Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

This combined Form 10-K is separately filed by PSEG, PSE&G and 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 as to any other company.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Public Service Enterprise Group Incorporated

Newark, New Jersey

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2017, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(a) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2018, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.




/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey
February 26, 2018

We have served as the Company's auditor since 1934.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Sole Stockholder of

Public Service Electric and Gas Company

Newark, New Jersey

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company”) as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(b) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.




/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey
February 26, 2018

We have served as the Company's auditor since 1934.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Sole Member of

PSEG Power LLC

Newark, New Jersey

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of PSEG Power LLC and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, member’s equity, and cash flows for each of the three years in the period ended December 31, 2017, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(c) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.




/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey
February 26, 2018

We have served as the Company's auditor since 2000.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions, except per share data




	Years Ended December 31,
	2017			2016			2015
OPERATING REVENUES	$	9,084		$	9,061		$	10,415
OPERATING EXPENSES
Energy Costs	2,800			3,001			3,261
Operation and Maintenance	2,869			3,008			2,978
Depreciation and Amortization	1,986			1,476			1,214
Total Operating Expenses	7,655			7,485			7,453
OPERATING INCOME	1,429			1,576			2,962
Income from Equity Method Investments	14			11			12
Other Income	319			191			254
Other Deductions	(91		)	(67		)	(102		)
Other-Than-Temporary Impairments	(12		)	(28		)	(53		)
Interest Expense	(391		)	(385		)	(393		)
INCOME BEFORE INCOME TAXES	1,268			1,298			2,680
Income Tax Benefit (Expense)	306			(411		)	(1,001		)
NET INCOME	$	1,574		$	887		$	1,679
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			505			505
DILUTED	507			508			508
NET INCOME PER SHARE:
BASIC	$	3.12		$	1.76		$	3.32
DILUTED	$	3.10		$	1.75		$	3.30

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2017			2016			2015
NET INCOME		$	1,574		$	887		$	1,679
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(37), $(41) and $34 for the years ended 2017, 2016 and 2015, respectively		44			42			(27		)
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $1, $(1), and $7 for the years ended 2017, 2016 and 2015, respectively		(2		)	2			(10		)
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(4), $8 and $(18) for the years ended 2017, 2016 and 2015, respectively		(8		)	(12		)	25
Other Comprehensive Income (Loss), net of tax		34			32			(12		)
COMPREHENSIVE INCOME		$	1,608		$	919		$	1,667

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2017			2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	313		$	423
Accounts Receivable, net of allowances of $59 in 2017 and $68 in 2016	1,348			1,161
Tax Receivable	127			78
Unbilled Revenues	296			260
Fuel	289			326
Materials and Supplies, net	577			561
Prepayments	118			76
Derivative Contracts	29			163
Regulatory Assets	211			199
Other	4			7
Total Current Assets	3,312			3,254
PROPERTY, PLANT AND EQUIPMENT	41,231			39,337
Less: Accumulated Depreciation and Amortization	(9,434		)	(10,051		)
Net Property, Plant and Equipment	31,797			29,286
NONCURRENT ASSETS
Regulatory Assets	3,222			3,319
Long-Term Investments	932			1,050
Nuclear Decommissioning Trust (NDT) Fund	2,133			1,859
Long-Term Tax Receivable	—			104
Long-Term Receivable of VIEs	686			589
Other Special Funds	231			217
Goodwill	16			16
Other Intangibles	114			98
Derivative Contracts	7			24
Other	266			254
Total Noncurrent Assets	7,607			7,530
TOTAL ASSETS	$	42,716		$	40,070

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2017			2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	1,000		$	500
Commercial Paper and Loans	542			388
Accounts Payable	1,694			1,459
Derivative Contracts	16			13
Accrued Interest	103			97
Accrued Taxes	48			31
Clean Energy Program	128			142
Obligation to Return Cash Collateral	129			132
Regulatory Liabilities	47			88
Other	461			426
Total Current Liabilities	4,168			3,276
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	5,240			8,658
Regulatory Liabilities	2,948			118
Asset Retirement Obligations	1,024			726
Other Postretirement Benefit (OPEB) Costs	1,455			1,324
OPEB Costs of Servco	542			452
Accrued Pension Costs	537			568
Accrued Pension Costs of Servco	129			128
Environmental Costs	357			401
Derivative Contracts	5			3
Long-Term Accrued Taxes	175			180
Other	221			211
Total Noncurrent Liabilities	12,633			12,769
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT	12,068			10,895
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016— 534 shares	4,961			4,936
Treasury Stock, at cost, 2017 and 2016—29 shares	(763		)	(717		)
Retained Earnings	9,878			9,174
Accumulated Other Comprehensive Loss	(229		)	(263		)
Total Stockholders’ Equity	13,847			13,130
Total Capitalization	25,915			24,025
TOTAL LIABILITIES AND CAPITALIZATION	$	42,716		$	40,070

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,574		$	887		$	1,679
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,986			1,476			1,214
Amortization of Nuclear Fuel	199			203			213
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual	103			109			104
Impairment Costs for Early Plant Retirements	—			102			—
Provision for Deferred Income Taxes (Other than Leases) and ITC	(167		)	474			685
Non-Cash Employee Benefit Plan Costs	89			127			161
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	(159		)	(6		)	26
Net (Gain) Loss on Lease Investments	48			92			—
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	188			183			(143		)
Net Change in Regulatory Assets and Liabilities	(188		)	(138		)	(48		)
Cost of Removal	(107		)	(131		)	(120		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(156		)	(26		)	(38		)
Net Change in Certain Current Assets and Liabilities
Tax Receivable	65			303			(94		)
Accrued Taxes	16			3			(91		)
Margin Deposit	(90		)	(76		)	122
Other Current Assets and Liabilities	(70		)	(180		)	288
Employee Benefit Plan Funding and Related Payments	(81		)	(103		)	(109		)
Other	11			12			70
Net Cash Provided By (Used In) Operating Activities	3,261			3,311			3,919
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(4,190		)	(4,199		)	(3,863		)
Purchase of Emissions Allowances and RECs	(117		)	(99		)	(106		)
Proceeds from Sales of Available-for-Sale Securities	2,319			824			1,501
Investments in Available-for-Sale Securities	(2,340		)	(856		)	(1,552		)
Other	72			82			78
Net Cash Provided By (Used In) Investing Activities	(4,256		)	(4,248		)	(3,942		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	154			24			364
Issuance of Long-Term Debt	2,175			2,675			1,350
Redemption of Long-Term Debt	(500		)	(824		)	(600		)
Redemption of Securitization Debt	—			—			(259		)
Cash Dividends Paid on Common Stock	(870		)	(830		)	(789		)
Other	(74		)	(79		)	(51		)
Net Cash Provided By (Used In) Financing Activities	885			966			15
Net Increase (Decrease) in Cash and Cash Equivalents	(110		)	29			(8		)
Cash and Cash Equivalents at Beginning of Period	423			394			402
Cash and Cash Equivalents at End of Period	$	313		$	423		$	394
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(8	)	$	(245	)	$	447
Interest Paid, Net of Amounts Capitalized	$	377		$	365		$	381
Accrued Property, Plant and Equipment Expenditures	$	722		$	664		$	510

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Millions




	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest
	Shs.	Amount		Shs.		Amount				Total
Balance as of January 1, 2015	534	$	4,876	(28	)	$	(635	)	$	8,227		$	(283	)	$	1		$	12,186
Net Income	—	—		—		—			1,679			—			—			1,679
Other Comprehensive Income (Loss), net of tax (expense) benefit of $23	—	—		—		—			—			(12		)	—			(12		)
Comprehensive Income																		1,667
Cash Dividends on Common Stock	—	—		—		—			(789		)	—			—			(789		)
Other	—	39		—		(36		)	—			—			—			3
Balance as of December 31, 2015	534	$	4,915	(28	)	$	(671	)	$	9,117		$	(295	)	$	1		$	13,067
Net Income	—	—		—		—			887			—			—			887
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(34)	—	—		—		—			—			32			—			32
Comprehensive Income																		919
Cash Dividends on Common Stock	—	—		—		—			(830		)	—			—			(830		)
Other	—	21		(1	)	(46		)	—			—			(1		)	(26		)
Balance as of December 31, 2016	534	$	4,936	(29	)	$	(717	)	$	9,174		$	(263	)	$	—		$	13,130
Net Income	—	—		—		—			1,574			—			—			1,574
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(40)	—	—		—		—			—			34			—			34
Comprehensive Income																		1,608
Cash Dividends on Common Stock	—	—		—		—			(870		)	—			—			(870		)
Other	—	25		—		(46		)	—			—			—			(21		)
Balance as of December 31, 2017	534	$	4,961	(29	)	$	(763	)	$	9,878		$	(229	)	$	—		$	13,847

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions




	Years Ended December 31,
	2017			2016			2015
OPERATING REVENUES	$	6,234		$	6,221		$	6,636
OPERATING EXPENSES
Energy Costs	2,363			2,567			2,722
Operation and Maintenance	1,434			1,475			1,560
Depreciation and Amortization	685			565			892
Total Operating Expenses	4,482			4,607			5,174
OPERATING INCOME	1,752			1,614			1,462
Other Income	92			83			79
Other Deductions	(5		)	(4		)	(4		)
Interest Expense	(303		)	(289		)	(280		)
INCOME BEFORE INCOME TAXES	1,536			1,404			1,257
Income Tax Expense	(563		)	(515		)	(470		)
NET INCOME	$	973		$	889		$	787

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2017			2016		2015
NET INCOME		$	973		$	889	$	787
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $0 and $0 for the years ended 2017, 2016 and 2015, respectively		(1		)	—		(1		)
COMPREHENSIVE INCOME		$	972		$	889	$	786

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2017			2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	242		$	390
Accounts Receivable, net of allowances of $59 in 2017 and $68 in 2016	882			810
Accounts Receivable—Affiliated Companies	—			76
Unbilled Revenues	296			260
Materials and Supplies	197			180
Prepayments	44			9
Regulatory Assets	211			199
Other	4			6
Total Current Assets	1,876			1,930
PROPERTY, PLANT AND EQUIPMENT	29,117			26,347
Less: Accumulated Depreciation and Amortization	(6,101		)	(5,760		)
Net Property, Plant and Equipment	23,016			20,587
NONCURRENT ASSETS
Regulatory Assets	3,222			3,319
Long-Term Investments	280			299
Other Special Funds	46			43
Other	114			110
Total Noncurrent Assets	3,662			3,771
TOTAL ASSETS	$	28,554		$	26,288

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2017		2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	750	$	—
Accounts Payable	728		718
Accounts Payable—Affiliated Companies	340		260
Accrued Interest	78		76
Clean Energy Program	128		142
Derivative Contracts	—		5
Obligation to Return Cash Collateral	129		132
Regulatory Liabilities	47		88
Other	311		296
Total Current Liabilities	2,511		1,717
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	3,391		5,873
OPEB Costs	1,103		1,009
Accrued Pension Costs	226		250
Regulatory Liabilities	2,948		118
Environmental Costs	283		332
Asset Retirement Obligations	212		213
Long-Term Accrued Taxes	91		130
Other	114		116
Total Noncurrent Liabilities	8,368		8,041
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT	7,841		7,818
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2017 and 2016—132 shares	892		892
Contributed Capital	1,095		945
Basis Adjustment	986		986
Retained Earnings	6,861		5,888
Accumulated Other Comprehensive Income	—		1
Total Stockholder’s Equity	9,834		8,712
Total Capitalization	17,675		16,530
TOTAL LIABILITIES AND CAPITALIZATION	$	28,554	$	26,288

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	973		$	889		$	787
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	685			565			892
Provision for Deferred Income Taxes and ITC	616			658			386
Non-Cash Employee Benefit Plan Costs	50			72			95
Cost of Removal	(107		)	(131		)	(120		)
Net Change in Other Regulatory Assets and Liabilities	(188		)	(138		)	(48		)
Net Change in Certain Current Assets and Liabilities
Accounts Receivable and Unbilled Revenues	(106		)	(84		)	165
Materials and Supplies	(13		)	(7		)	(15		)
Prepayments	(35		)	22			11
Accounts Payable	1			(29		)	45
Accounts Receivable/Payable—Affiliated Companies, net	101			199			—
Other Current Assets and Liabilities	17			8			(29		)
Employee Benefit Plan Funding and Related Payments	(68		)	(82		)	(91		)
Other	(87		)	(48		)	47
Net Cash Provided By (Used In) Operating Activities	1,839			1,894			2,125
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,919		)	(2,816		)	(2,692		)
Proceeds from Sales of Available-for-Sale Securities	36			22			21
Investments in Available-for-Sale Securities	(37		)	(24		)	(22		)
Solar Loan Investments	7			14			11
Other	10			15			11
Net Cash Provided By (Used In) Investing Activities	(2,903		)	(2,789		)	(2,671		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	—			(153		)	153
Issuance of Long-Term Debt	775			1,275			850
Redemption of Long-Term Debt	—			(271		)	(300		)
Redemption of Securitization Debt	—			—			(259		)
Contributed Capital	150			250			—
Other	(9		)	(14		)	(10		)
Net Cash Provided By (Used In) Financing Activities	916			1,087			434
Net Increase (Decrease) in Cash and Cash Equivalents	(148		)	192			(112		)
Cash and Cash Equivalents at Beginning of Period	390			198			310
Cash and Cash Equivalents at End of Period	$	242		$	390		$	198
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(104	)	$	(295	)	$	(28	)
Interest Paid, Net of Amounts Capitalized	$	294		$	273		$	261
Accrued Property, Plant and Equipment Expenditures	$	429		$	420		$	396

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

Millions




	Common Stock		Contributed Capital		Basis Adjustment		Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Total
Balance as of January 1, 2015	$	892	$	695	$	986	$	4,212	$	2		$	6,787
Net Income	—		—		—		787		—			787
Other Comprehensive Income, net of tax (expense) benefit of $0	—		—		—		—		(1		)	(1		)
Comprehensive Income												786
Balance as of December 31, 2015	$	892	$	695	$	986	$	4,999	$	1		$	7,573
Net Income	—		—		—		889		—			889
Other Comprehensive Income, net of tax (expense) benefit of $0	—		—		—		—		—			—
Comprehensive Income												889
Contributed Capital			250		—		—		—			250
Balance as of December 31, 2016	$	892	$	945	$	986	$	5,888	$	1		$	8,712
Net Income	—		—		—		973		—			973
Other Comprehensive Income, net of tax (expense) benefit of $0	—		—		—		—		(1		)	(1		)
Comprehensive Income												972
Contributed Capital	—		150		—		—		—			150
Balance as of December 31, 2017	$	892	$	1,095	$	986	$	6,861	$	—		$	9,834

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

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions




	Years Ended December 31,
	2017			2016			2015
OPERATING REVENUES	$	3,930		$	4,023		$	4,928
OPERATING EXPENSES
Energy Costs	1,983			1,986			2,150
Operation and Maintenance	1,038			1,143			1,057
Depreciation and Amortization	1,268			881			291
Total Operating Expenses	4,289			4,010			3,498
OPERATING INCOME (LOSS)	(359		)	13			1,430
Income from Equity Method Investments	14			11			14
Other Income	213			102			169
Other Deductions	(56		)	(57		)	(72		)
Other-Than-Temporary Impairments	(12		)	(28		)	(53		)
Interest Expense	(50		)	(84		)	(121		)
INCOME (LOSS) BEFORE INCOME TAXES	(250		)	(43		)	1,367
Income Tax Benefit (Expense)	729			61			(511		)
NET INCOME	$	479		$	18		$	856

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

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2017			2016			2015
NET INCOME		$	479		$	18		$	856
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(39), $(41) and $32 for the years ended 2017, 2016 and 2015, respectively		46			42			(25		)
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0 and $7 for the years ended 2017, 2016 and 2015, respectively		—			—			(11		)
Pension/OPEB adjustment, net of tax (expense) benefit of $(3), $9 and $(16) for the years ended 2017, 2016 and 2015, respectively		(7		)	(13		)	24
Other Comprehensive Income (Loss), net of tax		39			29			(12		)
COMPREHENSIVE INCOME		$	518		$	47		$	844

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

PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2017			2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	32		$	11
Accounts Receivable	380			276
Accounts Receivable—Affiliated Companies	221			205
Short-Term Loan to Affiliate	—			87
Fuel	289			326
Materials and Supplies, net	376			381
Derivative Contracts	29			162
Prepayments	11			10
Other	3			2
Total Current Assets	1,341			1,460
PROPERTY, PLANT AND EQUIPMENT	11,755			12,655
Less: Accumulated Depreciation and Amortization	(3,159		)	(4,135		)
Net Property, Plant and Equipment	8,596			8,520
NONCURRENT ASSETS
NDT Fund	2,133			1,859
Long-Term Investments	87			102
Goodwill	16			16
Other Intangibles	114			98
Other Special Funds	57			53
Derivative Contracts	7			24
Other	67			61
Total Noncurrent Assets	2,481			2,213
TOTAL ASSETS	$	12,418		$	12,193

