Edgar Filing: PUBLIC SERVICE ENTERPRISE GROUP INC

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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED September 30, 2017

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO



Commission File Number	Registrants, State of Incorporation, Address, and Telephone Number	I.R.S. Employer Identification No.
001-09120	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza Newark, New Jersey 07102 973 430-7000 http://www.pseg.com	22-2625848
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza Newark, New Jersey 07102 973 430-7000 http://www.pseg.com	22-1212800
001-34232	PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza Newark, New Jersey 07102 973 430-7000 http://www.pseg.com	22-3663480

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes ý No ¨

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Public Service Enterprise Group Incorporated	Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company o

Public Service Electric and Gas Company	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o	Emerging growth company o

PSEG Power LLC	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o	Emerging growth company o

If any of the registrants is an emerging growth company, indicate by check mark if such registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

As of October 17, 2017, Public Service Enterprise Group Incorporated had outstanding 506,038,791 shares of its sole class of Common Stock, without par value.

As of October 17, 2017, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.

Public Service Electric and Gas Company and PSEG Power LLC are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q. Each is filing its Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.

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		Page
FORWARD-LOOKING STATEMENTS		ii
FILING FORMAT		iii
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated	1
	Public Service Electric and Gas Company	6
	PSEG Power LLC	11
	Notes to Condensed Consolidated Financial Statements
	Note 1. Organization and Basis of Presentation	16
	Note 2. Recent Accounting Standards	16
	Note 3. Early Plant Retirements	19
	Note 4. Variable Interest Entity (VIE)	21
	Note 5. Rate Filings	21
	Note 6. Financing Receivables	22
	Note 7. Available-for-Sale Securities	25
	Note 8. Pension and Other Postretirement Benefits (OPEB)	30
	Note 9. Commitments and Contingent Liabilities	32
	Note 10. Debt and Credit Facilities	40
	Note 11. Financial Risk Management Activities	41
	Note 12. Fair Value Measurements	46
	Note 13. Other Income and Deductions	54
	Note 14. Income Taxes	55
	Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax	56
	Note 16. Earnings Per Share (EPS) and Dividends	60
	Note 17. Financial Information by Business Segments	61
	Note 18. Related-Party Transactions	62
	Note 19. Guarantees of Debt	64
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	67
	Executive Overview of 2017 and Future Outlook	67
	Results of Operations	75
	Liquidity and Capital Resources	80
	Capital Requirements	82
	Accounting Matters	82
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	82
Item 4.	Controls and Procedures	83

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	83
Item 1A.	Risk Factors	83
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	84
Item 5.	Other Information	85
Item 6.	Exhibits	89
	Signatures	90

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FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report about our and our subsidiaries’ future performance, including, without limitation, future revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in filings we make with the United States Securities and Exchange Commission (SEC), including our Annual Report on Form 10-K and subsequent reports on Form 10-Q and Form 8-K. These factors include, but are not limited to:


•	fluctuations in wholesale power and natural gas markets, including the potential impacts on the economic viability of our generation units;


•	our ability to obtain adequate fuel supply;


•	any inability to manage our energy obligations with available supply;


•	increases in competition in wholesale energy and capacity markets;


•	changes in technology related to energy generation, distribution and consumption and customer usage patterns;


•	economic downturns;


•	third-party credit risk relating to our sale of generation output and purchase of fuel;


•	adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in funding requirements;


•	changes in state and federal legislation and regulations;


•	the impact of pending rate case proceedings;


•	regulatory, financial, environmental, health and safety risks associated with our ownership and operation of nuclear facilities;


•	adverse changes in energy industry laws, policies and regulations, including market structures and transmission planning;


•	changes in federal and state environmental regulations and enforcement;


•	delays in receipt of, or an inability to receive, necessary licenses and permits;


•	adverse outcomes of any legal, regulatory or other proceeding, settlement, investigation or claim applicable to us and/or the energy industry;


•	changes in tax laws and regulations;


•	the impact of our holding company structure on our ability to meet our corporate funding needs, service debt and pay dividends;


•	lack of growth or slower growth in the number of customers or changes in customer demand;


•	any inability of Power to meet its commitments under forward sale obligations;


•	reliance on transmission facilities that we do not own or control and the impact on our ability to maintain adequate transmission capacity;


•	any inability to successfully develop or construct generation, transmission and distribution projects;


•	any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers;


•	our inability to exercise control over the operations of generation facilities in which we do not maintain a controlling interest;

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•	any inability to maintain sufficient liquidity;


•	any inability to realize anticipated tax benefits or retain tax credits;


•	challenges associated with recruitment and/or retention of key executives and a qualified workforce;


•	the impact of our covenants in our debt instruments on our operations; and


•	the impact of acts of terrorism, cybersecurity attacks or intrusions.

All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected consequences to, or effects on, us or our business, prospects, financial condition, results of operations or cash flows. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report apply only as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even in light of new information or future events, unless otherwise required by applicable securities laws.

The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.

FILING FORMAT

This combined Quarterly Report on Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power). Information relating to any individual company is filed by such company on its own behalf. PSE&G and Power are each only responsible for information about itself and its subsidiaries.

Discussions throughout the document refer to PSEG and its direct operating subsidiaries, PSE&G and Power. Depending on the context of each section, references to “we,” “us,” and “our” relate to PSEG or to the specific company or companies being discussed.

iii

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions, except per share data

(Unaudited)




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
OPERATING REVENUES	$	2,263		$	2,450		$	6,988		$	6,971
OPERATING EXPENSES
Energy Costs	638			866			2,100			2,326
Operation and Maintenance	680			776			2,100			2,215
Depreciation and Amortization	252			231			1,721			679
Total Operating Expenses	1,570			1,873			5,921			5,220
OPERATING INCOME	693			577			1,067			1,751
Income from Equity Method Investments	3			3			11			9
Other Income	66			47			208			139
Other Deductions	(10		)	(8		)	(30		)	(39		)
Other-Than-Temporary Impairments	(5		)	(5		)	(9		)	(25		)
Interest Expense	(100		)	(99		)	(289		)	(288		)
INCOME BEFORE INCOME TAXES	647			515			958			1,547
Income Tax Expense	(252		)	(188		)	(340		)	(562		)
NET INCOME	$	395		$	327		$	618		$	985
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			505			505			505
DILUTED	507			508			507			508
NET INCOME PER SHARE:
BASIC	$	0.78		$	0.65		$	1.22		$	1.95
DILUTED	$	0.78		$	0.64		$	1.22		$	1.94
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.43		$	0.41		$	1.29		$	1.23

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)




	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2017			2016		2017			2016
NET INCOME	$	395		$	327	$	618		$	985
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(15), $(24), $(40) and $(50) for the three and nine months ended 2017 and 2016, respectively	17			24		42			50
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $0 and $(1) for the three and nine months ended 2017 and 2016, respectively	(1		)	1		(1		)	2
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(4), $(5), $(12) and $(17) for the three and nine months ended 2017 and 2016, respectively	6			9		18			25
Other Comprehensive Income (Loss), net of tax	22			34		59			77
COMPREHENSIVE INCOME	$	417		$	361	$	677		$	1,062

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	278		$	423
Accounts Receivable, net of allowances of $59 in 2017 and $68 in 2016	1,022			1,161
Tax Receivable	127			78
Unbilled Revenues	176			260
Fuel	348			326
Materials and Supplies, net	588			561
Prepayments	200			76
Derivative Contracts	84			163
Regulatory Assets	239			199
Other	19			7
Total Current Assets	3,081			3,254
PROPERTY, PLANT AND EQUIPMENT	39,916			39,337
Less: Accumulated Depreciation and Amortization	(9,383		)	(10,051		)
Net Property, Plant and Equipment	30,533			29,286
NONCURRENT ASSETS
Regulatory Assets	3,336			3,319
Long-Term Investments	936			1,050
Nuclear Decommissioning Trust (NDT) Fund	2,012			1,859
Long-Term Tax Receivable	—			104
Long-Term Receivable of Variable Interest Entity (VIE)	599			589
Other Special Funds	229			217
Goodwill	16			16
Other Intangibles	88			98
Derivative Contracts	62			24
Other	265			254
Total Noncurrent Assets	7,543			7,530
TOTAL ASSETS	$	41,157		$	40,070

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2017			December 31, 2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	1,250		$	500
Commercial Paper and Loans	202			388
Accounts Payable	1,305			1,459
Derivative Contracts	7			13
Accrued Interest	136			97
Accrued Taxes	146			31
Clean Energy Program	184			142
Obligation to Return Cash Collateral	132			132
Regulatory Liabilities	44			88
Other	425			426
Total Current Liabilities	3,831			3,276
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,931			8,658
Regulatory Liabilities	89			118
Asset Retirement Obligations	748			726
OPEB Costs	1,301			1,324
OPEB Costs of Servco	474			452
Accrued Pension Costs	504			568
Accrued Pension Costs of Servco	113			128
Environmental Costs	399			401
Derivative Contracts	1			3
Long-Term Accrued Taxes	173			180
Other	195			211
Total Noncurrent Liabilities	12,928			12,769
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT	11,274			10,895
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016—534 shares	4,938			4,936
Treasury Stock, at cost, 2017 and 2016—29 shares	(750		)	(717		)
Retained Earnings	9,140			9,174
Accumulated Other Comprehensive Loss	(204		)	(263		)
Total Stockholders’ Equity	13,124			13,130
Total Capitalization	24,398			24,025
TOTAL LIABILITIES AND CAPITALIZATION	$	41,157		$	40,070

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)




	Nine Months Ended
	September 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	618		$	985
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,721			679
Amortization of Nuclear Fuel	152			154
Renewable Energy Credit (REC) Compliance Accrual	79			87
Impairment Costs for Early Plant Retirements	—			102
Provision for Deferred Income Taxes (Other than Leases) and ITC	227			445
Non-Cash Employee Benefit Plan Costs	67			95
Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes	(7		)	(12		)
Net (Gain) Loss on Lease Investments	48			86
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	8			96
Net Change in Regulatory Assets and Liabilities	(121		)	(72		)
Cost of Removal	(72		)	(109		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(86		)	(12		)
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	64			282
Accrued Taxes	115			202
Margin Deposit	64			(4		)
Other Current Assets and Liabilities	(69		)	(229		)
Employee Benefit Plan Funding and Related Payments	(64		)	(81		)
Other	(10		)	67
Net Cash Provided By (Used In) Operating Activities	2,734			2,761
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(3,046		)	(2,985		)
Purchase of Emissions Allowances and RECs	(90		)	(77		)
Proceeds from Sales of Available-for-Sale Securities	1,013			551
Investments in Available-for-Sale Securities	(1,029		)	(576		)
Other	48			33
Net Cash Provided By (Used In) Investing Activities	(3,104		)	(3,054		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(186		)	(109		)
Issuance of Long-Term Debt	1,125			1,975
Redemption of Long-Term Debt	—			(824		)
Cash Dividends Paid on Common Stock	(652		)	(622		)
Other	(62		)	(71		)
Net Cash Provided By (Used In) Financing Activities	225			349
Net Increase (Decrease) in Cash and Cash Equivalents	(145		)	56
Cash and Cash Equivalents at Beginning of Period	423			394
Cash and Cash Equivalents at End of Period	$	278		$	450
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(16	)	$	(274	)
Interest Paid, Net of Amounts Capitalized	$	261		$	252
Accrued Property, Plant and Equipment Expenditures	$	604		$	579

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
OPERATING REVENUES	$	1,509		$	1,684		$	4,689		$	4,746
OPERATING EXPENSES
Energy Costs	535			721			1,760			1,979
Operation and Maintenance	346			376			1,064			1,110
Depreciation and Amortization	169			137			506			412
Total Operating Expenses	1,050			1,234			3,330			3,501
OPERATING INCOME	459			450			1,359			1,245
Other Income	23			22			70			61
Other Deductions	(1		)	(1		)	(3		)	(3		)
Interest Expense	(79		)	(72		)	(223		)	(214		)
INCOME BEFORE INCOME TAXES	402			399			1,203			1,089
Income Tax Expense	(156		)	(144		)	(450		)	(393		)
NET INCOME	$	246		$	255		$	753		$	696

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017			2016
NET INCOME	$	246	$	255	$	753		$	696
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $0, $1 and $0 for the three and nine months ended 2017 and 2016, respectively	—		—		(1		)	1
COMPREHENSIVE INCOME	$	246	$	255	$	752		$	697

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	239		$	390
Accounts Receivable, net of allowances of $59 in 2017 and $68 in 2016	762			810
Accounts Receivable—Affiliated Companies	—			76
Unbilled Revenues	176			260
Materials and Supplies	196			180
Prepayments	115			9
Regulatory Assets	239			199
Other	18			6
Total Current Assets	1,745			1,930
PROPERTY, PLANT AND EQUIPMENT	28,301			26,347
Less: Accumulated Depreciation and Amortization	(6,019		)	(5,760		)
Net Property, Plant and Equipment	22,282			20,587
NONCURRENT ASSETS
Regulatory Assets	3,336			3,319
Long-Term Investments	283			299
Other Special Funds	46			43
Other	110			110
Total Noncurrent Assets	3,775			3,771
TOTAL ASSETS	$	27,802		$	26,288

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2017		December 31, 2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	750	$	—
Accounts Payable	624		718
Accounts Payable—Affiliated Companies	178		260
Accrued Interest	89		76
Clean Energy Program	184		142
Derivative Contracts	—		5
Obligation to Return Cash Collateral	132		132
Regulatory Liabilities	44		88
Other	278		296
Total Current Liabilities	2,279		1,717
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	6,408		5,873
OPEB Costs	977		1,009
Accrued Pension Costs	209		250
Regulatory Liabilities	89		118
Environmental Costs	325		332
Asset Retirement Obligations	216		213
Long-Term Accrued Taxes	83		130
Other	109		116
Total Noncurrent Liabilities	8,416		8,041
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT	7,493		7,818
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2017 and 2016—132 shares	892		892
Contributed Capital	1,095		945
Basis Adjustment	986		986
Retained Earnings	6,641		5,888
Accumulated Other Comprehensive Income	—		1
Total Stockholder’s Equity	9,614		8,712
Total Capitalization	17,107		16,530
TOTAL LIABILITIES AND CAPITALIZATION	$	27,802	$	26,288

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)




	Nine Months Ended
	September 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	753		$	696
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	506			412
Provision for Deferred Income Taxes and ITC	497			482
Non-Cash Employee Benefit Plan Costs	37			55
Cost of Removal	(72		)	(109		)
Net Change in Other Regulatory Assets and Liabilities	(121		)	(72		)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	136			2
Materials and Supplies	(13		)	(42		)
Prepayments	(106		)	(63		)
Accounts Payable	(37		)	(30		)
Accounts Receivable/Payable—Affiliated Companies, net	(61		)	154
Other Current Assets and Liabilities	(12		)	(6		)
Employee Benefit Plan Funding and Related Payments	(55		)	(64		)
Other	(59		)	(14		)
Net Cash Provided By (Used In) Operating Activities	1,393			1,401
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,118		)	(2,035		)
Proceeds from Sales of Available-for-Sale Securities	33			16
Investments in Available-for-Sale Securities	(34		)	(17		)
Solar Loan Investments	(2		)	—
Other	7			6
Net Cash Provided By (Used In) Investing Activities	(2,114		)	(2,030		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	—			(153		)
Issuance of Long-Term Debt	425			1,275
Redemption of Long-Term Debt	—			(271		)
Contributed Capital	150			—
Other	(5		)	(14		)
Net Cash Provided By (Used In) Financing Activities	570			837
Net Increase (Decrease) In Cash and Cash Equivalents	(151		)	208
Cash and Cash Equivalents at Beginning of Period	390			198
Cash and Cash Equivalents at End of Period	$	239		$	406
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(107	)	$	(279	)
Interest Paid, Net of Amounts Capitalized	$	208		$	194
Accrued Property, Plant and Equipment Expenditures	$	363		$	404

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.

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PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
OPERATING REVENUES	$	873		$	1,075		$	3,086		$	3,102
OPERATING EXPENSES
Energy Costs	357			462			1,461			1,481
Operation and Maintenance	227			289			711			807
Depreciation and Amortization	76			86			1,191			245
Total Operating Expenses	660			837			3,363			2,533
OPERATING INCOME (LOSS)	213			238			(277		)	569
Income from Equity Method Investments	3			3			11			9
Other Income	43			23			127			74
Other Deductions	(8		)	(6		)	(22		)	(33		)
Other-Than-Temporary Impairments	(5		)	(5		)	(9		)	(25		)
Interest Expense	(12		)	(24		)	(41		)	(66		)
INCOME (LOSS) BEFORE INCOME TAXES	234			229			(211		)	528
Income Tax Benefit (Expense)	(98		)	(90		)	80			(208		)
NET INCOME (LOSS)	$	136		$	139		$	(131	)	$	320

See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.

