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

We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2016 and 2015, and 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, 2016. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15(B)(a). These consolidated financial statements and consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2017 expressed an unqualified opinion on the Company’s internal control over financial reporting.




/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey
February 27, 2017

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

We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company”) as of December 31, 2016 and 2015, 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, 2016. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15(B)(b). These consolidated financial statements and consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.




/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey
February 27, 2017

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Sole Member of

PSEG Power LLC

Newark, New Jersey

We have audited the accompanying consolidated balance sheets of PSEG Power LLC and subsidiaries (the “Company”) as of December 31, 2016 and 2015, and 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, 2016. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15(B)(c). These consolidated financial statements and consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.




/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey
February 27, 2017

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions, except per share data




	Years Ended December 31,
	2016			2015			2014
OPERATING REVENUES	$	9,061		$	10,415		$	10,886
OPERATING EXPENSES
Energy Costs	3,001			3,261			3,886
Operation and Maintenance	3,008			2,978			3,150
Depreciation and Amortization	1,476			1,214			1,227
Total Operating Expenses	7,485			7,453			8,263
OPERATING INCOME	1,576			2,962			2,623
Income from Equity Method Investments	11			12			13
Other Income	191			254			290
Other Deductions	(67		)	(102		)	(61		)
Other-Than-Temporary Impairments	(28		)	(53		)	(20		)
Interest Expense	(385		)	(393		)	(389		)
INCOME BEFORE INCOME TAXES	1,298			2,680			2,456
Income Tax Expense	(411		)	(1,001		)	(938		)
NET INCOME	$	887		$	1,679		$	1,518
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			505			506
DILUTED	508			508			508
NET INCOME PER SHARE:
BASIC	$	1.76		$	3.32		$	3.00
DILUTED	$	1.75		$	3.30		$	2.99

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2016			2015			2014
NET INCOME		$	887		$	1,679		$	1,518
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(41), $34, and $26 for the years ended 2016, 2015 and 2014, respectively		42			(27		)	(27		)
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(1), $7 and $(8) for the years ended 2016, 2015 and 2014, respectively		2			(10		)	12
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $8, $(18) and $120 for the years ended 2016, 2015 and 2014, respectively		(12		)	25			(173		)
Other Comprehensive Income (Loss), net of tax		32			(12		)	(188		)
COMPREHENSIVE INCOME		$	919		$	1,667		$	1,330

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2016			2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	423		$	394
Accounts Receivable, net of allowances of $68 in 2016 and $67 in 2015	1,161			1,068
Tax Receivable	78			305
Unbilled Revenues	260			197
Fuel	326			463
Materials and Supplies, net	561			513
Prepayments	76			135
Derivative Contracts	163			242
Regulatory Assets	199			164
Other	7			13
Total Current Assets	3,254			3,494
PROPERTY, PLANT AND EQUIPMENT	39,337			35,494
Less: Accumulated Depreciation and Amortization	(10,051		)	(8,955		)
Net Property, Plant and Equipment	29,286			26,539
NONCURRENT ASSETS
Regulatory Assets	3,319			3,196
Long-Term Investments	1,050			1,233
Nuclear Decommissioning Trust (NDT) Fund	1,859			1,754
Long-Term Tax Receivable	104			171
Long-Term Receivable of VIEs	589			495
Other Special Funds	217			227
Goodwill	16			16
Other Intangibles	98			102
Derivative Contracts	24			77
Other	254			231
Total Noncurrent Assets	7,530			7,502
TOTAL ASSETS	$	40,070		$	37,535

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2016			2015
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	500		$	734
Commercial Paper and Loans	388			364
Accounts Payable	1,459			1,369
Derivative Contracts	13			76
Accrued Interest	97			96
Accrued Taxes	31			42
Clean Energy Program	142			142
Obligation to Return Cash Collateral	132			128
Regulatory Liabilities	88			123
Regulatory Liabilities of VIEs	—			42
Other	426			459
Total Current Liabilities	3,276			3,575
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,658			8,166
Regulatory Liabilities	118			175
Asset Retirement Obligations	726			679
Other Postretirement Benefit (OPEB) Costs	1,324			1,228
OPEB Costs of Servco	452			375
Accrued Pension Costs	568			487
Accrued Pension Costs of Servco	128			114
Environmental Costs	401			415
Derivative Contracts	3			27
Long-Term Accrued Taxes	180			212
Other	211			181
Total Noncurrent Liabilities	12,769			12,059
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT	10,895			8,834
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2016 and 2015— 534 shares	4,936			4,915
Treasury Stock, at cost, 2016—29 shares; 2015—28 shares	(717		)	(671		)
Retained Earnings	9,174			9,117
Accumulated Other Comprehensive Loss	(263		)	(295		)
Total Common Stockholders’ Equity	13,130			13,066
Noncontrolling Interest	—			1
Total Stockholders’ Equity	13,130			13,067
Total Capitalization	24,025			21,901
TOTAL LIABILITIES AND CAPITALIZATION	$	40,070		$	37,535

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	887		$	1,679		$	1,518
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,476			1,214			1,227
Amortization of Nuclear Fuel	203			213			200
Renewable Energy Credit (REC) Compliance Accrual	109			104			69
Impairment Costs for Early Plant Retirements	102			—			—
Provision for Deferred Income Taxes (Other than Leases) and ITC	474			685			515
Non-Cash Employee Benefit Plan Costs	127			161			47
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	(6		)	26			(4		)
Net (Gain) Loss on Lease Investments	92			—			(3		)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	183			(143		)	(93		)
Net Change in Regulatory Assets and Liabilities	(138		)	(48		)	187
Cost of Removal	(131		)	(120		)	(98		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(26		)	(38		)	(166		)
Net Change in Certain Current Assets and Liabilities
Tax Receivable	303			(94		)	30
Accrued Taxes	3			(91		)	(156		)
Margin Deposit	(76		)	122			(22		)
Other Current Assets and Liabilities	(180		)	288			(31		)
Employee Benefit Plan Funding and Related Payments	(103		)	(109		)	(95		)
Other	12			70			35
Net Cash Provided By (Used In) Operating Activities	3,311			3,919			3,160
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(4,199		)	(3,863		)	(2,820		)
Purchase of Emissions Allowances and RECs	(99		)	(106		)	(101		)
Proceeds from Sale of Capital Leases and Investments	—			14			25
Proceeds from Sales of Available-for-Sale Securities	824			1,501			1,915
Investments in Available-for-Sale Securities	(856		)	(1,552		)	(1,934		)
Other	82			64			23
Net Cash Provided By (Used In) Investing Activities	(4,248		)	(3,942		)	(2,892		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	24			364			(60		)
Issuance of Long-Term Debt	2,675			1,350			1,250
Redemption of Long-Term Debt	(824		)	(600		)	(500		)
Redemption of Securitization Debt	—			(259		)	(237		)
Cash Dividend Paid on Common Stock	(830		)	(789		)	(748		)
Other	(79		)	(51		)	(64		)
Net Cash Provided By (Used In) Financing Activities	966			15			(359		)
Net Increase (Decrease) in Cash and Cash Equivalents	29			(8		)	(91		)
Cash and Cash Equivalents at Beginning of Period	394			402			493
Cash and Cash Equivalents at End of Period	$	423		$	394		$	402
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(245	)	$	447		$	538
Interest Paid, Net of Amounts Capitalized	$	365		$	381		$	382
Accrued Property, Plant and Equipment Expenditures	$	664		$	510		$	382

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, 2014	534	$	4,861	(28	)	$	(615	)	$	7,457		$	(95	)	$	1		$	11,609
Net Income	—	—		—		—			1,518			—			—			1,518
Other Comprehensive Income (Loss), net of tax (expense) benefit of $138	—	—		—		—			—			(188		)	—			(188		)
Comprehensive Income																		1,330
Cash Dividends on Common Stock	—	—		—		—			(748		)	—			—			(748		)
Other	—	15		—		(20		)	—			—			—			(5		)
Balance as of December 31, 2014	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

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions




	Years Ended December 31,
	2016			2015			2014
OPERATING REVENUES	$	6,221		$	6,636		$	6,766
OPERATING EXPENSES
Energy Costs	2,567			2,722			2,909
Operation and Maintenance	1,475			1,560			1,558
Depreciation and Amortization	565			892			906
Total Operating Expenses	4,607			5,174			5,373
OPERATING INCOME	1,614			1,462			1,393
Other Income	83			79			61
Other Deductions	(4		)	(4		)	(3		)
Interest Expense	(289		)	(280		)	(277		)
INCOME BEFORE INCOME TAXES	1,404			1,257			1,174
Income Tax Expense	(515		)	(470		)	(449		)
NET INCOME	$	889		$	787		$	725

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,
		2016		2015			2014
NET INCOME		$	889	$	787		$	725
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 2016, 2015 and 2014, respectively		—		(1		)	1
COMPREHENSIVE INCOME		$	889	$	786		$	726

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,
	2016			2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	390		$	198
Accounts Receivable, net of allowances of $68 in 2016 and $67 in 2015	810			787
Accounts Receivable-Affiliated Companies	76			222
Unbilled Revenues	260			197
Materials and Supplies	180			148
Prepayments	9			31
Regulatory Assets	199			164
Derivative Contracts	—			13
Other	6			9
Total Current Assets	1,930			1,769
PROPERTY, PLANT AND EQUIPMENT	26,347			23,732
Less: Accumulated Depreciation and Amortization	(5,760		)	(5,504		)
Net Property, Plant and Equipment	20,587			18,228
NONCURRENT ASSETS
Regulatory Assets	3,319			3,196
Long-Term Investments	299			330
Other Special Funds	43			49
Other	110			105
Total Noncurrent Assets	3,771			3,680
TOTAL ASSETS	$	26,288		$	23,677

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,
	2016		2015
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	—	$	171
Commercial Paper and Loans	—		153
Accounts Payable	718		724
Accounts Payable—Affiliated Companies	260		292
Accrued Interest	76		70
Clean Energy Program	142		142
Derivative Contracts	5		—
Obligation to Return Cash Collateral	132		128
Regulatory Liabilities	88		123
Regulatory Liabilities of VIEs	—		42
Other	296		297
Total Current Liabilities	1,717		2,142
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	5,873		5,181
OPEB Costs	1,009		937
Accrued Pension Costs	250		202
Regulatory Liabilities	118		175
Environmental Costs	332		365
Asset Retirement Obligations	213		218
Derivative Contracts	—		11
Long-Term Accrued Taxes	130		109
Other	116		114
Total Noncurrent Liabilities	8,041		7,312
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT	7,818		6,650
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2016 and 2015—132 shares	892		892
Contributed Capital	945		695
Basis Adjustment	986		986
Retained Earnings	5,888		4,999
Accumulated Other Comprehensive Income	1		1
Total Stockholder’s Equity	8,712		7,573
Total Capitalization	16,530		14,223
TOTAL LIABILITIES AND CAPITALIZATION	$	26,288	$	23,677

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,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	889		$	787		$	725
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	565			892			906
Provision for Deferred Income Taxes and ITC	658			386			310
Non-Cash Employee Benefit Plan Costs	72			95			27
Cost of Removal	(131		)	(120		)	(98		)
Net Change in Other Regulatory Assets and Liabilities	(138		)	(48		)	187
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	(84		)	165			63
Materials and Supplies	(7		)	(15		)	(18		)
Prepayments	22			11			(18		)
Accounts Payable	(29		)	45			(3		)
Accounts Receivable/Payable-Affiliated Companies, net	199			—			(167		)
Other Current Assets and Liabilities	8			(29		)	6
Employee Benefit Plan Funding and Related Payments	(82		)	(91		)	(83		)
Other	(48		)	47			(4		)
Net Cash Provided By (Used In) Operating Activities	1,894			2,125			1,833
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,816		)	(2,692		)	(2,164		)
Proceeds from Sales of Available-for-Sale Securities	22			21			103
Investments in Available-for-Sale Securities	(24		)	(22		)	(101		)
Solar Loan Investments	14			11			7
Other	15			11			—
Net Cash Provided By (Used In) Investing Activities	(2,789		)	(2,671		)	(2,155		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	(153		)	153			(60		)
Issuance of Long-Term Debt	1,275			850			1,250
Redemption of Long-Term Debt	(271		)	(300		)	(500		)
Redemption of Securitization Debt	—			(259		)	(237		)
Contributed Capital	250			—			175
Other	(14		)	(10		)	(14		)
Net Cash Provided By (Used In) Financing Activities	1,087			434			614
Net Increase (Decrease) in Cash and Cash Equivalents	192			(112		)	292
Cash and Cash Equivalents at Beginning of Period	198			310			18
Cash and Cash Equivalents at End of Period	$	390		$	198		$	310
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(295	)	$	(28	)	$	283
Interest Paid, Net of Amounts Capitalized	$	273		$	261		$	259
Accrued Property, Plant and Equipment Expenditures	$	420		$	396		$	292

