaining gross sales available under this agreement were $301 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 sixmonths ended June 30, 2016, 4 million shares were issued for cash proceeds of $165 million under these plans.

NOTE 6: EARNINGS PER SHARE

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions, except per share amounts)	2016		2015		2016		2015
Income available for common shareholders	$	206	$	402	$	313	$	433
Weighted average common shares outstanding, basic		497		480		495		479
Add incremental shares from assumed conversions:
Employee share-based compensation		1		3		2		4
Weighted average common shares outstanding, diluted		498		483		497		483
Total earnings per common share, diluted	$	0.41	$	0.83	$	0.63	$	0.90

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’s Condensed 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
		June 30,	December 31,
Underlying Product	Instruments	2016	2015
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	380,865,985	333,091,813
	Options	113,148,965	111,550,004
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	3,852,324	3,663,512
	Congestion Revenue Rights (3)	181,803,754	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 June 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	$	106	$	(11)	$	17	$	112
Other noncurrent assets – other		165		(7)		-		158
Current liabilities – other		(75)		11		14		(50)
Noncurrent liabilities – other		(110)		7		3		(100)
Net commodity risk	$	86	$	-	$	34	$	120

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				Six Months Ended
	June 30,				June 30,
(in millions)	2016		2015		2016		2015
Unrealized gain (loss) - regulatory assets and liabilities (1)	$	66	$	28	$	59	$	(24)
Realized gain (loss) - cost of electricity (2)		(12)		10		(41)		3
Realized loss - cost of natural gas (2)		(5)		(4)		(6)		(5)
Net commodity risk	$	49	$	34	$	12	$	(26)

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

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

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

The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At June 30, 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
	June 30,		December 31,
(in millions)	2016		2015
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(11)	$	(2)
Collateral posting in the normal course of business related to
these derivatives		7		-
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(4)	$	(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 June 30, 2016
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	70	$	-	$	-	$	-	$	70
Nuclear decommissioning trusts
Short-term investments		11		-		-		-		11
Global equity securities		1,644		-		-		-		1,644
Fixed-income securities		698		523		-		-		1,221
Assets measured at NAV		-		-		-		-		13
Total nuclear decommissioning trusts (2)		2,353		523		-		-		2,889
Price risk management instruments
(Note 7)
Electricity		21		23		215		(1)		258
Gas		1		11		-		-		12
Total price risk management instruments		22		34		215		(1)		270
Rabbi trusts
Fixed-income securities		-		59		-		-		59
Life insurance contracts		-		74		-		-		74
Total rabbi trusts		-		133		-		-		133
Long-term disability trust
Short-term investments		4		-		-		-		4
Assets measured at NAV		-		-		-		-		143
Total long-term disability trust		4		-		-		-		147
Total assets	$	2,449	$	690	$	215	$	(1)	$	3,509
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	26	$	2	$	149	$	(28)	$	149
Gas		5		3		-		(7)		1
Total liabilities	$	31	$	5	$	149	$	(35)	$	150

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

(2) Represents amount before deducting $343 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 six months ended June 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 June 30, 2016				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	215	$	53	Market approach	CRR auction prices	$	(23.81) - 103.97
Power purchase agreements	$	-	$	96	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 six months ended June 30, 2016 and 2015:

	Price Risk Management Instruments
(in millions)	2016		2015
Asset (liability) balance as of April 1	$	75	$	42
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(9)		6
Asset (liability) balance as of June 30	$	66	$	48

(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)		(23)		(21)
Asset (liability) balance as of June 30	$	66	$	48

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments:

The fair values of cash, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at June 30, 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 June 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 June 30, 2016				At December 31, 2015
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
PG&E Corporation	$	350	$	357	$	350	$	354
Utility		15,415		18,356		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 June 30, 2016
Nuclear decommissioning trusts
Short-term investments	$	11	$	-	$	-	$	11
Global equity securities		621		1,051		(15)		1,657
Fixed-income securities		1,126		98		(3)		1,221
Total (1)	$	1,758	$	1,149	$	(18)	$	2,889
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 $343 million and $314 million at June 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)	June 30, 2016
Less than 1 year	$	35
1–5 years		408
5–10 years		262
More than 10 years		516
Total maturities of fixed-income securities	$	1,221

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015			2016	2015
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
trust investments	$	282	$	362	$	721	$	779
Gross realized gains on securities held as available-for-sale		4		12		9		47
Gross realized losses on securities held as available-for-sale		(1)		(10)		(3)		(13)

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 also may be 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 been made 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 the CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.