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PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Millions

(Unaudited)




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017			2016
NET INCOME (LOSS)	$	136	$	139	$	(131	)	$	320
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(14), $(23), $(41) and $(48) for the three and nine months ended 2017 and 2016, respectively	15		22		44			47
Pension/OPEB adjustment, net of tax (expense) benefit of $(4), $(5), $(11) and $(15) for the three and nine months ended 2017 and 2016, respectively	5		7		15			21
Other Comprehensive Income (Loss), net of tax	20		29		59			68
COMPREHENSIVE INCOME (LOSS)	$	156	$	168	$	(72	)	$	388

See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.

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PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	22		$	11
Accounts Receivable	206			276
Accounts Receivable—Affiliated Companies	86			205
Short-Term Loan to Affiliate	1			87
Fuel	348			326
Materials and Supplies, net	391			381
Derivative Contracts	84			162
Prepayments	20			10
Other	4			2
Total Current Assets	1,162			1,460
PROPERTY, PLANT AND EQUIPMENT	11,256			12,655
Less: Accumulated Depreciation and Amortization	(3,184		)	(4,135		)
Net Property, Plant and Equipment	8,072			8,520
NONCURRENT ASSETS
NDT Fund	2,012			1,859
Long-Term Investments	90			102
Goodwill	16			16
Other Intangibles	88			98
Other Special Funds	57			53
Derivative Contracts	62			24
Other	72			61
Total Noncurrent Assets	2,397			2,213
TOTAL ASSETS	$	11,631		$	12,193

See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.

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PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2017			December 31, 2016
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts Payable	$	499		$	539
Accounts Payable—Affiliated Companies	128			25
Derivative Contracts	7			8
Accrued Interest	43			20
Other	87			88
Total Current Liabilities	764			680
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	1,962			2,170
Asset Retirement Obligations	530			511
OPEB Costs	258			251
Derivative Contracts	1			3
Accrued Pension Costs	174			191
Long-Term Accrued Taxes	57			77
Other	123			129
Total Noncurrent Liabilities	3,105			3,332
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
LONG-TERM DEBT	2,385			2,382
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,301			4,782
Accumulated Other Comprehensive Loss	(152		)	(211		)
Total Member’s Equity	5,377			5,799
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,631		$	12,193

See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.

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PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)




	Nine Months Ended
	September 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(131	)	$	320
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,191			245
Amortization of Nuclear Fuel	152			154
Provision for Deferred Income Taxes and ITC	(259		)	(34		)
Interest Accretion on Asset Retirement Obligation	23			20
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	8			96
Impairment Costs for Early Plant Retirements	—			102
Renewable Energy Credit (REC) Compliance Accrual	79			87
Non-Cash Employee Benefit Plan Costs	21			28
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(86		)	(12		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	(32		)	(27		)
Margin Deposit	64			(4		)
Accounts Receivable	19			(11		)
Accounts Payable	(32		)	(29		)
Accounts Receivable/Payable—Affiliated Companies, net	205			235
Other Current Assets and Liabilities	11			20
Employee Benefit Plan Funding and Related Payments	(5		)	(10		)
Other	21			80
Net Cash Provided By (Used In) Operating Activities	1,249			1,260
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(903		)	(923		)
Purchase of Emissions Allowances and RECs	(90		)	(77		)
Proceeds from Sales of Available-for-Sale Securities	886			490
Investments in Available-for-Sale Securities	(900		)	(512		)
Short-Term Loan—Affiliated Company, net	86			(151		)
Other	37			22
Net Cash Provided By (Used In) Investing Activities	(884		)	(1,151		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	—			700
Cash Dividend Paid	(350		)	(250		)
Redemption of Long-Term Debt	—			(553		)
Other	(4		)	(6		)
Net Cash Provided By (Used In) Financing Activities	(354		)	(109		)
Net Increase (Decrease) in Cash and Cash Equivalents	11			—
Cash and Cash Equivalents at Beginning of Period	11			12
Cash and Cash Equivalents at End of Period	$	22		$	12
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	75		$	(7	)
Interest Paid, Net of Amounts Capitalized	$	30		$	51
Accrued Property, Plant and Equipment Expenditures	$	241		$	175

See disclosures regarding PSEG Power LLC included in the Notes to the Condensed Consolidated Financial Statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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Note 1. Organization and Basis of Presentation

Organization

Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are:

•

Public Service Electric and Gas Company (PSE&G)—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and related programs in New Jersey, which are regulated by the BPU.

•

PSEG Power LLC (Power)—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under an Operations Services Agreement (OSA); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Basis of Presentation

The financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 2016.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2016.

Note 2. Recent Accounting Standards

New Standard Issued and Adopted

Business Combinations: Clarifying the Definition of a Business

This accounting standard was issued mainly to provide more consistency in how the definition of a business is applied to acquisitions or dispositions. The new guidance will generally reduce the number of transactions that will require treatment as a business combination. The definition of a business now includes consideration of whether substantially all the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets. If this condition is met, the transaction would not qualify as a business.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG adopted this standard in the third quarter 2017 with the acquisition of a solar project. This standard upon adoption had no impact on PSEG’s financial statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

This accounting standard clarifies the principles for recognizing revenue and removes inconsistencies in revenue recognition requirements; improves comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provides improved disclosures.

The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services.

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance and possible changes in presentation. Included in the scope of the new standard are PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the distribution of electricity and gas to retail residential and commercial and industrial customers, and transmission revenues. The tariff revenue comprises substantially all of PSE&G’s revenue. PSEG expects no material change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. PSE&G’s revenue from contracts with customers will continue to be recorded as electricity or gas is delivered to the customer. PSEG continues to evaluate contracts under its other revenue streams.

Certain implementation issues are currently being finalized by the AICPA’s Financial Reporting Executive Committee, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. While those issues are out for comment, based on tentative conclusions PSEG does not expect any material changes to its revenue due to those issues. PSEG will adopt this standard on January 1, 2018 and anticipates electing the full retrospective method of transition. Under this method, PSEG will restate its prior period financial statements to align with the 2018 presentation. Certain reclassifications may affect revenue and expense due to the application of this standard; however, PSEG does not anticipate any material impact to net income.

Recognition and Measurement of Financial Assets and Financial Liabilities

This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under the equity method. Under the new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard also changes certain disclosures.

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG expects to record a cumulative effect adjustment by reclassifying the after-tax net unrealized gain (loss) related to equity investments from Accumulated Other Comprehensive Income to Retained Earnings as of January 1, 2018, and expects increased volatility in Net Income due to changes in fair value of its equity securities within the nuclear decommissioning (NDT) and Rabbi Trust Funds.

Leases

This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.

The standard is effective for annual and interim periods beginning after December 15, 2018 with retrospective application to previously issued financial statements for 2018 and 2017. Early application is permitted. PSEG is currently analyzing the impact of this standard on its financial statements.

Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

This accounting standard’s amendments more closely align hedge accounting with the companies’ risk management activities in the financial statements. The amendments expand hedge accounting for both non-financial and financial risk components by

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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permitting contractually specified components to designate as the hedged risk in a cash flow hedge involving the purchase or sale of non-financial assets or variable rate financial instruments. Additionally, the amendments ease the operational burden of applying hedge accounting by allowing more time to prepare hedge documentation, and allow effectiveness assessments to be performed on a qualitative basis after hedge inception.

The new guidance is effective for annual and interim periods beginning after December 15, 2018. The standard requires using a modified retrospective method upon adoption. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on its consolidated financial statements.

Measurement of Credit Losses on Financial Instruments

This accounting standard provides a new model for recognizing credit losses on financial assets carried at amortized cost. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale securities should be measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination.

The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG does not anticipate any current impact on PSEG’s financial statements. PSEG will adopt this standard as of January 1, 2018 using a retrospective transition method to each period presented.

Statement of Cash Flows: Restricted Cash

This accounting standard requires entities to explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents, either in a narrative or a tabular format. Amounts generally described as restricted cash or restricted cash equivalents should be included in entities’ reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG plans to adopt this standard on January 1, 2018 using a retrospective transition method for each period presented. PSEG will continue the current balance sheet classification of restricted cash or restricted cash equivalents. PSEG will provide a reconciliation of cash and cash equivalents and restricted cash or restricted cash equivalents and include a description of these amounts.

Simplifying the Test for Goodwill Impairment

This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.

An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)

This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.

Under the new guidance, entities are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by their employees during the period. The other components of net benefit

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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cost are required to be presented in the Statement of Operations separately from the service cost component after Operating Income. Additionally, only the service cost component will be eligible for capitalization, when applicable.

The standard requires the amendments to be applied retrospectively for the presentation of the service cost component and the other cost components of net periodic pension cost and net periodic OPEB cost in the Statement of Operations and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension and OPEB costs.

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. PSEG is currently analyzing the impact of this standard on its financial statements.

Premium Amortization on Purchased Callable Debt Securities

This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.

The standard is effective for annual and interim reporting periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period. If an entity early adopts the standard in an interim period, any

adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity should apply this standard on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Additionally, in the period of adoption, an entity should provide disclosures about a change in accounting principle. PSEG is currently analyzing the impact of this standard on its financial statements.

Stock Compensation - Scope of Modification Accounting

This accounting standard provides clarity and reduces both diversity in practice and complexity when applying the stock compensation guidance to a change in the terms or conditions of a stock-based payment award. Specifically, the standard provides guidance as to which changes to the terms or conditions of a stock-based payment award require an entity to apply modification accounting.

The standard is effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, including adoption in any interim period, for reporting periods for which financial statements have not yet been issued. This standard should be applied prospectively to an award modified on or after the adoption date. PSEG plans to adopt this standard effective January 1, 2018.

Note 3. Early Plant Retirements

Fossil

In October 2016, Power determined that it would cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Both units were available to operate through May 31, 2017 and were subsequently retired from operation on June 1, 2017.

In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and Operation and Maintenance (O&M) of $62 million and $53 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shut down items. In addition to these charges, Power recognized Depreciation and Amortization (D&A) during 2016 of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer.

As of June 1, 2017, Power recognized total D&A of $964 million for the Hudson and Mercer units to reflect the end of their economic useful lives in 2017. In the three and nine months ended September 30, 2017, Power recognized pre-tax charges in Energy Costs of $1 million and $10 million, respectively, primarily for coal inventory lower of cost or market adjustments. For the three and nine months ended September 30, 2017, Power also recognized pre-tax charges in O&M of $8 million and $12 million, respectively, of shut down costs and an increase in the Asset Retirement Obligation due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such environmental remediation are neither currently probable nor estimable but may be material.

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As of December 31, 2016, Power had reduced the estimated useful life of Bridgeport Harbor Station unit 3 (BH3) from 2025 to the summer of 2021 as it was more likely than not it will retire the unit by this time.

PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the held for use classification of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.

Nuclear

Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. This situation is generally due to the decline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.

If the market trends noted above continue or worsen, Power’s New Jersey nuclear generating units could cease being economically competitive which may cause Power to retire such units prior to the end of their useful lives. The costs associated with any such potential retirement, which may include, among other things, accelerated D&A or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs, and additional funding of the NDT Fund would likely have a material adverse impact on PSEG’s and Power’s future financial results and cash flows. PSEG and Power continue to advocate for sound policies that recognize nuclear power as a source of reliable clean energy, free of air emissions and an important part of a diverse and reliable energy portfolio.

The following table provides the balance sheet amounts by generating station as of September 30, 2017 for significant assets and liabilities associated with Power’s owned share of its nuclear assets.




	As of September 30, 2017
	Hope Creek			Salem			Support Facilities and Other (A)		Peach Bottom
	Millions
Assets
Materials and Supplies Inventory	$	85		$	81		$	—	$	41
Nuclear Production, net of Accumulated Depreciation	452			557			204		753
Nuclear Fuel In-Service, net of Accumulated Depreciation	120			94			—		109
Construction Work in Progress (including nuclear fuel)	216			130			9		92
Total Assets	$	873		$	862		$	213	$	995
Liability
Asset Retirement Obligation	$	148		$	162		$	—	$	164
Total Liabilities	$	148		$	162		$	—	$	164
Net Assets	$	725		$	700		$	213	$	831
NRC License Renewal Term	2046			2036/2040			—		2033/2034
% Owned	100		%	57		%	—		50		%


(A)	Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital.

The precise timing of any potential early retirement and resulting financial statement impact may be affected by a number of factors, including co-owner considerations, the results of any transmission system reliability study assessments and

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decommissioning trust fund requirements and other commitments, as well as future energy prices. Power maintains a NDT Fund that funds its decommissioning obligations. See Note 7. Available-for-Sale Securities.

Note 4. Variable Interest Entity (VIE)

VIE for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates Long Island Electric Utility Servco, LLC (Servco), a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.

Pursuant to the OSA, Servco’s operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.

For transactions in which Servco acts as principal, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. Servco recorded $114 million and $116 million for the three months and $338 million and $315 million for the nine months ended September 30, 2017 and 2016, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Condensed Consolidated Statement of Operations.

Note 5. Rate Filings

This Note should be read in conjunction with Note 6. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2016.

In addition to items previously reported in the Annual Report on Form 10-K, significant regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows:

Transmission Formula Rate Filings—In June 2017, PSE&G filed its 2016 true-up adjustment pertaining to its transmission formula rates in effect for 2016. This resulted in an adjustment of $12 million more than the 2016 originally filed revenues.

In October 2017, the 2018 Annual Formula Rate update was filed with FERC and requests approximately $212 million in increased annual transmission revenue effective January 1, 2018, subject to true-up.

Gas System Modernization Program (GSMP)—In July of each year, PSE&G files with the BPU for base rate recovery of GSMP investments which include a return of and on its investment.

In October 2017, PSE&G submitted the planned update to its annual GSMP cost recovery petition, originally filed in July 2017, to include GSMP investments in service as of September 30, 2017. This filing seeks BPU approval to recover in gas base rates an annual revenue increase of $25 million effective January 1, 2018. This increase represents the return of and on investment for GSMP investments in service through September 30, 2017. This proceeding is ongoing.

Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment.

In June 2017, PSE&G submitted the planned update to its March Energy Strong cost recovery petition, originally filed in March 2017, to include Energy Strong investments in service as of May 31, 2017. This filing requested estimated annual increases in electric and gas revenues of $16 million and $2 million, respectively. In August 2017, the BPU approved these rate increases effective September 1, 2017.

In September 2017, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs placed in service from June 1, 2017 through November 30, 2017. The petition requests rates to be effective March 1, 2018, consistent with the BPU Order of approval of the

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Energy Strong program. The annualized requested increase in electric revenue requirement is approximately $9 million. This proceeding is ongoing.

Basic Gas Supply Services (BGSS)—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase in the BGSS rate from approximately 34 cents to 37 cents per therm effective October 1, 2017. In September 2017, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was increased.

Weather Normalization Clause—In April 2017, the BPU gave final approval to PSE&G’s petition to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period.

In June 2017, PSE&G filed a petition requesting approval to collect $55 million in total net deficiency revenues comprised of $31 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period and the remaining carryover balance of $24 million in net deficiency gas revenue from the 2015-2016 Winter Period. The deficiency gas revenue would be collected from customers over the 2017-2018 and 2018-2019 Winter Periods (October 1 through May 31). In September 2017, the BPU approved this petition on a provisional basis with rates effective October 1, 2017, allowing recovery during the 2017-2018 Winter Period.

Green Program Recovery Charges (GPRC)—In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extend the subprogram offerings and establish the residential energy efficiency sub-programs under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11th component of the GPRC rate effective September 1, 2017.

Each year PSE&G files with the BPU for annual recovery for the 11 combined components of its electric and gas Green Program investments which include a return on its investment and recovery of expenses.

In March 2017, the BPU gave final approval to PSE&G’s 2016 GPRC cost recovery petition to recover approximately $37 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved GPRC programs for the period October 1, 2016 through September 30, 2017. The rates were effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge.

In June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery of approximately $47 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU-approved programs for the period October 1, 2017 through September 30, 2018. This proceeding is ongoing.

Remediation Adjustment Charge (RAC)—In June 2017, the BPU approved PSE&G's filing with respect to its RAC 24 petition allowing recovery of $41 million effective July 10, 2017 related to net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016.

Note 6. Financing Receivables

PSE&G

PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. The loans are generally paid back with solar renewable energy certificates generated from the installed solar electric system. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which are considered “non-performing.”

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Outstanding Loans by Class of Customer
	As of		As of
Consumer Loans	September 30, 2017		December 31, 2016
	Millions
Commercial/Industrial	$	160	$	164
Residential	10		11
Total	$	170	$	175

Energy Holdings

Energy Holdings, through several of its indirect subsidiary companies, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Condensed Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Condensed Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Condensed Consolidated Balance Sheets.

During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the

NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements, negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016, calculated by comparing the gross investment in the leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million pre-tax charge for its best estimate of loss related to the leveraged lease receivables as a result of the current liquidity issues facing REMA, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of December 31, 2016.

During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as certain recent discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss related to the lease receivables, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of September 30, 2017.

