New Jersey Resources (NJR) 10-K 21 Nov 17 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2017	Nov. 17, 2017	Mar. 31, 2017
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Registrant Name	NEW JERSEY RESOURCES CORP
Entity Central Index Key	356,309
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 3,356,717,008
Entity Common Stock, Shares Outstanding		86,866,461

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
OPERATING REVENUES
Utility		$ 695,637	$ 594,346	$ 781,970
Nonutility		1,572,980	1,286,559	1,952,017
Total operating revenues		2,268,617	1,880,905	2,733,987
Gas purchases:
Utility		258,687	205,034	304,953
Nonutility		1,436,740	1,139,301	1,767,841
Related parties		8,340	8,351	12,851
Operation and maintenance		226,356	208,421	209,453
Regulatory rider expenses		40,243	39,300	75,779
Depreciation and amortization		81,841	72,748	61,399
Energy and other taxes		49,366	40,215	53,260
Total operating expenses		2,101,573	1,713,370	2,485,536
OPERATING INCOME		167,044	167,535	248,451
Other income, net		14,437	9,196	6,545
Interest expense, net of capitalized interest		44,886	31,044	27,721
INCOME BEFORE INCOME TAXES AND EQUITY IN EARNINGS OF AFFILIATES		136,595	145,687	227,275
Income tax provision		18,343	23,530	59,724
Equity in earnings of affiliates		13,813	9,515	13,409
NET INCOME		$ 132,065	$ 131,672	$ 180,960
EARNINGS PER COMMON SHARE
Basic (in dollars per share)		$ 1.53	$ 1.53	$ 2.12
Diluted (in dollars per share)	[1]	1.52	1.52	2.10
DIVIDENDS DECLARED PER COMMON SHARE (in usd per share)		$ 1.0375	$ 0.975	$ 0.915
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic (in shares)		86,321	85,884	85,186
Diluted (in shares)		87,144	86,731	86,265
[1]	There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2017, 2016 and 2015.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income		$ 132,065	$ 131,672	$ 180,960
Other comprehensive income, net of tax:
Unrealized gain (loss) on available for sale securities, net of tax of $(4,401), $1,499, and $(1,135), respectively	[1]	6,846	(2,187)	1,603
Net unrealized gain on derivatives, net of tax of $0, $0 and $(56), respectively		0	0	93
Adjustment to postemployment benefit obligation, net of tax of $(3,487), $2,466 and $3,688 respectively		5,053	(3,574)	(5,496)
Other comprehensive income (loss)		11,899	(5,761)	(3,800)
Comprehensive income		$ 143,964	$ 125,911	$ 177,160
[1]	Available for sale securities are included in other noncurrent assets on the Consolidated Balance Sheets.

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Tax on unrealized gain (loss) on available for sale securities	$ (4,401)	$ 1,499	$ (1,135)
Tax on net unrealized gain (loss) on derivatives	0	0	(56)
Tax on adjustment to postemployment benefit obligation	$ (3,487)	$ 2,466	$ 3,688

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 132,065,000	$ 131,672,000	$ 180,960,000
Adjustments to reconcile net income to cash flows from operating activities
Unrealized (gain) loss on derivative instruments	(11,241,000)	46,883,000	(38,681,000)
Gain on sale of property and available for sale securities, net	(7,287,000)	0	0
Depreciation and amortization	81,841,000	72,748,000	61,399,000
Allowance for equity used during construction	(3,867,000)	(4,375,000)	(3,825,000)
Allowance for bad debt expense	2,023,000	1,616,000	2,859,000
Deferred income taxes	41,442,000	27,721,000	45,934,000
Manufactured gas plant remediation costs	(10,934,000)	(8,106,000)	(6,805,000)
Distributions received from equity investees, net of equity in earnings	(462,000)	4,534,000	6,663,000
Cost of removal - asset retirement obligations	(484,000)	(403,000)	(1,034,000)
Contributions to postemployment benefit plans	(6,077,000)	(33,359,000)	(5,778,000)
Tax benefit of delivered shares from stock based compensation	1,285,000	1,755,000	881,000
Changes in:
Components of working capital	17,081,000	(123,325,000)	81,817,000
Other noncurrent assets	14,740,000	3,933,000	38,716,000
Other noncurrent liabilities	(2,079,000)	21,336,000	27,841,000
Cash flows from operating activities	248,046,000	142,630,000	390,947,000
Expenditures for:
Utility plant	(144,106,000)	(176,067,000)	(140,797,000)
Solar and wind equipment	(149,400,000)	(149,063,000)	(151,002,000)
Real estate properties and other	(2,434,000)	(1,896,000)	(209,000)
Cost of removal	(32,143,000)	(29,066,000)	(28,078,000)
Acquisition of retail and wholesale energy contracts	(55,661,000)	0	0
Investments in equity investees	(27,070,000)	(11,176,000)	(5,780,000)
Distributions from equity investees in excess of equity in earnings	2,749,000	2,351,000	2,620,000
Withdrawal from (payment to) restricted cash construction fund	1,322,000	979,000	(1,499,000)
Proceeds from sale of investment	0	0	3,016,000
Proceeds from sale of property	9,443,000	748,000	0
Proceeds from sale of available for sale securities	6,639,000	0	0
Cash flows (used in) investing activities	(390,661,000)	(363,190,000)	(321,729,000)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Proceeds from long-term debt	100,000,000	275,000,000	250,000,000
Payments of long-term debt	(97,854,000)	(13,289,000)	(37,039,000)
Net proceeds from (payments of) short-term debt	144,300,000	55,350,000	(234,650,000)
Proceeds from sale-leaseback transaction - solar	32,901,000	0	0
Proceeds from sale-leaseback transaction - other	9,587,000	7,107,000	7,216,000
Payments of common stock dividends	(87,988,000)	(82,445,000)	(76,532,000)
Proceeds from issuance of common stock	17,492,000	16,010,000	37,299,000
Purchases of treasury stock	(6,355,000)	(1,008,000)	(10,589,000)
Tax withholding payments related to net settled stock compensation	(4,788,000)	(3,547,000)	(2,146,000)
Cash flows from (used in) financing activities	107,295,000	253,178,000	(66,441,000)
Change in cash and cash equivalents	(35,320,000)	32,618,000	2,777,000
Cash and cash equivalents at beginning of period	37,546,000	4,928,000	2,151,000
Cash and cash equivalents at end of period	2,226,000	37,546,000	4,928,000
CHANGES IN COMPONENTS OF WORKING CAPITAL
Receivables	(56,974,000)	11,303,000	32,529,000
Inventories	3,022,000	(45,986,000)	114,638,000
Recovery of gas costs	(90,000)	(39,642,000)	18,979,000
Gas purchases payable	20,663,000	(11,963,000)	(54,525,000)
Gas purchases payable - related parties	2,000	(411,000)	202,000
Prepaid and accrued taxes	10,366,000	2,385,000	(18,161,000)
Accounts payable and other	13,086,000	(15,656,000)	(14,714,000)
Restricted broker margin accounts	22,570,000	(38,752,000)	18,452,000
Customers’ credit balances and deposits	(5,877,000)	12,044,000	(1,545,000)
Other current assets	10,313,000	3,353,000	(14,038,000)
Components of working capital	17,081,000	(123,325,000)	81,817,000
Cash paid (received) for:
Interest (net of amounts capitalized)	44,362,000	31,996,000	24,208,000
Income taxes	(6,877,000)	(3,516,000)	28,790,000
Accrued capital expenditures	21,769,000	48,881,000	28,676,000
Deferred gain on non-cash exchange of investments	$ 0	$ 0	$ 24,601,000

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
PROPERTY, PLANT AND EQUIPMENT
Utility plant, at cost	$ 2,241,324	$ 2,107,375
Construction work in progress	119,318	122,268
Solar and wind equipment, real estate properties and other, at cost	843,142	631,696
Construction work in progress	7,286	93,791
Total property, plant and equipment	3,211,070	2,955,130
Accumulated depreciation and amortization, utility plant	(489,122)	(467,702)
Accumulated depreciation and amortization, solar and wind equipment, real estate properties and other	(112,207)	(79,776)
Property, plant and equipment, net	2,609,741	2,407,652
CURRENT ASSETS
Cash and cash equivalents	2,226	37,546
Customer accounts receivable:
Billed	196,467	142,658
Unbilled revenues	7,202	5,744
Allowance for doubtful accounts	(5,181)	(4,865)
Regulatory assets	50,791	54,286
Gas in storage, at average cost	202,063	206,251
Materials and supplies, at average cost	11,944	10,778
Prepaid and accrued taxes	24,764	34,179
Derivatives, at fair value	30,081	29,964
Restricted broker margin accounts	25,827	47,644
Asset held for sale	0	7,660
Other current assets	33,260	35,419
Total current assets	579,444	607,264
NONCURRENT ASSETS
Investments in equity investees	172,585	141,148
Regulatory assets	375,919	441,294
Derivatives, at fair value	9,164	5,227
Available for sale securities	65,752	55,789
Intangible assets	41,084	0
Other noncurrent assets	74,818	60,196
Total noncurrent assets	739,322	703,654
Total assets	3,928,507	3,718,570
CAPITALIZATION
Common stock, $2.50 par value; authorized 150,000,000 shares; outstanding September 30, 2017 — 86,555,507; September 30, 2016 — 86,086,355	222,258	221,654
Premium on common stock	219,696	215,580
Accumulated other comprehensive (loss), net of tax	(3,256)	(15,155)
Treasury stock at cost and other; shares September 30, 2017 — 2,347,380; September 30, 2016 — 2,575,139	(70,039)	(81,044)
Retained earnings	867,984	825,556
Common stock equity	1,236,643	1,166,591
Long-term debt	997,080	1,055,038
Total capitalization	2,233,723	2,221,629
CURRENT LIABILITIES
Current maturities of long-term debt	165,375	61,452
Short-term debt	266,000	121,700
Gas purchases payable	160,115	139,452
Gas purchases payable to related parties	1,152	1,150
Accounts payable and other	96,878	107,184
Dividends payable	23,586	21,975
Accrued taxes	2,031	1,080
Regulatory liabilities	78	9,469
New Jersey clean energy program	14,202	14,232
Derivatives, at fair value	46,544	61,080
Customers’ credit balances and deposits	26,957	32,834
Total current liabilities	802,918	571,608
NONCURRENT LIABILITIES
Deferred income taxes	514,708	473,847
Deferred investment tax credits	4,297	4,619
Deferred gain	27,728	28,519
Derivatives, at fair value	11,330	25,252
Manufactured gas plant remediation	149,000	172,000
Postemployment employee benefit liability	128,888	141,604
Regulatory liabilities	14,507	41,411
Asset retirement obligation	31,420	28,379
Other noncurrent liabilities	9,988	9,702
Total noncurrent liabilities	891,866	925,333
Commitments and contingent liabilities
Total capitalization and liabilities	$ 3,928,507	$ 3,718,570

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2017	Sep. 30, 2016
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 2.50	$ 2.50
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	86,555,507	86,086,355
Treasury stock at cost and other (in shares)	2,347,380	2,575,139

