PUBLIC SERVICE ENTERPRISE GROUP INC - Quarter Report: 2017 March (Form 10-Q)

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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 March 31, 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 April 18, 2017, Public Service Enterprise Group Incorporated had outstanding 505,878,825 shares of its sole class of Common Stock, without par value.

As of April 18, 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)	20
	Note 5. Rate Filings	21
	Note 6. Financing Receivables	21
	Note 7. Available-for-Sale Securities	23
	Note 8. Pension and Other Postretirement Benefits (OPEB)	29
	Note 9. Commitments and Contingent Liabilities	30
	Note 10. Debt and Credit Facilities	38
	Note 11. Financial Risk Management Activities	39
	Note 12. Fair Value Measurements	44
	Note 13. Other Income and Deductions	51
	Note 14. Income Taxes	52
	Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax	53
	Note 16. Earnings Per Share (EPS) and Dividends	56
	Note 17. Financial Information by Business Segments	57
	Note 18. Related-Party Transactions	57
	Note 19. Guarantees of Debt	59
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	61
	Executive Overview of 2017 and Future Outlook	61
	Results of Operations	67
	Liquidity and Capital Resources	71
	Capital Requirements	73
	Accounting Matters	73
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	73
Item 4.	Controls and Procedures	74

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	74
Item 1A.	Risk Factors	74
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	76
Item 5.	Other Information	76
Item 6.	Exhibits	79
	Signatures	80

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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
	March 31,
	2017			2016
OPERATING REVENUES	$	2,592		$	2,616
OPERATING EXPENSES
Energy Costs	874			836
Operation and Maintenance	712			729
Depreciation and Amortization	828			224
Total Operating Expenses	2,414			1,789
OPERATING INCOME	178			827
Income from Equity Method Investments	3			2
Other Income	72			48
Other Deductions	(11		)	(21		)
Other-Than-Temporary Impairments	(1		)	(10		)
Interest Expense	(98		)	(92		)
INCOME BEFORE INCOME TAXES	143			754
Income Tax Expense	(29		)	(283		)
NET INCOME	$	114		$	471
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			505
DILUTED	508			508
NET INCOME PER SHARE:
BASIC	$	0.23		$	0.93
DILUTED	$	0.22		$	0.93
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.43		$	0.41

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
	March 31,
	2017		2016
NET INCOME	$	114	$	471
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(16) and $(16) for 2017 and 2016, respectively	15		16
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0 and $(1) for 2017 and 2016, respectively	—		2
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(4) and $(6) for 2017 and 2016, respectively	6		8
Other Comprehensive Income (Loss), net of tax	21		26
COMPREHENSIVE INCOME	$	135	$	497

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	March 31, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	193		$	423
Accounts Receivable, net of allowances of $67 in 2017 and $68 in 2016	1,212			1,161
Tax Receivable	9			78
Unbilled Revenues	209			260
Fuel	173			326
Materials and Supplies, net	566			561
Prepayments	56			76
Derivative Contracts	114			163
Regulatory Assets	176			199
Other	8			7
Total Current Assets	2,716			3,254
PROPERTY, PLANT AND EQUIPMENT	40,195			39,337
Less: Accumulated Depreciation and Amortization	(10,850		)	(10,051		)
Net Property, Plant and Equipment	29,345			29,286
NONCURRENT ASSETS
Regulatory Assets	3,287			3,319
Long-Term Investments	1,001			1,050
Nuclear Decommissioning Trust (NDT) Fund	1,913			1,859
Long-Term Tax Receivable	113			104
Long-Term Receivable of Variable Interest Entity (VIE)	595			589
Other Special Funds	221			217
Goodwill	16			16
Other Intangibles	106			98
Derivative Contracts	93			24
Other	258			254
Total Noncurrent Assets	7,603			7,530
TOTAL ASSETS	$	39,664		$	40,070

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	March 31, 2017			December 31, 2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	500		$	500
Commercial Paper and Loans	315			388
Accounts Payable	1,245			1,459
Derivative Contracts	7			13
Accrued Interest	131			97
Accrued Taxes	172			31
Clean Energy Program	86			142
Obligation to Return Cash Collateral	135			132
Regulatory Liabilities	74			88
Other	446			426
Total Current Liabilities	3,111			3,276
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,567			8,658
Regulatory Liabilities	131			118
Asset Retirement Obligations	738			726
OPEB Costs	1,309			1,324
OPEB Costs of Servco	460			452
Accrued Pension Costs	547			568
Accrued Pension Costs of Servco	126			128
Environmental Costs	393			401
Derivative Contracts	1			3
Long-Term Accrued Taxes	180			180
Other	198			211
Total Noncurrent Liabilities	12,650			12,769
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT	10,898			10,895
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016—534 shares	4,920			4,936
Treasury Stock, at cost, 2017 and 2016—29 shares	(743		)	(717		)
Retained Earnings	9,070			9,174
Accumulated Other Comprehensive Loss	(242		)	(263		)
Total Stockholders’ Equity	13,005			13,130
Total Capitalization	23,903			24,025
TOTAL LIABILITIES AND CAPITALIZATION	$	39,664		$	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)




	Three Months Ended
	March 31,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	114		$	471
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	828			224
Amortization of Nuclear Fuel	54			58
Renewable Energy Credit (REC) Compliance Accrual	26			27
Provision for Deferred Income Taxes (Other than Leases) and ITC	(85		)	182
Non-Cash Employee Benefit Plan Costs	23			32
Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes	(15		)	(15		)
Net (Gain) Loss on Lease Investments	32			—
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(5		)	(21		)
Net Change in Regulatory Assets and Liabilities	(60		)	(105		)
Cost of Removal	(24		)	(35		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(23		)	3
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	69			301
Accrued Taxes	143			144
Margin Deposit	(4		)	(4		)
Other Current Assets and Liabilities	163			27
Employee Benefit Plan Funding and Related Payments	(28		)	(56		)
Other	(12		)	(19		)
Net Cash Provided By (Used In) Operating Activities	1,196			1,214
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,062		)	(1,065		)
Purchase of Emissions Allowances and RECs	(15		)	(16		)
Proceeds from Sales of Available-for-Sale Securities	298			202
Investments in Available-for-Sale Securities	(307		)	(207		)
Other	7			5
Net Cash Provided By (Used In) Investing Activities	(1,079		)	(1,081		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(73		)	(352		)
Issuance of Long-Term Debt	—			850
Redemption of Long-Term Debt	—			(171		)
Cash Dividends Paid on Common Stock	(218		)	(207		)
Other	(56		)	(55		)
Net Cash Provided By (Used In) Financing Activities	(347		)	65
Net Increase (Decrease) in Cash and Cash Equivalents	(230		)	198
Cash and Cash Equivalents at Beginning of Period	423			394
Cash and Cash Equivalents at End of Period	$	193		$	592
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(80	)	$	(299	)
Interest Paid, Net of Amounts Capitalized	$	77		$	66
Accrued Property, Plant and Equipment Expenditures	$	492		$	434

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
	March 31,
	2017			2016
OPERATING REVENUES	$	1,812		$	1,712
OPERATING EXPENSES
Energy Costs	753			729
Operation and Maintenance	367			382
Depreciation and Amortization	171			139
Total Operating Expenses	1,291			1,250
OPERATING INCOME	521			462
Other Income	25			20
Other Deductions	(1		)	(1		)
Interest Expense	(75		)	(68		)
INCOME BEFORE INCOME TAXES	470			413
Income Tax Expense	(171		)	(151		)
NET INCOME	$	299		$	262

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
	March 31,
	2017			2016
NET INCOME	$	299		$	262
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $1 and $0 for 2017 and 2016, respectively	(1		)	—
COMPREHENSIVE INCOME	$	298		$	262

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)




	March 31, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	153		$	390
Accounts Receivable, net of allowances of $67 in 2017 and $68 in 2016	895			810
Accounts Receivable—Affiliated Companies	34			76
Unbilled Revenues	209			260
Materials and Supplies	187			180
Prepayments	6			9
Regulatory Assets	176			199
Derivative Contracts	1			—
Other	7			6
Total Current Assets	1,668			1,930
PROPERTY, PLANT AND EQUIPMENT	26,931			26,347
Less: Accumulated Depreciation and Amortization	(5,849		)	(5,760		)
Net Property, Plant and Equipment	21,082			20,587
NONCURRENT ASSETS
Regulatory Assets	3,287			3,319
Long-Term Investments	301			299
Other Special Funds	44			43
Other	105			110
Total Noncurrent Assets	3,737			3,771
TOTAL ASSETS	$	26,487		$	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)




	March 31, 2017		December 31, 2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Accounts Payable	$	574	$	718
Accounts Payable—Affiliated Companies	218		260
Accrued Interest	83		76
Clean Energy Program	86		142
Derivative Contracts	—		5
Obligation to Return Cash Collateral	135		132
Regulatory Liabilities	74		88
Other	319		296
Total Current Liabilities	1,489		1,717
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	6,042		5,873
OPEB Costs	991		1,009
Accrued Pension Costs	237		250
Regulatory Liabilities	131		118
Environmental Costs	324		332
Asset Retirement Obligations	214		213
Long-Term Accrued Taxes	116		130
Other	114		116
Total Noncurrent Liabilities	8,169		8,041
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT	7,819		7,818
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2017 and 2016—132 shares	892		892
Contributed Capital	945		945
Basis Adjustment	986		986
Retained Earnings	6,187		5,888
Accumulated Other Comprehensive Income	—		1
Total Stockholder’s Equity	9,010		8,712
Total Capitalization	16,829		16,530
TOTAL LIABILITIES AND CAPITALIZATION	$	26,487	$	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)