In June 2017, GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. GenOn is a subsidiary of NRG Energy, Inc. and is the parent of REMA. REMA was not included in the GenOn filing. Energy Holdings continues to monitor the restructuring of GenOn and its possible impacts on REMA and continues to discuss the situation with GenOn. During the second quarter of 2017, Energy Holdings completed its review of estimated residual values embedded in its leveraged lease portfolio of generating assets and the outcome indicated that one of the residual value estimates was lower than the recorded residual value due to a further deterioration of market conditions and changes to operating cost estimates. This decline was determined to be other than temporary. As a result, a pre-tax write-down of $7 million was recorded in the quarter ended June 30, 2017. In addition, based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded an additional $15 million pre-tax charge for its current best estimate of loss related to lease receivables. The second quarter 2017 pre-tax write-down and additional charge were reflected in Operating Revenues and are included in Gross Investment in Leases for September 30, 2017.

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The following table shows Energy Holdings’ gross and net lease investment as of September 30, 2017 and December 31, 2016, respectively.




	As of			As of
	September 30, 2017			December 31, 2016
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	546		$	629
Estimated Residual Value of Leased Assets	326			346
Total Investment in Rental Receivables	872			975
Unearned and Deferred Income	(309		)	(326		)
Gross Investment in Leases	563			649
Deferred Tax Liabilities	(631		)	(674		)
Net Investment in Leases	$	(68	)	$	(25	)

The corresponding receivables associated with the lease portfolio are reflected in the following table, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings.




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating Standard & Poor’s (S&P) as of September 30, 2017
	As of September 30, 2017
	Millions
AA	$	15
BBB+ — BBB-	316
BB-	133
CCC-	82
Total	$	546

The “BB-” and the “CCC-” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of September 30, 2017, the gross investment in the leases of such assets, net of non-recourse debt, was $337 million ($(184) million, net of deferred taxes). A more detailed description of such assets under lease, as of September 30, 2017, is presented in the following table.




Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	133	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	84	64	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CCC-	REMA (A)
Conemaugh Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CCC-	REMA (A)
Shawville Station Units 1, 2, 3 and 4	PA	$	80	100	%	596	Gas	CCC-	REMA (A)


(A)	REMA’s parent company, GenOn, and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete.

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The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s restructuring process or the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments and continues to discuss the situation with GenOn. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service (IRS).

Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease.

Note 7. Available-for-Sale Securities

NDT Fund

Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power.

Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.




	As of September 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	706	$	331	$	(5	)	$	1,032
Debt Securities
Government	561		10		(4		)	567
Corporate	352		7		(1		)	358
Total Debt Securities	913		17		(5		)	925
Other Securities	55		—		—			55
Total NDT Available-for-Sale Securities	$	1,674	$	348	$	(10	)	$	2,012

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	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	705	$	263	$	(11	)	$	957
Debt Securities
Government	518		8		(6		)	520
Corporate	337		4		(4		)	337
Total Debt Securities	855		12		(10		)	857
Other Securities	44		—		—			44
Total NDT Available-for-Sale Securities (A)	$	1,604	$	275	$	(21	)	$	1,858


(A)	The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund.

The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.




	As of		As of
	September 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	11	$	8
Accounts Payable	$	5	$	5

The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months.




	As of September 30, 2017										As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months					Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	67	$	(5	)	$	—	$	—		$	120	$	(10	)	$	8	$	(1	)
Debt Securities
Government (B)	237		(2		)	62		(2		)	276		(6		)	4		—
Corporate (C)	60		—			36		(1		)	139		(3		)	15		(1		)
Total Debt Securities	297		(2		)	98		(3		)	415		(9		)	19		(1		)
Other Securities	3		—			—		—			—		—			—		—
NDT Available-for-Sale Securities	$	367	$	(7	)	$	98	$	(3	)	$	535	$	(19	)	$	27	$	(2	)


(A)	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2017.

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(B)

Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2017.

(C)

Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2017.

The proceeds from the sales of and the net realized gains on securities in the NDT Fund were:




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	Millions
Proceeds from NDT Fund Sales (A)	$	278		$	139		$	845		$	470
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	$	29		$	11		$	82		$	36
Gross Realized Losses	(5		)	(3		)	(14		)	(25		)
Net Realized Gains (Losses) on NDT Fund	$	24		$	8		$	68		$	11

(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.

The cost of these securities was determined on the basis of specific identification.

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $172 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of September 30, 2017.

The NDT available-for-sale debt securities held as of September 30, 2017 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	37
1 - 5 years	236
6 - 10 years	230
11 - 15 years	62
16 - 20 years	67
Over 20 years	293
Total NDT Available-for-Sale Debt Securities	$	925

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the nine months ended September 30, 2017, Other-Than-Temporary Impairments (OTTI) of$9 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be

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recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

Rabbi Trust

PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”

PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.




	As of September 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	22	$	1	$	—		$	23
Debt Securities
Government	82		2		—			84
Corporate	118		3		(1		)	120
Total Debt Securities	200		5		(1		)	204
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	224	$	6	$	(1	)	$	229




	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	11	$	—		$	22
Debt Securities
Government	105		—		(2		)	103
Corporate	92		1		(2		)	91
Total Debt Securities	197		1		(4		)	194
Other Securities	1		—		—			1
Total Rabbi Trust Available-for-Sale Securities	$	209	$	12	$	(4	)	$	217

The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.




	As of		As of
	September 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	2	$	5
Accounts Payable	$	—	$	3

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The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months.




	As of September 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	—	$	—		$	—	$	—	$	—	$	—		$	—	$	—
Debt Securities
Government (B)	25		—			3		—		60		(2		)	1		—
Corporate (C)	14		(1		)	4		—		46		(2		)	3		—
Total Debt Securities	39		(1		)	7		—		106		(4		)	4		—
Rabbi Trust Available-for-Sale Securities	$	39	$	(1	)	$	7	$	—	$	106	$	(4	)	$	4	$	—


(A)	Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors.

(B)

Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2017.

(C)

Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2017.

The proceeds from the sales of and the net realized gains (losses) on securities in the Rabbi Trust Fund were:




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	Millions
Proceeds from Rabbi Trust Sales (A)	$	24		$	20		$	168		$	81
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	—		$	2		$	17		$	5
Gross Realized Losses	(1		)	(2		)	(5		)	(4		)
Net Realized Gains (Losses) on Rabbi Trust	$	(1	)	$	—		$	12		$	1

(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.

The cost of these securities was determined on the basis of specific identification.

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains of $3 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of September 30, 2017.

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The Rabbi Trust available-for-sale debt securities held as of September 30, 2017 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	—
1 - 5 years	40
6 - 10 years	27
11 - 15 years	6
16 - 20 years	19
Over 20 years	112
Total Rabbi Trust Available-for-Sale Debt Securities	$	204

PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in an indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the nine months ended September 30, 2017, no OTTIs were recognized on securities in the Rabbi Trust. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:




	As of		As of
	September 30, 2017		December 31, 2016
	Millions
PSE&G	$	46	$	43
Power	57		53
Other	126		121
Total Rabbi Trust Available-for-Sale Securities	$	229	$	217

Note 8. Pension and Other Postretirement Benefits (OPEB)

PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria.

As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $12 million and $36 million for the three months and nine months, ended September 30, 2017, respectively, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.

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The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco.




	Pension Benefits						OPEB						Pension Benefits						OPEB
	Three Months Ended						Three Months Ended						Nine Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2017			2016			2017			2016			2017			2016			2017			2016
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	29		$	28		$	4		$	5		$	86		$	82		$	12		$	13
Interest Cost	51			50			15			15			153			151			47			44
Expected Return on Plan Assets	(98		)	(98		)	(8		)	(8		)	(295		)	(295		)	(25		)	(23		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(5		)	(3		)	(4		)	(14		)	(14		)	(8		)	(11		)
Actuarial Loss	24			39			13			10			73			118			38			30
Total Benefit Costs	$	1		$	14		$	21		$	18		$	3		$	42		$	64		$	53

Pension and OPEB costs for PSE&G, Power and PSEG’s other subsidiaries, excluding Servco, are detailed as follows:




	Pension Benefits					OPEB				Pension Benefits					OPEB
	Three Months Ended					Three Months Ended				Nine Months Ended					Nine Months Ended
	September 30,					September 30,				September 30,					September 30,
	2017			2016		2017		2016		2017			2016		2017		2016
	Millions
PSE&G	$	(1	)	$	8	$	13	$	11	$	(3	)	$	22	$	40	$	33
Power	—			3		7		6		1			11		20		17
Other	2			3		1		1		5			9		4		3
Total Benefit Costs	$	1		$	14	$	21	$	18	$	3		$	42	$	64	$	53

During the three months ended March 31, 2017, PSEG contributed its entire planned contribution for the year 2017 of $14 million into its OPEB plan.

Servco Pension and OPEB

At the direction of LIPA, Servco sponsors benefit plans that cover its current and former employees who meet certain eligibility criteria. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 4. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.

Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco’s pension-related revenues and costs were $18 million and $16 million for the three months ended September 30, 2017 and 2016, respectively, and $35 million and $28 million for the nine months ended September 30, 2017 and 2016, respectively. Servco’s pension-related costs of $35 million for the nine months ended September 30, 2017 represent its entire planned contribution for the year 2017. The OPEB-related revenues earned and costs incurred were $1 million and $3 million for the three months and nine months ended September 30, 2017. The OPEB-related revenues earned and costs incurred were immaterial for the three months and nine months ended September 30, 2016.

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Note 9. Commitments and Contingent Liabilities

Guaranteed Obligations

Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral.

Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to


•	support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and


•	obtain credit.

Power is subject to


•	counterparty collateral calls related to commodity contracts, and


•	certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.

Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.

In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to


•	fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and


•	the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).

Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.

In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.

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The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of September 30, 2017 and December 31, 2016.




	As of			As of
	September 30, 2017			December 31, 2016
	Millions
Face Value of Outstanding Guarantees	$	1,846		$	1,806
Exposure under Current Guarantees	$	108		$	139

Letters of Credit Margin Posted	$	134		$	157
Letters of Credit Margin Received	$	59		$	99

Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(2	)	$	(1	)
Net Broker Balance Deposited (Received)	$	(6	)	$	57

Additional Amounts Posted:
Other Letters of Credit	$	61		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 11. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Condensed Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. In June 2017, Power sold its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s obligations related to PennEast was terminated.

Environmental Matters

Passaic River

Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows.

Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)

In 2002, the EPA determined that a 17-mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA.

The EPA determined that there was a need to perform a comprehensive study of the entire 17 miles of the lower Passaic River. PSE&G and certain of its predecessors conducted operations at properties in this area of the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites.

In early 2007, 73 Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the

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RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim.

In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

In 2012, Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than with respect to their obligation to fund the EPA’s portion of its RI/FS oversight costs. At such time, the remaining members of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. Construction is complete. The CPG is awaiting EPA approval of the construction report, long-term monitoring plan and confirmatory sampling plan. PSE&G’s and Power’s combined share of the cost of that effort is approximately three percent. The remaining CPG members, PSE&G and Power included, have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal.

On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17-mile stretch of the Passaic River. The revised draft FFS sets forth various alternatives for remediating this portion of the Passaic River.

The CPG, which consisted of 50 members as of September 30, 2017, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $195 million, which the CPG continues to incur. Of the estimated $195 million, as of September 30, 2017, the CPG had spent approximately $168 million, of which PSEG’s total share was approximately $12 million.

The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River. It set forth the CPG’s estimated costs to remediate the lower 17 miles of the Passaic River which range from approximately $518 million to $3.2 billion on an undiscounted basis. The CPG identified a targeted remedy in the draft FS which would involve removal, treatment and disposal of contaminated sediments taken from targeted locations within the entire 17 miles of the lower Passaic River. The estimated cost in the draft FS for the targeted remedy ranged from approximately $518 million to $772 million. Based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G’s and Power’s estimated share of those costs, and (iii) the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued a $10 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued a $3 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2015.

In March 2016, the EPA released its Record of Decision (ROD) for the FFS which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The ROD Remedy requires a bank-to-bank dredge ranging from approximately 5 to 30 feet deep in the federal navigation channel from River Mile 0 to River Mile 1.7 and an approximately 2.5 foot deep dredge everywhere else in the lower 8.3 miles of the river. An engineered cap approximately two feet thick will be placed over the dredged areas. Dredged sediments will be transported to facilities and landfills out-of-state. The EPA estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation.

Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. These accruals brought the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power. There have been no additional accruals recorded since the first quarter of 2016.

Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA

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executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.”

In June 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Maxus and Tierra are subsidiaries of YPF Holdings, Inc. (YPF Holdings). YPF Holdings is a wholly owned subsidiary of YPF S.A. (YPF), a company controlled by the Argentinian government. Neither YPF Holdings nor YPF is a party to the bankruptcy proceedings. However, Tierra and Maxus have filed a plan of liquidation that may allow the parties to assert one or more causes of action to hold YPF responsible for certain amounts owed by Tierra and Maxus. The bankruptcy plan ordered by the Delaware Court in July, 2017 created a Liquidating Trust to pursue outstanding creditors’ claims, including alter ego claims against YPF. PSEG cannot currently determine the impact, if any, that the bankruptcy of Tierra and Maxus or any related proceeding might have on its allocable share or total liability for the Passaic River matter, and therefore, PSEG, through the CPG and independently, will continue to monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs.

In March 2017, the EPA sent a letter to certain PRPs that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. The impact of this proposed settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.

In September 2017, the EPA concluded that an Agency-commenced allocation process for the Passaic River’s lower 8.3 miles should include only certain PRPs that received General Notice letters (excluding PRPs that settle pursuant to the early cash-out settlement that the EPA offered in March 2017, among others). The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform the remedial action under EPA oversight. Discussions on the matter are ongoing.

The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G’s and Power’s respective shares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.

Natural Resource Damage Claims

In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.

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MGP Remediation Program

PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $390 million and $440 million on an undiscounted basis through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $390 million as of September 30, 2017. Of this amount, $74 million was recorded in Other Current Liabilities and $316 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $390 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding to what extent sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.

Prevention of Significant Deterioration (PSD)/New Source Review (NSR)

The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred.

In 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent the PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.

Clean Water Act (CWA) Permit Renewals

Pursuant to the Federal Water Pollution Control Act, National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.

In May 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range of studies related to impingement mortality and entrainment and submit the results with their permit applications.

In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Court of Appeals for the Second Circuit (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision remains pending.

In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final permit for Salem. This matter is still pending. The Riverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with

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the CWA. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.

State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intake structures and cooling systems.

Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations.

Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at BH3. To address compliance with the EPA’s CWA Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit.

Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut and local community organizations. That CEBA provides that Power would retire BH3 early if all its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life.

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council (CSC) issued an order to approve siting Bridgeport Harbor Station unit 5. All major environmental permits have been received; however, secondary approvals are still being obtained to allow operations to begin by June 2019. Power’s obligations under the CEBA are being monitored regularly and carried out as needed.

Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance

In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. Power cannot predict the impact of this matter.

Jersey City, New Jersey Subsurface Feeder Cable Matter

In early October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The impacted cable was repaired in late-September 2017; however, the investigation and response actions related to the fluid discharge are ongoing. Also ongoing is the process to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC, including an action filed by PSE&G in New Jersey federal court seeking damages from NADC. Based on the information currently available and depending on the outcome of the New Jersey federal action, PSE&G’s portion of the costs to address the leak may be material; however, PSE&G anticipates that it will recover these costs through regulatory proceedings.

Steam Electric Effluent Guidelines

In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and

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Conemaugh stations, have bottom ash transport water discharges that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations for the aforementioned waste streams. In September 2017, the EPA issued a rule postponing for two years compliance dates solely related to bottom ash transport water and flue gas desulfurization wastewater. The EPA has announced plans to issue a new rule by November 2020 addressing revised requirements and compliance dates for these two waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)

PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.

The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2016 is $276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $335.33 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:




	Auction Year
	2014	2015	2016	2017
36-Month Terms Ending	May 2017	May 2018	May 2019	May 2020	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per MWh	$97.39	$99.54	$96.38	$90.78


(A)	Prices set in the 2017 BGS auction year became effective on June 1, 2017 when the 2014 BGS auction agreements expired.

Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.

PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 18. Related-Party Transactions.

Minimum Fuel Purchase Requirements

Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2020 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom.

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Power has various multi-year contracts for natural gas and firm pipeline transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess pipeline capacity available beyond the needs of PSE&G’s customers, Power can use the gas to make third-party sales and if excess volume remains after the third-party sales, supply its fossil generating stations in New Jersey.

Power also has various long-term fuel purchase commitments for coal through 2021 to support its Keystone and Conemaugh fossil generation stations.

