Recently Adopted Accounting ~~Standards Issued But Not Yet Adopted~~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. ~~The ASU will be effective for fiscal years beginning after December 15, 2015.~~ PG&E Corporation and the Utility ~~are currently evaluating~~adopted this guidance effectiveJanuary 1, 2016 and applied the ~~impact the guidance will have on their disclosures and will adopt~~requirements retrospectively for all periods presented. The adoption of this standard ~~starting~~did not impact their Condensed Consolidated Financial Statements. All prior periods presented in these Condensed Consolidated financial statements reflect the ~~first quarter~~retrospective adoption of ~~2016.~~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. ~~The ASU will be effective on January 1, 2016.~~ PG&E Corporation and the Utility ~~are currently evaluating the~~adopted this guidance effective January 1, 2016. The adoption of this guidance did not have a material impact ~~the guidance will have~~ on their ~~consolidated financial statements and related disclosures and will adopt this standard starting in the first quarter of 2016.~~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. ~~PG&E Corporation and the Utility currently disclose debt issuance costs in current assets – other and noncurrent assets – other.~~ The amendments in this ASU ~~effective on January 1, 2016,~~ 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 doadopted this guidance effective January 1, 2016 and applied the requirements retrospectively for all periods presented. The adoption of this guidance did not ~~expect this reclassification to~~ have a material impact on their ~~consolidated financial statements.~~Condensed Consolidated Financial Statements. PG&E Corporation and the Utility ~~will adopt~~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 ~~standard starting in the first quarter of 2016.~~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 are currently evaluating the impact the guidance will have on their 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 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 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 ~~issued~~deferred ~~ASU No. 2015-14,~~ ~~Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, deferring~~ 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 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				Balance at
	September 30,		December 31,		March 31,		December 31,
(in millions)	2015		2014		2016		2015
Pension benefits	$	2,304	$	2,347	$	2,414	$	2,414
Deferred income taxes		2,771		2,390		3,265		3,054
Environmental compliance costs		705		717
Utility retained generation		423		456		399		411
Environmental Compliance Costs						683		748
Price risk management		143		127		134		138
Unamortized loss, net of gain, on reacquired debt		98		113		90		94
Electromechanical meters		18		70
Other		122		102		145		170
Total long-term regulatory assets	$	6,584	$	6,322	$	7,130	$	7,029

Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at				Balance at
	September 30,		December 31,		March 31,		December 31,
(in millions)	2015		2014		2016		2015
Cost of removal obligations	$	4,509	$	4,211	$	4,717	$	4,605
Recoveries in excess of asset retirement obligations		610		754		645		631
Public purpose programs		701		701		620		600
Other		474		624		504		485
Total long-term regulatory liabilities	$	6,294	$	6,290	$	6,486	$	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’s recovery of revenue requirements and costs is generally decoupled from the volume of sales.~~ 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 ~~composed~~comprised of the following:

	Receivable				Receivable
	Balance at				Balance at
	September 30,		December 31,		March 31,		December 31,
(in millions)	2015		2014		2016		2015
Electric distribution	$	265	$	344	$	515	$	380
Utility generation		24		261		225		122
Gas distribution		718		566		280		493
Energy procurement		390		608		87		262
Public purpose programs		136		109		149		155
Other		324		378		465		348
Total regulatory balancing accounts receivable	$	1,857	$	2,266	$	1,721	$	1,760

	Payable				Payable
	Balance at				Balance at
	September 30,		December 31,		March 31,		December 31,
(in millions)	2015		2014		2016		2015
Energy procurement	$	181	$	188	$	184	$	112
Public purpose programs		173		154		212		244
Other		449		748		308		359
Total regulatory balancing accounts payable	$	803	$	1,090	$	704	$	715

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

NOTE 4: DEBT

Revolving Credit Facilities and Commercial Paper Program

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at ~~September 30, 2015:~~March 31,2016:

					Letters of										Letters of
	Termination	Facility			Credit		Commercial		Facility		Termination	Facility			Credit		Commercial		Facility
(in millions)	Date	Limit			Outstanding		Paper		Availability		Date	Limit			Outstanding		Paper		Availability
PG&E Corporation	April 2020	$	300	(1)	$	-	$	-	$	300	April 2020	$	300	(1)	$	-	$	-	$	300
Utility	April 2020		3,000	(2)		34		881		2,085	April 2020		3,000	(2)		33		443		2,524
Total revolving
credit facilities		$	3,300		$	34	$	881	$	2,385
Total revolving credit facilities												$	3,300		$	33	$	443	$	2,824

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

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

On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities. The amendments and restatements extended the termination dates of the credit facilities from April 1, 2019 to April 27, 2020, reduced the amount of lender commitments to the letter of credit sublimits from $100 million to $50 million for PG&E Corporation’s credit facility and from $1.0 billion to $500 million for the Utility’s credit facility, and reduced the swingline commitment on the Utility’s credit facility from $300 million to $75 million.21

Other Short-term Borrowings

In ~~July 2015,~~March 2016, the Utility ~~increased the commercial paper program limit from $1.75 billion to $2.5 billion. PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300~~entered into a $250 million and $2.5 billion, respectively. PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a reduction to the amount available under their respective revolving credit facilities.

~~Issuances and Maturities~~

~~In June 2015, the Utility issued $400 million principal amount of 3.50% Senior Notes due June 15, 2025 and $100 million of 4.30% Senior Notes due March 15, 2045.~~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

In ~~addition, $300~~March 2016, the Utility issued $600 million principal amount of 2.95% Senior Notes due March 1, 2026. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s ~~Floating Rate Senior Notes matured in May 2015.~~outstanding commercial paper.

Variable Rate Interest

At ~~September 30, 2015,~~March 31,2016, 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 ~~were 0.01%~~ranged from 0.37% to 0.45%. At ~~September 30, 2015,~~March 31, 2016, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ~~were 0.01%~~ranged from 0.34% to 0.38%.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the ~~nine~~three months ended ~~September 30, 2015were~~March 31,2016were as follows:

	PG&E Corporation		Utility		PG&E Corporation		Utility
	Total		Total		Total		Total
(in millions)	Equity		Shareholders' Equity		Equity		Shareholders' Equity
Balance at December 31, 2014	$	16,000	$	16,229
Balance at December 31, 2015					$	16,828	$	17,060
Comprehensive income		733		715		110		108
Equity contributions		-		605		-		65
Common stock issued		704		-		152		-
Share-based compensation		58		8		6		-
Common stock dividends declared		(665)		(537)		(229)		(179)
Preferred stock dividend requirement		-		(10)		-		(3)
Preferred stock dividend requirement of subsidiary		(10)		-		(3)		-
Balance at September 30, 2015	$	16,820	$	17,010
Balance at March 31, 2016					$	16,864	$	17,051

~~In February 2015, PG&E Corporation entered into a new equity distribution agreement providing for~~

During the ~~sale of PG&E Corporation common stock having an aggregate gross sales price of up to $500 million. In the first quarter of 2015,~~three months ended March 31, 2016, PG&E Corporation sold ~~1.4~~1.3 million shares under ~~this~~the February 2015 equity distribution agreement for cash proceeds of $74 million, net of commissions paid of $1 million. ~~No additional shares have been sold~~As of March 31, 2016, the remaining gross sales available under ~~the equity distribution agreement.~~

~~In August 2015, PG&E Corporation sold 6.8 million shares of its common stock in an underwritten public offeringfor cash proceeds of $352 million, net of fees.~~this agreement were $350 million.

PG&E Corporation also issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the ~~nine months~~threemonths ended ~~September 30, 2015, 6.1~~March 31,2016, 2.3 million shares were issued for cash proceeds of ~~$263~~$72 million under these plans.

NOTE 6: EARNINGS PER SHARE

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,				Three Months Ended March 31,
(in millions, except per share amounts)	2015		2014		2015		2014		2016		2015
Income available for common shareholders	$	307	$	811	$	740	$	1,305	$	107	$	31
Weighted average common shares outstanding, basic		486		472		481		466		493		477
Add incremental shares from assumed conversions:
Employee share-based compensation		3		2		3		2		2		4
Weighted average common share outstanding, diluted		489		474		484		468
Weighted average common shares outstanding, diluted										495		481
Total earnings per common share, diluted	$	0.63	$	1.71	$	1.53	$	2.79	$	0.22	$	0.06

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 ~~forward~~physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, ~~futures,~~ options, and ~~CRRs.~~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~~Utility’sCondensed Consolidated Balance Sheets on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.

~~Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets.~~ These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives 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			Contract Volume at
		September 30,	December 31,		March 31,	December 31,
Underlying Product	Instruments	2015	2014	Instruments	2016	2015
Natural Gas (1) (MMBtus (2))	Forwards and Swaps	276,847,153	308,130,101	Forwards and Swaps	341,884,852	333,091,813
	Options	134,380,439	164,418,002	Options	92,426,200	111,550,004
Electricity (Megawatt-hours)	Forwards and Swaps	4,884,523	5,346,787	Forwards and Swaps	3,580,205	3,663,512
	Congestion Revenue Rights (3)	186,018,832	224,124,341	Congestion Revenue Rights (3)	198,499,963	216,383,389

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

(2) Million British Thermal Units.

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

Presentation of Derivative Instruments in the Financial Statements

At ~~September 30,~~March 31,2016, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative						Total Derivative
(in millions)	Balance		Netting		Cash Collateral		Balance
Current assets – other	$	91	$	(5)	$	12	$	98
Other noncurrent assets – other		173		(5)		-		168
Current liabilities – other		(105)		5		46		(54)
Noncurrent liabilities – other		(139)		5		16		(118)
Net commodity risk	$	20	$	-	$	74	$	94

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
$
63

$
(2)

$
11

$
72
Other noncurrent assets – other

130

(2)

-

128
Current liabilities – other

(84)

2

34

(48)
Noncurrent liabilities – other

(145)

2

24

(119)
Net commodity risk
$
(36)

$
-

$
69

$
33

~~At December 31, 2014, the Utility’s outstanding derivative balances were as follows:~~

	Commodity Risk								Commodity Risk
	Gross Derivative						Total Derivative		Gross Derivative						Total Derivative
(in millions)	Balance		Netting		Cash Collateral		Balance		Balance		Netting		Cash Collateral		Balance
Current assets – other	$	73		(4)		19	$	88	$	97		(4)		25	$	118
Other noncurrent assets – other		178		(13)		-		165		172		(2)		-		170
Current liabilities – other		(78)		4		26		(48)		(102)		4		44		(54)
Noncurrent liabilities – other		(140)		13		9		(118)		(140)		2		21		(117)
Net commodity risk	$	33	$	-	$	54	$	87	$	27	$	-	$	90	$	117

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

Commodity Risk

Three Months Ended

Nine Months Ended

September 30,

September 30,
(in millions)
2015

2014

2015

2014
Unrealized gain (loss) - regulatory assets and liabilities (1)
$
(45)

$
(6)

$
(69)

$
79
Realized gain (loss) - cost of electricity (2)

1

(22)

4

(48)
Realized loss - cost of natural gas (2)

(3)

(4)

(8)

(7)
Net commodity risk
$
(47)

$
(32)

$
(73)

$
24

	Commodity Risk
	Three Months Ended March 31,
(in millions)	2016		2015
Net unrealized gain (loss) - regulatory assets and liabilities (1)	$	(7)	$	(52)
Realized loss - cost of electricity (2)		(29)		(7)
Realized loss - cost of natural gas (2)		(1)		(1)
Total commodity risk	$	(37)	$	(60)

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

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

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

The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At ~~September 30, 2015,~~March 31,2016, 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				Balance at
	September 30,		December 31,		March 31,		December 31,
(in millions)	2015		2014		2016		2015
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(2)	$	(47)	$	(9)	$	(2)
Collateral posting in the normal course of business related to these derivatives		-		44
Collateral posting in the normal course of business related to
these derivatives						7		-
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(2)	$	(3)	$	(2)	$	(2)

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

NOTE 8: FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

	Fair Value Measurements										Fair Value Measurements
	At September 30, 2015										At March 31, 2016
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total		Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	92	$	-	$	-	$	-	$	92
Short-term investments											$	97	$	-	$	-	$	-	$	97
Nuclear decommissioning trusts
Money market investments		21		-		-		-		21
Short-term investments												25		-		-		-		25
Global equity securities		1,445		12		-		-		1,457		1,619		-		-		-		1,619
Fixed-income securities		710		523		-		-		1,233		682		508		-		-		1,190
Assets measured at NAV												-		-		-		-		13
Total nuclear decommissioning trusts (2)		2,176		535		-		-		2,711		2,326		508		-		-		2,847
Price risk management instruments
(Note 7)
Electricity		-		4		185		7		196		1		12		246		3		262
Gas		-		4		-		-		4		2		3		-		(1)		4
Total price risk management
instruments		-		8		185		7		200
Total price risk management instruments												3		15		246		2		266
Rabbi trusts
Fixed-income securities		-		45		-		-		45		-		58		-		-		58
Life insurance contracts		-		71		-		-		71		-		72		-		-		72
Total rabbi trusts		-		116		-		-		116		-		130		-		-		130
Long-term disability trust
Money market investments		7		-		-		-		7
Global equity securities		-		18		-		-		18
Fixed-income securities		-		106		-		-		106
Short-term investments												8		-		-		-		8
Assets measured at NAV												-		-		-		-		147
Total long-term disability trust		7		124		-		-		131		8		-		-		-		155
Total assets	$	2,275	$	783	$	185	$	7	$	3,250	$	2,434	$	653	$	246	$	2	$	3,495
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	60	$	3	$	164	$	(62)	$	165	$	67	$	5	$	171	$	(72)	$	171
Gas		-		2		-		-		2		-		1		-		-		1
Total liabilities	$	60	$	5	$	164	$	(62)	$	167	$	67	$	6	$	171	$	(72)	$	172

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

(2) Represents amount before deducting ~~$294~~$331 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements										Fair Value Measurements
	At December 31, 2014										At December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total		Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	94	$	-	$	-	$	-	$	94
Short-term investments											$	64	$	-	$	-	$	-	$	64
Nuclear decommissioning trusts
Money market investments		17		-		-		-		17
Short-term investments												36		-		-		-		36
Global equity securities		1,585		13		-		-		1,598		1,520		-		-		-		1,520
Fixed-income securities		741		389		-		-		1,130		694		521		-		-		1,215
Assets measured at NAV												-		-		-		-		13
Total nuclear decommissioning trusts (2)		2,343		402		-		-		2,745		2,250		521		-		-		2,784
Price risk management instruments
(Note 9 in the 2014 Form 10-K)
(Note 9 in the 2015 Form 10-K)
Electricity		-		17		232		2		251		-		9		259		18		286
Gas		1		1		-		-		2		-		1		-		1		2
Total price risk management
instruments		1		18		232		2		253
Total price risk management instruments												-		10		259		19		288
Rabbi trusts
Fixed-income securities		-		42		-		-		42		-		57		-		-		57
Life insurance contracts		-		72		-		-		72		-		70		-		-		70
Total rabbi trusts		-		114		-		-		114		-		127		-		-		127
Long-term disability trust
Money market investments		7		-		-		-		7
Global equity securities		-		25		-		-		25
Fixed-income securities		-		128		-		-		128
Short-term investments												7		-		-		-		7
Assets measured at NAV												-		-		-		-		158
Total long-term disability trust		7		153		-		-		160		7		-		-		-		165
Other investments		33		-		-		-		33
Total assets	$	2,478	$	687	$	232	$	2	$	3,399	$	2,321	$	658	$	259	$	19	$	3,428
Liabilities:
Price risk management instruments
(Note 9 in the 2014 Form 10-K)
(Note 9 in the 2015 Form 10-K)
Electricity	$	47	$	5	$	163	$	(52)	$	163	$	69	$	1	$	170	$	(70)	$	170
Gas		-		3		-		-		3		-		2		-		(1)		1
Total liabilities	$	47	$	8	$	163	$	(52)	$	166	$	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 ~~$324~~$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. ~~Investments, primarily consisting of equity securities, that~~There are ~~valued using a net asset value per share can~~no restrictions on the terms and conditions upon which the investments may be ~~redeemed quarterly with notice not to exceed 90 days. Equity investments valued at net asset value per share utilize investment strategies aimed at matching the performance of indexed funds.~~redeemed. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the ~~nine~~three months ended ~~September 30, 2015~~March 31,2016 and ~~2014.~~2015.

Trust Assets

~~Nuclear decommissioning trust assets and other trust assets are composed primarily of equity securities, debt securities, and life insurance policies.~~ 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.

~~Equity~~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. Equity securities also include commingled funds that are composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world. Investments in these funds are classified as Level 2 because price quotes are readily observable and available.