On July 12, 2016, the assigned commissioner and ALJ adopted the process report jointly submitted by the Cities of San Bruno and San Carlos, ORA, the SED, TURN, and the Utility in April 2016. The approved framework for resolving the proceeding includes 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 does not currently include these communications within the scope of the proceeding but leaves the matter open for review pending the parties’ discovery on these communications.

The CPUC will determine whether the communications included within the scope of the proceeding were in violation of its rules and whether to impose penalties or other remedies. The CPUC can impose fines up to $50,000 for each violation, per day. 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 this discretion in determining penalties.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the OII but they 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 the federal and state investigators. 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 June 1, 2016, the assigned ALJ issued a POD in the CPUC’s investigation. The POD finds that the Utility failed to comply with applicable laws and regulations in maintaining accurate records of its natural gas distribution system and assesses a penalty of $24 million. With the citation previously assessed for the Carmel incident, the total fine imposed on the Utility is $35 million. The POD determines that certain incidents show systemic failure on the Utility’s part, while other incidents are isolated deviations in an otherwise generally compliant system. The identified systemic failures are as follows: (1) failure to promptly and comprehensively correct mapping errors of plastic inserts in the distribution system, (2) failure to promptly and comprehensively analyze the impacts of the missing paper leak repair records from 1979 to 1991 for the De Anza division, and to institute such corrective actions as may be possible, and (3) failure to adequately respond to local officials. The POD also identifies 13 operational incidents defined as isolated violations.

The POD does not order remedial measures. Instead, the Utility and all interested parties are to meet and confer to consider and develop additional remedial measures necessary to address the issues identified in the POD. The objective of this process will be a comprehensive compliance plan that includes all feasible and cost-effective measures necessary to improve the Utility’s natural gas distribution facilities record-keeping. The POD indicates that the SED shall participate in and monitor this process and, no later than 120 days after the effective date of the order, the Utility shall submit its initial compliance plan.

On June 28, 2016 and July 1, 2016, the City of Carmel-by-the-Sea (“Carmel”) and the SED, respectively, filed an appeal from the POD. In its appeal, the SED indicates that the $24 million fine assessed in the POD is insufficient and recommends that its initial penalty recommendation of $112 million be adopted. If the recommended penalty is not adopted, the SED recommends modifications to the POD, including both method and scope changes to the penalty calculation, that would result in a shareholder-funded fine of $55.5 million. With the citation previously assessed for the Carmel incident, the total fines imposed on the Utility would amount to $66 million. Specifically, if the SED’s initial recommendation of $112 million is not adopted, the SED recommends edits to the POD proposing that (1) the POD should remove all language that suggests that 99 percent safety is acceptable, (2) the Utility should be ordered to pay a shareholder-funded fine in connection with the maximum allowable operating pressure documentation, (3) a different violation end date should be used for the missing DeAnza leak repair records, and (4) the POD’s methodology for assessing fines for specific incidents should be adjusted. Carmel indicates that the POD incorrectly applied fines corresponding to the violations it found the Utility committed and requests that the CPUC imposes a just fine and proper remedies to promote deterrence. Carmel also indicates that the POD erred by not offering discussions on whether the shareholders or customers should bear the cost of the fine and on Carmel’s proposed remedies.

On July 18, 2016, the Utility filed its response to these appeals. The Utility cannot predict when the CPUC will issue a decision or its outcome.

At June 30, 2016, the Utility’s Condensed Consolidated Balance Sheets include a $24 million accrual in connection with the POD. It is reasonably possible that the Utility will incur a loss in excess of this amount, as the CPUC may impose a higher fine and other penalties, as a result of the appeals currently pending in this proceeding. PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows could be materially affected depending on the ultimate amount of the penalty that is imposed and the ultimate amount of unrecoverable costs that the Utility incurs to comply with required remedial measures.

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. In addition, the California utilities are required to inform the SED of self-identified or self-corrected violations of natural gas safety regulations. 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 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. The SED is required, however, to impose the maximum statutory penalty of $50,000 for each separate violation.

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.