As of September 30, 2017, the total minimum purchase requirements included in these commitments were as follows:




Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	257
Enrichment	$	328
Fabrication	$	178
Natural Gas	$	963
Coal	$	308

Regulatory Proceedings

FERC Compliance

PJM Bidding Matter

In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power has implemented procedures and continues to review its policies and practices to mitigate the risk of similar issues occurring in the future. During the three months ended March 31, 2014, based upon its best estimate available at the time, Power recorded a pre-tax charge to income in the amount of $25 million related to this matter.

Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into these matters. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. Power is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power.

Power continues to believe that it has legal defenses that it may assert in a judicial challenge, including the legal defense that its cost-based bidding in a substantial majority of the hours was below the allowed rate under the Tariff and therefore any errors in those hours did not violate the Tariff or were immaterial. Furthermore, it is unclear whether the quantity of energy offered violated any legal requirement. As a result, PSEG and Power cannot predict the final outcome of these matters.

Financial Transmission Rights (FTR) Auction Matter

In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in PJM’s annual FTR auction for the 2016-2017 planning year and the monthly PJM FTR auctions for February, March and April 2016. In October 2017, FERC Staff closed the investigation with no impact to PSEG’s operations or future earnings results.

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Note 10. Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transactions occurred in the nine months ended September 30, 2017:

PSEG


•	entered into an agreement for a new term loan maturing June 2019. The term loan has a balance of $700 million at an interest rate of 1 month LIBOR + 0.80% and can be terminated at any time without penalty.

PSE&G


•	issued $425 million of 3.00% Secured Medium-Term Notes, Series L due May 2027.

Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.

In March 2017, PSEG, Power and PSE&G amended their credit agreements, extending the expiration dates to March 2022. Concurrently, PSEG increased its existing $1 billion in credit facilities to $1.5 billion and Power decreased its existing $2.6 billion in credit facilities to $2.1 billion, which includes two new 3-year $100 million letter of credit facilities that expire in March 2020.

The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of September 30, 2017, the total available credit capacity was $3.8 billion.

As of September 30, 2017, no single institution represented more than 8% of the total commitments in the credit facilities.

As of September 30, 2017, total credit capacity was in excess of the total anticipated maximum liquidity requirements of PSEG, PSE&G and Power.

Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support its subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of September 30, 2017 were as follows:




	As of September 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	215	$	1,285	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	215	$	1,285
PSE&G
5-year Credit Facility (A)	$	600	$	15	$	585	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	15	$	585
Power
3-year LC Facilities	$	200	$	112	$	88	Mar 2020	Letters of Credit
5-year Credit Facilities	1,900		70		1,830		Mar 2022	Funding/Letters of Credit
Total Power	$	2,100	$	182	$	1,918
Total	$	4,200	$	412	$	3,788


(A)	The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs, under which as of September 30, 2017, PSEG had $202 million outstanding at a weighted average interest rate of 1.37%. PSE&G had no amounts outstanding under its Commercial Paper Program as of September 30, 2017.

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Note 11. Financial Risk Management Activities

Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include normal purchases and normal sales (NPNS), cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow or fair value hedges. Power and PSE&G enter into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value.

Commodity Prices

Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk relating primarily to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings.

Interest Rates

PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps.

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of September 30, 2017 or December 31, 2016. The fair value hedges reduced interest expense by $2 million and $6 million for the three months and nine months ended September 30, 2016.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, related primarily to variable-rate debt instruments. As of September 30, 2017 and December 31, 2016, PSEG had interest rate hedges outstanding totaling $500 million. These hedges convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. As of December 31, 2016, the fair value of these hedges was $1 million and was immaterial as of September 30, 2017. There was no ineffectiveness as of September 30, 2017 and December 31, 2016.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $1 million and $2 million as of September 30, 2017 and December 31, 2016, respectively. The after-tax unrealized gain expected to be reclassified to earnings during the next 12 months is immaterial.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Condensed Consolidated Balance Sheets of Power and PSEG.

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The following tabular disclosure does not include the offsetting of trade receivables and payables.




	As of September 30, 2017
	Power (A)									PSEG (A)		Consolidated
	Not Designated									Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	352		$	(268	)	$	84		$	—	$	84
Noncurrent Assets	178			(116		)	62			—		62
Total Mark-to-Market Derivative Assets	$	530		$	(384	)	$	146		$	—	$	146
Derivative Contracts
Current Liabilities	$	(268	)	$	261		$	(7	)	$	—	$	(7	)
Noncurrent Liabilities	(110		)	109			(1		)	—		(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(378	)	$	370		$	(8	)	$	—	$	(8	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	152		$	(14	)	$	138		$	—	$	138




	As of December 31, 2016
	Power (A)									PSE&G (A)			PSEG (A)		Consolidated
	Not Designated									Not Designated			Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	435		$	(273	)	$	162		$	—		$	1	$	163
Noncurrent Assets	122			(98		)	24			—			—		24
Total Mark-to-Market Derivative Assets	$	557		$	(371	)	$	186		$	—		$	1	$	187
Derivative Contracts
Current Liabilities	$	(285	)	$	277		$	(8	)	$	(5	)	$	—	$	(13	)
Noncurrent Liabilities	(98		)	95			(3		)	—			—		(3		)
Total Mark-to-Market Derivative (Liabilities)	$	(383	)	$	372		$	(11	)	$	(5	)	$	—	$	(16	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	174		$	1		$	175		$	(5	)	$	1	$	171


(A)	Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of September 30, 2017 and December 31, 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

(B)

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positions. Of the $(14) million as of September 30, 2017, $(7) million was netted against current assets, and $(7) million was netted against noncurrent assets. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets, and $4 million was netted against current liabilities.

Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $16 million and $19 million as of September 30, 2017 and December 31, 2016, respectively. As of each of September 30, 2017 and December 31, 2016, Power had the contractual right of offset of $9 million related to derivative instruments that are assets with the same counterparty under agreements and net of margin posted. If Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $7 million and $10 million as of September 30, 2017 and December 31, 2016, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months and nine months ended September 30, 2017 and 2016.




Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Three Months Ended					Three Months Ended
	September 30,					September 30,
	2017		2016			2017		2016
	Millions					Millions
PSEG
Interest Rate Swaps	$	1	$	1	Interest Expense	$	2	$	—
Total PSEG	$	1	$	1		$	2	$	—




Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Nine Months Ended					Nine Months Ended
	September 30,					September 30,
	2017		2016			2017		2016
	Millions					Millions
PSEG
Interest Rate Swaps	$	1	$	3	Interest Expense	$	2	$	—
Total PSEG	$	1	$	3		$	2	$	—

There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of September 30, 2017 and

2016.

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The following reconciles the AOCI for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis.




Accumulated Other Comprehensive Income	Pre-Tax			After-Tax
	Millions
Balance as of December 31, 2015	$	—		$	—
Gain Recognized in AOCI	3			2
Less: Gain Reclassified into Income	—			—
Balance as of December 31, 2016	$	3		$	2
Gain Recognized in AOCI	1			—
Less: Gain Reclassified into Income	(2		)	(1		)
Balance as of September 30, 2017	$	2		$	1

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months and nine months ended September 30, 2017 and 2016. Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts for which Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.




Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2017			2016			2017			2016
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	25		$	125		$	221		$	255
Energy-Related Contracts	Energy Costs	(3		)	(11		)	(19		)	(3		)
Total PSEG and Power		$	22		$	114		$	202		$	252

The following reflects the gross volume, on an absolute value basis, of derivatives as of September 30, 2017 and December 31, 2016.




Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of September 30, 2017
Natural Gas	Dekatherm (Dth)	265	—	265	—
Electricity	MWh	332	—	332	—
Financial Transmission Rights (FTRs)	MWh	5	—	5	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—
As of December 31, 2016
Natural Gas	Dth	357	—	348	9
Electricity	MWh	323	—	323	—
FTRs	MWh	9	—	9	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—

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Credit Risk

Credit risk relates to the risk of loss that Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

As of September 30, 2017, 99% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).

The following table provides information on Power’s credit risk from others, net of collateral, as of September 30, 2017. It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties.




Rating	Current Exposure		Collateral Held		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	318	$	55	$	263	2	$	128	(A)
Non-Investment Grade	5		1		4		—	—
Total	$	323	$	56	$	267	2	$	128


(A)	Includes net exposure of $97 million with PSE&G.

As of September 30, 2017, collateral held from counterparties where Power had credit exposure included $3 million in cash collateral and $53 million in letters of credit.

As of September 30, 2017, Power had 144 active counterparties.

PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of September 30, 2017, primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of September 30, 2017, PSE&G had no net credit exposure with suppliers, including Power.

PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.

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Note 12. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX.

Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.

Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of September 30, 2017, these consisted primarily of certain electric load contracts and gas contracts.

Certain derivative transactions may transfer from Level 2 to Level 3 if inputs become unobservable and internal modeling techniques are employed to determine fair value. Conversely, measurements may transfer from Level 3 to Level 2 if the inputs become observable.

The following tables present information about PSEG’s, PSE&G’s and Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and Power.

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	Recurring Fair Value Measurements as of September 30, 2017
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	220		$	—		$	220		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	146		$	(384	)	$	11		$	513		$	6
NDT Fund (D)
Equity Securities	$	1,032		$	—		$	1,030		$	2		$	—
Debt Securities—U.S. Treasury	$	249		$	—		$	—		$	249		$	—
Debt Securities—Govt Other	$	318		$	—		$	—		$	318		$	—
Debt Securities—Corporate	$	358		$	—		$	—		$	358		$	—
Other Securities	$	55		$	—		$	55		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	23		$	—		$	23		$	—		$	—
Debt Securities—U.S. Treasury	$	51		$	—		$	—		$	51		$	—
Debt Securities—Govt Other	$	33		$	—		$	—		$	33		$	—
Debt Securities—Corporate	$	120		$	—		$	—		$	120		$	—
Other Securities	$	2		$	—		$	2		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(8	)	$	370		$	(6	)	$	(372	)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	220		$	—		$	220		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—U.S. Treasury	$	10		$	—		$	—		$	10		$	—
Debt Securities—Govt Other	$	7		$	—		$	—		$	7		$	—
Debt Securities—Corporate	$	24		$	—		$	—		$	24		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	146		$	(384	)	$	11		$	513		$	6
NDT Fund (D)
Equity Securities	$	1,032		$	—		$	1,030		$	2		$	—
Debt Securities—U.S. Treasury	$	249		$	—		$	—		$	249		$	—
Debt Securities—Govt Other	$	318		$	—		$	—		$	318		$	—
Debt Securities—Corporate	$	358		$	—		$	—		$	358		$	—
Other Securities	$	55		$	—		$	55		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	6		$	—		$	6		$	—		$	—
Debt Securities—U.S. Treasury	$	13		$	—		$	—		$	13		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	30		$	—		$	—		$	30		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(8	)	$	370		$	(6	)	$	(372	)	$	—

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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	Recurring Fair Value Measurements as of December 31, 2016
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—U.S. Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—U.S. Treasury	$	37		$	—		$	—		$	37		$	—
Debt Securities—Govt Other	$	66		$	—		$	—		$	66		$	—
Debt Securities—Corporate	$	91		$	—		$	—		$	91		$	—
Other Securities	$	1		$	—		$	1		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(16	)	$	372		$	(18	)	$	(364	)	$	(6	)
PSE&G
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	—		$	—		$	—		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—U.S. Treasury	$	7		$	—		$	—		$	7		$	—
Debt Securities—Govt Other	$	13		$	—		$	—		$	13		$	—
Debt Securities—Corporate	$	18		$	—		$	—		$	18		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(5	)	$	—		$	—		$	—		$	(5	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—U.S. Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—U.S. Treasury	$	9		$	—		$	—		$	9		$	—
Debt Securities—Govt Other	$	16		$	—		$	—		$	16		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	372		$	(18	)	$	(364	)	$	(1	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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(A)	Represents money market mutual funds.


(B)	Level 1— During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from an exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

Level 3—Unobservable inputs are used for the valuation of certain contracts. See “Additional Information Regarding Level 3 Measurements” below for more information on the utilization of unobservable inputs.


(C)	Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(D)

The fair value measurement tables exclude an immaterial amount of cash as of September 30, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of September 30, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.

Level 2—NDT and Rabbi Trust fixed income securities include primarily investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(E)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of September 30, 2017, net cash collateral (received) paid of $(14) million was netted against the corresponding net derivative contract positions. The $(14) million of cash collateral as of September 30, 2017 was netted against assets. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities.

Additional Information Regarding Level 3 Measurements

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The RMC reports to the Corporate Governance and Audit Committees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

For PSE&G, the natural gas supply contract was measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of September 30, 2017 and December 31, 2016.

Quantitative Information About Level 3 Fair Value Measurements

Significant

Fair Value as of

Valuation

Unobservable

Commodity

Level 3 Position

September 30, 2017

Technique(s)

Input

Range

Assets

(Liabilities)

Millions

Power

Electricity

Electric Load Contracts

—

Discounted Cash flow

Historic Load Variability

0% to +10%

Gas

Other

—

Total Power

—

Total PSEG

—




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	—	$	(5	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(5	)
Power
Electricity	Electric Load Contracts	$	7	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	7	$	(1	)
Total PSEG		$	7	$	(6	)


(A)	Includes gas positions which were immaterial.

Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value.

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A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months ended September 30, 2017 and September 30, 2016, respectively, follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months and Nine Months Ended September 30, 2017




	Three Months Ended September 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of September 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	6		$	3	$	—	$	—	$	(3	)	$	—		$	6
PSE&G
Net Derivative Assets (Liabilities)	$	—		$	—	$	—	$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	6		$	3	$	—	$	—	$	(3	)	$	—		$	6

	Nine Months Ended September 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of September 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	29	$	5	$	—	$	(28	)	$	(1	)	$	6
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	—	$	5	$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	6		$	29	$	—	$	—	$	(28	)	$	(1	)	$	6

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Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Three Months and Nine Months Ended September 30, 2016




	Three Months Ended September 30, 2016
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2016			Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	5		$	8	$	(2	)	$	4	$	(4	)	$	—	$	11
PSE&G
Net Derivative Assets (Liabilities)	$	(2	)	$	—	$	(2	)	$	—	$	—		$	—	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	7		$	8	$	—		$	4	$	(4	)	$	—	$	15

	Nine Months Ended September 30, 2016
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016			Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2016

PSEG
Net Derivative Assets (Liabilities)	$	13		$	24	$	(6	)	$	4	$	(24	)	$	—	$	11
PSE&G
Net Derivative Assets (Liabilities)	$	2		$	—	$	(6	)	$	—	$	—		$	—	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	11		$	24	$	—		$	4	$	(24	)	$	—	$	15


(A)	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $3 million and $29 million in Operating Income for the three months and nine months ended September 30, 2017, respectively. The $3 million in Operating Income is realized. Of the $29 million in Operating Income, $1 million is unrealized.


(B)	Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.


(C)	Represents $(3) million and $(28) million in settlements for the three months and nine months ended September 30, 2017, respectively. Represents $(4) million and $(24) million in settlements for the three months and nine months

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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ended September 30, 2016, respectively.


(D)	During the three months ended September 30, 2017 there were no transfers in to or out of Level 3. During the nine months ended September 30, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in to or out of Level 3 during three months and nine months ended September 30, 2016.


(E)	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $8 million and $24 million in Operating Income for the three months and nine months ended September 30, 2016, respectively. Of the $8 million in Operating Income, $4 million is unrealized. The $24 million in Operating Income is realized.

As of September 30, 2017, PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $6 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of September 30, 2016, PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $11 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of September 30, 2017 and December 31, 2016.




	As of				As of
	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A) (B)	$	1,896	$	1,891	$	1,195	$	1,185
PSE&G (B)	8,243		8,857		7,818		8,240
Power - Recourse Debt (B)	2,385		2,657		2,382		2,578
Total Long-Term Debt	$	12,524	$	13,405	$	11,395	$	12,003

(A)

As of September 30, 2017, fair value includes a $700 million floating rate term loan in addition to the $500 million floating rate term loan and net offsets as of December 31, 2016. The fair values of the term loan debt (Level 2 measurement) approximate the carrying values because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time.