~~Debt~~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 US 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 ~~forwards and swaps~~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 ~~forwards and swaps,~~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 ~~California Independent System Operator-imposed~~CAISO-imposed congestion charges in the day-ahead market. ~~CRRs are classified as Level 3 and are valued based on CRR auction prices, including historical prices.~~ Limited market data is available in the ~~California Independent System Operator~~CAISO auction and between auction dates; therefore, the Utility ~~uses models~~utilizes historical prices to forecast ~~CRR prices for those periods not covered in the auctions.~~ 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~~financeand 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								Fair Value at
(in millions)	At September 30, 2015				Valuation	Unobservable			At March 31, 2016				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)		Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	185	$	51	Market approach	CRR auction prices	$	(15.97) - 8.17	$	246	$	59	Market approach	CRR auction prices	$	(23.81) - 8.76
Power purchase agreements	$	-	$	113	Discounted cash flow	Forward prices	$	17.64 - 38.80	$	-	$	112	Discounted cash flow	Forward prices	$	17.64 - 38.80

(1) Represents price per megawatt-hour

	Fair Value at								Fair Value at
(in millions)	At December 31, 2014				Valuation	Unobservable			At December 31, 2015				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)		Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	232	$	63	Market approach	CRR auction prices	$	(15.97) - 8.17	$	259	$	63	Market approach	CRR auction prices	$	(161.36) - 8.76
Power purchase agreements	$	-	$	100	Discounted cash flow	Forward prices	$	16.04 - 56.21	$	-	$	107	Discounted cash flow	Forward prices	$	15.08 - 37.27

(1) Represents price per megawatt-hour

Level 3 Reconciliation

The following tables present the reconciliation for Level 3 price risk management instruments for the three ~~and nine~~ months ended ~~September 30, 2015~~March 31, 2016 and ~~2014:~~2015:

	Price Risk Management Instruments				Price Risk Management Instruments
(in millions)	2015		2014		2016		2015
Asset (liability) balance as of July 1	$	48	$	(11)
Asset (liability) balance as of January 1					$	89	$	69
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(27)		(9)		(14)		(27)
Asset (liability) balance as of September 30	$	21	$	(20)
Asset (liability) balance as of March 31					$	75	$	42

(1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.

Price Risk Management Instruments
(in millions)
2015

2014
Asset (liability) balance as of January 1
$
69

$
(30)
Net realized and unrealized gains:

Included in regulatory assets and liabilities or balancing accounts (1)

(48)

10
Asset (liability) balance as of September 30
$
21

$
(20)

~~(1)~~ The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.

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, ~~floating rate senior notes,~~ and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at ~~September 30, 2015~~March 31,2016 and December 31, ~~2014,~~2015, as they are short-term in nature or have interest rates that reset daily.

The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at ~~September 30, 2015~~March 31,2016 and December 31, ~~2014.~~2015.

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

	At September 30, 2015				At December 31, 2014				At March 31, 2016				At December 31, 2015
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
PG&E Corporation	$	350	$	354	$	350	$	352	$	350	$	356	$	350	$	354
Utility		14,273		15,858		13,778		15,851		15,412		17,823		14,918		16,422

Available for Sale Investments

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

				Total		Total						Total		Total
	Amortized			Unrealized		Unrealized		Total Fair	Amortized			Unrealized		Unrealized		Total Fair
(in millions)	Cost			Gains		Losses		Value	Cost			Gains		Losses		Value
As of September 30, 2015
As of March 31, 2016
Nuclear decommissioning trusts
Money market investments	$	21	$	-	$	-	$	21
Short-term investments									$	25	$	-	$	-	$	25
Global equity securities		510		963		(16)		1,457		603		1,038		(9)		1,632
Fixed-income securities		1,168		70		(5)		1,233		1,113		81		(4)		1,190
Total (1)	$	1,699	$	1,033	$	(21)	$	2,711	$	1,741	$	1,119	$	(13)	$	2,847
As of December 31, 2014
As of December 31, 2015
Nuclear decommissioning trusts
Money market investments	$	17	$	-	$	-	$	17
Short-term investments									$	36	$	-	$	-	$	36
Global equity securities		520		1,087		(9)		1,598		508		1,034		(9)		1,533
Fixed-income securities		1,059		75		(4)		1,130		1,165		58		(8)		1,215
Total nuclear decommissioning trusts (1)		1,596		1,162		(13)		2,745
Other investments		5		28		-		33
Total	$	1,601	$	1,190	$	(13)	$	2,778
Total (1)									$	1,709	$	1,092	$	(17)	$	2,784

(1) Represents amounts before deducting ~~$294~~$331 million and ~~$324~~$314 million at ~~September 30, 2015~~March 31,2016 and December 31, ~~2014,~~2015, respectively, primarily related to deferred taxes on appreciation of investment value.

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

	As of
(in millions)	~~September 30, 2015~~March 31, 2016
Less than 1 year	$	2126
1–5 years		~~465~~409
5–10 years		~~290~~251
More than 10 years		~~457~~504
Total maturities of ~~debt~~fixed-income securities	$	~~1,233~~1,190

The following table provides a summary of activity for the ~~debt and equity securities:~~investments:

Three Months Ended

Nine Months Ended

September 30,

September 30,

2015

2014

2015

2014
(in millions)

Proceeds from sales and maturities of nuclear decommissioning

trust investments
$
244

$
182

$
1,023

$
1,059
Gross realized gains on securities held as available-for-sale

3

30

50

114
Gross realized losses on securities held as available-for-sale

(12)

-

(25)

(3)

	Three Months Ended
	March 31, 2016		March 31, 2015
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments	$	439		417
Gross realized gains on sales of securities held as available-for-sale		5		35
Gross realized losses on sales of securities held as available-for-sale		(2)		(3)

NOTE 9: CONTINGENCIES AND COMMITMENTS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. 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

~~Improper CPUC Communications~~Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

~~In September~~During 2014 and 2015, the Utility ~~notified~~filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte communications ~~between~~that either should not have been made or that should have been timely reported to the ~~Utility and the CPUC regarding the 2015 GT&S rate case.~~CPUC. Ex parte communications include ~~any communication~~communications between a decision maker or a Commissioner’s advisor and an interested ~~person~~persons concerning substantive issues in certain ~~identified categories~~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 ~~formal proceedings~~the CPUC’s Rules of Practice and Procedure governing the conduct of those appearing before the CPUC. ~~In November~~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 ~~imposed a fine~~investigations related to the Utility’s natural gas transmission pipeline operations and practices.

On April 18, 2016, the Cities of ~~$1.05 million on~~San Bruno and San Carlos, ORA, the SED, TURN, and the Utility filed a joint Meet and Confer Process Report in advance of the prehearing conference that was held on April 20, 2016. The report included the proposed scope of the proceeding, including the number of communications at issue, a procedure for ~~these communications. In addition,~~moving undisputed facts into the ~~CPUC may disallow the Utility from recovering up~~evidentiary record, a diligence process for providing additional factual information, and a procedural schedule. Subject to the ~~entire amount~~CPUC’s approval, the parties have agreed that the scope of ~~the revenue increase that~~this proceeding may ~~be authorized~~include a total of 159 communications (the 46 communications already included in the ~~pending GT&S rate case~~OII and ~~that otherwise would have been collected from ratepayers over~~113 additional communications). The parties also recommended briefing on whether an additional 21 communications should be included in the proceeding. The Utility is expecting a ~~five-month period.~~ ruling on these proposals in the second quarter of 2016.

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 ~~disallowance when it issues its decision to authorize the Utility’s GT&S revenue requirements, which is expected to be issued~~discretion in ~~2016.~~determining penalties.

~~In October~~PG&E Corporation and ~~December 2014,~~ the Utility also notified the CPUC of additional email communications between the Utility and the CPUC regarding various matters (not limited to the GT&S rate case) that the Utility believes may constitute or describe ex parte communications. The Utility also notified the CPUC of an additional potential ex parte communication made in the 2011 General Rate Case to supplement a notification that the Utility voluntarily provided on October 6, 2014. Additionally, on May 21, 2015, the Utility filed various documents (including copies of internal email correspondence) with the CPUC to complete its response to orders issued by CPUC administrative law judges regarding potential ex parte communications between the Utility and CPUC personnel. For these additional communications, the Utility believesbelieve it is probable that the CPUC ~~enforcement action~~ will ~~be taken. The~~impose penalties on the Utility isin the OII but they are unable to reasonably estimate the amount or range of future charges that could be incurred, ~~given~~because it is uncertain how the ~~CPUC’s wide discretion and~~CPUC will calculate the number of ~~factors that can be considered in determining~~violations or the ~~final penalties.~~

~~In the Penalty Decision (further described below),~~penalty for any violations, and whether the CPUC ~~stated that it~~ will ~~begin~~consider additional communications in the OII, including those identified in a ~~new investigation to examine allegations~~motion filed on December 1, 2015, by the City of San Bruno in the 2015 GT&S rate case. It is also uncertain whether the CPUC will take additional action in any of the proceedings in which the Utility has self-reported communications that ~~communications between the Utility’s employees and CPUC personnel~~may have violated the CPUC’s ~~rules relating to~~ ex parte communications. The Utility believes that the communications cited by San Bruno are not prohibited ex parte communications. If the CPUC determines that the communications constitute ex parte violations, it is reasonably possible that the CPUC will impose penalties or other remedies, but the Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining the final penalties.rules.

~~The~~Finally, the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office also have ~~also begun investigations in connection with~~been investigating matters related to allegedly improper communication between the ~~ex parte communications.~~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 requires 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 cites 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, for which the CPUC has previously imposed a penalty of $10.85 million.~~2014.

On September 30, 2015, the SED submitted its supplemental testimony, which included incidents allegedly related to record-keeping that had not been identified in the initial order, and also asserted violations related to the Utility’s pre-excavation location and marking practices, causal evaluation practices, and compliance with regulations governing pressure validation for certain distribution facilities. Testimony from intervenors was submitted in October 2015. The Utility’s response is due on November 12, 2015, followed by rebuttal testimony in December 2015. Hearings are scheduled for January 2016.

On February 26, 2016, the Utility, the SED, TURN, and the City of Carmel, California(“Carmel”) filed their opening briefs. In its brief, the SED cited alleged record-keeping violations related to various natural gas distribution incidents, the Utility’s pre-excavation location and marking practices, causal evaluation practices, and compliance with regulations governing pressure validation for certain distribution facilities. The SED recommended that the CPUC ~~can~~impose a fine on the Utility of approximately $112 million for these alleged violations. The SED also recommended that the CPUC require the Utility to undertake various remedial actions with respect to its gas distribution system records and facilities and that the Utility be prohibited from recovering remedial-related costs from customers. Carmel recommended that the CPUC impose penalties on the Utility of up to ~~$50,000 per day, per violation,~~approximately $652 million, including approximately $137 million for ~~violations~~the natural gas explosion that occurred ~~after January~~in Carmel on March 3, 2014 (for which the Utility has previously paid a CPUC-imposed fine of $10.85 million). Carmel also recommended various remedial measures. TURN recommended that the Utility be required to undertake remedial actions, fund annual SED audits of the Utility’s record-keeping practices for a period of ten years, and promptly correct any deficiencies identified in those audits.

On April 1, ~~2012. (The statutory maximum~~2016, the Utility filed its reply brief in which the Utility indicated that it did not agree that any penalty was appropriate, but if the CPUC determined that a penalty should be imposed, such penalty should not exceed $33.6 million. The Utility recommended that such penalty, if imposed, should be invested in the safety of the Utility’s gas distribution system, for ~~violations~~example for implementation of certain remedial measures. The Utility expects that ~~occurred before January~~the presiding officer’s decision will be issued within 60 days of the April 1, ~~2012 is $20,000 per violation.)~~2016 filing. Unless any party files an appeal of the presiding officer’s decision or a CPUC Commissioner requests a CPUC review of the presiding officer’s decision within 30 days, the decision will become final. The CPUC has ~~wide discretion~~the authority to ~~determine~~extend the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The 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 wide discretion in determining penalties.deadlines indicated above.

PG&E Corporation and the Utility believe it is ~~reasonably possible~~probable that the CPUC will impose penalties on the Utility in the form of fines or ~~that the Utility will incur~~other remedies, including possible future unrecoverable costs to implement operational remedies. Remedies would be recorded in the period the expense is incurred and fines would be recorded when considered probable and their amount or range can be reasonably estimated. The Utility is unable to determine the form or amount of penalties or reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s ~~wide~~ discretion ~~(discussed above)~~in imposing fines and ~~the number of factors that can be considered in determining penalties and given the fact that the extent of any alleged violations is currently unknown.~~other remedies.

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 ~~has~~had been completed and that remediation work, including removal of the encroachments, iswas 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 ~~or take other enforcement action~~ 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. ~~Although the~~The SED can consider the discretionary factors discussed above (see ~~“CPUC~~“Order Instituting an Investigation ~~Regarding Natural Gas Distribution Facilities Record-Keeping”~~into Compliance with Ex Parte Communication Rules” above) in determining the number of violations and whether to impose daily fines ~~the~~for continuing violations. The SED is required, however, to impose the maximum statutory penalty of $50,000 for each separate ~~violation and has the discretion to impose daily fines for continuing violations.~~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 ~~succeeded~~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. Although the trial previously had been scheduled to begin on April 26, 2016, the court vacated the trial date and no new trial date has been set. The court stated that it will set a new trial date in due course.

The maximum statutory fine for each felony count is $500,000, for total potential fines of ~~$14~~$6.5 million. The ~~superseding indictment~~government is also ~~seeks an alternative fine~~seeking fines under the Alternative Fines Act. The Alternative Fines Act ~~which~~ 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 ~~allegations~~allegation that the Utility derived gross gains of approximately $281 million, ~~and that~~ the ~~victims suffered losses of approximately $565 million, the~~potential maximum alternative fine would be approximately ~~$1.13 billion. The~~$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 ~~is scheduled to begin March 8, 2016.~~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. The Utility has filed several motions requesting that the court dismiss many of the counts based on various legal arguments. The court has heard oral argument on all the motions and the Utility is waiting for the court’s decisions. PG&E Corporation and the Utility have not accrued any charges for criminal fines in their Condensed Consolidated Financial Statements as such amounts are not considered to be probable.

Other Federal Matters

The Utility was informed that the U.S. Attorney’s Office was investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. ~~(For more information refer to Note 14 of the Notes to the Consolidated Financial Statements appearing under Item 8 in the 2014 Form 10-K).~~ The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case discussed above. It is uncertain whether any additional charges will be brought against the Utility.

Capital Expenditures Relating to Pipeline Safety Enhancement Plan

~~At September 30, 2015, approximately $657~~The CPUC has authorized the Utility to collect $766 million for recovery of PSEP capital costs. As of March 31, 2016, the Utility has spent $1.3 billion on PSEP-related capital costs, ~~is recorded~~of which $665 million was written off in ~~property, plant, and equipment on~~previous years for costs that are expected to exceed the ~~Condensed Consolidated Balance Sheets.~~authorized amount. The Utility expects the remaining PSEP work to continue beyond 2016. The Utility would be required to record charges ~~to the statement of income~~ in future periods to the extent ~~total forecasted~~ PSEP-related capital costs are higher than currently expected.

Penalty ~~Decision Related to the CPUC’s Investigative Enforcement Proceedings Related to~~Decision’s Disallowance of Natural Gas ~~Transmission~~Capital Spend

~~The Penalty Decision (see Note 1 above) imposes~~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 ~~totaling $1.6 billion comprised of:~~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, ~~to be paid to the State General Fund,~~ (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. In August 2015, the Utility paid the $300 million fine. At September 30, 2015, the Condensed Consolidated Balance Sheets include $400 million in current regulatory liabilities for the one-time bill credit that will be provided to the Utility’s natural gas customers in 2016.

The Penalty Decision requires that at least $689 million of the $850 million disallowance be allocated to capital expenditures, and that the Utility be precluded from including these capital costs in rate base. The CPUC will determine which safety projects and programs will be funded by shareholders in the Utility’s pending 2015 GT&S rate case. If the $850 million is not exhausted by designated safety-related projects and programs in the GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the full $850 million is spent. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify safety-related projects and programs that will be subject to the disallowance. It is uncertain how the CPUC will identify the costs that are counted toward the $850 million shareholder-funded obligation. If the Utility’s actual costs exceed costs that the CPUC counts towards the $850 million maximum, the Utility would record additional charges if such costs are not otherwise authorized by the CPUC. As a result, the total shareholder-funded obligation could exceed $850 million.

For the three months ~~and nine months~~ ended ~~September 30, 2015,~~March 31, 2016, the Utility recorded additional charges in operating and maintenance expenses in the Condensed Consolidated Statements of Income of ~~$142~~$87 million, ~~and $770 million, respectively,~~ as a result of the Penalty Decision. The cumulative charges at ~~September 30, 2015,~~March 31, 2016, and the additional future charges to reach the $1.6 billion total are shown in the following table:


	Nine Months		Cumulative		Future				Three Months		Cumulative		Future
	Ended		Charges		Charges		Total		Ended		Charges		Charges
		September 30,		September 30,	and					March 31,		March 31,	and		Total
(in millions)	2015		2015		Costs		Amount		2016		2016		Costs		Amount
Fine payable to the state (1)	$	100	$	300	$	-	$	300
Fine paid to the state									$	-	$	300	$	-	$	300
Customer bill credit		400		400		-		400		-		400		-		400
Charge for disallowed capital ~~(2)~~(1)		270		270		419		689		87		494		195		689
Disallowed revenue for pipeline safety
expenses ~~(3)~~(2)		-		-		161		161		-		-		161		161
CPUC estimated cost of other remedies ~~(4)~~(3)		-		20		30		50		-		-		-		50
Total Penalty Decision fines and remedies	$	770	$	990	$	610	$	1,600	$	87	$	1,194	$	356	$	1,600

(1)~~In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million.~~

~~(2)~~The Penalty Decision ~~prohibits~~disallows the Utility from ~~recovering certain expenses and capital spending~~recovering$850 million in costs associated with pipeline safety-related projects and programs that the CPUC will identify in ~~the~~a final decision to be issued in the Utility’s 2015 GT&S rate case. The Penalty Decision requires that at least $689 million of the $850 million cost disallowance be allocated to capital expenditures. The Utility estimates that approximately ~~$142 million and $270~~$494 million of cumulative capital spending ~~(which include less than $1 million for remedy related capital costs)in the three months and nine months ended September 30, 2015, respectively, are~~is probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision.