	Three Months Ended
	March 31,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	299		$	262
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	171			139
Provision for Deferred Income Taxes and ITC	160			147
Non-Cash Employee Benefit Plan Costs	13			18
Cost of Removal	(24		)	(35		)
Net Change in Other Regulatory Assets and Liabilities	(60		)	(105		)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	(34		)	(26		)
Materials and Supplies	(7		)	(6		)
Prepayments	3			26
Accounts Payable	(12		)	(24		)
Accounts Receivable/Payable—Affiliated Companies, net	15			197
Other Current Assets and Liabilities	40			35
Employee Benefit Plan Funding and Related Payments	(25		)	(44		)
Other	(25		)	(16		)
Net Cash Provided By (Used In) Operating Activities	514			568
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(748		)	(724		)
Proceeds from Sales of Available-for-Sale Securities	10			5
Investments in Available-for-Sale Securities	(10		)	(5		)
Solar Loan Investments	(4		)	—
Other	2			—
Net Cash Provided By (Used In) Investing Activities	(750		)	(724		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	—			(153		)
Issuance of Long-Term Debt	—			850
Redemption of Long-Term Debt	—			(171		)
Other	(1		)	(10		)
Net Cash Provided By (Used In) Financing Activities	(1		)	516
Net Increase (Decrease) In Cash and Cash Equivalents	(237		)	360
Cash and Cash Equivalents at Beginning of Period	390			198
Cash and Cash Equivalents at End of Period	$	153		$	558
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(26	)	$	(200	)
Interest Paid, Net of Amounts Capitalized	$	65		$	53
Accrued Property, Plant and Equipment Expenditures	$	287		$	318

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
	March 31,
	2017			2016
OPERATING REVENUES	$	1,284		$	1,313
OPERATING EXPENSES
Energy Costs	707			638
Operation and Maintenance	230			253
Depreciation and Amortization	650			79
Total Operating Expenses	1,587			970
OPERATING INCOME (LOSS)	(303		)	343
Income from Equity Method Investments	3			2
Other Income	38			26
Other Deductions	(7		)	(18		)
Other-Than-Temporary Impairments	(1		)	(10		)
Interest Expense	(16		)	(22		)
INCOME (LOSS) BEFORE INCOME TAXES	(286		)	321
Income Tax Benefit (Expense)	116			(129		)
NET INCOME (LOSS)	$	(170	)	$	192

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

Millions

(Unaudited)




	Three Months Ended
	March 31,
	2017			2016
NET INCOME (LOSS)	$	(170	)	$	192
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(18) and $(16) for 2017 and 2016, respectively	19			16
Pension/OPEB adjustment, net of tax (expense) benefit of $(4) and $(5) for 2017 and 2016, respectively	5			7
Other Comprehensive Income (Loss), net of tax	24			23
COMPREHENSIVE INCOME (LOSS)	$	(146	)	$	215

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)




	March 31, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	18		$	11
Accounts Receivable	263			276
Accounts Receivable—Affiliated Companies	175			205
Short-Term Loan to Affiliate	157			87
Fuel	173			326
Materials and Supplies, net	379			381
Derivative Contracts	111			162
Prepayments	13			10
Other	3			2
Total Current Assets	1,292			1,460
PROPERTY, PLANT AND EQUIPMENT	12,922			12,655
Less: Accumulated Depreciation and Amortization	(4,837		)	(4,135		)
Net Property, Plant and Equipment	8,085			8,520
NONCURRENT ASSETS
NDT Fund	1,913			1,859
Long-Term Investments	103			102
Goodwill	16			16
Other Intangibles	106			98
Other Special Funds	55			53
Derivative Contracts	93			24
Other	66			61
Total Noncurrent Assets	2,352			2,213
TOTAL ASSETS	$	11,729		$	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)




	March 31, 2017			December 31, 2016
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts Payable	$	513		$	539
Accounts Payable—Affiliated Companies	81			25
Derivative Contracts	7			8
Accrued Interest	42			20
Other	102			88
Total Current Liabilities	745			680
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	1,966			2,170
Asset Retirement Obligations	522			511
OPEB Costs	254			251
Derivative Contracts	1			3
Accrued Pension Costs	185			191
Long-Term Accrued Taxes	78			77
Other	117			129
Total Noncurrent Liabilities	3,123			3,332
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
LONG-TERM DEBT	2,383			2,382
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,437			4,782
Accumulated Other Comprehensive Loss	(187		)	(211		)
Total Member’s Equity	5,478			5,799
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,729		$	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)




	Three Months Ended
	March 31,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(170	)	$	192
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Depreciation and Amortization	650			79
Amortization of Nuclear Fuel	54			58
Provision for Deferred Income Taxes and ITC	(226		)	34
Interest Accretion on Asset Retirement Obligation	8			7
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(5		)	(21		)
Renewable Energy Credit (REC) Compliance Accrual	26			27
Non-Cash Employee Benefit Plan Costs	7			10
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(23		)	3
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	155			143
Margin Deposit	(4		)	(4		)
Accounts Receivable	24			(41		)
Accounts Payable	(18		)	(34		)
Accounts Receivable/Payable—Affiliated Companies, net	71			184
Other Current Assets and Liabilities	33			15
Employee Benefit Plan Funding and Related Payments	(2		)	(8		)
Other	—			19
Net Cash Provided By (Used In) Operating Activities	580			663
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(307		)	(333		)
Purchase of Emissions Allowances and RECs	(15		)	(16		)
Proceeds from Sales of Available-for-Sale Securities	259			183
Investments in Available-for-Sale Securities	(268		)	(188		)
Short-Term Loan—Affiliated Company, net	(70		)	(309		)
Other	7			4
Net Cash Provided By (Used In) Investing Activities	(394		)	(659		)
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid	(175		)	—
Other	(4		)	—
Net Cash Provided By (Used In) Financing Activities	(179		)	—
Net Increase (Decrease) in Cash and Cash Equivalents	7			4
Cash and Cash Equivalents at Beginning of Period	11			12
Cash and Cash Equivalents at End of Period	$	18		$	16
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	19		$	(100	)
Interest Paid, Net of Amounts Capitalized	$	5		$	11
Accrued Property, Plant and Equipment Expenditures	$	205		$	116

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

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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 demand response 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 through competitive energy sales in well-developed energy markets and fuel supply functions 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) 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 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. PSEG continues to evaluate all of its revenue streams and its contracts. Certain implementation issues are currently being finalized by the AICPA’s Revenue Recognition Working Group and the FASB’s Transition Resource Group, including the ability to recognize revenue for certain contracts where there is uncertainty regarding

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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collection from customers and accounting for contributions in aid of construction. Upon formal resolution of the implementation issues noted above, PSEG will elect its transition method.

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 is currently analyzing the impact of this standard on its financial statements; however, PSEG 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.

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 is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Restricted Cash

This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in their reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.

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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 a filter that would consider 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 does not have any current transactions impacted by this guidance and expects future acquisitions of individual solar plants will not qualify as business combinations. PSEG does not expect this guidance to materially impact its financial statements upon adoption.

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 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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. Power has filed deactivation notices with PJM for these existing units at both stations and final must-offer exception requests for the 2020-2021 PJM capacity auction to the PJM Independent Market Monitor. Power expects the units to continue to be available to generate electricity and receive previously cleared capacity payments through the date the units cease operations.

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.

In the first quarter of 2017, Power recognized total D&A of $574 million and expects to recognize additional total D&A of $389 million in 2017 for the Hudson and Mercer units. Power also recognized pre-tax charges in Energy Costs of $7 million primarily for coal inventory lower of cost or market adjustments. 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.

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. The change in the estimated useful life is not expected to have a material impact on Power’s future financial results.

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.

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 low natural gas prices, and the related decline in market prices of energy, resulting from 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 and greater reliance on natural gas pipelines for fuel delivery.

If trends noted above continue or worsen, Power’s 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 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 will likely have a material adverse impact on PSEG’s and Power’s future financial results. PSEG and Power continue to advocate for sound policies that recognize nuclear power as a source of reliable and clean energy and an important part of a diverse and reliable energy portfolio.

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The following table provides the balance sheet amounts by generating station as of March 31, 2017 for significant assets and liabilities associated with Power’s owned share of its nuclear assets.




	As of March 31, 2017
	Hope Creek			Salem			Support Facilities and Other (A)		Peach Bottom
	Millions
Assets
Materials and Supplies Inventory	$	82		$	86		$	—	$	39
Nuclear Production, net of Accumulated Depreciation	456			545			208		774
Nuclear Fuel In-Service, net of Accumulated Depreciation	152			77			—		142
Construction Work in Progress (including nuclear fuel)	156			137			12		26
Total Assets	$	846		$	845		$	220	$	981
Liability
Asset Retirement Obligation	$	144		$	157		$	—	$	159
Total Liabilities	$	144		$	157		$	—	$	159
Net Assets	$	702		$	688		$	220	$	822
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 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 $112 million and $98 million for the three months ended March 31, 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.