Federal Matters

Federal Criminal Indictment

On July 29, 2014, a federal grand jury for the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court that superseded the original indictment that was returned on April 1, 2014. The superseding indictment charges 27 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. The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. On December 23, 2015, the court presiding over the federal criminal proceeding dismissed 15 of the Pipeline Safety Act counts, leaving 13 remaining counts. The trial began on June 14, 2016. 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 strength pressure test record with respect to a distribution feeder main (DFM1816-01). Therefore, the number of counts has been reduced from 13 to 12. On July 27, 2016, the parties completed delivering their closing arguments and the case was submitted to the jury. The Utility is unable to predict when and if the jury will return its verdict.

The maximum statutory fine for each felony count is $500,000, for total potential fines of $6 million. The government is also seeking fines under the Alternative Fines Act. 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.” On December 8, 2015, the court issued an order granting, in part, the Utility’s request to dismiss the government’s allegations seeking an alternative fine under the Alternative Fines Act. The court dismissed the government’s allegations regarding the amount of losses, but concluded that it required additional information about how the government would prove its allegations about the amount of gross gains prior to deciding whether to dismiss those allegations. Based on the superseding indictment’s allegation that the Utility derived gross gains of approximately $281 million, the potential maximum alternative fine would be approximately $562 million. On February 2, 2016, the court issued an order holding that if the government’s allegations about the Utility’s gross gains are considered, they would be considered in a second trial phase that would take place after the trial on the criminal charges.

The Utility entered a plea of not guilty. The Utility believes that criminal charges and the alternative fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB's investigation, as alleged in the superseding indictment. PG&E Corporation and the Utility have not accrued any charges for criminal fines in their Condensed Consolidated Financial Statements as such amounts were not considered to be probable.

Other Federal Matters

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 indictment discussed above. It is uncertain whether any additional charges will be brought against the Utility.

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 and the April 9, 2015 Penalty Decision 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 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, during the three and six months ended June 30, 2016, the Utility incurred charges of $190 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This includes $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.

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 future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.

For the three and six months ended June 30, 2016, the Utility recorded charges for disallowed capital spending of $148 million and $235 million, respectively, as a result of the Penalty Decision. The cumulative charges at June 30, 2016, and the additional future charges to reach the $1.6 billion total are shown in the following table:


	Six Months		Cumulative		Future
	Ended		Charges		Charges
		June 30,		June 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)		235		642		50		692
Disallowed revenue for pipeline safety
expenses (2)		-		-		158		158
CPUC estimated cost of other remedies (3)		-		-		-		50
Total Penalty Decision fines and remedies	$	235	$	1,342	$	208	$	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 identify 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 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. (In the final phase one decision, the CPUC requested comments on whether the percentage of the disallowance that should be applied to capital expenditures as opposed to expense should be changed.) The Utility estimates that approximately $642 million of cumulative capital spending is probable of disallowance, subject to adjustment based on the CPUC final phase two decision in the Utility’s 2015 GT&S rate case.

(2) These costs are being expensed as incurred. 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 June 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.

Butte Fire Litigation

On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the “Butte fire,” the wildfire that ignited and spread in Amador and Calaveras Counties in Northern California in September 2015. 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. Approximately 44 complaints have been filed to date against the Utility and its vegetation management contractors in the Superior Court of California in both the County of Calaveras and the County of San Francisco, involving approximately 1,550 individual plaintiffs and their insurance companies. These complaints are now part of the master complaints. The number of individual complaints and plaintiffs may increase in the future.

Plaintiffs have begun to present to the Utility claims seeking early resolution of preference cases (individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling). The Utility has begun mediating and settling these preference cases. A case management conference was held on July 14, 2016 and the next case management conference is scheduled for September 1, 2016.

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 in connection with this matter, which corresponds to the lower end of the range of its reasonably estimable losses. This amount is based on estimates about the number, size, and type of structures damaged or destroyed, and assumptions about the contents of such structures and other property damage. The Utility currently is unable to reasonably estimate the upper end of the rangebecause it is at an early stage of the evaluation of claims and the mediation and settlement process. At June 30, 2016, the Condensed Consolidated Balance Sheets include $350 million in other current liabilities for the estimated property damages.

The Utility also believes that it is reasonably possible that it will incur a loss in excess of the $350 million accrued through June 30, 2016, for additional costs related to fire suppression, personal injury damages, and other damages. The Utility believes that $90 million is a reasonable estimate of fire suppression costs. The Utility currently is unable to reasonably estimate other costs for the reasons indicated above.