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

PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2017			2016
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	250		$	—
Accounts Payable	712			539
Accounts Payable—Affiliated Companies	57			25
Short-Term Loan from Affiliate	281			—
Derivative Contracts	16			8
Accrued Interest	20			20
Other	99			88
Total Current Liabilities	1,435			680
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	1,406			2,170
Asset Retirement Obligations	810			511
OPEB Costs	283			251
Derivative Contracts	5			3
Accrued Pension Costs	184			191
Long-Term Accrued Taxes	52			77
Other	140			129
Total Noncurrent Liabilities	2,880			3,332
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
LONG-TERM DEBT	2,136			2,382
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,911			4,782
Accumulated Other Comprehensive Loss	(172		)	(211		)
Total Member’s Equity	5,967			5,799
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	12,418		$	12,193

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

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	479		$	18		$	856
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,268			881			291
Amortization of Nuclear Fuel	199			203			213
Provision for Deferred Income Taxes and ITC	(807		)	(208		)	261
Interest Accretion on Asset Retirement Obligation	30			26			26
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	188			183			(143		)
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual	103			109			104
Impairment Costs for Early Plant Retirements	—			102			—
Non-Cash Employee Benefit Plan Costs	28			39			48
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(156		)	(26		)	(38		)
Net Change in Certain Current Assets and Liabilities
Fuel, Materials and Supplies	42			31			62
Margin Deposit	(90		)	(76		)	122
Accounts Receivable	(45		)	(71		)	63
Accounts Payable	39			(22		)	(46		)
Accounts Receivable/Payable—Affiliated Companies, net	(2		)	6			(84		)
Other Current Assets and Liabilities	10			10			(36		)
Employee Benefit Plan Funding and Related Payments	(7		)	(13		)	(11		)
Other	47			63			18
Net Cash Provided By (Used In) Operating Activities	1,326			1,255			1,706
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,231		)	(1,343		)	(1,117		)
Purchase of Emissions Allowances and RECs	(117		)	(99		)	(106		)
Proceeds from Sales of Available-for-Sale Securities	2,182			739			1,422
Investments in Available-for-Sale Securities	(2,199		)	(766		)	(1,455		)
Short-Term Loan—Affiliated Company	87			276			221
Other	46			46			34
Net Cash Provided By (Used In) Investing Activities	(1,232		)	(1,147		)	(1,001		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	—			700			—
Cash Dividend Paid	(350		)	(250		)	(400		)
Redemption of Long-Term Debt	—			(553		)	(300		)
Short-Term Loan—Affiliated Company	281			—			—
Other	(4		)	(6		)	(2		)
Net Cash Provided By (Used In) Financing Activities	(73		)	(109		)	(702		)
Net Increase (Decrease) in Cash and Cash Equivalents	21			(1		)	3
Cash and Cash Equivalents at Beginning of Period	11			12			9
Cash and Cash Equivalents at End of Period	$	32		$	11		$	12
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	77		$	50		$	393
Interest Paid, Net of Amounts Capitalized	$	48		$	81		$	116
Accrued Property, Plant and Equipment Expenditures	$	293		$	244		$	114

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

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

Millions




	Contributed Capital		Basis Adjustment			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance as of January 1, 2015	$	2,214	$	(986	)	$	4,558		$	(228	)	$	5,558
Net Income	—		—			856			—			856
Other Comprehensive Income (Loss), net of tax (expense) benefit of $23	—		—			—			(12		)	(12		)
Comprehensive Income												844
Cash Dividends Paid	—		—			(400		)	—			(400		)
Balance as of December 31, 2015	$	2,214	$	(986	)	$	5,014		$	(240	)	$	6,002
Net Income	—		—			18			—			18
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(32)	—		—			—			29			29
Comprehensive Income												47
Cash Dividends Paid	—		—			(250		)	—			(250		)
Balance as of December 31, 2016	$	2,214	$	(986	)	$	4,782		$	(211	)	$	5,799
Net Income	—		—			479			—			479
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(42)	—		—			—			39			39
Comprehensive Income												518
Cash Dividends Paid	—		—			(350		)	—			(350		)
Balance as of December 31, 2017	$	2,214	$	(986	)	$	4,911		$	(172	)	$	5,967

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies

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 energy efficiency and related programs in New Jersey, which are regulated by the BPU.

•

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 energy efficiency and related programs in New Jersey, which are regulated by the BPU.


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

•

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

PSEG’s other direct wholly owned subsidiaries are: 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); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Basis of Presentation

The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP).

Significant Accounting Policies

Principles of Consolidation

Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 4. Variable Interest Entity. Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation.

PSE&G and Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories.

Accounting for the Effects of Regulation

In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6. Regulatory Assets and Liabilities.

Derivative Instruments

Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash.

Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period.

Certain offsetting derivative assets and liabilities 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, these positions are offset on the Consolidated Balance Sheets of Power and PSEG.

For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings.

For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions.

Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time.

For additional information regarding derivative financial instruments, see Note 16. Financial Risk Management Activities.

Revenue Recognition

PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms.

Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities.

The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 16. Financial Risk Management Activities for further discussion.

PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense is also reported net based on Power’s monthly net sale or purchase position in the individual ISOs.

PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 4. Variable Interest Entity for further information.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The majority of Energy Holdings' revenues relate to its investments in leveraged leases. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio.

Depreciation and Amortization

PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows:




	2017		2016		2015
	Avg Rate		Avg Rate		Avg Rate
Electric Transmission	2.41	%	2.39	%	2.42	%
Electric Distribution	2.51	%	2.49	%	2.50	%
Gas Distribution	1.63	%	1.63	%	1.64	%

Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are:


•	general plant assets—3 years to 20 years


•	fossil production assets—30 years to 70 years


•	nuclear generation assets—approximately 60 years


•	pumped storage facilities—76 years


•	solar assets—25 years

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)

AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2017, 2016 and 2015 were as follows:




	AFUDC/IDC Capitalized
	2017				2016				2015
	Millions		Avg Rate		Millions		Avg Rate		Millions		Avg Rate
PSE&G	$	73	7.42	%	$	66	7.81	%	$	65	8.01	%
Power	$	78	4.60	%	$	54	4.87	%	$	27	5.14	%

Income Taxes

PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary in accordance with a tax sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property.

Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 20. Income Taxes for further discussion.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Impairment of Long-Lived Assets and Leveraged Leases

Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 3. Early Plant Retirements for more information.

For Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically Power’s solar plants and Kalaeloa).

Energy Holdings’ leveraged leases are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. Residual values are the estimated values of the leased assets at the end of the respective lease per the original lease terms, net of any subsequent impairments. A review of the residual valuations, which are calculated by discounting the cash flows related to the leased assets after the lease term, is performed at least annually for each plant subject to lease using specific assumptions tailored to each plant. Those valuations are compared to the recorded residual values to determine if an impairment is warranted.

Cash and Cash Equivalents

Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less.

Accounts Receivable—Allowance for Doubtful Accounts

PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence.

Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received.

Materials and Supplies and Fuel

PSE&G’s and Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method.

Property, Plant and Equipment

PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation.

Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity, improve or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Available-for-Sale Securities

These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans.

Realized gains and losses on available-for-sale securities are recorded in earnings and unrealized gains and losses on such securities are recorded as a component of Accumulated Other Comprehensive Income (Loss). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 9. Available-for-Sale Securities for further discussion.

Pension and Other Postretirement Benefits (OPEB) Plans

The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) for all plan assets.

PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset because it is restricted.

Pursuant to the OSA, Servco records expense only to the extent of its contributions to its pension plan trusts and for OPEB payments made to retirees.

See Note 12. Pension and Other Postretirement Benefits (OPEB) for further discussion.

Basis Adjustment

PSE&G and Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million, net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Note 2. Recent Accounting Standards

New Standards Issued and Adopted

Business Combinations: Clarifying the Definition of a Business

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

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

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. PSEG adopted this standard on January 1, 2018. PSEG will elect the full retrospective method of transition. Under this method, PSEG will restate its prior period financial statements to align with the 2018 presentation.

PSEG has evaluated existing contracts and revenue streams for potential changes under the new revenue recognition standard. Included in the scope of the new standard are PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the distribution of electricity and gas to retail residential and commercial and industrial customers, and transmission revenues. Tariff revenues comprise substantially all of PSE&G’s revenue. PSEG expects no material change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. PSE&G’s revenue from contracts with customers will continue to be recorded as electricity or gas is delivered to the customer. Certain reclassifications of PSE&G’s revenue streams will affect Operating Revenues and Operating Expenses due to the application of this standard.

Also included in the scope of the new standard are Power’s electricity, gas and related product sales. Certain reclassifications of Power’s revenue streams will also affect Operating Revenues and Energy Costs due to the application of this standard.

PSEG, PSE&G and Power do not anticipate any material impact to net income as a result of adoption of this new standard.

The new standard will result in more detailed disclosures of revenue compared to current guidance and changes in presentation. PSEG will disaggregate its revenues by operating segment. PSE&G will further disaggregate its revenue by product line (i.e. electric distribution, gas distribution, and transmission). Power will further disaggregate its revenues by product line (i.e. electricity, gas). Electricity revenues will be further disaggregated by region (i.e. PJM, New York ISO and ISO New England). Gas revenues will be further disaggregated by third party sales and sales to affiliates. Other Revenues from Contracts with Customers will also be disclosed including PSE&G appliance service and repair and Power solar power revenues.

PSEG will elect the invoice practical expedient, where applicable, in recording its revenue. Under the practical expedient, PSEG has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of PSEG’s performance completed to date. PSEG may recognize revenue in the amount to which it has a right to invoice. As such under this practical expedient, there are no future performance obligations to disclose. Where PSEG has entered into fixed consideration contracts, it will disclose its remaining performance obligations under these agreements.

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 recorded a cumulative effect adjustment by reclassifying the unrealized gain related to equity investments of $342 million ($176 million, net of tax) from Accumulated Other Comprehensive Income to Retained Earnings on January 1, 2018, and expects increased volatility in Net Income due to changes in fair value of its equity securities within the NDT and Rabbi Trust Funds.

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; early adoption was permitted. PSEG expects no changes in its presentation of its Statement of Cash Flows as a result of adopting this new standard. PSEG adopted this standard on January 1, 2018 using a retrospective transition method to each period presented.

Statement of Cash Flows: Restricted Cash

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

The standard is effective for annual and interim periods beginning after December 15, 2017; early adoption was permitted. PSEG adopted this standard on January 1, 2018 using a retrospective transition method for each period presented. PSEG will

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

continue the current balance sheet classification of restricted cash or restricted cash equivalents. PSEG will provide a reconciliation of cash and cash equivalents and restricted cash or restricted cash equivalents and include a description of these amounts.

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. PSEG adopted this standard as of January 1, 2018. Beginning January 1, 2018, PSEG and each of its subsidiaries began to classify the total net pension and OPEB non-service benefit costs in a separate line item in the Statement of Operations after Operating Income. PSEG will also recast those amounts for prior years in accordance with the new standard by using the practical expedient of using the previously disclosed non-service components of pension and OPEB costs. The service cost component of pension and OPEB costs will continue to be classified in O&M Expense, except for that portion capitalized, as appropriate, within Property, Plant and Equipment. As a result of adopting this new standard, PSE&G expects to reduce its charge to expense by approximately $55 million to $65 million in 2018.

Stock Compensation - Scope of Modification Accounting

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

The standard is effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017, early adoption was permitted. This standard should be applied prospectively to an award modified on or after the adoption date. PSEG adopted this standard effective January 1, 2018.

New Standards Issued But Not Yet Adopted

Leases

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

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

Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

This accounting standard’s amendments more closely align hedge accounting with the companies’ risk management activities in the financial statements. The amendments expand hedge accounting for both non-financial and financial risk components by permitting contractually specified components to designate as the hedged risk in a cash flow hedge involving the purchase or sale of non-financial assets or variable rate financial instruments. Additionally, the amendments ease the operational burden of applying hedge accounting by allowing more time to prepare hedge documentation, and allow effectiveness assessments to be performed on a qualitative basis after hedge inception.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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.

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

This accounting standard would affect any entity that is required to apply the provisions of the Accounting Standards Codification topic, “Income Statement-Reporting Comprehensive Income,” and has items of other comprehensive income for which the related tax effects are presented in other comprehensive income as required by GAAP. Specifically, this standard would allow entities to record a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the newly enacted federal corporate income tax rate. The amount of the reclassification would be the difference between the historical corporate income tax rate and the newly enacted 21% corporate income tax rate.

The standard is effective for all entities for annual periods, and interim periods within those annual periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period for public business entities for reporting periods for which financial statements have not yet been issued or made available for issuance.

An entity would be able to choose to apply this standard retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the new tax legislation enacted in 2017 is recognized or apply the standard in the reporting period adopted. PSEG is currently analyzing the impact this standard, if adopted, could have on its consolidated financial statements.

Measurement of Credit Losses on Financial Instruments

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

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

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3. Early Plant Retirements

Fossil

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

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

As of June 1, 2017, Power recognized total D&A of $964 million for the Hudson and Mercer units to reflect the end of their economic useful lives in 2017. During the year ended December 31, 2017, Power recognized pre-tax charges in Energy Costs of $15 million, primarily for coal inventory lower of cost or market adjustments. During the year ended December 31, 2017, Power also recognized pre-tax charges in O&M of $23 million, including shut down costs and an increase in the Asset Retirement Obligation due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. Power is exploring various opportunities with these sites, including using the sites for alternative industrial activity or the disposition of one or both of the sites. 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.

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

Nuclear

Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. Most recently, in February 2018, Exelon, a co-owner of the Salem units, announced its intention to accelerate the closure of its Oyster Creek nuclear plant located in New Jersey, one year earlier than previously planned for economic reasons. These closures and retirements are generally due to the decline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities, both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar and the failure to adequately compensate nuclear generating stations for the attributes they bring similar to renewable energy production. 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 further shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.

If any or all of the Salem and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominately by increasing New Jersey’s reliance on natural gas generation. Such a decrease in fuel diversity could also increase the market’s vulnerability to price fluctuations and power disruptions in times of high demand. The New Jersey Legislature is assessing legislation that would provide a safety net in order to prevent the loss of environmental attributes from nuclear generating stations. Power cannot predict whether the legislation will be enacted or, if enacted, whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.

In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number of decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

influenced by the financial outlook of the units, including the progress, timing and continued outlook for enactment of proposed legislation in the state of New Jersey.

If market prices continue to be depressed and legislation is not enacted that adequately compensates nuclear generating stations for their attributes, Power anticipates it will no longer be covering its costs nor be adequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units and would anticipate retiring these units early. The costs associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs and additional funding of the Nuclear Decommissioning Trust Fund (NDT) would be material to both PSEG and Power.

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




	As of December 31, 2017
	Hope Creek			Salem			Support Facilities and Other (A)		Peach Bottom
	Millions
Assets
Materials and Supplies Inventory	$	86		$	78		$	—	$	41
Nuclear Production, net of Accumulated Depreciation	605			661			211		802
Nuclear Fuel In-Service, net of Accumulated Depreciation	104			124			—		153
Construction Work in Progress (including nuclear fuel)	245			90			1		25
Total Assets	$	1,040		$	953		$	212	$	1,021
Liabilities
Asset Retirement Obligation	$	302		$	249		$	—	$	205
Total Liabilities	$	302		$	249		$	—	$	205
Net Assets	$	738		$	704		$	212	$	816
NRC License Renewal Term	2046			2036/2040			N/A		2033/2034
% Owned	100		%	57		%	Various		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 9. 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. In 2017, 2016 and 2015, Servco recorded $438 million, $410 million

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and $375 million, 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 Consolidated Statement of Operations.

Note 5. Property, Plant and Equipment and Jointly-Owned Facilities

Information related to Property, Plant and Equipment as of December 31, 2017 and 2016 is detailed below:




	PSE&G		Power		Other		PSEG Consolidated
	Millions
2017
Transmission and Distribution:
Electric Transmission	$	10,425	$	—	$	—	$	10,425
Electric Distribution	8,455		—		—		8,455
Gas Distribution and Transmission	7,122		—		—		7,122
Construction Work in Progress	1,735		—		—		1,735
Other	512		—		—		512
Total Transmission and Distribution	28,249		—		—		28,249
Generation:
Fossil Production	—		4,923		—		4,923
Nuclear Production	—		2,893		—		2,893
Nuclear Fuel in Service	—		745		—		745
Other Production-Solar	593		757		—		1,350
Construction Work in Progress	—		2,339		—		2,339
Total Generation	593		11,657		—		12,250
Other	275		98		359		732
Total	$	29,117	$	11,755	$	359	$	41,231




	PSE&G		Power		Other		PSEG Consolidated
	Millions
2016
Transmission and Distribution:
Electric Transmission	$	9,149	$	—	$	—	$	9,149
Electric Distribution	7,976		—		—		7,976
Gas Distribution and Transmission	6,458		—		—		6,458
Construction Work in Progress	1,501		—		—		1,501
Other	439		—		—		439
Total Transmission and Distribution	25,523		—		—		25,523
Generation:
Fossil Production	—		7,096		—		7,096
Nuclear Production	—		2,516		—		2,516
Nuclear Fuel in Service	—		783		—		783
Other Production-Solar	591		687		—		1,278
Construction Work in Progress	—		1,483		—		1,483
Total Generation	591		12,565		—		13,156
Other	233		90		335		658
Total	$	26,347	$	12,655	$	335	$	39,337

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PSE&G and Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses.