~~(3)~~(2)These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.

~~(4)~~(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 ~~including approximately $30 million for the cost of future audits to be conducted by the SED. The amounts shown in the table above represent these estimated amounts~~ and dodoes not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred.

Other Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. 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 ~~Utility has submitted testimony in its 2017 GRC request~~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 ~~remove additionalremedy-related~~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 ~~of approximately $61 million. The Utility could incur remedy-related~~from the provision for loss and expense these costs ~~that are higher than current estimates.~~as incurred.

~~Other Legal~~Investigation of the Butte Fire

On April 28, 2016, Cal Fire released its report of the investigation of the origin and ~~Regulatory Contingencies~~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.

In connection with the Butte fire, approximately 32 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 1,300 individual plaintiffs and their insurance companies. In response to plaintiffs’ and the Utility’s requests, the California Judicial Council has authorized the coordination of all cases in the Superior Court of California, Sacramento County. 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 number of complaints may increase in the future. An initial case management conference was held on April 22, 2016 and the next case management conference is currently scheduled for May 24, 2016.

In connection with this matter, the Utility may be liable for property damages without having been found negligent, through the theory of inverse condemnation. In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent.

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 estimated 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 range. At March 31, 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 this amount, 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.

The Utility has insurance coverage for third party claims. 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.

As a result of the Cal Fire report, additional investigations and proceedings may be opened, the outcome of which PG&E Corporation and the Utility are unable to predict.

Rehearing of CPUC Decisions Approving 2006 – 2008 Energy Efficiency Incentive Awards

On September 17, 2015, the CPUC ~~issued an order granting~~granted TURN’s and ~~the~~ ORA’s long-standing applications for rehearing of the CPUC decisions that awarded energy efficiency incentive payments to the California ~~investor-owned utilities~~IOUs for the 2006-2008 energy efficiency program cycle. Under the incentive ratemaking mechanism applicable to the 2006-2008 program cycle, the ~~maximum amount of incentives that the~~ Utility could have earned ~~(or~~incentive revenues up to a maximum of $180 million, depending on the ~~maximum amount that~~extent to which the Utility achieved the energy savings targets. Conversely, to the extent the Utility failed to achieve the targets, the Utility could have been required to ~~reimburse customers) over the 2006-2008 program cycle was~~offset future incentive earnings claims by amounts previously awarded, and, in addition, could have incurred penalties of up to $180 million. The Utility was awarded a total of $104 million for the 2006-2008 program cycle. In the re-opened ~~energy efficiency~~ proceeding, the CPUC will evaluate whether ~~incentives~~the incentive amounts awarded to the ~~California investor-owned utilities~~IOUs were just and reasonable, and whether any refunds are due.

On March 18, 2016, TURN and ORA submitted a joint proposal to require a refund of incentive awards that TURN and ORA argue were not calculated in accordance with the ratemaking mechanism rules and procedures the CPUC had previously adopted. TURN and ORA contended that the CPUC should order the Utility to refund $104 million, the entire incentive earnings award, plus interest, to customers as either (1) a revenue credit to customers’ distribution and gas transportation accounts or (2) as a line item to the customers’ first monthly bill following the issuance of a CPUC decision.

Additionally, on March 18, 2016, the IOUs submitted their proposals requesting that the CPUC reaffirm its prior decisions. The IOUs asserted that, given the many unresolved disputes about the data in the Energy Division’s 2010 Evaluation Report, the CPUC appropriately used different data to calculate the awards. The IOUs noted that under the incentive ratemaking mechanism, any refunds of prior incentive earnings should be deducted from future incentive earnings claims.

On April 8, 2016, the IOUs, TURN and ORA filed comments on the proposals, in which the parties reiterated their requests. The Utility currently expects that evidentiary hearings, if ordered by the CPUC, would be held in July 2016. It is uncertain how the CPUC will resolve this matter and when the CPUC will issue a ~~decision and whether the Utility will be required to refund amounts or incur other obligations related to the 2006-2008 program cycle.~~ decision.

~~Investigation of the Butte Fire~~

In September 2015, a wildfire (known as the “Butte Fire”) ignited and spread in Amador and Calaveras Counties in Northern California. The California Department of Forestry and Fire Protection (“Cal Fire”) is investigating the source of the fire including whether a live tree may have contacted apower line owned and operated by If the Utility ~~in the vicinity of the ignition point. The Utility also is conducting an investigation. Cal Fire has reported that~~were required to make a refund as ~~a result of the fire there were two deaths~~TURN and ~~965 structures, including 571 houses, were damaged or destroyed.~~

Although the cause of the fire has not yet been determined, PG&E Corporation and the Utility believe that it is reasonably possible that the Utility will incur a material amount of losses associated with third-party claims for property damage, fire suppression costs, personal injury, or other claims. PG&E Corporation and the Utility are unable to reasonably estimate the amount of possible losses (or range of amounts) given the preliminary stages of the investigation into the cause of the fire and uncertainty about the extent and value of real and personal property damaged by the fire which spread over 70,000 acres much of which is remote and rugged terrain. The Utility has insurance coverage for these types of claims. If the amount of insurance is insufficient to cover the Utility's liability resulting from the Butte fire, or if insurance is otherwise unavailable,ORA propose, PG&E Corporation’s and the Utility’s financial ~~condition~~results would be affected by the amount of any refund-related charges.

Residential Rate Reform Rate Change

On February 17, 2016, the Utility filed a proposed rate change for rates to be billed to customers effective March 1, 2016. On February 29, 2016, the CPUC rejected the Utility’s proposed rate change, stating that the rate design failed to comply with the requirements adopted in the Decision on Residential Rate Reform issued on July 3, 2015, that set a specific rate change “glidepath” for the Utility. The Utility began billing customers based on its proposed rates on March 1, 2016. On March 9, 2016, the assigned ALJ issued a ruling directing the Utility to show cause why the CPUC should not order sanctions and other remedies in response to the Utility charging rates not authorized by the CPUC. On March 14, 2016, the assigned ALJ issued an additional ruling that (1) acknowledged that utilities might not be able to follow the exact “glidepath” set forth in the decision because it had been based on forecast data and (2) indicated a new process to be followed before the CPUC if the new rates do not exactly match the “glidepath.” On March 24, 2016, the Utility temporarily reverted back to billing customers based on rates generally similar to those in place prior to March 1, 2016. Also, on March 24, 2016, the Utility filed an additional advice letter proposing a new, three-tiered rate structure. The proposed new rate structure is subject to the CPUC approval. On April 20, 2016, the Energy Division of the CPUC issued a draft resolution that approves the Utility’s proposed solution, but does not address the ruling to show cause. The Utility believes it is reasonably possible it may be subject to penalties or ~~results~~shareholder reparations for charging rates not authorized by the CPUC between March 1, 2016 and March 24, 2016. The Utility is unable to determine the form or amount of ~~operations~~penalties or reasonably estimate the amount or range of future charges that could be ~~materially affected.~~

incurred.

Other Contingencies

Accruals for other legal and regulatory contingencies (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters” and “Other Legal and Regulatory Contingencies”) totaled ~~$61~~$55 million at ~~September 30, 2015,~~March 31, 2016 and ~~$55~~$63 million at December 31, ~~2014.~~2015. These amounts are included in other current liabilities in the Condensed Consolidated Balance Sheets. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

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				Balance at
	September 30,		December 31,		March 31,		December 31,
(in millions)	2015		2014		2016		2015
Topock natural gas compressor station (1)	$	296	$	291	$	302	$	300
Hinkley natural gas compressor station (1)		136		158		140		140
Former manufactured gas plant sites owned by the Utility or third parties		267		257		283		271
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		153		150		136		164
Fossil fuel-fired generation facilities and sites		94		98		103		94
Total environmental remediation liability	$	946	$	954	$	964	$	969

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

At ~~September 30, 2015,~~March 31,2016, the Utility expected to recover ~~$678~~$680 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~~Utility’s remediation and abatement efforts at the Hinkley site are ~~overseen by~~subject to the regulatory authority of the Regional Board. On ~~October 16,~~November 4, 2015, the Regional Board ~~issued~~adopted a ~~revised draft~~final clean-up and abatement order ~~updating previous versions~~to contain and remediate the underground plume of hexavalent chromium and the ~~draft~~potential environmental impacts. The final order ~~released in September 2015 and January 2015. The updated draft order proposes~~states that the Utility must continue and improve its remediation ~~efforts; defines~~efforts, define the boundaries of the chromium plume, and take other action. ~~The draft~~Additionally, the final order ~~also proposes to set~~requires setting plume capture requirements, ~~proposes~~requires establishing a monitoring and reporting program, and finalizes deadlines for the Utility to meet interim cleanup targets, and proposes to establish a monitoring and reporting program. After a public comment period, the Regional Board is expected to consider adoption of a final clean-up and abatement order at its November 2015 meeting.targets.

The Utility’s environmental remediation liability at ~~September 30, 2015 reflects~~March 31,2016reflects the Utility’s best estimate of probable future costs associated with ~~the continuation of interim~~its final remediation ~~measures and the anticipated final clean-up and abatement order.~~plan. Future costs will depend on many factors, including the ~~levels~~extent of ~~hexavalent chromium~~work to be performed to implement the ~~Utility is required to use as~~final remediation plan and the ~~standard for remediation, the~~Utility’s required time ~~period by which those standards must be met, and the nature and extent of the chromium contamination.~~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 ~~results of operations,~~ and cash flows.

Topock Site

The ~~Utility's~~Utility’s remediation and abatement efforts at the Topock site are ~~overseen by~~subject to the ~~DTSC~~regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior. While the Utility has been working with these agencies to develop a final remediation plan, the Utility has been employing various interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of the chromium plume toward the Colorado River. In ~~September 2014,~~November 2015, the Utility submitted its ~~near-final~~final remediation ~~plan~~design to the agencies for approval. The Utility’s ~~plan~~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 ~~plan,~~design, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in July 2016. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in December 2016. After the Utility modifies its ~~plan~~design in response to the final report, the Utility plans to seek approval to begin construction of the new in-situ treatment system in early 2017.

The ~~Utility's~~Utility’s environmental remediation liability at ~~September 30, 2015 reflects~~March 31, 2016reflects its best estimate of probable future costs associated with its ~~anticipated~~ final remediation plan. Future costs will depend on many factors, including the ~~scope~~extent of work to be performed to implement the final groundwater remedy and ~~timing of~~the Utility’s required ~~remediation work.~~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 ~~$1.8 billion~~$1.9billion (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, as of April 1, 2016, 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, as of April 1, 2016. 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.

At December 31, ~~2014,~~2015, the Consolidated Balance Sheets reflected ~~$434~~$454 million in net claims, within Disputed claims and customer refunds, and ~~$291~~$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 ~~nine~~three months ended ~~September 30, 2015.~~March 31, 2016. However, on April 14, 2016, PG&E filed a Joint Offer of Settlement with the FERC requesting approval of a $256 million settlement agreement which, if approved, would result in a reduction to PG&E’s net disputed claims liability.

Tax Matters

~~The IRS is currently auditing several items in the 2011 to 2014 tax returns. The most significant relates to a 2011 accounting method change to adopt guidance issued by the IRS in determining~~ which repair costs are deductible for the electric transmission and distribution businesses. PG&E Corporation and the Utility expect that the IRS will complete its audit of the 2011 and 2012 deductible repair costs for the electric transmission and distribution businesses in 2015. The IRS also is expected to issue guidance in late 2015 or 2016 that clarifies which repair costs are deductible for the natural gas transmission and distribution businesses. PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months ~~depending on the IRS guidance that is issued and~~due to the resolution of ~~the outstanding audits related to the 2011 and 2012 tax returns.~~several matters, including audits. As ~~of September 30, 2015,~~ofMarch 31,2016, it is reasonably possible that unrecognized tax benefits will decrease by approximately ~~$380~~$70 million within the next 12 ~~months most~~months. PG&E Corporation and the Utility believe that the majority of ~~which would~~the decrease will not impact net income.

There were no other significant developments to tax matters during the nine months ended September 30,2015. (Refer to Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of the 2014 Form 10-K.)

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, ~~2014~~2015 the Utility hadundiscounted future expected obligations of approximately ~~$53.3~~$50 billion. (See Note 1413 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2014~~2015 Form 10-K.) ~~During~~The Utility has not entered into any new material commitments during the ~~nine~~three months ended September 30, 2015, the Utility entered into several renewable energy and other power purchase agreements that were approved by the CPUC and completed major milestones with respect to construction, resulting in additional commitments of approximately $780 million over the next 25 years.

March 31, 2016.

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

RESULTS OF OPERATIONS

OVERVIEW

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 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 also is subject to the jurisdiction of other federal, state, and local governmental agencies.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report. It should also be read in conjunction with the ~~2014~~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. PG&E Corporation uses earnings from operations to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating plans, and employee incentive compensation. PG&E Corporation believes that earnings from operations provide additional insight into the underlying trends of the business allowing for a better comparison against historical results and expectations for future performance. Earnings from operations are not a substitute or alternative for GAAP measures such as income available for common shareholders and may not be comparable to similarly titled measures used by other companies.

Three Months Ended

Nine Months Ended

September 30,

September 30,

EPS

EPS
(in millions, except per share amounts)
Earnings

(Diluted)

Earnings

(Diluted)
Income Available for Common Shareholders - 2014
$
811

$
1.71

$
1,305

$
2.79
Natural gas matters (1)

13

0.03

94

0.20
Environmental-related costs (2)

(4)

(0.01)

(4)

(0.01)
Earnings from Operations - 2014 (3)
$
820

$
1.73

$
1,395

$
2.98
Growth in rate base earnings

26

0.05

79

0.16
Nuclear refueling outage

-

-

26

0.05
2014 GRC cost recovery (4)

(228)

(0.47)

-

-
Timing of 2015 GT&S cost recovery (5)

(78)

(0.16)

(159)

(0.33)
Regulatory and legal matters (6)

(24)

(0.05)

(18)

(0.04)
Gain on disposition of SolarCity stock (7)

(14)

(0.03)

(13)

(0.03)
Timing of taxes (8)

(45)

(0.09)

(7)

(0.01)
Increase in shares outstanding

-

(0.05)

-

(0.10)
Miscellaneous

(45)

(0.09)

(31)

(0.05)
Earnings from Operations - 2015 (3)
$
412

$
0.84

$
1,272

$
2.63
Insurance recoveries (9)

6

0.01

29

0.06
Fines and penalties (10)

(84)

(0.16)

(497)

(1.03)
Pipeline-related expenses (11)

(19)

(0.04)

(38)

(0.08)
Legal and regulatory related expenses (11)

(8)

(0.02)

(26)

(0.05)
Income Available for Common Shareholders - 2015
$
307

$
0.63

$
740

$
1.53

	Three Months Ended
	March 31,
			EPS
(in millions, except per share amounts)	Earnings		(Diluted)
Income Available for Common Shareholders - March 31, 2015	$	31	$	0.06
Fines and penalties (1)		369		0.77
Pipeline-related expenses (2)		10		0.02
Legal and regulatory related expenses (2)		8		0.02
Earnings from Operations -March 31, 2015 (3)	$	418	$	0.87
Growth in rate base earnings		26		0.05
Timing of taxes (4)		(40)		(0.08)
Gain on disposition of SolarCity stock (5)		(14)		(0.03)
Increase in shares outstanding		-		(0.03)
Miscellaneous		17		0.04
Earnings from Operations - March 31, 2016 (3)	$	407	$	0.82
Butte fire related expenses (6)		(226)		(0.45)
Fines and penalties (1)		(51)		(0.10)
Pipeline-related expenses (2)		(13)		(0.03)
Legal and regulatory related expenses (2)		(10)		(0.02)
Income Available for Common Shareholders - March 31, 2016	$	107	$	0.22

(1) ~~In 2014, natural gas matters included pipeline-related costs to perform work under~~Represents the ~~PSEP and other activities associated with safety improvements~~impact of the Penalty Decision (see Note 9 of the Notes to the Utility’s natural gas system, as well as legal and other costs related to natural gas matters. Natural gas matters also included charges recorded related to fines, third party liability claims, and insurance recoveries in 2014.Condensed Consolidated Financial Statements for before-tax amounts).