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY - USD ($) $ in Thousands		Total		Common Stock	Premium on Common Stock		Accumulated Other Comprehensive (Loss) Income	Treasury Stock And Other		Retained Earnings
Beginning Balance (in shares) at Sep. 30, 2014				84,356,000
Beginning Balance at Sep. 30, 2014		$ 966,166		$ 218,223	$ 199,739		$ (5,594)	$ (121,031)		$ 674,829
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		180,960								180,960
Other comprehensive loss		(3,800)					(3,800)
Common stock issued:
Incentive compensation plan (in shares)				359,000
Incentive compensation plan		5,908		$ 895	5,013
Divident reinvestment plan (in shares)	[1]			1,149,000
Dividend reinvestment plan		27,538	[1]	$ 1,720	6,722	[1]		19,096	[1]
Tax benefits from stock plans		(1,344)			(1,344)
Cash dividend declared ($1.0375 per share in 2017, $.975 per share in 2016, and $.915 per share in 2015)		(78,044)								(78,044)
Treasury stock and other (in shares)				(333,000)
Treasury stock and other		9,572			(199)			9,771
Ending Balance (in shares) at Sep. 30, 2015				85,531,000
Ending Balance at Sep. 30, 2015		$ 1,106,956		$ 220,838	209,931		(9,394)	(92,164)		777,745
Common stock issued:
Dividend Reinvestment Plan waiver discount feature (in shares)		688,000
Net income		$ 131,672								131,672
Other comprehensive loss		(5,761)					(5,761)
Incentive compensation plan (in shares)				325,000
Incentive compensation plan		9,399		$ 816	8,583
Divident reinvestment plan (in shares)	[1]			471,000
Dividend reinvestment plan	[1]	16,063			(2,879)			18,942
Cash dividend declared ($1.0375 per share in 2017, $.975 per share in 2016, and $.915 per share in 2015)		(83,861)								(83,861)
Treasury stock and other (in shares)				(241,000)
Treasury stock and other		$ (7,877)			(55)			(7,822)
Ending Balance (in shares) at Sep. 30, 2016		86,086,355		86,086,000
Ending Balance at Sep. 30, 2016		$ 1,166,591		$ 221,654	215,580		(15,155)	(81,044)		825,556
Common stock issued:
Dividend Reinvestment Plan waiver discount feature (in shares)		0
Net income		$ 132,065								132,065
Other comprehensive loss		11,899					11,899
Incentive compensation plan (in shares)				241,000
Incentive compensation plan		5,694		$ 604	5,090
Divident reinvestment plan (in shares)	[1]			472,000
Dividend reinvestment plan	[1]	17,622			(946)			18,568
Cash dividend declared ($1.0375 per share in 2017, $.975 per share in 2016, and $.915 per share in 2015)		(89,637)								(89,637)
Treasury stock and other (in shares)				(243,000)
Treasury stock and other		$ (7,591)			(28)			(7,563)
Ending Balance (in shares) at Sep. 30, 2017		86,555,507		86,556,000
Ending Balance at Sep. 30, 2017		$ 1,236,643		$ 222,258	$ 219,696		$ (3,256)	$ (70,039)		$ 867,984
Common stock issued:
Dividend Reinvestment Plan waiver discount feature (in shares)		0
[1]	The DRP allows NJR, at its option, to use newly issued shares to raise capital. During fiscal 2015, NJR issued approximately 688,000 new shares through the waiver discount feature of its DRP. There were no new shares issued through the waiver discount feature during fiscal 2016 and fiscal 2017.

CONSOLIDATED STATEMENTS OF COM9

CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Statement of Stockholders' Equity [Abstract]
Cash dividends declared per share (in usd per share)	$ 1.0375	$ 0.975	$ 0.915