			As of December 31,
			2017				2016
	Ownership				Accumulated				Accumulated
	Interest		Plant		Depreciation		Plant		Depreciation
			Millions
PSE&G:
Transmission Facilities	Various		$	162	$	58	$	169	$	65
Power:
Coal Generating:
Conemaugh	23	%	$	408	$	178	$	408	$	166
Keystone	23	%	$	409	$	187	$	409	$	176
Nuclear Generating:
Peach Bottom	50	%	$	1,328	$	348	$	1,272	$	306
Salem	57	%	$	1,147	$	277	$	1,077	$	304
Nuclear Support Facilities	Various		$	239	$	81	$	238	$	71
Pumped Storage Facilities:
Yards Creek	50	%	$	44	$	26	$	42	$	25
Merrill Creek Reservoir	14	%	$	1	$	—	$	1	$	—

Power holds undivided ownership interests in the jointly-owned facilities above. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.

Power co-owns Salem and Peach Bottom with Exelon Generation. Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process.

GenOn Northeast Management Company is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process.

Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process.

Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process.

Note 6. Regulatory Assets and Liabilities

PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate cases. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2017 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods.

Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income.

PSE&G had the following Regulatory Assets and Liabilities:




	As of December 31,
	2017		2016
	Millions
Regulatory Assets
Current
New Jersey Clean Energy Program	$	128	$	142
Weather Normalization Clause (WNC)	40		49
Electric Energy Costs—Basic Generation Service	23		2
FERC Formula Rate True-up	12		—
Other	8		6
Total Current Regulatory Assets	$	211	$	199
Noncurrent
Pension and OPEB Costs	$	1,488	$	1,403
Manufactured Gas Plant (MGP) Remediation Costs	358		403
Deferred Income Taxes	282		507
Storm Damage Deferrals	241		239
Electric Transmission and Gas Cost of Removal	199		189
Remediation Adjustment Charge (RAC) (Other SBC)	172		180
Conditional Asset Retirement Obligation	162		157
Green Program Recovery Charges (GPRC)	98		91
Unamortized Loss on Reacquired Debt and Debt Expense	55		61
Gas Costs—Basic Gas Supply Service (BGSS)	30		—
FERC Formula Rate True-up	16		—
Other	121		89
Total Noncurrent Regulatory Assets	$	3,222	$	3,319
Total Regulatory Assets	$	3,433	$	3,518




	As of December 31,
	2017		2016
	Millions
Regulatory Liabilities
Current
Gas Costs —BGSS	$	30	$	6
Gas Margin Adjustment Clause	12		11
GPRC	3		28
FERC Formula Rate True-up	—		34
Other	2		9
Total Current Regulatory Liabilities	$	47	$	88
Noncurrent
Excess Deferred Income Tax Regulatory Liability	$	2,868	$	—
Electric Distribution Cost of Removal	80		94
Mark-to-Market (MTM) Contracts	—		20
Other	—		4
Total Noncurrent Regulatory Liabilities	$	2,948	$	118
Total Regulatory Liabilities	$	2,995	$	206

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows:


•	Conditional Asset Retirement Obligation: These costs represent the differences between rate regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates as assets are retired.


•	Deferred Income Taxes: These amounts represent the portion of deferred income taxes that will be recovered or refunded through future rates, based upon established regulatory practices. In December 2017, new tax legislation was enacted (Tax Act) reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSE&G is subject to Financial Accounting Standards Board (FASB) Accounting Standards Codification 740, Income Taxes (ASC 740), which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of reduction in tax rate is the primary reason for the decrease in the Regulatory Asset.

•

Deferred Income Taxes: These amounts represent the portion of deferred income taxes that will be recovered or refunded through future rates, based upon established regulatory practices. In December 2017, new tax legislation was enacted (Tax Act) reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSE&G is subject to Financial Accounting Standards Board (FASB) Accounting Standards Codification 740, Income Taxes (ASC 740), which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of reduction in tax rate is the primary reason for the decrease in the Regulatory Asset.


•	Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its transmission and distribution assets upon retirement. The regulatory asset or liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred.


•	Electric Energy Costs—Basic Generation Service: These costs represent the over or under recovered amounts associated with Basic Generation Services (BGS), as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under recovered balances with interest are returned or recovered through monthly filings.

•

Electric Energy Costs—Basic Generation Service: These costs represent the over or under recovered amounts associated with Basic Generation Services (BGS), as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under recovered balances with interest are returned or recovered through monthly filings.


•	Excess Deferred Income Tax Regulatory Liability: The $2.9 billion Regulatory Liability represents the future revenue reduction of PSE&G’s existing $2.1 billion Accumulated Deferred Income Tax liabilities that are in excess of what is needed to offset future tax liabilities as a result of the Tax Act that reduces the federal corporate income tax rate from a maximum of 35% to 21% effective January 1, 2018. The excess deferred income taxes are primarily related to the difference between book and tax plant depreciation and under the new tax legislation cannot be returned to customers any faster than over the remaining regulatory lives of the related property. For the remaining excess deferred taxes, the mechanism and timing of these refunds will be determined by the BPU and FERC.

•

Excess Deferred Income Tax Regulatory Liability: The $2.9 billion Regulatory Liability represents the future revenue reduction of PSE&G’s existing $2.1 billion Accumulated Deferred Income Tax liabilities that are in excess of what is needed to offset future tax liabilities as a result of the Tax Act that reduces the federal corporate income tax rate from a maximum of 35% to 21% effective January 1, 2018. The excess deferred income taxes are primarily related to the difference between book and tax plant depreciation and under the new tax legislation cannot be returned to customers any faster than over the remaining regulatory lives of the related property. For the remaining excess deferred taxes, the mechanism and timing of these refunds will be determined by the BPU and FERC.


•	FERC Formula Rate True-up: Over or under collection of transmission earnings calculated using a FERC approved formula. Over or under collected balances with interest are returned or recovered through the subsequent annual filing.


•	Gas Costs—Basic Gas Supply Service: These costs represent the over or under recovered amounts associated with Basic Gas Supply Service (BGSS), as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under collected balances are returned or recovered through an annual filing. Interest is accrued only on over recovered balances.

•

Gas Costs—Basic Gas Supply Service: These costs represent the over or under recovered amounts associated with Basic Gas Supply Service (BGSS), as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under collected balances are returned or recovered through an annual filing. Interest is accrued only on over recovered balances.


•	Gas Margin Adjustment Clause: This mechanism credits Firm delivery customers for net distribution margin revenue collected from Transportation Gas Service Non-Firm (TSG-NF) delivery customers. The balance represents the difference between the net margin collected from the TSG-NF Customers versus bill credits provided to Firm delivery customers. Over or under recovered balances with interest are returned or recovered through the subsequent annual filing.

•

Gas Margin Adjustment Clause: This mechanism credits Firm delivery customers for net distribution margin revenue collected from Transportation Gas Service Non-Firm (TSG-NF) delivery customers. The balance represents the difference between the net margin collected from the TSG-NF Customers versus bill credits provided to Firm delivery customers. Over or under recovered balances with interest are returned or recovered through the subsequent annual filing.


•	GPRC: This amount represents costs of the over or under collected balances associated with various renewable energy and energy efficiency programs. The Company files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from 5 to 10 years. Interest is accrued monthly on any over or under recovered balances. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All), Solar 4 All Extension, Solar 4 All Extension II, Solar Loan II Program, Solar Loan III Program and the Energy Efficiency 2017 Program.

•

GPRC: This amount represents costs of the over or under collected balances associated with various renewable energy and energy efficiency programs. The Company files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from 5 to 10 years. Interest is accrued monthly on any over or under recovered balances. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All), Solar 4 All Extension, Solar 4 All Extension II, Solar Loan II Program, Solar Loan III Program and the Energy Efficiency 2017 Program.


•	MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for manufactured gas plants that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC over a seven year period with interest.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


•	MTM Contracts: The estimated fair value of gas hedge contracts and gas cogeneration supply contract. The regulatory asset/liability is offset by a derivative asset/liability and, with respect to the gas hedge contracts only, an intercompany receivable/payable on the Consolidated Balance Sheets.


•	New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2018. The BPU funding requirements are recovered through the SBC.


•	Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses, prior service costs and transition obligations as a result of adoption, which have not been expensed. These costs are amortized and recovered in future rates.

•

Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses, prior service costs and transition obligations as a result of adoption, which have not been expensed. These costs are amortized and recovered in future rates.


•	RAC (Other SBC): Costs incurred to clean up manufactured gas plants which are recovered over seven years with interest through an annual filing.

•

SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund (USF); (2) Energy Efficiency and Renewable Energy Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. Over or under recovered balances with interest are to be returned or recovered through an annual filing.


•	Storm Damage Deferrals: Costs incurred in the cleanup of major storms in 2010 through 2017. As of December 31, 2017, this includes the $220 million of storm costs, net of insurance recoveries, primarily as a result of Hurricane Irene and Superstorm Sandy, approved for recovery in a future base rate case proceeding under a BPU order received in September 2014.


•	Unamortized Loss on Reacquired Debt and Debt Expense: Represents losses on reacquired long-term debt and expenses associated with issuances of new debt, which are recovered through rates over the remaining life of the debt.

•

WNC: This represents the over or under recovery of gas margin under the BPU’s weather normalization clause which is filed annually. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. Over recoveries are returned to customers in the next winter season while under recoveries (subject to an earnings cap) are recovered from customers in the next winter season.

Significant 2017 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows:

•

Electric and Gas Distribution Base Rate Filing—In January 2018, PSE&G filed a distribution base rate case as required as a condition of approval of its Energy Strong Program approved by the BPU in 2014. The filing requests an approximate one percent increase in revenues and seeks to recover investments made to strengthen electric and gas distribution systems. In its filing, PSE&G requested that these rates take into account a reduction in the revenue requirement as a result of the federal corporate income tax rate reduction from 35% to 21% provided in the Tax Act, including a one-time credit for estimated excess income taxes collected between January 1, 2018 and the time new rates go into effect, and the flow back to customers of certain additional tax benefits. PSE&G anticipates the new base rates will go into effect in the fourth quarter of 2018.

Separately, in January 2018, the BPU issued an order commencing a proceeding to ensure that the rate revenue resulting from expenses relating to taxes reflected in rates but no longer owed as the result of the Tax Act shall be passed onto the ratepayers. The BPU directed New Jersey utilities (including PSE&G) to make filings by March 2, 2018 setting forth interim rates to be effective April 1, 2018 reflecting the new federal corporate tax rate, and to subsequently file proposed final rates, effective July 1, 2018, incorporating all other effects of the Tax Act. This proceeding is currently pending.


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

For the year ended December 31, 2017, PSE&G recorded an estimated true-up adjustment of $16 million to its 2017 Annual Formula rate. That true-up will be filed by no later than June 15, 2018.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In October 2017, the 2018 Annual Formula Rate Update was filed with FERC and requested approximately $212 million in increased annual transmission revenues effective January 1, 2018, subject to true-up. In January 2018, PSE&G filed with FERC a revised 2018 Annual Transmission Formula Rate Update reducing the 2018 transmission annual revenue requirement to reflect the federal corporate income tax rate reduction from 35% to 21%, effective January 1, 2018, provided in the Tax Act. This change in the federal corporate tax rate reduces the annual revenue requirement by $148 million. The revised increase in annual transmission revenues effective January 1, 2018 is $64 million.


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

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

In September 2017, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs placed in service from June 1, 2017 through November 30, 2017. The filing was updated in December 2017 requesting an annual increase in electric revenues of $8 million. This matter is pending.


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

In December 2017, the BPU approved PSE&G’s annual GSMP cost recovery petition, originally filed in July 2017, and updated in October 2017, to include GSMP investments in service as of September 30, 2017. The BPU approved an annual increase in gas revenues of $25 million, effective January 1, 2018.

•

BGSS—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase in the BGSS rate from approximately 34 cents to 37 cents per therm effective October 1, 2017. In September 2017, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was increased. In December 2017 and February 2018, PSE&G filed with the BPU for self-implementing monthly bill credits of 15 cents per therm for the months of January, February and March 2018. These monthly bill credits are estimated to provide approximately $100 million in customer credits. In November 2017, a filing was made by the Retail Energy Supply Association (RESA) with the BPU requesting that the BPU revisit the BGSS process and establish a gas capacity release program. This filing, which remains pending, is applicable to all New Jersey gas utilities.


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

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

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

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


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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In September 2017, the BPU approved on a provisional basis, PSE&G’s petition to collect $31 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period and a remaining carryover balance of $24 million in net deficiency gas revenues from the 2015-2016 Winter Period for a total recovery of $55 million in net deficiency revenues. The deficiency will be collected from customers over the 2017-2018 and 2018-2019 Winter Periods (October 1 through May 31). Final approval in this matter is pending.

•

Remediation Adjustment Charge (RAC)—In June 2017, the BPU approved PSE&G’s filing with respect to its RAC 24 petition allowing recovery of $41 million effective July 10, 2017 related to net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016. In February 2018, PSE&G filed a RAC 25 Petition with the BPU requesting recovery of $63 million of net Manufactured Gas Plant expenditures from August 1, 2016 through July 31, 2017. This matter is pending.

•

Universal Service Fund (USF)/Lifeline—In September 2017, the BPU approved rates set to recover state-wide costs incurred by New Jersey electric and gas distribution companies under the State’s USF/Lifeline energy assistance programs effective October 1, 2017. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on its Consolidated Statement of Operations.

Note 7. Long-Term Investments

Long-Term Investments as of December 31, 2017 and 2016 included the following:




	As of December 31,
	2017		2016
	Millions
PSE&G
Life Insurance and Supplemental Benefits	$	130	$	140
Solar Loans	150		159
Power
Partnerships and Corporate Joint Ventures (Equity Method Investments) (A)	87		102
Energy Holdings
Lease Investments	565		649
Total Long-Term Investments	$	932	$	1,050


(A)	During the three years ended December 31, 2017, 2016 and 2015, dividends from these investments were $18 million, $18 million and $16 million, respectively.

Leases

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 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 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 Consolidated Balance Sheets.

During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements, negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016, calculated by comparing the gross investment in the leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million charge for its best estimate of loss 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. For additional information, see Note 8. Financing Receivables.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

In June 2017, GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. REMA was not included in the GenOn filing. Energy Holdings continues to monitor the restructuring of GenOn and its possible impacts on REMA and continues to discuss the situation with various parties relevant to this matter. During the second quarter of 2017, Energy Holdings completed its review of estimated residual values embedded in its leveraged lease portfolio of generating assets and the outcome indicated that one of the residual value estimates was lower than the recorded residual value due to a further deterioration of market conditions and changes to operating cost estimates. This decline was determined to be other than temporary. As a result, a pre-tax write-down of $7 million was recorded in the quarter ended June 30, 2017. In addition, based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded an additional $15 million pre-tax charge in the quarter ended June 30, 2017 for its current best estimate of loss related to lease receivables. Pre-tax write-downs and additional charges are reflected in Operating Revenues and are included in Gross Investment in Leases as of December 31, 2017.

In January 2018, certain subsidiaries of Energy Holdings, REMA, certain holders of the pass-through certificates and other parties entered into a Forbearance Agreement (Forbearance) relating to the Conemaugh facility. Pursuant to the Forbearance, the parties thereto agreed to temporarily forbear from exercising rights and remedies related to certain events of default related to REMA’s obligation to procure additional qualifying credit support. The Forbearance will remain effective until the earlier of (i) the later of (a) April 15, 2018 and (b) two weeks following the date on which Energy Holdings subsidiaries, REMA and/or the consenting certificate holders provide written notice to REMA of its intention to terminate the Forbearance, and (ii) the date on which any event of termination as specified in the Forbearance occurs.

PSEG cannot predict the outcome of GenOn’s restructuring process or the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service (IRS).

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




	As of December 31,
	2017			2016
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	546		$	629
Estimated Residual Value of Leased Assets	326			346
Total Investment in Rental Receivables	872			975
Unearned and Deferred Income	(307		)	(326		)
Gross Investments in Leases	565			649
Deferred Tax Liabilities	(480		)	(674		)
Net Investments in Leases	$	85		$	(25	)

In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in Deferred Tax Liabilities. For additional information, see Note 20. Income Taxes.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The pre-tax income (loss) and income tax effects related to investments in leases, excluding gains and losses on sales and the impacts of the Tax Act, were as follows:




	Years Ended December 31,
	2017			2016			2015
	Millions
Pre-Tax Income (Loss) from Leases	$	(69	)	$	(135	)	$	12
Income Tax Expense (Benefit) on Income from Leases	$	(26	)	$	(51	)	$	5

Equity Method Investments

Power had the following equity method investments as of December 31, 2017 and 2016:




	As of December 31,
Name	2017		2016		Location	% Owned
	Millions
Power
Keystone Fuels, LLC	$	8	$	7	PA	23%
Conemaugh Fuels, LLC	8		8		PA	23%
PennEast Pipeline	—		11		PA	10%
Kalaeloa	71		76		HI	50%
Total	$	87	$	102

Note 8. 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. Interest income on the loans is recorded on an accrual basis. The loans are generally paid back with solar renewable energy certificates (SRECs) generated from the installed solar electric system. In the event of a loan default, the basis of the solar loan would be recovered through a regulatory recovery mechanism. None of the solar loans are impaired; however, in the event a loan becomes impaired, the basis of the loan would be recovered through a regulatory recovery mechanism.