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. At June 30, 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 full 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 amount of insurance is insufficient to cover the Utility’s liability resulting from the Butte fire, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected.

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” and “Butte Fire Litigation”) totaled $69 million at June 30, 2016 and $63 million at December 31, 2015. These amounts are included in other current liabilities in the Condensed Consolidated Balance Sheets. At June 30, 2016, it is reasonably possible that the accrual could increase by $30 million. 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.

Environmental Remediation Contingencies

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

	Balance at
	June 30,		December 31,
(in millions)	2016		2015
Topock natural gas compressor station (1)	$	302	$	300
Hinkley natural gas compressor station (1)		138		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		148		164
Fossil fuel-fired generation facilities and sites		103		94
Total environmental remediation liability	$	996	$	969

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

At June 30, 2016, the Utility expected to recover $711 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.

The Utility’s environmental remediation liability at June 30, 2016 reflects the Utility’s 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 be performed to implement the final remediation plan 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.

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 late 2016. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in early 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.

The Utility’s environmental remediation liability at June 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 be performed to implement the final groundwater remedy 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.

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, future 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.

At December 31, 2015, the Consolidated Balance Sheets reflected $454 million in net claims, within Disputed claims and customer refunds, and $228 million of cash in escrow for payment of the remaining net disputed claims, within Restricted cash. There were no significant changes to these balances during the six months ended June 30, 2016. However, on June 27, 2016, the FERC approved the Utility’sjoint offer of settlement which includes a $256 million settlement agreementand any related adjustments. If approved by the respective bankruptcy courts for the Utility and the California Power Exchange, the settlement agreement would not result in a refund to customers or an impact to net income. The settlement agreement would result in a reduction to the Utility’s net disputed claims liability and a reduction to both the receivable in regulatory assets and the remaining escrow balance.

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 June 30, 2016, it is reasonably possible that unrecognized tax benefits will decrease by approximately $60 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 had undiscounted 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.) The Utility has not entered into any new material commitments during the six months ended June 30, 2016.

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 and 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				Six Months Ended
	June 30,				June 30,
			EPS				EPS
(in millions, except per share amounts)	Earnings (1)		(Diluted)		Earnings (1)		(Diluted)
Income Available for Common Shareholders - June 30, 2015	$	402	$	0.83	$	433	$	0.90
Fines and penalties (2)		44		0.09		413		0.85
Pipeline-related expenses (3)		9		0.02		19		0.04
Legal and regulatory related expenses (4)		10		0.02		18		0.04
Natural gas matters insurance recoveries		(23)		(0.05)		(23)		(0.05)
Earnings from Operations - June 30, 2015 (5)	$	442	$	0.91	$	860	$	1.78
Growth in rate base earnings		25		0.05		51		0.10
Timing of taxes (6)		(41)		(0.08)		(81)		(0.16)
Nuclear refueling outage		(30)		(0.06)		(30)		(0.06)
Regulatory and legal matters		(23)		(0.05)		(23)		(0.05)
Gain on disposition of SolarCity stock (7)		-		-		(14)		(0.03)
Increase in shares outstanding		-		(0.03)		-		(0.05)
Miscellaneous		(43)		(0.08)		(26)		(0.05)
Earnings from Operations - June 30, 2016 (5)	$	330	$	0.66	$	737	$	1.48
Butte fire related costs (net of insurance) (8)		125		0.25		(101)		(0.20)
Fines and penalties (2)		(112)		(0.22)		(163)		(0.32)
Pipeline-related expenses (3)		(16)		(0.03)		(29)		(0.06)
Legal and regulatory related expenses (4)		(8)		(0.02)		(18)		(0.04)
GT&S capital disallowance (9)		(113)		(0.23)		(113)		(0.23)
Income Available for Common Shareholders - June 30, 2016	$	206	$	0.41	$	313	$	0.63

(1) All amounts presented in the table above are tax-adjusted at PG&E Corporation’s combined statutory tax rate of 40.75%, unless otherwise noted.