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, 2014	$	892	$	520	$	986	$	3,487	$	1		$	5,886
Net Income	—		—		—		725		—			725
Other Comprehensive Income, net of tax (expense) benefit of $0	—		—		—		—		1			1
Comprehensive Income												726
Contributed Capital			175		—		—		—			175
Balance as of December 31, 2014	$	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

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,
	2016			2015			2014
OPERATING REVENUES	$	4,023		$	4,928		$	5,434
OPERATING EXPENSES
Energy Costs	1,986			2,150			2,747
Operation and Maintenance	1,143			1,057			1,186
Depreciation and Amortization	881			291			292
Total Operating Expenses	4,010			3,498			4,225
OPERATING INCOME	13			1,430			1,209
Income from Equity Method Investments	11			14			14
Other Income	102			169			222
Other Deductions	(57		)	(72		)	(52		)
Other-Than-Temporary Impairments	(28		)	(53		)	(20		)
Interest Expense	(84		)	(121		)	(122		)
INCOME (LOSS) BEFORE INCOME TAXES	(43		)	1,367			1,251
Income Tax Benefit (Expense)	61			(511		)	(491		)
NET INCOME	$	18		$	856		$	760

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,
		2016			2015			2014
NET INCOME		$	18		$	856		$	760
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(41), $32, and $28 for the years ended 2016, 2015 and 2014, respectively		42			(25		)	(30		)
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $7 and $(8) for the years ended 2016, 2015 and 2014, respectively		—			(11		)	12
Pension/OPEB adjustment, net of tax (expense) benefit of $9, $(16), and $101 for the years ended 2016, 2015 and 2014, respectively		(13		)	24			(147		)
Other Comprehensive Income (Loss), net of tax		29			(12		)	(165		)
COMPREHENSIVE INCOME		$	47		$	844		$	595

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

PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2016			2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	11		$	12
Accounts Receivable	276			217
Accounts Receivable—Affiliated Companies	205			276
Short-Term Loan to Affiliate	87			363
Fuel	326			463
Materials and Supplies, net	381			363
Derivative Contracts	162			223
Prepayments	10			25
Other	2			7
Total Current Assets	1,460			1,949
PROPERTY, PLANT AND EQUIPMENT	12,655			11,354
Less: Accumulated Depreciation and Amortization	(4,135		)	(3,227		)
Net Property, Plant and Equipment	8,520			8,127
NONCURRENT ASSETS
NDT Fund	1,859			1,754
Long-Term Investments	102			119
Goodwill	16			16
Other Intangibles	98			102
Other Special Funds	53			55
Derivative Contracts	24			77
Other	61			51
Total Noncurrent Assets	2,213			2,174
TOTAL ASSETS	$	12,193		$	12,250

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

PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2016			2015
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	—		$	553
Accounts Payable	539			432
Accounts Payable—Affiliated Companies	25			33
Derivative Contracts	8			76
Accrued Interest	20			25
Other	88			107
Total Current Liabilities	680			1,226
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	2,170			2,347
Asset Retirement Obligations	511			457
OPEB Costs	251			230
Derivative Contracts	3			16
Accrued Pension Costs	191			166
Long-Term Accrued Taxes	77			35
Other	129			87
Total Noncurrent Liabilities	3,332			3,338
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
LONG-TERM DEBT	2,382			1,684
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,782			5,014
Accumulated Other Comprehensive Loss	(211		)	(240		)
Total Member’s Equity	5,799			6,002
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	12,193		$	12,250

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,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	18		$	856		$	760
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	881			291			292
Amortization of Nuclear Fuel	203			213			200
Provision for Deferred Income Taxes and ITC	(208		)	261			221
Interest Accretion on Asset Retirement Obligation	26			26			30
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	183			(143		)	(93		)
Renewable Energy Credit (REC) Compliance Accrual	109			104			69
Impairment Costs for Early Plant Retirements	102			—			—
Non-Cash Employee Benefit Plan Costs	39			48			13
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(26		)	(38		)	(166		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	31			62			19
Margin Deposit	(76		)	122			(22		)
Accounts Receivable	(71		)	63			(15		)
Accounts Payable	(22		)	(46		)	(59		)
Accounts Receivable/Payable-Affiliated Companies, net	6			(84		)	220
Other Current Assets and Liabilities	10			(36		)	(6		)
Employee Benefit Plan Funding and Related Payments	(13		)	(11		)	(7		)
Other	63			18			(31		)
Net Cash Provided By (Used In) Operating Activities	1,255			1,706			1,425
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,343		)	(1,117		)	(626		)
Purchase of Emissions Allowances and RECs	(99		)	(106		)	(101		)
Proceeds from Sales of Available-for-Sale Securities	739			1,422			1,557
Investments in Available-for-Sale Securities	(766		)	(1,455		)	(1,573		)
Short-Term Loan—Affiliated Company, net	276			221			206
Other	46			34			13
Net Cash Provided By (Used In) Investing Activities	(1,147		)	(1,001		)	(524		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	700			—			—
Cash Dividend Paid	(250		)	(400		)	(895		)
Redemption of Long-Term Debt	(553		)	(300		)	—
Other	(6		)	(2		)	(3		)
Net Cash Provided By (Used In) Financing Activities	(109		)	(702		)	(898		)
Net Increase (Decrease) in Cash and Cash Equivalents	(1		)	3			3
Cash and Cash Equivalents at Beginning of Period	12			9			6
Cash and Cash Equivalents at End of Period	$	11		$	12		$	9
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	50		$	393		$	68
Interest Paid, Net of Amounts Capitalized	$	81		$	116		$	119
Accrued Property, Plant and Equipment Expenditures	$	244		$	114		$	91

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, 2014	$	2,214	$	(986	)	$	4,693		$	(63	)	$	5,858
Net Income	—		—			760			—			760
Other Comprehensive Income (Loss), net of tax (expense) benefit of $121	—		—			—			(165		)	(165		)
Comprehensive Income												595
Cash Dividends Paid	—		—			(895		)				(895		)
Balance as of December 31, 2014	$	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

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 has implemented energy efficiency and demand response 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 has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU.


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

•

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

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

Basis of Presentation

The 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 Entities. 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 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.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. 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 Entities for further information.

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:




	2016		2015		2014
	Avg Rate		Avg Rate		Avg Rate
PSE&G Depreciation Rate	2.45	%	2.46	%	2.47	%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2016, 2015 and 2014 were as follows:




	AFUDC/IDC Capitalized
	2016				2015				2014
	Millions		Avg Rate		Millions		Avg Rate		Millions		Avg Rate
PSE&G	$	66	7.81	%	$	65	8.01	%	$	44	8.09	%
Power	$	54	4.87	%	$	27	5.14	%	$	24	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.

Impairment of Long-Lived Assets

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).

Cash and Cash Equivalents

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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 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.

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) and Savings Plans 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements.

Note 2. Recent Accounting Standards

New Standards Issued and Adopted

Stock Compensation-Improvements to Employee Share-Based Payment Accounting

This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Statement of Cash Flows.

Under the new guidance, all excess tax benefits and tax deficiencies related to employee share-based payments will be recognized in income tax expense rather than recognized in additional paid in capital. In the Statement of Cash Flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award.

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. PSEG adopted this standard in the fourth quarter of 2016. The impact to the financial statements was immaterial.

Disclosure for Investments in Certain Entities that Calculate Net Asset Value (NAV) per Share

This accounting standard eliminates the requirement to categorize, in the fair value hierarchy, investments whose fair values are measured at NAV using the practical expedient provided in the fair value guidance. The practical expedient applies to investments in mutual funds or structures similar to a mutual fund for which there is not a readily determinable fair value. Although not required in the fair value hierarchy, sufficient information must be provided to allow for reconciliation between the fair value of assets categorized in the hierarchy and the balance sheet.

The standard is effective for annual and interim periods beginning after December 15, 2015 with early adoption permitted. PSEG adopted this standard in the fourth quarter 2016 on a retrospective basis and has reflected the effect of the new disclosure requirements in Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plan.

Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

This accounting standard requires management to assess an entity’s ability to continue as a going concern and provide related disclosures in certain circumstances. These disclosures are only required when conditions give rise to substantial doubt about an entity’s ability to continue as a going concern within one year from the financial statement issuance date. The standard is effective for annual and interim periods beginning after December 15, 2016. PSEG adopted this standard in the fourth quarter of 2016; however, no disclosures were required this period based on the above criteria.

New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

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

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possibly changes in presentation. PSEG continues to evaluate all of its revenue streams and its contracts. Certain implementation issues continue to be debated and are currently being addressed by the AICPA’s Revenue Recognition Working Group and the FASB’s Transition Resource Group, including the ability to recognize revenue for certain contracts where there

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

is uncertainty regarding collection from customers and accounting for contributions in aid of construction. As the ultimate impact of the new standard has not yet been determined, PSEG has not elected its transition method.

Recognition and Measurement of Financial Assets and Financial Liabilities

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the NDT and Rabbi Trust Funds.

Leases

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

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

Measurement of Credit Losses on Financial Instruments

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

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

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

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

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Restricted Cash

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

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG will include those amounts that are deemed to be restricted cash and restricted cash equivalents in its cash and cash equivalents balances in the statement of cash flows as well as disclosure regarding the nature of restricted amounts.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Business Combinations: Clarifying the Definition of a Business

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

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG is currently evaluating the impact of this standard on its financial statements; however, PSEG does not expect this guidance to materially impact its financial statements upon adoption.

Simplifying the Test for Goodwill Impairment

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

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

Note 3. Early Plant Retirements

On October 3, 2016, Power determined that it would cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Power has filed deactivation notices with PJM for these existing units at both stations and final must-offer exception requests for the 2020-2021 PJM capacity auction to the PJM Independent Market Monitor. Power expects the units to continue to be available to generate electricity and receive previously cleared capacity payments through the date the units cease operations. The exact timing of the early retirement of these units may be impacted by operational and other conditions that could subsequently arise.

PSEG and Power undertake their annual five-year strategic planning process primarily during the third and fourth quarters of each year. The primary factors considered during this process that contributed to the decision to retire these units early include significant declines in revenues and margin caused by a sustained period of depressed wholesale power prices and reduced capacity factors caused by lower natural gas prices making coal generation less economically competitive than natural gas-fired generation. Despite experiencing recent warmer than normal weather in PJM this summer, Power did not experience the usual increase in electricity prices in PJM as it had in past hot summers. This trend has a further adverse economic impact to these units because they generally dispatch and earn energy margin on peak hot and cold days. In addition, the upcoming PJM capacity auction in May 2017 for the capacity period from June 2020 to May 2021 will be the first to require all generating units to meet the increased operating performance standards of PJM’s new capacity performance regulations. During the current annual five-year strategic planning process, Power determined, on October 3, 2016, that the costs to upgrade the existing units at the Hudson and Mercer stations to comply with these higher reliability standards to be too significant and not economic given current market conditions, including anticipated future capacity prices, current forward energy prices and past operational performance results of the units. While these units have the capability to run on both coal and natural gas, they have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The decision to retire the Hudson and Mercer units early had and will continue to have a material effect on PSEG’s and Power’s results of operations. In 2016, PSEG and Power recognized the following pre-tax charges in Energy Costs, Operation and Maintenance and Depreciation expense during the period following the announcement of the early retirement of the plants:




	Year Ended December 31, 2016
	Millions
Statement of Operations Expense (pre-tax)
Energy Costs
Coal Inventory Lower of Cost or Market Adjustments and Capacity Penalties	$	62
Operation and Maintenance
Materials and Supplies Obsolescence	31
Write-down of Construction Work in Progress	14
Other (A)	8
Depreciation and Amortization
Depreciation including Asset Retirement Costs	571
Total Pre-Tax Expense	$	686


(A)	Includes severance and miscellaneous costs. Power recorded $7 million of severance expense which it expects to pay in 2017.

In addition to these charges, Power expects to recognize the remaining Depreciation and Amortization of $958 million in 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. Additional employee-related salary continuance and severance costs and various miscellaneous costs may also be incurred during the period prior to retirement. Finally, Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such environmental remediation are neither currently probable nor estimable but may be material.

Because the Hudson and Mercer generating units will cease operations significantly before the end of their previously estimated useful lives, Power performed a recoverability test for its portfolio of generating assets in the PJM region to determine if an impairment exists. As of September 30, 2016, the estimated undiscounted future cash flows of the PJM asset group exceeded the carrying amount and no impairment was identified. For additional information on impairment of long-lived assets, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies.