The following table reflects the outstanding loans, including the noncurrent portion reported in Note 7. Long-Term Investments, by class of customer, none of which would be considered “non-performing.”




Outstanding Loans by Class of Customer
	As of December 31,
Consumer Loans	2017		2016
	Millions
Commercial/Industrial	$	158	$	164
Residential	10		11
Total	$	168	$	175

Energy Holdings

Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $85 million as of December 31, 2017 and $(25) million as of December 31, 2016 (See Note 7. Long-Term Investments).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The corresponding receivables associated with the lease portfolio are reflected as follows, 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 December 31, 2017	As of December 31, 2017
	Millions
AA	$	15
BBB+, BBB, BBB-	316
BB-	133
CCC-	82
Total	$	546

The “BB-” and the “CCC-” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2017, the gross investment in the leases of such assets, net of non-recourse debt, was $335 million, ($(67) million, net of deferred taxes). A more detailed description of such assets under lease is presented in the following table.




Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	132	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	85	64	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CCC-	REMA (A)
Conemaugh Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CCC-	REMA (A)
Shawville Station Units 1, 2, 3 and 4	PA	$	78	100	%	596	Gas	CCC-	REMA (A)

(A)

GenOn Energy Inc. (GenOn), and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. Certain subsidiaries of Energy Holdings, REMA, consenting holders of the pass-through certificates and other parties entered into a Forbearance relating to the Conemaugh facility. For additional information, see Note 7. Long-Term Investments.

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. 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.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9. Available-for-Sale Securities

NDT Fund

In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements.

Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective 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. Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8 billion and $3.0 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2017 was approximately $756 million and is included in the Asset Retirement Obligation. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power.

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




	As of December 31, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities
Domestic	$	405	$	245	$	(2	)	$	648
International	311		99		(3		)	407
Total Equity Securities	716		344		(5		)	1,055
Debt Securities
Government	586		2		(4		)	584
Corporate	400		4		(2		)	402
Total Debt Securities	986		6		(6		)	986
Other Securities	92		—		—			92
Total NDT Available-for-Sale Securities	$	1,794	$	350	$	(11	)	$	2,133




	As of December 31, 2016
	Cost		Gross Unrealized Gains			Gross Unrealized Losses			Fair Value
	Millions
Equity Securities
Domestic	$	439	$	214		$	(3	)	$	650
International	266		49		—	(8		)	307
Total 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 as of December 31, 2016, which is part of the NDT Fund.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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 Consolidated Balance Sheets as shown in the following table.




	As of December 31, 2017		As of December 31, 2016
	Millions
Accounts Receivable	$	24	$	8
Accounts Payable	$	74	$	5

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




	As of December 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)
Domestic	$	40	$	(2	)	$	—	$	—		$	51	$	(3	)	$	2	$	—
International	29		(3		)	2		—			69		(7		)	6		(1		)
Total Equity Securities	69		(5		)	2		—			120		(10		)	8		(1		)
Debt Securities
Government (B)	343		(2		)	91		(2		)	276		(6		)	4		—
Corporate (C)	191		(1		)	27		(1		)	139		(3		)	15		(1		)
Total Debt Securities	534		(3		)	118		(3		)	415		(9		)	19		(1		)
NDT Available-for-Sale Securities	$	603	$	(8	)	$	120	$	(3	)	$	535	$	(19	)	$	27	$	(2	)


(A)	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 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 before recovery 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 December 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 before recovery 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 December 31, 2017.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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




	Years Ended December 31,
	2017			2016			2015
	Millions
Proceeds from Sales (A)	$	2,137		$	711		$	1,397
Net Realized Gains (Losses):
Gross Realized Gains	$	157		$	53		$	97
Gross Realized Losses	(23		)	(32		)	(37		)
Net Realized Gains (Losses) on NDT Fund (B)	$	134		$	21		$	60


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


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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Consolidated Statements of Operations. Net unrealized gains of $175 million (after-tax) are included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Consolidated Balance Sheets as of December 31, 2017. Under 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), effective January 1, 2018. For additional information, see Note 2. Recent Accounting Standards.

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




Time Frame	Fair Value
	Millions
Less than one year	$	42
1 - 5 years	320
6 - 10 years	207
11 - 15 years	40
16 - 20 years	65
Over 20 years	312
Total NDT Available-for-Sale Debt Securities	$	986

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). In 2017, other-than-temporary impairments of $12 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 bases for the securities held in the Rabbi Trust.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	As of December 31, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities
Domestic	$	22	$	3	$	—		$	25
International	—		—		—			—
Total Equity Securities	$	22	$	3	$	—		$	25
Debt Securities
Government	85		1		(1		)	85
Corporate	118		2		(1		)	119
Total Debt Securities	203		3		(2		)	204
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	227	$	6	$	(2	)	$	231




	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities
Domestic	$	11	$	11	$	—		$	22
International	—		—		—			—
Total 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 Consolidated Balance Sheets as shown in the following table.




	As of December 31, 2017		As of December 31, 2016
	Millions
Accounts Receivable	$	2	$	5
Accounts Payable	$	1	$	3

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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




	As of December 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)
Domestic	$	—	$	—		$	—	$	—		$	—	$	—		$	—	$	—
International	—		—			—		—			—		—			—		—
Total Equity Securities	—		—			—		—			—		—			—		—
Debt Securities
Government (B)	28		—			25		(1		)	60		(2		)	1		—
Corporate (C)	39		(1		)	9		—			46		(2		)	3		—
Total Debt Securities	67		(1		)	34		(1		)	106		(4		)	4		—
Rabbi Trust Available-for-Sale Securities	$	67	$	(1	)	$	34	$	(1	)	$	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 before recovery 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 December 31, 2017.

(C)

Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities before recovery 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 December 31, 2017.

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




	Years Ended December 31,
	2017			2016			2015
	Millions
Proceeds from Rabbi Trust Sales (A)	$	182		$	113		$	104
Net Realized Gains (Losses):
Gross Realized Gains	$	17		$	6		$	3
Gross Realized Losses	(5		)	(5		)	(2		)
Net Realized Gains (Losses) on Rabbi Trust (B)	$	12		$	1		$	1


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


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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Gross realized gains and gross realized losses disclosed in the above table were recognized in Other Income and Other Deductions, respectively, in the Consolidated Statements of Operations. Net unrealized gains of $2 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets as of December 31, 2017. The Rabbi Trust available-for-sale debt securities held as of December 31, 2017 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	1
1 - 5 years	37
6 - 10 years	30
11 - 15 years	5
16 - 20 years	18
Over 20 years	113
Total Rabbi Trust Available-for-Sale Debt Securities	$	204

PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in 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). 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. In 2017, there were no other-than-temporary impairments recognized on investments of the Rabbi Trust. The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:




	As of December 31, 2017		As of December 31, 2016
	Millions
PSE&G	$	46	$	43
Power	57		53
Other	128		121
Total Rabbi Trust Available-for-Sale Securities	$	231	$	217

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10. Goodwill and Other Intangibles

As of December 31, 2017 and 2016, Power had goodwill of $16 million related to the Bethlehem Energy Center facility. Power conducted an annual review for goodwill impairment in the fourth quarter of 2017 and concluded that goodwill continues to remain unimpaired. In addition to goodwill, as of December 31, 2017 and 2016, Power had intangible assets of $114 million and $98 million, respectively, related to emissions allowances and renewable energy credits. Emissions allowances and renewable energy credits are recorded at cost and evaluated for impairment at least annually. Emissions expense includes impairments of emissions allowances and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded. The changes to Power’s intangible assets during 2016 and 2017 are presented in the following table:





	Emissions Allowances			Renewable Energy Credits			Total Other Intangibles
	Millions
Balance as of January 1, 2016	$	62		$	40		$	102
Retirements	(6		)	(94		)	(100		)
Purchases	—			99			99
Sales and Transfers, net	(1		)	(1		)	(2		)
Impairments	(1		)	—			(1		)
Balance as of December 31, 2016	$	54		$	44		$	98
Retirements	(7		)	(93		)	(100		)
Purchases	27			90			117
Sales and Transfers, net	—			(1		)	(1		)
Balance as of December 31, 2017	$	74		$	40		$	114

Note 11. Asset Retirement Obligations (AROs)

PSEG, PSE&G and Power recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists to remove or dispose of an asset or some component of an asset at retirement. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes regulatory assets or liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in Operation and Maintenance.

PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life.

Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 9. Available-for-Sale Securities. Power also identified conditional AROs primarily related to Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, ash ponds, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates.

Updated cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015. When assumptions are revised to calculate fair values of existing AROs, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The changes to the ARO liabilities for PSEG, PSE&G and Power during 2016 and 2017 are presented in the following table:




	PSEG			PSE&G			Power			Other
	Millions
ARO Liability as of January 1, 2016	$	679		$	218		$	457		$	4
Liabilities Settled	(13		)	(9		)	(4		)	—
Liabilities Incurred	25			2			23			—
Accretion Expense	26			—			26			—
Accretion Expense Deferred and Recovered in Rate Base (A)	12			12			—			—
Revision to Present Values of Estimated Cash Flows	(3		)	(10		)	9			(2		)
ARO Liability as of December 31, 2016	$	726		$	213		$	511		$	2
Liabilities Settled	(29		)	(8		)	(21		)	—
Liabilities Incurred	1			—			1			—
Accretion Expense	30			—			30			—
Accretion Expense Deferred and Recovered in Rate Base (A)	12			12			—			—
Revision to Present Values of Estimated Cash Flows	284			(5		)	289			—
ARO Liability as of December 31, 2017	$	1,024		$	212		$	810		$	2


(A)	Not reflected as expense in Consolidated Statements of Operations

During 2017, PSE&G recorded a reduction to its ARO liabilities primarily due to the impact of settlements and changes to cash flow estimates. These changes had no impact in PSE&G’s Consolidated Statement of Operations.

During 2017, Power recorded an increase to its ARO liabilities primarily due to a higher assumed probability of early retirement of its nuclear units of $276 million (See Note 3. Early Plant Retirements for additional information).

Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans

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. Eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described below.

PSEG, PSE&G and Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which had not been expensed.

For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations.

As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $48 million for the year ended December 31, 2017, 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.

Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2017 and 2016. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.




	Pension Benefits						Other Benefits
	2017			2016			2017			2016
	Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A)	$	5,772		$	5,522		$	1,754		$	1,612
Service Cost	114			109			17			17
Interest Cost	204			202			63			59
Actuarial (Gain) Loss	564			219			199			127
Gross Benefits Paid	(295		)	(282		)	(57		)	(57		)
Plan Amendments	—			2			—			(4		)
Benefit Obligation at End of Year (A)	$	6,359		$	5,772		$	1,976		$	1,754
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	5,193		$	5,039		$	420		$	374
Actual Return on Plan Assets	903			403			77			32
Employer Contributions	11			33			71			71
Gross Benefits Paid	(295		)	(282		)	(57		)	(57		)
Fair Value of Assets at End of Year	$	5,812		$	5,193		$	511		$	420
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(547	)	$	(579	)	$	(1,465	)	$	(1,334	)
Additional Amounts Recognized in the Consolidated Balance Sheets
Current Accrued Benefit Cost	(10		)	(11		)	(10		)	(10		)
Noncurrent Accrued Benefit Cost	(537		)	(568		)	(1,455		)	(1,324		)
Amounts Recognized	$	(547	)	$	(579	)	$	(1,465	)	$	(1,334	)
Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B)
Prior Service Cost	$	(46	)	$	(63	)	$	(3	)	$	(14	)
Net Actuarial Loss	1,721			1,763			629			523
Total	$	1,675		$	1,700		$	626		$	509


(A)	Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement.

(B)

Includes $683 million ($406 million, after-tax) and $679 million ($398 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2017 and 2016, respectively. Also includes Regulatory Assets of $1,485 million and Deferred Assets of $133 million as of December 31, 2017 and Regulatory Assets of $1,396 million and Deferred Assets of $134 million as of December 31, 2016.

The pension benefits table above provides information relating to the funded status of the qualified, nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2017, PSEG had funded approximately 91% of its projected benefit obligation. This percentage does not include $231 million of assets in the Rabbi Trust as of December 31, 2017 which were used partially to fund the nonqualified pension plans. As of December 31, 2017, the nonqualified pension plans included in the projected benefit obligation in the above table were $167 million. The fair values of the Rabbi Trust assets are included in Other Special Funds on the Consolidated Balance Sheets.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Accumulated Benefit Obligation

The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $6.1 billion as of December 31, 2017 and $5.6 billion as of December 31, 2016.

The following table provides the components of net periodic benefit cost for the years ended December 31, 2017, 2016 and 2015.




	Pension Benefits Years Ended December 31,									Other Benefits Years Ended December 31,
	2017			2016			2015			2017			2016			2015
	Millions
Components of Net Periodic Benefit Cost
Service Cost	$	114		$	109		$	123		$	17		$	17		22
Interest Cost	204			202			234			63			59			67
Expected Return on Plan Assets	(394		)	(394		)	(414		)	(34		)	(31		)	(31		)
Amortization of Net
Prior Service Credit	(18		)	(19		)	(19		)	(11		)	(14		)	(14		)
Actuarial Loss	97			158			150			51			40			43
Net Periodic Benefit Cost	$	3		$	56		$	74		$	86		$	71		$	87

Pension costs and OPEB costs for PSEG, PSE&G and Power are detailed as follows:




	Pension Benefits Years Ended December 31,							Other Benefits Years Ended December 31,
	2017			2016		2015		2017		2016		2015
	Millions
PSE&G	$	(4	)	$	29	$	40	$	54	$	43	$	55
Power	1			16		21		27		23		27
Other	6			11		13		5		5		5
Total Benefit Cost	$	3		$	56	$	74	$	86	$	71	$	87

The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:




	Pension						OPEB
	2017			2016			2017			2016
	Millions
Net Actuarial (Gain) Loss in Current Period	$	55		$	211		$	156		$	125
Amortization of Net Actuarial Gain (Loss)	(97		)	(158		)	(50		)	(40		)
Prior Service Cost (Credit) in current period	—			1			—			(3		)
Amortization of Prior Service Credit	18			19			11			14
Total	$	(24	)	$	73		$	117		$	96

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2018 are as follows:




	Pension Benefits			Other Benefits
	2018			2018
	Millions
Actuarial Loss	$	85		$	64
Prior Service Credit	$	(18	)	$	(1	)

The following assumptions were used to determine the benefit obligations and net periodic benefit costs:




	Pension Benefits						Other Benefits
	2017		2016		2015		2017			2016			2015
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	3.73	%	4.29	%	4.54	%	3.76		%	4.37		%	4.58		%
Rate of Compensation Increase	3.90	%	3.61	%	3.61	%	3.90		%	3.61		%	3.61		%
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount Rate	4.29	%	4.54	%	4.20	%	4.37		%	4.58		%	4.21		%
Service Cost Interest Rate	4.53	%	4.81	%	4.20	%	4.64		%	4.87		%	4.21		%
Interest Cost Interest Rate	3.63	%	3.75	%	4.20	%	3.69		%	3.76		%	4.21		%
Expected Return on Plan Assets	7.80	%	8.00	%	8.00	%	7.80		%	8.00		%	8.00		%
Rate of Compensation Increase	3.61	%	3.61	%	3.61	%	3.61		%	3.61		%	3.61		%
Assumed Health Care Cost Trend Rates as of December 31
Health Care Costs
Immediate Rate							7.93		%	7.55		%	7.75		%
Ultimate Rate							4.75		%	4.75		%	4.75		%
Year Ultimate Rate Reached							2026			2025			2025
							Millions
Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs
Total of Service Cost and Interest Cost							$	13		$	11		$	12
Postretirement Benefit Obligation							$	240		$	191		$	194
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs
Total of Service Cost and Interest Cost							$	(10	)	$	(9	)	$	(10	)
Postretirement Benefit Obligation							$	(198	)	$	(160	)	$	(160	)

Plan Assets

The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2017, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 92% and 8%, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2017 and 2016, including the fair value measurements and the levels of inputs used in determining those fair values.