NATURE OF THE BUSINESS

NATURE OF THE BUSINESS	12 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF THE BUSINESS	1. NATURE OF THE BUSINESS New Jersey Resources Corporation provides regulated gas distribution services and operates certain unregulated businesses primarily through the following: New Jersey Natural Gas Company provides natural gas utility service to approximately 529,800 retail customers in central and northern New Jersey and is subject to rate regulation by the BPU. NJNG comprises the Natural Gas Distribution segment; NJR Clean Energy Ventures Corporation, the Company’s clean energy subsidiary, comprises the Clean Energy Ventures segment and consists of the Company’s capital investments in commercial and residential solar projects located throughout New Jersey and onshore wind investments in Montana, Iowa, Kansas, Wyoming and Pennsylvania; NJR Energy Services Company and N JR Retail Services Company comprise the Energy Services segment. NJRES maintains and transacts around a portfolio of natural gas storage and transportation capacity contracts and provides physical wholesale energy and energy management services in the U.S. and Canada. N JRRS provides retail natural gas supply and transportation services to commercial and industrial customers in Delaware, Maryland, Pennsylvania and New Jersey; NJR Midstream Holdings Corporation, which comprises the Midstream segment, invests in energy-related ventures through its subsidiaries, NJR Steckman Ridge Storage Company, which holds the Company’s 50 percent combined interest in Steckman Ridge located in Pennsylvania, NJR Pipeline Company, which holds the Company’s 20 percent ownership interest in PennEast and NJNR Pipeline Company, which holds approximately 1.84 million DM Common Units. See Note 7. Investments in Equity Investees for more information; and NJR Retail Holdings Corporation has two principal subsidiaries, NJR Home Services Company, which provides heating, central air conditioning, standby generators, solar and other indoor and outdoor comfort products to residential homes throughout New Jersey, and Commercial Realty & Resources Corporation, which owns commercial real estate. NJR Home Services Company and Commercial Realty & Resources Corporation are included in Home Services and Other operations.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation The Consolidated Financial Statements include the accounts of the Company and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated. Other financial investments or contractual interests that lack the characteristics of a voting interest entity, which are commonly referred to as variable interest entities, are evaluated by the Company to determine if it has the power to direct business activities and, therefore, would be considered a controlling interest that the Company would have to consolidate. Based on those evaluations, NJR has determined that it does not have any investments in variable interest entities as of September 30, 2017 , 2016 and 2015 . Investments in entities over which the Company does not have a controlling financial interest are either accounted for under the equity method or cost method of accounting. Use of Estimates The preparation of financial statements in conformity with GAAP requires the Company to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a monthly basis, the Company evaluates its estimates, including those related to the calculation of the fair value of derivative instruments, debt, unbilled revenues, allowance for doubtful accounts, provisions for depreciation and amortization, regulatory assets and liabilities, income taxes, pensions and other postemployment benefits, contingencies related to environmental matters and litigation. AROs are evaluated as often as needed. The Company’s estimates are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. The Company has legal, regulatory and environmental proceedings during the normal course of business that can result in loss contingencies. When evaluating the potential for a loss, the Company will establish a reserve if a loss is probable and can be reasonably estimated, in which case it is the Company’s policy to accrue the full amount of such estimates. Where the information is sufficient only to establish a range of probable liability, and no point within the range is more likely than any other, it is the Company’s policy to accrue the lower end of the range. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from estimates. Business Combinations The Company accounts for business combinations by applying the acquisition method of accounting. Identifiable assets acquired and liabilities assumed are measured separately at their fair value as of the acquisition date and associated transactions costs are expensed as incurred. The determination and allocation of fair values to the identifiable assets acquired and liabilities assumed are based on various assumptions and valuation methodologies requiring considerable management judgment. The most significant variables in these valuations are discount rates, the number of years on which to base the cash flow projections, as well as other assumptions and estimates used to determine the cash inflows and outflows. Management determines discount rates based on the risk inherent in the acquired assets and related cash flows. Our valuation of an acquired business is based on available information at the acquisition date and assumptions that we believe are reasonable. However, a change in facts and circumstances as of the acquisition date can result in subsequent adjustments during the measurement period, but no later than one year from the acquisition date. See Note 3. Acquisition for information related to the Company’s acquisition of a gas marketing business on July 27, 2017. Regulatory Assets & Liabilities Under cost-based regulation, regulated utility enterprises generally are permitted to recover their operating expenses and earn a reasonable rate of return on their utility investment. Our Natural Gas Distribution segment maintains its accounts in accordance with the FERC Uniform System of Accounts as prescribed by the BPU and in accordance with the Regulated Operations Topic of the FASB ASC. As a result of the impact of the ratemaking process and regulatory actions of the BPU, NJNG is required to recognize the economic effects of rate regulation. Accordingly, NJNG capitalizes or defers certain costs that are expected to be recovered from its customers as regulatory assets and recognizes certain obligations representing probable future expenditures as regulatory liabilities on the Consolidated Balance Sheets. See Note 4. Regulation for a more detailed description of NJNG’s regulatory assets and liabilities. Gas in Storage Gas in storage is reflected at average cost on the Consolidated Balance Sheets, and represents natural gas and LNG that will be utilized in the ordinary course of business. The following table summarizes gas in storage, at average cost by company, as of September 30 : 2017 2016 ($ in thousands) Gas in Storage Bcf Gas in Storage Bcf Energy Services $ 122,884 53.9 $ 130,493 62.0 Natural Gas Distribution 79,179 21.8 75,758 21.3 Total $ 202,063 75.7 $ 206,251 83.3 Demand Fees For the purpose of securing storage and pipeline capacity in support of their respective businesses, our Energy Services and Natural Gas Distribution segments enter into storage and pipeline capacity contracts, which require the payment of associated demand fees and charges that allow them access to a high priority of service in order to maintain the ability to access storage or pipeline capacity during a fixed time period, which generally ranges from one to 10 years. Many of these demand fees and charges are based on established tariff rates as established and regulated by FERC. These charges represent commitments to pay storage providers and pipeline companies for the priority right to transport and/or store natural gas utilizing their respective assets. The following table summarizes the demand charges, which are net of capacity releases, and are included as a component of gas purchases on the Consolidated Statements of Operations for the fiscal years ended September 30: (Millions) 2017 2016 2015 Energy Services $ 126.4 $ 141.0 $ 130.6 Natural Gas Distribution 80.2 77.8 80.5 Total $ 206.6 $ 218.8 $ 211.1 Energy Services expenses demand charges ratably over the term of the service being provided. Our Natural Gas Distribution segment’s costs associated with demand charges are included in its weighted average cost of gas. The demand charges are expensed based on NJNG’s BGSS sales and recovered as part of its gas commodity component of its BGSS tariff. Derivative Instruments The Company accounts for its financial instruments, such as futures, options, foreign exchange contracts, interest rate contracts, as well as its physical commodity contracts related to the purchase and sale of natural gas at Energy Services, as derivatives, and therefore recognizes them at fair value on the Consolidated Balance Sheets. The Company’s unregulated subsidiaries record changes in the fair value of their financial commodity derivatives in gas purchases and changes in the fair value of their physical forward contracts in gas purchases or operating revenues, as appropriate, on the Consolidated Statements of Operations. Energy Services designated its foreign exchange contracts, entered into prior to January 1, 2016, as cash flow hedges of Canadian dollar denominated gas purchases. Changes in the fair value of the effective portion of these hedges are recorded to AOCI, a component of stockholders’ equity, and reclassified to gas purchases on the Consolidated Statements of Operations when they settle. Ineffective portions of the cash flow hedges are recognized immediately in earnings. The Company did not have derivatives designated as fair value hedges during fiscal 2016 and 2017 . The Derivatives and Hedging Topic of the ASC also provides for a NPNS scope exception for qualifying physical commodity contracts that are intended for purchases and sales during the normal course of business and for which physical delivery is probable. Effective January 1, 2016, the Company prospectively applies this normal scope exception on a case-by-case basis to physical commodity contracts at NJNG and forward SREC contracts at Clean Energy Ventures. When applied, it does not record changes in the fair value of these contracts until the contract settles and the related underlying natural gas or SREC is delivered. Gains and/or losses on NJNG’s derivatives used to economically hedge its regulated natural gas supply obligations, as well as its exposure to interest rate variability, are recoverable through its BGSS, a component of its tariff. Accordingly, the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability on the Consolidated Balance Sheets. See Note 5. Derivative Instruments for additional details regarding natural gas trading and hedging activities. Fair values of exchange-traded instruments, including futures, swaps, and certain options, are based on unadjusted, quoted prices in active markets. The Company’s non-exchange-traded financial instruments, foreign currency derivatives, over-the-counter physical commodity contracts at Energy Services and NJNG’s Treasury Lock are valued using observable, quoted prices for similar or identical assets when available. In establishing the fair value of contracts for which a quoted basis price is not available at the measurement date, management utilizes available market data and pricing models to estimate fair values. Fair values are subject to change in the near term and reflect management’s best estimate based on a variety of factors. Estimating fair values of instruments that do not have quoted market prices requires management’s judgment in determining amounts that could reasonably be expected to be received from, or paid to, a third party in settlement of the instruments. These amounts could be materially different from amounts that might be realized in an actual sale transaction. Revenues Revenues from the sale of natural gas to NJNG customers are recognized in the period that gas is delivered and consumed by customers, including an estimate for unbilled revenue. NJNG records unbilled revenue for natural gas services. Natural gas sales to individual customers are based on meter readings, which are performed on a systematic basis throughout the month. At the end of each month, the amount of natural gas delivered to each customer after the last meter reading through the end of the respective accounting period is estimated, and recognizes unbilled revenues related to these amounts. The unbilled revenue estimates are based on estimated customer usage by customer type, weather effects, unaccounted-for gas and the most current tariff rates. Clean Energy Ventures recognizes revenue when SRECs are transferred to counterparties. SRECs are physically delivered through the transfer of certificates as per contractual settlement schedules. Revenues for Energy Services are recognized when the natural gas is physically delivered to the customer. In addition, changes in the fair value of derivatives that economically hedge the forecasted sales of the natural gas are recognized in operating revenues as they occur, as noted above. Energy Services also recognizes changes in the fair value of SREC derivative contracts as a component of operating revenues. Revenues from all other activities are recorded in the period during which products or services are delivered and accepted by customers, or over the related contractual term. Gas Purchases NJNG’s tariff includes a component for BGSS, which is designed to allow it to recover the cost of natural gas through rates charged to its customers and is typically revised on an annual basis. As part of computing its BGSS rate, NJNG projects its cost of natural gas, net of supplier refunds, the impact of hedging activities and cost savings created by BGSS incentive programs. NJNG subsequently recovers or credits the difference, if any, of actual costs compared with those included in current rates. Any underrecoveries or overrecoveries are either credited to customers or deferred and, subject to BPU approval, reflected in the BGSS rates in subsequent years. Gas purchases at Energy Services are comprised of gas costs to be paid upon completion of a variety of transactions, as well as realized gains and losses from settled derivative instruments and unrealized gains and losses on the change in fair value of derivative instruments that have not yet settled. Changes in the fair value of derivatives that economically hedge the forecasted purchases of natural gas are recognized in gas purchases as they occur. Income Taxes The Company computes income taxes using the asset and liability method, whereby deferred income taxes are generally determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. See Note 13. Income Taxes . In addition, the Company evaluates its tax positions to determine the appropriate accounting and recognition of future obligations associated with unrecognized tax benefits. The Company invests in property that qualifies for federal ITCs and utilizes the ITCs, as allowed, based on the cost and life of the assets. ITCs at NJNG are deferred and amortized as a reduction to the tax provision over the average lives of the related equipment in accordance with regulatory treatment. ITCs at NJR’s unregulated subsidiaries are recognized as a reduction to income tax expense when the property is placed in service. The Company invests in property that qualifies for PTCs. PTCs are recognized as reductions to current federal income tax expense as PTCs are generated through the production activities of the assets. Changes to the federal statutes related to ITCs and PTCs, which have the effect of reducing or eliminating the credits, could have a negative impact on earnings and cash flows. Capitalized and Deferred Interest NJNG’s base rates include the ability to recover AFUDC on its construction work in progress. For all NJNG construction projects, an incremental cost of equity is recoverable during periods when NJNG’s short-term debt balances are lower than its construction work in progress. For more information on AFUDC treatment with respect to certain accelerated infrastructure projects, see Note 4. Regulation - Infrastructure programs. Capitalized amounts associated with the debt and equity components of NJNG’s AFUDC are recorded in utility plant on the Consolidated Balance Sheets. Corresponding amounts for the debt component is recognized in interest expense and in other income for the equity component on the Consolidated Statements of Operations and include the following for the fiscal years