(B)

Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Note 13. Other Income and Deductions




Other Income	PSE&G		Power		Other (A)			Consolidated
	Millions
Three Months Ended September 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	41	$	—		$	41
Allowance for Funds Used During Construction	14		—		—			14
Rabbi Trust Realized Gains, Interest and Dividends	1		1		—			2
Solar Loan Interest	6		—		—			6
Other	2		1		—			3
Total Other Income	$	23	$	43	$	—		$	66
Nine Months Ended September 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	117	$	—		$	117
Allowance for Funds Used During Construction	42		—		—			42
Rabbi Trust Realized Gains, Interest and Dividends	5		6		11			22
Solar Loan Interest	16		—		—			16
Other	7		4		—			11
Total Other Income	$	70	$	127	$	11		$	208
Three Months Ended September 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	21	$	—		$	21
Allowance for Funds Used During Construction	14		—		—			14
Rabbi Trust Realized Gains, Interest and Dividends	1		—		3			4
Solar Loan Interest	6		—		—			6
Other	1		2		(1		)	2
Total Other Income	$	22	$	23	$	2		$	47
Nine Months Ended September 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	69	$	—		$	69
Allowance for Funds Used During Construction	35		—		—			35
Rabbi Trust Realized Gains, Interest and Dividends	2		2		6			10
Solar Loan Interest	17		—		—			17
Other	7		3		(2		)	8
Total Other Income	$	61	$	74	$	4		$	139




Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended September 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	8	$	—	$	8
Other	1		—		1		2
Total Other Deductions	$	1	$	8	$	1	$	10
Nine Months Ended September 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	21	$	—	$	21
Other	3		1		5		9
Total Other Deductions	$	3	$	22	$	5	$	30
Three Months Ended September 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	5	$	—	$	5
Other	1		1		1		3
Total Other Deductions	$	1	$	6	$	1	$	8
Nine Months Ended September 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	31	$	—	$	31
Other	3		2		3		8
Total Other Deductions	$	3	$	33	$	3	$	39


(A)	Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Note 14. Income Taxes

PSEG’s, PSE&G’s and Power’s effective tax rates for the three months and nine months ended September 30, 2017 and 2016 were as follows:




	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
PSEG	38.9%	36.5%	35.5%	36.3%
PSE&G	38.8%	36.1%	37.4%	36.1%
Power	41.9%	39.3%	37.9%	39.4%

For the three months and nine months ended September 30, 2017, the differences in PSEG’s effective tax rates as compared to the same periods in the prior year, as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions and the NDT Fund. For the nine months ended September 30, 2017, the effective tax rate was also favorably impacted by interest from a New Jersey State income tax refund.

For the three months and nine months ended September 30, 2017, the differences in PSE&G’s effective tax rates as compared to the same periods in the prior year, as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow-through items.

For the three months and nine months ended September 30, 2017, the differences in Power’s effective tax rates as compared to the same periods in the prior year, as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, manufacturing deduction and the NDT Fund.

PSEG’s federal tax returns for the years 2011 and 2012 are currently being audited by the IRS. The audit and other related claims are reasonably expected to be completed within the next 12 months. As a result, it is reasonably possible that a decrease in PSEG’s total unrecognized tax benefits may be necessary in the range of $80 million to $180 million based on current estimates.

The Protecting Americans from Tax Hikes Act of 2015 (Tax Act) extended the 50% bonus depreciation rules for qualified property placed in service from January 1, 2015 through December 31, 2017. The rate is reduced to 40% and 30% for eligible property placed in service in 2018 and 2019, respectively. On May 8, 2017 the IRS issued guidance allowing for 50% bonus depreciation on long production property that is placed in service in 2018. For long production property placed in service in 2019, qualified costs incurred before January 1, 2019 is afforded a 40% rate, while qualified costs incurred during 2019 receives a 30% rate. For long production property placed in service in 2020, subject to a written binding contract entered into before 2020, a 30% rate is allowed for qualified costs incurred before January 1, 2020, with a 0% rate thereafter. The Tax Act also extended the 30% ITC for qualified property placed in service starting January 1, 2016 through December 31, 2019 but reduces the ITC rate to 26% and 22% for projects commenced in 2020 and 2021, respectively. The financial impact of the extensions of the ITC rate will depend upon future transactions.

This provision has generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period. However, these tax benefits will have a negative impact on the rate base of several of PSE&G’s programs.

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Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax




PSEG	Other Comprehensive Income (Loss)
	Three Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2017	$	2		$	(386	)	$	158		$	(226	)
Other Comprehensive Income before Reclassifications	—			—			25			25
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(1		)	6			(8		)	(3		)
Net Current Period Other Comprehensive Income (Loss)	(1		)	6			17			22
Balance as of September 30, 2017	$	1		$	(380	)	$	175		$	(204	)

PSEG	Other Comprehensive Income (Loss)
	Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)
Other Comprehensive Income before Reclassifications	1			—			26			27
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			9			(2		)	7
Net Current Period Other Comprehensive Income (Loss)	1			9			24			34
Balance as of September 30, 2016	$	2		$	(361	)	$	141		$	(218	)

PSEG	Other Comprehensive Income (Loss)
	Nine Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	2		$	(398	)	$	133		$	(263	)
Other Comprehensive Income before Reclassifications	—			—			78			78
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(1		)	18			(36		)	(19		)
Net Current Period Other Comprehensive Income (Loss)	(1		)	18			42			59
Balance as of September 30, 2017	$	1		$	(380	)	$	175		$	(204	)

PSEG	Other Comprehensive Income (Loss)
	Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(386	)	$	91		$	(295	)
Other Comprehensive Income before Reclassifications	2			—			44			46
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			25			6			31
Net Current Period Other Comprehensive Income (Loss)	2			25			50			77
Balance as of September 30, 2016	$	2		$	(361	)	$	141		$	(218	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Power	Other Comprehensive Income (Loss)
	Three Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2017	$	—	$	(330	)	$	158		$	(172	)
Other Comprehensive Income before Reclassifications	—		—			24			24
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		5			(9		)	(4		)
Net Current Period Other Comprehensive Income (Loss)	—		5			15			20
Balance as of September 30, 2017	$	—	$	(325	)	$	173		$	(152	)

Power	Other Comprehensive Income (Loss)
	Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2016	$	—	$	(313	)	$	112		$	(201	)
Other Comprehensive Income before Reclassifications	—		—			24			24
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		7			(2		)	5
Net Current Period Other Comprehensive Income (Loss)	—		7			22			29
Balance as of September 30, 2016	$	—	$	(306	)	$	134		$	(172	)

Power	Other Comprehensive Income (Loss)
	Nine Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	—	$	(340	)	$	129		$	(211	)
Other Comprehensive Income before Reclassifications	—		—			74			74
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		15			(30		)	(15		)
Net Current Period Other Comprehensive Income (Loss)	—		15			44			59
Balance as of September 30, 2017	$	—	$	(325	)	$	173		$	(152	)

Power	Other Comprehensive Income (Loss)
	Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—	$	(327	)	$	87		$	(240	)
Other Comprehensive Income before Reclassifications	—		—			40			40
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		21			7			28
Net Current Period Other Comprehensive Income (Loss)	—		21			47			68
Balance as of September 30, 2016	$	—	$	(306	)	$	134		$	(172	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	September 30, 2017									September 30, 2017
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Interest Rate Swaps	Interest Expense	$	2		$	(1	)	$	1		$	2		$	(1	)	$	1
Total Cash Flow Hedges		2			(1		)	1			2			(1		)	1
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	3			(1		)	2			7			(3		)	4
Amortization of Actuarial Loss	O&M Expense	(13		)	5			(8		)	(37		)	15			(22		)
Total Pension and OPEB Plans		(10		)	4			(6		)	(30		)	12			(18		)
Available-for-Sale Securities
Realized Gains	Other Income	29			(15		)	14			99			(49		)	50
Realized Losses	Other Deductions	(6		)	2			(4		)	(19		)	9			(10		)
OTTI	OTTI	(5		)	3			(2		)	(9		)	5			(4		)
Total Available-for-Sale Securities		18			(10		)	8			71			(35		)	36
Total		$	10		$	(7	)	$	3		$	43		$	(24	)	$	19




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	September 30, 2016									September 30, 2016
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	3		$	(2	)	$	1		$	9		$	(4	)	$	5
Amortization of Actuarial Loss	O&M Expense	(17		)	7			(10		)	(51		)	21			(30		)
Total Pension and OPEB Plans		(14		)	5			(9		)	(42		)	17			(25		)
Available-for-Sale Securities
Realized Gains	Other Income	13			(6		)	7			41			(20		)	21
Realized Losses	Other Deductions	(5		)	3			(2		)	(29		)	15			(14		)
OTTI	OTTI	(5		)	2			(3		)	(25		)	12			(13		)
Total Available-for-Sale Securities		3			(1		)	2			(13		)	7			(6		)
Total		$	(11	)	$	4		$	(7	)	$	(55	)	$	24		$	(31	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	September 30, 2017									September 30, 2017
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	6		$	(3	)	$	3
Amortization of Actuarial Loss	O&M Expense	(11		)	5			(6		)	(32		)	14			(18		)
Total Pension and OPEB Plans		(9		)	4			(5		)	(26		)	11			(15		)
Available-for-Sale Securities
Realized Gains	Other Income	29			(15		)	14			86			(44		)	42
Realized Losses	Other Deductions	(5		)	2			(3		)	(15		)	7			(8		)
OTTI	OTTI	(5		)	3			(2		)	(9		)	5			(4		)
Total Available-for-Sale Securities		19			(10		)	9			62			(32		)	30
Total		$	10		$	(6	)	$	4		$	36		$	(21	)	$	15




Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	September 30, 2016									September 30, 2016
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	3		$	(1	)	$	2		$	8		$	(3	)	$	5
Amortization of Actuarial Loss	O&M Expense	(15		)	6			(9		)	(44		)	18			(26		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(36		)	15			(21		)
Available-for-Sale Securities
Realized Gains	Other Income	12			(5		)	7			37			(18		)	19
Realized Losses	Other Deductions	(4		)	2			(2		)	(26		)	13			(13		)
OTTI	OTTI	(5		)	2			(3		)	(25		)	12			(13		)
Total Available-for-Sale Securities		3			(1		)	2			(14		)	7			(7		)
Total		$	(9	)	$	4		$	(5	)	$	(50	)	$	22		$	(28	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Note 16. Earnings Per Share (EPS) and Dividends

EPS

Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:




	Three Months Ended September 30,								Nine Months Ended September 30,
	2017				2016				2017				2016
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	395	$	395	$	327	$	327	$	618	$	618	$	985	$	985
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		505		505		505		505		505		505
Effect of Stock Based Compensation Awards	—		2		—		3		—		2		—		3
Total Shares	505		507		505		508		505		507		505		508

EPS
Net Income	$	0.78	$	0.78	$	0.65	$	0.64	$	1.22	$	1.22	$	1.95	$	1.94

There were approximately 0.3 million for the three months and nine months ended September 30, 2017 and approximately 0.4 million for the three months and nine months ended September 30, 2016 of stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect.

Dividends




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Dividend Payments on Common Stock	2017		2016		2017		2016
Per Share	$	0.43	$	0.41	$	1.29	$	1.23
In Millions	$	217	$	207	$	652	$	622

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Note 17. Financial Information by Business Segment




	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
Three Months Ended September 30, 2017
Total Operating Revenues	$	1,509	$	873		$	135		$	(254	)	$	2,263
Net Income (Loss)	246		136			13			—			395
Gross Additions to Long-Lived Assets	729		327			9			—			1,065
Nine Months Ended September 30, 2017
Operating Revenues	$	4,689	$	3,086		$	334		$	(1,121	)	$	6,988
Net Income (Loss)	753		(131		)	(4		)	—			618
Gross Additions to Long-Lived Assets	2,118		903			25			—			3,046
Three Months Ended September 30, 2016
Total Operating Revenues	$	1,684	$	1,075		$	7		$	(316	)	$	2,450
Net Income (Loss)	255		139			(67		)	—			327
Gross Additions to Long-Lived Assets	680		325			9			—			1,014
Nine Months Ended September 30, 2016
Operating Revenues	$	4,746	$	3,102		$	256		$	(1,133	)	$	6,971
Net Income (Loss)	696		320			(31		)	—			985
Gross Additions to Long-Lived Assets	2,035		923			27			—			2,985
As of September 30, 2017
Total Assets	$	27,802	$	11,631		$	2,288		$	(564	)	$	41,157
Investments in Equity Method Subsidiaries	$	—	$	90		$	—		$	—		$	90
As of December 31, 2016
Total Assets	$	26,288	$	12,193		$	2,373		$	(784	)	$	40,070
Investments in Equity Method Subsidiaries	$	—	$	102		$	—		$	—		$	102


(A)	Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.

(B)

Intercompany eliminations relate primarily to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 18. Related-Party Transactions.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Note 18. Related-Party Transactions

The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.

PSE&G

The financial statements for PSE&G include transactions with related parties as follows:




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	259	$	320	$	1,154	$	1,162
Administrative Billings from Services (B)	82		73		226		224
Total Billings from Affiliates	$	341	$	393	$	1,380	$	1,386




	As of		As of
Related-Party Transactions	September 30, 2017		December 31, 2016
	Millions
Receivables from PSEG (C)	$	—	$	76
Payable to Power (A)	$	86	$	193
Payable to Services (B)	46		67
Payable to PSEG (C)	46		—
Accounts Payable—Affiliated Companies	$	178	$	260
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	83	$	130

Power

The financial statements for Power include transactions with related parties as follows:




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	259	$	320	$	1,154	$	1,162
Billings from Affiliates:
Administrative Billings from Services (B)	$	39	$	44	$	117	$	134

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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	As of		As of
Related-Party Transactions	September 30, 2017		December 31, 2016
	Millions
Receivables from PSE&G (A)	$	86	$	193
Receivables from PSEG (C)	—		12
Accounts Receivable—Affiliated Companies	$	86	$	205
Payable to Services (B)	$	17	$	25
Payable to PSEG (C)	111		—
Accounts Payable—Affiliated Companies	$	128	$	25
Short-Term Loan Due (to) from Affiliate (E)	$	1	$	87
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	57	$	77

(A)

PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.


(B)	Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies.

(C)

PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.


(D)	PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Condensed Consolidated Balance Sheets.


(E)	Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Note 19. Guarantees of Debt

Power’s Senior Notes are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries, as of September 30, 2017 and December 31, 2016 and for the three months and nine months ended September 30, 2017 and 2016.




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended September 30, 2017
Operating Revenues	$	—		$	856		$	46		$	(29	)	$	873
Operating Expenses	2			643			44			(29		)	660
Operating Income (Loss)	(2		)	213			2			—			213
Equity Earnings (Losses) of Subsidiaries	143			(3		)	3			(140		)	3
Other Income	24			58			(2		)	(37		)	43
Other Deductions	—			(8		)	—			—			(8		)
Other-Than-Temporary Impairments	—			(5		)	—			—			(5		)
Interest Expense	(32		)	(12		)	(5		)	37			(12		)
Income Tax Benefit (Expense)	3			(103		)	2			—			(98		)
Net Income (Loss)	$	136		$	140		$	—		$	(140	)	$	136
Comprehensive Income (Loss)	$	156		$	154		$	—		$	(154	)	$	156
Nine Months Ended September 30, 2017
Operating Revenues	$	—		$	3,036		$	145		$	(95	)	$	3,086
Operating Expenses	4			3,315			139			(95		)	3,363
Operating Income (Loss)	(4		)	(279		)	6			—			(277		)
Equity Earnings (Losses) of Subsidiaries	(111		)	(8		)	11			119			11
Other Income	71			155			—			(99		)	127
Other Deductions	(1		)	(21		)	—			—			(22		)
Other-Than-Temporary Impairments	—			(9		)	—			—			(9		)
Interest Expense	(96		)	(30		)	(14		)	99			(41		)
Income Tax Benefit (Expense)	10			68			2			—			80
Net Income (Loss)	$	(131	)	$	(124	)	$	5		$	119		$	(131	)
Comprehensive Income (Loss)	$	(72	)	$	(80	)	$	5		$	75		$	(72	)
Nine Months Ended September 30, 2017
Net Cash Provided By (Used In) Operating Activities	$	(55	)	$	1,159		$	142		$	3		$	1,249
Net Cash Provided By (Used In) Investing Activities	$	738		$	(289	)	$	(343	)	$	(990	)	$	(884	)
Net Cash Provided By (Used In) Financing Activities	$	(683	)	$	(869	)	$	211		$	987		$	(354	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended September 30, 2016
Operating Revenues	$	—		$	1,059		$	43		$	(27	)	$	1,075
Operating Expenses	(2		)	826			40			(27		)	837
Operating Income (Loss)	2			233			3			—			238
Equity Earnings (Losses) of Subsidiaries	143			(1		)	3			(142		)	3
Other Income	18			26			—			(21		)	23
Other Deductions	(2		)	(4		)	—			—			(6		)
Other-Than-Temporary Impairments	—			(5		)	—			—			(5		)
Interest Expense	(30		)	(12		)	(3		)	21			(24		)
Income Tax Benefit (Expense)	8			(97		)	(1		)	—			(90		)
Net Income (Loss)	$	139		$	140		$	2		$	(142	)	$	139
Comprehensive Income (Loss)	$	168		$	161		$	2		$	(163	)	$	168
Nine Months Ended September 30, 2016
Operating Revenues	$	—		$	3,061		$	131		$	(90	)	$	3,102
Operating Expenses	10			2,494			119			(90		)	2,533
Operating Income (Loss)	(10		)	567			12			—			569
Equity Earnings (Losses) of Subsidiaries	347			(1		)	9			(346		)	9
Other Income	52			88			—			(66		)	74
Other Deductions	(2		)	(31		)	—			—			(33		)
Other-Than-Temporary Impairments	—			(25		)	—			—			(25		)
Interest Expense	(91		)	(29		)	(12		)	66			(66		)
Income Tax Benefit (Expense)	24			(234		)	2			—			(208		)
Net Income (Loss)	$	320		$	335		$	11		$	(346	)	$	320
Comprehensive Income (Loss)	$	388		$	381		$	11		$	(392	)	$	388
Nine Months Ended September 30, 2016
Net Cash Provided By (Used In) Operating Activities	$	175		$	1,261		$	234		$	(410	)	$	1,260
Net Cash Provided By (Used In) Investing Activities	$	(588	)	$	(1,166	)	$	(549	)	$	1,152		$	(1,151	)
Net Cash Provided By (Used In) Financing Activities	$	413		$	(95	)	$	315		$	(742	)	$	(109	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of September 30, 2017
Current Assets	$	4,089	$	1,324	$	182	$	(4,433	)	$	1,162
Property, Plant and Equipment, net	57		5,408		2,607		—			8,072
Investment in Subsidiaries	4,168		338		—		(4,506		)	—
Noncurrent Assets	184		2,211		116		(114		)	2,397
Total Assets	$	8,498	$	9,281	$	2,905	$	(9,053	)	$	11,631
Current Liabilities	$	233	$	3,221	$	1,743	$	(4,433	)	$	764
Noncurrent Liabilities	503		2,192		524		(114		)	3,105
Long-Term Debt	2,385		—		—		—			2,385
Member’s Equity	5,377		3,868		638		(4,506		)	5,377
Total Liabilities and Member’s Equity	$	8,498	$	9,281	$	2,905	$	(9,053	)	$	11,631
As of December 31, 2016
Current Assets	$	4,412	$	1,593	$	152	$	(4,697	)	$	1,460
Property, Plant and Equipment, net	55		6,145		2,320		—			8,520
Investment in Subsidiaries	4,249		344		—		(4,593		)	—
Noncurrent Assets	168		2,016		129		(100		)	2,213
Total Assets	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193
Current Liabilities	$	171	$	3,752	$	1,454	$	(4,697	)	$	680
Noncurrent Liabilities	532		2,398		502		(100		)	3,332
Long-Term Debt	2,382		—		—		—			2,382
Member’s Equity	5,799		3,948		645		(4,593		)	5,799
Total Liabilities and Member’s Equity	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193

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ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)

This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and Power each make representations only as to itself and make no representations whatsoever as to any other company.