	Recurring Fair Value Measurements as of December 31, 2017
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Cash Equivalents (A)	$	133	$	117	$	16	$	—
Equity Securities
Common Stock (B)	1,275		1,275		—		—
Commingled (C)	1,401		1,218		183		—
Preferred Stock (B)	6		6		—		—
Debt Securities (D)
U.S. Treasury	571		—		571		—
Government—Other	272		—		272		—
Corporate	963		—		963		—
Subtotal Fair Value	$	4,621	$	2,616	$	2,005	$	—
Measured at net asset value practical expedient
Commingled—Equities (E)	1,675
Private Equity (F)	14
Total Fair Value (G)	$	6,310




	Recurring Fair Value Measurements as of December 31, 2016
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Cash Equivalents (A)	$	107	$	105	$	2	$	—
Equity Securities
Common Stock (B)	944		944		—		—
Commingled (C)	1,387		1,247		140		—
Preferred Stock (B)	1		1		—		—
Debt Securities (D)
U.S. Treasury	441		—		441		—
Government—Other	263		—		263		—
Corporate	836		—		836		—
Subtotal Fair Value	$	3,979	$	2,297	$	1,682	$	—
Measured at net asset value practical expedient
Commingled—Equities (E)	1,604
Private Equity (F)	16
Total Fair Value (G)	$	5,599

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(A)	The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2).


(B)	Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1.


(C)	Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2.

(D)

Debt securities include mainly investment grade corporate and municipal bonds, US Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach 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 or the most recent quoted for similar securities which are a Level 2 measure.

(E)

In 2016, as part of the implementation of the accounting guidance on investments measured at fair value using NAV as a practical expedient, certain commingled equity funds have been removed from the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from five to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index.

(F)

Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-US distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments have been removed from the fair value hierarchy in accordance with the guidance on NAV practical expedient.


(G)	Excludes net receivable of $13 million and $14 million at December 31, 2017 and 2016, respectively, which consists of interest, dividends and receivables and payables related to pending securities sales and purchases.

The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31:




	As of December 31,
Investments	2017		2016
Equity Securities	69	%	70	%
Debt Securities	29		28
Other Investments	2		2
Total Percentage	100	%	100	%

PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 7.8% for 2017 and will be 7.8% for 2018. This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception.

Plan Contributions

PSEG has no planned contributions to its pension plans in 2018. PSEG plans to make discretionary contributions of $14 million into its OPEB plan during 2018.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Estimated Future Benefit Payments

The following pension benefit and postretirement benefit payments are expected to be paid to plan participants.




Year	Pension Benefits		Other Benefits
	Millions
2018	$	337	$	88
2019	331		92
2020	341		96
2021	352		101
2022	364		105
2023-2027	1,954		560
Total	$	3,679	$	1,042

401(k) Plans

PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act (ERISA) defined contribution retirement plans. Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants.

The amount paid for employer matching contributions to the plans for PSEG, PSE&G and Power are detailed as follows:




	Thrift Plan and Savings Plan
	Years Ended December 31,
	2017		2016		2015
	Millions
PSE&G	$	25	$	24	$	22
Power	11		12		12
Other	5		5		5
Total Employer Matching Contributions	$	41	$	41	$	39

Servco Pension and OPEB

At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco’s employees had worked under NGES’ T&D operations services arrangement with LIPA, Servco’s plans provide certain of those employees with pension and OPEB vested credit for prior years’ services earned while working for NGES. The benefit plans cover all employees of Servco for current service. 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 Consolidated Balance Sheet of PSEG.

The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2017 and 2016. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Pension Benefits						Other Benefits
	2017			2016			2017			2016
				Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year	$	262		$	211		$	452		$	375
Service Cost	27			24			15			12
Interest Cost	11			9			19			17
Actuarial (Gain) Loss	22			14			60			50
Gross Benefits Paid	(2		)	(1		)	(4		)	(2		)
Plan Amendments	—			5			—			—
Benefit Obligation at End of Year (A)	$	320		$	262		$	542		$	452
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	134		$	97		$	—		$	—
Actual Return on Plan Assets	24			10			—			—
Employer Contributions	35			28			4			2
Gross Benefits Paid	(2		)	(1		)	(4		)	(2		)
Fair Value of Assets at End of Year	$	191		$	134		$	—		$	—
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(129	)	$	(128	)	$	(542	)	$	(452	)
Additional Amounts Recognized in the Consolidated Balance Sheets
Accrued Pension Costs of Servco	$	(129	)	$	(128	)	N/A			N/A
OPEB Costs of Servco	N/A			N/A			(542		)	(452		)
Amounts Recognized (B)	$	(129	)	$	(128	)	$	(542	)	$	(452	)


(A)	Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement.


(B)	Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets.

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. The pension-related revenues and costs for 2017, 2016 and 2015 were $35 million, $28 million and $30 million, respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2017. The OPEB-related revenues earned and costs incurred were $4 million and $2 million in 2017 and 2016, respectively, and immaterial for 2015.

The following assumptions were used to determine the benefit obligations of Servco:




	Pension Benefits						Other Benefits
	2017		2016		2015		2017			2016			2015
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	3.90	%	4.61	%	4.92	%	3.96		%	4.71		%	4.97		%
Rate of Compensation Increase	3.25	%	3.25	%	3.25	%	3.25		%	3.25		%	3.25		%
Assumed Health Care Cost Trend Rates as of December 31
Health Care Costs
Immediate Rate							7.69		%	7.55		%	7.55		%
Ultimate Rate							4.75		%	4.75		%	4.75		%
Year Ultimate Rate Reached							2026			2025			2025
							Millions
Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs
Postretirement Benefit Obligation							$	131		$	97		$	75
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs
Postretirement Benefit Obligation							$	(99	)	$	(75	)	$	(60	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Plan Assets

All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. The Actuary maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans.

The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2017 and 2016, including the fair value measurements and the levels of inputs used in determining those fair values.




	Recurring Fair Value Measurements as of December 31, 2017
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Commingled Equities (A)	$	137	$	—	$	137	$	—
Commingled Bonds (A)	54		—		54		—
Total	$	191	$	—	$	191	$	—




	Recurring Fair Value Measurements as of December 31, 2016
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Commingled Equities (A)	$	96	$	—	$	96	$	—
Commingled Bonds (A)	38		—		38		—
Total	$	134	$	—	$	134	$	—


(A)	Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2).

The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31:




	As of December 31,
Investments	2017		2016
Equity Securities	72	%	71	%
Debt Securities	28		29
Total Percentage	100	%	100	%

Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. The results from Servco’s latest asset/liability study indicated that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. The expected long-term rate of return on plan assets was 7.6% for 2017 and will be 7.6% for 2018. This expected return was determined based on the study discussed above, including a premium for active management.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Plan Contributions

Servco plans to contribute $40 million into its pension plan during 2018.

Estimated Future Benefit Payments

The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants:




Year	Pension Benefits		Other Benefits
	Millions
2018	$	3	$	4
2019	4		6
2020	5		8
2021	7		9
2022	9		12
2023-2027	78		87
Total	$	106	$	126

Servco 401(k) Plans

Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the Plans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any Catch-Up Contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amounts expensed by Servco for employer matching contributions for the years ended December 31, 2017, 2016 and 2015 were $6 million, $5 million and $4 million, respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.

Note 13. Commitments and Contingent Liabilities

Guaranteed Obligations

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

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


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


•	obtain credit.

Power is subject to


•	counterparty collateral calls related to commodity contracts, and


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

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

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


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


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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 December 31, 2017 and 2016.




	As of December 31, 2017			As of December 31, 2016
	Millions
Face Value of Outstanding Guarantees	$	1,701		$	1,806
Exposure under Current Guarantees	$	153		$	139

Letters of Credit Margin Posted	$	103		$	157
Letters of Credit Margin Received	$	32		$	99

Cash Deposited and Received
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(1	)	$	(1	)
Net Broker Balance Deposited (Received)	$	147		$	57

Additional Amounts Posted
Other Letters of Credit	$	61		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 16. 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. In June 2017, Power sold its minority interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s payment obligations related to PennEast was terminated.

Environmental Matters

Passaic River

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

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

The U.S. Environmental Protection Agency (EPA) has determined that a 17-mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA and a comprehensive study of the entire 17 miles of the lower Passaic River needed to be performed. 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In early 2007, certain 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. The CPG has 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 7.6 percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately 1.9 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. Certain PRPs are currently involved in discussions with the EPA regarding cost allocations and related indemnification matters. We cannot predict the outcome of these discussions, or whether individual PRPs will be able to meet their obligations, either of which could have a material impact on PSE&G’s and Power’s allocation of costs.

The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River with an estimated cost to remediate the lower 17 miles of the Passaic River ranging from approximately $518 million to $3.2 billion on an undiscounted basis.

In March 2016, the EPA released its Record of Decision (ROD) for the EPA’s own Focused Feasibility Study (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 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. Occidental Chemical Corporation, one of the PRPs, has committed to perform the remedial design required by the ROD Remedy, reserving its right of cost contribution from all other PRPs.

In September 2017, the EPA concluded that an Agency-commenced allocation process for the Passaic River’s lower 8.3 miles should include only certain PRPs. The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform the remedial action under EPA oversight. Discussions on the matter are ongoing. Conversations between the EPA and the PRPs regarding remediation of the Passaic River’s upper 9 miles are ongoing.

Based upon (i) the estimated cost of the ROD Remedy, (ii) PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and (iii) the continued ability of PSE&G to recover such costs in its rates, as of December 31, 2017, PSEG has accrued approximately $57 million. Of this amount $46 million has been accrued by PSE&G as an Environmental Costs Liability and a corresponding Regulatory Asset and $11 million has been accrued by Power as an Other Noncurrent Liability with the corresponding O&M Expense recorded in the periods when the liability was accrued.

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

Natural Resource Damage Claims

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

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $358 million and $403 million on an undiscounted basis through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $358 million as of December 31, 2017. Of this amount, $79 million was recorded in Other Current Liabilities and $279 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $358 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding to what extent sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.

Clean Water Act (CWA) 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 cooling water intake rule that establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

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, based on studies related to impingement mortality and entrainment and submit the results with their permit applications to be conducted by the facilities seeking renewal permits.

Several environmental organizations and certain energy industry groups have filed suit under the Clean Water Act and the Endangered Species Act. The cases have been consolidated at the Second Circuit and a decision remains pending.

In June 2016, the NJDEP issued a final NJPDES permit for Salem. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. The final permit does not mandate specific service water system modifications but, 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 NJPDES renewal permit for Salem. NJDEP has granted the hearing request, but it has not yet been scheduled. 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 CWA. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.

State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intakes 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 Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s CWA Section 316(b) final rule, Power has proposed to continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit.

Power has 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 of its conditions precedent occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

site that BH3 currently operates. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life.

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council (CSC) issued an order to approve siting Bridgeport Harbor Station unit 5 (BH5). All major environmental permits have been received; however, secondary approvals are still being obtained to allow operations to begin in mid-2019. Power’s obligations under the CEBA are being monitored regularly and carried out as needed.

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

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

Jersey City, New Jersey Subsurface Feeder Cable Matter

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

Steam Electric Effluent Guidelines

In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under the ELG Rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the ELG Rule.

Through various orders, the EPA has stayed the compliance dates in the ELG Rule and has announced plans to further revise the requirements and compliance dates of the ELG Rule. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

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

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

The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2018 is $287.76 per MW-

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

day, replacing the BGS-CIEP auction year price ending May 31, 2018 of $276.83 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

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




	Auction Year
	2015	2016	2017	2018
36-Month Terms Ending	May 2018	May 2019	May 2020	May 2021	(A)
Load (MW)	2,900	2,800	2,800	2,900
$ per MWh	$99.54	$96.38	$90.78	$91.77


(A)	Prices set in the 2018 BGS auction will become effective on June 1, 2018 when the 2015 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 24. Related-Party Transactions.

Minimum Fuel Purchase Requirements

Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2020 and a significant portion through 2022 at Salem, Hope Creek and Peach Bottom.

Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G’s customers, Power can use the gas to supply its fossil generating stations.

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

As of December 31, 2017, the total minimum purchase requirements included in these commitments were as follows:




Fuel Type	Power's Share of Commitments through 2022
	Millions
Nuclear Fuel
Uranium	$	240
Enrichment	$	391
Fabrication	$	170
Natural Gas	$	1,042
Coal	$	293

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Proceedings

FERC Compliance

PJM Bidding Matter

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

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

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

Other Litigation and Legal Proceedings

PSEG and its subsidiaries are party to various lawsuits in the ordinary course of business. In view of the inherent difficulty in predicting the outcome of such matters, PSEG, PSE&G and Power generally cannot predict the eventual outcome of the pending matters, the timing of the ultimate resolution of these matters, or the eventual loss, fines or penalties related to each pending matter.

In accordance with applicable accounting guidance, a liability is accrued when those matters present loss contingencies that are both probable and reasonably estimable. In such cases, there may be an exposure to loss in excess of any amounts accrued. PSEG will continue to monitor the matter for further developments that could affect the amount of the accrued liability that has been previously established.

Based on current knowledge, management does not believe that loss contingencies arising from pending matters, other than the matters described herein, could have a material adverse effect on PSEG’s, PSE&G’s or Power’s consolidated financial position or liquidity. However, in light of the inherent uncertainties involved in these matters, some of which are beyond PSEG’s control, and the large or indeterminate damages sought in some of these matters, an adverse outcome in one or more of these matters could be material to PSEG’s, PSE&G’s or Power’s results of operations or liquidity for any particular reporting period.

Nuclear Insurance Coverages and Assessments

Power is a member of the joint underwriting association, American Nuclear Insurers (ANI), which provides nuclear liability insurance coverage at the Salem and Hope Creek site and the Peach Bottom site. The ANI policies are designed to satisfy the financial protection requirements outlined in the Price-Anderson Act, which sets the limit of liability for claims that could arise from an incident involving any licensed nuclear facility in the United States. The limit of liability per incident per site is composed of primary and excess layers. As of December 31, 2017, nuclear sites were required to purchase $450 million of primary liability coverage for each site (through ANI). The primary layer is supplemented by an excess layer, which is an industry self-insurance pool. In the event a nuclear site, which is part of the industry self-insurance pool, has a claim that exceeds the primary layer, each licensee would be assessed a prorated share of the excess layer. The excess layer limit is $13.4 billion. Power’s maximum aggregate assessment per incident is $401 million (based on Power’s ownership interests in Salem, Hope Creek and Peach Bottom) and its maximum aggregate annual assessment per incident is $60 million. If the damages exceed the limit of liability, Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Further, a decision by the U.S. Supreme Court, not involving Power, held that the Price-Anderson Act did not preclude punitive damage awards based on state law claims.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Power is also a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the property, decontamination and decommissioning liability insurance at the Salem and Hope Creek site and the Peach Bottom site. NEIL also provides replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in the case of adverse loss experience. The current maximum aggregate annual retrospective premium obligation for Power is approximately $76 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.

The ANI and NEIL policies all include coverage for claims arising out of acts of terrorism. However, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus such additional amounts as NEIL recovers for such losses from reinsurance, indemnity and any other source applicable to such losses.

Minimum Lease Payments

The total future minimum payments under various operating leases as of December 31, 2017 are:




	PSE&G		Power		Services		Other		Total
	Millions
2018	$	16	$	5	$	14	$	1	$	36
2019	9		6		15		1		31
2020	8		3		15		1		27
2021	8		3		15		1		27
2022	7		3		15		1		26
Thereafter	65		38		120		1		224
Total Minimum Lease Payments	$	113	$	58	$	194	$	6	$	371

Note 14. Debt and Credit Facilities

Long-Term Debt




		As of December 31,
	Maturity	2017			2016
		Millions
PSEG
Term Loan:
Variable	2017	$	—		$	500
Variable	2019	700			—
Total Term Loan		700			500
Senior Notes:
1.60%	2019	400			400
2.00%	2021	300			300
2.65%	2022	700			—
Total Senior Notes		1,400			700
Principal Amount Outstanding		2,100			1,200
Amounts Due Within One Year		—			(500		)
Net Unamortized Discount and Debt Issuance Costs		(9		)	(5		)
Total Long-Term Debt of PSEG		$	2,091		$	695

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




		As of December 31,
	Maturity	2017			2016
		Millions
PSE&G
First and Refunding Mortgage Bonds (A):
9.25%	2021	$	134		$	134
8.00%	2037	7			7
5.00%	2037	8			8
Total First and Refunding Mortgage Bonds		149			149
Medium-Term Notes (MTNs) (A):
5.30%	2018	400			400
2.30%	2018	350			350
1.80%	2019	250			250
2.00%	2019	250			250
7.04%	2020	9			9
3.50%	2020	250			250
1.90%	2021	300			300
2.38%	2023	500			500
3.75%	2024	250			250
3.15%	2024	250			250
3.05%	2024	250			250
3.00%	2025	350			350
2.25%	2026	425			425
3.00%	2027	425			—
5.25%	2035	250			250
5.70%	2036	250			250
5.80%	2037	350			350
5.38%	2039	250			250
5.50%	2040	300			300
3.95%	2042	450			450
3.65%	2042	350			350
3.80%	2043	400			400
4.00%	2044	250			250
4.05%	2045	250			250
4.15%	2045	250			250
3.80%	2046	550			550
3.60%	2047	350			—
Total MTNs		8,509			7,734
Principal Amount Outstanding		8,658			7,883
Amounts Due Within One Year		(750		)	—
Net Unamortized Discount and Debt Issuance Costs		(67		)	(65		)
Total Long-Term Debt of PSE&G		$	7,841		$	7,818

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




		As of December 31,
	Maturity	2017			2016
		Millions
Power
Senior Notes:
2.45%	2018	$	250		$	250
5.13%	2020	406			406
4.15%	2021	250			250
3.00%	2021	700			700
4.30%	2023	250			250
8.63%	2031	500			500
Total Senior Notes		2,356			2,356
Pollution Control Notes:
Floating Rate (B)	2019	44			44
Total Pollution Control Notes		44			44
Principal Amount Outstanding		2,400			2,400
Amounts Due Within One Year		(250		)	—
Net Unamortized Discount and Debt Issuance Costs		(14		)	(18		)
Total Long-Term Debt of Power		$	2,136		$	2,382


(A)	Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.