(2) ~~The Utility reduced its accrual~~Represents pipeline-related expenses, including costs incurred to identify and remove encroachments from transmission pipeline rights of way and to perform remaining work under the Utility’s PSEP which only occurred in 2015. Legal and regulatory related ~~to the Hinkley whole house water program in the third quarter of 2014.~~expenses include various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

(3) “Earnings from operations” is not calculated in accordance with GAAP and excludes the items impacting comparability shown in Notes (1) and (2) ~~above and Notes (9), (10), and (11) below.~~.

(4)Represents the increase in base revenues authorized by the CPUC in the 2014 GRC decision, as well as the impact of flow-through ratemaking treatment for federal tax deductions for repairs, for the first two quarters of 2014. In 2014, the increase in base revenue and the impact of flow-through repairs deductions was not recognized until the quarter ended September 30, 2014, when the 2014 GRC decision was issued. Alsoincludes 2014 GRC related items included in Miscellaneous in previous quarters.

~~(5)~~Represents expenses during the three and nine months ended September 30, 2015 as compared to the same periods in 2014, with no corresponding increase in revenue. The Utility has requested the CPUC to authorize an increase to its revenue requirements for 2015, 2016, and 2017 in its 2015 GT&S rate case. Based on the procedural schedule, it is unlikely that the Utility will be able to recognize a revenue increase from a final 2015 GT&S rate case decision until 2016.

~~(6)Primarily reflects incentive awards received in 2014. Also includes legal costs included in Miscellaneous in previous quarters.~~

~~(7)Represents the gain recognized during the three months ended September 30, 2014 as compared to the three months ended September 30, 2015 during which no comparable gain was recognized.~~

~~(8)~~Represents the timing of taxes reportable in quarterly financial statements.

~~(9)~~(5)Represents ~~insurance recoveries~~the gain recognized during the three months ended March 31, 2015. No comparable gain was recognized in 2016.

(6)For the three months ended March 31, 2016, the Utility incurred charges of ~~$10~~$350 million, pre-tax, related to estimated property damages in connection with the Butte fire and ~~$49~~$31 million, pre-tax, for ~~third party claims~~Utility clean-up, repair, and ~~associated~~ legal costs ~~related to~~associated with the ~~San Bruno accident the Utility received during the three and nine months ended September 30, 2015, respectively. The Utility has received~~Butte fire, for a ~~cumulative~~ total of ~~$515~~$381 million, ~~through insurance related to $558 million of third-party claims and $92 million of legal costs incurred. No further insurance recoveries related to these claims and costs are expected.~~pre-tax.

~~(10)Represents the impact of the Penalty Decision (see Note 9 of the Notes to the Condensed Consolidated Financial Statements for before-tax amounts).~~

~~(11)~~ In 2015, pipeline-related expenses include costs incurred to identify and remove encroachments from transmission pipeline rights of way and to perform remaining work under the Utility’s PSEP. Legal and regulatory related expenses include various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

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:

•	~~Penalties, Fines~~The Outcome of Enforcement, Litigation, and ~~Remedial Costs.~~Regulatory Matters. Future financial results will be impacted by the ~~timing and amount of disallowed costs the Utility incurs for designated~~unrecoverable pipeline safety-related ~~projects~~ and ~~programs and to implement remedial measures, as~~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~~Utility’s future results may also ~~could~~ be ~~required~~impacted by various other pending enforcement, litigation and regulatory actions, including but not limited to ~~pay fines associated with pending~~those related to the federal criminal ~~charges. Based on the superseding indictment’s allegations, the maximum statutory fine would be $14 million~~charges and the maximum alternative fine would be approximately $1.13 billion. The Utility also could be required to pay fines, or incur other unrecoverable costs, associated with the CPUC’s pending investigationCPUC investigations of the Utility’s compliance with natural gas distribution facilities record-keeping practices, ~~enforcement action that may be taken with respect to~~potential violations of the CPUC’s ex parte ~~communications or other improper communications between~~communication rules, the ~~Utility~~re-hearing of the 2006-2008 energy efficiency incentive awards, and the ~~CPUC, or other enforcement matters.~~Butte fire. (See “Enforcement and Litigation Matters” in Note 9 of the Notes to the Condensed Consolidated Financial ~~Statements.~~Statements in Item 1.)

•	The Timing and Outcome of Ratemaking Proceedings.~~In the~~ The 2015 GT&S rate case ~~the~~remains pending. The Utility ~~has~~ requested that the CPUC authorize ana $532 million increase in ~~the Utility’s~~annual revenue requirements for gas transmission and storage operations beginning on January 1, 2015 with ~~additional~~attrition increases in 2016 and 2017. Any revenue requirement increase that the CPUC may authorize would be retroactive to January 1, ~~2015. Based on the scoping ruling and procedural schedule that was issued on June 11,~~ 2015 the CPUC’s initial decision to authorize revenue requirements is not likely to be issued before December 31, 2015. If the Utility does not recognize any increase in 2015, the authorized revenue increasebut would be recorded in ~~2016.~~the period a final decision is reached. (See ~~“Ratemaking Proceedings−~~“Regulatory Matters − 2015 Gas Transmission and Storage Rate Case” below for more information.) In ~~September 2015,~~February 2016, the Utility ~~filed~~updated its 2017 GRC application to request that the CPUC authorize a revenue ~~requirements~~requirement increase of $333 million for 2017 for the Utility’s electric generation business and its electric and natural gas distribution ~~business for 2017 through~~businesses with attrition increases in 2018 and 2019. (See ~~“Ratemaking Proceedings−~~“Regulatory Matters − 2017 General Rate Case” below for more information.) ~~Also, the CPUC recently granted applications for rehearing of CPUC~~The CPUC’s decisions in these cases are expected to be issued in 2008, 2009, and 2010 that awarded a total of $104 million of incentive revenues to the Utility based on implementation of customer energy efficiency programs. It is uncertain whether the Utility would be required to refund any of the incentive revenues or incur other expense related to the final resolution of the re-opened proceedings. In addition, the Utility has one transmission owner rate case pending at the FERC (See “Ratemaking Proceedings – FERC TO Rate Cases” below).2016. The outcome of ~~ratemaking~~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. Whether the Utility is able to earn its authorized rate of return could be materially affected if the Utility’s actual costs differ from the amounts ~~that have been~~ authorized in the ~~final 2014 GRC decision and that may be authorized in the 2015 GT&S rate case and future~~ rate case decisions. In addition to incurring shareholder-funded costs and costs associated with remedial measures required by the Penalty Decision, the Utility also forecasts that in ~~2015~~2016 it will incur unrecovered pipeline-related expenses ranging from $100 million to ~~$125~~$150 million which primarily relate to costs to identify and remove encroachments from transmission pipeline rights-of-way. ~~Actual costs could be higher.~~ The ultimate amount of unrecovered ~~costsalso~~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 “Enforcement and Litigation Matters” ~~below.~~in 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 driven by legislative and regulatory initiatives relating to distributed generation resources, renewable energy requirements, and changes in the electric rate structure.

•	The Amount and Timing of the Utility’s Financing Needs. PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. For the ~~nine~~three months ended ~~September 30, 2015,~~March 31, 2016, PG&E Corporation issued ~~$689~~$152 million of common stock and ~~made~~used $65 million of the cash proceeds to make equity contributions to the ~~Utility of $605 million.~~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’s~~Utility to comply with the Penalty Decision, to fund unrecoverable pipeline-related expenses, ~~(including charges incurred under the Penalty Decision)~~ and to pay fines and penalties that may be required by the final outcomes of pending enforcement matters. These additional ~~equity~~ issuances would have a ~~further~~ material dilutive ~~effect~~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 “Enforcement and Litigation Matters” ~~below,~~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 ~~2014~~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~~management’s knowledge of facts as of the date of this report. See the section entitled “Cautionary Language Regarding 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.

RESULTS OF OPERATIONS

PG&E Corporation

The consolidated results of operations consist primarily of balances related to the Utility, which are discussed below. The following table provides a summary of net income available for common shareholders for the three ~~and nine~~ months ended ~~September 30, 2015~~March 31,2016 and ~~2014:~~2015:

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
(in millions)	2015		2014		2015		2014		2016		2015
Consolidated Total	$	307	$	811	$	740	$	1,305	$	107	$	31
PG&E Corporation		5		21		35		44		2		30
Utility	$	302��	$	790	$	705	$	1,261	$	105	$	1

PG&E Corporation’s net income primarily consists of interest expense on long-term debt, income taxes, and other income from investments. Results in 2015 include approximately $30 ~~million and $45~~ million of realized gains and associated tax benefits related to an investment in SolarCity Corporation ~~recognized~~with no corresponding gains in ~~the nine months ended September 30, 2015 and 2014, respectively.~~2016.

Utility

The ~~tables~~table below ~~show~~shows certain items from the Utility’s Condensed Consolidated Statements of Income for the ~~three~~threemonths ended March 31,2016 and ~~nine months ended September 30, 2015 and 2014.~~2015. The ~~tables~~table separately ~~identify~~identifies the revenues and costs that impacted earnings from those that did not impact earnings. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs), and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings. In addition, expenses that have been specifically ~~authorized (such~~authorized(such as the payment of pension costs) and the corresponding revenues the Utility is authorized to collect to recover such costs, do not impact earnings.

Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base. Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.

The Utility’s operating results for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015 reflect charges associated with the impact of the Penalty Decision. (See “Utility Revenues and Costs that Impacted Earnings” below.)

	Three Months Ended September 30, 2015						Three Months Ended September 30, 2014						Three Months Ended March 31, 2016						Three Months Ended March 31, 2015
	Revenues/Costs:						Revenues/Costs:						Revenues/Costs:						Revenues/Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	1,907	$	1,961	$	3,868	$	1,979	$	2,033	$	4,012	$	1,933	$	1,199	$	3,132	$	1,786	$	1,228	$	3,014
Natural gas operating revenues		516		166		682		643		284		927		523		320		843		506		380		886
Total operating revenues		2,423		2,127		4,550		2,622		2,317		4,939		2,456		1,519		3,975		2,292		1,608		3,900
Cost of electricity		-		1,681		1,681		-		1,782		1,782		-		950		950		-		1,000		1,000
Cost of natural gas		-		50		50		-		134		134		-		222		222		-		274		274
Operating and maintenance		1,226		396		1,622		892		401		1,293		1,664		347		2,011		1,589		334		1,923
Depreciation, amortization, and decommissioning		653		-		653		671		-		671		696		-		696		631		-		631
Total operating expenses		1,879		2,127		4,006		1,563		2,317		3,880		2,360		1,519		3,879		2,220		1,608		3,828
Operating income		544		-		544		1,059		-		1,059		96		-		96		72		-		72
Interest income (1)						2						1						4						1
Interest expense (1)						(191)						(171)						(201)						(187)
Other income, net (1)						22						19						24						26
Income before income taxes						377						908
Income tax provision (1)						72						115
Income (loss) before income taxes																		(77)						(88)
Income tax benefit (1)																		(185)						(92)
Net income						305						793						108						4
Preferred stock dividend requirement (1)						3						3						3						3
Income Available for Common Stock					$	302					$	790					$	105					$	1

(1) These items impacted earnings for the three months ~~ended September 30, 2015~~endedMarch 31,2016 and ~~2014.~~

Nine Months Ended September 30, 2015

Nine Months Ended September 30, 2014

Revenues/Costs:

Revenues/Costs:

(in millions)
That Impacted Earnings
That Did Not Impact Earnings
Total Utility

That Impacted Earnings
That Did Not Impact Earnings
Total Utility
Electric operating revenues
$
5,569
$
4,775
$
10,344

$
5,200
$
5,044
$
10,244
Natural gas operating revenues

1,547

775

2,322

1,569

967

2,536
Total operating revenues

7,116

5,550

12,666

6,769

6,011

12,780
Cost of electricity

-

3,958

3,958

-

4,341

4,341
Cost of natural gas

-

442

442

-

694

694
Operating and maintenance

3,878

1,150

5,028

2,935

976

3,911
Depreciation, amortization, and decommissioning

1,935

-

1,935

1,765

-

1,765
Total operating expenses

5,813

5,550

11,363

4,700

6,011

10,711
Operating income

1,303

-

1,303

2,069

-

2,069
Interest income (1)

6

6
Interest expense (1)

(567)

(535)
Other income, net (1)

68

56
Income before income taxes

810

1,596
Income tax provision (1)

95

325
Net income

715

1,271
Preferred stock dividend requirement (1)

10

10
Income Available for Common Stock

$
705

$
1,261

~~(1)~~ ~~These items impacted earnings for the nine months ended September 30, 2015 and 2014.~~2015.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for the ~~threeand nine~~three months ended ~~September 30,~~March 31,2016 and 2015, ~~and 2014,~~ focusing on revenues and expenses that impacted earnings for these periods.

Operating Revenues

The Utility’s electric and natural gas operating revenues that impacted earnings decreased by $199 million, or 8%,in the three months ended September 30, 2015, compared to the same period in 2014 primarily due to the timing of the 2014 GRC decision that was issued in August 2014. Revenue increases of approximately $305 million pertaining to the six months ended June 30, 2014 were not recognized until the third quarter of 2014. Additionally, operating revenues decreased in the three months ended September 30, 2015 due to the absence of approximately $35 million of revenues the CPUC authorized the Utility to collect for recovery of certain PSEP-related costs during the same period in 2014. These decreases were offset by an increase in base revenues of approximately $150 million as authorized by the CPUC in the 2014 GRC and by the FERC in the TO rate case.

The Utility’s electric and natural gas operating revenues that impacted earnings increased by ~~$347~~$164 million, or 5%7%,in the ~~ninemonths endedSeptember 30,2015,~~three months ended March 31, 2016, compared to the same period in ~~2014. The increase was~~ 2015 primarily ~~a result of approximately $410 million of~~due additional base revenues as authorized by the CPUC in the 2014 GRC decision and by the FERC in the TO rate case. This increase was partially offset by the absence of approximately $100 million of revenues the CPUC authorized the Utility to collect for recovery of certain PSEP-related costs during the same period in 2014.

~~Recovery of PSEP-related costs incurred during 2015 will depend upon the timing and outcome of the GT&S rate case.~~ The Utility has requested the CPUC authorize an increase to its revenue requirements for 2015, 2016, and 2017 in its GT&S rate case. ~~Based on the procedural schedule, it~~It is unlikely that the Utility will be able to recognize an increase in its GT&S revenue ~~before~~until the second half 2016 or a later period during which a final decision is issued. The CPUC’s decision in this case is expected to be issued in 2016. (See “Ratemaking Proceedings” below.)

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased by ~~$334million,~~$75million, or ~~37%~~5%,in the three months ended ~~September 30, 2015~~March 31, 2016 compared to the same period in ~~2014primarily~~2015 primarily due to ~~$142 millionin~~$381 million in charges related to the Butte Fire,approximately $90 million ofother operating expenses, $34 million of higher disallowed capital charges related to the Penalty Decision, and $30 million of higher benefit-related expenses. This increase was offset by $500 million in charges associated with the Penalty Decision ~~(see~~for fines and customer refunds incurred in the first quarter of 2015 with no corresponding charges in 2016. (See Note 9 of the Notes to the Condensed Consolidated Financial ~~Statements). Additionally, the Utility received $76 million fewer insurance recoveries during the three months ended September 30, 2015 compared to the same period in 2014.~~

The Utility’s operating and maintenance expenses that impacted earnings increased by $943 million, or 32%, in the nine months ended September 30,2015 compared to the same periods in 2014 primarily due to $770 million in charges associated with the Penalty Decision (see Note 9 of the Notes to the Condensed Consolidated Financial Statements). Additionally, the Utility received $37 million fewer insurance recoveriesfor third-party claims related to the San Bruno accident during the nine months ended September 30, 2015 compared to the same period in 2014. No further insurance recoveries related to these claims are expected. Statements.)

The Utility’s future financial statements will continue to be impacted by additional charges associated with the Penalty Decision, costs related to the Butte Fire, and unrecoverable pipeline-related expenses. (See “Key Factors Affecting Financial Results” above and Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses decreased by $18 million, or 3%, in the three months ended September 30, 2015 compared to the same period in 2014. This decrease primarily reflects the timing of the 2014 GRC decision that was issued in August 2014 and authorized the Utility to increase its depreciation rates. The decrease was partially offset by an increase in capital additions during the period.

The Utility’s depreciation, amortization, and decommissioning expenses increased by ~~$170~~$65 million, or 10%, in the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 compared to the same period in ~~2014, primarily due to an~~2015. This increase ~~in capital additions.~~

~~Interest Expense~~

~~The Utility’s interest expenses increased by $32 million in the nine months ended September 30, 2015 compared to the same period in 2014,~~was primarily due to the ~~issuance~~impact of ~~additional long-term debt.~~capital additions and higher depreciation rates as authorized by CPUC in the 2014 GRC decision, which was first reflected in the third quarter of 2014, and by the FERC in the TO rate case.

Interest Income, Interest Expense, and Other Income, Net

There were no material changes to interest income, interest expense, and other income, net for the periods presented.