PSEG’s business consists of two reportable segments, our principal direct wholly owned subsidiaries, which are:

•

PSE&G—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and related programs in New Jersey, which are regulated by the BPU, and

•

Power—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under a contractual Operations and Services Agreement; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Our business discussion in Part I, Item 1. Business of our 2016 Annual Report on 10-K (Form 10-K) provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Part I, Item 1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Executive Overview of 2016 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2017 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes and the 2016 Form 10-K.

EXECUTIVE OVERVIEW OF 2017 AND FUTURE OUTLOOK

Our business plan is designed to achieve growth while managing the risks associated with fluctuating commodity prices and changes in customer demand. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:


•	improving utility operations through investment in T&D and other infrastructure projects designed to enhance system reliability and resiliency and to meet customer expectations and public policy objectives,


•	maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.

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Financial Results

The results for PSEG, PSE&G and Power for the three months and nine months ended September 30, 2017 and 2016 are presented as follows:




	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Earnings (Losses)	2017		2016			2017			2016
	Millions
PSE&G	$	246	$	255		$	753		$	696
Power (A)	136		139			(131		)	320
Other (B)	13		(67		)	(4		)	(31		)
PSEG Net Income	$	395	$	327		$	618		$	985

PSEG Net Income Per Share (Diluted)	$	0.78	$	0.64		$	1.22		$	1.94


(A)	Includes after-tax expenses of $5 million and $568 million in the three months and nine months ended September 30, 2017, respectively, and after-tax expenses of $67 million for the three months and nine months ended September 30, 2016 related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants. See Item 1. Note 3. Early Plant Retirements for additional information.

(B)

Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges of $45 million for the nine months ended September 30, 2017, and an after-tax impairment of $86 million for the three months and nine months ended September 30, 2016 related to its investments in NRG REMA, LLC’s (REMA) leveraged leases. See Item 1. Note 6. Financing Receivables for additional information.

Power’s results above include the realized gains, losses and earnings on the Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity and the impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with future delivery dates.

The variances in our Net Income include the changes related to NDT and MTM shown in the following table:




	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2017			2016		2017		2016
	Millions, after tax
NDT Fund Income (Expense) (A) (B)	$	10		$	2	$	32	$	(4	)
Non-Trading MTM Gains (Losses) (C)	$	(27	)	$	34	$	—	$	(54	)

(A)

NDT Fund Income (Expense) includes the realized gains and losses, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions, and impairments on certain NDT securities recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) is recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset is recorded in Depreciation and Amortization (D&A) Expense.


(B)	Net of tax (expense) benefit of $(12) million, $(2) million, $(37) million and $0 million for the three and nine months ended September 30, 2017 and 2016, respectively.


(C)	Net of tax (expense) benefit of $19 million $(24) million, $0 million and $37 million for the three and nine months ended September 30, 2017 and 2016, respectively.

Our $68 million increase in Net Income for the three months ended September 30, 2017 was driven primarily by


•	an impairment in 2016 related to investments in certain leveraged leases at Energy Holdings,


•	higher charges in 2016 related to early retirement of our Hudson and Mercer coal/gas generation units at Power,


•	lower generation costs driven by lower natural gas costs and congestion costs, and


•	higher transmission revenues.

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These favorable variances were partially offset by


•	lower sales of electricity sold under the Basic Generation Service contract and in PJM, and


•	MTM losses in 2017 as compared to MTM gains in 2016.

Our $367 million decrease in Net Income for the nine months ended September 30, 2017 was driven largely by higher charges, primarily accelerated depreciation, related to the early retirement of our Hudson and Mercer coal/gas generation units at Power. These decreases were partially offset by


•	lower O&M Expense due to cost control efforts,


•	lower charges related to investments in certain leveraged leases at Energy Holdings,


•	MTM losses in 2016, and


•	higher NDT gains and lower NDT losses in 2017.

During the first nine months of 2017, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results, which when combined with the cash flow generated by Power, our merchant generator and power marketer, has allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our long-term approach to managing our company. Our focus has been to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.

At PSE&G, we continue to invest in transmission projects that focus on reliability improvements and replacement of aging infrastructure, including our $275 million Newark Switch project that was approved by PJM in July 2017. We also continue to make investments to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014 and to seek recovery on such investments. We also continue to modernize PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G.

As a result of our Energy Strong Order from the BPU, we are required to file a distribution base rate case. Following discussions with BPU Staff and Rate Counsel, and as approved by the BPU at its October 20, 2017 meeting, the deadline for filing PSE&G’s distribution base rate case was moved from November 1, 2017 to December 1, 2017. The initial filing will now be based upon three months of actual data and nine months of forecasted data updated for actual data throughout the proceeding. The distribution base rate case will provide PSE&G the opportunity to recover investments made since its last distribution base rate case, including investments that were not recovered through clauses, such as the stipulated base investment associated with GSMP, the portion of Energy Strong investment not recovered through the clause, and investments that exceeded our depreciation levels in revenues. Recovery of these investments, coupled with updates to O&M and other adjustments, are anticipated to result in a proposed mid-single digit percentage increase in PSE&G distribution revenues. The distribution base rate case filing will include a test year through June 30, 2018 and will request the inclusion of known and measurable changes in rate base through December 31, 2018, a 10.3% return on equity (ROE) and a capitalization structure with a 54% equity component, and we expect to request new rates effective October 1, 2018. As part of the filing, we will also request approval to decouple electric and gas revenues from sales volumes for most distribution customer classes. We cannot predict the outcome of this proceeding.

In July 2017, we filed a petition with the BPU for GSMP II, a five-year extension of GSMP, which would accelerate the pace of replacement of our aging cast iron and unprotected steel mains and associated service. We proposed to invest up to $540 million per year over this five-year program beginning in 2019. In August 2017, the BPU approved our request for an extension of our Energy Efficiency program.

Although the weather in the first three months of 2017 was warmer than normal, Power’s results saw a continuing benefit from access to natural gas supplies through existing firm pipeline transportation contracts. Power manages these contracts for the benefit of PSE&G’s customers through the basic gas supply (BGSS) arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter demand days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third-party sales and if excess volume remains after the third-party sales, supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units.

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Power’s hedging practices and ability to capitalize on market opportunities help us to balance some of the volatility of the merchant power business. Power’s hedging program in combination with expected revenues from the capacity market mechanisms and certain ancillary service payments, such as reactive power, has secured approximately 60% of its estimated gross margin for the 2017-2019 period.

Our investments in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station unit 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These highly efficient additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to improve our financial performance.

Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced as being at risk for early retirement. This situation is generally due to the decline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.

If the market trends noted above continue or worsen, our New Jersey nuclear generating units could cease being economically competitive, which may cause us to retire such units prior to the end of their useful lives. The costs associated with any such potential retirement, which may include, among other things, accelerated D&A or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs, and additional funding of NDT funds would likely have a material adverse impact on future financial results. We continue to advocate for sound policies that recognize nuclear power as a source of reliable and clean energy, free of air emissions and an important part of a diverse and reliable energy portfolio. See Item 1. Note 3. Early Plant Retirements for additional information.

In addition, a number of states have either taken action or are investigating the situation faced by nuclear generating units. Recently, courts in Illinois and New York upheld challenges to the programs which established zero emissions credits, recognizing the importance of nuclear units for providing clean energy, free of air emissions.

In September 2017, the Secretary of the U.S. Department of Energy (DOE) issued a Notice of Proposed Rulemaking (NOPR) directing FERC to act within 60 days to develop a mechanism that would allow for the recovery of costs of fuel-secure generation units such as nuclear and coal. To be eligible for compensation under the NOPR, units must be able to provide certain essential energy and ancillary reliability services, have a 90-day fuel supply on site and not subject to cost-of-service rate regulation by any State or local authority. PSEG is evaluating the potential effects this NOPR could have on its generating fleet. PSEG filed comments in support of the DOE’s NOPR and contended that it should be implemented immediately as an interim measure to prevent the premature retirement of fuel-secure baseload units. PSEG also requested that FERC direct the regional transmission organizations (RTOs) to work with stakeholders to develop a long-term market-based methodology for valuing resiliency in the generator fleet. Additionally, PSEG argued that FERC should expedite the implementation of pending price formation reforms, including fast-start pricing and uplift allocation and market transparency. Finally, PSEG requested that FERC direct PJM to file its proposal that would allow baseload units to set the locational marginal prices during low load conditions. We cannot predict the outcome of this matter.

Regulatory, Legislative and Other Developments

In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets.

Transmission

In April 2017, the PJM Board announced that it would be lifting the previously disclosed suspension of the Artificial Island transmission project and approved the award to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. Also, in April 2017, PJM submitted a proposal to FERC concerning the cost responsibility assigned to certain entities, including PSE&G, for the Artificial Island project. In October 2017, FERC accepted PJM’s filing on the grounds that PJM correctly applied its Tariff, but deferred any further ruling on whether the cost allocation methodology applied to the Artificial Island project is appropriate. FERC will decide this issue in a separate proceeding that is currently pending before it.

There are several matters pending before FERC and the U. S. Court of Appeals for the District of Columbia Circuit that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayers in New Jersey. In addition, as a basic generation

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service (BGS) supplier, Power provides services that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to recovery, subject to BPU approval. We do not believe that these matters will have a material effect on Power’s business or results of operations.

Several complaints have been filed and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners’ base ROEs. The results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.

Wholesale Power Market Design

Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. The CP product was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. Subsequent to its implementation, FERC approved changes to the CP construct that will enhance the participation of intermittent and demand response resources (seasonal resources). However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions.

In May 2017, PJM announced the results of the RPM capacity auction for the 2020-2021 delivery year. Power cleared approximately 7,800 MW of its generating capacity at an average price of $174 per MW-day for the 2020-2021 delivery period. In the two prior capacity auctions covering the 2019-2020 and 2018-2019 delivery years, Power cleared approximately 8,900 MW at an average price of $116 and approximately 8,700 MW at an average price of $215 per MW-day, respectively. Prices in the most recent auction reflect PJM’s downwardly-revised demand forecast, changes in the emergency transfer limits due to transmission expansion and the effects of both the new generation and uncleared generation from the prior year’s auction.

As a result of the efforts of certain entities in PJM to obtain financial support arrangements from their state commissions, a group of suppliers requested that FERC direct PJM to expand the currently effective “minimum offer price rule” to apply to certain existing units seeking subsidies. The suppliers’ request was intended to avoid a scenario where the subsidized generators would submit bids into the PJM capacity market that did not reflect their actual costs of operation and could artificially suppress capacity market prices. We are currently awaiting FERC action on the suppliers’ request and cannot predict the outcome of the proceeding.

In June 2017, PJM issued an energy price formation proposal to address a flaw in the energy market in which energy prices during off-peak periods often do not reflect the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible units to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving load will be better reflected in clearing prices. We cannot predict the outcome of this matter.

Distribution

In June 2017, the BPU issued proposed Infrastructure Investment Program (IIP) regulations that would allow utilities to construct, install, or remediate utility plant and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under the proposed regulations, utilities could seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the IIP regulations as a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety. The proposed regulations will be subject to comment from interested parties.

Environmental Regulation

We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs.

In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards, which establish emissions standards for CO₂ for certain new fossil power plants, and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In October 2017, the EPA Administrator signed a proposed repeal of the CPP. The Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric

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generating units). Whether the EPA chooses to propose a replacement rule has not been decided. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.

We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs of any such remediation efforts could be material.

For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 1. Note 9. Commitments and Contingent Liabilities.

FERC Compliance

Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of Power’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power. We cannot predict the final outcome of these matters. For additional information, see Item 1. Note 9. Commitments and Contingent Liabilities.

Early Retirement of Hudson and Mercer Units

On June 1, 2017, Power completed its previously announced retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations. The decision to retire the Hudson and Mercer units had a material effect on PSEG’s and Power’s results of operations in 2016 and continued to adversely impact their results of operations in 2017. As of June 1, 2017, Power completed recognition of the incremental D&A of $938 million ($964 million in total) due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the first nine months of 2017, Energy Costs of $10 million and O&M of $12 million were also incurred and other costs may be incurred during the remaining period in 2017. See Item 1. Note 3. Early Plant Retirements for additional information.

Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such remediation are neither currently probable nor estimable but may be material.

In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.

Leveraged Lease Portfolio

GenOn Energy, Inc. (GenOn), the parent company of REMA, and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on June 14, 2017. REMA was not included in the GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its balance sheet and improve its liquidity. We continue to monitor the restructuring of GenOn and the possible related impact on REMA and continue to discuss the situation with GenOn.

During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its REMA leveraged

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lease receivables, which was reflected in Operating Revenues. During the second quarter of 2017, Energy Holdings recorded an additional $22 million pre-tax charge for its current best estimate of loss related to lease receivables due to collectability of payments ($15 million) and economics impacting the residual value ($7 million) of certain leased assets. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged lease receivables. For additional information, see Item 1. Note 6. Financing Receivables. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.

Additional facilities in our leveraged lease portfolio include the Joliet and Powerton generating facilities. Similar to Shawville, Joliet was recently converted to use natural gas. Converted natural gas units such as Shawville and Joliet may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. Powerton is a coal-fired generating facility in Illinois. Each of these three facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by other less efficient natural gas and coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged lease receivables associated with these facilities.

Salem

Concurrently with the planned refueling outage at the Salem 2 unit that was conducted in the second quarter of 2017, we inspected and replaced baffle bolts as part of our strategy to replace baffle bolts at the Salem station. The unit was returned to service in June 2017.

Operational Excellence

We emphasize operational performance, exercising diligence in managing costs, while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market. For the first nine months of 2017, our


•	utility continued top decile performance in electric reliability,


•	total nuclear fleet achieved an average capacity factor of 95%,


•	diverse fuel mix and dispatch flexibility allowed us to generate approximately 39 terawatt hours, and


•	combined cycle fleet produced 11 terawatt hours at an equivalent availability factor of 94%.

Financial Strength

Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first nine months of 2017 as we


•	maintained sufficient liquidity,


•	maintained solid investment grade credit ratings, and


•	increased our indicative annual dividend for 2017 to $1.72 per share.

We expect to be able to fund our planned capital requirements without the issuance of new equity.