In addition, Power has reduced the estimated useful life of Bridgeport Harbor Station unit 3 from 2025 to the summer of 2021 as it is more likely than not it will retire the unit by this time. The change in the estimated useful life is not expected to have a material impact on Power’s future financial results. PSEG and Power continue to monitor their 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 these assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.

Note 4. Variable Interest Entities (VIEs)

VIEs for which PSE&G is the Primary Beneficiary

PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which was pledged as collateral to a trustee. PSE&G acted as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds were remitted to Transition Funding and Transition Funding II and were used for interest and principal payments on the transition bonds and related costs. During 2015, Transition Funding and Transition Funding II paid their final securitization bond payments and as of December 31, 2015, no further debt or related costs remained with these VIEs. During 2016,

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Transition Funding and Transition Funding II refunded final over-collected transition charges to ratepayers and as of December 31, 2016 the securitization program was completed.

VIE for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates 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 2016, 2015 and 2014, Servco recorded $410 million, $375 million and $389 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, 2016 and 2015 is detailed below:




	PSE&G		Power		Other		PSEG Consolidated
	Millions
2016
Transmission and Distribution:
Electric Transmission	$	9,132	$	—	$	—	$	9,132
Electric Distribution	7,974		—		—		7,974
Gas Transmission	89		—		—		89
Gas Distribution	6,369		—		—		6,369
Construction Work in Progress	1,501		—		—		1,501
Plant Held for Future Use	19		—		—		19
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		Power		Other		PSEG Consolidated
	Millions
2015
Transmission and Distribution:
Electric Transmission	$	7,554	$	—	$	—	$	7,554
Electric Distribution	7,553		—		—		7,553
Gas Transmission	89		—		—		89
Gas Distribution	5,875		—		—		5,875
Construction Work in Progress	1,459		—		—		1,459
Plant Held for Future Use	26		—		—		26
Other	411		—		—		411
Total Transmission and Distribution	22,967		—		—		22,967
Generation:
Fossil Production	—		7,005		—		7,005
Nuclear Production	—		2,202		—		2,202
Nuclear Fuel in Service	—		785		—		785
Other Production-Solar	569		389		—		958
Construction Work in Progress	—		892		—		892
Total Generation	569		11,273		—		11,842
Other	196		81		408		685
Total	$	23,732	$	11,354	$	408	$	35,494

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,
			2016				2015
	Ownership				Accumulated				Accumulated
	Interest		Plant		Depreciation		Plant		Depreciation
			Millions
PSE&G:
Transmission Facilities	Various		$	169	$	65	$	166	$	72
Power:
Coal Generating:
Conemaugh	23	%	$	408	$	166	$	404	$	154
Keystone	23	%	$	409	$	176	$	408	$	163
Nuclear Generating:
Peach Bottom	50	%	$	1,272	$	306	$	1,219	$	262
Salem	57	%	$	1,077	$	304	$	990	$	276
Nuclear Support Facilities	Various		$	238	$	71	$	226	$	60
Pumped Storage Facilities:
Yards Creek	50	%	$	42	$	25	$	42	$	24
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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2016 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 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,
	2016		2015		Recovery/Refund Period
	Millions
Regulatory Assets
Current
New Jersey Clean Energy Program	$	142	$	142	Annual filing for recovery (2)
Weather Normalization Clause (WNC)	49		10		Annual filing for recovery (2)
Underrecovered Electric Energy Costs—Basic Generation Service	2		11		Annual filing for recovery (1) (2)
Other	6		1		Various
Total Current Regulatory Assets	$	199	$	164
Noncurrent
Pension and OPEB Costs	$	1,403	$	1,270	Various
Deferred Income Taxes	507		467		Various
Manufactured Gas Plant (MGP) Remediation Costs	403		431		Various (2)
Storm Damage Deferrals	239		233		To be determined
Electric Transmission and Gas Cost of Removal	189		160		Through depreciation rates
Remediation Adjustment Charge (RAC) (Other SBC)	180		174		Through 2022 (1) (2)
Conditional Asset Retirement Obligation	157		152		Various
Green Program Recovery Charges (GPRC)	91		104		Various (1) (2)
Unamortized Loss on Reacquired Debt and Debt Expense	61		67		Over remaining debt life
Mark-to-Market (MTM) Contracts	—		63		Through 2017
Other	89		75		Various
Total Noncurrent Regulatory Assets	$	3,319	$	3,196
Total Regulatory Assets	$	3,518	$	3,360

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	As of December 31,
	2016		2015		Recovery/Refund Period
	Millions
Regulatory Liabilities
Current
FERC Formula Rate True-up	$	34	$	19	Annual filing for recovery (1) (2)
GPRC	28		36		Annual filing for recovery (1) (2)
Gas Margin Adjustment Clause	11		13		Annual filing for recovery (1) (2)
Overrecovered Gas Costs —Basic Gas Supply Service	6		1		Annual filing for recovery (1) (2)
Overrecovered Non-Utility Generation Charge (NGC)	5		1		Annual filing for recovery (1) (2)
Societal Benefit Clause (SBC)	4		31		Various (1) (2)
Stranded Costs (including $42 in 2015 related to VIEs)	—		64		Through December 2016 (2)
Total Current Regulatory Liabilities	$	88	$	165
Noncurrent
Electric Distribution Cost of Removal	$	94	$	122	Through depreciation rates
MTM Contracts	20		—		Various
FERC Formula Rate True-up	1		49		Annual filing for recovery (1) (2)
Other	3		4		Various
Total Noncurrent Regulatory Liabilities	$	118	$	175
Total Regulatory Liabilities	$	206	$	340


(1)	Recovered/Refunded with interest.


(2)	Recoverable/Refundable per specific rate order.

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.


•	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.


•	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.


•	FERC Formula Rate True-up: Overcollection or undercollection of transmission earnings calculated using a FERC approved formula.


•	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.


•	GPRC: These costs are amounts associated with various renewable energy and energy efficiency programs. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program, Energy Efficiency Economic (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 and Solar Loan III Program.

•

GPRC: These costs are amounts associated with various renewable energy and energy efficiency programs. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program, Energy Efficiency Economic (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 and Solar Loan III 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.


•	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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


•	New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2017. The BPU funding requirements are recovered through the SBC.


•	NGC: These costs represent the difference between the cost of non-utility generation and the benefit realized from the energy received at market rates.


•	Overrecovered Gas Costs: These costs represent the overrecovered 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. For BGSS, interest is accrued only on overrecovered balances.

•

Overrecovered Gas Costs: These costs represent the overrecovered 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. For BGSS, interest is accrued only on overrecovered balances.

•

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.

•

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. All components accrue interest on both over and underrecoveries.


•	Storm Damage Deferrals: Costs incurred in the cleanup of major storms in 2010 through 2016. As of December 31, 2016, 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.

•

Stranded Costs: As of December 31, 2015, the balance represented overrecovered costs, which were collected by PSE&G as servicer on behalf of Transition Funding and Transition Funding II, respectively through the securitization transition charges authorized by the BPU in irrevocable financing. Collected funds were remitted to Transition Funding and Transition Funding II and used for interest and principal payments on the transition bonds and related costs and taxes. During 2015, Transition Funding and Transition Funding II paid their final securitization bond payments and as of December 31, 2015, no further debt or related costs remained. In 2016, PSE&G refunded over-collections from customers associated with Stranded Costs and as of December 31, 2016, there were no remaining Regulatory Assets or Liabilities associated with this program.


•	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.


•	Underrecovered Electric Energy Costs: These costs represent the underrecovered amounts associated with BGS, as approved by the BPU. For BGS, interest is accrued on both overrecovered and underrecovered balances.

•

WNC: This represents the over- or under- collection of gas margin refundable or recoverable under the BPU’s weather normalization clause. 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 refunded to customers in the next winter season while under recoveries (subject to an earnings cap) are collected from customers in the next winter season.

Significant 2016 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows:

•

Transmission Formula Rate Filings—In June 2016, PSE&G filed its 2015 true-up adjustment pertaining to its transmission formula rates in effect for 2015. This resulted in an adjustment of $34 million less than the 2015 originally filed revenues primarily due to the impact of bonus depreciation legislation enacted after PSE&G filed its 2015 formula rate requirement in October 2014. PSE&G had recognized the majority of this adjustment in its Consolidated Statement of Operations for the year ended December 31, 2015. For the year ended December 31, 2016, PSE&G does not anticipate a significant true-up adjustment to its 2016 Annual Formula rate. That true-up will be filed

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

by no later than June 15, 2017. In October 2016, the 2017 Annual Formula Rate Update was filed with FERC and requests approximately $121 million in increased annual transmission revenues effective January 1, 2017, subject to true-up.

•

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 2016, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2016 which represents estimated annual increases in electric and gas revenues of $16 million and $23 million, respectively. In August 2016, the BPU approved these rate increases effective September 1, 2016.

In September 2016, 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, 2016 through November 30, 2016. In February 2017, the BPU approved PSE&G’s request for an annualized increase in electric revenue requirements of $12 million with rates effective March 1, 2017.


•	Gas System Modernization Program (GSMP)—In December 2016, the BPU approved PSE&G’s initial annual GSMP cost recovery petition which results in an annual revenue increase of $10 million effective January 1, 2017. This increase represents the return of and on investment for GSMP infrastructure in service through September 30, 2016.

•

Green Program Recovery Charges (GPRC)—Each year PSE&G files with the BPU for annual recovery of its Green Program investments which include a return on its investment and recovery of expenses. In July 2016, PSE&G filed its 2016 GPRC cost recovery petition requesting recovery for the nine combined components of the electric and gas GPRC. In September 2016, the BPU approved rates on a provisional basis effective October 1, 2016 designed to recover approximately $44 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.

In November 2016, the BPU approved PSE&G’s petition for a Solar 4 All Extension II Program for an additional 33 MWs of solar development on brownfields and closed landfills. The order allows PSE&G to extend the program under the same clause recovery process as its existing Solar 4 All Programs, with an estimated initial capital investment (excluding AFUDC) of approximately $80 million with a 9.75% ROE. The Solar 4 All Extension II Program is the tenth component of the GPRC.

•

BGSS—In June 2016, PSE&G made its annual BGSS filing with the BPU requesting a reduction of $87 million in annual BGSS revenues. In September 2016, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was reduced from approximately 40 cents to 34 cents per therm effective October 1, 2016. The rate is subject to final settlement. In December 2016, PSE&G filed with the BPU for a self-implementing two-month bill credit of 7.5 cents per therm for the months of January and February 2017. In February 2017, PSE&G filed with the BPU to extend the self-implementing bill credit of 7.5 cents per therm to customers through March 2017. The 3-month bill credits are estimated to provide approximately $47 million in customer credits. The specific amount returned will depend on actual usage over that period.

•

Weather Normalization Clause—In July 2016, PSE&G filed a petition requesting approval to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period. The deficiency gas revenues would be collected from customers over the 2016-2017 and 2017-2018 Winter Periods (October 1 through May 31). In September 2016, the BPU approved PSE&G’s filing on a provisional basis with respect to the $54 million in deficiency revenues to be collected from customers effective October 1, 2016. This matter is pending.

•

Remediation Adjustment Charge (RAC)—In April 2016, the BPU approved PSE&G’s filing with respect to its RAC 23 petition allowing recovery of $54 million effective May 7, 2016 related to net Manufactured Gas Plant expenditures from August 1, 2014 through July 31, 2015. In November 2016, PSE&G filed a RAC 24 Petition with the BPU requesting recovery of $41 million of net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016. This matter is pending.

•

Universal Service Fund (USF)/Lifeline—In September 2016, 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, 2016. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on its Consolidated Statement of Operations.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7. Long-Term Investments

Long-Term Investments as of December 31, 2016 and 2015 included the following:




	As of December 31,
	2016		2015
	Millions
PSE&G
Life Insurance and Supplemental Benefits	$	140	$	150
Solar Loans	159		175
Other Investments	—		5
Power
Partnerships and Corporate Joint Ventures (Equity Method Investments) (A)	102		119
Energy Holdings
Lease Investments	649		784
Total Long-Term Investments	$	1,050	$	1,233


(A)	During the three years ended December 31, 2016, 2015 and 2014, dividends from these investments were $18 million, $16 million and $17 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.

The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2016 and 2015, respectively.