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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:

Energy Strong Recovery Filing—In March 2017, PSE&G filed its Energy Strong electric and gas cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs associated with electric and gas plant investments under the program that is anticipated to be in service by May 31, 2017. The petition requests rates to be effective September 1, 2017, consistent with the BPU Order of approval of the Energy Strong Program. The annualized requested increase in revenue requirement is approximately $22 million for electric and $3 million for gas. This matter is pending.

Green Program Recovery Charges—In March 2017, the BPU gave final approval to PSE&G’s 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 programs. The rates are effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge.

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.

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.”




Outstanding Loans by Class of Customer
	As of		As of
Consumer Loans	March 31, 2017		December 31, 2016
	Millions
Commercial/Industrial	$	168	$	164
Residential	11		11
Total	$	179	$	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

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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 leases 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.

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




	As of			As of
	March 31, 2017			December 31, 2016
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	574		$	629
Estimated Residual Value of Leased Assets	346			346
Total Investment in Rental Receivables	920			975
Unearned and Deferred Income	(324		)	(326		)
Gross Investment in Leases	596			649
Deferred Tax Liabilities	(640		)	(674		)
Net Investment in Leases	$	(44	)	$	(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 March 31, 2017
	As of March 31, 2017
	Millions
AA	$	16
BBB+ — BBB-	316
BB-	133
CCC-	109
Total	$	574

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 March 31, 2017, the gross investment in the leases of such assets, net of non-recourse debt, was $371 million ($(154) million, net of deferred taxes). A more detailed description of such assets under lease, as of March 31, 2017, is presented in the following table.

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Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	83	64	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	26	17	%	1,711	Coal	CCC- (A)	REMA
Conemaugh Station Units 1 and 2	PA	$	29	17	%	1,711	Coal	CCC- (A)	REMA
Shawville Station Units 1, 2, 3 and 4	PA	$	99	100	%	596	Gas	CCC- (A)	REMA

(A)

REMA’s parent company, GenOn Energy Inc. (GenOn), reported in August 2016 that GenOn did not expect to have sufficient liquidity to repay its senior unsecured notes due in June 2017. In January 2017, S&P further lowered its corporate credit rating on GenOn and its affiliates (including REMA) to “CCC-” from “CCC” reflecting the primary credit concern of the near-term maturity of GenOn’s senior unsecured notes in June 2017 and expressed a negative outlook reflecting the continuing pressure on financial measures. In October 2016, Moody’s downgraded the GenOn Corporate Family Rating to “Caa3” to reflect its high debt burden relative to cash flow.

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 efforts to restructure its portfolio and improve its liquidity and 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. 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 pay material cash tax liabilities to the Internal Revenue Service.

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 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.

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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 March 31, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	717	$	297	$	(7	)	$	1,007
Debt Securities
Government	515		8		(6		)	517
Corporate	342		5		(4		)	343
Total Debt Securities	857		13		(10		)	860
Other Securities	46		—		—			46
Total NDT Available-for-Sale Securities	$	1,620	$	310	$	(17	)	$	1,913




	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
	March 31, 2017		December 31, 2016
	Millions
Accounts Receivable	$	15	$	8
Accounts Payable	$	4	$	5

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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 March 31, 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)	$	80	$	(6	)	$	4	$	(1	)	$	120	$	(10	)	$	8	$	(1	)
Debt Securities
Government (B)	276		(6		)	4		—			276		(6		)	4		—
Corporate (C)	125		(3		)	9		(1		)	139		(3		)	15		(1		)
Total Debt Securities	401		(9		)	13		(1		)	415		(9		)	19		(1		)
NDT Available-for-Sale Securities	$	481	$	(15	)	$	17	$	(2	)	$	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 March 31, 2017.

(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 March 31, 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 March 31, 2017.

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




		Three Months Ended
		March 31,
		2017			2016
	Millions
Proceeds from NDT Fund Sales (A)		$	247		$	177
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains		$	21		$	15
Gross Realized Losses		(4		)	(16		)
Net Realized Gains (Losses) on NDT Fund		$	17		$	(1	)

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

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 $149 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of March 31, 2017.

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The NDT available-for-sale debt securities held as of March 31, 2017 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	16
1 - 5 years	257
6 - 10 years	199
11 - 15 years	59
16 - 20 years	63
Over 20 years	266
Total NDT Available-for-Sale Debt Securities	$	860

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

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 three months ended March 31, 2017, Other-Than-Temporary Impairments (OTTI) of $1 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be 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 March 31, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	22	$	—	$	—		$	22
Debt Securities
Government	99		—		(1		)	98
Corporate	99		1		(1		)	99
Total Debt Securities	198		1		(2		)	197
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	222	$	1	$	(2	)	$	221

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	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
	March 31, 2017		December 31, 2016
	Millions
Accounts Receivable	$	1	$	5
Accounts Payable	$	1	$	3

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 March 31, 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)	53		(1		)	1		—		60		(2		)	1		—
Corporate (C)	36		(1		)	3		—		46		(2		)	3		—
Total Debt Securities	89		(2		)	4		—		106		(4		)	4		—
Rabbi Trust Available-for-Sale Securities	$	89	$	(2	)	$	4	$	—	$	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 March 31, 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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(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 March 31, 2017.

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




		Three Months Ended
		March 31,
		2017			2016
	Millions
Proceeds from Rabbi Trust Sales (A)		$	51		$	25
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains		$	15		$	1
Gross Realized Losses		(3		)	(1		)
Net Realized Gains (Losses) on Rabbi Trust		$	12		$	—

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

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 losses of $(1) million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of March 31, 2017.

The Rabbi Trust available-for-sale debt securities held as of March 31, 2017 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	6
1 - 5 years	50
6 - 10 years	42
11 - 15 years	9
16 - 20 years	8
Over 20 years	82
Total Rabbi Trust Available-for-Sale Debt Securities	$	197

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

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 a commingled 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 three months ended March 31, 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.

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(UNAUDITED)

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




	As of		As of
	March 31, 2017		December 31, 2016
	Millions
PSE&G	$	44	$	43
Power	55		53
Other	122		121
Total Rabbi Trust Available-for-Sale Securities	$	221	$	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, as of March 31, 2017, the total net periodic benefit costs decreased by approximately $12 million, net of amounts capitalized, 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.

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, except for Servco.




	Pension Benefits						OPEB
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2017			2016			2017			2016
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	29		$	27		$	4		$	4
Interest Cost	51			50			16			15
Expected Return on Plan Assets	(98		)	(98		)	(8		)	(8		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(4		)	(3		)	(3		)
Actuarial Loss	24			39			13			10
Total Benefit Costs	$	1		$	14		$	22		$	18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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




	Pension Benefits					OPEB
	Three Months Ended					Three Months Ended
	March 31,					March 31,
	2017			2016		2017		2016
	Millions
PSE&G	$	(1	)	$	7	$	14	$	11
Power	—			4		7		6
Other	2			3		1		1
Total Benefit Costs	$	1		$	14	$	22	$	18

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 plans to contribute $35 million into its pension plan trusts during 2017. Servco’s pension-related revenues and costs were $9 million and $6 million for the three months ended March 31, 2017 and 2016, respectively. The OPEB-related revenues earned and costs incurred for the three months ended March 31, 2017 were $1 million and were immaterial for the three months ended March 31, 2016.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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•	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.

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




	As of			As of
	March 31, 2017			December 31, 2016
	Millions
Face Value of Outstanding Guarantees	$	1,886		$	1,806
Exposure under Current Guarantees	$	151		$	139

Letters of Credit Margin Posted	$	183		$	157
Letters of Credit Margin Received	$	104		$	99

Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(1	)	$	(1	)
Net Broker Balance Deposited (Received)	$	61		$	57

Additional Amounts Posted:
Other Letters of Credit	$	69		$	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 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 had posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $106 million guarantee to support Power’s payment obligations related to its equity interest in the PennEast natural gas pipeline and 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. As previously announced, Power is currently in the process of selling its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee would terminate. 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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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 U.S. Environmental Protection Agency (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 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 52 members as of March 31, 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 $190 million, which the CPG continues to incur. Of the estimated $190 million, as of March 31, 2017, the CPG had spent approximately $160 million, of which PSEG’s total share was approximately $11 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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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. As of March 31, 2017, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.

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 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. 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 20 PRPs, that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements in return for payments by each PRP of $280,600. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. It is unclear how the EPA made that determination or how many PRPs will accept the proposal. The settlement is subject to a 30 day public comment period that has not yet commenced. The impact of this settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.

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

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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.

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 $386 million and $443 million 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 $386 million as of March 31, 2017. Of this amount, $74 million was recorded in Other Current Liabilities and $312 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $386 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 whether 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 Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), 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

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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. 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 is expected by

mid-2017.

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 Clean Water Act, 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. 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 the Clean Water Act. Such service 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 Clean Water Act 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. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2017. See Note 3. Early Plant Retirements.

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. The receipt of permits to allow construction and operation of the new facility could occur in 2017. 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 issued an order to approve siting BH5. All major environmental permits have been obtained. Operations are expected to begin in mid-2019.