(B)	The Pennsylvania Economic Development Authority (PEDFA) bond that is serviced and secured by Power Pollution Control Notes, is a variable rate bond that is in weekly reset mode.

Long-Term Debt Maturities

The aggregate principal amounts of maturities for each of the five years following December 31, 2017 are as follows:




Year	PSEG		PSE&G		Power		Total

2018	$	—	$	750	$	250	$	1,000
2019	1,100		500		44		1,644
2020	—		259		406		665
2021	300		434		950		1,684
2022	700		—		—		700
Thereafter	—		6,715		750		7,465
Total	$	2,100	$	8,658	$	2,400	$	13,158

Long-Term Debt Financing Transactions

During 2017, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:

PSEG


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


•	issued $700 million of 2.65% Senior Notes due November 2022, and


•	redeemed at maturity a $500 million term loan at an interest rate of 1 month LIBOR + 0.875% due November 2017.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PSE&G


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


•	issued $350 million of 3.60% Secured Medium-Term Notes, Series L due December 2047.

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.

The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2017, the total available credit capacity was $3.5 billion.

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

As of December 31, 2017, the total credit capacity was in excess of the anticipated maximum liquidity requirements over PSEG’s 12-month planning horizon.

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 our subsidiaries’ liquidity needs.

The total credit facilities and available liquidity as of December 31, 2017 were as follows:




	As of December 31, 2017
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	556	$	944	Mar 2022	Commercial Paper Support/Funding/Letters of Credit (LC)
Total PSEG	$	1,500	$	556	$	944
PSE&G
5-year Credit Facility (A)	$	600	$	15	$	585	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	15	$	585
Power
3-year LC Facilities	$	200	$	112	$	88	Mar 2020	Letters of Credit
5-year Credit Facilities	1,900		39		1,861		Mar 2022	Funding/Letters of Credit
Total Power	$	2,100	$	151	$	1,949
Total	$	4,200	$	722	$	3,478


(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 December 31, 2017, PSEG had $542 million outstanding at a weighted average interest rate of 1.89%. PSE&G had no amounts outstanding under its Commercial Paper Program as of December 31, 2017.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value of Debt

The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 2017 and 2016 are included in the following table and accompanying notes as of December 31, 2017 and 2016. See Note 17. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels.




	December 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (A) (B)	$	2,091	$	2,081	$	1,195	$	1,185
PSE&G (B)	8,591		9,322		7,818		8,240
Power (B)	2,386		2,659		2,382		2,578
	$	13,068	$	14,062	$	11,395	$	12,003


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

(B)

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

Note 15. Schedule of Consolidated Capital Stock




	As of December 31,
	Outstanding Shares		Book Value
	2017	2016	2017		2016
	Millions
PSEG Common Stock (no par value) (A)
Authorized 1,000 shares	505	505	$	4,198	$	4,219


(A)	PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2017 or 2016.

As of December 31, 2017, PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16. 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 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. Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 13. Commitments and Contingent Liabilities. Changes in the fair market value of these derivative contracts are recorded in earnings.

Interest Rates

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

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of December 31, 2017 or 2016. The fair value hedges reduced interest expense by $6 million and $19 million for the years ended December 31, 2016 and 2015, respectively.

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. There were no outstanding interest rate hedges as of December 31, 2017. As of December 31, 2016, PSEG had interest rate hedges outstanding totaling $500 million. These hedges converted PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. As of December 31, 2016, the fair value of these hedges was $1 million and there was no ineffectiveness. The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was immaterial as of December 31, 2017 and $2 million as of December 31, 2016. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months is immaterial.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the 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 Consolidated Balance Sheets of Power and PSEG. For additional information see Note 17. Fair Value Measurements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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




	As of December 31, 2017
	Power (A)										PSE&G (A)		PSEG (A)		Consolidated
		Not Designated									Not Designated		Cash Flow Hedges
Balance Sheet Location		Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts		Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets		$	391		$	(362	)	$	29		$	—	$	—	$	29
Noncurrent Assets		78			(71		)	7			—		—		7
Total Mark-to-Market Derivative Assets		$	469		$	(433	)	$	36		$	—	$	—	$	36
Derivative Contracts
Current Liabilities		$	(403	)	$	387		$	(16	)	$	—	$	—	$	(16	)
Noncurrent Liabilities		(95		)	90			(5		)	—		—		(5		)
Total Mark-to-Market Derivative (Liabilities)		$	(498	)	$	477		$	(21	)	$	—	$	—	$	(21	)
Total Net Mark-to-Market Derivative Assets (Liabilities)		$	(29	)	$	44		$	15		$	—	$	—	$	15




	As of December 31, 2016
	Power (A)										PSE&G (A)			PSEG (A)		Consolidated
		Not Designated									Not Designated			Fair Value 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 December 31, 2017 and 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

(B)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

respectively. Of these net cash collateral/margin payments, $44 million as of December 31, 2017 and $1 million as of December 31, 2016 were netted against the corresponding net derivative contract positions. Of the $44 million as of December 31, 2017, $(3) million was netted against current assets, $28 million was netted against current liabilities and $19 million was netted against noncurrent liabilities. 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 $30 million and $19 million as of December 31, 2017 and 2016, respectively. As of December 31, 2017 and 2016, Power had the contractual right of offset of $13 million and $9 million, respectively, related to derivative instruments that are assets with the same counterparty under master 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 $17 million and $10 million as of December 31, 2017 and 2016, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.

The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the years ended December 31, 2017, 2016 and 2015.




		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)
Derivatives in Cash Flow Hedging Relationships	Years Ended December 31,								Years Ended December 31,
		2017		2016		2015				2017		2016		2015
		Millions								Millions
PSEG
Energy-Related Contracts		$	—	$	—	$	3	Operating Revenues		$	—	$	—	$	20
Interest Rate Swaps		—		3		—		Interest Expense		3		—		—
Total PSEG		$	—	$	3	$	3			$	3	$	—	$	20
Power
Energy-Related Contracts		$	—	$	—	$	3	Operating Revenues		$	—	$	—	$	20
Total Power		$	—	$	—	$	3			$	—	$	—	$	20

There were no pre-tax gain (loss) recognized in income on derivatives (ineffective portion) as of December 31, 2017, 2016 and 2015.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	(3		)	(2		)
Balance as of December 31, 2017	$	—		$	—

The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2017, 2016 and 2015. 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 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
		Years Ended December 31,
		2017			2016			2015
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	72		$	230		$	412
Energy-Related Contracts	Energy Costs	(17		)	(8		)	(8		)
Total PSEG and Power		$	55		$	222		$	404

The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 2017 and 2016.




Type	Notional	Total		PSEG	Power		PSE&G
	Millions
As of December 31, 2017
Natural Gas	Dth	154		—	154		—
Electricity	MWh	(63	)	—	(63	)	—
Financial Transmission Rights (FTRs)	MWh	6		—	6		—
As of December 31, 2016
Natural Gas	Dth	122		—	113		9
Electricity	MWh	(44	)	—	(44	)	—
FTRs	MWh	9		—	9		—
Interest Rate Swaps	U.S. Dollars	500		500	—		—

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 December 31, 2017, 99% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).

The following table provides information on Power’s credit risk from others, net of collateral, as of December 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	$	329	$	25	$	304	1	$	204	(A)
Non-Investment Grade	3		1		2		—	—
Total	$	332	$	26	$	306	1	$	204


(A)	Represents net exposure with PSE&G.

As of December 31, 2017, collateral held from counterparties where Power had credit exposure included $1 million in cash collateral and $25 million in letters of credit.

As of December 31, 2017, Power had 152 active counterparties.

PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 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 December 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17. 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 December 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 December 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Recurring Fair Value Measurements as of December 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)	$	223		$	—		$	223		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	36		$	(433	)	$	15		$	442		$	12
NDT Fund (D)
Equity Securities	$	1,055		$	—		$	1,053		$	2		$	—
Debt Securities—U.S. Treasury	$	314		$	—		$	—		$	314		$	—
Debt Securities—Govt Other	$	270		$	—		$	—		$	270		$	—
Debt Securities—Corporate	$	402		$	—		$	—		$	402		$	—
Other Securities	$	92		$	—		$	92		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	25		$	—		$	25		$	—		$	—
Debt Securities—U.S. Treasury	$	51		$	—		$	—		$	51		$	—
Debt Securities—Govt Other	$	34		$	—		$	—		$	34		$	—
Debt Securities—Corporate	$	119		$	—		$	—		$	119		$	—
Other Securities	$	2		$	—		$	2		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(21	)	$	477		$	(8	)	$	(485	)	$	(5	)
PSE&G
Assets:
Cash Equivalents (A)	$	223		$	—		$	223		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—U.S. Treasury	$	10		$	—		$	—		$	10		$	—
Debt Securities—Govt Other	$	7		$	—		$	—		$	7		$	—
Debt Securities—Corporate	$	24		$	—		$	—		$	24		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	36		$	(433	)	$	15		$	442		$	12
NDT Fund (D)
Equity Securities	$	1,055		$	—		$	1,053		$	2		$	—
Debt Securities—U.S. Treasury	$	314		$	—		$	—		$	314		$	—
Debt Securities—Govt Other	$	270		$	—		$	—		$	270		$	—
Debt Securities—Corporate	$	402		$	—		$	—		$	402		$	—
Other Securities	$	92		$	—		$	92		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	6		$	—		$	6		$	—		$	—
Debt Securities—U.S. Treasury	$	13		$	—		$	—		$	13		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	30		$	—		$	—		$	30		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(21	)	$	477		$	(8	)	$	(485	)	$	(5	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




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


(A)	Represents money market mutual funds.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(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 similar assets and liabilities from an exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

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


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

(D)

As of December 31, 2016, the fair value measurement table excludes cash of $1 million, 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 December 31, 2017. The Rabbi Trust maintained investments in an 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. Other Securities in the NDT and Rabbi Trust Funds consist primarily of investments in Dreyfus money market funds which seek a high level of current income as is consistent with the preservation of capital and the maintenance of liquidity. To pursue its goals, the fund normally invests in a diversified portfolio of high quality, short-term, dollar-denominated debt securities and government securities. The funds’ Net Asset Value is priced and published daily. 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 U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(E)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Consolidated Balance Sheets. As of December 31, 2017 and 2016, Power had net cash collateral/margin payments to counterparties of $146 million and $56 million, respectively. Of these net cash collateral/margin payments $44 million as of December 31, 2017 and $1 million as of December 31, 2016 were netted against the corresponding net derivative contract positions. Of the $44 million of cash collateral as of December 31, 2017, $(3) million was netted against assets, and $47 million was netted against liabilities. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets and $4 million was netted against liabilities.

Additional Information Regarding Level 3 Measurements

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

For PSE&G, the natural gas supply contract 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 fair value of Power’s gas physical contracts at certain illiquid delivery locations are measured using average historical basis and, accordingly, are categorized as Level 3. While these gas physical contracts have an unobservable component in their respective forward price curves, the fluctuations in fair value have been driven primarily by changes in the observable inputs. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2017 and 2016.




	Quantitative Information About Level 3 Fair Value Measurements
Commodity	Level 3 Position	Fair Value as of December 31, 2017					Valuation Technique(s)	Significant Unobservable Input	Range

		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Load Contracts	$	1	$	(3	)	Discounted Cash flow	Historic Load Variability	0% to +10%
Gas	Gas Physical Contracts	11		(2		)	Discounted Cash flow	Average Historical Basis	-40% to -10%
Total Power		$	12	$	(5	)
Total PSEG		$	12	$	(5	)




	Quantitative Information About Level 3 Fair Value Measurements
Commodity	Level 3 Position	Fair Value as of December 31, 2016					Valuation Technique(s)	Significant Unobservable Input	Range

		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	—	$	(5	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(5	)
Power
Electricity	Electric Load Contracts	$	7	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	7	$	(1	)
Total PSEG		$	7	$	(6	)


(A)	Includes gas positions which were immaterial.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

decrease the fair value. For gas-related contracts in cases where Power is a buyer, an increase in the average historical basis would increase the fair value.

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

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

for the Year Ended December 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 December 31, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	26	$	5	$	—	$	(24	)	$	(1	)	$	7
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	—	$	5	$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	6		$	26	$	—	$	—	$	(24	)	$	(1	)	$	7

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

for the Year Ended December 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		Balance as of December 31, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	13	$	13	$	(7	)	$	3	$	(21	)	$	—	$	1
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(7	)	$	—	$	—		$	—	$	(5	)
Power
Net Derivative Assets (Liabilities)	$	11	$	13	$	—		$	3	$	(21	)	$	—	$	6


(A)	PSEG’s and Power’s gains(losses) attributable to changes in net derivative assets and liabilities for 2017 include $14 million in Operating Revenues, of which $(9) million is unrealized and $12 million in Energy Costs, all of which is unrealized. For 2016, $25 million is included in Operating Revenues, of which $(5) million is unrealized, and $(12)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

million is in Energy Costs, all of which 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 $(24) million and $(21) million in settlements for derivative contracts in 2017 and 2016, respectively.


(D)	During the year ended December 31, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3.

As of December 31, 2017, PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of December 31, 2016, PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $1 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Note 18. Stock Based Compensation

PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee.

The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2017, there were approximately 14 million shares available for future awards under the LTIP.

Stock Options

Under the LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been issued since 2009.

Restricted Stock Units

Under the LTIP, PSEG has granted restricted stock unit awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unit grants for 2017 and 2016 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as retirement, disability, change-in-control or death.

Performance Share Units

Under the LTIP, PSEG has granted performance share units to officers and other key employees. These provide for payment in shares of PSEG common stock based on achievement of certain financial goals over a three-year performance period. Following the end of the performance period, the payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The performance share units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control (unless substituted with an equity award of equal value), retirement, death or disability.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-Based Compensation

PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.

PSEG recognizes compensation expense for restricted stock units over the vesting period based on the grant date fair value of the shares, which is equal to the market price of PSEG’s common stock on the date of the grant.

PSEG recognizes compensation expense for the total shareholder return target for its performance share unit awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its performance share units based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome.




	2017		2016		2015
	Millions
Compensation Cost included in Operation and Maintenance Expense	$	31	$	29	$	34
Income Tax Benefit Recognized in Consolidated Statement of Operations	$	13	$	12	$	14

For 2017, 2016 and 2015 the excess tax benefit of $4 million, $4 million and $3 million, respectively was included as financing cash flows on the Consolidated Statements of Cash Flow.

PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests.

Stock Options

Changes in stock options for 2017 are summarized as follows:




	Options	Weighted Average Exercise Price		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Outstanding as of January 1, 2017	1,029,900	$	37.93
Exercised	654,200	$	40.02
Canceled/Forfeited	27,800	$	44.44
Outstanding as of December 31, 2017	347,900	$	33.49	1.9	$	6,265,679
Exercisable at December 31, 2017	347,900	$	33.49	1.9	$	6,265,679

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no option grants in 2017, 2016 and 2015.

Activity for options exercised for the years ended December 31, 2017, 2016 and 2015 is shown below:




	2017		2016		2015
	Millions
Total Intrinsic Value of Options Exercised	$	5	$	7	$	3
Cash Received from Options Exercised	$	26	$	22	$	12
Tax Benefit Realized from Options Exercised	$	—	$	1	$	—

No options were vested during the years ended December 31, 2017, 2016 and 2015.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Restricted Stock Units

Changes in restricted stock units for the year ended December 31, 2017 are summarized as follows:




	Shares	Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Non-vested as of January 1, 2017	322,196	$	38.75
Granted	212,158	$	44.33
Vested	303,092	$	39.96
Canceled/Forfeited	17,363	$	41.76
Non-vested as of December 31, 2017	213,899	$	42.32	1.0	$	11,015,850

The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2017, 2016 and 2015 was $44.33, $42.28 and $39.65 per share, respectively.

The total intrinsic value of restricted stock units distributed during the years ended December 31, 2017, 2016 and 2015 was

$13 million, $17 million and $11 million, respectively.

As of December 31, 2017, there was approximately $3 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of ten months. Dividend equivalents units of 30,066 accrued on the restricted stock units during the year.

Performance Share Units

Changes in performance share units for the year ended December 31, 2017 are summarized as follows:




	Shares	Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Non-vested as of January 1, 2017	393,812	$	44.20
Granted	382,830	$	45.02
Vested	402,451	$	44.03
Canceled/Forfeited	41,730	$	44.69
Non-vested as of December 31, 2017	332,461	$	45.29	1.7	$	17,121,742

The weighted average grant date fair value per share for performance share units during the years ended December 31, 2017, 2016 and 2015 was $45.02, $45.97 and $41.32 per share, respectively.