	As of December 31,
	2016			2015
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	629		$	631
Estimated Residual Value of Leased Assets	346			519
Total Investment in Rental Receivables	975			1,150
Unearned and Deferred Income	(326		)	(366		)
Gross Investments in Leases	649			784
Deferred Tax Liabilities	(674		)	(724		)
Net Investments in Leases	$	(25	)	$	60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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




	Years Ended December 31,
	2016			2015		2014
	Millions
Pre-Tax Income (Loss) from Leases	$	(135	)	$	12	$	24
Income Tax Expense (Benefit) on Income from Leases	$	(51	)	$	5	$	32

Equity Method Investments

Power had the following equity method investments as of December 31, 2016 and 2015:




	As of December 31,
Name	2016		2015		Location	% Owned
	Millions
Power
Keystone Fuels, LLC	$	7	$	16	PA	23%
Conemaugh Fuels, LLC	$	8	$	14	PA	23%
PennEast Pipeline	$	11	$	5	PA	10%
Kalaeloa	$	76	$	84	HI	50%

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. The loans are generally paid back with solar renewable energy certificates (SRECs) generated from the installed solar electric system. 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	2016		2015
	Millions
Commercial/Industrial	$	164	$	177
Residential	11		12
Total	$	175	$	189

Energy Holdings

Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $(25) million as of December 31, 2016 and $60 million as of December 31, 2015 (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, 2016	As of December 31, 2016
	Millions
AA	$	16
BBB+ — BBB-	316
BB-	133
CCC	164
Total	$	629

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, 2016, the gross investment in the leases of such assets, net of non-recourse debt, was $426 million, ($(131) 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	$	134	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	83	64	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	55	17	%	1,711	Coal	CCC (A)	REMA
Conemaugh Station Units 1 and 2	PA	$	55	17	%	1,711	Coal	CCC (A)	REMA
Shawville Station Units 1, 2, 3 and 4	PA	$	99	100	%	596	Gas	CCC (A)	REMA

(A)

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 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, 2016 was approximately $454 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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	705	$	263	$	(11	)	$	957
Debt Securities
Government	518		8		(6		)	520
Corporate	337		4		(4		)	337
Total Debt Securities	855		12		(10		)	857
Other Securities	44		—		—			44
Total NDT Available-for-Sale Securities (A)	$	1,604	$	275	$	(21	)	$	1,858


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




	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	693	$	185	$	(13	)	$	865
Debt Securities
Government	483		8		(3		)	488
Corporate	366		3		(10		)	359
Total Debt Securities	849		11		(13		)	847
Other Securities	42		—		—			42
Total NDT Available-for-Sale Securities	$	1,584	$	196	$	(26	)	$	1,754

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2016		As of December 31, 2015
	Millions
Accounts Receivable	$	8	$	17
Accounts Payable	$	5	$	10

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




	As of December 31, 2016										As of December 31, 2015
	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)	$	120	$	(10	)	$	8	$	(1	)	$	151	$	(13	)	$	1	$	—
Debt Securities
Government (B)	276		(6		)	4		—			245		(2		)	19		(1		)
Corporate (C)	139		(3		)	15		(1		)	222		(7		)	36		(3		)
Total Debt Securities	415		(9		)	19		(1		)	467		(9		)	55		(4		)
NDT Available-for-Sale Securities	$	535	$	(19	)	$	27	$	(2	)	$	618	$	(22	)	$	56	$	(4	)


(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, 2016.

(B)

Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016.

(C)

Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016.

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,
	2016			2015			2014
	Millions
Proceeds from Sales (A)	$	711		$	1,397		$	1,448
Net Realized Gains (Losses):
Gross Realized Gains	$	53		$	97		$	177
Gross Realized Losses	(32		)	(37		)	(23		)
Net Realized Gains (Losses) on NDT Fund	$	21		$	60		$	154


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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Consolidated Statements of Operations. Net unrealized gains of $128 million (after-tax) are included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Consolidated Balance Sheets as of December 31, 2016.

The available-for-sale debt securities held as of December 31, 2016 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	15
1 - 5 years	257
6 - 10 years	193
11 - 15 years	50
16 - 20 years	60
Over 20 years	282
Total NDT Available-for-Sale Debt Securities	$	857

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

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). In 2016, other-than-temporary impairments of $28 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.”

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.




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




	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	12	$	10	$	—		$	22
Debt Securities
Government	108		1		(1		)	108
Corporate	82		—		(1		)	81
Total Debt Securities	190		1		(2		)	189
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	204	$	11	$	(2	)	$	213

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, 2016		As of December 31, 2015
	Millions
Accounts Receivable	$	5	$	1
Accounts Payable	$	3	$	—

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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




	As of December 31, 2016									As of December 31, 2015
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	—	$	—		$	—	$	—	$	—	$	—		$	—	$	—
Debt Securities
Government (B)	60		(2		)	1		—		53		(1		)	2		—
Corporate (C)	46		(2		)	3		—		46		(1		)	9		—
Total Debt Securities	106		(4		)	4		—		99		(2		)	11		—
Rabbi Trust Available-for-Sale Securities	$	106	$	(4	)	$	4	$	—	$	99	$	(2	)	$	11	$	—


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

(B)

Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016.

(C)

Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016.

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




	Years Ended December 31,
	2016			2015			2014
	Millions
Proceeds from Rabbi Trust Sales (A)	$	113		$	104		$	467
Net Realized Gains (Losses):
Gross Realized Gains	$	6		$	3		$	4
Gross Realized Losses	(5		)	(2		)	(3		)
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	1		$	1


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

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 $5 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets as of December 31, 2016. The Rabbi Trust available-for-sale debt securities held as of December 31, 2016 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	8
1 - 5 years	44
6 - 10 years	44
11 - 15 years	9
16 - 20 years	8
Over 20 years	81
Total Rabbi Trust Available-for-Sale Debt Securities	$	194

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

PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). 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 2016, 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, 2016		As of December 31, 2015
	Millions
PSE&G	$	43	$	42
Power	53		52
Other	121		119
Total Rabbi Trust Available-for-Sale Securities	$	217	$	213

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10. Goodwill and Other Intangibles

As of December 31, 2016 and 2015, 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 2016 and concluded that goodwill was not impaired. In addition to goodwill, as of December 31, 2016 and 2015, Power had intangible assets of $98 million and $102 million, respectively, related to emissions allowances and renewable energy credits. 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. Such expenses for the years ended December 31, 2016, 2015 and 2014 were as follows:




	Years Ended December 31,
	2016		2015		2014
	Millions
Emissions Expense	$	14	$	13	$	10
Renewable Energy Expense	$	95	$	91	$	59

Note 11. Asset Retirement Obligations (AROs)

PSEG, PSE&G and Power have recorded various AROs which represent legal obligations to remove or dispose of an asset or some component of an asset at retirement.

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, 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 2015 and 2016 are presented in the following table:




	PSEG			PSE&G			Power			Other
	Millions
ARO Liability as of January 1, 2015	$	743		$	290		$	450		$	3
Liabilities Settled	(5		)	(4		)	(1		)	—
Liabilities Incurred	14			1			12			1
Accretion Expense	26			—			26			—
Accretion Expense Deferred and Recovered in Rate Base (A)	16			16			—			—
Revision to Present Values of Estimated Cash Flows	(115		)	(85		)	(30		)	—
ARO Liability as of December 31, 2015	$	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


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

During 2016, PSE&G recorded a reduction in 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 2016, Power recorded $23 million primarily related to new ARO liabilities at its fossil units coupled with new solar generation ARO liabilities.

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.

Effective January 1, 2016, PSEG changed the approach used to measure future service and interest costs for pension benefits. For 2015 and prior, PSEG calculated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016 and beyond, PSEG has elected to calculate service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. PSEG believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations. As a change in accounting estimate, this change was reflected prospectively. Pension and OPEB costs, net of amounts capitalized, were reduced by $34 million and $13 million, respectively, as compared to the 2016 amounts that would have been derived from applying PSEG’s 2015 and prior years’ methodology.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. No changes were made to the benefit formulas, the 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.

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, 2016 and 2015. 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
	2016			2015			2016			2015
	Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A)	$	5,522		$	5,722		$	1,612		$	1,638
Service Cost	109			123			17			22
Interest Cost	202			234			59			67
Actuarial (Gain) Loss (B)	219			(289		)	127			(45		)
Gross Benefits Paid	(282		)	(268		)	(57		)	(70		)
Plan Amendments	2			—			(4		)	—
Benefit Obligation at End of Year (A)	$	5,772		$	5,522		$	1,754		$	1,612
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	5,039		$	5,293		$	374		$	361
Actual Return on Plan Assets	403			(11		)	32			(1		)
Employer Contributions	33			25			71			84
Gross Benefits Paid	(282		)	(268		)	(57		)	(70		)
Fair Value of Assets at End of Year	$	5,193		$	5,039		$	420		$	374
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(579	)	$	(483	)	$	(1,334	)	$	(1,238	)
Additional Amounts Recognized in the Consolidated Balance Sheets
Noncurrent Assets (included in Other Special Funds)	$	—		$	14		$	—		$	—
Current Accrued Benefit Cost	(11		)	(10		)	(10		)	(10		)
Noncurrent Accrued Benefit Cost	(568		)	(487		)	(1,324		)	(1,228		)
Amounts Recognized	$	(579	)	$	(483	)	$	(1,334	)	$	(1,238	)
Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B)
Prior Service Cost	$	(63	)	$	(83	)	$	(14	)	$	(25	)
Net Actuarial Loss	1,763			1,710			523			438
Total	$	1,700		$	1,627		$	509		$	413


(A)	Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits.


(B)	Includes $679 million ($398 million, after-tax) and $658 million ($386 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2016 and 2015, respectively.

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, 2016, PSEG had funded approximately 90% of its projected benefit obligation. This percentage does not include $217 million of assets in the Rabbi Trust as of December 31, 2016 which were used partially to fund the nonqualified pension plans. As of December 31, 2016, the nonqualified pension plans included in the projected benefit obligation in the above table were $161 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 $5.6 billion as of December 31, 2016 and $5.4 billion as of December 31, 2015.

The following table provides the components of net periodic benefit cost for the years ended December 31, 2016, 2015 and 2014.




	Pension Benefits Years Ended December 31,									Other Benefits Years Ended December 31,
	2016			2015			2014			2016			2015			2014
	Millions
Components of Net Periodic Benefit Cost (Credit)
Service Cost	$	109		$	123		$	104		$	17		$	22		18
Interest Cost	202			234			234			59			67			69
Expected Return on Plan Assets	(394		)	(414		)	(399		)	(31		)	(31		)	(26		)
Amortization of Net
Prior Service Credit	(19		)	(19		)	(18		)	(14		)	(14		)	(14		)
Actuarial Loss	158			150			56			40			43			23
Net Periodic Benefit Cost (Credit)	$	56		$	74		$	(23	)	$	71		$	87		$	70

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,
	2016		2015		2014			2016		2015		2014
	Millions
PSE&G	$	29	$	40	$	(19	)	$	43	$	55	$	46
Power	16		21		(7		)	23		27		20
Other	11		13		3			5		5		4
Total Benefit Cost (Credit)	$	56	$	74	$	(23	)	$	71	$	87	$	70

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




	Pension						OPEB
	2016			2015			2016			2015
	Millions
Net Actuarial (Gain) Loss in Current Period	$	211		$	136		$	125		$	(14	)
Amortization of Net Actuarial Gain (Loss)	(158		)	(150		)	(40		)	(43		)
Prior Service Cost (Credit) in current period	1			—			(3		)	—
Amortization of Prior Service Credit	19			19			14			14
Total	$	73		$	5		$	96		$	(43	)

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 2017 are as follows:




	Pension Benefits			Other Benefits
	2017			2017
	Millions
Actuarial (Gain) Loss	$	97		$	51
Prior Service Cost	$	(18	)	$	(11	)

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




	Pension Benefits						Other Benefits
	2016		2015		2014		2016			2015			2014
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	4.29	%	4.54	%	4.20	%	4.37		%	4.58		%	4.21		%
Rate of Compensation Increase	3.61	%	3.61	%	3.61	%	3.61		%	3.61		%	3.61		%
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount Rate	4.54	%	4.20	%	5.00	%	4.58		%	4.21		%	5.01		%
Service Cost Interest Rate	4.81	%	4.20	%	5.00	%	4.87		%	4.21		%	5.01		%
Interest Cost Interest Rate	3.75	%	4.20	%	5.00	%	3.76		%	4.21		%	5.01		%
Expected Return on Plan Assets	8.00	%	8.00	%	8.00	%	8.00		%	8.00		%	8.00		%
Rate of Compensation Increase	3.61	%	3.61	%	4.61	%	3.61		%	3.61		%	4.61		%
Assumed Health Care Cost Trend Rates as of December 31
Administrative Expense							3.00		%	3.00		%	3.00		%
Health Care Costs
Immediate Rate							7.55		%	7.75		%	7.40		%
Ultimate Rate							4.75		%	4.75		%	5.00		%
Year Ultimate Rate Reached							2025			2025			2022
							Millions
Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs
Total of Service Cost and Interest Cost							$	11		$	12		$	13
Postretirement Benefit Obligation							$	191		$	194		$	201
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs
Total of Service Cost and Interest Cost							$	(9	)	$	(10	)	$	(10	)
Postretirement Benefit Obligation							$	(160	)	$	(160	)	$	(165	)

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, 2016, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 93% and 7%, 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, 2016 and 2015, including the fair value measurements and the levels of inputs used in determining those fair values.