(2) Represents the impact of the Penalty Decision (see Note 9 of the Notes to the Condensed Consolidated Financial Statements). For the three and six months ended June 30, 2016, the Utility incurred costs of $148 million pre-tax (before tax impact of $60 million) and $235 million pre-tax (before tax impact of $96 million), respectively for disallowed capital charges. In addition, for the three and six months ended June 30, 2016, the Utility accrued fines of $24 million, which are not deductible for tax purposes, in connection with the POD in the CPUC’s investigation regarding natural gas distribution facilities record-keeping practices.

(3) The Utility incurred costs of $27 million pre-tax (before tax impact of $11 million) and $49 million pre-tax (before tax impact of $20 million), during the three and six months ended June 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.

(4) The Utility incurred costs of $14 million pre-tax (before tax impact of $6 million) and $31 million pre-tax (before tax impact of $13 million), during the three and six months ended June 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.

(5) “Earnings from operations” is not calculated in accordance with GAAP and excludes the items impacting comparability shown in Notes (2), (3), (4), (8) and (9).

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

(7) Represents the gain recognized during the six months ended June 30, 2015. No comparable gain was recognized in 2016.

(8) The Utility accrued charges of $0 million and $350 million pre-tax (before tax impact of $143 million), for the three and six months ended June 30, 2016, respectively, related to estimated property damages in connection with the Butte fire, partially offset by approximately $260 million pre-tax (before tax impact of $106 million) accrued as probable insurance recoveries. The Utility also incurred charges of $49 million pre-tax (before tax impact of $20 million) and $80 million pre-tax (before tax impact of $32 million), for the three and six months ended June 30, 2016, respectively, for Utility clean-up, repair, and legal costs associated with the Butte fire.

(9) Represents charges of $190 million pre-tax (before tax impact of $77 million) of probablecapitaldisallowancesas a result of thephase one 2015 GT&S rate case decision that the Utility incurred in the three and six months ended June 30, 2016, including $134 million pre-tax (before tax impact of $54 million) for 2011 through 2014 capital expenditures in excess of adopted amounts and $56 million pre-tax (before tax impact of $23 million) for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. (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. Future financial results will be impacted by the unrecoverable pipeline safety-related and remedies costs required by the Penalty Decision. (For more information about the Penalty Decision, see Note 9 of the Notes to the Condensed Consolidated Financial Statements.) The Utility’s future results may also be impacted by various other pending enforcement, litigation and regulatory actions, including but not limited to those related to the federal criminal charges and CPUC investigations of the Utility’s compliance with natural gas distribution facilities record-keeping practices, potential violations of the CPUC’s ex parte communication rules, and the Butte fire. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

•	The Timing and Outcome of Ratemaking Proceedings. The CPUC approved 2015 GT&S “interim” revenue requirements in its 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 revenue requirement increase since January 1, 2015 until after the final phase two decision is issued. The final phase two decision will allocate the $850 million of shareholder funded safety work related to the Penalty Decision and as a result, reduce revenue requirements in this rate case. (See “Regulatory Matters – 2015 Gas Transmission and Storage Rate Case” below for more information.) Additionally, in May 2016, the Utility updated its 2017 GRC application to request that the CPUC authorize a revenue requirement increase of $319 million for 2017 for the Utility’s electric generation business and its electric and natural gas distribution businesses with attrition increases in 2018 and 2019. In order to allow settlement discussions to proceed, the procedural schedule for this case has been updated calling for a final decision in early 2017, if a settlement has not been reached before then. A settlement conference is currently scheduled for August 3, 2016. (See “Regulatory Matters − 2017 General Rate Case” 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’s ability to earn its authorized rate of return could be materially affected if actual costs differ from the amounts authorized in the rate case decisions. In addition to incurring shareholder-funded safety costs and costs associated with remedial measures required by the Penalty Decision, the Utility also 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 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 current rate case cycle. The ultimate amount of unrecovered costs also could be affected by how the CPUC determines which costs are included in determining whether the $850 million shareholder-funded obligation under the Penalty Decision has been met, and the outcome of pending and future investigations and enforcement matters. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The Utility’s ability to recover costs in the future also could be affected by decreases in customer demand. (See “Forward-Looking Statements” below for more information.)

•

The Amount and Timing of the Utility’s Financing Needs. PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. For the six months ended June 30, 2016, PG&E Corporation issued $299 million of common stock and used $280 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 2016 and future years to support the Utility’s capital expenditures. PG&E Corporation will issue additional equity to fund charges incurred by the Utility to comply with the Penalty Decision, 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.