ended September 30: ($ in thousands) 2017 2016 2015 AFUDC: Debt $ 1,311 $ 5,009 $ 2,472 Equity 3,867 4,375 3,825 Total $ 5,178 $ 9,384 $ 6,297 Weighted average interest rate 6.90 % 5.06 % 4.63 % Pursuant to a BPU order, NJNG is permitted to recover carrying costs on uncollected balances related to SBC program costs, which include NJCEP, RAC and USF expenditures. See Note 4. Regulation . The SBC interest rate changes each September based on the August 31 seven -year constant maturity Treasury rate plus 60 basis points . The rate was 2.55 percent , 2.05 percent and 2.54 percent for the fiscal years ended September 30, 2017 , 2016 and 2015 , respectively. Accordingly, other income included $78,000 , $54,000 and $61,000 in the fiscal years ended September 30, 2017 , 2016 and 2015 , respectively. Sale-Leasebacks The Company utilizes sale-leaseback arrangements to fund certain of its capital expenditures, whereby the physical asset is sold concurrent with an agreement to lease the asset back, with options that allow the Company to renew the lease at the end of the term or repurchase the asset. Proceeds from sale-leaseback transactions are included in long-term debt on the Consolidated Balance Sheets. For certain of its commercial solar energy projects, the Company enters into lease agreements that provide for the sale of commercial solar energy assets to third-parties and the concurrent leaseback of the assets. For sale-leaseback transactions where the Company has concluded that the terms of the arrangement create a continuing involvement in the asset and the asset is considered integral equipment, the Company uses the financing method to account for the transaction. Under the financing method, the Company recognizes the proceeds received from the lessor that constitute a payment to acquire the solar energy asset as a financing arrangement, which is recorded as a component of debt on the Consolidated Balance Sheets. During fiscal 2017 and 2016 , NJNG received $9.6 million and $7.1 million , respectively, in connection with the sale-leaseback of its natural gas meters with terms ranging from seven to 11 years. In September 2017, Clean Energy Ventures received $32.9 million in proceeds related to the sale of two commercial solar assets. Clean Energy Ventures simultaneously entered into an agreement to lease the assets back over seven -year terms. The Company will continue to operate the solar assets including related expenses and retain the revenue generated from SRECs and energy sales. The ITCs and other tax benefits associated with these solar projects were transferred to the buyer, however, the lease payments are structured so that Clean Energy Ventures is compensated for the transfer of the related tax incentives. Accordingly, Clean Energy Ventures will recognize the equivalent value of the ITC in other income on the Consolidated Statements of Operations over the respective five-year ITC recapture periods that are recognized as the recapture periods expire, starting at the beginning of the second year of the lease. There were no sale-leaseback transactions at Clean Energy Ventures during fiscal 2016. Sales Tax Accounting Sales tax that is collected from customers is presented in both operating revenues and operating expenses on the Consolidated Statements of Operations. During fiscal 2017 , 2016 and 2015 , sales tax collected was $39.4 million , $31 million and $44.1 million , respectively. Effective January 1, 2017, the New Jersey sales tax rate decreased from 7 percent to 6.875 percent . Cash and Cash Equivalents Cash and cash equivalents consist of cash on deposit and temporary investments with maturities of three months or less, and excludes restricted cash of $243,000 and $1.6 million as of September 30, 2017 and 2016 , respectively, related to escrow balances for utility plant projects, which is recorded in other current and noncurrent assets on the Consolidated Balance Sheets. Property Plant and Equipment Regulated property, plant and equipment and solar and wind equipment are stated at original cost. Regulated property, plant and equipment costs include direct labor, materials and third-party construction contractor costs, AFUDC and certain indirect costs related to equipment and employees engaged in construction. Upon retirement, the cost of depreciable regulated property, plus removal costs less salvage, is charged to accumulated depreciation with no gain or loss recorded. Depreciation is computed on a straight-line basis over the useful life of the assets for unregulated assets, and using rates based on the estimated average lives of the various classes of depreciable property for NJNG. The composite rate of depreciation used for NJNG was 2.25 percent of average depreciable property in fiscal 2017 , 2.32 percent in fiscal 2016 and 2.31 percent in fiscal 2015 . The Company recorded $81.8 million , $72.7 million and $61.4 million in depreciation expense during fiscal 2017 , 2016 and 2015 , respectively. Effective October 1, 2016, the overall depreciation rate is 2.4 percent , as settled in the base rate case. Property, plant and equipment was comprised of the following as of September 30 : (Thousands) Property Classifications Estimated Useful Lives 2017 2016 Distribution facilities 38 to 74 years $ 1,952,697 $ 1,823,672 Transmission facilities 35 to 56 years 294,586 292,433 Storage facilities 34 to 47 years 78,245 78,238 Solar property 20 to 25 years 587,345 479,948 Wind property 25 years 244,764 228,644 All other property 5 to 35 years 53,433 52,195 Total property, plant and equipment 3,211,070 2,955,130 Accumulated depreciation and amortization (601,329 ) (547,478 ) Property, plant and equipment, net $ 2,609,741 $ 2,407,652 On March 8, 2017 , CR&R sold a 56,400 square foot office building on five acres of land located in Monmouth County for $9.4 million , net of closing costs, generating a pre-tax gain of $1.9 million , which was recognized as a reduction to O&M on the Consolidated Statements of Operations. Intangible Assets Finite-lived intangible assets are stated at cost less accumulated amortization. The Company amortizes intangible assets based upon the pattern in which the economic benefits are consumed over the life of the asset unless a pattern cannot be reliably determined, in which case the Company uses a straight-line amortization method. As of September 30, 2017, the Company has an intangible asset, net of amortization, of $41.1 million related to its acquisition of Talen's wholesale natural gas energy contracts. These contracts are being amortized based upon expected cash flows over the respective terms of the agreements. The estimated future amortization expense for the next five years as of September 30, is as follows: (Thousands) 2018 $ 18,222 2019 $ 8,424 2020 $ 4,925 2021 $ 4,604 2022 $ 2,561 Thereafter $ 2,348 See Note 3. Acquisition for more information about the acquisition of Talen's gas marketing business. Long-lived Assets The Company reviews the recoverability of long-lived assets and finite-lived intangible assets whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. If there are changes indicating that the carrying value of such assets may not be recoverable, an undiscounted cash flows test is performed. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, an impairment loss is recognized by reducing the recorded value of the asset to its fair value. During the year, there were no events or circumstances that indicated that the carrying value of assets is not recoverable. Investments in Equity Investees The Company accounts for its investments in Steckman Ridge, PennEast and Iroquois (through September 29, 2015), using the equity method of accounting, where its respective ownership interests are 50 percent or less and/or it has significant influence over operating and management decisions, but is not the primary beneficiary, as defined under ASC 810, Consolidation . The Company’s share of earnings is recognized as equity in earnings of affiliates on the Consolidated Statements of Operations. See Note 7. Investments in Equity Investees for more information. Available for Sale Securities The Company had investments in two publicly traded energy companies that have a fair value of $65.8 million and $55.8 million as of September 30, 2017 and 2016 , respectively, which are included in available for sale securities on the Consolidated Balance Sheets. Total unrealized gains associated with these investments are included as a part of accumulated other comprehensive income, a component of common stock equity, and were $18.4 million , $11 million after tax, and $7.2 million , $4.2 million after tax, as of September 30, 2017 and 2016 , respectively. During fiscal 2017 , the Company received proceeds of approximately $6.6 million from the sale of available for sale securities and realized a pre-tax gain of approximately $5.4 million , which is included in other income, net on the Consolidated Statements of Operations. Reclassifications of realized gains out of other comprehensive income into income are determined based on average cost. There were no sales of securities during fiscal 2016 . Customer Accounts Receivable and Allowance for Doubtful Accounts Receivables consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers, as well as equipment sales, installations, solar leases and PPAs to commercial and residential customers. The Company evaluates its accounts receivables and, to the extent customer account balances are outstanding for more than 60 days , establishes an allowance for doubtful accounts. The allowance is based on a combination of factors including historical collection experience and trends, aging of receivables, general economic conditions in the company’s distribution or sales territories, and customer specific information. The Company writes-off customers’ accounts once it is determined they are uncollectible. The following table summarizes customer accounts receivable by company as of September 30 : (Thousands) 2017 2016 Energy Services $ 150,322 77 % $ 102,884 72 % NJNG (1) 37,432 19 30,951 22 Clean Energy Ventures 2,655 1 1,807 1 NJRHS and other 6,058 3 7,016 5 Total $ 196,467 100 % $ 142,658 100 % (1) Does not include unbilled revenues of $7.2 million and $5.7 million as of September 30, 2017 and 2016 , respectively. Loans Receivable NJNG currently provides loans, with terms ranging from three to 10 years, to customers that elect to purchase and install certain energy efficient equipment in accordance with its BPU-approved SAVEGREEN program. The loans are recognized at net present value on the Consolidated Balance Sheets. Refer to Note 6. Fair Value for a discussion of the Company’s fair value measurement policies and level disclosures. The Company has recorded $8.9 million and $7.8 million in other current assets and $40.4 million and $39.5 million in other noncurrent assets as of September 30, 2017 and 2016 , respectively, on the Consolidated Balance Sheets, related to the loans. NJNG’s policy is to establish an allowance for doubtful accounts when loan balances are in arrears for more than 60 days . There was no allowance for doubtful accounts established for the SAVEGREEN loans during fiscal 2017 and 2016 . Asset Retirement Obligations The Company recognizes a liability for its AROs based on the fair value of the liability when incurred, which is generally upon acquisition, construction, development and/or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost by increasing the carrying amount of the related asset by the same amount as the liability. In periods subsequent to the initial measurement, the Company is required to recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either timing or the amount of the originally estimated cash flows to settle the conditional ARO. Pension and Postemployment Plans The Company has two noncontributory defined pension plans covering eligible employees, including officers. Benefits are based on each employee’s years of service and compensation. The Company’s funding policy is to contribute annually to these plans at least the minimum amount required under Employee Retirement Income Security Act, as amended, and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments. The Company made a discretionary contribution of $30 million during the first quarter of fiscal 2016 to improve the funded status of the pension plans based on the current actuarial assumptions, which included the adoption of the most recent mortality table. The Company made no discretionary contributions to the pension plans in fiscal 2017 and 2015 . The Company also provides two primarily noncontributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. The Company contributed $6 million , $3.2 million and $5.7 million in aggregate to these plans in fiscal 2017 , 2016 and 2015 , respectively. See Note 11. Employee Benefit Plans , for a more detailed description of the Company’s pension and postemployment plans. Accumulated Other Comprehensive Income The following table presents the changes in the components of accumulated other comprehensive income, net of related tax effects, as of September 30 : (Thousands) Unrealized gain (loss) on available for sale securities Net unrealized gain (loss) on derivatives Adjustment to postemployment benefit obligation Total Balance as of September 30, 2015 $ 6,385 $ — $ (15,779 ) $ (9,394 ) Other comprehensive income, net of tax Other comprehensive (loss), before reclassifications, net of tax of $1,499, $10, $3,164, $4,673 (2,187 ) (17 ) (4,600 ) (6,804 ) Amounts reclassified from accumulated other comprehensive income, net of tax of $0, $(10), $(698), $(708) — 17 (1) 1,026 (2) 1,043 Net current-period other comprehensive (loss), net of tax of $1,499, $0, $2,466, $3,965 (2,187 ) — (3,574 ) (5,761 ) Balance at September 30, 2016 $ 4,198 $ — $ (19,353 ) $ (15,155 ) Other comprehensive income, net of tax Other comprehensive income, before reclassifications, net of tax of $(6,593), $0, $(2,619), $(9,212) 10,019 — 3,783 13,802 Amounts reclassified from accumulated other comprehensive (loss) income, net of tax of $2,192, $0, $(868), $1,324 (3,173 ) — (1) 1,270 (2) (1,903 ) Net current-period other comprehensive income, net of tax of $(4,401), $0, $(3,487), $(7,888) 6,846 — 5,053 11,899 Balance at September 30, 2017 $ 11,044 $ — $ (14,300 ) $ (3,256 ) (1) Consists of realized losses related to foreign currency derivatives, which are reclassified to gas purchases on the Consolidated Statements of Operations. (2) Included in the computation of net periodic pension cost, a component of O&M expense on the Consolidated Statements of Operations. For more details, see Note 11. Employee Benefit Plans . Foreign Currency Transactions Energy Services’ market area includes Canadian delivery points and as a result, Energy Services incurs certain natural gas commodity costs and demand fees denominated in Canadian dollars. Gains or losses that occur as a result of these foreign currency transactions are reported as a component of gas purchases on the Consolidated Statements of Operations and were not material during the fiscal years ended September 30, 2017 , 2016 and 2015 . Recently Adopted Updates to the Accounting Standards Codification Stock Compensation In June 2014, the FASB issued ASU No. 2014-12, an amendment to ASC 718, Compensation - Stock Compensation , which clarifies the accounting for performance awards when the terms of the award provide that a performance target could be achieved after the requisite service period. The Company adopted the new guidance in the first quarter of fiscal 2017 and applied the new provisions on a prospective basis, which did not impact its financial position, results of operations or cash flows upon adoption. Consolidation In February 2015, the FASB issued ASU No. 2015-02, an amendment to ASC 810, Consolidation , which changes the consolidation analysis required under GAAP and reevaluates whether limited partnerships and similar entities must be consolidated. The Company adopted the new guidance in the first quarter of fiscal 2017 and applied the new provisions on a full retrospective basis, which did not impact its financial position, results of operations or cash flows upon adoption. Interest In April 2015, the FASB issued ASU No. 2015-03, an amendment to ASC 835, Interest - Imputation of Interest, which simplifies the presentation of debt issuance costs by requiring them to be presented on the balance sheet as a deduction from the carrying amount of the liability. The amendment does not affect the recognition and measurement guidance for debt issuance costs. In August 2015, the FASB issued ASU No. 2015-15, which clarified that the amendment contained within ASU No. 2015-03 does not require companies to modify their accounting for costs incurr