Disciplined Investment

We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first nine months of 2017, we


•	made additional investments in transmission infrastructure projects,


•	continued to execute our BPU-approved utility programs, and


•	continued construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and began construction of BH5 for targeted commercial operations in mid-2019.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance in a cost-constrained environment with low gas prices, to capitalize on or otherwise address appropriately regulatory and legislative

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developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue to:


•	focus on controlling costs while maintaining safety and reliability and complying with applicable standards and requirements,


•	successfully manage our energy obligations and re-contract our open supply positions in response to changes in demand,


•	successfully launch and grow our retail energy business, which complements our existing wholesale energy business,


•	execute our utility capital investment program, including our Energy Strong program, GSMP and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliability of the service we provide to our customers,


•	effectively manage construction and start-up of our Keys, Sewaren 7, BH5 and other generation projects,


•	advocate for measures to ensure the implementation by PJM and FERC of market design and transmission planning rules that continue to promote fair and efficient electricity markets,


•	engage multiple stakeholders, including regulators, government officials, customers and investors, and


•	successfully operate the LIPA T&D system and manage LIPA’s fuel supply and generation dispatch obligations.

For 2017 and beyond, the key issues, challenges and opportunities we expect our business to confront include:


•	regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,


•	fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respect to our distribution base rate case proceeding to be filed in 2017,


•	the potential for comprehensive tax reform, particularly in light of public statements by the current U.S. administration and key members of Congress,


•	uncertainty in the national and regional economic performance, continuing customer conservation efforts, changes in energy usage patterns and evolving technologies, which impact customer behaviors and demand,


•	the potential for continued reductions in demand and sustained lower natural gas and electricity prices, both at market hubs and the locations where we operate,


•	the impact of lower natural gas prices and increasing environmental compliance costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,


•	ensuring timely completion of construction of our T&D, generation and other development projects, including obtaining required permits and regulatory approvals,


•	maintaining a diverse mix of fuels to mitigate risks associated with fuel price volatility and market demand cycles, and


•	FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market.

Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:


•	the acquisition, construction or disposition of transmission and distribution facilities and/or generation units,


•	the disposition or reorganization of our merchant generation business or other existing businesses or the acquisition or development of new businesses,


•	the expansion of our geographic footprint,

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•	continued or expanded participation in solar, energy efficiency and related programs, and


•	investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency, modernizing existing infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.

There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.

RESULTS OF OPERATIONS

PSEG

Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, PSE&G and Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 1. Note 18. Related-Party Transactions.




	Three Months Ended				Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2017		2016		2017 vs. 2016					2017		2016		2017 vs. 2016
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	2,263	$	2,450	$	(187	)	(8	)	$	6,988	$	6,971	$	17		—
Energy Costs	638		866		(228		)	(26	)	2,100		2,326		(226		)	(10	)
Operation and Maintenance	680		776		(96		)	(12	)	2,100		2,215		(115		)	(5	)
Depreciation and Amortization	252		231		21			9		1,721		679		1,042			N/A
Income from Equity Method Investments	3		3		—			—		11		9		2			22
Other Income (Deductions)	56		39		17			44		178		100		78			78
Other-Than-Temporary Impairments	5		5		—			—		9		25		(16		)	(64	)
Interest Expense	100		99		1			1		289		288		1			—
Income Tax Expense	252		188		64			34		340		562		(222		)	(40	)

The following discussions for PSE&G and Power provide a detailed explanation of their respective variances.

PSE&G




	Three Months Ended				Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2017		2016		2017 vs. 2016					2017		2016		2017 vs. 2016
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,509	$	1,684	$	(175	)	(10	)	$	4,689	$	4,746	$	(57	)	(1	)
Energy Costs	535		721		(186		)	(26	)	1,760		1,979		(219		)	(11	)
Operation and Maintenance	346		376		(30		)	(8	)	1,064		1,110		(46		)	(4	)
Depreciation and Amortization	169		137		32			23		506		412		94			23
Other Income (Deductions)	22		21		1			5		67		58		9			16
Interest Expense	79		72		7			10		223		214		9			4
Income Tax Expense	156		144		12			8		450		393		57			15

Three Months Ended September 30, 2017 as Compared to 2016

Operating Revenues decreased $175 million due to changes in delivery, commodity, clause and other operating revenues.

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Delivery Revenues increased $10 million due primarily to an increase in transmission revenues.


•	Transmission revenues were $34 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.


•	Gas distribution revenues increased $5 million due to a $1 million increase from the inclusion of Energy Strong in base rates, and $1 million increases in both GSMP collections and Green Program Recovery Charges (GPRC) and higher sales volumes.


•	Electric distribution revenues decreased $29 million due to a $38 million decrease due to lower sales volumes and lower GPRC of $6 million, partially offset by a $15 million increase from the inclusion of Energy Strong in base rates.

Commodity Revenue decreased $186 million as a result of lower Electric and Gas revenues. The changes in Commodity revenue for both electric and gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.


•	Electric commodity revenues decreased $176 million due primarily to a $153 million decrease in BGS revenues due to $97 million in lower sales volumes and $56 million from lower prices and $23 million of lower revenues from collections of Non-Utility Generation Charges (NGC).


•	Gas commodity revenues decreased $10 million due to lower BGSS sales prices of $22 million, partially offset by higher BGSS sales volumes of $12 million.

Clause Revenues increased $1 million due primarily to the return of $20 million to customers in 2016 of overcollections of Securitization Transition Charges (STC), partially offset by lower Societal Benefit Charges (SBC) of $12 million and a $6 million decrease in 2017 in Margin Adjustment Clause (MAC) revenues. The changes in the STC, SBC and MAC amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC, SBC or MAC collections.

Operating Expenses

Energy Costs decreased $186 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenance decreased $30 million, primarily due to a $17 million reduction in clause-related costs, $6 million in lower appliance service costs, $6 million of lower distribution corrective and preventative maintenance and a $5 million reduction in GPRC related costs, partially offset by a net increase of $4 million in certain operational expenses.

Depreciation and Amortization increased $32 million due primarily to an increase of $19 million in amortization of Regulatory Assets and a $14 million increase in depreciation due to additional plant in service.

Interest Expense increased $7 million due primarily to an increase of $5 million due to net debt issuances in 2016 and 2017 and a $2 million increase in other interest.

Income Tax Expense increased $12 million due primarily to uncertain tax positions and plant-related items.

Nine Months Ended September 30, 2017 as Compared to 2016

Operating Revenues decreased $57 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $119 million due primarily to an increase in transmission revenues.


•	Transmission revenues were $116 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.


•	Gas distribution revenues increased $29 million due to a $14 million increase due to the inclusion of Energy Strong in base rates, $8 million in higher Weather Normalization Clause (WNC) revenue, a $7 million increase due to the GSMP and higher GPRC of $3 million, partially offset by $3 million of lower delivery volumes.


•	Electric distribution revenues decreased $26 million due to a $36 million decrease due to lower sales volumes and lower GPRC of $14 million, partially offset by a $24 million increase due to the inclusion of Energy Strong in base rates.

Commodity Revenue decreased $219 million as a result of lower Electric revenues partially offset by higher Gas revenues. The changes in Commodity revenue for both electric and gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.


•	Electric commodity revenues decreased $266 million due primarily to a $188 million decrease in BGS revenues due to $116 million in lower sales volumes and $72 million of lower prices, $64 million of lower revenues from collections of NGC and a decrease of $14 million due to lower volumes of Non-Utility Generation energy sold.

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•	Gas commodity revenues increased $47 million due primarily to $69 million of higher BGSS sales prices, partially offset by $22 million of lower sales volumes.

Clause Revenues increased $41 million due primarily to the 2016 return to customers of $50 million of overcollections of STC, and higher MAC revenues of $2 million in 2017, partially offset by a $12 million decrease in collections of SBC. The changes in the STC, MAC and SBC amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC, MAC or SBC collections.

Operating Expenses

Energy Costs decreased $219 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenance decreased $46 million, of which the most significant components were decreases of $17 million in distribution corrective and preventative maintenance, $14 million in appliance service costs, $11 million in clause-related costs and $11 million in GPRC costs, partially offset by a $10 million net increase in certain operational expenses.

Depreciation and Amortization increased $94 million due primarily to an increase of $51 million in amortization of Regulatory Assets and a $43 million increase in depreciation due to additional plant in service.

Other Income and (Deductions) increased $9 million due primarily to an increase of $7 million in allowance for funds used during construction and a $3 million increase in realized gains on Rabbi Trust investments, partially offset by a net $1 million decrease in Solar Loan interest.

Interest Expense increased $9 million due primarily to an increase of $16 million due to net debt issuances in 2016 and 2017, partially offset by a $7 million decrease predominantly driven by a reduction in clause interest.

Income Tax Expense increased $57 million due primarily to higher pre-tax income and changes in uncertain tax positions.

Power




	Three Months Ended				Increase/ (Decrease)					Nine Months Ended					Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,					Increase/ (Decrease)
	2017		2016		2017 vs. 2016					2017			2016		2017 vs. 2016
	Millions				Millions			%		Millions					Millions			%
Operating Revenues	$	873	$	1,075	$	(202	)	(19	)	$	3,086		$	3,102	$	(16	)	(1	)
Energy Costs	357		462		(105		)	(23	)	1,461			1,481		(20		)	(1	)
Operation and Maintenance	227		289		(62		)	(21	)	711			807		(96		)	(12	)
Depreciation and Amortization	76		86		(10		)	(12	)	1,191			245		946			N/A
Income from Equity Method Investments	3		3		—			—		11			9		2			22
Other Income (Deductions)	35		17		18			N/A		105			41		64			N/A
Other-Than-Temporary Impairments	5		5		—			—		9			25		(16		)	(64	)
Interest Expense	12		24		(12		)	(50	)	41			66		(25		)	(38	)
Income Tax Expense (Benefit)	98		90		8			9		(80		)	208		(288		)	N/A

Three Months Ended September 30, 2017 as Compared to 2016

Operating Revenues decreased $202 million due to changes in generation and gas supply revenues.

Generation Revenues decreased $200 million due primarily to


•	a decrease of $110 million due to MTM losses in 2017 as compared to MTM gains in 2016. Of this amount, $98 million was due to changes in forward prices and $12 million was due to greater gains on positions reclassified to realized upon settlement this year as compared to last year,


•	a decrease of $83 million in electricity sold under our BGS contracts due to lower volumes and lower prices, and


•	a decrease of $25 million in energy sales in the PJM region due to lower generation volumes and lower average realized prices,

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•	partially offset by a net increase of $18 million due primarily to higher capacity revenue and electricity sold under wholesale load contracts at higher average prices, coupled with new solar projects.

Gas Supply Revenues decreased $2 million due to lower MTM gains in 2017 as compared to 2016.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $105 million due to

Generation costs decreased $108 million due primarily to


•	a net decrease of $59 million due to charges associated with the early retirement of the Mercer and Hudson units announced in October 2016, primarily related to a coal inventory write-down, partially offset by additional retirement costs incurred in 2017,


•	a net decrease of $26 million due primarily to lower natural gas costs reflecting lower volumes,


•	a net decrease of $11 million primarily due to lower congestion costs in PJM due to lower congestion rates coupled with less congestion volumes, and


•	a decrease of $8 million due to MTM gains in 2017 as compared to MTM losses in 2016.

Gas costs increased $3 million due mainly to a net increase of $2 million related to sales to third parties, of which $5 million was due to higher average gas costs, partially offset by $3 million due to lower volumes sold.

Operation and Maintenance decreased $62 million due primarily to


•	a $51 million decrease at our fossil plants, due to the retirement of the Hudson and Mercer units on June 1, 2017, and


•	a $10 million net decrease related to our nuclear plants due primarily to lower labor-related costs.

Depreciation and Amortization decreased $10 million due primarily to


•	$19 million of lower depreciation due to the retirement of the Hudson and Mercer units,


•	partially offset by $4 million of increased depreciation due to the accelerated retirement date at Bridgeport Harbor Station unit 3 (BH3),


•	$3 million of higher depreciation due to new solar projects, and


•	a $2 million increase due to additional nuclear plant placed into service.

Other Income (Deductions) increased $18 million due primarily to higher net realized gains in the NDT Fund.

Interest Expense decreased $12 million due primarily to


•	a $7 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys, and


•	a $5 million decrease due to debt maturities in September 2016.

Income Tax Expense (Benefit) reflected an increased tax expense of $8 million due primarily to changes in the manufacturing deduction and higher pre-tax income in 2017.

Nine Months Ended September 30, 2017 as Compared to 2016

Operating Revenues decreased $16 million due to changes in generation and gas supply revenues.

Generation Revenues decreased $101 million due primarily to


•	a net decrease of $115 million in energy sales in the PJM and New England regions due primarily to lower average realized prices,


•	a decrease of $91 million in electricity sold under our BGS contracts due to lower volumes and lower prices,


•	a net decrease of $11 million in operating reserves in the PJM region, and


•	a charge of $10 million due to an increase in the FERC reserve accrual related to the PJM bidding matter see Item 1. Note 9. Commitments and Contingent Liabilities,

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•	partially offset by an increase of $86 million due to lower MTM losses in 2017 as compared to 2016. Of this amount, $110 million was due to lower gains on positions reclassified to realized upon settlement this year as compared to last year partially offset by a decrease of $24 million due to changes in forward power prices.


•	a net increase of $31 million due primarily to higher volumes of electricity sold under wholesale load contracts in the NE region, and


•	an increase of $10 million due to new solar projects.

Gas Supply Revenues increased $84 million due primarily to


•	an increase of $45 million in sales under the BGSS contract due primarily to higher average sales prices,


•	an increase of $25 million related to sales to third parties, of which $52 million was due to higher average sales prices, partially offset by $27 million of lower volumes sold, and


•	a net increase of $14 million due to MTM gains in 2017 as compared to MTM losses in 2016.

Operating Expenses

Generation costs decreased $76 million due primarily to


•	a net decrease of $57 million primarily due to lower congestion costs in PJM due to lower congestion rates coupled with less congestion volumes, partially offset by higher transmission charges due to higher rates,


•	a net decrease of $49 million due to charges associated with the announced early retirement of the Mercer and Hudson units in 2016, primarily related to a coal inventory write-down partially offset by additional retirement costs incurred in 2016,


•	partially offset by higher fuel costs of $12 million reflecting higher average realized prices for natural gas coupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of gas and oil,


•	a net increase of $10 million primarily due to an increase in energy purchase volumes in the NE region to serve load obligations, and


•	an increase of $9 million due to MTM losses in 2017 as compared to MTM gains in 2016.

Gas costs increased $56 million due mainly to


•	an increase of $32 million related to sales under the BGSS contract due to higher average gas costs, and


•	an increase of $24 million related to sales to third parties, of which $48 million was due to higher average gas costs, partially offset by a $24 million decrease in volumes sold.

Operation and Maintenance decreased $96 million due primarily to


•	a $71 million decrease at our fossil plants, due primarily to the retirement of the Hudson and Mercer units and higher planned outage costs in 2016 as compared to 2017,


•	a $20 million net decrease related to our nuclear plants due primarily to lower labor-related costs and outage costs, and


•	an $8 million legal accrual for environmental expenses recorded in 2016,


•	partially offset by $3 million of costs related to new solar plants placed into service since September 2016.

Depreciation and Amortization increased $946 million due primarily to


•	$914 million of higher depreciation due to the early retirement of the Hudson and Mercer units,


•	$11 million of increased depreciation due to the accelerated retirement date at BH3,


•	$9 million of higher depreciation due to new solar projects, and


•	a $9 million increase due to additional nuclear plant placed into service.

Other Income (Deductions) increased $64 million due primarily to $57 million of higher net realized gains in the NDT Fund and $3 million of higher net realized gains in the Rabbi Trust Fund.

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Other-Than-Temporary Impairments decreased $16 million due to lower impairments of equity securities in the NDT Fund in 2017.

Interest Expense decreased $25 million due primarily to


•	a $16 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys, and


•	a net $7 million decrease due to debt maturities in September 2016, partially offset by a debt issuance in June 2016.

Income Tax Expense (Benefit) decreased $288 million in 2017 due primarily to a pre-tax loss in 2017 as compared to pre-tax income in 2016.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.

Operating Cash Flows

We expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund capital expenditures and shareholder dividend payments.

For the nine months ended September 30, 2017, our operating cash flow decreased $27 million as compared to the same period in 2016. The net change was due primarily to net changes from PSE&G and Power as discussed below as well as net tax payments at PSEG and its other subsidiaries.

PSE&G

PSE&G’s operating cash flow decreased $8 million from $1,401 million to $1,393 million for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to lower tax refunds and a decrease of $49 million due to a change in regulatory deferrals, partially offset by higher earnings.

Power

Power’s operating cash flow decreased $11 million from $1,260 million to $1,249 million for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to tax payments in 2017 as compared to tax refunds in 2016 and lower earnings, partially offset by a $68 million decrease in margin deposit requirements and a $30 million increase from net collection of counterparty receivables.

Short-Term Liquidity

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.

Our total credit facilities and available liquidity as of September 30, 2017 were as follows:




Company/Facility	As of September 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	215	$	1,285
PSE&G	600		15		585
Power	2,100		182		1,918
Total	$	4,200	$	412	$	3,788

As of September 30, 2017, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of Power losing its investment grade credit rating from S&P or Moody’s, which would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of Power’s

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credit rating certain of Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if Power were to lose its investment grade credit rating was approximately $899 million and $783 million as of September 30, 2017 and December 31, 2016, respectively.