The total intrinsic value of performance share units distributed during the years ended December 31, 2017, 2016 and 2015 was

$18 million, $17 million and $13 million, respectively.

As of December 31, 2017, there was approximately $16 million of unrecognized compensation cost related to the performance share units, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units of 38,425 accrued on the performance share units during the year.

Outside Directors

Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. Dividend equivalents are credited quarterly and distributions will commence upon the director leaving the Board as specified by him/her in accordance with the provisions of the Directors Equity Plan.

The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan was immaterial for each of the years ended December 31, 2017, 2016 and 2015.

Employee Stock Purchase Plan (ESPP)

PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees through payroll deductions. Dividends will be reinvested for all employees at 95% of the fair market price unless the participant elects to receive a cash dividend. All employees are required to hold the shares purchased under the ESPP for at least three

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was immaterial for each of the years ended December 31, 2017, 2016 and 2015.

During the years ended December 31, 2017, 2016 and 2015, employees purchased 288,527 shares, 262,763 shares and 250,499 shares at an average price of $42.07, $40.70 and $36.66 per share, respectively. As of December 31, 2017, 3.2 million shares were available for future issuance under this plan.

Note 19. Other Income and Deductions




Other Income	PSE&G		Power		Other (A)		Consolidated Total
	Millions
Year Ended December 31, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	202	$	—	$	202
Allowance for Funds Used During Construction	56		—		—		56
Rabbi Trust Realized Gains, Interest and Dividends	5		6		13		24
Solar Loan Interest	21		—		—		21
Other	10		5		1		16
Total Other Income	$	92	$	213	$	14	$	319
Year Ended December 31, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	96	$	—	$	96
Allowance for Funds Used During Construction	49		—		—		49
Rabbi Trust Realized Gains, Interest and Dividends	3		3		6		12
Solar Loan Interest	22		—		—		22
Other	9		3		—		12
Total Other Income	$	83	$	102	$	6	$	191
Year Ended December 31, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	138	$	—	$	138
Allowance for Funds Used During Construction	48		—		—		48
Rabbi Trust Realized Gains, Interest and Dividends	2		2		6		10
Solar Loan Interest	23		—		—		23
Gain on Insurance Recovery	—		28		—		28
Other	6		1		—		7
Total Other Income	$	79	$	169	$	6	$	254




Other Deductions	PSE&G		Power		Other (A)		Consolidated Total
	Millions
Year Ended December 31, 2017
NDT Fund Realized Losses and Expenses	$	—	$	32	$	—	$	32
Other	5		24		30		59
Total Other Deductions	$	5	$	56	$	30	$	91
Year Ended December 31, 2016
NDT Fund Realized Losses and Expenses	$	—	$	40	$	—	$	40
Other	4		17		6		27
Total Other Deductions	$	4	$	57	$	6	$	67
Year Ended December 31, 2015
NDT Fund Realized Losses and Expenses	$	—	$	45	$	—	$	45
Other	4		27		26		57
Total Other Deductions	$	4	$	72	$	26	$	102


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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 20. Income Taxes

A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:




	Years Ended December 31,
PSEG	2017			2016			2015
	Millions
Net Income	$	1,574		$	887		$	1,679
Income Taxes:
Operating Income:
Current Expense (Benefit):
Federal	$	86		$	(74	)	$	243
State	(31		)	61			85
Total Current	55			(13		)	328
Deferred (Benefit) Expense:
Federal	(482		)	311			540
State	92			28			104
Total Deferred	(390		)	339			644
Investment Tax Credit (ITC)	29			85			29
Total Income Tax (Benefit) Expense	$	(306	)	$	411		$	1,001
Pre-Tax Income	$	1,268		$	1,298		$	2,680
Tax Computed at Statutory Rate @ 35%	$	444		$	454		$	938
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	36			56			129
Uncertain Tax Positions	(3		)	(31		)	7
Manufacturing Deduction	(13		)	(17		)	(10		)
NDT Fund	19			3			7
Plant-Related Items	(23		)	(20		)	(20		)
Tax Credits	(22		)	(25		)	(13		)
Audit Settlement	6			—			—
Nuclear Decommissioning Tax Carryback	—			—			(33		)
Provisional Deferred Tax Benefit - Tax Act	(755		)	—			—
Other	5			(9		)	(4		)
Sub-Total	(750		)	(43		)	63
Total Income Tax (Benefit) Expense	$	(306	)	$	411		$	1,001
Effective Income Tax Rate	(24.1		)%	31.7		%	37.4		%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is an analysis of deferred income taxes for PSEG:




	As of December 31,
PSEG	2017		2016
	Millions
Deferred Income Taxes
Assets:
Noncurrent
Regulatory Liability Excess Deferred Tax	$	602	$	—
OPEB	217		283
Related to Uncertain Tax Position	142		155
Total Noncurrent Assets	$	961	$	438

Liabilities:
Noncurrent:
Plant-Related Items	$	4,257	$	6,593
New Jersey Corporate Business Tax	674		674
Leasing Activities	384		565
AROs and NDT Fund	233		398
Pension Costs	123		197
Taxes Recoverable Through Future Rates (net)	80		208
Other	171		212
Total Noncurrent Liabilities	$	5,922	$	8,847
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	4,961	$	8,409
ITC	279		249
Net Total Noncurrent Deferred Income Taxes and ITC	$	5,240	$	8,658

The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. Also, the deferred tax effect of AROs is presented net of the deferred tax effect of the associated funding of those obligations.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:




	Years Ended December 31,
PSE&G	2017			2016			2015
	Millions
Net Income	$	973		$	889		$	787
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal	$	(52	)	$	(153	)	$	32
State	(1		)	10			52
Total Current	(53		)	(143		)	84
Deferred Expense:
Federal	492			551			325
State	129			102			52
Total Deferred	621			653			377
ITC	(5		)	5			9
Total Income Tax Expense	$	563		$	515		$	470
Pre-Tax Income	$	1,536		$	1,404		$	1,257
Tax Computed at Statutory Rate @ 35%	$	538		$	491		$	440
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	83			72			67
Uncertain Tax Positions	(9		)	(18		)	(14		)
Plant-Related Items	(23		)	(20		)	(20		)
Tax Credits	(9		)	(7		)	(6		)
Provisional Deferred Tax Benefit - Tax Act	(10		)	—			—
Other	(7		)	(3		)	3
Sub-Total	25			24			30
Total Income Tax Expense	$	563		$	515		$	470
Effective Income Tax Rate	36.7		%	36.7		%	37.4		%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is an analysis of deferred income taxes for PSE&G:




	As of December 31,
PSE&G	2017		2016
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
Regulatory Liability Excess Deferred Tax	$	602	$	—
OPEB	116		189
Total Noncurrent Assets	$	718	$	189
Liabilities:
Noncurrent:
Plant-Related Items	$	3,311	$	4,983
New Jersey Corporate Business Tax	378		385
Pension Costs	152		252
Conservation Costs	24		33
Taxes Recoverable Through Future Rates (net)	80		208
Other	86		118
Total Noncurrent Liabilities	$	4,031	$	5,979
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	3,313	$	5,790
ITC	78		83
Net Total Noncurrent Deferred Income Taxes and ITC	$	3,391	$	5,873

The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.

In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSE&G is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in the deferred tax liabilities.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:




	Years Ended December 31,
Power	2017			2016			2015
	Millions
Net Income	$	479		$	18		$	856
Income Taxes:
Operating Income:
Current Expense (Benefit):
Federal	$	95		$	107		$	220
State	(17		)	40			30
Total Current	78			147			250
Deferred (Benefit) Expense:
Federal	(804		)	(222		)	189
State	(37		)	(68		)	52
Total Deferred	(841		)	(290		)	241
ITC	34			82			20
Total Income Tax (Benefit) Expense	$	(729	)	$	(61	)	$	511
Pre-Tax (Loss) Income	$	(250	)	$	(43	)	$	1,367
Tax Computed at Statutory Rate @ 35%	$	(88	)	$	(15	)	$	478
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	(36		)	(18		)	59
Manufacturing Deduction	(13		)	(17		)	(10		)
NDT Fund	19			3			7
Tax Credits	(12		)	(18		)	(7		)
Uncertain Tax Positions	7			9			22
Audit Settlement	1			—			—
Nuclear Decommissioning Tax Carryback	—			—			(33		)
Provisional Deferred Tax Benefit - Tax Act	(610		)	—			—
Other	3			(5		)	(5		)
Sub-Total	(641		)	(46		)	33
Total Income Tax (Benefit) Expense	$	(729	)	$	(61	)	$	511
Effective Income Tax Rate	291.6		%	141.9		%	37.4		%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is an analysis of deferred income taxes for Power:




	As of December 31,
Power	2017		2016
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
Related to Uncertain Tax Positions	$	45	$	53
Pension Costs	40		68
Contractual Liabilities & Environmental Costs	12		18
Other	93		76
Total Noncurrent Assets	$	190	$	215
Liabilities:
Noncurrent:
Plant-Related Items	$	935	$	1,605
AROs and NDT Fund	235		400
New Jersey Corporate Business Tax	225		214
Total Noncurrent Liabilities	$	1,395	$	2,219
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	1,205	$	2,004
ITC	201		166
Net Total Noncurrent Deferred Income Taxes and ITC	$	1,406	$	2,170

In the above table, the deferred tax effect of asset retirement obligations is presented net of the deferred tax effect of the associated funding of those obligations.

PSEG, PSE&G and Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. See Note 6. Regulatory Assets and Liabilities.

In December 2017, the U.S. government enacted comprehensive tax legislation. The Tax Act establishes new tax laws that will take effect in 2018, including, but not limited to (1) reduction of the U.S. federal corporate tax rate from a maximum of 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) a new limitation on deductible interest expense; (4) the repeal of the domestic production activity deduction; (5) limitations on the deductibility of certain executive compensation; and (6) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80% of taxable income. In addition, certain changes were made to the bonus depreciation rules that will impact 2017.

The SEC staff issued Staff Accounting Bulletin 118 (SAB 118), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act.

PSEG, PSE&G and Power are subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change is enacted.

The majority of the current period activity was determined using the federal income tax rate of 35% and state income tax rate of 9%. As required under ASC 740, the ending 2017 deferred tax balances were adjusted to reflect the enacted lower tax rate, which resulted in a one-time, provisional deferred tax benefit of $755 million, including $610 million related to Power and $149 million related to Energy Holdings (including other impacts related to the new tax legislation, PSEG’s net non-cash provisional earnings benefit was $745 million, including $588 million related to Power and $147 million related to Energy

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Holdings). In addition, PSE&G had excess deferred taxes of approximately $2.1 billion as of December 31, 2017 and recorded a $2.9 billion revenue impact of these excess deferred taxes as Regulatory Liabilities where it is probable that refunds will be made to customers in future rates. The amount and timing of any such refund cannot be determined at this time.

For certain aspects of the Tax Act, which are discussed below, PSEG, PSE&G and Power made reasonable, good faith estimates for which provisional amounts were recorded.

PSEG’s accounting for the following elements of the Tax Act is incomplete. However, PSEG was able to make reasonable, good faith estimates of certain effects and, therefore, recorded provisional adjustments for the following: the tax rules regarding the appropriate bonus deprecation rate that should be applied to assets placed in service after September 27, 2017 for Power and PSE&G, including the information required to compute the applicable depreciable tax basis, and the impact on PSEG’s, PSE&G’s and Power’s deferred taxes associated with FIN 48 reserves.

Further, the Tax Act is unclear in certain respects and will require interpretations and implementing regulations by the Internal Revenue Service (IRS), as well as state tax authorities. The Tax Act could also be subject to potential amendments and technical corrections which could impact PSEG, PSE&G and Power’s financial statements.

In December 2015, the U.S. government enacted the Protecting Americans from Tax Hikes Act of 2015 (2015 Tax Act). Among other provisions, the 2015 Tax Act included an extension of the bonus depreciation rules and the 30% ITC for qualified property placed into service after 2016. Qualified property that is placed in service from January 1, 2015 through December 31, 2017 is eligible for 50% bonus depreciation. The provisions of the 2015 Tax Act have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. Those tax benefits would have otherwise been received over an estimated average 20 year period. However, the tax benefits have a negative impact on the rate base of several of PSE&G’s programs.

For the period beginning September 28, 2017, subject to the transition rules, the Tax Act has modified the bonus depreciation rules of the 2015 Tax Act. Subject to further guidance, it is expected that Power will be entitled to 100% expensing and bonus depreciation will no longer apply to PSE&G.

PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, Power and Energy Holdings:




2017	PSEG			PSE&G			Power			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2017	$	328		$	140		$	128		$	57
Increases as a Result of Positions Taken in a Prior Period	40			15			18			8
Decreases as a Result of Positions Taken in a Prior Period	(32		)	(11		)	(10		)	(13		)
Increases as a Result of Positions Taken during the Current Period	12			5			6			1
Decreases as a Result of Positions Taken during the Current Period	(1		)	(1		)	—			—
Decreases as a Result of Settlements with Taxing Authorities	—			—			—			—
Decreases due to Lapses of Applicable Statute of Limitations	(13		)	(13		)	—			—
Total Amount of Unrecognized Tax Benefits as of December 31, 2017	$	334		$	135		$	142		$	53
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(157		)	(73		)	(72		)	(12		)
Regulatory Asset—Unrecognized Tax Benefits	(56		)	(56		)	—			—
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	121		$	6		$	70		$	41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




2016	PSEG			PSE&G			Power			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2016	$	386		$	181		$	111		$	93
Increases as a Result of Positions Taken in a Prior Period	12			3			6			2
Decreases as a Result of Positions Taken in a Prior Period	(62		)	(23		)	(1		)	(38		)
Increases as a Result of Positions Taken during the Current Period	19			6			12			—
Decreases as a Result of Positions Taken during the Current Period	—			—			—			—
Decreases as a Result of Settlements with Taxing Authorities	—			—			—			—
Decreases due to Lapses of Applicable Statute of Limitations	(27		)	(27		)	—			—
Total Amount of Unrecognized Tax Benefits as of December 31, 2016	$	328		$	140		$	128		$	57
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(200		)	(106		)	(74		)	(20		)
Regulatory Asset—Unrecognized Tax Benefits	(31		)	(31		)	—			—
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	97		$	3		$	54		$	37




2015	PSEG			PSE&G			Power			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2015	$	332		$	165		$	70		$	95
Increases as a Result of Positions Taken in a Prior Period	87			55			28			4
Decreases as a Result of Positions Taken in a Prior Period	(50		)	(43		)	(6		)	(1		)
Increases as a Result of Positions Taken during the Current Period	28			5			23			—
Decreases as a Result of Positions Taken during the Current Period	(1		)	(1		)	—			—
Decreases as a Result of Settlements with Taxing Authorities	(10		)	—			(4		)	(5		)
Decreases due to Lapses of Applicable Statute of Limitations	—			—			—			—
Total Amount of Unrecognized Tax Benefits as of December 31, 2015	$	386		$	181		$	111		$	93
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(264		)	(162		)	(68		)	(34		)
Regulatory Asset—Unrecognized Tax Benefits	(27		)	(27		)	—			—
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	95		$	(8	)	$	43		$	59

PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded, as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows:




	Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31,
	2017		2016		2015
	Millions
PSE&G	$	25	$	22	$	20
Power	24		17		6
Energy Holdings	21		20		40
Total	$	70	$	59	$	66

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows:




Possible (Increase)/Decrease in Total Unrecognized Tax Benefits	Over the next 12 Months
	Millions
PSEG	$	69
PSE&G	$	35
Power	$	30

A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are:




	PSEG	PSE&G	Power
United States
Federal	2011-2016	N/A	N/A
New Jersey	2006-2016	2011-2016	N/A
Pennsylvania	2014-2016	2014-2016	N/A
Connecticut	2016	N/A	N/A
Texas	2008-2016	N/A	N/A
California	2006-2016	N/A	N/A
New York	2014-2016	N/A	2014-2016

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 21. Accumulated Other Comprehensive Income (Loss), Net of Tax




PSEG	Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	10		$	(411	)	$	118		$	(283	)
Other Comprehensive Income before Reclassifications	2			(7		)	(25		)	(30		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(12		)	32			(2		)	18
Net Current Period Other Comprehensive Income (Loss)	(10		)	25			(27		)	(12		)
Balance as of December 31, 2015	$	—		$	(386	)	$	91		$	(295	)
Other Comprehensive Income before Reclassifications	2			(45		)	40			(3		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			33			2			35
Net Current Period Other Comprehensive Income (Loss)	2			(12		)	42			32
Balance as of December 31, 2016	$	2		$	(398	)	$	133		$	(263	)
Other Comprehensive Income before Reclassifications	—			(32		)	109			77
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(2		)	24			(65		)	(43		)
Net Current Period Other Comprehensive Income (Loss)	(2		)	(8		)	44			34
Balance as of December 31, 2017	$	—		$	(406	)	$	177		$	(229	)