ACQUISITION

ACQUISITION	12 Months Ended
	Sep. 30, 2017
Business Combinations [Abstract]
ACQUISITION	3. ACQUISITION On July 27, 2017 , NJR, through its wholly owned subsidiary NJRRS, signed an asset purchase agreement with Talen to acquire certain of their retail and wholesale natural gas energy contract assets. The acquisition included sales agreements with large commercial and industrial retail customers, pipeline and storage capacity agreements on various pipelines, and various wholesale transportation contracts. The final purchase price totaled $55.7 million upon satisfaction of certain conditions as set forth in the asset purchase agreement. The following table summarizes the purchase price allocation for the fair value of the assets acquired and liabilities assumed as of July 27, 2017 : (Thousands) Estimated Fair Value Total purchase price consideration transferred $ 55,661 Identifiable assets acquired Wholesale energy contracts (1) $ 41,846 Retail energy contracts (2) 13,815 Net assets acquired $ 55,661 (1) Wholesale energy contracts are presented within Intangible assets, net on the Consolidated Balance Sheets. (2) Retail energy contracts are presented within the Derivatives, at fair value line items on the Consolidated Balance Sheets. The purchase price equaled the estimated fair value of the net assets acquired and, therefore, no goodwill or bargain purchase was recorded as of September 30, 2017. Identifiable assets were recorded at their estimated fair value as determined by management and were based upon significant estimates and assumptions that are judgmental in nature, including the projected amount and timing of future cash flows, a discount rate reflecting risk inherent in the future cash flows and future natural gas prices. During fiscal 2017, the Company incurred approximately $300,000 in acquisition related transaction costs, which are recorded in operations and maintenance expense on the Consolidated Statements of Operations. The useful lives of the acquired assets are based upon the terms of the contractual arrangements. The acquired wholesale energy contracts have useful lives ranging from 1 to 9 years, and the acquired retail energy contracts have useful lives ranging from 0 to 4 years. The acquisition date fair value of the wholesale contracts is presented as an intangible asset on the Consolidated Balance Sheet and is amortized based upon the pattern of expected future cash flows. The related amortization expense totaled $762,000 during fiscal 2017, and is included in gas purchases on the Consolidated Statements of Operations. The acquired retail contracts consist of natural gas physical forward sales agreements and therefore are subsequently measured and accounted for in accordance with ASC 815, Derivatives and Hedging . Accordingly, the acquisition date fair value of the retail contracts is presented within the Derivatives, at fair value line items on the Consolidated Balance Sheets and is relieved in subsequent periods as the underlying physical forward contracts settle. During fiscal 2017, operating revenues of approximately $20.5 million , and operating income of approximately $281,000 attributable to the acquisition are included in the Consolidated Statements of Operations. As the assets were acquired from a non-public company that did not prepare financial information for the specific assets involved in the transaction, historical financial information was impracticable to obtain. As a result, pro forma results for the acquired assets are not presented.