	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	$	—
Equities (B)
Common Stock	944		944		—		—
Commingled (C)	1,387		1,247		140		—
Preferred Stock	1		1		—		—
Bonds (D)
US 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 (C)
Commingled—Equities	1,604
Private Equity (E)	16
Total Fair Value (F)	$	5,599




	Recurring Fair Value Measurements as of December 31, 2015
			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)	$	96	$	95	$	1	$	—
Equities (B)
Common Stock	816		816		—		—
Commingled (C)	1,463		1,269		194		—
Bonds (D)
US Treasury	322		—		322		—
Government—Other	279		—		279		—
Corporate	906		—		906		—
Subtotal Fair Value	$	3,882	$	2,180	$	1,702	$	—
Measured at net asset value practical expedient (C)
Commingled—Equities	1,504
Private Equity (E)	19
Total Fair Value (F)	$	5,405


(A)	Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active market (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(B)

Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. Investments in certain commingled equity funds are measured at their published daily net asset value (NAV) available to investors; if they are redeemable daily without restrictions, they are classified as Level 1 or, if they have restrictions which prevent daily redemptions, they are classified as Level 2.

(C)

In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled equity funds. As a result, PSEG determined that certain commingled funds in the amount of $1,698 million at December 31, 2015 should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at their published price. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report such investments as Level 2. In addition, as part of our implementation of the new accounting guidance on investments measured at fair value using NAV as a practical expedient in 2016, the majority of these same 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. See Note 2. Recent Accounting Standards. 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 one 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. As a result of the error correction for the $1,698 million that should have been classified as Level 2 for 2015 and $1,504 million that was removed from the fair value hierarchy as part of the new guidance on NAV practical expedient implementation, $194 million has been reclassified to Level 2 as of December 31, 2015.

(D)

Fixed income 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)

Private equity investments include various limited partnerships that invest in operating companies through acquisitions or developing a portfolio of non-US distressed investments. These investments are valued at NAV on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. These investments have been removed from the fair value hierarchy in accordance with the new guidance on NAV practical expedient.


(F)	Excludes net receivable of $14 million and $8 million at December 31, 2016 and 2015, respectively, which consists of interest and dividend, 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	2016		2015
Equity Securities	70	%	70	%
Fixed Income Securities	28		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 8.0% for 2016 and will be 7.8% for 2017. 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, which was 9.3%.

Plan Contributions

PSEG plans to contribute $14 million into its OPEB plan during 2017.

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
2017	$	310	$	82
2018	307		86
2019	319		90
2020	331		94
2021	343		99
2022-2026	1,887		534
Total	$	3,497	$	985

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,
	2016		2015		2014
	Millions
PSE&G	$	24	$	22	$	20
Power	12		12		11
Other	5		5		5
Total Employer Matching Contributions	$	41	$	39	$	36

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 Entities. 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, 2016 and 2015. 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
	2016			2015			2016			2015
				Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year	$	211		$	195		$	375		$	452
Service Cost	24			26			12			17
Interest Cost	9			9			17			21
Actuarial (Gain) Loss	14			(20		)	50			(114		)
Gross Benefits Paid	(1		)	—			(2		)	(1		)
Plan Amendments	5			1			—			—
Benefit Obligation at End of Year (A)	$	262		$	211		$	452		$	375
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	97		$	69		$	—		$	—
Actual Return on Plan Assets	10			(2		)	—			—
Employer Contributions	28			30			2			1
Gross Benefits Paid	(1		)	—			(2		)	(1		)
Fair Value of Assets at End of Year	$	134		$	97		$	—		$	—
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(128	)	$	(114	)	$	(452	)	$	(375	)
Additional Amounts Recognized in the Consolidated Balance Sheets
Accrued Pension Costs of Servco	$	(128	)	$	(114	)	N/A			N/A
OPEB Costs of Servco	N/A			N/A			(452		)	(375		)
Amounts Recognized (B)	$	(128	)	$	(114	)	$	(452	)	$	(375	)


(A)	Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits.


(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 2016, 2015 and 2014 were $28 million, $30 million and $67 million, respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2016. The OPEB-related revenues earned and costs incurred in 2016 was $2 million, and were immaterial 2015 and 2014.

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




	Pension Benefits						Other Benefits
	2016		2015		2014		2016			2015			2014
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	4.61	%	4.92	%	4.50	%	4.71		%	4.97		%	4.60		%
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
Administrative Expense							5.00		%	5.00		%	5.00		%
Health Care Costs
Immediate Rate							7.55		%	7.55		%	7.33		%
Ultimate Rate							4.75		%	4.75		%	5.00		%
Year Ultimate Rate Reached							2025			2025			2021
							Millions
Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs
Postretirement Benefit Obligation							$	97		$	75		$	160
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs
Postretirement Benefit Obligation							$	(75	)	$	(60	)	$	(106	)

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, 2016 and 2015, including the fair value measurements and the levels of inputs used in determining those fair values.




	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	$	—




	Recurring Fair Value Measurements as of December 31, 2015
			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)	$	68	$	—	$	68	$	—
Commingled Bonds (A)	29		—		29		—
Total	$	97	$	—	$	97	$	—

(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). In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled funds. As a result, PSEG determined that the commingled equity funds should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at the published price. In addition to the advance notice of one or two days, redemption days may be limited to twice per month for certain funds. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report the commingled equity fund balance of $68 million as of December 31, 2015 as 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	2016		2015
Equity Securities	71	%	71	%
Fixed Income Securities	29		29
Total Percentage	100	%	100	%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 7.7% for 2016 and will be 7.6% for 2017. This expected return was determined based on the study discussed above, including a premium for active management.

Plan Contributions

Servco plans to contribute $35 million into its pension plan during 2017.

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
2017	$	2	$	4
2018	3		6
2019	5		9
2020	7		11
2021	8		13
2022-2026	76		96
Total	$	101	$	139

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, 2016, 2015 and 2014 were $5 million, $4 million and $3 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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


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

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

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

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

The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2016 and 2015.




	As of December 31, 2016			As of December 31, 2015
	Millions
Face Value of Outstanding Guarantees	$	1,806		$	1,734
Exposure under Current Guarantees	$	139		$	172

Letters of Credit Margin Posted	$	157		$	122
Letters of Credit Margin Received	$	99		$	192

Cash Deposited and Received
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(1	)	$	(15	)
Net Broker Balance Deposited (Received)	$	57		$	(5	)

Additional Amounts Posted
Other Letters of Credit	$	51		$	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. PSEG also issued a $106 million guarantee to support Power’s payment obligations related to its equity interest in the PennEast natural gas pipeline and a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

In early 2007, 73 Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim.

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

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

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

The CPG, which consisted of 52 members as of December 31, 2016, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $190 million, which the CPG continues to incur. Of the estimated $190 million, as of December 31, 2016, the CPG had spent approximately $158 million, of which PSEG’s total share was approximately $11 million.

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of December 31, 2016, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.

Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.”

On June 16, 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Although PSEG does not currently anticipate that the filing for bankruptcy by Tierra and Maxus will affect its allocable share or total liability for the Passaic River matter, PSEG, through the CPG and independently, will monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs.

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

Natural Resource Damage Claims

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

Newark Bay Study Area

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $403 million and $460 million through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $403 million as of December 31, 2016. Of this amount, $81 million was recorded in Other Current Liabilities and $322 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $403 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.

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

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

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

Clean Water Act Permit Renewals

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

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

The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing

power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing

adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range

of studies related to impingement mortality and entrainment and submit the results with their permit applications.

In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for

review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental

organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the

Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is expected by

mid-2017.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s Clean Water Act Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2017. See Note 3. Early Plant Retirements.

Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. That CEBA provides that Power would retire BH3 early if all its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life.

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council issued an order to approve siting BH5. All major environmental permits have been obtained except for the New Source air permit that is currently in draft form for public comment. Operations are expected to begin in mid-2019.

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

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

Jersey City, New Jersey Subsurface Feeder Cable Matter

In early October 2016, a discharge of mineral oil dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The investigation and response actions related to the fluid discharge are ongoing. The investigation of the discharge and its potential cause is in the preliminary stages, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the necessary repair and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs has been extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s debris removal activities are ongoing.

Steam Electric Effluent Guidelines

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

bottom ash transport water discharges that are regulated under this rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

Coal Combustion Residuals (CCRs)

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

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

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

The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2017 is $276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2017 of $335.33 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

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




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


(A)	Prices set in the 2017 BGS auction will become effective on June 1, 2017 when the 2014 BGS auction agreements expire.

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

PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 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 2018 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2018 to support its fossil generation stations.

As of December 31, 2016, the total minimum purchase requirements included in these commitments were as follows:




Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	301
Enrichment	$	356
Fabrication	$	192
Natural Gas	$	1,029
Coal	$	215

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 continues to implement procedures to help 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 charge to income in the amount of $25 million related to this matter. No additional charges to income have been recorded for this matter since that time.

Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into the matter and issued data requests covering a period from 2002 through the date of the self-report. This investigation is ongoing. Since that time, Power has responded to data requests from FERC Staff, including recent data requests in which Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC’s response to PSEG’s legal arguments and the amount of disgorgement or other remedies FERC may ultimately seek.

PSEG is unable to reasonably estimate the range of possible loss for this matter; however, the amounts of potential disgorgement and other potential penalties that Power may incur span a wide range depending on the success of PSEG’s legal arguments. These arguments include that Power’s energy market bids in a substantial majority of the hours were below the allowed rate under the Tariff and therefore any errors in those hours were immaterial and that it is unclear whether the quantity of the bids violated any legal requirement. If PSEG’s legal arguments do not prevail in whole or in part with FERC or in a judicial challenge that PSEG may choose to pursue, it is likely that Power would record additional losses and that such additional losses would be material to PSEG’s and Power’s Consolidated Statements of Operations in the quarterly and annual periods in which they are recorded.

Financial Transmission Rights (FTR) Auction Matter

In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in the annual FTR auction in PJM for the 2016-2017 planning year and the monthly FTR auctions in PJM for February, March and April 2016. PSEG is cooperating with FERC in this matter. PSEG cannot predict the outcome of this matter at this time.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nuclear Insurance Coverages and Assessments

Power is 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/Hope Creek and Peach Bottom sites. NEIL also provides replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Power’s maximum potential liabilities under these assessments are included in the table and notes below. 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.

Power is also a member of the joint underwriting association, American Nuclear Insurers (ANI), which provides nuclear liability insurance coverage at the Salem/Hope Creek and Peach Bottom sites. The ANI policies are designed to satisfy the financial protection requirements outlined in the Price-Anderson Act.

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.

The Price-Anderson Act 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” is based on the number of licensed nuclear reactors and is adjusted at least every five years based on the Consumer Price Index. The “limit of liability” per incident per site is comprised of a primary and excess layer. As of December 31, 2016, nuclear sites were required to purchase $375 million of primary liability coverage for each site (through ANI). This limit was increased to $450 million effective January 1, 2017.The primary layer is supplemented by an excess layer, which is an industry self-insurance pool. In the event a nuclear site has a claim that exceeds the primary layer, each licensee would be assessed a prorated share of the excess, up to $127 million per reactor, payable at not more than $19 million per reactor per incident per year. With 102 reactors currently in the insurance pool, the excess layer limit is $13.0 billion. If the damages exceed the “limit of liability,” Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Power’s maximum aggregate assessment per incident is $401 million (based on Power’s ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $60 million. Further, a decision by the U.S. Supreme Court, not involving Power, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.

Power’s insurance coverages and maximum retrospective assessments for its nuclear operations as of December 31, 2016 were as follows:




Type and Source of Coverages	Site Coverage			Retrospective Assessments
	Millions
Public and Nuclear Worker Liability (Primary Layer):
ANI	$	375	(A)	$	—
Nuclear Liability (Excess Layer):
Price-Anderson Act	12,986		(B)	401
Nuclear Liability Total	$	13,361	(C)	$	401

Property Damage (Primary Layer):
NEIL Primary (Salem/Hope Creek)	$	1,500		$	35
NEIL Primary (Peach Bottom)	$	1,500		14
Property Damage (Excess Layers):
NEIL Excess (Salem/Hope Creek - Nuclear)	$	300	(D)	2
NEIL Excess (Peach Bottom - Nuclear)	$	300	(D)	1
NEIL Excess (Salem/Hope Creek - Non - Nuclear)	$	300	(D)	1
NEIL Excess (Peach Bottom - Non - Nuclear)	$	600	(D)	1
Accidental Outage - PSEG Share:(Nuclear / Non-Nuclear)
NEIL I (Peach Bottom)	$245 / $164		(E)	8
NEIL I (Salem)	$281 / $188		(E)	9
NEIL I (Hope Creek)	$490 / $328		(E)	7
Nuclear Property Total				$	78

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(A)	The primary limit for Public Liability is a per site aggregate limit with no potential for retrospective assessment. The Nuclear Worker Liability represents the potential liability from third-party workers claiming exposure to the nuclear energy hazard. This coverage is subject to an industry aggregate limit that is subject to reinstatement at ANI discretion.