Income Tax ~~Provision~~Benefit

The income tax ~~provision decreased~~benefit increased by ~~$43~~$93 million, or ~~37%~~ 101%in the three months ended ~~September 30, 2015~~March 31, 2016 as compared to the same period in ~~2014.~~2015. The effective tax rates for the three months ended ~~September 30,~~March 31, 2016 and 2015 were 241% and ~~2014 were 19% and 13%~~105%, respectively. ~~The decrease in the income~~These increases were primarily driven by benefits resulting from various tax ~~provision~~audit results in the three months ended ~~September 30,~~March 31, 2016 with no comparable amounts in the three months ended March 31, 2015 ~~is primarily due to lower pre-tax income resulting from the timing of the 2014 GRC decision (see “Operating Revenues” above)~~ and the tax impact of a non-deductible penalty accrued in the ~~Penalty Decision recorded in~~three months ended March 31, 2015 with no comparable amount ~~recorded for the same period in 2014. Under applicable accounting standards, charges resulting from the Penalty Decision are recorded at the statutory rate~~ in the ~~period incurred. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements).~~

~~The income tax provision decreased by $230 million, or 71%, in the nine~~three months ended September 30, 2015 as compared to the same period in 2014. The effective tax rates for the nine months ended September 30, 2015 and 2014 were 12% and 20%, respectively. The decrease in the income tax provision and effective tax rate in the nine months ended September 30, 2015 is primarily due to lower pre-tax income resulting from the impact of the Penalty Decision.

SB 681 was introduced in June 2015 and proposed that the Utility be denied applicable state tax deductions for expenditures associated with the Penalty Decision. In September 2015, members of the California State Senate voted on this legislation and it did not receive a sufficient number of votes to pass. The authors of SB 681 requested to have the bill reconsidered and may reintroduce it in the future for subsequent votes. (See “Item 1A. Risk Factors” in Part II below). March 31, 2016.

Utility Revenues and Costs that did not Impact Earnings

Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs. See below for more detail.

Cost of Electricity

TheUtility’s cost of electricity includes the costs of power purchased from third parties (including renewable energy resources), transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
(in millions)	2015		2014		2015		2014		2016		2015
Cost of purchased power	$	1,605	$	1,684	$	3,734	$	4,083	$	886	$	922
Fuel used in own generation facilities		76		98		224		258		64		78
Total cost of electricity	$	1,681	$	1,782	$	3,958	$	4,341	$	950	$	1,000
Average cost of purchased power per kWh(1)	$	0.111	$	0.114	$	0.105	$	0.101	$	0.104	$	0.099
Total purchased power (in millions of kWh) ~~(1)~~(2)		14,424		14,724		35,462		40,512		8,539		9,291

(1)Average cost of purchased power for the three months ended March 31, 2016 increased compared to the same period in 2015 primarily due to higher percentage of renewable energy resources. This increase was partially offset by lower market prices for natural gas.

(2) The decrease in purchased power resulted from an increase in generation from the Utility’s own generation facilities. ~~Gas-fired generation increased in both the three and nine months ended September 30, 2015~~Hydroelectric and nuclear generation increased during the ~~nine~~three months ended ~~September 30,2015 2015~~March 31, 2016 as compared to the same periods in ~~2014.~~2015.

The Utility’s total purchased power is driven by customer demand, the availability of the Utility’s own generation facilities (including the Diablo Canyon nuclear generation power plant and hydroelectric plants), and the cost-effectiveness of each source of electricity.

Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage, transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand.

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
(in millions)	2015		2014		2015		2014		2016		2015
Cost of natural gas sold	$	18	$	102	$	335	$	591	$	181	$	235
Transportation cost of natural gas sold		32		32		107		103		41		39
Total cost of natural gas	$	50	$	134	$	442	$	694	$	222	$	274
Average cost per Mcf (1) of natural gas sold (2)	$	0.69	$	3.78	$	2.46	$	4.13	$	2.26	$	3.26
Total natural gas sold (in millions of Mcf)(1)		26		27		136		143		80		72

(1) One thousand cubic feet

(2) Average cost of natural gas sold primarily impacted by a decline in the market price of natural gas ~~and a decrease~~ in ~~compliance costs.~~the three months ended March 31, 2016 compared to the same period in 2015.

Operating and Maintenance Expenses

The Utility’s operating expenses also include certain recoverable costs that the Utility incurs as part of its operations such as pension contributions and public purpose programs costs. If the Utility were to spend over authorized amounts, these expenses could have an impact toon earnings.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations, finance capital expenditures, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its debt financing costs. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to maintain its CPUC-authorized capital structure consisting of 52% equity and 48% debt and preferred stock. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends, primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital and credit markets. PG&E Corporation has material stand-alone cash flows related to the issuance of equity and long-term debt, dividend payments, and borrowings and repayments under its revolving credit facility. PG&E Corporation relies on short-term debt, including commercial paper, to fund temporary financing needs.

PG&E Corporation’s equity contributions to the Utility are funded primarily through common stock issuances. PG&E Corporation forecasts that it will issue between ~~$700~~$600 million and $800 million in common stock during ~~2015~~2016, primarily to fund equity contributions to the Utility. The Utility’s equity needs will continue to be affected by ~~unrecoverablepipeline-related expenses (includingcharges~~charges incurred to comply with the Penalty ~~Decision)~~Decision, by the timing and outcome of the 2015 GT&S rate case, by unrecoverable pipeline-related expenses, and by fines and penalties that may be imposed in connection with ~~thematters~~the matters described in “Enforcement and Litigation Matters” below. Common stock issuances by PG&E Corporation to fund these needs would have a material dilutive impact on PG&E Corporation’s EPS.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of cash held in escrow pending the resolution of the remaining disputed claims ~~made by electricity suppliers~~that were filed in the Utility’s ~~proceeding~~reorganization proceedings under Chapter 11 of the U.S. Bankruptcy Code. (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 9 of the Notes to the Condensed Consolidated Financial ~~Statements).~~Statements.) The Utility is uncertain when and how the remaining disputed claims will be resolved.

Financial Resources

Debt and Equity Financings

~~In February 2015, PG&E Corporation entered into a new equity distribution agreement providing for~~During the ~~sale of PG&E Corporation common stock having an aggregate gross sales price of up to $500 million. In the first quarter of 2015,~~three months ended March 31, 2016, PG&E Corporation sold ~~1.4~~1.3 million shares under ~~this~~its February 2015 equity distribution agreement for cash proceeds of $74 million, net of commissions paid of $1 million. ~~No additional shares have been sold~~As of March 31, 2016, the remaining gross sales available under ~~the equity distribution agreement.~~ this agreement were $350 million.

~~In August 2015,~~ PG&E Corporation ~~sold 6.8 million shares of its common stock in an underwritten public offering for cash proceeds of $352 million, net of fees.~~

~~In addition, PG&E Corporation~~also issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the ~~nine~~three months ended ~~September 30, 2015, 6.1~~March 31, 2016, 2.3 million shares were issued for cash proceeds of ~~$263~~$72 million under these plans.

The proceeds from these sales were used for general corporate purposes, including the contribution of equity to the Utility. For the ~~nine~~three months ended ~~September 30, 2015,~~March 31, 2016, PG&E Corporation made equity contributions to the Utility of $605 million, of which $300 million was used to pay a fine to the State General Fund as required by the Penalty Decision. Additionally, PG&E Corporation and the Utility expect to continue to issue long-term and short-term debt for general corporate purposes and to maintain the CPUC-authorized capital structure during 2015.$65 million.

In ~~June 2015,~~March 2016, the Utility issued ~~$400~~$600 million principal amount of ~~3.50% Senior Notes due June 15, 2025 and $100 million of 4.30%~~2.95% Senior Notes due March ~~15, 2045.~~1, 2026. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. In addition, 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.

Revolving Credit Facilities and Commercial Paper Program

~~On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities.~~ At ~~September 30, 2015,~~March 31, 2016, PG&E Corporation and the Utility had $300 million and ~~$2.1~~$2.5 billion available under their respective $300 million and $3.0 billion revolving credit facilities. (See Note 4 of the Notes to the Condensed Consolidated Financial ~~Statements)~~Statements.)

The revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. At March 31, 2016, PG&E Corporation’s and the Utility’s total consolidated debt to total consolidated capitalization was 51% and 50%, respectively. PG&E Corporation’s revolving credit facility agreement also requires that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility. In addition, ~~these~~the revolving credit facilities include usual and customary ~~provisionsregarding~~provisions regarding events of default and covenants including covenants limiting liens to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, ~~sales~~and imposing conditions on the sale of all or substantially all of PG&E Corporation’s and the Utility’s assets and other fundamental changes. At ~~September 30, 2015,~~March 31, 2016, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

Dividends

In ~~September 2015,~~February 2016, the Board of Directors of PG&E Corporation declared quarterly dividends of $0.455 per share, totaling ~~$223~~$226 million, of which approximately ~~$218~~$221 million was paid on ~~October~~April 15, ~~2015,~~2016, to shareholders of record on ~~September 30, 2015.~~March 31, 2016.

In ~~September 2015,~~February 2016, the Board of Directors of the Utility declared a common stock dividend of $179 million that was paid to PG&E Corporation on ~~September 16, 2015.~~February 19, 2016.

In ~~September 2015,~~February 2016, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on ~~November~~May 15, ~~2015,~~2016, to shareholders of record on ~~October 30, 2015.~~April 29, 2016.

Utility Cash Flows

The Utility’s cash flows were as follows:

	Nine Months Ended September 30,				Three Months Ended March 31, 2016
(in millions)	2015		2014		2016		2015
Net cash provided by operating activities	$	2,932	$	2,914	$	1,063	$	1,101
Net cash used in investing activities		(3,734)		(3,546)		(1,250)		(1,272)
Net cash provided by financing activities		809		652		172		166
Net change in cash and cash equivalents	$	7	$	20	$	(15)	$	(5)

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. During the ~~nine~~three months ended ~~September 30, 2015,~~March 31, 2016, net cash provided by operating activities ~~increased~~decreased by ~~$18~~$38 million compared to the same period in ~~2014.~~2015. This ~~increase~~decrease was primarily due to ~~lower purchased power costs (see “Cost~~fluctuations in activities within the normal course of ~~Electricity” under “Results~~business such as the timing and amount of ~~Operations – Utility Revenues~~customer billings and ~~Costs that did not Impact Earnings” above) and offset by the payment of a $300 million fine to the State General Fund as required by the Penalty Decision.~~collections.

Future cash flow from operating activities will be affected by various factors, including:

•	the shareholder-funded bill credit of $400 million to natural gas customers in 2016, as required by the Penalty Decision (see ~~“Enforcement and Litigation Matters” in~~ Note 9 of the Notes to the Condensed Consolidated Financial Statements);

•	the timing and amounts of other fines or penalties that may be imposed in connection with the criminal prosecution of the Utility and the remaining investigations and other enforcement and litigation matters (see ~~“Enforcement and Litigation Matters” below)~~Note 9 of the Notes to the Condensed Consolidated Financial Statements);

•	the timing and outcome of ratemaking proceedings, including the 2015 GT&S rate ~~case;~~case and the 2017 GRC;

•	the timing and amount of costs the Utility incurs, but does not recover, associated with its natural gas system (including costs to implement remedial measures and $850 million to pay for designated pipeline safety projects and programs, as required by the Penalty Decision);

•	the timing and amount of tax payments (including the bonus depreciation), tax refunds, net collateral payments, and interest payments; and

•	the timing of the resolution of the Chapter 11 disputed claims and the amount of principal and interest on these claims that the Utility will be required to pay.

Investing Activities

Net cash used in investing activities ~~increased~~decreased by ~~$188~~$22 million during the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 as compared to the same period in ~~2014.~~2015. The Utility’s investing activities primarily consist of construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur approximately ~~$5.3~~$5.6 billion in capital expenditures in ~~2015~~2016 and between ~~$5.3~~$5.4 billion and ~~$5.8~~$6.5 billion in ~~2016.~~2017.

Financing Activities

During the ~~nine~~three months ended ~~September 30, 2015,~~March 31, 2016, net cash provided by financing activities increased by ~~$157~~$6 million compared to the same period in ~~2014.~~2015. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments. The Utility generally utilizes long-term debt issuances and equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

ENFORCEMENT AND LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Note 9 in the Condensed Consolidated Financial Statements. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s future financial results. In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the 2015 Form 10-K and Part II. Other Information, Item 1. Legal Proceedings. Significant regulatory developments that have occurred since the 2015 Form 10-K was filed with the SEC are discussed below.

Department of Interior Inquiry

In September 2015, the Utility was notified that the ~~U.S. Department of Interior (“DOI”)~~DOI had initiated an inquiry into whether the Utility should be suspended or debarred from entering into federal procurement and non-procurement contracts and programs citing the allegations contained in the superseding federal criminal indictment discussed ~~above.~~in Note 9 of the Notes to the Condensed Consolidated Financial Statements. The Utility ~~will file~~filed its initial response on November 2, 2015 to demonstrate that it is a presently responsible contractor under federal procurement regulations and that it believes suspension or debarment is not appropriate. On April 8, 2016, the Utility received a series of follow-up questions from the DOI regarding the Utility’s November 2015 submission. The DOI has not yet set a timeline for the Utility’s response to the questions. It is uncertain when or if further action will be ~~taken.~~

~~Pending Lawsuits and Claims~~taken by DOI following the Utility’s response.

Litigation Related to the San Bruno Accident and Natural Gas Spending

As of ~~September 30, 2015,~~March 31, 2016, there were ~~six~~seven purported derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. ~~Four of the complaints were consolidated in an action entitled~~

On February 27, 2016, a new shareholder derivative complaint, ~~Hind Bou-Salman, et. al.~~Bushkin v. ~~Peter A. Darbee, et. al.~~Rambo et al ~~pending~~., was filed in the ~~San Mateo County Superior Court. On August 28, 2015,~~United States District Court for the ~~San Mateo County Superior Court overruled the demurrers filed by PG&E Corporation, the Utility and the individual director and officer defendants seeking to dismiss the~~ ~~Bou-Salman~~ ~~action, based upon the plaintiffs’ failure to demand action~~Northern District of California. This complaint has been designated by the ~~Boards of PG&E Corporation and~~plaintiff as related to the Utility prior to filing the complaint. After the ruling, and pursuant to a writ previously filed by PG&E Corporation, the Utility, and the individual defendants, on September 3, 2015 the California Court of Appeal issued an order staying the ~~Bou-Salman~~ ~~action~~ pending the court’s final determination whether to stay the matter altogether until the resolution of federal criminal proceedings against the Utility. On September 30, 2015, PG&E Corporation, the Utility, and the individual defendants filed an additional writ petition asking the Court of Appeal to review the lower court’s August 28 decision overruling their demurrers. On October 22, 2015, the Court of Appeal issued a ruling stating that it was declining to review the August 28 decision. The other twoshareholder derivative ~~actions are entitled~~ ~~Tellardin v. PG&E Corp. et. al., pending in the San Mateo County Superior Court, and~~suit Iron Workers Mid-South Pension Fund v. Johns, ~~et.~~et al., discussed below. The Bushkin complaint seeks to hold certain individual defendants responsible on claims of breach of fiduciary duty for damage to the company caused by the San Bruno accident, as well as by an alleged obstruction of the NTSB's investigation into the San Bruno accident and an alleged false statement related to PG&E Corporation’s corporate governance practices in its 2015 Proxy Statement. A case management conference on this matter is currently set for June 17, 2016.

A case management conference in the Iron Workers action pending in the United States District Court for the Northern District of ~~California. The~~ ~~Iron Workers~~ ~~matter remains stayed by agreement of~~California is currently set for June 3, 2016. Aside from the ~~parties, pending further developments in the~~ ~~Bou-Salman~~ ~~action. There is a~~June 3, 2016 case management conference, ~~set~~the case has been stayed pending conclusion of the federal criminal proceedings against the Utility. As previously disclosed, on December 8, 2015, the California Court of Appeal issued a writ of mandate to the Superior Court of California, San Mateo County, ordering the Court to stay all proceedings in the four consolidated ~~Tellardin~~ ~~action for December 21, 2015. In addition, an Evaluation Committee the Board formed in May 2015 continues to consider responses to a demand on the board by the plaintiff in the~~ ~~Tellardin~~San Bruno Fire Derivative Cases ~~matter.~~pending conclusion of the federal criminal proceedings against the Utility.

A case management conference in the action entitled Tellardin v. PG&E Corp. et al., also pending in the Superior Court of California, San Mateo County, is currently set for August 9, 2016. PG&E Corporation and the Utility are uncertain when and how the above ~~lawsuitswill~~lawsuits will be resolved.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. Significant regulatory developments that have occurred since the ~~2014~~2015 Form 10-K was filed with the ~~SEC are~~SECare discussed below.