REGULATION

REGULATION	12 Months Ended
	Sep. 30, 2017
Regulated Operations [Abstract]
REGULATION	4. REGULATION The EDECA is the legal framework for New Jersey’s public utility and wholesale energy landscape. NJNG is required, pursuant to a written order by the BPU under EDECA, to open its residential markets to competition from third-party natural gas suppliers. Customers can choose the supplier of their natural gas commodity in NJNG’s service territory. As required by EDECA, NJNG’s rates are segregated into two primary components the commodity portion, which represents the wholesale cost of natural gas, including the cost for interstate pipeline capacity to transport the gas to NJNG’s service territory, and the delivery portion, which represents the transportation of the commodity portion through NJNG’s gas distribution system to the end-use customer. NJNG does not earn utility gross margin on the commodity portion of its natural gas sales. NJNG earns utility gross margin through the delivery of natural gas to its customers, regardless of whether it or a third-party supplier provides the wholesale natural gas commodity. Under EDECA, the BPU is required to audit the state’s energy utilities every two years. The primary purpose of the audit is to ensure that utilities and their affiliates offering unregulated retail services do not have an unfair competitive advantage over nonaffiliated providers of similar retail services. A combined competitive services and management audit of NJNG commenced in August 2013 . A draft management audit report was accepted by the BPU on July 23, 2014, for public comment. To date, NJNG has implemented all audit recommendations with the approval of BPU staff and is waiting for final BPU approval. NJNG is subject to cost-based regulation, therefore, it is permitted to recover authorized operating expenses and earn a reasonable return on its utility capital investments based on the BPU’s approval. The impact of the ratemaking process and decisions authorized by the BPU allows NJNG to capitalize or defer certain costs that are expected to be recovered from its customers as regulatory assets, and to recognize certain obligations representing amounts that are probable future expenditures as regulatory liabilities in accordance with accounting guidance applicable to regulated operations. NJNG’s recovery of costs is facilitated through its base rates, BGSS and other regulatory tariff riders. NJNG is required to make an annual filing to the BPU by June 1 of each year for review of its BGSS, CIP and other programs and related rates. Annual rate changes are requested to be effective at the beginning of the following fiscal year. In addition, NJNG is permitted to request approval of certain rate or program changes on an interim basis. All rate and program changes are subject to proper notification and BPU review and approval. In September 2016 , the BPU approved NJNG's base rate case, effective October 2016 , which included an increase in base rates in the amount of $45 million . The base rate increase includes a return on common equity of 9.75 percent , a common equity ratio of 52.5 percent and a depreciation rate of 2.4 percent . The approval also included the rate mechanism and five -year extension of SAFE II, rate recovery of NJ RISE capital investment costs through June 30, 2016, recovery of NJNG’s SAFE I, NGV and LNG capital investments and recovery of other costs previously deferred in regulatory assets. Regulatory assets and liabilities included on the Consolidated Balance Sheets as of September 30, are comprised of the following: (Thousands) 2017 2016 Regulatory assets-current Conservation Incentive Program $ 17,669 $ 36,957 New Jersey Clean Energy Program 14,202 14,232 Underrecovered gas costs 9,910 — Derivatives at fair value, net 9,010 3,097 Total current regulatory assets $ 50,791 $ 54,286 Regulatory assets-noncurrent Environmental remediation costs: Expended, net of recoveries $ 28,547 $ 19,595 Liability for future expenditures 149,000 172,000 Deferred income taxes 21,795 20,273 Derivatives at fair value, net — 23,384 SAVEGREEN 16,302 25,208 Postemployment and other benefit costs 141,433 157,027 Deferred Superstorm Sandy costs 13,030 15,201 Other noncurrent regulatory assets 5,812 8,606 Total noncurrent regulatory assets $ 375,919 $ 441,294 Regulatory liability-current Derivatives at fair value, net 78 — Overrecovered gas costs — 9,469 Total current regulatory liabilities $ 78 $ 9,469 Regulatory liabilities-noncurrent Cost of removal obligation $ 7,902 $ 30,549 New Jersey Clean Energy Program 5,795 10,657 Other noncurrent regulatory liabilities 664 205 Derivatives at fair value, net 146 — Total noncurrent regulatory liabilities $ 14,507 $ 41,411 Recovery of regulatory assets is subject to BPU approval, and therefore, if there are any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to income in the period of such determination. The BPU’s decision and order approving NJNG’s new base rates resulted in no changes to the recovery of NJNG’s regulatory assets. Conservation Incentive Program The CIP permits NJNG to recover utility gross margin variations related to customer usage resulting from customer conservation efforts and mitigates the impact of weather on its gross margin. Such utility gross margin variations are recovered in the year following the end of the CIP usage year, without interest, and are subject to additional conditions, including an earnings test, a revenue test and an evaluation of BGSS related savings. This program has no expiration date. New Jersey Clean Energy Program The NJCEP is a statewide program that encourages energy efficiency and renewable energy. Funding amounts are determined by the BPU’s Office of Clean Energy and all New Jersey utilities are required to share in the annual funding obligation. The current NJCEP program is for the State of New Jersey’s fiscal year ending June 2018 . NJNG recovers the costs associated with its portion of the NJCEP obligation through its NJCEP rider. Derivatives Derivatives are utilized by NJNG to manage the price risk associated with its natural gas purchasing activities and to participate in certain BGSS incentive programs. The gains and losses associated with NJNG’s derivatives are recoverable through its BGSS, as noted above, without interest. See Note 5. Derivative Instruments . Environmental Remediation Costs NJNG is responsible for the cleanup of certain former gas manufacturing facilities. Actual expenditures are recovered from customers, with interest, over seven year rolling periods, through a RAC rate rider. Recovery for NJNG’s estimated future liability will be requested and/or recovered when actual expenditures are incurred. See Note 14. Commitments and Contingent Liabilities . Deferred Income Taxes In 1993, NJNG adopted the provisions of ASC 740, Income Taxes , which changed the method used to determine deferred tax assets and liabilities. Upon adoption, NJNG recognized a transition adjustment and corresponding regulatory asset representing the difference between NJNG’s existing deferred tax amounts compared with the deferred tax amounts calculated in accordance with the change in method prescribed by ASC 740. NJNG recovers the regulatory asset associated with these tax impacts through future base rates, without interest. SAVEGREEN NJNG administers certain programs that supplement the state’s NJCEP and that allow NJNG to promote clean energy to its residential and commercial customers, as described further below. NJNG will recover related expenditures and a weighted average cost of capital on the unamortized balance through a tariff rider, as approved by the BPU, over a two to 10 -year period depending upon the specific program incentive. Postemployment and Other Benefit Costs Postemployment and Other Benefit Costs represents NJNG’s underfunded postemployment benefit obligations that the Company began recognizing in fiscal 2006, as a result of changes in the accounting provisions of ASC 715, Compensation and Benefits , as well as a $2.4 million fiscal 2010 tax charge resulting from a change in the deductibility of federal subsidies associated with Medicare Part D, both of which are deferred as regulatory assets and are recoverable, without interest, in base rates. In the September 2016 base rate case decision and order, the BPU approved the recovery of the tax charge over a seven -year amortization period. See Note 11. Employee Benefit Plans . Deferred Superstorm Sandy Costs In October 2012, portions of NJNG’s distribution system incurred significant damage as a result of Superstorm Sandy. NJNG filed a petition with the BPU in November 2012 requesting deferred accounting for uninsured incremental O&M costs associated with its restoration efforts, which was approved in May 2013. In October 2014, the BPU approved, as prudent and reasonable, the deferred O&M storm costs. The deferred Superstorm Sandy costs were approved for recovery through NJNG’s new base rates effective October 2016 , over a seven -year amortization period. Other Regulatory Assets Other regulatory assets consists primarily of deferred costs associated with certain components of NJNG’s SBC, as discussed further below, and NJNG’s compliance with federal and state mandated PIM provisions. NJNG’s related costs to maintain the operational integrity of its distribution and transmission main are recoverable, subject to BPU review and approval. Through September 30, 2016, NJNG was limited to recording a regulatory asset associated with PIM that did not exceed $700,000 per year. In addition, to the extent that project costs were lower than the approved PIM annual expense of $1.4 million , NJNG recorded a regulatory liability to be refunded as a credit to customers’ gas costs when the net cumulative liability exceeded $1 million . As of September 30, 2017 , NJNG recorded $3.8 million of PIM in other regulatory assets. The deferred PIM costs were approved for recovery through NJNG’s new base rates effective October 2016 , over a seven -year amortization period. As of October 1, 2016, NJNG will no longer defer costs associated with PIM. Over and Underrecovered Gas Costs NJNG recovers its cost of gas through the BGSS rate component of its customers’ bills. NJNG’s cost of gas includes the purchased cost of the natural gas commodity, fees paid to pipelines and storage facilities, adjustments as a result of BGSS incentive programs and hedging transactions. Overrecovered gas costs represent a regulatory liability that generally occurs when NJNG’s BGSS rates are higher than actual costs and requests approval to be returned to customers including interest, when applicable, in accordance with NJNG’s approved BGSS tariff. Conversely, underrecovered gas costs generally occur during periods when NJNG’s BGSS rates are lower than actual costs, in which case NJNG records a regulatory asset and requests amounts to be recovered from customers in the future. Cost of Removal Obligation NJNG accrues and collects for cost of removal in base rates on its utility property, without interest. NJNG’s regulatory liability represents customer collections in excess of actual expenditures, which the Company will return to customers as a reduction to depreciation expense until it is depleted. The following is a description of certain regulatory proceedings during fiscal 2016 and 2017 : BGSS and CIP BGSS rates are normally revised on an annual basis. In addition, to manage the fluctuations in wholesale natural gas costs, NJNG has the ability to make two interim filings during each fiscal year to increase residential and small commercial customer BGSS rates on a self-implementing and provisional basis. NJNG is also permitted to refund or credit back a portion of the commodity costs to customers at any time given five days notice when the natural gas commodity costs decrease in comparison to amounts projected or to amounts previously collected from customers. Concurrent with the annual BGSS filing, NJNG files for an annual review of its CIP. NJNG’s annual BGSS and CIP filings are summarized as follows: • June 2015 BGSS/CIP filing — In February 2016 , the BPU approved NJNG’s proposal to continue its existing BGSS rate and to increase its CIP rates resulting in a $1.1 million annual recovery increase, effective October 2015 . NJNG also provided bill credits to residential and small commercial customers from November 2015 through February 2016, as a result of the decline in the wholesale price of natural gas, which totaled $61.6 million . • June 2016 BGSS/CIP filing — In September 2016 , the BPU approved NJNG's filing to increase its CIP rates resulting in a $43.9 million annual recovery increase and to decrease its annual BGSS rate for residential and small commercial customers resulting in a $22.6 million annual recovery decrease, effective October 2016 . This petition also included proposed bill credits to residential and small commercial customers during the months of November 2016 through February 2017, as a result of a decline in the wholesale price of natural gas. In September 2016 , NJNG notified the BPU that the estimated bill credits would be approximately $48 million ; however, customer usage was lower due to warmer weather during winter months and therefore, a total of $42 million in bill credits were issued during fiscal 2017. • June 2017 BGSS/CIP filing — On September 22, 2017 , the BPU provisionally approved NJNG's petition to maintain its BGSS rate for residential and small commercial customers, increase its balancing charge rate, which will result in a $3.7 million increase to the annual revenues credited to BGSS and decrease its CIP rates, which will result in a $16.2 million annual recovery decrease, effective October 2017 . BGSS Incentive Programs NJNG is eligible to receive financial incentives for reducing BGSS costs through a series of utility gross margin-sharing programs that include off-system sales, capacity release, storage incentive programs and the FRM program (through October 2015). The Company is permitted to annually propose a process to evaluate and discuss alternative incentive programs, should performance of the existing incentives or market conditions warrant re-evaluation. In October 2015 , the BPU issued an order approving the continuation of the BGSS Incentive Programs with modification to the storage incentive program, beginning with the 2015 storage injection period, and termination of the FRM Program, effective November 2015 . Energy Efficiency Programs SAVEGREEN conducts home energy audits and provides various grants, incentives and financing alternatives, which are designed to encourage the installation of high efficiency heating and cooling equipment and other energy efficiency upgrades to promote energy efficiency incentives to its residential and commercial customers while stimulating state and local economies through the creation of jobs. Depending on the specific initiative or approval, NJNG recovers costs associated with the programs over a two to 10 -year period through a tariff rider mechanism. As of September 30, 2017 , the BPU has approved total SAVEGREEN investments of approximately $219.3 million , of which, $149.7 million in grants, rebates and loans have been provided to customers, with a total annual recovery of approximately $20 million . The recovery includes a weighted average cost of capital on the unamortized balance that ranges from 6.69 percent , with a return on equity of 9.75 percent , to 7.76 percent , with a return on equity of 10.3 percent . SAVEGREEN investments and costs are filed with the BPU on an annual basis. In June 2016 , the BPU approved NJNG's petition to extend its current program, which was set to expire on July 31, 2017 , to December 31, 2018 . In October 2016 , the BPU approved NJNG's filing to maintain its existing recovery rate. On October 20, 2017 , the BPU approved NJNG's filing to decrease its EE recovery rate, which will result in an annual decrease of $3.9 million , effective November 1, 2017 . Societal Benefits Clause The SBC is comprised of three primary riders that allow NJNG to recover costs associated with USF, which is a permanent statewide program for all natural gas and electric utilities for the benefit of income-eligible customers, MGP remediation and the NJCEP. NJNG has submitted the following filings to the BPU, which include a report of program expenditures incurred each program year: • 2015 SBC filings — In September 2015 , the BPU approved the annual USF compliance filing decreasing the statewide USF rate, resulting in an annual $3.9 million decrease to USF recoveries, effective October 2015 . In June 2016 , the BPU approved NJNG's additional filing to recover remediation expenses incurred through June 30, 2015 , increase the RAC with an annual recovery of $9.4 million and to decrease the NJCEP factor, effective July 9, 2016 . • 2016 SBC filing — In September 2016 , the BPU approved NJNG's annual USF compliance filing proposing to increase the statewide USF rate, resulting in a $1.3 million annual increase in USF recoveries, effective October 2016 . • 2017 SBC filing — On September 22, 2017 , the BPU approved NJNG's annual USF compliance filing to decrease the statewide USF rate, which will result in a $2.6 million annual decrease, effective October 1, 2017 . On November 17, 2017 , NJNG filed it's annual SBC application requesting to recover remediation expenses incurred through June 30, 2017, a reduction in the RAC, which will decrease the annual recovery to $7 million and to increase the NJCEP factor, effective April 1, 2018 . Infrastructure Programs NJNG has significant annual capital expenditures associated with the management of its natural gas distribution and transmission system, including new utility plant for customer growth and its associated PIM and infrastructure programs. NJNG continues to implement BPU-approved infrastructure projects that are designed to enhance the reliability of NJNG’s gas distribution system, including SAFE and NJ RISE. SAFE/NJ RISE In October 2012 , the BPU approved NJNG’s petition to implement SAFE I, investing up to $130 million , exclusive of AFUDC, over a four -year period to replace portions of NJNG’s gas distribution unprotected steel, cast iron infrastructure and associated services to improve the safety and reliability of the gas distribution system. The recovery of SAFE I capital investments and the rate mechanism and five-year extension of SAFE II were approved through NJNG’s base rate case, effective October 2016 . The estimated cost for SAFE II is approximately $200 million , excluding AFUDC and related costs to be recovered are approximately $157.5 million . As a condition of approval of the extension, NJNG is required to file a base rate case no later than November 2019. In July 2014 , the BPU approved NJ RISE, which consists of six capital investment projects estimated to cost $102.5 million over a five -year period, excluding AFUDC, for gas distribution storm hardening and mitigation projects, along with incremental depreciation expense. In October 2015 , the BPU approved a base rate increase to recover capital costs through July 2015 , resulting in a $390,000 annual recovery increase, effective November 2015 , and earned a weighted average cost of capital of 6.74 percent , including a return on equity of 9.75 percent . NJ RISE investments through June 30, 2016, were approved for recovery through NJNG’s new base rates, effective October 2016 . Requests for recovery of future NJ RISE capital costs will occur in conjunction with SAFE II, commencing with the rate recovery filing that was submitted in March 2017, with a weighted cost of capital of 6.9 percent , including a return on equity of 9.75 percent . On March 30, 2017 , NJNG filed its annual petition with the BPU requesting a base rate increase for the recovery of NJ RISE and SAFE II capital investment costs related to the period ending June 30, 2017 , based on estimates, pursuant to the September 2016 base rate case. On July 20, 2017 , NJNG filed an update to this petition with actuals, requesting a $4.1 million annual increase in recoveries, which was approved by the BPU, effective October 1, 2017 . NGV refueling stations In June 2012 , the BPU approved a pilot program for NJNG to invest up to $10 million to build NGV refueling stations. NJNG has opened all three of its NGV stations to the public and its capital investments were approved for recovery through the new base rates, effective October 2016 . SRL The SRL is an approximate 30-mile, 30-inch transmission main designed to support improved system integrity and reliability in the southern portion of NJNG’s service territory, estimated to cost between $180 million and $200 million . In January 2016 , the BPU issued an order approving NJNG’s modified proposed SRL pipeline installation, operation and route selection. In March 2016 , the BPU issued an order designating the SRL route and exempting the SRL from municipal land use ordinances, regulations, permits and license requirements. In February 2017, the New Jersey Department of Environmental Protection issued a permit authorizing construction of the SRL within the jurisdiction of the Coastal Area Facility Review Act as well as a Freshwater Wetlands permit. On September 14, 2017, the NJ Pinelands Commission approved construction of NJNG’s SRL. All approvals and permits have been appealed by third parties. Other Regulatory Initiatives In May 2016 , NJNG included a proposal in its base rate case to recover certain capital costs and incremental operation and maintenance costs related to a March 2016 BPU Order regarding new cyber security requirements. In June 2016, NJNG’s liquefaction project became operational, allowing NJNG to convert natural gas into LNG and to fill NJNG’s existing LNG storage tanks. Costs for this project along with other plant upgrades were approximately $36.5 million . Costs associated with both initiatives were approved for recovery through NJNG’s new base rates, effective October 2016 .