(B)

Retrospective premium program under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. Power is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the United States that produces greater than 100 MW of electrical power. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of September 10, 2013. The next adjustment is due on or before September 10, 2018. This retrospective program is in excess of the Public and Nuclear Worker Liability primary layers.


(C)	Maximum limit of liability under the Price-Anderson Act for each nuclear incident per site.

(D)

For nuclear event property limits in excess of $1.5 billion, Power purchases a $300 million Excess Policy for the Salem/Hope Creek site, and a $300 million Excess Policy only for Power’s 50% interest in Peach Bottom. This limit is not subject to reinstatement in the event of a loss. In addition, for non-nuclear event limits in excess of $1.5 billion, Power maintains a $300 million limit for the combined Salem/Hope Creek sites. Exelon maintains a $600 million non-nuclear event limit for Peach Bottom.

(E)

Peach Bottom 2 and 3 have an aggregate nuclear indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Peach Bottom 2 and 3 have an aggregate non-nuclear indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 24 weeks. Salem 1 and 2 have an aggregate nuclear indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 76 weeks. Salem 1 and 2 have an aggregate non-nuclear indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 29 weeks. Hope Creek has an aggregate nuclear indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 71 weeks. Hope Creek has an aggregate non-nuclear indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 26 weeks.

Minimum Lease Payments

The total future minimum payments under various operating leases as of December 31, 2016 are:




	PSE&G		Power		Services		Other		Total
	Millions
2017	$	12	$	3	$	13	$	1	$	29
2018	8		3		13		1		25
2019	7		3		13		1		24
2020	6		2		13		1		22
2021	6		2		14		1		23
Thereafter	61		39		132		—		232
Total Minimum Lease Payments	$	100	$	52	$	198	$	5	$	355

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 14. Debt and Credit Facilities

Long-Term Debt




		As of December 31,
	Maturity	2016			2015
		Millions
PSEG
Term Loan:
Variable	2017	$	500		$	500
Total Term Loan		500			500
Senior Notes:
1.60%	2019	400			—
2.00%	2021	300			—
Total Senior Notes		700			—
Principal Amount Outstanding		1,200			500
Fair Value of Swaps (A)		—			6
Amounts Due Within One Year		(500		)	(6		)
Net Unamortized Discount and Debt Issuance Costs		(5		)	—
Total Long-Term Debt of PSEG		$	695		$	500

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




		As of December 31,
	Maturity	2016			2015
		Millions
PSE&G
First and Refunding Mortgage Bonds (B):
6.75%	2016	$	—		$	171
9.25%	2021	134			134
8.00%	2037	7			7
5.00%	2037	8			8
Total First and Refunding Mortgage Bonds		149			320
Pollution Control Bonds (B):
Floating Rate (C)	2033	—			50
Floating Rate (C)	2046	—			50
Total Pollution Control Bonds		—			100
Medium-Term Notes (MTNs) (B):
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			—
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			—
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			—
Total MTNs		7,734			6,459
Principal Amount Outstanding		7,883			6,879
Amounts Due Within One Year		—			(171		)
Net Unamortized Discount and Debt Issuance Costs		(65		)	(58		)
Total Long-Term Debt of PSE&G		$	7,818		$	6,650

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




		As of December 31,
	Maturity	2016			2015
		Millions
Power
Senior Notes:
5.32%	2016	$	—		$	303
2.75%	2016	—			250
2.45%	2018	250			250
5.13%	2020	406			406
4.15%	2021	250			250
3.00%	2021	700			—
4.30%	2023	250			250
8.63%	2031	500			500
Total Senior Notes		2,356			2,209
Pollution Control Notes:
Floating Rate (C)	2019	44			44
Total Pollution Control Notes		44			44
Principal Amount Outstanding		2,400			2,253
Amounts Due Within One Year		—			(553		)
Net Unamortized Discount and Debt Issuance Costs		(18		)	(16		)
Total Long-Term Debt of Power		$	2,382		$	1,684


(A)	PSEG entered into various interest rate swaps to hedge the fair value of certain debt at Power. The fair value adjustments from these hedges are reflected as offsets to long-term debt on the Consolidated Balance Sheets. For additional information, see Note 16. Financial Risk Management Activities.


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


(C)	The Pollution Control Financing Authority of Salem County bonds (Salem Bonds), which were repurchased and retired in 2016, and the Pennsylvania Economic Development Authority (PEDFA) bond that are serviced and secured by PSE&G Pollution Control Bonds and Power Pollution Control Notes, respectively, were variable rate bonds that were in weekly reset mode.

Long-Term Debt Maturities

The aggregate principal amounts of maturities for each of the five years following December 31, 2016 are as




Year	PSEG		PSE&G		Power		Total

2017	$	500	$	—	$	—	$	500
2018	—		750		250		1,000
2019	400		500		44		944
2020	—		259		406		665
2021	300		434		950		1,684
Thereafter	—		5,940		750		6,690
Total	$	1,200	$	7,883	$	2,400	$	11,483

Long-Term Debt Financing Transactions

During 2016, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:

PSEG


•	issued $400 million of 1.60% Senior Notes due November 2019, and

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


•	issued $300 million of 2.00% Senior Notes due November 2021

PSE&G


•	issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021,


•	issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046,


•	issued $425 million of 2.25% Secured Medium-Term Notes, Series L due September 2026,


•	retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds Series VV at maturity, and


•	repurchased at par $100 million of Salem Bonds and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds.

Power

issued $700 million of 3.00% Senior Notes due June 2021,
retired $303 million of 5.32% Senior Notes due September 2016, and
retired $250 million of 2.75% Senior Notes due September 2016.

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, 2016, the total available credit capacity was $3.5 billion.

As of December 31, 2016, no single institution represented more than 7% of the total commitments in the credit facilities.

As of December 31, 2016, the total credit capacity was in excess of the anticipated maximum liquidity requirements.

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, 2016 were as follows:




	As of December 31, 2016
Company/Facility	Total Facility		Usage (D)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	10	$	490	Mar 2019	Commercial Paper Support/Funding/Letters of Credit
5-year Credit Facility (A)	500		388		112		Apr 2020	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	398	$	602
PSE&G
5-year Credit Facility (B)	$	600	$	14	$	586	Apr 2020	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	14	$	586
Power
5-year Credit Facility	$	1,600	$	195	$	1,405	Mar 2019	Funding/Letters of Credit
5-year Credit Facility (C)	953		3		950		Apr 2020	Funding/Letters of Credit
Total Power	$	2,553	$	198	$	2,355
Total	$	4,153	$	610	$	3,543


(A)	PSEG facility will be reduced by $12 million in March 2018.


(B)	PSE&G facility will be reduced by $14 million in March 2018.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(C)	Power facility will be reduced by $24 million in March 2018.


(D)	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, 2016, PSEG had $388 million outstanding at a weighted average interest rate of 1.03%. PSE&G had no amounts outstanding under its Commercial Paper Program as of December 31, 2016.

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, 2016 and 2015 are included in the following table and accompanying notes as of December 31, 2016 and 2015. 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, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (A) (B)	$	1,195	$	1,185	$	503	$	506
PSE&G (B)	7,818		8,240		6,821		7,235
Power - Recourse Debt (B)	2,382		2,578		2,237		2,508
Energy Holdings:
Project Level, Non-Recourse Debt (C)	—		—		7		7
	$	11,395	$	12,003	$	9,568	$	10,256

(A)

Fair value includes a $500 million floating rate term loan and net offsets. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. As of December 31, 2015, carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.

(B)

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


(C)	Non-recourse project debt was valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

Note 15. Schedule of Consolidated Capital Stock




	As of December 31,
	Outstanding Shares		Book Value
	2016	2015	2016		2015
			Millions
PSEG Common Stock (no par value) (A)
Authorized 1,000,000,000 shares	504,866,212	505,282,421	$	4,219	$	4,244


(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 2016 or 2015. Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to approximately 7 million shares as of December 31, 2016.

As of December 31, 2016, 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. Changes in the fair market value of the derivative contracts are recorded in earnings.

Interest Rates

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

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. Interest rate swaps totaling $550 million that converted Power’s Senior Notes due September 2016 into variable-rate debt matured in the third quarter of 2016. There were no outstanding interest rate swaps as of December 31, 2016. As of December 31, 2015, the fair value of all the underlying hedges was $6 million. The fair value hedges reduced interest expense by $6 million, $19 million and $20 million for the years ended December 31, 2016, 2015 and 2014, 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. As of December 31, 2016, PSEG had interest rate hedges outstanding totaling $500 million. These hedges were executed during the first quarter of 2016 and convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. The fair value of these hedges was $1 million and there was no ineffectiveness as of December 31, 2016. There were no outstanding interest rate hedges as of December 31, 2015.

PSEG executed forward starting swaps totaling $400 million during the first quarter of 2016 which were terminated upon the issuance of Power’s $700 million of 3.00% Senior Notes due June 2021. In the fourth quarter of 2016, PSEG executed $500 million of forward starting swaps which were terminated upon the issuance of PSEG’s $400 million of 1.6% Senior Notes due November 2019 and $300 million of 2.0% Senior Notes due November 2021. For additional information see Note 14. Debt and Credit Facilities.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of December 31, 2016 and immaterial as of December 31, 2015. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months is $1 million.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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




	As of December 31, 2016
	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		$	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




	As of December 31, 2015
	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		$	700		$	(477	)	$	223		$	13		$	6	$	242
Noncurrent Assets		208			(131		)	77			—			—		77
Total Mark-to-Market Derivative Assets		$	908		$	(608	)	$	300		$	13		$	6	$	319
Derivative Contracts
Current Liabilities		$	(513	)	$	437		$	(76	)	$	—		$	—	$	(76	)
Noncurrent Liabilities		(132		)	116			(16		)	(11		)	—		(27		)
Total Mark-to-Market Derivative (Liabilities)		$	(645	)	$	553		$	(92	)	$	(11	)	$	—	$	(103	)
Total Net Mark-to-Market Derivative Assets (Liabilities)		$	263		$	(55	)	$	208		$	2		$	6	$	216


(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, 2016 and 2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

(B)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, cash collateral of $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

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 $19 million and $78 million as of December 31, 2016 and 2015, respectively. As of December 31, 2016 and 2015, Power had the contractual right of offset of $9 million and $12 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 $10 million and $66 million as of December 31, 2016 and 2015, 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, 2016, 2015 and 2014.




		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,
		2016		2015		2014				2016		2015		2014
		Millions								Millions
PSEG
Energy-Related Contracts		$	—	$	3	$	12	Operating Revenues		$	—	$	20	$	(9	)
Interest Rate Swaps		3		—		—		Interest Expense		—		—		—
Total PSEG		$	3	$	3	$	12			$	—	$	20	$	(9	)
Power
Energy-Related Contracts		$	—	$	3	$	12	Operating Revenues		$	—	$	20	$	(9	)
Total Power		$	—	$	3	$	12			$	—	$	20	$	(9	)

There were no pre-tax gain (loss) recognized in income on derivatives (ineffective portion) as of December 31, 2016, 2015 and 2014.

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, 2014	$	17		$	10
Gain Recognized in AOCI	3			2
Less: Gain Reclassified into Income	(20		)	(12		)
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

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, 2016, 2015 and 2014.




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,
		2016			2015			2014
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	230		$	412		$	(348	)
Energy-Related Contracts	Energy Costs	(8		)	(8		)	32
Total PSEG and Power		$	222		$	404		$	(316	)

Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and natural gas and the purchase of fuel. The tables above do not include contracts for which Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.

The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2016 and 2015.




Type	Notional	Total	PSEG	Power	PSE&G
	Millions
As of December 31, 2016
Natural Gas	Dth	357	—	348	9
Electricity	MWh	323	—	323	—
Financial Transmission Rights (FTRs)	MWh	9	—	9	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—
As of December 31, 2015
Natural Gas	Dth	201	—	168	33
Electricity	MWh	299	—	299	—
FTRs	MWh	23	—	23	—
Interest Rate Swaps	U.S. Dollars	550	550	—	—

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, 2016, 93% 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, 2016. 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	$	423	$	94	$	329	1	$	219	(A)
Non-Investment Grade	26		1		25		—	—
Total	$	449	$	95	$	354	1	$	219


(A)	Represents net exposure with PSE&G.