2017 General Rate Case

~~On September 1, 2015, the Utility filed its 2017 GRC application with the CPUC.~~ In the 2017 GRC, the Utility has requested that the CPUC determine the annual amount of base revenues (or “revenue requirements”) that the Utility will be authorized to collect from customers from 2017 through 2019 to recover its anticipated costs for electric distribution, natural gas distribution, and electric generation operations and to provide the Utility an opportunity to earn its authorized rate of return. (The Utility’s revenue requirements for other portions of its operations, such as electric transmission, natural gas transmission and storage services, and electricity and natural gas purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC.) ~~In its application,~~

The Utility’s supplemental testimony filed on February 22, 2016, reduced the ~~Utility~~Utility's previously requested a2017 revenue requirement increase of $457 million as(as compared to the 2016 authorized ~~base revenues~~amount of $7.9 billion) to $333 million, representing a $124 million reduction from the previous request. The requested increase for ~~2016,~~2018 was reduced from $489 million to $469 million, and the requested increase for 2019 was reduced from $390 million to $368 million. The Utility reduced its requested increase primarily to reflect the impact of the five-year extension of the federal tax code provisions regarding bonus depreciation, as ~~shown in~~well as the ~~following tables:~~ tax-deductibility of repair costs.

Increase

Amounts

Amounts

Compared to

Requested In

Currently

Currently
Line of Business:

the GRC

Authorized For

Authorized
(in millions)

Application

2016

Amounts
Electric distribution
$
4,376

$
4,212

$
164
Gas distribution

1,827

1,742

85
Electric generation

2,170

1,962

208
Total revenue requirements
$
8,373

$
7,916

$
457

Cost Category:

(in millions)

Operations and maintenance
$
1,833

$
1,664

$
169
Customer services

367

319

48
Administrative and general

978

1,011

(33)
Less: Revenue credits

(140)

(131)

(9)
Franchise fees, taxes other than income, and other adjustments

185

37

148
Depreciation (including costs of asset removal), return, and

income taxes

5,150

5,016

134
Total revenue requirements
$
8,373

$
7,916

$
457

InOn April 8, 2016, ORA submitted its ~~application, the Utility stated that over the 2017-2019 GRC period, the Utility plans to make average annual capital investments~~testimony. For 2017, instead of approximately $4 billion in electric distribution, natural gas distribution and electric generation infrastructure, and to improve safety, reliability, and customer service. (These annual investments would be incremental to the Utility’s ~~capital expenditures for electric and natural gas transmission infrastructure.~~requested increase, ORA recommended an $85 million reduction (approximately 1.1%) ~~The Utility also requested that the CPUC establish a ratemaking mechanism that would increase~~from the Utility’s currently authorized ~~revenues in~~2016 revenue requirement. For 2018 and 2019, ~~primarily~~ORA proposed increases of $274 million and $283 million, respectively (representing an approximately 3.5% annual increase), significantly below the Utility’s requested attrition increases of $469 million and $368 million, respectively. ORA also recommended to ~~reflect increases in rate base due~~extend the GRC cycle another year and recommends a 2020 increase of $294 million (a 3.5% increase).

On April 29, 2016, TURN and several other intervening parties filed their testimonies. While TURN’s proposal does not include a revenue requirement recommendation for 2017, TURN recommended significant reductions to 2017 forecast operating expense, capital ~~investments in infrastructure and, to a lesser extent, anticipated increases in wages~~expenditures and other ~~expenses. The Utility estimates that this mechanism would result in increases in revenue of $489 million in~~items. For 2018 and ~~an additional $390 million in 2019.~~

~~In October 2015, the Utility filed supplemental testimony to reduce its original~~2019, TURN presented a revenue requirement ~~request by~~increase proposal of $469 million (representing an approximately ~~$17~~5.9% annual increase) and $250 million ~~per year based on its forecast that it will incur~~(representing an approximately ~~$61 million for unrecoverable costs to implement the remedies ordered in the Penalty Decision.~~3.0% annual increase), respectively.

The ~~Utility expects that a procedural schedule will be issued to set~~table below summarizes the ~~dates for public hearings,~~differences between the ~~submission of testimony by~~Utility’s revenue requirement increase proposal (based on the ~~ORA~~February 22, 2016 update), and ~~other interested parties, evidentiary hearings,~~ORA’s and TURN’s recommendations:

				ORA's Recommendation (in millions)					TURN's Recommendation (in millions)
Year		Utility's Proposal (in millions)		Increase / (Decrease)			Difference (1) (Decrease)		Increase / (Decrease)			Difference Increase/(Decrease)
2017	$	333	$	(85)		$	(418)	$	N/A	(2)	$	N/A
2018		469		274			(195)		469			-
2019		368		283			(85)		250			(118)
2020		N/A		294	(3)		N/A		N/A			N/A

(1) Reflects the difference between the Utility’s proposal and the ~~submission of briefs. After~~recommendation.

(2) TURN’s proposal does not include a revenue requirement recommendation for 2017.

(3) Reflects ORA’s recommendation to extend the ~~submission of briefs, the ALJ will issue a proposed decision for consideration by the CPUC. In its application, the Utility requested that the CPUC issue a final decision by December 31, 2016.~~

GRC cycle another year.

For 2017, ORA accepted the Utility’s capital expenditure forecasts in most lines of business. The reduction proposed by ORA is primarily related to operating expenses. ORA recommended reductions in programs across all major lines of business, including programs such as gas leak survey frequency, gas record consolidation, information technology programs, electric operations and automation, hydroelectric programs, residential rate reform education and outreach (ORA recommended that these costs be tracked in a memorandum account), and enterprise records and information management. ORA also recommended reductions in administrative and general expenses, employee incentive compensation and benefits, as well as general business expenses, such as insurance. ORA’s recommended capital reductions for 2015, 2016, and 2017 would result in a rate base reduction of nearly $200 million in 2017 compared to the Utility’s 2017 forecast of $24.5 billion in the GRC lines of business.

For 2017, TURN recommended significant reductions to forecast operating expense, capital expenditures and other items across the major lines of business. TURN recommended reductions in gas programs, including pipeline replacement, replacement of gas services; electric programs, including new business and substation equipment replacement and grid modernization programs; customer service programs; and real estate programs. TURN also recommended reductions in administrative and general expenses, as well as employee incentive compensation and benefits. For 2017, TURN’s recommended reductions in operating expense and capital expenditures amount to approximately $166 million and $733 million, respectively.

The following table shows the difference between the Utility’s requested increases in 2017 revenue requirements (based on the February 22, 2016 update) and ORA’s recommended amounts by line of business:

(in millions) Line of Business:		Utility's Proposal				ORA's Recommendation Increase / (Decrease) (1)				Difference (1) (2) Increase / (Decrease)
Electric distribution	$	71	1.7	%	$	(146)	(3.5)	%	$	(217)
Gas distribution		63	3.6			(59)	(3.4)			(122)
Electric generation		199	10.1			119	6.1			(80)
Total revenue requirements	$	333	4.2	%	$	(85)	(1.1)	%	$	(418)

(1) Certain amounts have been rounded.

(2) Reflects the difference between the Utility’s proposal and the recommendation.

TURN did not present revenue requirement recommendations by line of business.

In addition, 11 other parties provided recommendations. The Alliance for Nuclear Responsibility recommended for the Utility’s Diablo Canyon nuclear power plant an annual filing on the Utility’s plans to extend the license, a new performance-based ratemaking measure and various disallowances. The Coalition of California Utility Employees, which represents the International Brotherhood of Electrical Workers, recommended increasing funding for gas operations (such as for pipe replacement and leak survey frequency) and for electric operations (such as for fault location isolation and services restoration, also known as FLISR, overhead fuses, poles, and cable), and reducing depreciation expense for gas mains and poles. Other parties made various other recommendations regarding investments in connection with electric reliability, leak management practices, safety, executive compensation, customer outreach, local office closures, and supplier and employee diversity.

The following tables show the Utility’s currently requested amounts compared to 2016 authorized amounts:

						Increase
				Amounts		Compared to
				Currently		Currently
(in millions)		Amounts		Authorized For		Authorized
Line of Business:		Requested		2016		Amounts
Electric distribution	$	4,284	$	4,213	$	71
Gas distribution		1,804		1,741		63
Electric generation		2,161		1,962		199
Total revenue requirements	$	8,249	$	7,916	$	333

Cost Category:
(in millions)
Operations and maintenance	$	1,833	$	1,664	$	169
Customer services		367		319		48
Administrative and general		975		1,011		(36)
Less: Revenue credits		(140)		(131)		(9)
Franchise fees, taxes other than income, and other adjustments		184		37		147
Depreciation (including costs of asset removal), return, and
income taxes		5,030		5,016		14
Total revenue requirements	$	8,249	$	7,916	$	333

According to the CPUC’s procedural schedule, rebuttal testimonies are scheduled to be submitted by the Utility and other parties on May 27, 2016. Evidentiary hearings are to be held this summer, followed by a proposed decision to be released in November 2016 and a final CPUC decision to be issued in December 2016. On March 17, 2016, the CPUC issued a decision to allow the authorized revenue requirement changes to become effective on January 1, 2017, even if the final decision is issued after that date.

2015 Gas Transmission and Storage Rate Case

In the 2015 GT&S rate case, the Utility requested that the CPUC authorize a 2015 revenue requirement of $1.263 billion to recover anticipated costs of providing natural gas transmission and storage services, an increase of $532 million over currently authorized amounts. The Utility also requested attrition increases of $83 million in 2016 and $142 million in 2017. The Utility requested that the CPUC authorize the Utility’s forecast of its 2015 weighted average rate base for its gas transmission and storage business of $3.44 billion, which includes capital spending above authorized levels for the prior rate case period.

~~The~~ ORA has recommended a 2015 revenue requirement of $1.044 billion, an increase of $329 million over authorized amounts. TURN recommended that the Utility not recover costs associated with hydrostatic testing for pipeline segments placed in service after January 1, 1956, as well as certain other work that TURN considers to be remedial. TURN also recommended the disallowance of about $200 million of capital expenditures incurred over the period 2011 through 2014 and recommended that about $500 million of capital expenditures during this period be subject to a reasonableness review and an independent audit. TURN ~~states~~stated that the Utility’s cost recovery should not begin until the CPUC issues a decision on the independent audit.

The Utility also has proposed changes to the revenue sharing mechanism authorized in the last GT&S rate case (covering 2011-2014) that subjected a portion of the Utility’s transportation and storage revenue requirement to market risk. The Utility proposed full balancing account treatment that allows for recovery of the Utility’s authorized transportation and storage revenue requirements (except for the revenue requirement associated with the Utility’s 25% interest in the Gill Ranch storage field).

Based on the scoping ruling and procedural schedule that was issued on June 11, 2015, the CPUC plans to issue an initial decision to authorize revenue requirements followed by a second decision to reduce the authorized revenue requirements by the costs of designated safety-related projects and programs ~~up to the~~of $850 million ~~maximum~~ cost disallowance imposed by the Penalty Decision. (See Note 9 in the Condensed Consolidated Financial Statements for more information about the CPUC’s Penalty Decision.) (In accordance with an earlier CPUC decision regarding the Utility’s violation of the CPUC’s ex parte communication rules made in the GT&S rate case, the first decision could disallow the Utility from recovering up to a five-month portion of the revenue increase that may otherwise have been authorized.)~~It is uncertain how the~~ The second CPUC decision ~~will~~is expected to identify the costs that are counted toward the $850 million shareholder-funded obligation. If the Utility’s actual costs exceed costs that the CPUC counts towards the $850 million maximum, the Utility would record additional charges if such costs are not otherwise authorized by the CPUC.

The authorized revenue requirements in the 2015 GT&S rate case would be retroactive to January 1, ~~2015. Under~~2015but would be recorded in the ~~procedural schedule,~~period a final decision is issued. Both decisions are anticipated in 2016.

CPUC Cost of Capital Decision

On February 25, 2016, the CPUC issued a decision granting a petition for modification filed by the Utility and the other two California investor-owned electric utilities to clarify that the CPUC’s ~~first decision~~previously adopted cost of capital adjustment mechanism would not be triggered before their 2018 cost of capital applications are due on April 20, 2017. As a result, the Utility’s currently authorized return on equity of 10.40% and capital structure, consisting of 52% common equity, 47% long-term debt, and 1% preferred stock, will remain the same for 2017.

Asset Retirement Obligations

Detailed studies of the cost to ~~authorize~~decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. On March 1, 2016, the Utility submitted its updated decommissioning cost estimate with the CPUC in its 2015 NDCTP. The estimated undiscounted cost to decommission the Utility’s nuclear power plants increased by approximately $1.4 billion, for a total estimated cost of $4.8 billion, due to 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 likely will not be issued until 2016 and the second decision to determine the revenue requirement reduction will follow. (The ruling states that, in any event, the case would be completed within 18 months of the date of the ruling, or by December 2016.) Based on the procedural schedule, it is unlikelyfor decommissioning costs from customers through a non-bypassable charge that the Utility expects will ~~be able to recognize any increase in its GT&S revenue in 2015.~~

~~FERC TO Rate Cases~~

On September 30, 2015, the FERC approved a settlement that sets the Utility’s 2015 retail electric transmission revenue requirement at $1.201 billion, a $161 million increase over the currently authorized revenue requirement of $1.040 billion.

~~On July 29, 2015, the~~continue until those costs are fully recovered. The Utility requested that the ~~FERC approve a~~CPUC authorize the collection of increased annual revenue requirements beginning on January 1, 2017 based on these updated cost estimates.

On April 4, 2016, ~~retail electric transmission revenue requirement of $1.515 billion. The proposed amount reflects a $314 million increase over~~TURN and ORA submitted protests to the ~~settled revenue requirement of $1.201 billion. The Utility forecasts~~Utility’s 2015 NDCTP. TURN indicated that it ~~will make investments~~intends to thoroughly review the Utility’s power plants cost estimate to determine overall reasonableness of ~~$1.246 billion in 2016 in various capital projects. The~~the Utility’s ~~forecasted rate base for 2016 is $5.85 billion, compared to forecasted rate base of $5.12 billion in 2015. The Utility has requested~~request and that the ~~FERC approve~~Utility should be required to provide an alternative assessment of decommissioning costs and funding requirements if the Diablo Canyon license is renewed.ORA requested an evidentiary hearing to develop a ~~10.96% return~~full and complete record of the support and justification for the Utility’s 2015 NDCTP application. On April 14, 2016, the Utility filed its response and objected to TURN’s proposal for an alternate assessment of Diablo Canyon costs.

The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on ~~equity. On September 30, 2015,~~ the ~~FERC accepted~~Condensed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $3.3 billion at March 31, 2016, which includes an $818 million adjustment to reflect the ~~proposed revenue requirement, subject to hearing~~increased cost estimates described above, and ~~refund, and established March 1,~~$2.5 billion at December 31, 2015. These estimates are based on the 2016 asdecommissioning cost studies prepared in accordance with the ~~effective date~~CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for ~~rate changes. Hearings are being held in abeyance pending settlement discussions among the parties.~~these assets.

CPUC Investigation of the Utility’s Safety Culture

On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards. The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents. The CPUC authorized the SED to engage a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment. The consultant’s work is expected to begin in the second quarter of 2016.

The CPUC stated that the initial phase of the proceeding was categorized as ~~ratesetting~~rate setting because it will consider issues both of fact and policy and because the Utility and PG&E Corporation do not face the prospect of fines, penalties, or remedies in this phase. Upon completion of the consultant’s report, the assigned Commissioner will determine the scope of and next actions in the ~~proceeding.The~~proceeding. The timing scope and potential outcome of the investigation are uncertain.

Rehearing of CPUC Decisions Approving 2006 – 2008 Energy Efficiency Incentive Awards

On September 17, 2015, the CPUC granted TURN’s and ORA’s long-standing applications for rehearing of the CPUC decisions that awarded energy efficiency incentive payments to the California IOUs for the 2006-2008 energy efficiency program cycle. Under the incentive ratemaking mechanism applicable to the 2006-2008 program cycle, the Utility could have earned incentive revenues up to a maximum of $180 million, depending on the extent to which the Utility achieved the energy savings targets. Conversely, to the extent the Utility failed to achieve the targets, the Utility could have been required to offset future incentive earnings claims by amounts previously awarded, and, in addition, could have incurred penalties of up to $180 million. The Utility was awarded a total of $104 million for the 2006-2008 program cycle. In the re-opened proceeding, the CPUC will evaluate whether the incentive amounts awarded to the IOUs were just and reasonable, and whether any refunds are due.

On March 18, 2016, TURN and ORA submitted a joint proposal to require the refund of incentive awards that TURN and ORA argue were not calculated in accordance with the ratemaking mechanism rules and procedures the CPUC had previously adopted. TURN and ORA contended that the CPUC should order the Utility to refund $104 million, the entire incentive earnings award, plus interest, to customers as either (1) a revenue credit to customers’ distribution and gas transportation accounts or (2) as a line item to the customers’ first monthly bill following the issuance of a CPUC decision.

PG&E Corporation and the Utility believe it is reasonably possible that the Utility will be required to refund amounts previously awarded or incur other obligations related to this matter, but they are unable to reasonably estimate the amount of such refunds or other obligations. If the Utility were required to make a refund as TURN and ORA propose, PG&E Corporation’s and the Utility’s financial results would be affected by the amount of any refund-related charges.

OTHER MATTERS

Agreement with TransCanyon, LLC for Competitive Transmission Opportunities

On March 29, 2016, the Utilityentered into an agreement with TransCanyon, LLC, a joint venture between subsidiaries of Berkshire Hathaway Energy and Pinnacle West Capital Corporation, to jointly pursue competitive transmission opportunities solicited by the CAISO, the operator for the majority of the California electric transmission grid. The Utility and TransCanyon intend to jointly engage in the development of future transmission infrastructure and compete to develop, build, own and operate transmission projects approved by the CAISO.