Power	Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	11		$	(351	)	$	112		$	(228	)
Other Comprehensive Income before Reclassifications	1			(4		)	(24		)	(27		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(12		)	28			(1		)	15
Net Current Period Other Comprehensive Income (Loss)	(11		)	24			(25		)	(12		)
Balance as of December 31, 2015	$	—		$	(327	)	$	87		$	(240	)
Other Comprehensive Income before Reclassifications	—			(42		)	39			(3		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			29			3			32
Net Current Period Other Comprehensive Income (Loss)	—			(13		)	42			29
Balance as of December 31, 2016	$	—		$	(340	)	$	129		$	(211	)
Other Comprehensive Income before Reclassifications	—			(28		)	106			78
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			21			(60		)	(39		)
Net Current Period Other Comprehensive Income (Loss)	—			(7		)	46			39
Balance as of December 31, 2017	$	—		$	(347	)	$	175		$	(172	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2015
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	20		$	(8	)	$	12
Total Cash Flow Hedges		20			(8		)	12
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	12			(3		)	9
Amortization of Actuarial Loss	O&M Expense	(68		)	27			(41		)
Total Pension and OPEB Plans		(56		)	24			(32		)
Available-for-Sale Securities
Realized Gains	Other Income	100			(52		)	48
Realized Losses	Other Deductions	(39		)	20			(19		)
Other-Than-Temporary Impairments (OTTI)	OTTI	(53		)	26			(27		)
Total Available-for-Sale Securities		8			(6		)	2
Total		$	(28	)	$	10		$	(18	)

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2015
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	20		$	(8	)	$	12
Total Cash Flow Hedges		20			(8		)	12
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	11			(3		)	8
Amortization of Actuarial Loss	O&M Expense	(60		)	24			(36		)
Total Pension and OPEB Plans		(49		)	21			(28		)
Available-for-Sale Securities
Realized Gains	Other Income	98			(51		)	47
Realized Losses	Other Deductions	(38		)	19			(19		)
OTTI	OTTI	(53		)	26			(27		)
Total Available-for-Sale Securities		7			(6		)	1
Total		$	(22	)	$	7		$	(15	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2016
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	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	$	12		$	(5	)	$	7
Amortization of Actuarial Loss	O&M Expense	(68		)	28			(40		)
Total Pension and OPEB Plans		(56		)	23			(33		)
Available-for-Sale Securities
Realized Gains	Other Income	59			(29		)	30
Realized Losses	Other Deductions	(37		)	19			(18		)
OTTI	OTTI	(28		)	14			(14		)
Total Available-for-Sale Securities		(6		)	4			(2		)
Total		$	(62	)	$	27		$	(35	)

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2016
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	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	$	11		$	(5	)	$	6
Amortization of Actuarial Loss	O&M Expense	(59		)	24			(35		)
Total Pension and OPEB Plans		(48		)	19			(29		)
Available-for-Sale Securities
Realized Gains	Other Income	55			(28		)	27
Realized Losses	Other Deductions	(33		)	17			(16		)
OTTI	OTTI	(28		)	14			(14		)
Total Available-for-Sale Securities		(6		)	3			(3		)
Total		$	(54	)	$	22		$	(32	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2017
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Interest Rate Swaps	Interest Expense	3			(1		)	2
Total Cash Flow Hedges		3			(1		)	2
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	10		$	(4	)	$	6
Amortization of Actuarial Loss	O&M Expense	(51		)	21			(30		)
Total Pension and OPEB Plans		(41		)	17			(24		)
Available-for-Sale Securities
Realized Gains	Other Income	174			(89		)	85
Realized Losses	Other Deductions	(28		)	14			(14		)
OTTI	OTTI	(12		)	6			(6		)
Total Available-for-Sale Securities		134			(69		)	65
Total		$	96		$	(53	)	$	43

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2017
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	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	$	9		$	(4	)	$	5
Amortization of Actuarial Loss	O&M Expense	(44		)	18			(26		)
Total Pension and OPEB Plans		(35		)	14			(21		)
Available-for-Sale Securities
Realized Gains	Other Income	161			(83		)	78
Realized Losses	Other Deductions	(24		)	12			(12		)
OTTI	OTTI	(12		)	6			(6		)
Total Available-for-Sale Securities		125			(65		)	60
Total		$	90		$	(51	)	$	39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 22. 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. For additional information on PSEG’s stock compensation plans see Note 18. Stock Based Compensation. 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:




	Years Ended December 31,
	2017				2016				2015
	Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator:
(Millions)
Net Income	$	1,574	$	1,574	$	887	$	887	$	1,679	$	1,679
EPS Denominator:
(Millions)
Weighted Average Common Shares Outstanding	505		505		505		505		505		505
Effect of Stock Based Compensation Awards	—		2		—		3		—		3
Total Shares	505		507		505		508		505		508
EPS:
Net Income	$	3.12	$	3.10	$	1.76	$	1.75	$	3.32	$	3.30

There were approximately 0.4 million and 0.5 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the years ended December 31, 2016 and 2015, respectively.

For additional information on all the types of long-term incentive awards, see Note 18. Stock Based Compensation.

Dividends




	Years Ended December 31,
Dividend Payments on Common Stock	2017		2016		2015
Per Share	$	1.72	$	1.64	$	1.56
in Millions	$	870	$	830	$	789

On February 20, 2018, PSEG’s Board of Directors approved a $0.45 per share common stock dividend for the first quarter of 2018.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 23. Financial Information by Business Segment

Basis of Organization

PSEG’s, PSE&G’s and Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and Power. PSE&G and Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants.

PSE&G

PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.

Power

Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities and by bidding energy, capacity and ancillary services into the markets for these products. A significant portion of Power’s revenue is obtained from the various ISOs in which Power operates. The ISOs act similarly to a clearing house for all of its members in that all revenues paid out are collected from market participants based on their consumption of energy and energy-related products. Power also enters into bilateral contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations.

Other

This category 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.




	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
Year Ended December 31, 2017
Operating Revenues	$	6,234	$	3,930		$	466		$	(1,546	)	$	9,084
Depreciation and Amortization	685		1,268			33			—			1,986
Operating Income (Loss)	1,752		(359		)	36			—			1,429
Income from Equity Method Investments	—		14			—			—			14
Interest Income	24		3			5			(2		)	30
Interest Expense	303		50			40			(2		)	391
Income (Loss) before Income Taxes	1,536		(250		)	(18		)	—			1,268
Income Tax Expense (Benefit)	563		(729		)	(140		)	—			(306		)
Net Income (Loss)	973		479			122			—			1,574
Gross Additions to Long-Lived Assets	$	2,919	$	1,231		$	40		$	—		$	4,190
As of December 31, 2017
Total Assets	$	28,554	$	12,418		$	2,666		$	(922	)	$	42,716
Investments in Equity Method Subsidiaries	$	—	$	87		$	—		$	—		$	87

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
Year Ended December 31, 2016
Operating Revenues	$	6,221	$	4,023		$	370		$	(1,553	)	$	9,061
Depreciation and Amortization	565		881			30			—			1,476
Operating Income (Loss)	1,614		13			(51		)	—			1,576
Income from Equity Method Investments	—		11			—			—			11
Interest Income	24		4			4			(2		)	30
Interest Expense	289		84			14			(2		)	385
Income (Loss) before Income Taxes	1,404		(43		)	(63		)	—			1,298
Income Tax Expense (Benefit)	515		(61		)	(43		)	—			411
Net Income (Loss)	889		18			(20		)	—			887
Gross Additions to Long-Lived Assets	$	2,816	$	1,343		$	40		$	—		$	4,199
As of December 31, 2016
Total Assets	$	26,288	$	12,193		$	2,373		$	(784	)	$	40,070
Investments in Equity Method Subsidiaries	$	—	$	102		$	—		$	—		$	102




	PSE&G		Power		Other (A)			Eliminations (B)			Consolidated Total
	Millions
Year Ended December 31, 2015
Operating Revenues	$	6,636	$	4,928	$	462		$	(1,611	)	$	10,415
Depreciation and Amortization	892		291		31			—			1,214
Operating Income (Loss)	1,462		1,430		70			—			2,962
Income from Equity Method Investments	—		14		(2		)	—			12
Interest Income	25		2		33			(29		)	31
Interest Expense	280		121		21			(29		)	393
Income (Loss) before Income Taxes	1,257		1,367		56			—			2,680
Income Tax Expense (Benefit)	470		511		20			—			1,001
Net Income (Loss)	787		856		36			—			1,679
Gross Additions to Long-Lived Assets	$	2,692	$	1,117	$	54		$	—		$	3,863
As of December 31, 2015
Total Assets	$	23,677	$	12,250	$	2,810		$	(1,202	)	$	37,535
Investments in Equity Method Subsidiaries	$	—	$	119	$	—		$	—		$	119


(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. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 24. Related-Party Transactions.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24. 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 presented as follows:




	Years Ended December 31,
Related Party Transactions	2017		2016		2015
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	1,580	$	1,587	$	1,630
Administrative Billings from Services (B)	331		312		274
Total Billings from Affiliates	$	1,911	$	1,899	$	1,904




	Years Ended December 31,
Related Party Transactions	2017		2016
	Millions
Receivables from PSEG (C)	$	—	$	76
Payable to Power (A)	$	221	$	193
Payable to Services (B)	78		67
Payable to PSEG (C)	$	41	$	—
Accounts Payable—Affiliated Companies	$	340	$	260
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	91	$	130

Power

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




	Years Ended December 31,
Related Party Transactions	2017		2016		2015
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	1,580	$	1,587	$	1,630
Billings from Affiliates:
Administrative Billings from Services (B)	$	168	$	179	$	187

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Years Ended December 31,
Related Party Transactions	2017			2016
	Millions
Receivable from PSE&G (A)	$	221		$	193
Receivable from PSEG (C)	—			12
Accounts Receivable—Affiliated Companies	$	221		$	205
Payable to Services (B)	$	28		$	25
Payable to PSEG (C)	29			—
Accounts Payable—Affiliated Companies	$	57		$	25
Short-Term Loan due (to) from Affiliate (E)	$	(281	)	$	87
Working Capital Advances to Services (D)	$	17		$	17
Long-Term Accrued Taxes Payable	$	52		$	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. The rates in the BGS and BGSS contracts are prescribed by the BPU. 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 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 CONSOLIDATED FINANCIAL STATEMENTS

Note 25. Selected Quarterly Data (Unaudited)

The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.




	Quarter Ended
	March 31,				June 30,				September 30,				December 31, (A)
	2017		2016		2017		2016		2017		2016		2017		2016
PSEG Consolidated:	Millions, except per share data
Operating Revenues	$	2,592	$	2,616	$	2,133	$	1,905	$	2,263	$	2,450	$	2,096	$	2,090
Operating Income (Loss)	$	178	$	827	$	196	$	347	$	693	$	577	$	362	$	(175	)
Net Income (Loss)	$	114	$	471	$	109	$	187	$	395	$	327	$	956	$	(98	)
Earnings Per Share:
Basic:
Net Income (Loss)	$	0.23	$	0.93	$	0.22	$	0.37	$	0.78	$	0.65	$	1.89	$	(0.19	)
Diluted:
Net Income (Loss)	$	0.22	$	0.93	$	0.22	$	0.37	$	0.78	$	0.64	$	1.88	$	(0.19	)
Weighted Average Common Shares Outstanding:
Basic	505		505		505		505		505		505		505		505
Diluted	508		508		507		508		507		508		508		508




	Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2017		2016		2017		2016		2017		2016		2017		2016
PSE&G:	Millions
Operating Revenues	$	1,812	$	1,712	$	1,368	$	1,350	$	1,509	$	1,684	$	1,545	$	1,475
Operating Income	$	521	$	462	$	379	$	333	$	459	$	450	$	393	$	369
Net Income	$	299	$	262	$	208	$	179	$	246	$	255	$	220	$	193




	Quarter Ended
	March 31,					June 30,						September 30,				December 31, (A)
	2017			2016		2017			2016			2017		2016		2017			2016
Power:	Millions
Operating Revenues	$	1,284		$	1,313	$	929		$	714		$	873	$	1,075	$	844		$	921
Operating Income (Loss)	$	(303	)	$	343	$	(187	)	$	(12	)	$	213	$	238	$	(82	)	$	(556	)
Net Income (Loss)	$	(170	)	$	192	$	(97	)	$	(11	)	$	136	$	139	$	610		$	(302	)

(A)

The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2017 as compared to the same quarter in 2016 were primarily due to higher costs in 2016 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Net Income at PSEG consolidated and Power in the fourth quarter 2017 as compared to the same quarter in 2016 also includes the impact of the remeasurement of deferred tax balances resulting from the enactment of new tax legislation in December 2017. See Note 20. Income Taxes for additional information.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 26. 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 December 31, 2017 and 2016 and for the years ended December 31, 2017, 2016 and 2015.




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2017
Operating Revenues	$	—		$	3,891		$	174		$	(135	)	$	3,930
Operating Expenses	8			4,221			195			(135		)	4,289
Operating Income (Loss)	(8		)	(330		)	(21		)	—			(359		)
Equity Earnings (Losses) of Subsidiaries	567			60			14			(627		)	14
Other Income	98			257			2			(144		)	213
Other Deductions	(24		)	(32		)	—			—			(56		)
Other-Than-Temporary Impairments	—			(12		)	—			—			(12		)
Interest Expense	(128		)	(49		)	(17		)	144			(50		)
Income Tax Benefit (Expense)	(26		)	588			167			—			729
Net Income (Loss)	$	479		$	482		$	145		$	(627	)	$	479
Comprehensive Income (Loss)	$	518		$	529		$	145		$	(674	)	$	518
As of December 31, 2017
Current Assets	$	4,327		$	1,500		$	200		$	(4,686	)	$	1,341
Property, Plant and Equipment, net	54			5,778			2,764			—			8,596
Investment in Subsidiaries	4,844			404			—			(5,248		)	—
Noncurrent Assets	100			2,349			110			(78		)	2,481
Total Assets	$	9,325		$	10,031		$	3,074		$	(10,012	)	$	12,418
Current Liabilities	$	689		$	3,586		$	1,846		$	(4,686	)	$	1,435
Noncurrent Liabilities	533			1,966			459			(78		)	2,880
Long-Term Debt	2,136			—			—			—			2,136
Member’s Equity	5,967			4,479			769			(5,248		)	5,967
Total Liabilities and Member’s Equity	$	9,325		$	10,031		$	3,074		$	(10,012	)	$	12,418
Year Ended December 31, 2017
Net Cash Provided By (Used In) Operating Activities	$	(42	)	$	1,185		$	238		$	(55	)	$	1,326
Net Cash Provided By (Used In) Investing Activities	$	506		$	(448	)	$	(525	)	$	(765	)	$	(1,232	)
Net Cash Provided By (Used In) Financing Activities	$	(464	)	$	(736	)	$	307		$	820		$	(73	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2016
Operating Revenues	$	—		$	3,971		$	173		$	(121	)	$	4,023
Operating Expenses	8			3,962			161			(121		)	4,010
Operating Income (Loss)	(8		)	9			12			—			13
Equity Earnings (Losses) of Subsidiaries	36			(3		)	11			(33		)	11
Other Income	71			120			—			(89		)	102
Other Deductions	(18		)	(39		)	—			—			(57		)
Other-Than-Temporary Impairments	—			(28		)	—			—			(28		)
Interest Expense	(115		)	(40		)	(18		)	89			(84		)
Income Tax Benefit (Expense)	52			(11		)	20			—			61
Net Income (Loss)	$	18		$	8		$	25		$	(33	)	$	18
Comprehensive Income (Loss)	$	47		$	50		$	25		$	(75	)	$	47
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
Year Ended December 31, 2016
Net Cash Provided By (Used In) Operating Activities	$	97		$	1,442		$	323		$	(607	)	$	1,255
Net Cash Provided By (Used In) Investing Activities	$	60		$	(707	)	$	(789	)	$	289		$	(1,147	)
Net Cash Provided By (Used In) Financing Activities	$	(157	)	$	(736	)	$	466		$	318		$	(109	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2015
Operating Revenues	$	—		$	4,883		$	179		$	(134	)	$	4,928
Operating Expenses	12			3,451			169			(134		)	3,498
Operating Income (Loss)	(12		)	1,432			10			—			1,430
Equity Earnings (Losses) of Subsidiaries	906			(4		)	14			(902		)	14
Other Income	48			174			—			(53		)	169
Other Deductions	(27		)	(45		)	—			—			(72		)
Other-Than-Temporary Impairments	—			(53		)	—			—			(53		)
Interest Expense	(116		)	(39		)	(19		)	53			(121		)
Income Tax Benefit (Expense)	57			(574		)	6			—			(511		)
Net Income (Loss)	$	856		$	891		$	11		$	(902	)	$	856
Comprehensive Income (Loss)	$	844		$	855		$	11		$	(866	)	$	844
Year Ended December 31, 2015
Net Cash Provided By (Used In) Operating Activities	$	571		$	2,089		$	80		$	(1,034	)	$	1,706
Net Cash Provided By (Used In) Investing Activities	$	(366	)	$	(1,519	)	$	(430	)	$	1,314		$	(1,001	)
Net Cash Provided By (Used In) Financing Activities	$	(205	)	$	(571	)	$	354		$	(280	)	$	(702	)

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