As of December 31, 2016, collateral held from counterparties where Power had credit exposure included $1 million in cash collateral and $94 million in letters of credit.

As of December 31, 2016, Power had 149 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, 2016, 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, 2016, 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, 2016, these consisted primarily of gas supply contracts and certain electric load contracts.

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, 2016 and December 31, 2015, 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, 2016
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	37		$	—		$	—		$	37		$	—
Debt Securities—Govt Other	$	66		$	—		$	—		$	66		$	—
Debt Securities—Corporate	$	91		$	—		$	—		$	91		$	—
Other Securities	$	1		$	—		$	1		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(16	)	$	372		$	(18	)	$	(364	)	$	(6	)
PSE&G
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	—		$	—		$	—		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	7		$	—		$	—		$	7		$	—
Debt Securities—Govt Other	$	13		$	—		$	—		$	13		$	—
Debt Securities—Corporate	$	18		$	—		$	—		$	18		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(5	)	$	—		$	—		$	—		$	(5	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	9		$	—		$	—		$	9		$	—
Debt Securities—Govt Other	$	16		$	—		$	—		$	16		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	372		$	(18	)	$	(364	)	$	(1	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Recurring Fair Value Measurements as of December 31, 2015
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)	$	326		$	—		$	326	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	313		$	(608	)	$	—	$	896		$	25
Interest Rate Swaps (C)	$	6		$	—		$	—	$	6		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—US Treasury	$	177		$	—		$	—	$	177		$	—
Debt Securities—Govt Other	$	311		$	—		$	—	$	311		$	—
Debt Securities—Corporate	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22	$	—		$	—
Debt Securities—US Treasury	$	48		$	—		$	—	$	48		$	—
Debt Securities—Govt Other	$	60		$	—		$	—	$	60		$	—
Debt Securities—Corporate	$	81		$	—		$	—	$	81		$	—
Other Securities	$	2		$	—		$	2	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(103	)	$	553		$	—	$	(644	)	$	(12	)
PSE&G
Assets:
Cash Equivalents (A)	$	160		$	—		$	160	$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	13		$	—		$	—	$	—		$	13
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—US Treasury	$	9		$	—		$	—	$	9		$	—
Debt Securities—Govt Other	$	12		$	—		$	—	$	12		$	—
Debt Securities—Corporate	$	16		$	—		$	—	$	16		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	—		$	—	$	—		$	(11	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	300		$	(608	)	$	—	$	896		$	12
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—US Treasury	$	177		$	—		$	—	$	177		$	—
Debt Securities—Govt Other	$	311		$	—		$	—	$	311		$	—
Debt Securities—Corporate	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—US Treasury	$	12		$	—		$	—	$	12		$	—
Debt Securities—Govt Other	$	14		$	—		$	—	$	14		$	—
Debt Securities—Corporate	$	20		$	—		$	—	$	20		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(92	)	$	553		$	—	$	(644	)	$	(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 an exchange, such as NYMEX, Intercontinental Exchange and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.


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

(D)

The fair value measurement 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 an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

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

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

(E)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015, $(69) million was netted against assets and $14 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 Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

For PSE&G, the natural gas supply contract is measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2016 and 2015.




	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	)




	Quantitative Information About Level 3 Fair Value Measurements
Commodity	Level 3 Position	Fair Value as of December 31, 2015					Valuation Technique(s)	Significant Unobservable Input	Range

		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	13	$	(11	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	13	$	(11	)
Power
Electricity	Electric Load Contracts	$	11	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Electricity	Other	1		—
Total Power		$	12	$	(1	)
Total PSEG		$	25	$	(12	)


(A)	Includes gas supply positions which were immaterial as of December 31, 2016.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2016 and 2015, respectively, follows:

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

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

for the Year Ended December 31, 2015




			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2015		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales)		Issuances/ Settlements (C)			Transfers In/Out		Balance as of December 31, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	37	$	20	$	(24	)	$	—	$	(20	)	$	—	$	13
PSE&G
Net Derivative Assets (Liabilities)	$	26	$	—	$	(24	)	$	—	$	—		$	—	$	2
Power
Net Derivative Assets (Liabilities)	$	11	$	20	$	—		$	—	$	(20	)	$	—	$	11


(A)	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $13 million and $20 million in Operating Income in 2016 and 2015, respectively. Of the $13 million in Operating Income in 2016 $(5) million is unrealized. The $20 million in Operating Income in 2015 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(C)	Represents $(21) million and $(20) million in settlements for derivative contracts in 2016 and 2015, respectively.

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.

As of December 31, 2015, PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $13 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, 2016, there were approximately 15 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 2016 and 2015 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.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome.




	2016		2015		2014
	Millions
Compensation Cost included in Operation and Maintenance Expense	$	29	$	34	$	32
Income Tax Benefit Recognized in Consolidated Statement of Operations	$	12	$	14	$	13

For 2016 and 2015 the excess tax benefit was $4 million and $3 million, respectively. There was no excess tax benefit for 2014.

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 2016 are summarized as follows:




	Options	Weighted Average Exercise Price		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Outstanding as of January 1, 2016	1,707,250	$	36.00
Exercised	677,350	$	33.06
Canceled/Forfeited	—	$	—
Outstanding as of December 31, 2016	1,029,900	$	37.93	2.0	$	7,640,178
Exercisable at December 31, 2016	1,029,900	$	37.93	2.0	$	7,640,178

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 2016, 2015 and 2014.

Activity for options exercised for the years ended December 31, 2016, 2015 and 2014 is shown below:




	2016		2015		2014
	Millions
Total Intrinsic Value of Options Exercised	$	7	$	3	$	4
Cash Received from Options Exercised	$	22	$	12	$	16
Tax Benefit Realized from Options Exercised	$	1	$	—	$	—

No options were vested during the years ended December 31, 2016, 2015 and 2014.

Restricted Stock Units

Changes in restricted stock units for the year ended December 31, 2016 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, 2016	408,507	$	34.95
Granted	285,258	$	42.28
Vested	362,098	$	37.23
Canceled/Forfeited	9,471	$	39.67
Non-vested as of December 31, 2016	322,196	$	38.75	1.0	$	14,137,960

The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2016, 2015 and 2014 was $42.28, $39.65 and $35.16 per share, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The total intrinsic value of restricted stock units vested during the years ended December 31, 2016, 2015 and 2014 was $17 million, $11 million and $12 million, respectively.

As of December 31, 2016, there was approximately $4 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 35,537 accrued on the restricted stock units during the year.

Performance Share Units

Changes in performance share units for the year ended December 31, 2016 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, 2016	403,961	$	40.42
Granted	319,718	$	45.97
Vested	301,554	$	41.22
Canceled/Forfeited	28,313	$	42.04
Non-vested as of December 31, 2016	393,812	$	44.20	1.6	$	17,280,471

The weighted average grant date fair value per share for performance share units during the years ended December 31, 2016, 2015 and 2014 was $45.97, $41.32 and $38.94 per share, respectively.

The total intrinsic value of performance share units vested during the years ended December 31, 2016, 2015 and 2014 was $17 million, $13 million and $6 million, respectively.

As of December 31, 2016, there was approximately $13 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 36,856 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 for each of the years ended December 31, 2016, 2015 and 2014 was approximately $1 million.

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 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 the years ended December 31, 2016, 2015 and 2014.

During the years ended December 31, 2016, 2015 and 2014, employees purchased 262,763 shares, 250,499 shares and 207,248 shares at an average price of $40.70, $36.66 and $36.07 per share, respectively. As of December 31, 2016, 3.5 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, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	96	$	—	$	96
Allowance for Funds Used During Construction	49		—		—		49
Solar Loan Interest	22		—		—		22
Other	12		6		6		24
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
Solar Loan Interest	23		—		—		23
Gain on Insurance Recovery	—		28		—		28
Other	8		3		6		17
Total Other Income	$	79	$	169	$	6	$	254
Year Ended December 31, 2014
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	219	$	—	$	219
Allowance for Funds Used During Construction	31		—		—		31
Solar Loan Interest	24		—		—		24
Other	6		3		7		16
Total Other Income	$	61	$	222	$	7	$	290




Other Deductions	PSE&G		Power		Other (A)		Consolidated Total
	Millions
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
Year Ended December 31, 2014
NDT Fund Realized Losses and Expenses	$	—	$	31	$	—	$	31
Other	3		21		6		30
Total Other Deductions	$	3	$	52	$	6	$	61


(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	2016			2015			2014
	Millions
Net Income	$	887		$	1,679		$	1,518
Income Taxes:
Operating Income:
Current Expense:
Federal	$	(74	)	$	243		$	335
State	61			85			58
Total Current	(13		)	328			393
Deferred Expense:
Federal	311			540			262
State	28			104			260
Total Deferred	339			644			522
Investment Tax Credit (ITC)	85			29			23
Total Income Taxes	$	411		$	1,001		$	938
Pre-Tax Income	$	1,298		$	2,680		$	2,456
Tax Computed at Statutory Rate @ 35%	$	454		$	938		$	860
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	56			129			145
Uncertain Tax Positions	(31		)	7			(9		)
Manufacturing Deduction	(17		)	(10		)	(16		)
NDT Fund	3			7			14
Plant-Related Items	(20		)	(20		)	(13		)
Tax Credits	(25		)	(13		)	(14		)
Audit Settlement	—			—			(12		)
Nuclear Decommissioning Tax Carryback	—			(33		)	—
Other	(9		)	(4		)	(17		)
Sub-Total	(43		)	63			78
Total Income Tax Provision	$	411		$	1,001		$	938
Effective Income Tax Rate	31.7		%	37.4		%	38.2		%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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




	As of December 31,
PSEG	2016		2015
	Millions
Deferred Income Taxes
Assets:
Noncurrent
OPEB	$	283	$	256
Related to Uncertain Tax Position	155		160
Securitization-Overcollection	—		27
Total Noncurrent Assets	$	438	$	443

Liabilities:
Noncurrent:
Plant-Related Items	$	6,593	$	6,174
New Jersey Corporate Business Tax	674		615
Leasing Activities	565		612
Pension Costs	197		218
AROs and NDT Fund	398		393
Taxes Recoverable Through Future Rate (net)	208		191
Other	212		244
Total Noncurrent Liabilities	$	8,847	$	8,447
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	8,409	$	8,004
ITC	249		162
Net Total Noncurrent Deferred Income Taxes and ITC	$	8,658	$	8,166

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	2016			2015			2014
	Millions
Net Income	$	889		$	787		$	725
Income Taxes:
Operating Income:
Current Expense:
Federal	$	(153	)	$	32		$	124
State	10			52			16
Total Current	(143		)	84			140
Deferred Expense:
Federal	551			325			214
State	102			52			84
Total Deferred	653			377			298
ITC	5			9			11
Total Income Taxes	$	515		$	470		$	449
Pre-Tax Income	$	1,404		$	1,257		$	1,174
Tax Computed at Statutory Rate @ 35%	$	491		$	440		$	411
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	72			67			65
Uncertain Tax Positions	(18		)	(14		)	—
Plant-Related Items	(20		)	(20		)	(13		)
Tax Credits	(7		)	(6		)	(7		)
Audit Settlement	—			—			1
Other	(3		)	3			(8		)
Sub-Total	24			30			38
Total Income Tax Provision	$	515		$	470		$	449
Effective Income Tax Rate	36.7		%	37.4		%	38.2		%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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




	As of December 31,
PSE&G	2016		2015
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
OPEB	$	189	$	164
Securitization-Overcollection	—		27
Total Noncurrent Assets	$	189	$	191
Liabilities:
Noncurrent:
Plant-Related Items	$	4,983	$	4,435
New Jersey Corporate Business Tax	385		312
Conservation Costs	33		40
Pension Costs	252		262
Taxes Recoverable Through Future Rate (net)	208		191
Other	118		54
Total Noncurrent Liabilities	$	5,979	$	5,294
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	5,790	$	5,103
ITC	83		78
Net Total Noncurrent Deferred Income Taxes and ITC	$	5,873	$	5,181

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.