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS	12 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	5. DERIVATIVE INSTRUMENTS The Company is subject to commodity price risk due to fluctuations in the market price of natural gas, SRECs and electricity. To manage this risk, the Company enters into a variety of derivative instruments including, but not limited to, futures contracts, physical forward contracts, financial options and swaps to economically hedge the commodity price risk associated with its existing and anticipated commitments to purchase and sell natural gas, SRECs and electricity. In addition, the Company may utilize foreign currency derivatives to hedge Canadian dollar denominated gas purchases and/or sales. Therefore, the Company’s primary underlying risks include commodity prices, interest rates and foreign currency. These contracts, with a few exceptions as described below, are accounted for as derivatives. Accordingly, all of the financial and certain of the Company’s physical derivative instruments are recorded at fair value on the Consolidated Balance Sheets. For a more detailed discussion of the Company’s fair value measurement policies and level disclosures associated with the Company’s derivative instruments, see Note 6. Fair Value . Energy Services Energy Services chooses not to designate its financial commodity and physical forward commodity derivatives as accounting hedges or to elect NPNS, and therefore changes in the fair value of these derivatives are recorded as a component of gas purchases or operating revenues, as appropriate for Energy Services, on the Consolidated Statements of Operations as unrealized gains or (losses). For Energy Services at settlement, realized gains and (losses) on all financial derivative instruments are recognized as a component of gas purchases and realized gains and (losses) on all physical derivatives follow the presentation of the related unrealized gains and (losses) as a component of either gas purchases or operating revenues. Energy Services also enters into natural gas transactions in Canada and, consequently, is exposed to fluctuations in the value of Canadian currency relative to the U.S. dollar. Energy Services may utilize foreign currency derivatives to lock in the exchange rate associated with natural gas transactions denominated in Canadian currency. The derivatives may include currency forwards, futures, or swaps and are accounted for as derivatives. These derivatives are typically used to hedge demand fee payments on pipeline capacity, storage and gas purchase agreements. For transactions occurring on or before December 31, 2015, Energy Services designates its foreign exchange contracts as cash flow hedges, and the effective portion of the hedges are recorded in OCI. Effective January 1, 2016, on a prospective basis, the Company has elected not to designate its foreign currency derivatives as accounting hedges. Accordingly, changes in the fair value of foreign exchange contracts entered into from January 1, 2016, are recognized in gas purchases on the Consolidated Statements of Operations. As a result of Energy Services entering into transactions to borrow natural gas, commonly referred to as “park and loans,” an embedded derivative is recognized relating to differences between the fair value of the amount borrowed and the fair value of the amount that will ultimately be repaid, based on changes in the forward price for natural gas prices at the borrowed location over the contract term. This embedded derivative is accounted for as a forward sale in the month in which the repayment of the borrowed gas is expected to occur, and is considered a derivative transaction that is recorded at fair value on the Consolidated Balance Sheets, with changes in value recognized in current period earnings. Expected production of SRECs is hedged through the use of forward and futures contracts. All contracts require the Company to physically deliver SRECs through the transfer of certificates as per contractual settlement schedules. For transactions occurring on or before December 31, 2015, the Company elected NPNS accounting treatment on SREC forward and futures contracts. Effective January 1, 2016, on a prospective basis, Energy Services no longer elects NPNS accounting treatment on SREC contracts entered into from January 1, 2016, and recognizes changes in the fair value of these derivatives as a component of operating revenues. Upon settlement of the contract, the related revenue is recognized when the SREC is transferred to the counterparty. NPNS is a contract-by-contract election and, where it makes sense to do so, we can and may elect certain contracts to be normal. Natural Gas Distribution Changes in fair value of NJNG’s financial commodity derivatives are recorded as a component of regulatory assets or liabilities on the Consolidated Balance Sheets. The Company elects NPNS accounting treatment on all physical commodity contracts that NJNG entered into on or before December 31, 2015, and accounts for these contracts on an accrual basis. Accordingly, physical natural gas purchases are recognized in regulatory assets or liabilities on the Consolidated Balance Sheets when the contract settles and the natural gas is delivered. The average cost of natural gas is amortized in current period earnings based on the current BPU BGSS factor and therm sales. Effective January 1, 2016, on a prospective basis, NJNG no longer elects NPNS accounting treatment on all of its physical commodity contracts entered into from January 1, 2016. However, since NPNS is a contract-by-contract election, where it makes sense to do so, we can and may elect certain contracts to be normal. Because NJNG recovers these amounts through future BGSS rates as increases or decreases to the cost of natural gas in NJNG’s tariff for gas service, the changes in fair value of these contracts are deferred as a component of regulatory assets or liabilities on the Consolidated Balance Sheets. In an April 2014 BPU Order, NJNG received regulatory approval to enter into interest rate risk management transactions related to long-term debt securities. On June 1, 2015, NJNG entered into a treasury lock transaction to fix a benchmark treasury rate of 3.26 percent associated with a forecasted $125 million debt issuance expected in May 2018. This forecasted debt issuance coincides with the maturity of NJNG’s existing $125 million , 5.6 percent notes due May 15, 2018 . The change in fair value of NJNG’s treasury lock agreement is recorded as a component of regulatory assets or liabilities on the Consolidated Balance Sheets since NJNG believes that the market value upon settlement will be recovered in future rates. Upon settlement, any gain or loss will be amortized into earnings over the life of the future underlying debt issuance. Fair Value of Derivatives The following table reflects the fair value of the Company’s derivative assets and liabilities recognized on the Consolidated Balance Sheets as of September 30 : Fair Value 2017 2016 (Thousands) Balance Sheet Location Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives Derivatives not designated as hedging instruments: NJNG: Physical commodity contracts Derivatives - current $ 151 $ 72 $ 235 $ 1,154 Financial commodity contracts Derivatives - current — 1,149 805 2,979 Derivatives - noncurrent — — 75 386 Interest rate contracts Derivatives - current — 8,467 — — Interest rate contracts Derivatives - noncurrent — — — 23,073 Energy Services: Physical commodity contracts Derivatives - current 14,588 16,589 5,994 11,660 Derivatives - noncurrent 7,127 8,710 3,987 1,212 Financial commodity contracts Derivatives - current 15,302 20,267 22,929 45,255 Derivatives - noncurrent 2,033 2,620 1,165 581 Foreign currency contracts Derivatives - current 40 — 1 32 Derivatives - noncurrent 4 — — — Total fair value of derivatives $ 39,245 $ 57,874 $ 35,191 $ 86,332 Offsetting of Derivatives The Company transacts under master netting arrangements or equivalent agreements that allow it to offset derivative assets and liabilities with the same counterparty. However, the Company’s policy is to present its derivative assets and liabilities on a gross basis at the contract level unit of account on the Consolidated Balance Sheets. The following table summarizes the reported gross amounts, the amounts that the Company has the right to offset but elects not to, financial collateral, as well as the net amounts the Company could present on the Consolidated Balance Sheets but elects not to. (Thousands) Amounts Presented in Balance Sheets (1) Offsetting Derivative Instruments (2) Financial Collateral Received/Pledged (3) Net Amounts (4) As of September 30, 2017: Derivative assets: Energy Services Physical commodity contracts $ 21,715 $ (2,173 ) $ (200 ) $ 19,342 Financial commodity contracts 17,335 (14,121 ) — 3,214 Foreign currency contracts 44 — — 44 Total Energy Services $ 39,094 $ (16,294 ) $ (200 ) $ 22,600 NJNG Physical commodity contracts $ 151 $ (20 ) $ — $ 131 Financial commodity contracts — — — — Interest rate contracts — — — — Total NJNG $ 151 $ (20 ) $ — $ 131 Derivative liabilities: Energy Services Physical commodity contracts $ 25,299 $ (2,173 ) $ — $ 23,126 Financial commodity contracts 22,887 (14,121 ) (8,766 ) — Foreign currency contracts — — — — Total Energy Services $ 48,186 $ (16,294 ) $ (8,766 ) $ 23,126 NJNG Physical commodity contracts $ 72 $ (20 ) $ — $ 52 Financial commodity contracts 1,149 — (1,149 ) — Interest rate contracts 8,467 — — 8,467 Total NJNG $ 9,688 $ (20 ) $ (1,149 ) $ 8,519 As of September 30, 2016: Derivative assets: Energy Services Physical commodity contracts $ 9,981 $ (2,837 ) $ (755 ) $ 6,389 Financial commodity contracts 24,094 (17,945 ) (6,149 ) — Foreign currency contracts 1 (1 ) — — Total Energy Services $ 34,076 $ (20,783 ) $ (6,904 ) $ 6,389 NJNG Physical commodity contracts $ 235 $ (31 ) $ — $ 204 Financial commodity contracts 880 (880 ) — — Interest rate contracts — — — — Total NJNG $ 1,115 $ (911 ) $ — $ 204 Derivative liabilities: Energy Services Physical commodity contracts $ 12,872 $ (2,837 ) $ 1,200 $ 11,235 Financial commodity contracts 45,836 (17,945 ) (27,891 ) — Foreign currency contracts 32 (1 ) — 31 Total Energy Services $ 58,740 $ (20,783 ) $ (26,691 ) $ 11,266 NJNG Physical commodity contracts $ 1,154 $ (31 ) $ — $ 1,123 Financial commodity contracts 3,365 (880 ) (2,485 ) — Interest rate contracts 23,073 — — 23,073 Total NJNG $ 27,592 $ (911 ) $ (2,485 ) $ 24,196 (1) Derivative assets and liabilities are presented on a gross basis in the balance sheet as the Company does not elect balance sheet offsetting under ASC 210-20. (2) Offsetting derivative instruments include transactions with NAESB netting election, transactions held by FCMs with net margining and transactions with ISDA netting. (3) Financial collateral includes cash balances at FCMs, as well as cash received from or pledged to other counterparties. (4) Net amounts represent presentation of derivative assets and liabilities if the Company were to elect balance sheet offsetting under ASC 210-20. Energy Services utilizes financial derivatives to economically hedge the gross margin associated with the purchase of physical gas to be used for storage injection and its subsequent sale at a later date. The gains or (losses) on the financial transactions that are economic hedges of the cost of the purchased gas are recognized prior to the gains or (losses) on the physical transaction, which are recognized in earnings when the natural gas is delivered. Therefore, mismatches between the timing of the recognition of realized gains or (losses) on the financial derivative instruments and gains or (losses) associated with the actual sale of the natural gas that is being economically hedged, along with fair value changes in derivative instruments, creates volatility in the results of Energy Services, although the Company’s intended economic results relating to the entire transaction are unaffected. The following table reflects the effect of derivative instruments on the Consolidated Statements of Operations as of September 30 : (Thousands) Location of gain (loss) recognized in income on derivatives Amount of gain (loss) recognized in income on derivatives Derivatives not designated as hedging instruments: 2017 2016 2015 Energy Services: Physical commodity contracts Operating revenues $ 8,912 $ 33,034 $ 32,568 Physical commodity contracts Gas purchases (27,461 ) (45,637 ) (34,438 ) Financial commodity contracts Gas purchases 26,563 45,579 109,082 Foreign currency contracts Gas purchases 41 (34 ) — Total unrealized and realized gains (losses) $ 8,055 $ 32,942 $ 107,212 Energy Services designated its foreign exchange contracts, entered into prior to January 1, 2016, as cash flow hedges and, as a result, changes in fair value of the effective portion of the hedges are recorded in OCI and, upon settlement of the contracts, realized gains and (losses) are reclassified from AOCI to gas purchases on the Consolidated Statements of Operations. The following table reflects the effect of derivative instruments designated as cash flow hedges on OCI as of September 30 : (Thousands) Amount of Gain or (Loss) Recognized in OCI on Derivatives (Effective Portion) Amount of Gain or (Loss) Reclassified from OCI into Income (Effective Portion) Amount of Gain or (Loss) Recognized on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) Derivatives in cash flow hedging relationships: 2017 2016 2017 2016 2017 2016 Foreign currency contracts $ — $ (27 ) $ — $ 27 $ — $ — NJNG’s derivative contracts are part of the Company’s risk management activities that relate to its natural gas purchases, BGSS incentive programs and debt financing. These transactions are entered into pursuant to regulatory approval and, at settlement, the resulting gains and/or losses are payable to or recoverable from utility customers. Any changes in the value of NJNG’s financial derivatives are deferred in regulatory assets or liabilities resulting in no impact to earnings. The following table reflects the (losses) gains associated with NJNG’s derivative instruments as of September 30 : (Thousands) 2017 2016 2015 NJNG: Physical commodity contracts $ (12,303 ) $ (15,756 ) $ — Financial commodity contracts 5,595 (7,984 ) (33,428 ) Interest rate contracts 14,606 (18,845 ) (4,228 ) Total unrealized and realized (losses) gains $ 7,898 $ (42,585 ) $ (37,656 ) NJNG and Energy Services had the following outstanding long (short) derivatives as of September 30 : Volume (Bcf) 2017 2016 NJNG Futures 18.2 23.6 Physical 32.1 9.2 Energy Services Futures (16.4 ) (79.1 ) Financial Options — 1.2 Physical (13.1 ) 94.6 Not included in the previous table are Energy Services’ gross notional amount of foreign currency transactions of approximately $4.5 million , NJNG’s treasury lock agreement, as previously discussed, and 283,000 SRECs at Energy Services that are open as of September 30, 2017 . Broker Margin Futures exchanges have contract specific performance bond requirements, also known as margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily marked-to-market relative to maintenance margin requirements. The Company maintains separate broker margin accounts for NJNG and Energy Services. The balances as of September 30 , by company, are as follows: (Thousands) Balance Sheet Location 2017 2016 NJNG Broker margin - Current assets $ 2,661 $ 4,822 Energy Services Broker margin - Current assets $ 23,166 $ 42,822 Due to CME rulebook changes that took effect in January 2017, variation margin is being treated as a settlement payment, rather than collateral. As a result, the Company is now required to present variation margin net with the related derivative assets and/or liabilities on the Consolidated Balance Sheets for any derivatives the Company clears through the CME. This change is being applied on a prospective basis. In September 30, 2016, prior to the rule change, the Company reported the variation margin as a separate unit of account within restricted broker margin on the Consolidated Balance Sheets. There was no impact to the Company’s derivative gains or losses in the Consolidated Statements of Operations as a result of the CME rule amendment. Wholesale Credit Risk NJNG, Energy Services and Clean Energy Ventures are exposed to credit risk as a result of their sales/wholesale and retail marketing activities. As a result of the inherent volatility in the prices of natural gas commodities, derivatives, SRECs, electricity and RECs, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If a counterparty fails to perform the obligations under its contract (e.g., fails to deliver or pay for natural gas, SRECs, electricity or RECs), the Company could sustain a loss. The Company monitors and manages the credit risk of its wholesale operations through credit policies and procedures that management believes reduce overall credit risk. These policies include a review and evaluation of current and prospective counterparties’ financial statements and/or credit ratings, daily monitoring of counterparties’ credit limits and exposure, daily communication with traders regarding credit status and the use of credit mitigation measures, such as collateral requirements and netting agreements. Examples of collateral include letters of credit and cash received for either prepayment or margin deposit. Collateral may be requested due to the Company’s election not to extend credit or because exposure exceeds defined thresholds. Most of the Company’s wholesale marketing contracts contain standard netting provisions. These contracts include those governed by ISDA and the NAESB. The netting provisions refer to payment netting, whereby receivables and payables with the same counterparty are offset and the resulting net amount is paid to the party to which it is due. Internally-rated exposure applies to counterparties that are not rated by S&P or Moody’s. In these cases, the counterparty’s or guarantor’s financial statements are reviewed, and similar methodologies and ratios used by S&P and/or Moody’s are applied to arrive at a substitute rating. Gross credit exposure is defined as the unrealized fair value of physical and financial derivative commodity contracts, plus any outstanding wholesale receivable for the value of natural gas delivered and/or financial derivative commodity contract that has settled for which payment has not yet been received. The following is a summary of gross credit exposures grouped by investment and noninvestment grade counterparties, as of September 30, 2017 .The amounts presented below have not been reduced by any collateral received or netting and exclude accounts receivable for NJNG retail natural gas sales and services and Clean Energy Ventures residential solar installations. (Thousands) Gross Credit Exposure Investment grade $ 136,804 Noninvestment grade 16,889 Internally-rated investment grade 16,378 Internally-rated noninvestment grade 68,498 Total $ 238,569 Conversely, certain of NJNG’s and Energy Services’ derivative instruments are linked to agreements containing provisions that would require cash collateral payments from the Company if certain events occur. These provisions vary based upon the terms in individual counterparty agreements and can result in cash payments if NJNG’s credit rating were to fall below its current level. NJNG’s credit rating, with respect to S&P, reflects the overall corporate credit profile of the Company. Specifically, most, but not all, of these additional payments will be triggered if NJNG’s debt is downgraded by the major credit agencies, regardless of investment grade status. In addition, some of these agreements include threshold amounts that would result in additional collateral payments if the values of derivative liabilities were to exceed the maximum values provided for in relevant counterparty agreements. Other provisions include payment features that are not specifically linked to ratings, but are based on certain financial metrics. Collateral amounts associated with any of these conditions are determined based on a sliding scale and are contingent upon the degree to which the Company’s credit rating and/or financial metrics deteriorate, and the extent to which liability amounts exceed applicable threshold limits. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on September 30, 2017 and 2016 , is $8.7 million and $23.1 million , respectively, for which the Company had not posted collateral. If all thresholds related to the credit-risk-related contingent features underlying these agreements had been invoked on September 30, 2017 and 2016 , the Company would have been required to post an additional $8.6 million and $23.1 million , respectively, to its counterparties. These amounts differ from the respective net derivative liabilities reflected on the Consolidated Balance Sheets because the agreements also include clauses, commonly known as “Rights of Offset,” that would permit the Company to offset its derivative assets against its derivative liabilities for determining additional collateral to be posted, as previously discussed.