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; 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 investigation and response actions related to the fluid discharge are ongoing. The investigation of the discharge and its potential cause is in the preliminary

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stages, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the necessary repair and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs has been extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s debris removal activities are ongoing.

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. 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. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and is acting promptly to issue an administrative stay of the compliance dates in the rule that have not yet passed pending judicial review. The deadlines that are expected to be stayed include the BAT limitations and pretreatment standards for each of the following waste streams: fly ash transport water, bottom ash transport water, flue gas desulfurization wastewater, flue gas mercury control wastewater, and gasification wastewater. Power is unable to determine how this will ultimately impact compliance requirements or the financial impact it may have on the company.

Coal Combustion Residuals (CCRs)

On December 19, 2014, the EPA issued a final rule that regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power’s Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows.

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.

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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 will become effective on June 1, 2017 when the 2014 BGS auction agreements expire.

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 2018 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom.

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 2019 to support its fossil generation stations.

As of March 31, 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	$	301
Enrichment	$	359
Fabrication	$	192
Natural Gas	$	1,101
Coal	$	181

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

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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 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 recent developments in the investigation, 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 the annual FTR auction in PJM for the 2016-2017 planning year and the monthly FTR auctions in PJM for February, March and April 2016. PSEG is cooperating with FERC in this matter. PSEG cannot predict the outcome of this matter at this time.

Note 10. Debt and Credit Facilities

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, 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 March 31, 2017, the total available credit capacity was $3.6 billion.

As of March 31, 2017, no single institution represented more than 8% of the total commitments in the credit facilities.

As of March 31, 2017, the total credit capacity was in excess of its anticipated maximum liquidity requirements.

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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 March 31, 2017 were as follows:




	As of March 31, 2017
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	332	$	1,168	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	332	$	1,168
PSE&G
5-year Credit Facility (A)	$	600	$	14	$	586	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	14	$	586
Power
3-year LC Facilities	$	200	$	137	$	63	Mar 2020	Letters of Credit
5-year Credit Facilities	1,900		98		1,802		Mar 2022	Funding/Letters of Credit
Total Power	$	2,100	$	235	$	1,865
Total	$	4,200	$	581	$	3,619

(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 March 31, 2017, PSEG had $315 million outstanding at a weighted average interest rate of 1.25%. As of March 31, 2017, PSE&G had no amounts outstanding under its Commercial Paper Program.

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 primarily relating 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.

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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 March 31, 2017 or December 31, 2016. The fair value hedges reduced interest expense by $2 million for the three months ended March 31, 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, primarily related to variable-rate debt instruments. As of March 31, 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 March 31, 2017 and December 31, 2016, the fair value of these hedges was $2 million and $1 million, respectively. There was no ineffectiveness as of March 31, 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 $2 million as of March 31, 2017 and December 31, 2016. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months is $1 million.

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.

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




	As of March 31, 2017
	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	$	525		$	(414	)	$	111		$	1	$	2	$	114
Noncurrent Assets	264			(171		)	93			—		—		93
Total Mark-to-Market Derivative Assets	$	789		$	(585	)	$	204		$	1	$	2	$	207
Derivative Contracts
Current Liabilities	$	(425	)	$	418		$	(7	)	$	—	$	—	$	(7	)
Noncurrent Liabilities	(168		)	167			(1		)	—		—		(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(593	)	$	585		$	(8	)	$	—	$	—	$	(8	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	196		$	—		$	196		$	1	$	2	$	199

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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	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 March 31, 2017 and December 31, 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

(B)

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 on the Condensed Consolidated Balance Sheets. As of March 31, 2017 net cash collateral (received) paid was netted against the corresponding net derivative contract positions with $(4) million of cash collateral netted against noncurrent assets, and $4 million netted against current liabilities. 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 $13 million and $19 million as of March 31, 2017 and December 31, 2016, respectively. As of March 31, 2017 and December 31, 2016, Power had the contractual right of offset of $7 million and $9 million, respectively, 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 $6 million and $10 million as of March 31, 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.

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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 ended March 31, 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
	March 31,					March 31,
	2017		2016			2017		2016
	Millions					Millions
PSEG
Interest Rate Swaps	—		3		Interest Expense	—		—
Total PSEG	$	—	$	3		$	—	$	—

There were no pre-tax gain (loss) recognized in income on derivatives (ineffective portion) as of March 31, 2017 and 2016.

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	—		—
Less: Gain Reclassified into Income	—		—
Balance as of March 31, 2017	$	3	$	2

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 ended March 31, 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
			March 31,
			2017			2016
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues		$	83		$	216
Energy-Related Contracts	Energy Costs		(5		)	2
Total PSEG and Power			$	78		$	218

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




Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of March 31, 2017
Natural Gas	Dekatherm (Dth)	357	—	355	2
Electricity	MWh	346	—	346	—
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	—	—

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 March 31, 2017, 98% 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 March 31, 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		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	433	$	94	$	339	1	$	202	(A)
Non-Investment Grade	9		1		8		—	—
Total	$	442	$	95	$	347	1	$	202


(A)	Represents net exposure of $202 million with PSE&G.

As of March 31, 2017, collateral held from counterparties where Power had credit exposure included $1 million in cash collateral and $94 million in letters of credit.

As of March 31, 2017, Power had 159 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

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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 March 31, 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 March 31, 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.

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 March 31, 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 March 31, 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 March 31, 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)	$	125		$	—		$	125		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	205		$	(585	)	$	11		$	774		$	5
Interest Rate Swaps (C)	$	2		$	—		$	—		$	2		$	—
NDT Fund (D)
Equity Securities	$	1,007		$	—		$	1,005		$	2		$	—
Debt Securities—US Treasury	$	223		$	—		$	—		$	223		$	—
Debt Securities—Govt Other	$	294		$	—		$	—		$	294		$	—
Debt Securities—Corporate	$	343		$	—		$	—		$	343		$	—
Other Securities	$	46		$	—		$	46		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	36		$	—		$	—		$	36		$	—
Debt Securities—Govt Other	$	62		$	—		$	—		$	62		$	—
Debt Securities—Corporate	$	99		$	—		$	—		$	99		$	—
Other Securities	$	2		$	—		$	2		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(8	)	$	585		$	(6	)	$	(585	)	$	(2	)
Interest Rate Swaps (C)	$	—		$	—		$	—		$	—		$	—
PSE&G
Assets:
Cash Equivalents (A)	$	125		$	—		$	125		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	1		$	—		$	—		$	—		$	1
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	7		$	—		$	—		$	7		$	—
Debt Securities—Govt Other	$	12		$	—		$	—		$	12		$	—
Debt Securities—Corporate	$	20		$	—		$	—		$	20		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	—		$	—		$	—		$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	204		$	(585	)	$	11		$	774		$	4
NDT Fund (D)
Equity Securities	$	1,007		$	—		$	1,005		$	2		$	—
Debt Securities—US Treasury	$	223		$	—		$	—		$	223		$	—
Debt Securities—Govt Other	$	294		$	—		$	—		$	294		$	—
Debt Securities—Corporate	$	343		$	—		$	—		$	343		$	—
Other Securities	$	46		$	—		$	46		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	6		$	—		$	6		$	—		$	—
Debt Securities—US Treasury	$	9		$	—		$	—		$	9		$	—
Debt Securities—Govt Other	$	15		$	—		$	—		$	15		$	—
Debt Securities—Corporate	$	25		$	—		$	—		$	25		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(8	)	$	585		$	(6	)	$	(585	)	$	(2	)

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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—US 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—US 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—US 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—US 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—US 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	)

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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—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.


(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 March 31, 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 March 31, 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 investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and certain government and US 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 March 31, 2017, $(4) million of cash collateral was netted against assets, and $4 million was netted against liabilities. 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

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Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee 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 is 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 March 31, 2017 and December 31, 2016.




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	March 31, 2017					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	1	$	—		Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	1	$	—
Power
Electricity	Electric Load Contracts	$	4	$	(2	)	Discounted Cash flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	4	$	(2	)
Total PSEG		$	5	$	(2	)

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	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 as of March 31, 2017 and December 31, 2016.

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 gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. For energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value.

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months ended March 31, 2017 and March 31, 2016, respectively, follows:

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

for the Three Months Ended March 31, 2017




	Three Months Ended March 31, 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 March 31, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	19	$	6	$	—	$	(22	)	$	(1	)	$	3
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	—	$	6	$	—	$	—		$	—		$	1
Power
Net Derivative Assets (Liabilities)	$	6		$	19	$	—	$	—	$	(22	)	$	(1	)	$	2

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

for the Three Months Ended March 31, 2016




	Three Months Ended March 31, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of March 31, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	13	$	15	$	8	$	—	$	(15	)	$	—	$	21
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	8	$	—	$	—		$	—	$	10
Power
Net Derivative Assets (Liabilities)	$	11	$	15	$	—	$	—	$	(15	)	$	—	$	11


(A)	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $19 million and $15 million in Operating Income for the three months ended March 31, 2017 and 2016, respectively. Of the $19 million in Operating Income, $3 million is unrealized. The $15 million in Operating Income is realized.


(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 $(22) million and $(15) million in settlements for the three months ended March 31, 2017 and 2016, respectively.


(D)	During the three months ended March 31, 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 2016.