For additional information, see Item 1. Note 10. Debt and Credit Facilities.

Long-Term Debt Financing

During the next twelve months, PSEG has a floating rate $500 million term loan maturing in November 2017. PSE&G has $400 million of 5.30% Medium-Term Notes maturing in May 2018 and $350 million of 2.30% Medium-Term Notes maturing in September 2018.

For a discussion of our long-term debt issuances and maturities during 2017, see Item 1. Note 10. Debt and Credit Facilities.

Common Stock Dividends

On July 18, 2017, our Board of Directors approved a $0.43 dividend per share of common stock for the third quarter of 2017. This reflects an indicative annual dividend rate of $1.72 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 1. Note16. Earnings Per Share (EPS) and Dividends.

Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s) and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

In April 2017, S&P published updated research and affirmed the ratings and outlooks of PSEG and PSE&G. In June 2017, S&P published updated research on Power and the rating and outlook remained unchanged. In July 2017, Moody’s upgraded PSEG’s senior unsecured rating to Baa1 from Baa2 and revised its outlook to Stable from Positive. Also in July, Moody’s affirmed the ratings at PSE&G and Power.




	Moody’s (A)	S&P (B)
PSEG
Outlook	Stable	Stable
Senior Notes	Baa1	BBB
Commercial Paper	P2	A2
PSE&G
Outlook	Stable	Stable
Mortgage Bonds	Aa3	A
Commercial Paper	P1	A2
Power
Outlook	Stable	Stable
Senior Notes	Baa1	BBB+


(A)	Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.


(B)	S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

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CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There were no material changes to our projected capital expenditures as compared to amounts disclosed in our 2016 Form 10-K.

PSE&G

During the nine months ended September 30, 2017, PSE&G made capital expenditures of $2,118 million, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $72 million, which are included in operating cash flows.

In July 2017, PSE&G filed a petition with the BPU for a GSMP II program, requesting extension of our gas system modernization program through which PSE&G has proposed investing up to $540 million per year beginning in 2019 to continue to modernize our gas system. Under this proposed program, PSE&G plans to replace up to 1,250 miles of gas mains and associated service lines. This is not included in PSE&G’s projected capital expenditures.

Power

During the nine months ended September 30, 2017, Power made capital expenditures of $779 million, excluding $124 million for nuclear fuel, primarily related to our Keys, Sewaren 7, BH5 and other generation projects.

ACCOUNTING MATTERS

For information related to recent accounting matters, see Item 1. Note 2. Recent Accounting Standards.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Condensed Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.

Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.

Commodity Contracts

The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.

Value-at-Risk (VaR) Models

VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.

MTM VaR consists of MTM derivatives that are economic hedges. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities.

The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.

From July through September 2017, MTM VaR remained relatively stable between a low of $5 million and a high of $9 million at the 95% confidence level. The range of VaR was narrower for the three months ended September 30, 2017 as compared with the year ended December 31, 2016.

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	MTM VaR
	Three Months Ended September 30, 2017		Year Ended December 31, 2016
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	8	$	26
Average for the Period	$	7	$	16
High	$	9	$	32
Low	$	5	$	10
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	13	$	40
Average for the Period	$	11	$	25
High	$	15	$	51
Low	$	8	$	16

See Item 1. Note 11. Financial Risk Management Activities for a discussion of credit risk.


ITEM 4.	CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSEG, PSE&G and Power

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of PSEG, PSE&G and Power. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG, PSE&G and Power have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.

Internal Controls

PSEG, PSE&G and Power

There have been no changes in internal control over financial reporting that occurred during the third quarter of 2017 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

PART II. OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

We are party to various lawsuits and regulatory matters in the ordinary course of business. For additional information regarding material legal proceedings, including updates to information reported in Item 3 of Part I of the 2016 Annual Report on Form 10-K, see Part I, Item 1. Note 9. Commitments and Contingent Liabilities and Item 5. Other Information.


ITEM 1A.	RISK FACTORS

The discussion of our business and operations in this Quarterly Report on Form 10-Q should be read together with the risk factors contained in Part I, Item 1A of our 2016 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, which describe various risks and uncertainties that could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report. Except as discussed below, there have been no material changes to the risk factors set forth in the above-referenced filings as of September 30, 2017.

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Cybersecurity attacks or intrusions could adversely impact our businesses.

Cybersecurity threats to the U.S. energy market infrastructure are increasing in sophistication, magnitude and frequency. We rely on information technology systems that utilize sophisticated digital systems and network infrastructure to operate our generation, transmission and distribution systems. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers and vendors on our systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the information technology systems of third parties, including our vendors, regulators, RTOs and Independent System Operators (ISOs), among others. Our and third-party information technology systems may be vulnerable to cybersecurity attacks involving domestic or foreign sources. A cybersecurity attack may also leverage such information technology to cause disruptions at a third party. Cybersecurity impacts to our operations include:


•	disruption of the operation of our assets and the power grid,


•	theft of confidential company, employee, shareholder, vendor or customer information, which may cause us to be in breach of certain covenants and contractual obligations,


•	general business system and process interruption or compromise, including preventing us from servicing our customers, collecting revenues or the ability to record, process and/or report financial information correctly, and


•	breaches of vendors’ infrastructures where our confidential information is stored.

We have experienced and expect to continue to experience actual or attempted cyber-attacks on our information technology systems; however, none of these incidents has had a material impact on our operations or financial condition. If a significant cybersecurity event or breach should occur within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties for non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, reputational damage and loss of confidence from our customers, regulators, investors, vendors and employees. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Part 1, Item 1. Regulatory Issues in our Annual Report on Form 10-K for the year ended December 31, 2016 and Item 5. Other Information in this Quarterly Report on Form 10-Q.

The market for cybersecurity insurance is relatively new and coverage available for cybersecurity events may evolve as the industry matures. While we maintain insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damage we experience.


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

The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the third quarter of 2017.




Three Months Ended September 30, 2017	Total Number of Shares Purchased	Average Price Paid per Share
July 1 - July 31	—	$	—
August 1 - August 31	135,277	$	45.25
September 1- September 30	—	$	—

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ITEM 5. OTHER INFORMATION

Certain information reported in the 2016 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2016 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017. References are to the related pages on the Forms 10-K and 10-Q as printed and distributed.

Employee Relations

December 31, 2016 Form 10-K page 15. In 2016, six of our eight labor unions ratified extensions of their collective bargaining agreements with us, with expiration dates from 2019 to 2021. In 2017, each of the remaining two unions ratified extensions of their collective bargaining agreements with us with expiration dates in 2021 and 2022.

Federal Regulation

FERC

Energy Clearing Prices/Price Formation Initiatives

December 31, 2016 Form 10-K page 16 and March 31, 2017 Form 10-Q on page 76. Energy clearing prices in the markets in which we operate are generally based on bids submitted by generating units. Under FERC-approved market rules, bids are subject to price caps and mitigation rules applicable to certain generation units. FERC rules also govern the overall design of these markets. At present, all units within a delivery zone receive a clearing price based on the bid of the marginal unit (i.e. the last unit that must be dispatched to serve the needs of load) which can vary by location. In addition, recent rule changes in the energy markets administered by PJM and ISO-NE (see Capacity Market Issues below) impose rigorous performance obligations and nonperformance penalties on resources during times of system stress. These FERC rules provide an opportunity for bonus payments or require the payment of penalties depending on whether a unit is available during a performance hour.

FERC has also recently ordered certain favorable changes to energy market price formation rules improving shortage pricing and enhancing bidding flexibility for units. We continue to advocate in this context for additional changes in market rules that would provide more transparency about energy market prices. We cannot predict what action FERC might ultimately take, but such an examination could lead to future rule changes.

Notice of Proposed Rulemaking on Baseload Generation

In September 2017, the Secretary of the U.S. Department of Energy issued a Notice of Proposed Rulemaking (NOPR) to allow a full recovery of costs for certain eligible units physically located within the FERC-approved organized markets. The NOPR directs FERC to take final action within 60 days. The NOPR contemplates a cost-of-service payment and a fair rate of return for units that are able to provide certain essential energy and ancillary reliability services, have a 90-day fuel supply on site and are not subject to cost-of-service rate regulation by any State or local authority. We are participating in this proceeding, but we are unable to predict the outcome.

Capacity Market Issues

December 31, 2016 Form 10-K page 16, March 31, 2017 Form 10-Q on page 76 and June 30, 2017 Form 10-Q on page 83. PJM, the New York Independent System Operator (NYISO) and the Independent System Operator New England, Inc. each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources or resource attributes, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. FERC held a technical conference to seek input from the industry on potential options to integrate public policy goals in wholesale markets. We cannot predict what action, if any, FERC might take with regard to capacity market designs.

Capacity Market Issues—PJM

December 31, 2016 Form 10-K page 16, March 31, 2017 Form 10-Q on page 76 and June 30, 2017 Form 10-Q page 83. PJM issued a series of white papers in response to public policies that seek to recognize value associated with generation plants beyond their cost effectiveness and reliability attributes. The three proposals are intended to spur stakeholder discussion and include both potential capacity and energy market reforms. The first energy market reform (see Energy Clearing Prices/Price Formation Initiatives) would allow inflexible generating units to set prices resulting in reduced uplift payments and improved

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price signals while the second energy market reform contemplates a voluntary carbon pricing program where states that elect to participate in the program would agree to put a price on carbon emissions. The capacity market proposal contemplates a two-stage capacity auction which, in its current form, would improve prices for unsubsidized resources, but would still continue to provide capacity payments for subsidized resources.

Transmission Regulation

December 31, 2016 Form 10-K page 18. In October 2017, PSE&G filed its 2018 Annual Formula Rate Update with FERC which requests approximately $212 million in increased annual transmission revenues effective January 1, 2018, subject to true-up. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. For additional information about our transmission formula rate, see Part I Item 1. Note 5. Rate Filings.

Transmission Regulation—Transmission Policy Developments

December 31, 2016 Form 10-K page 18, March 31, 2017 Form 10-Q on page 77 and June 30, 2017 Form 10-Q on page 83.

In a February 2016 order, FERC reversed a previous order and accepted a filing by the PJM transmission owners seeking authority to assign costs for Regional Transmission Expansion Plan projects (subject to PJM Board approval requirements) solely addressing localized needs to customers within the local transmission owner’s zone. FERC’s action in this order provides an exemption from the Order 1000 open window procedures for projects constructed by transmission owners to meet local transmission planning criteria. FERC’s orders have been challenged at the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit) and PSE&G has intervened in support of FERC.

In April 2017, the PJM Board announced that it would be lifting the previously disclosed suspension of the Artificial Island transmission project and approved the award to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. In October 2017, FERC accepted PJM’s filing on the grounds that PJM correctly applied its Tariff. However, FERC deferred a ruling on whether the cost allocation methodology applied to the Artificial Island project is appropriate. FERC will decide this issue in a separate proceeding that is currently pending. We are unable to predict the outcome.

Nuclear Regulatory Commission (NRC)

December 31, 2016 Form 10-K page 20. The NRC continues to evaluate potential revisions to its requirements in connection with its operational and safety reviews of nuclear facilities in the United States as a result of the Fukushima Daiichi incident. We are also subject to cybersecurity regulations promulgated by the NRC.

We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to our Salem, Hope Creek and Peach Bottom facilities, but such cost could be material.

State Regulation

Cybersecurity Requirements for Regulated Entities

December 31, 2016 Form 10-K page 21. In March 2016, the BPU issued an order for the regulated electric, natural gas and water/wastewater utilities to further reduce the potential for cyber threats to the reliability and resiliency of utility service and to protect customers’ information. The order requires these regulated utilities, including PSE&G, to, among other conditions, implement a cybersecurity program that defines and implements organization accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. New Jersey utilities, including PSE&G, were required to be compliant with these requirements by October 1, 2017. We have submitted the required certification of compliance to the BPU.

In an effort to reduce the likelihood and severity of cyber incidents, we have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our company and our customers’ information and our systems. In addition, we are subject to maintaining key cybersecurity controls to meet mandatory cybersecurity regulatory requirements. Our cybersecurity program is built on technical, procedural, and people-focused measures to detect, protect against, respond to, and recover from cyber threats to our systems and information including company, employee and customer data. Features of our program include: identifying critical information and systems; conducting cyber risk assessments of our and third party systems; maintaining awareness of cyber threats and vulnerabilities through partnerships with public and private entities, as well as industry groups; maintaining and testing our cybersecurity incident response plans and systems; training personnel on cybersecurity issues; and raising cybersecurity awareness throughout our company with electronic notices and seminars. We cannot assure that our cybersecurity program will be effective in preventing or mitigating cybersecurity incidents. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.

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Energy Efficiency 2017 Program (EE 2017)

In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extend the subprogram offerings and establish the residential energy efficiency sub-programs under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11th component of the GPRC rate effective September 1, 2017.

Consolidated Tax Adjustments (CTA)

December 31, 2016 Form 10-K page 21. New Jersey is one of only a few states that make CTA in setting rates for regulated utilities. These adjustments to rate base are made during the rate setting process and are intended to allocate to utility customers a portion of the tax benefits realized from the filing of a consolidated federal tax return by the utility’s parent corporation. The BPU has been considering the appropriateness of the adjustment and the methodology and mechanics of the calculation for some time. In October 2014, the BPU approved a proposal by its Staff that limits the tax benefit period to be considered in the calculation to five years, sets the distribution rate base adjustment at 25% of any such tax benefit and eliminates from the process any tax benefits tied to transmission earnings. In accordance with this October action, this CTA policy will be applied only with respect to future distribution rate base cases. In November 2014, the New Jersey Division of Rate Counsel appealed the BPU’s decision and in September 2017, the New Jersey Superior Court, Appellate Division granted that appeal on procedural grounds. While the issue has now been remanded to the BPU, it is not expected that application of a CTA will have a material impact on PSE&G’s current earnings or in its upcoming rate case filing.

Environmental Matters

Air Pollution Control

Hazardous Air Pollutants Regulation

December 31, 2016 Form 10-K page 22. In June 2015, the U.S. Supreme Court held that it was unreasonable for the EPA to refuse to consider the materiality of costs in determining whether to regulate hazardous air pollutants from power plants. In April 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plants in response to the U.S. Supreme Court’s ruling. Industry participants and various state authorities have filed petitions with the D.C. Circuit challenging the EPA’s Supplemental Finding. The D.C. Circuit is holding the case in abeyance pending further directions from the EPA. We do not expect this Supplemental Finding to impact operation of our facilities.

Climate Change

CO₂Regulation under the Clean Air Act (CAA)

December 31, 2016 Form 10-K page 23. In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards that establish emissions standards for CO₂ for certain new fossil power plants and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the CAA for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In April 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance for at least 60 days while the agency reviews the rule, which was subsequently extended by the D.C. Circuit in August 2017. In October 2017, upon completion of the review, the EPA Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). Whether the EPA chooses to propose a replacement rule has not been decided. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.

Regional Greenhouse Gas Initiative (RGGI)

December 31, 2016 Form 10-K page 23. In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO₂emission reductions in the electric power industry. New Jersey withdrew from RGGI in 2012. However, certain northeastern states (RGGI States), including New York and Connecticut where we have generation facilities, have state-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO₂ emissions. These rules make allowances available through a regional auction whereby generators may acquire allowances that are each equal to one ton of CO₂ emissions. Generators are required to submit an allowance for each ton emitted over a three-year period. Allowances are available through the auction or through secondary markets.

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In September 2017, the RGGI States announced their new post-2020 program for a cap on regional CO₂ emissions, which would require a decline in CO₂ emissions in 2021 and each year thereafter, resulting in a 30% reduction in the CO₂ emissions cap by 2030.

Water Pollution Control

Steam Electric Effluent Guidelines

December 31, 2016 Form 10-K page 23, March 31, 2017 Form 10-Q on page 77 and June 30, 2017 Form 10-Q on page 85. In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations for the aforementioned waste streams. In September 2017, the EPA issued a rule postponing for two years compliance dates related solely to bottom ash transport water and flue gas desulfurization wastewater. The EPA has announced plans to issue a new rule by November 2020 addressing revised requirements and compliance dates for these two waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

Cooling Water Intake Structure

December 31, 2016 Form 10-K page 24. In May 2014, the EPA issued a final cooling water intake rule under Section 316(b) of the Clean Water Act (CWA) that establishes new requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision remains pending.

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ITEM 6.	EXHIBITS

A listing of exhibits being filed with this document is as follows:



a. PSEG:
Exhibit 10		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017
Exhibit 12:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 31:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.1:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

b. PSE&G:
Exhibit 10		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017
Exhibit 12.1:		Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
Exhibit 31.2:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.3:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

c. Power:
Exhibit 10		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017
Exhibit 12.2:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 31.4:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.5:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.4:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.5:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.



PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: October 31, 2017

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SIGNATURE



PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: October 31, 2017

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SIGNATURE



PSEG POWER LLC
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: October 31, 2017