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	2016			2015			2014
	Millions
Net Income	$	18		$	856		$	760
Income Taxes:
Operating Income:
Current Expense:
Federal	$	107		$	220		$	231
State	40			30			39
Total Current	147			250			270
Deferred Expense:
Federal	(222		)	189			163
State	(68		)	52			48
Total Deferred	(290		)	241			211
ITC	82			20			10
Total Income Taxes	$	(61	)	$	511		$	491
Pre-Tax Income	$	(43	)	$	1,367		$	1,251
Tax Computed at Statutory Rate @ 35%	$	(15	)	$	478		$	438
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	(18		)	59			58
Manufacturing Deduction	(17		)	(10		)	(16		)
NDT Fund	3			7			15
Tax Credits	(18		)	(7		)	(6		)
Uncertain Tax Positions	9			22			(8		)
Audit Settlement	—			—			(4		)
Nuclear Decommissioning Tax Carryback	—			(33		)	—
Other	(5		)	(5		)	14
Sub-Total	(46		)	33			53
Total Income Tax Provision	$	(61	)	$	511		$	491
Effective Income Tax Rate	141.9		%	37.4		%	39.2		%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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




	As of December 31,
Power	2016		2015
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
Pension Costs	$	68	$	56
Contractual Liabilities & Environmental Costs	18		18
Related to Uncertain Tax Positions	53		47
Other	76		—
Total Noncurrent Assets	$	215	$	121
Liabilities:
Noncurrent:
Plant-Related Items	$	1,605	$	1,736
New Jersey Corporate Business Tax	214		243
AROs and NDT Fund	400		395
Other	—		10
Total Noncurrent Liabilities	$	2,219	$	2,384
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	2,004	$	2,263
ITC	166		84
Net Total Noncurrent Deferred Income Taxes and ITC	$	2,170	$	2,347

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. These amounts were determined using the enacted federal income tax rate of 35% and state income tax rate of 9%. For additional information, see Note 6. Regulatory Assets and Liabilities.

In December 2014, the Tax Increase Prevention Act of 2014 was enacted, which extended the 50% bonus depreciation rules for qualified property that was placed into service before January 1, 2015 and for long production property that was placed into service in 2015.

In December 2015, Congress passed the Protecting Americans from Tax Hikes Act of 2015 (Tax Act). Among other provisions, the Tax Act includes 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 rate is reduced to 40% and 30% for eligible property placed in service in 2018 and 2019, respectively. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. The ITC rate has been extended through December 31, 2019 but is reduced to 26% and 22% for projects commenced in 2020 and 2021, respectively. The financial impact of the extensions of the ITC rate will depend upon future transactions.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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:




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




2014	PSEG			PSE&G			Power			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2014	$	478		$	208		$	156		$	110
Increases as a Result of Positions Taken in a Prior Period	82			65			17			—
Decreases as a Result of Positions Taken in a Prior Period	(190		)	(92		)	(80		)	(18		)
Increases as a Result of Positions Taken during the Current Period	30			16			9			5
Decreases as a Result of Positions Taken during the Current Period	(8		)	—			(8		)	—
Decreases as a Result of Settlements with Taxing Authorities	(60		)	(32		)	(24		)	(2		)
Decreases due to Lapses of Applicable Statute of Limitations	—			—			—			—
Total Amount of Unrecognized Tax Benefits as of December 31, 2014	$	332		$	165		$	70		$	95
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(225		)	(138		)	(52		)	(35		)
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)	$	80		$	—		$	18		$	60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2016		2015		2014
	Millions
PSE&G	$	22	$	20	$	15
Power	17		6		9
Energy Holdings	20		40		45
Total	$	59	$	66	$	69

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	$	14
PSE&G	$	3
Power	$	7

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	2011-2015	N/A	N/A
New Jersey	2006-2015	2011-2015	N/A
Pennsylvania	2006-2015	2007-2015	N/A
Connecticut	2007-2015	N/A	N/A
Texas	2008-2015	N/A	N/A
California	2006-2015	N/A	N/A
New York	2014-2015	N/A	2014-2015

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, 2013	$	(2	)	$	(238	)	$	145		$	(95	)
Other Comprehensive Income before Reclassifications	7			(184		)	42			(135		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	5			11			(69		)	(53		)
Net Current Period Other Comprehensive Income (Loss)	12			(173		)	(27		)	(188		)
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	)

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, 2013	$	(1	)	$	(204	)	$	142		$	(63	)
Other Comprehensive Income before Reclassifications	7			(156		)	39			(110		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	5			9			(69		)	(55		)
Net Current Period Other Comprehensive Income (Loss)	12			(147		)	(30		)	(165		)
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	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2014
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	$	(9	)	$	4		$	(5	)
Total Cash Flow Hedges		(9		)	4			(5		)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	10			(4		)	6
Amortization of Actuarial Loss	O&M Expense	(28		)	11			(17		)
Total Pension and OPEB Plans		(18		)	7			(11		)
Available-for-Sale Securities
Realized Gains	Other Income	181			(89		)	92
Realized Losses	Other Deductions	(26		)	13			(13		)
Other-Than-Temporary Impairments (OTTI)	OTTI	(20		)	10			(10		)
Total Available-for-Sale Securities		135			(66		)	69
Total		$	108		$	(55	)	$	53

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2014
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	$	(9	)	$	4		$	(5	)
Total Cash Flow Hedges		(9		)	4			(5		)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	9			(4		)	5
Amortization of Actuarial Loss	O&M Expense	(25		)	11			(14		)
Total Pension and OPEB Plans		(16		)	7			(9		)
Available-for-Sale Securities
Realized Gains	Other Income	178			(87		)	91
Realized Losses	Other Deductions	(24		)	12			(12		)
OTTI	OTTI	(20		)	10			(10		)
Total Available-for-Sale Securities		134			(65		)	69
Total		$	109		$	(54	)	$	55

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		)
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

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. 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,
	2016				2015		2014
	Basic		Diluted		Basic	Diluted	Basic		Diluted
EPS Numerator:
(Millions)
Net Income	$	887	$	887	1,679	1,679	$	1,518	$	1,518
EPS Denominator:
(Millions)
Weighted Average Common Shares Outstanding	505		505		505	505	506		506
Effect of Stock Based Compensation Awards	—		3		—	3	—		2
Total Shares	505		508		505	508	506		508
EPS:
Net Income	$	1.76	$	1.75	3.32	3.30	$	3.00	$	2.99

There were approximately 0.4 million, 0.5 million and 0.4 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, 2015 and 2014, respectively. No other stock options had an antidilutive effect for the years ended December 31, 2016, 2015 or 2014.

Dividends




	Years Ended December 31,
Dividend Payments on Common Stock	2016		2015		2014
Per Share	$	1.64	$	1.56	$	1.48
in Millions	$	830	$	789	$	748

On February 21, 2017, PSEG’s Board of Directors approved a $0.43 per share common stock dividend for the first quarter of 2017.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Power also enters into 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, 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	PSE&G		Power		Other (A)			Eliminations (B)			Consolidated Total
	Millions
Year Ended December 31, 2014
Operating Revenues	$	6,766	$	5,434	$	455		$	(1,769	)	$	10,886
Depreciation and Amortization	906		292		29			—			1,227
Operating Income (Loss)	1,393		1,209		21			—			2,623
Income from Equity Method Investments	—		14		(1		)	—			13
Interest Income	26		1		25			(22		)	30
Interest Expense	277		122		12			(22		)	389
Income (Loss) before Income Taxes	1,174		1,251		31			—			2,456
Income Tax Expense (Benefit)	449		491		(2		)	—			938
Net Income (Loss)	725		760		33			—			1,518
Gross Additions to Long-Lived Assets	$	2,164	$	626	$	30		$	—		$	2,820
As of December 31, 2014
Total Assets	$	22,186	$	12,037	$	2,799		$	(1,735	)	$	35,287
Investments in Equity Method Subsidiaries	$	—	$	121	$	2		$	—		$	123


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

(B)

Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 24. Related-Party Transactions.

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	2016		2015		2014
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	1,587	$	1,630	$	1,771
Administrative Billings from Services (B)	312		274		248
Total Billings from Affiliates	$	1,899	$	1,904	$	2,019

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Years Ended December 31,
Related Party Transactions	2016		2015
	Millions
Receivables from PSEG (C)	$	76	$	222
Payable to Power (A)	$	193	$	212
Payable to Services (B)	67		80
Accounts Payable—Affiliated Companies	$	260	$	292
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	130	$	109

Power

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




	Years Ended December 31,
Related Party Transactions	2016		2015		2014
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	1,587	$	1,630	$	1,771
Billings from Affiliates:
Administrative Billings from Services (B)	$	179	$	187	$	165




	Years Ended December 31,
Related Party Transactions	2016		2015
	Millions
Receivable from PSE&G (A)	$	193	$	212
Receivable from PSEG (C)	12		64
Accounts Receivable—Affiliated Companies	$	205	$	276
Payable to Services (B)	$	25	$	33
Accounts Payable—Affiliated Companies	$	25	$	33
Short-Term Loan due (to) from Affiliate (E)	$	87	$	363
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	77	$	35

(A)

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


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

(C)

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


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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(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.

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)
	2016		2015		2016		2015		2016		2015		2016			2015
PSEG Consolidated:	Millions, except per share data
Operating Revenues	$	2,616	$	3,135	$	1,905	$	2,314	$	2,450	$	2,688	$	2,090		$	2,278
Operating Income	$	827	$	1,048	$	347	$	568	$	577	$	814	$	(175	)	$	532
Net Income (Loss)	$	471	$	586	$	187	$	345	$	327	$	439	$	(98	)	$	309
Earnings Per Share:
Basic:
Net Income (Loss)	$	0.93	$	1.16	$	0.37	$	0.68	$	0.65	$	0.87	$	(0.19	)	$	0.61
Diluted:
Net Income (Loss)	$	0.93	$	1.15	$	0.37	$	0.68	$	0.64	$	0.87	$	(0.19	)	$	0.60
Weighted Average Common Shares Outstanding:
Basic	505		506		505		506		505		505		505			505
Diluted	508		508		508		508		508		508		508			508




	Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2016		2015		2016		2015		2016		2015		2016		2015
PSE&G:	Millions
Operating Revenues	$	1,712	$	2,002	$	1,350	$	1,466	$	1,684	$	1,766	$	1,475	$	1,402
Operating Income	$	462	$	451	$	333	$	320	$	450	$	404	$	369	$	287
Net Income	$	262	$	242	$	179	$	167	$	255	$	222	$	193	$	156




	Quarter Ended
	March 31,				June 30,					September 30,				December 31, (A)
	2016		2015		2016			2015		2016		2015		2016			2015
Power:	Millions
Operating Revenues	$	1,313	$	1,725	$	714		$	1,025	$	1,075	$	1,096	$	921		$	1,082
Operating Income (Loss)	$	343	$	584	$	(12	)	$	228	$	238	$	391	$	(556	)	$	227
Net Income (Loss)	$	192	$	335	$	(11	)	$	166	$	139	$	206	$	(302	)	$	149


(A)	The decreases in Operating Income at PSEG consolidated and Power in the fourth quarter 2016 as compared to the same quarter in 2015 were primarily due to costs related to closing the coal/gas Hudson and Mercer units and higher MTM losses in 2016.

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, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014.




	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
As of December 31, 2015
Current Assets	$	4,501		$	1,912		$	364		$	(4,828	)	$	1,949
Property, Plant and Equipment, net	83			6,502			1,542			—			8,127
Investment in Subsidiaries	4,501			346			—			(4,847		)	—
Noncurrent Assets	155			1,959			136			(76		)	2,174
Total Assets	$	9,240		$	10,719		$	2,042		$	(9,751	)	$	12,250
Current Liabilities	$	1,112		$	3,866		$	1,076		$	(4,828	)	$	1,226
Noncurrent Liabilities	442			2,597			375			(76		)	3,338
Long-Term Debt	1,684			—			—			—			1,684
Member’s Equity	6,002			4,256			591			(4,847		)	6,002
Total Liabilities and Member’s Equity	$	9,240		$	10,719		$	2,042		$	(9,751	)	$	12,250
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	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2014
Operating Revenues	$	—		$	5,390		$	153		$	(109	)	$	5,434
Operating Expenses	16			4,175			143			(109		)	4,225
Operating Income (Loss)	(16		)	1,215			10			—			1,209
Equity Earnings (Losses) of Subsidiaries	799			(5		)	14			(794		)	14
Other Income	34			222			—			(34		)	222
Other Deductions	(20		)	(32		)	—			—			(52		)
Other-Than-Temporary Impairments	—			(20		)	—			—			(20		)
Interest Expense	(102		)	(35		)	(19		)	34			(122		)
Income Tax Benefit (Expense)	65			(558		)	2			—			(491		)
Net Income (Loss)	$	760		$	787		$	7		$	(794	)	$	760
Comprehensive Income (Loss)	$	595		$	768		$	7		$	(775	)	$	595
Year Ended December 31, 2014
Net Cash Provided By (Used In) Operating Activities	$	577		$	1,674		$	76		$	(902	)	$	1,425
Net Cash Provided By (Used In) Investing Activities	$	148		$	(856	)	$	(42	)	$	226		$	(524	)
Net Cash Provided By (Used In) Financing Activities	$	(724	)	$	(818	)	$	(32	)	$	676		$	(898	)

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