As of March 31, 2017, PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $3 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of March 31, 2016, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $21 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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 March 31, 2017 and December 31, 2016.




	As of				As of
	March 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	1,196	$	1,184	$	1,195	$	1,185
PSE&G (B)	7,819		8,349		7,818		8,240
Power - Recourse Debt (B)	2,383		2,611		2,382		2,578
Total Long-Term Debt	$	11,398	$	12,144	$	11,395	$	12,003


(A)	Fair value includes a $500 million floating rate term loan and net offsets. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly.

(B)

Given that most bonds do not trade, 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.

Note 13. Other Income and Deductions




Other Income	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended March 31, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	31	$	—	$	31
Allowance for Funds Used During Construction	14		—		—		14
Rabbi Trust Realized Gains, Interest and Dividends	3		4		9		16
Solar Loan Interest	5		—		—		5
Other	3		3		—		6
Total Other Income	$	25	$	38	$	9	$	72
Three Months Ended March 31, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	25	$	—	$	25
Allowance for Funds Used During Construction	11		—		—		11
Solar Loan Interest	6		—		—		6
Other	3		1		2		6
Total Other Income	$	20	$	26	$	2	$	48

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended March 31, 2017
NDT Fund Realized Losses and Expenses	$	—	$	7	$	—	$	7
Other	1		—		3		4
Total Other Deductions	$	1	$	7	$	3	$	11
Three Months Ended March 31, 2016
NDT Fund Realized Losses and Expenses	$	—	$	18	$	—	$	18
Other	1		—		2		3
Total Other Deductions	$	1	$	18	$	2	$	21


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

Note 14. Income Taxes

PSEG’s, PSE&G’s and Power’s effective tax rates for the three months ended March 31, 2017 and 2016 were as follows:




	Three Months Ended
	March 31,
	2017	2016
PSEG	20.3%	37.5%
PSE&G	36.4%	36.6%
Power	40.6%	40.2%

For the three months ended March 31, 2017, the overall decrease in PSEG’s effective tax rates as compared to the same period in the prior year as well as to the statutory tax rate of 40.85%, was primarily due to changes in uncertain tax positions and interest on a New Jersey State refund.

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. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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




PSEG	Other Comprehensive Income (Loss)
	Three Months Ended March 31, 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	—		—			30			30
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		6			(15		)	(9		)
Net Current Period Other Comprehensive Income (Loss)	—		6			15			21
Balance as of March 31, 2017	$	2	$	(392	)	$	148		$	(242	)

PSEG	Other Comprehensive Income (Loss)
	Three Months Ended March 31, 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		—			10			12
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		8			6			14
Net Current Period Other Comprehensive Income (Loss)	2		8			16			26
Balance as of March 31, 2016	$	2	$	(378	)	$	107		$	(269	)




Power	Other Comprehensive Income (Loss)
	Three Months Ended March 31, 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	—		—			28			28
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		5			(9		)	(4		)
Net Current Period Other Comprehensive Income (Loss)	—		5			19			24
Balance as of March 31, 2017	$	—	$	(335	)	$	148		$	(187	)

Power	Other Comprehensive Income (Loss)
	Three Months Ended March 31, 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	—		—			10			10
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		7			6			13
Net Current Period Other Comprehensive Income (Loss)	—		7			16			23
Balance as of March 31, 2016	$	—	$	(320	)	$	103		$	(217	)

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
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations		March 31, 2017
	Location of Pre-Tax Amount In Statement of Operations		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
Amortization of Actuarial Loss	O&M Expense		(12		)	5			(7		)
Total Pension and OPEB Plans			(10		)	4			(6		)
Available-for-Sale Securities
Realized Gains	Other Income		36			(17		)	19
Realized Losses	Other Deductions		(7		)	3			(4		)
OTTI	OTTI		(1		)	1			—
Total Available-for-Sale Securities			28			(13		)	15
Total			$	18		$	(9	)	$	9




PSEG			Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
			Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations		March 31, 2016
	Location of Pre-Tax Amount In Statement of Operations		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
Amortization of Actuarial Loss	O&M Expense		(17		)	7			(10		)
Total Pension and OPEB Plans			(14		)	6			(8		)
Available-for-Sale Securities
Realized Gains	Other Income		16			(8		)	8
Realized Losses	Other Deductions		(17		)	8			(9		)
OTTI	OTTI		(10		)	5			(5		)
Total Available-for-Sale Securities			(11		)	5			(6		)
Total			$	(25	)	$	11		$	(14	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Table of Contents




Power			Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
			Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations		March 31, 2017
	Location of Pre-Tax Amount In Statement of Operations		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
Amortization of Actuarial Loss	O&M Expense		(11		)	5			(6		)
Total Pension and OPEB Plans			(9		)	4			(5		)
Available-for-Sale Securities
Realized Gains	Other Income		25			(13		)	12
Realized Losses	Other Deductions		(5		)	2			(3		)
OTTI	OTTI		(1		)	1			—
Total Available-for-Sale Securities			19			(10		)	9
Total			$	10		$	(6	)	$	4




Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	March 31, 2016
	Location of Pre-Tax Amount In Statement of Operations	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
Amortization of Actuarial Loss	O&M Expense	(15		)	6			(9		)
Total Pension and OPEB Plans		(12		)	5			(7		)
Available-for-Sale Securities
Realized Gains	Other Income	15			(8		)	7
Realized Losses	Other Deductions	(16		)	8			(8		)
OTTI	OTTI	(10		)	5			(5		)
Total Available-for-Sale Securities		(11		)	5			(6		)
Total		$	(23	)	$	10		$	(13	)

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 March 31,
	2017				2016
	Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	114	$	114	$	471	$	471
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		505		505
Effect of Stock Based Compensation Awards	—		3		—		3
Total Shares	505		508		505		508

EPS
Net Income	$	0.23	$	0.22	$	0.93	$	0.93

There were approximately 0.3 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the three months ended March 31, 2017 and 2016.

Dividends




	Three Months Ended
	March 31,
Dividend Payments on Common Stock	2017		2016
Per Share	$	0.43	$	0.41
In Millions	$	218	$	207

On April 18, 2017, PSEG’s Board of Directors approved a $0.43 per share common stock dividend for the second quarter of 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Table of Contents

Note 17. Financial Information by Business Segment




	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated
	Millions
Three Months Ended March 31, 2017
Operating Revenues	$	1,812	$	1,284		$	83		$	(587	)	$	2,592
Net Income (Loss)	299		(170		)	(15		)	—			114
Gross Additions to Long-Lived Assets	748		307			7			—			1,062
Three Months Ended March 31, 2016
Operating Revenues	$	1,712	$	1,313		$	122		$	(531	)	$	2,616
Net Income (Loss)	262		192			17			—			471
Gross Additions to Long-Lived Assets	724		333			8			—			1,065
As of March 31, 2017
Total Assets	$	26,487	$	11,729		$	2,249		$	(801	)	$	39,664
Investments in Equity Method Subsidiaries	$	—	$	103		$	—		$	—		$	103
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 primarily relate 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.

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
	March 31,
Related-Party Transactions	2017		2016
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	599	$	545
Administrative Billings from Services (B)	65		69
Total Billings from Affiliates	$	664	$	614

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents




	As of		As of
Related-Party Transactions	March 31, 2017		December 31, 2016
	Millions
Receivables from PSEG (C)	$	34	$	76
Payable to Power (A)	$	175	$	193
Payable to Services (B)	43		67
Accounts Payable—Affiliated Companies	$	218	$	260
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	116	$	130

Power

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




	Three Months Ended
	March 31,
Related-Party Transactions	2017		2016
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	599	$	545
Billings from Affiliates:
Administrative Billings from Services (B)	$	36	$	45




	As of		As of
Related-Party Transactions	March 31, 2017		December 31, 2016
	Millions
Receivables from PSE&G (A)	$	175	$	193
Receivables from PSEG (C)	—		12
Accounts Receivable—Affiliated Companies	$	175	$	205
Payable to Services (B)	$	10	$	25
Payable to PSEG (C)	71		—
Accounts Payable—Affiliated Companies	$	81	$	25
Short-Term Loan Due (to) from Affiliate (E)	$	157	$	87
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	78	$	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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Table of Contents

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 March 31, 2017 and December 31, 2016 and for the three months ended March 31, 2017 and 2016.