LEGISLATIVE AND REGULATORY INITIATIVES

The California Legislature and the CPUC have adopted requirements and policies to accommodate the growth in distributed electric generation resources (including solar installations), increase the amount of renewable energy delivered to customers, foster the development of a state-wide electric vehicle charging infrastructure to encourage the use of electric vehicles, ~~and~~ promote customer energy efficiency and demand response ~~programs.~~programs, and implement new state law requirements applicable to natural gas storage facilities. In addition, the CPUC continues to implement state law requirements to reform electric rates to more closely reflect the utilities’ actual costs of service, reduce cross-subsidization among customer rate classes, implement new rules and rates for net energy metering (which currently allow certain self-generating customers to receive bill credits for surplus power at the full retail rate), and allow customers to have greater control over their energy use. ~~CPUC proceedings related to some of these matters~~Significant developments that have occurred since the 2015 Form 10-K was filed with the SEC are discussed below.

The Utility’s ability to recover its costs, including investments associated with legislative and regulatory initiatives, as well as its electricity procurement and other operating costs, will, in large part, depend on the final form of legislative or regulatory requirements, and whether the associated ratemaking mechanisms can be timely adjusted to reflect changes in customer demand for the Utility’s electricity and natural gas service.

~~New Renewable Energy Targets~~

In October 2015, the California Governor signed SB 350 which, effective January 1, 2016, increases the amount of renewable energy that must be delivered by most load-serving entities, including the Utility, to their customers from 33% of their total annual retail sales by the end of the 2017-2020 compliance period to 50% of their total annual retail sales by the end of the 2028- 2030 compliance period and in each compliance period thereafter. SB 350 includes increasing interim renewable energy targets for the periods between 2020 and 2030 and continues to include compliance flexibility and waiver mechanisms, including increased flexibility to apply excess renewable energy procurement in one compliance period to future compliance periods. The Utility will incur additional costs to procure renewable energy to meet the new renewable energy targets which the Utility expects will continue to be recoverable from customers as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets. The CPUC is required to open a new rulemaking proceeding to adopt regulations to implement the higher targets.

Electric Distribution Resources Plan

As required by California law, on July 1, 2015, the Utility filed its proposed electric distribution resources plan for approval by the CPUC. The Utility’s plan identifies optimal locations on its electric distribution system for deployment of distributed energy resources. The Utility’s proposal is designed to allow energy technologies to be interconnected with each other and integrated into the larger grid while continuing to provide customers with safe, reliable and affordable electric service. The Utility envisions a future electric grid, titled the Grid of Things™, that would allow customers to choose new advanced energy supply technologies and services to meet their needs consistent with safe, reliable and affordable electric service. The Utility’s 2017 GRC includes a request to recover some of the investment costs that it forecasts it will incur under its proposed electric distribution resources plan.

Integrated Distributed Energy Resources Pilot Program

On April 4, 2016, the assigned CPUC Commissioner and ALJ issued a ruling proposing to establish, on a pilot basis, an interim program offering regulatory incentives to the Utility and the other two large California IOUs for the deployment of cost-effective distributed energy resources (“DERs”). The ruling assumes that the incentive would take the form of an additional payment to the utility of 3.5% (grossed up for taxes) of the payments made to the DERprovider(s). The exact figure would be determined later if the proposal or a similar alternative is adopted by the CPUC. The ruling also states that it does not intend for this phase to adopt a new regulatory framework or business model for the California electric utilities. Comments on the proposal are due May 9, 2016 and reply comments are due May 23, 2016.

Electric Rate Reform and Net Energy Metering ~~(“NEM”)~~

On July 3, 2015, the CPUC approved a final decision to authorize the California ~~investor–owned utilities~~IOUs to gradually flatten their tiered residential electric rate structures from four tiers to two tiers by January 1, 2019. The decision approved increased minimum bill charges for residential customers and also allows the imposition of a surcharge on customers with extremely high electricity use beginning in 2017. The decision requires the Utility to file a proposal by January 1, 2018, to charge residential electric customers based on time-of-use rates ~~unless customers elect otherwise~~ (known as “default time-of-use rates”). unless customers elect otherwise. The Utility also may propose to impose a fixed charge on residential electric customers. Under the CPUC’s decision, default time-of-use rates must be implemented before the CPUC will permit the imposition of a fixed ~~charge. The CPUC also approved increased minimum bill charges for residential customers.~~charge in electric rates.

In ~~July 2014,~~January 2016, the CPUC ~~began a~~adopted new rulemaking proceeding to develop new net energy metering rules and rates to more accurately reflect the utilities’ costs of providing service to such customers while continuing to encourage the development and installation of renewable distributed generation technologies. On August 3, 2015, the Utility filed its proposal for new net energy meteringNEM rules and rates. The ~~CPUC is~~new rules and rates are expected to ~~issue a~~become effective for new NEM customerslater in 2016. New NEM customers will be required to pay an interconnection fee, will be charged on time-of-use rates, and will be required to pay non-bypassable charges to help fund some of the costs of low-income, energy efficiency, and other programs that other customers pay. On March 7, 2016, the Utility and certain other parties, including TURN and CUE, filed applications for rehearing. The Utility requested that the CPUC vacate its January 2016 decision ~~by December 2015.~~that the Utility asserts contains legal and factual errors. Many parties argued that the CPUC failed to complete its duties under AB 327, which required the CPUC to evaluate the costs and benefits of NEM.

Electric Vehicle (EV) Infrastructure Development

In December 2014, the CPUC issued a decision adopting a policy to expand the California utilities’ role in developing an EV charging infrastructure to support California’s climate goals. On February 9, 2015, the Utility filed an application requesting that the CPUC approve the Utility’s proposal to deploy, own, and maintain more than 25,000 EV charging stations and the associated infrastructure. The Utility proposed to engage with ~~third party~~third-party EV service providers to operate and maintain the charging stations. The Utility requested that the CPUC approve forecasted capital expenditures of $551 million over the ~~5 year~~5-year deployment period.

On September 4, 2015, the assigned CPUC Commissioner and the ALJ issued a scoping memo and procedural schedule that required the Utility to supplement its application by submitting a more phased deployment approach that will be considered in a first phase of the proceeding. On October 12, 2015, the Utility submitted supplemental testimony presenting two separate proposals. In its first proposal, the Utility has requested that the CPUC approve approximately $70 million in capital expenditures to deploy and own 2,510 EV charging stations over approximately 2 years. In its second proposal, the Utility has requested that the CPUC approve approximately $187 million in capital expenditures to deploy and own 7,530 EV charging stations over approximately 3 years. ~~Under~~

On March 21, 2016, the Utility filed with the CPUC a settlement agreement that it entered into with certain parties, including environmental advocates, automakers, electric vehicle drivers, labor, and environmental justice advocates, that makes adjustments to the Utility’s second proposal, including a reduction to requested capital expenditures to approximately $132 million. (TURN, ORA, and certain equipment suppliers are not parties to the agreementand filed responses on April 12, 2016, generally opposing the settlement.) The settlement agreement is subject to approval by the CPUC. Hearings were held in April 2016 and under the CPUC’s schedule, a proposed decision for the first phase of the proceeding is expected to be issued ~~by June~~in the third quarter of 2016. Further deployment of EV charging stations would be considered in a second phase of the proceeding depending on the outcome of the first phase.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes, such as groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations; the reporting and reduction of carbon dioxide and other greenhouse gas emissions; the discharge of pollutants into the air, water, and soil; and the transportation, handling, storage, and disposal of spent nuclear fuel. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements, as well as “Item 1A. Risk Factors” and Note 1413 in the ~~2014~~2015 Form 10-K.)

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities. (See “Purchase Commitments” in Note 9 of the Notes to the Condensed Consolidated Financial Statements). Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing. For more in-depth discussion about PG&E Corporation’s and the Utility’s contractual commitments, see “Liquidity and Financial Resources” above and Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Commitments in the ~~2014~~2015 Form 10-K.

Off-Balance Sheet Arrangements

PG&E Corporation and the Utility do not have ~~any off-balance~~anyoff-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 1413 of the Notes to the Consolidated Financial Statements in the ~~2014~~2015 Form 10-K (the Utility’s commodity purchase agreements).

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations; their financing arrangements; the marketplace for electricity, natural gas, electric transmission, natural gas transportation, and storage; emissions allowances and offset credits, other goods and services; and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as “price risk” and “interest rate risk.” The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations.

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility’s risk management activities include the use of ~~energy~~physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases. The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. These activities ~~are discussed~~arediscussed in detail in the ~~2014~~2015 Form 10-K. There were no significant developments to the Utility and PG&E Corporation’s risk management activities during the ~~nine~~three months ended ~~September 30, 2015.~~March 31, 2016.

CRITICAL ACCOUNTING POLICIES

The preparation of the Condensed Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, asset retirement obligations, and pension and other postretirement benefits plans to be critical accounting policies. These policies are considered critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates. These accounting policies and their key characteristics are discussed in detail in the ~~2014 Form~~2015Form 10-K.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See the discussion above in Note 2 of the Notes to the Condensed Consolidated Financial Statements.

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This 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. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations and proceedings; forecasts of pipeline-related expenses that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to regulatory assets and liabilities, environmental remediation, litigation, third-party claims, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

•	~~The outcome~~the timing and ~~timing~~outcomes of the 2015 GT&S rate case, ~~including~~ the ~~amount of revenue disallowance that may be imposed as a penalty for improper ex parte communications~~2017 GRC, the TO rate cases, and ~~how the authorized revenue requirements are reduced to reflect the disallowance of costs associated with designated safety-related projects~~other ratemaking and ~~programs as required by the Penalty Decision;~~regulatory proceedings;

•	the timing and outcomes of the federal criminal prosecution of the Utility, the ~~CPUC’s~~pending CPUC investigation of the Utility’s natural gas distribution record-keeping practices, the SED’s unresolved enforcement ~~action~~ matters relating to the Utility’s compliance with natural gas-related laws and regulations, and the other investigations that have been or may be commenced relating to the Utility’s compliance with natural gas-related laws and regulations, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with ~~such matters;~~the outcomes;

•	the timing and outcome of the CPUC’s investigation ~~and the pending criminal investigations relating to~~of communications between the Utility and the CPUC that may have violated the CPUC’s rules regarding ex parte communications or are otherwise alleged to be improper, whether additional criminal or regulatory investigations or enforcement actions are commenced with respect to allegedly improper communications, and whether such matters negatively affect the final decisions to be issued in the 2015 GT&S rate case or other ratemaking proceedings;
	the outcome of the Butte fire litigation, and whether the Utility’s insurance is sufficient to cover the Utility’s liability resulting therefrom, or if insurance is otherwise available; and whether additional investigations and proceedings will be opened

•	whether PG&E Corporation and the Utility are able to repair the harm to their reputations caused by the criminal prosecution of the Utility, the state and federal investigations of natural gas incidents, matters relating to the indicted case, improper communications between the CPUC and the Utility; and the Utility’s ongoing work to remove encroachments from transmission pipeline rights-of-way;

•	the restrictions on communications between the Utility and the CPUC that have been imposed by the CPUC that, along with continuing public criticism of the Utility and the CPUC, may make it more difficult for the Utility to sustain or repair a constructive working relationship with the CPUC and achieve balanced regulatory outcomes;

• •	the timing and outcome of ratemaking proceedings (such as the 2015 GT&S rate case, the 2017 GRC and the TO rate cases) and other regulatory proceedings (such as the recently re-opened proceeding related to the Utility’s 2006-2008 energy efficiency programs and the proceeding to consider the Utility’s proposal to develop an EV charging infrastructure); whether the Utility can control its costs within the authorized levels of spending, the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs, and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons;

•	the amount and timing of additional common stock and debt issuances by PG&E Corporation, including the ~~proceeds~~dilutive impact of ~~which are contributed as~~common stock issuances to fund PG&E Corporation’s equity contributions to ~~maintain~~ the ~~Utility’s authorized capital structure~~Utility as the Utility incurs charges and costs, including fines, that it cannot recover through ~~rates (including shareholder-funded costs to complete designated safety projects and programs as ordered in the Penalty Decision) and fines;~~rates;

•	the outcome of the ~~recently opened CPUC~~CPUC’s investigation into the Utility’s safety culture, and future legislative or regulatory actions that may be taken to require the Utility to separate its electric and natural gas businesses, restructure into separate entities, undertake some other corporate restructuring, or implement corporate governance changes;

•

the outcomes of future investigations or other enforcement proceedings that may be commenced relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to its operations, including the construction, expansion or replacement of its electric and gas facilities; inspection and maintenance practices, customer billing and privacy, and physical and cyber security; ~~and whether the current or potentially worsening state regulatory environment increases the likelihood of unfavorable outcomes;~~

•
	the impact of environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; and the extent to which the Utility is able to recover environmental costs in rates or from other sources; ~~and~~


	the ultimate amount of unrecoverable environmental costs the Utility incurs ~~but does not recover, such as the remediation costs~~ associated with the Utility’s natural gas compressor station site located near Hinkley, California;

•	the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, cooling water intake, or other issues; the impact of actions taken by state agencies, including the California State Water Resources Board and the California State Lands Commission, that may affect the Utility’s ability to continue operating Diablo Canyon; and whether the Utility decides to resume its pursuit to renew the two Diablo Canyon NRC operating licenses, and if so, whether the licenses are renewed;

•	the impact of droughts or other weather-related conditions or events, wildfires (such as the Butte fire), climate change, natural disasters, acts of terrorism, war, or vandalism (including cyber-attacks), and other events, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies; ~~and subject~~whether the Utility incurs liability to ~~third-party liability~~third parties for property damage or personal injury ~~or result in~~caused by such events; and whether the ~~imposition of~~Utility is subject to civil, criminal, or regulatory penalties onin connection with such events; and whether the ~~Utility;~~Utility’s insurance coverage is available for these types of claims and whether the amount of insurance is sufficient to cover the Utility’s liability;

•	how the ~~impact of~~CPUC and the CARB implement state environmental laws relating to GHG, renewable energy targets, energy efficiency standards, distributed energy resources, electric vehicles, and ~~regulations aimed at the reduction of greenhouse gases, and~~similar matters, including whether the Utility is able to continue recovering associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations, and whether the Utility ~~can~~is able to timely recover ~~renewable energy procurement~~its associated investment costs;

	•whether the Utility’s climate change adaptation strategies are successful;

	the impact that reductions in customer demand for electricity and natural gas have on the Utility’s ability to make and recover its investments through rates and earn its authorized return on equity, and whether the ~~Utility’s business strategy to address~~Utility is successful in addressing the impact of growing distributed and renewable generation resources and changing customer ~~demands is successful;~~demand for natural gas and electric services;

•	the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through ~~rates;~~rates, including its renewable energy procurement costs;

•	whether the Utility’s information technology, operating systems and networks, including the advanced metering system infrastructure, customer billing, financial, records management, and other systems, can continue to function accurately while meeting regulatory requirements; whether the Utility is able to protect its operating systems and networks from damage, disruption, or failure caused by cyber-attacks, computer viruses, or other hazards; whether the Utility’s security measures are sufficient to protect against unauthorized or inadvertent disclosure of information contained in such systems and ~~networks;~~networks, including confidential proprietary information and the personal information of customers; and whether the Utility can continue to rely on third-party vendors and contractors that maintain and support some of the Utility’s information technology and operating systems;

•	the amount and timing of charges reflecting probable liabilities for third-party claims; the extent to which costs incurred in connection with third-party claims or litigation can be recovered through insurance, rates, or from other third parties; and whether the Utility can continue to obtain adequate insurance coverage for future losses or claims, especially following a major event that causes widespread third-party losses;

•	the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms;

•	changes in credit ratings which could result in increased borrowing costs especially if PG&E Corporation or the Utility were to lose its investment grade credit ratings;

•

the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the ultimate outcomes of the CPUC’s pending investigations, the criminal prosecution, and other enforcement matters affect the Utility’s ability to make distributions to PG&E Corporation, and, in turn, PG&E Corporation’s ability to pay dividends;


•	the outcome of federal or state tax audits and the impact of any changes in federal or state tax laws, policies, regulations, or their interpretation, including whether state law is enacted to prohibit the Utility from claiming tax deductions for costs associated with designated safety-related projects and programs that are disallowed by the Penalty Decision;interpretation; and

•	the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see “Risk Factors” in the ~~2014~~2015 Form 10-K and in Part II, Item. 1A. Risk Factors below. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates. (See the section above entitled “Risk Management Activities” in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.)

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of ~~September 30, 2015,~~March 31,2016, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended ~~September 30, 2015,~~March 31,2016, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s contingencies, see Note 9 of the Notes to the Condensed Consolidated Financial ~~Statements.~~Statement and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Enforcement and Litigation Matters.”