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended March 31, 2017
Operating Revenues	$	—		$	1,270		$	52		$	(38	)	$	1,284
Operating Expenses	4			1,569			52			(38		)	1,587
Operating Income (Loss)	(4		)	(299		)	—			—			(303		)
Equity Earnings (Losses) of Subsidiaries	(161		)	(1		)	3			162			3
Other Income	25			41			—			(28		)	38
Other Deductions	(1		)	(6		)	—			—			(7		)
Other-Than-Temporary Impairments	—			(1		)	—			—			(1		)
Interest Expense	(30		)	(9		)	(5		)	28			(16		)
Income Tax Benefit (Expense)	1			111			4			—			116
Net Income (Loss)	$	(170	)	$	(164	)	$	2		$	162		$	(170	)
Comprehensive Income (Loss)	$	(146	)	$	(143	)	$	2		$	141		$	(146	)
Three Months Ended March 31, 2017
Net Cash Provided By (Used In) Operating Activities	$	77		$	377		$	91		$	35		$	580
Net Cash Provided By (Used In) Investing Activities	$	251		$	20		$	(154	)	$	(511	)	$	(394	)
Net Cash Provided By (Used In) Financing Activities	$	(328	)	$	(395	)	$	68		$	476		$	(179	)




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended March 31, 2016
Operating Revenues	$	—		$	1,302		$	42		$	(31	)	$	1,313
Operating Expenses	10			952			39			(31		)	970
Operating Income (Loss)	(10		)	350			3			—			343
Equity Earnings (Losses) of Subsidiaries	205			(1		)	2			(204		)	2
Other Income	17			32			—			(23		)	26
Other Deductions	—			(18		)	—			—			(18		)
Other-Than-Temporary Impairments	—			(10		)	—			—			(10		)
Interest Expense	(30		)	(10		)	(5		)	23			(22		)
Income Tax Benefit (Expense)	10			(140		)	1			—			(129		)
Net Income (Loss)	$	192		$	203		$	1		$	(204	)	$	192
Comprehensive Income (Loss)	$	215		$	219		$	1		$	(220	)	$	215
Three Months Ended March 31, 2016
Net Cash Provided By (Used In) Operating Activities	$	271		$	480		$	47		$	(135	)	$	663
Net Cash Provided By (Used In) Investing Activities	$	(598	)	$	(428	)	$	(246	)	$	613		$	(659	)
Net Cash Provided By (Used In) Financing Activities	$	326		$	(51	)	$	203		$	(478	)	$	—

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of March 31, 2017
Current Assets	$	4,244	$	1,332	$	174	$	(4,458	)	$	1,292
Property, Plant and Equipment, net	56		5,582		2,447		—			8,085
Investment in Subsidiaries	4,104		343		—		(4,447		)	—
Noncurrent Assets	175		2,154		129		(106		)	2,352
Total Assets	$	8,579	$	9,411	$	2,750	$	(9,011	)	$	11,729
Current Liabilities	$	187	$	3,436	$	1,580	$	(4,458	)	$	745
Noncurrent Liabilities	531		2,171		527		(106		)	3,123
Long-Term Debt	2,383		—		—		—			2,383
Member’s Equity	5,478		3,804		643		(4,447		)	5,478
Total Liabilities and Member’s Equity	$	8,579	$	9,411	$	2,750	$	(9,011	)	$	11,729
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 demand response 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 through competitive energy sales in well-developed energy markets and fuel supply functions 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) transmission and distribution (T&D) system under an Operations and Services Agreement contractual 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 ended March 31, 2017 and 2016 are presented as follows:




		Three Months Ended
		March 31,
Earnings (Losses)		2017			2016
	Millions
PSE&G		$	299		$	262
Power (A)		(170		)	192
Other (B)		(15		)	17
PSEG Net Income		$	114		$	471

PSEG Net Income Per Share (Diluted)		$	0.22		$	0.93


(A)	Includes after-tax expenses of $334 million primarily for accelerated depreciation related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants in the three months ended March 31, 2017. 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 an after-tax charge of $32 million related to its investments in NRG REMA, LLC’s leveraged leases in the three months ended March 31, 2017. 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
		March 31,
		2017		2016
	Millions, after tax
NDT Fund Income (Expense) (A) (B)		$	8	$	(5	)
Non-Trading MTM Gains (Losses) (C)		$	6	$	13

(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 $(9) million and $3 million for the three months ended March 31, 2017 and 2016, respectively.


(C)	Net of tax (expense) benefit of $(4) million and $(10) million for the three months ended March 31, 2017 and 2016, respectively.

Our $357 million decrease in Net Income for the three months ended March 31, 2017 was driven primarily by


•	accelerated depreciation related to the early retirement of our Hudson and Mercer coal/gas generation units at Power (see Item 1. Note 3. Early Plant Retirements),


•	a decrease in energy sales due primarily to lower average realized sales prices, and


•	a charge for estimated losses related to leveraged lease investments (see Item 1. Note 6. Financing Receivables).

These decreases were partially offset by:


•	higher transmission revenues, and


•	increased gas distribution revenues.

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During the first three 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 multi-year, 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. 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 will be required to file a distribution base rate case proceeding by no later than November 1, 2017. We cannot predict the impact such proceeding will have on our distribution business.

Although the weather in the first quarter 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 BGSS arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter 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. Power’s hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business. More than half of Power’s expected gross margin in 2017 relates to our hedging strategy, our expected revenues from the capacity market mechanisms and certain ancillary service payments such as reactive power.

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

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 low natural gas prices, and the related decline in market prices of energy, resulting from 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 and greater reliance on natural gas pipelines for fuel delivery.

If trends noted above continue or worsen, our 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 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 nuclear decommissioning trust funds will 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 and an important part of a diverse and reliable energy portfolio. See Item 1. Note 3. Early Plant Retirements for additional information.

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.

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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 in Hope Creek at a cost of approximately $130 million.

There are several matters pending before FERC 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 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 an adjustment, 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. While we are not the subject of a challenge to the ROE employed in PSE&G’s transmission formula rate, 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 is expected to be implemented fully 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. We do not expect action on the complaints before the upcoming 2020/2021 base residual auction in May 2017.

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.

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 (FWPCA) 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, 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. Upon completion of the review, the EPA is expected to suspend, revise or rescind the rules as appropriate.

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.

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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 recent developments in the investigation, 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 Note 9. Commitments and Contingent Liabilities.

Early Retirement of Hudson and Mercer Units

In October 2016, Power determined it will cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. The exact timing of the early retirement of these units may be impacted by operational and other conditions that could subsequently arise. 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 continues to adversely impact their results of operations in 2017. During the first three months of 2017, Power recognized incremental D&A of $558 million ($574 million in total) and expects to recognize an additional incremental $379 million ($389 million in total) in 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the first quarter of 2017, Energy Costs of $7 million for coal inventory adjustments was also incurred and other costs may be incurred during the remaining period in 2017 prior to retirement. 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 NRG REMA LLC, (REMA), reported in August 2016 that it did not expect to have sufficient liquidity to repay their senior unsecured notes due in June 2017. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA.

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 relating to its investments in the REMA leases, which was reflected in Operating Revenues. 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 leases. 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 Shawville generating facilities, which were converted to use natural gas, and Powerton, a coal facility. However, these units may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. As a result, these 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 coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged leases associated with these facilities.

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Salem

Concurrently with the planned refueling outage at the Salem 2 unit that is scheduled for the second quarter of 2017, we intend to inspect and replace degraded baffle bolts as part of our multi-year project to replace baffle bolts at the Salem station. As a result, we expect the duration of this outage to be modestly longer than our typical refueling outage, which will reduce production and lower the nuclear capacity factor for the second quarter of 2017 as compared to the first quarter of 2017.

Operational Excellence

We emphasize operational performance 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 as we remain diligent in managing costs. For the first three months of 2017, our


•	our utility continued top decile performance in electric reliability,


•	total nuclear fleet achieved an average capacity factor of 100%,


•	diverse fuel mix and dispatch flexibility allowed us to generate approximately 13 terawatt hours while addressing fuel availability and price volatility, and


•	combined cycle fleet produced three 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 three 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 three months of 2017, we


•	made additional investments in transmission infrastructure projects,


•	continued to execute our GSMP, Energy Strong and other existing 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 slow-growing economy and a cost-constrained environment with low gas prices, to capitalize on or otherwise address appropriately regulatory and legislative 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,


•	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 Energy Center (Keys) , Sewaren 7, (BH5) and other generation projects,

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•	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 and challenges 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,


•	delays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including in connection with permitting 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,


•	continued or expanded participation in solar, demand response and energy efficiency 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.

In 2016, Power announced its intention to develop a retail platform to sell physical electricity and natural gas, which we believe would begin to complement our existing wholesale marketing business. Power was granted licenses in 2016 to sell both electricity and gas in the states of New Jersey and Pennsylvania.

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)
	March 31,				Increase/ (Decrease)
	2017		2016		2017 vs. 2016
	Millions				Millions			%
Operating Revenues	$	2,592	$	2,616	$	(24	)	(1	)
Energy Costs	874		836		38			5
Operation and Maintenance	712		729		(17		)	(2	)
Depreciation and Amortization	828		224		604			270
Income from Equity Method Investments	3		2		1			50
Other Income (Deductions)	61		27		34			126
Other-Than-Temporary Impairments	1		10		(9		)	(90	)
Interest Expense	98		92		6			7
Income Tax Expense	29		283		(254		)	(90	)

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

PSE&G




	Three Months Ended				Increase/ (Decrease)
	March 31,				Increase/ (Decrease)
	2017		2016		2017 vs. 2016
	Millions				Millions			%
Operating Revenues	$	1,812	$	1,712	$	100		6
Energy Costs	753		729		24			3
Operation and Maintenance	367		382		(15		)	(4	)
Depreciation and Amortization	171		139		32			23
Other Income (Deductions)	24		19		5			26
Interest Expense	75		68		7			10
Income Tax Expense	171		151		20			13

Three Months Ended March 31, 2017 as Compared to 2016

Operating Revenues increased $100 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $58 million due primarily to an increase in transmission revenues.


•	Transmission revenues were $37 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.


•	Gas distribution revenues increased $24 million due to an $11 million increase due to the inclusion of Energy Strong in base rates, a $5 million increase due to the Gas System Modernization Program, $4 million of higher delivery volumes, higher Green Program Recovery Charges (GPRC) of $2 million and $2 million in higher Weather Normalization Clause revenue.


•	Electric distribution revenues decreased $3 million due to lower GPRC of $3 million and a $2 million decrease due to lower sales volumes, partially offset by a $2 million increase due to the inclusion of Energy Strong in base rates.

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Commodity Revenue increased $24 million as a result of higher Gas revenues partially offset by lower Electric revenues. The changes in Commodity revenue for both gas and electric are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of basic gas supply service (BGSS) and BGS to retail customers.


•	Gas commodity revenues increased $74 million due primarily to higher BGSS sales prices.


•	Electric commodity revenues decreased $50 million due primarily to $23 million of lower revenues from collections of Non-Utility Generation Charges (NGC), a $17 million decrease in BGS revenues due to lower sales prices and volumes and a decrease of $10 million due to lower volumes of Non-Utility Generation (NUG) energy sold.

Clause Revenues increased $19 million due primarily to the 2016 return to customers of $15 million of overcollections of Securitization Transition Charges (STC), and higher Societal Benefit Charges (SBC) of $2 million in 2017. The changes in the STC and SBC amounts are entirely offset by decreases in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC or SBC collections.

Operating Expenses

Energy Costs increased $24 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenance decreased $15 million, of which the most significant components were


•	a $6 million decrease in appliance service costs,


•	a $4 million decrease in distribution corrective and preventative maintenance,


•	a $2 million decrease in pension and OPEB costs, net of capitalized amounts and


•	a $3 million net decrease in operational expenses.

Depreciation and Amortization increased $32 million due primarily to an increase of $17 million in amortization of Regulatory Assets and a $14 million increase in depreciation due to additional plant in service.

Other Income and (Deductions) increased $5 million due primarily to an increase of $3 million in Allowance for Funds Used During Construction and a $3 million increase in realized gains on Rabbi Trust investments.

Interest Expense increased $7 million due primarily to net debt issuances in 2016.

Income Tax Expense increased $20 million due primarily to higher pre-tax income.

Power




	Three Months Ended					Increase/ (Decrease)
	March 31,					Increase/ (Decrease)
	2017			2016		2017 vs. 2016
	Millions					Millions			%
Operating Revenues	$	1,284		$	1,313	$	(29	)	(2	)
Energy Costs	707			638		69			11
Operation and Maintenance	230			253		(23		)	(9	)
Depreciation and Amortization	650			79		571			N/A
Income from Equity Method Investments	3			2		1			50
Other Income (Deductions)	31			8		23			N/A
Other-Than-Temporary Impairments	1			10		(9		)	(90	)
Interest Expense	16			22		(6		)	(27	)
Income Tax Expense (Benefit)	(116		)	129		(245		)	N/A

Three Months Ended March 31, 2017 as Compared to 2016

Operating Revenues decreased $29 million due to changes in generation and gas supply revenues.

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Generation Revenues decreased $124 million due primarily to


•	a net decrease of $95 million in energy sales in the PJM and New England (NE) regions due primarily to lower average realized prices, and


•	a net decrease of $24 million due to MTM losses in 2017 as compared to MTM gains in 2016. Of this amount, $131 million was due to changes in forward power prices. The decrease was offset by an increase of $107 million due to losses on positions reclassified to realized upon settlement this year as compared to gains last year, and


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


•	partially offset by a net increase of $10 million due primarily to higher volumes of electricity sold under wholesale load contracts in the NE region partially offset by lower average prices.

Gas Supply Revenues increased $95 million due primarily to


•	an increase of $46 million in sales under the BGSS contract due primarily to higher average sales prices coupled with an increase in sales volumes due to periods of colder weather in March,


•	an increase of $41 million related to sales to third parties due to higher average sales prices, and


•	a net increase of $8 million due to higher MTM gains in 2017 as compared to 2016, primarily due to losses on positions reclassified to realized upon settlement this year as compared to gains last year.

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 increased $69 million due to

Generation costs decreased $1 million due primarily to


•	a net decrease of $26 million primarily due to lower congestion costs in PJM due to lower congestion rates and volumes,


•	partially offset by higher fuel costs of $14 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,


•	an increase of $8 million in energy purchase volumes in the NE region to serve load obligations, and


•	a $7 million charge associated primarily with a lower of cost or market coal inventory adjustment at Mercer.

Gas costs increased $70 million due mainly to


•	an increase of $39 million related to sales to third parties due to higher average gas costs, and


•	an increase of $31 million related to sales under the BGSS contract due primarily to higher average gas costs and an increase in volumes sold due to periods of colder weather in March.

Operation and Maintenance decreased $23 million due primarily to


•	a $15 million decrease related to our nuclear plants due primarily to lower labor-related costs, and


•	a $7 million legal reserve for environmental expenses recorded in 2016.

Depreciation and Amortization increased $571 million due primarily to


•	$558 million of accelerated depreciation due to the early retirement of the Hudson and Mercer units,


•	$4 million of greater depreciation due to the accelerated retirement date at Bridgeport Harbor 3,


•	a $4 million increase due to a higher nuclear asset base, and


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

Other Income (Deductions) increased $23 million due primarily to $17 million of lower net realized losses from the NDT Fund in 2017 and $3 million of higher realized gains in the Rabbi Trust Fund.

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Other-Than-Temporary Impairments decreased $9 million due to lower impairments of equity securities in the NDT Fund in 2017.

Interest Expense decreased $6 million due primarily to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys.

Income Tax Expense decreased $245 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 three months ended March 31, 2017, our operating cash flow decreased $18 million as compared to the same period in 2016. The net change was primarily due to the net changes from PSE&G and Power as discussed below largely offset by higher tax refunds in 2017 at Energy Holdings.

PSE&G

PSE&G’s operating cash flow decreased $54 million from $568 million to $514 million for the three months ended March 31, 2017, as compared to the same period in 2016, due primarily to lower tax refunds, partially offset by higher earnings, and an increase of $45 million due to a change in regulatory deferrals.

Power

Power’s operating cash flow decreased $83 million from $663 million to $580 million for the three months ended March 31, 2017, as compared to the same period in 2016, primarily due to tax payments in 2017 as compared to tax refunds in 2016 and lower earnings, partially offset by a $65 million increase from net collection of counterparty receivables and a $12 million increase from fuels, materials and supplies.

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 March 31, 2017 were as follows:




Company/Facility	As of March 31, 2017
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	332	$	1,168
PSE&G	600		14		586
Power	2,100		235		1,865
Total	$	4,200	$	581	$	3,619

As of March 31, 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

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would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of Power’s 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 $801 million and $783 million as of March 31, 2017 and December 31, 2016, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units is not expected to have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 1. Note 3. Early Plant Retirements.

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

Long-Term Debt Financing

PSEG Parent has a floating rate $500 million term loan maturing in November 2017.

Common Stock Dividends

On February 21, 2017, our Board of Directors approved a $0.43 dividend per share of common stock for the first quarter of 2017. On April 18, 2017, our Board of Directors declared a $0.43 dividend per share of common stock for the second 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. PSEG Power’s rating and outlook also remain unchanged.




	Moody’s (A)	S&P (B)
PSEG
Outlook	Positive	Stable
Senior Notes	Baa2	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 at PSE&G, Power and Services as compared to amounts disclosed in our 2016 Form 10-K.

PSE&G

During the three months ended March 31, 2017, PSE&G made capital expenditures of $752 million, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of $24 million, which are included in operating cash flows.

Power

During the three months ended March 31, 2017, Power made capital expenditures of $274 million, excluding $33 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 January through March 2017, MTM VaR remained relatively stable between a low of $7 million and a high of $25 million at the 95% confidence level. The range of VaR was narrower for the three months ended March 31, 2017 as compared with the year ended December 31, 2016.

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	MTM VaR
	Three Months Ended March 31, 2017		Year Ended December 31, 2016
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	7	$	26
Average for the Period	$	12	$	16
High	$	25	$	32
Low	$	7	$	10
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	11	$	40
Average for the Period	$	19	$	25
High	$	39	$	51
Low	$	10	$	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 first 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, 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 follows, there have been no material changes to the risk factors set forth in the above-referenced filing as of March 31, 2017.

We may be unable to obtain an adequate fuel supply in the future.

We obtain substantially all of our physical natural gas, coal and nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services, financial hedging transactions and other contracts to ensure that the natural gas, coal and nuclear fuel are delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing the transportation of such fuels.

Additionally, the PJM power market has recently experienced an increase in natural gas-fired generation assets that supply electricity to the region. As a result, there has been a corresponding increase in the need for natural gas transportation assets to serve power generation assets. When extreme cold temperatures significantly increase the demand for natural gas used for residential heating, it can also create constraints on natural gas pipelines that serve power generation assets. When these conditions exist, it could interrupt the fuel supply to our natural gas-fired power plants in the PJM power market.