~~CPUC Investigations~~Penalty Decision Related to the CPUC’s Investigative Enforcement Proceedings Related to Natural Gas Transmission

For a description of this matter, see “Part ~~II,~~I, Item 1.3. Legal Proceedings” in the 2015 Form ~~10-Q for~~10-K, the ~~quarters ended March 31~~discussion of the Penalty Decision in Note 13 of the Notes to the Consolidated Financial Statements inthe 2015 Form 10-K, and ~~June 30, 2015. In addition, see~~the discussion ~~entitled “Enforcement and Litigation Matters”~~included in Note 9 of the Notes to the Condensed Consolidated Financial Statements.

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. Although the trial previously had been scheduled to begin on April 26, 2016, the court vacated the trial date and no new trial date has been set. The court stated that it will set a new trial date in due course.

The maximum statutory fine for each felony count is $500,000, for total potential fines of $6.5 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.

For description of this matter, see “Part ~~II,~~I, Item 1.3. Legal Proceedings” in the 2015 Form ~~10-Q for~~10-K, the ~~quarters ended March 31~~section entitled “Enforcement and ~~June 30, 2015. In addition, see discussion~~Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8 in the 2015 Form 10-K, and the section entitled “Enforcement and Litigation Matters” in Note 9 of the Notes to the Condensed Consolidated Financial Statements.

Litigation Related to the San Bruno Accident and Natural Gas Spending

On February 27, 2016, a new shareholder derivative complaint, ~~Hind Bou-Salman, et. al.~~Bushkin v. ~~Peter A. Darbee, et.~~Rambo et al. ~~pending~~, was filed in the ~~San Mateo County Superior Court. On August 28, 2015,~~United States District Court for the ~~San Mateo County Superior Court overruled the demurrers filed by PG&E Corporation, the Utility and the individual director and officer defendants seeking to dismiss the~~ ~~Bou-Salman~~ ~~action, based upon the plaintiffs’ failure to demand action~~Northern District of California. This complaint has been designated by the ~~Boards of PG&E Corporation and~~plaintiff as related to the Utility prior to filing the complaint. After the ruling, and pursuant to a writ previously filed by PG&E Corporation, the Utility, and the individual defendants, on September 3, 2015 the California Court of Appeal issued an order staying the ~~Bou-Salman~~ ~~action~~ pending the court’s final determination whether to stay the matter altogether until the resolution of federal criminal proceedings against the Utility. On September 30, 2015, PG&E Corporation, the Utility, and the individual defendants filed an additional writ petition asking the Court of Appeal to review the lower court’s August 28 decision overruling their demurrers. On October 22, 2015, the Court of Appeal issued a ruling stating that it was declining to review the August 28 decision. The other twoshareholder derivative ~~actions are entitled~~ ~~Tellardin v. PG&E Corp. et. al., pending in the San Mateo County Superior Court, and~~suit Iron Workers Mid-South Pension Fund v. Johns, ~~et.~~et al., discussed below. The Bushkin complaint seeks to hold certain individual defendants responsible on claims of breach of fiduciary duty for damage to the company caused by the San Bruno accident, as well as by an alleged obstruction of the NTSB's investigation into the San Bruno accident and an alleged false statement related to PG&E Corporation’s corporate governance practices in its 2015 Proxy Statement. A case management conference on this matter is currently set for June 17, 2016.

A case management conference in the Iron Workers action pending in the United States District Court for the Northern District of ~~California. The~~ ~~Iron Workers~~ ~~matter remains stayed by agreement of~~California is currently set for June 3, 2016. Aside from the ~~parties, pending further developments in the~~ ~~Bou-Salman~~ ~~action. There is a~~June 3, 2016 case management conference, ~~set~~the case has been stayed pending conclusion of the federal criminal proceedings against the Utility. As previously disclosed, on December 8, 2015, the California Court of Appeal issued a writ of mandate to the Superior Court of California, San Mateo County, ordering the Court, to stay all proceedings in the four consolidated ~~Tellardin~~San Bruno Fire Derivative Cases ~~action for December 21, 2015. In addition, an Evaluation Committee~~pending conclusion of the ~~Board formed in May 2015 continues to consider a demand on~~federal criminal proceedings against the ~~Boards by the plaintiff in the Tellardin matter.~~Utility.

A case management conference in the action entitled Tellardin v. PG&E ~~Corporation and~~Corp. et al., also pending in the ~~Utility are uncertain when and how the above lawsuits and the shareholder demand will be resolved.~~Superior Court of California, San Mateo County, is currently set for August 9, 2016.

For additional information regarding these matters, see the discussion entitled “Enforcement and Litigation Matters” above in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. In addition, see “Part I, Item 3. Legal Proceedings” in the ~~2014~~2015 Form ~~10-K,~~10-K.

Investigation of the Butte Fire

On April 28, 2016, Cal Fire released its report of the investigation of the origin and ~~“Part II, Item 1. Legal Proceedings”~~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.

In connection with the Butte fire, approximately 32 complaints have been filed to date against the Utility and its vegetation management contractors in the ~~Form 10-Q~~Superior Court of California in both the County of Calaveras and the County of San Francisco, involving approximately 1,300 individual plaintiffs and their insurance companies. In response to plaintiffs’ and the Utility’s requests, the California Judicial Council has authorized the coordination of all cases in the Superior Court of California, Sacramento County. 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 number of complaints may increase in the future. An initial case management conference was held on April 22, 2016 and the next case management conference is currently scheduled for May 24, 2016.

In connection with this matter, the ~~quarters ended March 31~~Utility may be liable for property damages without having been found negligent, through the theory of inverse condemnation. In addition, the Utility may be liable for fire suppression costs, personal injury damages, and ~~June 30, 2015.~~other damages if the Utility were found to have been negligent.

As a result of the Cal Fire report, additional investigations and proceedings may be opened, the outcome of which PG&E Corporation and the Utility are unable to predict.

For additional information, see Note 9 of the Notes to the Condensed Consolidated Financial Statements and Item 1A. Risk Factors.

Other Enforcement Matters

In addition, fines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to the Utility’s self-reports of noncompliance with natural gas safety regulations, prohibited ex parte communications between the Utility and CPUC personnel, investigations that were commenced after a pipeline explosion in Carmel, California on March 3, 2014, and other enforcement matters. See the discussion entitled “Enforcement and Litigation Matters” above in Part 1, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 9 of the Notes to the Condensed Consolidated Financial Statements. In addition, see “Part I, Item 3. Legal Proceedings” in the ~~2014~~2015 Form 10-K.

Diablo Canyon Nuclear Power Plant

For more information regarding the status of the 2003 settlement agreement between the Central Coast Regional Water Quality Control Board and the Utility, see “Part I, Item 3. Legal Proceedings” in the ~~2014~~2015 Form 10-K.

As part of its regular maintenance and inspection practices for its natural gas transmission system, the Utility performs in-line inspections of pipelines using devices called “pigs” that travel through the pipeline to inspect and clean the walls of the pipe. When in-line inspections are performed, natural gas in the pipeline is released or vented at the pipeline station where the device is removed. In February 2014, the Utility conducted an in-line inspection of a natural gas transmission pipeline that traverses San Benito County and vented the natural gas at the Utility’s transmission station located in Hollister, which is next to an elementary school. The Utility vented the natural gas during school hours on three occasions that month. After being informed of the venting by the local air district, the San Benito County District Attorney notified the Utility in December 2014 that it was contemplating bringing legal action against the Utility for violation of Health and Safety Code section 41700, which prohibits discharges of air contaminants that cause a public nuisance. The Utility has been in settlement discussions with the district attorney’s office since that time. On October 28, 2015, the district attorney informed the Utility that it would seek civil penalties in excess of $100,000 but is willing to continue to explore settlement options with the Utility.

For more information, see “Part I, Item 3. Legal Proceedings” in the 2015 Form 10-K.

ITEM 1A. RISK FACTORS

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see the section of the ~~2014~~2015 Form 10-K entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled “Cautionary Language Regarding Forward-Looking Statements.”

PG&E Corporation’s and the Utility’s future financial results will continue to be materially affected as the Utility complies with the Penalty Decision and also may be materially affected by the outcomes of the 2015 GT&S rate case, the CPUC investigative enforcement proceeding regarding the Utility’s natural gas distribution record-keeping, the ongoing federal criminal prosecution of the Utility, and the other federal, state and regulatory proceedings discussed above. In addition, their financial results may be materially affected if the Utility is required to refund incentive awards or incur other obligations with respect to its 2006-2008 energy efficiency programs.

PG&E Corporation’s EPS will be materially affected by dilutive common stock issuances needed to fund equity contributions to the Utility to comply with the terms of the Penalty Decision, as discussed above in Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) and Note 9 of the Condensed Consolidated Financial Statements. The Utility will incur material unrecoverable costs to meet the Penalty Decision’s requirement to fund safety-related projects and programs to be identified by the CPUC in the GT&S rate case. Depending on how the CPUC designates pipeline safety-related projects and programs the Utility is required to fund, and how the Utility’s associated costs are counted toward meeting the $850 million maximum disallowance, the ultimate amount of unrecoverable pipeline-related costs the Utility incurs may be higher than current forecasts. In addition, the Penalty Decision requires the Utility to implement various remedial measures which the CPUC estimated would cost $50 million. Actual costs to implement the remedies could be higher. The Penalty Decision also requires the SED to review the Utility’s gas transmission operations (including review of the Utility’s compliance with the remedies ordered by the Penalty Decision) and to perform annual audits (for a minimum of ten years) of the Utility’s record-keeping practices. The Utility could incur material charges, including fines and other penalties, depending on the outcome of these future audits.

The ultimate financial impact of the Penalty Decision also could be affected by the tax treatment of the costs the Utility incurs to comply with the Penalty Decision. Although proposed state legislation to prohibit the Utility from claiming state tax deductions for charges associated with the Penalty Decision was defeated in September 2015, similar legislation may be passed in the future.

The Utility could incur material charges, including fines and other penalties, in connection with the CPUC’s investigation of the Utility’s compliance with natural gas distribution record-keeping practices, and the self-reports the Utility has submitted to the CPUC in accordance with the SED’s safety citation program, and the Utility’s efforts to identify and remove encroachments from transmission pipeline rights of way.

The CPUC has not yet taken action with respect to the City of San Bruno’s allegations that the Utility violated the CPUC’s rules regarding ex parte communications, or with respect to the Utility’s self-reports about communications that may constitute or describe ex parte communications. Federal and state law enforcement authorities also have begun investigations in connection with these matters. The CPUC, or federal or state law enforcement authorities, could take enforcement action against the Utility with respect to these matters, and additional fines or penalties could be imposed on the Utility which could materially affect PG&E Corporation’s and the Utility’s financial results.

If the Utility is convicted of federal criminal charges, the Utility could be required to pay fines. Based on the superseding indictment’s allegations, the maximum alternative fine would be approximately $1.13 billion. The Utility also could incur a material amount of costs to comply with remedial measures that may be imposed on the Utility, such as a requirement that the Utility’s natural gas operations be supervised by a third-party monitor. The Utility was informed that the U.S. Attorney’s Office was 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 related to the indicted case discussed above. It is uncertain whether any additional charges will be brought against the Utility.

Further, the CPUC has begun a new investigation to examine the Utility’s safety culture and practices and has directed the SED to engage a consultant to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents. Although the initial phase of the proceeding has been categorized as rate setting, the assigned Commissioner will determine the scope of and next actions in the proceeding following the completion of the consultant’s report. The timing, scope and potential outcome of the investigation and successor proceedings are uncertain.

PG&E Corporation and the Utility may incur material liability in connection with the ~~recent wildfires in Northern California.~~Butte fire.

~~In September 2015, a wildfire (known as~~On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the “Butte ~~fire”)~~fire,” the wildfire that ignited and spread in Amador and Calaveras Counties in Northern ~~California. Although~~California in September 2015. Cal Fire’s report concluded that the ~~cause~~wildfire was caused when a Gray Pine tree contacted an electric line of the ~~fire has not yet been~~Utility, which ignited portions of the tree, and determined that the failure by the Utility ~~could incur material liability~~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.

In connection with the Butte fire, approximately 32 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 1,300 individual plaintiffs and their insurance companies. The number of complaints may increase in the future. PG&E Corporation’s and the Utility’s financial statements for ~~claims from third parties, including claims~~the period ended March 31, 2016 reflect a provision of $350 million for property ~~damage, fire suppression costs, personal injury,~~damages in connection with this matter. 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 ~~claims. If insurance recoveries are unavailable~~property damage. A change in management’s estimates or ~~insufficient to cover such losses,~~assumptions could result in an adjustment that could have a material impact on PG&E Corporation’s and the Utility’s financial condition orand results of operations during the period in which such change occurred. The Utility also could incur material charges related to fire suppression, personal injury damages and other damages.

The Utility has insurance coverage for third party claims. If the amount of insurance is insufficient to cover such losses, 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.

The Utility also could be subject to material fines, or penalties or disallowances if the CPUC or other law enforcement agency brought enforcement action against the Utility.

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

During the quarter ended ~~September 30, 2015,~~March 31, 2016, PG&E Corporation made equity contributions totaling ~~$420~~$65 million to the Utility in order to maintain the 52% common equity component of the Utility’s CPUC-authorized capital structure. Neither PG&E Corporation nor the Utility made any sales of unregistered equity securities during the quarter ended ~~September 30, 2015.~~March 31, 2016.

Issuer Purchases of Equity Securities

During the quarter ended ~~September 30, 2015,~~March 31, 2016, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the quarter ended ~~September 30, 2015,~~March 31, 2016, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends

The Utility’s earnings to fixed charges ratio for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 was ~~1.88. The~~0.75.The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 was ~~1.86.~~0.74. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility’s Registration Statement No. 333-193879.

PG&E Corporation’s earnings to fixed charges ratio for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 was ~~1.87.~~0.75. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-193880.

ITEM 6. EXHIBITS

3	Bylaws of PG&E Corporation amended as of February 17, 2016

4	Twenty-Seventh Supplemental Indenture, dated as of March 1, 2016, relating to the issuance of $600,000,000 aggregate principal amount of Pacific Gas and Electric ~~Company amended as of August 17, 2015~~Company’s 2.95% Senior Notes due March 1, 2026 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on ~~July 14, 2015~~March 1, 2016 (File No. 1-2348), Exhibit ~~99.2)~~4.1)

*10.1	~~Amended and Restated PG&E Corporation Director Grantor Trust~~Term Loan Agreement, dated ~~October 1, 2015~~as of March 2, 2016, between Pacific Gas and Electric Company and The Bank of Tokyo-Mitsubishi UFJ, Ltd. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on March 4, 2016 (File No. 1-2348), Exhibit 10.1)

*10.2	~~Amended~~Restricted Stock Unit Agreement between Dinyar Mistry and ~~Restated~~ PG&E Corporation ~~Officer Grantor Trust Agreement~~ dated ~~October 1, 2015~~February 23, 2016

*10.3	~~PG&E Corporation 2005 Supplemental Retirement Savings~~Separation agreement between Pacific Gas and Electric Company and Greg Kiraly dated February 18, 2016

*10.4	Amendment to the Postretirement Life Insurance Plan ~~as amended~~of the Pacific Gas and Electric Company, effective ~~September 15, 2015~~February 16, 2016

12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

31.1	Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

**32.1	Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

**32.2	Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB	XBRL Taxonomy Extension Labels Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

*Management contract or compensatory agreement.

**Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

PG&E CORPORATION

~~KENT M. HARVEY~~/s/ JASON P. WELLS

~~Kent M. Harvey~~Jason P. Wells
Senior Vice President and Chief Financial Officer
(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

/s/ DINYAR B. MISTRY

Dinyar B. Mistry

Senior Vice President, Human Resources, Chief Financial Officer and Controller

(duly authorized officer and principal financial officer)

Dated: ~~October 28, 2015~~May 4, 2016

EXHIBIT INDEX

3	Bylaws of PG&E Corporation amended as of February 17, 2016

4	Twenty-Seventh Supplemental Indenture, dated as of March 1, 2016, relating to the issuance of $600,000,000 aggregate principal amount of Pacific Gas and Electric ~~Company amended as of August 17, 2015~~Company’s 2.95% Senior Notes due March 1, 2026 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on ~~July 14, 2015~~March 1, 2016 (File No. 1-2348), Exhibit ~~99.2)~~4.1)

*10.1	~~Amended and Restated PG&E Corporation Director Grantor Trust~~Term Loan Agreement, dated ~~October 1, 2015~~as of March 2, 2016, between Pacific Gas and Electric Company and The Bank of Tokyo-Mitsubishi UFJ, Ltd. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on March 4, 2016 (File No. 1-2348), Exhibit 10.1)

*10.2	~~Amended~~Restricted Stock Unit Agreement between Dinyar Mistry and ~~Restated~~ PG&E Corporation ~~Officer Grantor Trust Agreement~~ dated ~~October 1, 2015~~February 23, 2016

*10.3	~~PG&E Corporation 2005 Supplemental Retirement Savings~~Separation agreement between Pacific Gas and Electric Company and Greg Kiraly dated February 18, 2016

*10.4	Amendment to the Postretirement Life Insurance Plan ~~as amended~~of the Pacific Gas and Electric Company, effective ~~September 15, 2015~~February 16, 2016

12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

31.1	Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

**32.1	Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

**32.2	Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB	XBRL Taxonomy Extension Labels Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document