We are exposed to increases in the price of natural gas, coal and nuclear fuel, and it is possible that sufficient supplies to operate our generating facilities profitably may not continue to be available to us. Significant changes in the price of natural gas, coal and nuclear fuel could affect our future results and impact our liquidity needs. In addition, we face risks with regard to the delivery to, and the use of natural gas, coal and nuclear fuel by, our power plants including the following:


•	transportation may be unavailable if pipeline infrastructure is damaged or disabled;


•	pipeline tariff changes may adversely affect our ability to, or cost to, deliver such fuels;


•	creditworthiness of third-party suppliers, defaults by third-party suppliers on supply obligations and our ability to replace supplies currently under contract may delay or prevent timely delivery;


•	market liquidity for physical supplies of such fuels or availability of related services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;


•	variation in the quality of such fuels may adversely affect our power plant operations;


•	legislative or regulatory actions or requirements, including those related to pipeline integrity inspections, may increase the cost of such fuels;


•	fuel supplies diverted to residential heating may limit the availability of such fuels for our power plants; and


•	the loss of critical infrastructure, terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences could impede the delivery of such fuels.

Our nuclear units have a diversified portfolio of contracts and inventory that provide a substantial portion of our fuel raw material needs over the next several years. However, each of our nuclear units has contracted with a single fuel fabrication services provider, and transitioning to an alternative provider could take an extended period of time. Certain of our other generation facilities also require fuel or other services that may only be available from one or a limited number of suppliers. The availability and price of this fuel may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, such fuel may not be available at any price, or we may not be able to transport it to our facilities on a timely basis. In this case, we may not be able to run those facilities even if it would be profitable. If we had sold forward the power from such a facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.

In March 2017, Westinghouse Electric Company (WEC) announced that it had filed for Chapter 11 bankruptcy in New York. WEC provides nuclear fuel fabrication services for Salem Units 1 and 2. In the event that WEC is unable to continue to provide fabrication services, we can provide no assurance that we would be able to find alternative providers of such services in a timely manner or on acceptable terms. As a result, a failure by WEC to perform its obligations during the pendency of, or following its emergence from, bankruptcy could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.

Although our fuel contract portfolio provides a degree of hedging against these market risks, such hedging may not be effective and future increases in our fuel costs could materially and adversely affect our liquidity, financial condition and results of operations. While our generation runs on a mix of fuels, primarily natural gas and nuclear fuel, an increase in the cost of any particular fuel ultimately used could impact our results of operations.

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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 first quarter of 2017.




Three Months Ended March 31, 2017	Total Number of Shares Purchased	Average Price Paid per Share
January 1 - January 31	—	$	—
February 1 - February 28	—	$	—
March 1- March 31	927,971	$	44.94

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. References are to the related pages on the Forms 10-K as printed and distributed.

Federal Regulation

FERC

Capacity Market Issues

December 31, 2016 Form 10-K page 16. PJM, NYISO and ISO-NE 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. Issues presented in various forums include consideration of whether the competitive market framework can 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. 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. 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. However, aspects of FERC’s order are currently pending appeal in the Court of Appeals for the D.C. Circuit (D.C. Circuit). The CP product will be implemented fully for the 2020-2021 Delivery Year. FERC has approved changes to the CP construct that will enhance the participation of intermittent and DR resources (“seasonal resources”). Specifically, FERC approved PJM’s modifications to the aggregation rules to improve the ability of seasonal resources to participate. 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. We do not expect action on the complaints before the upcoming base residual auction in May 2017.

Capacity Market Issues—ISO-NE

December 31, 2016 Form 10-K page 17. ISO-NE’s market for installed capacity in New England provides fixed capacity payments for generators, imports and DR. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the locational value of resources on the system and contains incentive mechanisms to encourage availability during stressed system conditions. ISO-NE also employs a mechanism, similar to PJM’s CP mechanism, that provides incentives for performance and that imposes charges for non-performance during times of system stress. We view this mechanism as generally positive for generating resources as providing more robust income streams. However, it also imposes additional financial risk for non-performance. One aspect of the current market design that we do not support and are currently challenging in the D.C. Circuit is the exemption from the MOPR in the capacity market afforded for up to 200 MW annually (600 MW cumulatively) of renewable resources.

Price Formation Initiatives

December 31, 2016 Form 10-K page 18. Power has been actively involved both through stakeholder processes and through filings at FERC in seeking improvements to the rules for setting prices for energy in the day-ahead and real-time markets administered by PJM and other system operators. FERC recently issued a notice of proposed rulemaking (NOPR) proposing that RTOs/ISOs modify their rules governing fast-start resources. Fast-start resources typically are committed in real-time, very

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close to the interval when needed and can respond quickly to unforeseen system needs. However, without fast-start pricing, some fast-start resources are ineligible to set prices due to inflexible operating limits. As a result, prices may not reflect the marginal cost of serving load. In a separate proceeding, PJM has submitted a proposal at FERC’s request to modify its rules to allow market sellers to submit day-ahead offers that vary by hour and to allow market sellers to update their offers in real time on an hourly basis under certain circumstances. FERC has accepted PJM’s proposal which will become effective on November 1, 2017. We believe that both changes will improve price formation in the energy and ancillary services markets.

Transmission Regulation—Transmission Policy Developments

December 31, 2016 Form 10-K page 18. In August 2016, PJM announced that it had suspended the Artificial Island transmission project and would be performing a comprehensive analysis to support a future course of action. In March 2017, PJM staff made its final recommendation to the PJM Board with respect to the project. Under the recommended project, PSE&G will construct necessary upgrade work in Hope Creek, at a cost of approximately $130 million. In April 2017, the PJM Board announced that it would be lifting the suspension and approved the staff recommended project. The PJM Board also stated that it would be analyzing project beneficiaries from an alternate perspective to potentially devise an alternative cost allocation methodology for stability projects.

Transmission Regulation—Con Edison Wheeling Agreement

December 31, 2016 Form 10-K page 19. In April 2016, Con Edison informed PJM that it would allow its Wheeling Agreement to expire effective as of May 1, 2017. The Wheeling Agreement enables Con Edison to move 1,000 MW of power from southeastern New York across the PSE&G system for delivery into New York City. NYISO and PJM submitted proposed tariff provisions in January 2017. The proposal concerns future operational procedures and transmission planning assumptions associated with the affected transmission lines. FERC accepted the proposal, subject to refund, effective May 1, 2017. We cannot predict the impact of the proposal on energy prices or transmission planning at this time. Both PSE&G and the BPU protested certain aspects of the proposal. In a related filing, PJM submitted a proposal to FERC revising the cost responsibility assigned to certain entities, including PSE&G, due to the termination of the Wheeling Agreement. Also, PSE&G will continue to recover the costs associated with the new arrangement through its formula rate. We cannot predict the outcome of this proceeding.

State Regulation

Energy Efficiency Program (Energy Efficiency 2017)

In March 2017, we filed a petition with the BPU for our Energy Efficiency 2017 program, requesting extension of three Energy Efficiency Economic sub-programs (multi-family, direct install and hospital efficiency) and the addition of two new sub-programs (smart thermostat and residential data analytics). The petition requested additional capital expenditures of approximately $74 million, additional administrative and other costs of $22 million and information technology system enhancement costs of $3 million. We proposed to recover our investment in these sub-programs under the same clause recovery process as currently approved. This matter is pending.

Environmental Matters

Climate Change

CO₂ Regulation 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, 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. Upon completion of the review, the EPA is expected to suspend, revise or rescind the rules as appropriate. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.

Water Pollution Control

Steam Electric Effluent Guidelines

December 31, 2016 Form 10-K page 23. 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. 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-

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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. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

Waters of the United States

December 31, 2016 Form 10-K page 24. In April 2014, the EPA Administrator and the Assistant Secretary of the Army (Civil Works) jointly published a proposed rule to clarify the definition of waters of the United States under the CWA programs in order to protect the streams and wetlands that form the foundation of the nation’s water resources. This definition will have broad application to all areas of compliance under the CWA, including permitted discharges and construction activities. The final rule was published in June 2015 and various states, industry coalitions and environmental organizations have initiated legal action related to the provisions of the final rule as well as which court has jurisdiction over the rule. The U.S. Supreme Court is expected to rule on the question of jurisdiction by June 2017. Some states, including New Jersey, are subject to state requirements beyond those imposed under federal law. While we do not anticipate material impacts to projects in New Jersey, the new definition could impose requirements in other states and regions that could impact the development of renewables.

In February 2017, the President of the United States issued an Executive Order that instructed the EPA to review the rule and issue a proposal to redefine “Waters of the United States.”

Endangered Species Act

December 31, 2016 Form 10-K page 25. In June 2015, the Sierra Club and another environmental group submitted to the NJDEP a sixty-day notice of intent to sue alleging the agency has caused violations of the Endangered Species Act by allowing our Mercer generation station to operate in a manner which has caused the mortality of certain species of sturgeon. Among other things, the notice requested the NJDEP to prioritize completion of a permit renewal action for Mercer which addresses the alleged Endangered Species Act violations. In March 2017, we submitted our Incidental Take Permit to the National Marine Fisheries Service outlining operation and monitoring requirements through retirement of the Mercer generation station on

June 1, 2017 and subsequent decommissioning.

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ITEM 6.	EXHIBITS

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



a. PSEG:
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 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 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: April 28, 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: April 28, 2017

Table of Contents

SIGNATURE



PSEG POWER LLC
(Registrant)

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

Date: April 28, 2017