FAIR VALUE

FAIR VALUE	12 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
FAIR VALUE	6. FAIR VALUE Fair Value of Assets and Liabilities The fair value of cash and cash equivalents, accounts receivable, current loan receivables, accounts payable, commercial paper and borrowings under revolving credit facilities are estimated to equal their carrying amounts due to the short maturity of those instruments. Non-current loan receivables are recorded based on what the Company expects to receive, which approximates fair value. The Company regularly evaluates the credit quality and collection profile of its customers to approximate fair value. As of September 30, the estimated fair value of long-term debt at NJNG and NJR, including current maturities, excluding capital leases, debt issuance costs and solar asset financing obligations, is as follows: (Thousands) 2017 2016 NJNG Carrying value (1) (2) $ 672,045 $ 707,845 Fair market value $ 673,051 $ 731,615 NJR Carrying value (3) $ 425,000 $ 375,000 Fair market value $ 434,625 $ 399,462 (1) Excludes capital leases of $39.7 million and $42.2 million as of September 30, 2017 and 2016 , respectively. (2) Excludes debt issuance costs of $6.3 million and $7.7 million as of September 30, 2017 and 2016 , respectively. (3) Excludes debt issuance costs of $770,000 and $853,000 as of September 30, 2017 and 2016 , respectively. The Company utilizes a discounted cash flow method to determine the fair value of its debt. Inputs include observable municipal and corporate yields, as appropriate, for the maturity of the specific issue and the Company’s credit rating. As of September 30, 2017 and 2016 , the Company disclosed its debt within Level 2 of the fair value hierarchy. Fair Value Hierarchy The Company applies fair value measurement guidance to its financial assets and liabilities, as appropriate, which include financial derivatives and physical commodity contracts qualifying as derivatives, available for sale securities and other financial assets and liabilities. In addition, authoritative accounting literature prescribes the use of a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value based on the source of the data used to develop the price inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to inputs that are based on unobservable market data and includes the following: Level 1 Unadjusted quoted prices for identical assets or liabilities in active markets. The Company’s Level 1 assets and liabilities include exchange traded natural gas futures and options contracts, listed equities and money market funds. Exchange traded futures and options contracts include all energy contracts traded on the NYMEX, CME and ICE that the Company refers internally to as basis swaps, fixed swaps, futures and financial options that are cleared through a FCM. Level 2 Other significant observable inputs, such as interest rates or price data, including both commodity and basis pricing that is observed either directly or indirectly from publications or pricing services. The Company’s Level 2 assets and liabilities include over-the-counter physical forward commodity contracts and swap contracts, SREC forward sales or derivatives that are initially valued using observable quotes and are subsequently adjusted to include time value, credit risk or estimated transport pricing components for which no basis price is available. Level 2 financial derivatives consist of transactions with non-FCM counterparties (basis swaps, fixed swaps and/or options). NJNG’s treasury lock is also considered Level 2 as valuation is based on quoted market interest and swap rates as inputs to the valuation model. Inputs are verifiable and do not require significant management judgment. For some physical commodity contracts, the Company utilizes transportation tariff rates that are publicly available and that it considers to be observable inputs that are equivalent to market data received from an independent source. There are no significant judgments or adjustments applied to the transportation tariff inputs and no market perspective is required. Even if the transportation tariff input were considered to be a “model,” it would still be considered to be a Level 2 input as the data is: • widely accepted and public; • non-proprietary and sourced from an independent third party; and • observable and published. These additional adjustments are generally not considered to be significant to the ultimate recognized values. Level 3 Inputs derived from a significant amount of unobservable market data. These include the Company’s best estimate of fair value and are derived primarily through the use of internal valuation methodologies. Financial derivative portfolios of NJNG and Energy Services consist mainly of futures, options and swaps. The Company primarily uses the market approach and its policy is to use actively quoted market prices when available. The principal market for its derivative transactions is the natural gas wholesale market, therefore, the primary sources for its price inputs are CME, NYMEX and ICE. Energy Services uses Platts and Natural Gas Exchange for Canadian delivery points. However, Energy Services also engages in transactions that result in transporting natural gas to delivery points for which there is no actively quoted market price. In most instances, the transportation cost to the final delivery location is not significant to the overall valuation. If required, Energy Services’ policy is to use the best information available to determine fair value based on internal pricing models, which would include estimates extrapolated from broker quotes or other pricing services. The Company also has available for sale securities and other financial assets that include listed equities, mutual funds and money market funds for which there are active exchange quotes available. When the Company determines fair values, measurements are adjusted, as needed, for credit risk associated with its counterparties, as well as its own credit risk. The Company determines these adjustments by using historical default probabilities that correspond to the applicable S&P issuer ratings, while also taking into consideration collateral and netting arrangements that serve to mitigate risk. Assets and liabilities measured at fair value on a recurring basis are summarized as follows: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs (Thousands) (Level 1) (Level 2) (Level 3) Total As of September 30, 2017: Assets Physical commodity contracts $ — $ 21,866 $ — $ 21,866 Financial commodity contracts 17,335 — — 17,335 Financial commodity contracts - foreign exchange — 44 — 44 Available for sale equity securities 65,752 — — 65,752 Money market funds 112 — — 112 Other 1,090 — — 1,090 Total assets at fair value $ 84,289 $ 21,910 $ — $ 106,199 Liabilities Physical commodity contracts $ — $ 25,371 $ — $ 25,371 Financial commodity contracts 24,036 — — 24,036 Financial commodity contracts - foreign exchange — — — — Interest rate contracts — 8,467 — 8,467 Total liabilities at fair value $ 24,036 $ 33,838 $ — $ 57,874 As of September 30, 2016: Assets Physical commodity contracts $ — $ 10,216 $ — $ 10,216 Financial commodity contracts 24,974 — — 24,974 Financial commodity contracts - foreign exchange — 1 — 1 Available for sale equity securities 55,789 — — 55,789 Money market funds 34,072 — — 34,072 Other 1,444 — — 1,444 Total assets at fair value $ 116,279 $ 10,217 $ — $ 126,496 Liabilities Physical commodity contracts $ — $ 14,026 $ — $ 14,026 Financial commodity contracts 49,201 — — 49,201 Financial commodity contracts - foreign exchange — 32 — 32 Interest rate contracts — 23,073 — 23,073 Total liabilities at fair value $ 49,201 $ 37,131 $ — $ 86,332 Assets measured at fair value on a non-recurring basis are summarized as follows: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs (Thousands) (Level 1) (Level 2) (Level 3) Total As of September 30, 2017: Assets Acquired wholesale energy contracts (1) $ — $ 41,084 $ — $ 41,084 Total assets at fair value $ — $ 41,084 $ — $ 41,084 (1) Included in intangible asset on the Consolidated Balance Sheets, see Note 3. Acquisition for more information regarding the acquired contracts.

INVESTMENTS IN EQUITY INVESTEES

INVESTMENTS IN EQUITY INVESTEES	12 Months Ended
	Sep. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
INVESTMENTS IN EQUITY INVESTEES	7. INVESTMENTS IN EQUITY INVESTEES As of September 30 , the Company’s investments in equity method investees includes the following: (Thousands) 2017 2016 Steckman Ridge (1) $ 120,262 $ 123,155 PennEast 52,323 17,993 Total $ 172,585 $ 141,148 (1) Includes loans with a total outstanding principal balance of $70.4 million for both fiscal 2017 and 2016 , which accrue interest at a variable rate that resets quarterly and are due October 1, 2023 . The Company, through its subsidiary NJR Pipeline Company, is an investor in PennEast, which is expected to construct and operate a 120 -mile pipeline that will extend from northeast Pennsylvania to western New Jersey and is estimated to be completed and operational in 2019 . NJNG and Energy Services have entered into storage and park and loan agreements with Steckman Ridge. In addition, NJNG has entered into a precedent capacity agreement with PennEast. See Note 16. Related Party Transactions for more information on these intercompany transactions.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
EARNINGS PER SHARE	8. EARNINGS PER SHARE The following table presents the calculation of the Company’s basic and diluted earnings per share for the fiscal years ended September 30 : (Thousands, except per share amounts) 2017 2016 2015 Net income, as reported $ 132,065 $ 131,672 $ 180,960 Basic earnings per share Weighted average shares of common stock outstanding-basic 86,321 85,884 85,186 Basic earnings per common share $1.53 $1.53 $2.12 Diluted earnings per share Weighted average shares of common stock outstanding-basic 86,321 85,884 85,186 Incremental shares (1) 823 847 1,079 Weighted average shares of common stock outstanding-diluted 87,144 86,731 86,265 Diluted earnings per common share (2) $1.52 $1.52 $2.10 (1) Incremental shares consist primarily of unvested stock awards and performance units. (2) There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2017 , 2016 and 2015 .

DEBT

DEBT	12 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
DEBT	9. DEBT NJNG and NJR finance working capital requirements and capital expenditures through the issuance of various long-term debt and other financing arrangements, including unsecured credit and private placement debt shelf facilities. Amounts available under credit facilities are reduced by bank or commercial paper borrowings, as applicable, and any outstanding letters of credit. Long-term Debt The following table presents the long-term debt of the Company as of September 30 : (Thousands) 2017 2016 NJNG First mortgage bonds: Maturity date: 4.50% Series II August 1, 2023 $ — $ 10,300 4.60% Series JJ August 1, 2024 — 10,500 4.90% Series KK October 1, 2040 — 15,000 5.60% Series LL May 15, 2018 125,000 125,000 Variable Series MM September 1, 2027 9,545 9,545 Variable Series NN August 1, 2035 41,000 41,000 Variable Series OO August 1, 2041 46,500 46,500 3.15% Series PP April 15, 2028 50,000 50,000 3.58% Series QQ March 13, 2024 70,000 70,000 4.61% Series RR March 13, 2044 55,000 55,000 2.82% Series SS April 15, 2025 50,000 50,000 3.66% Series TT April 15, 2045 100,000 100,000 3.63% Series UU June 21, 2046 125,000 125,000 Capital lease obligation-buildings June 1, 2021 11,617 14,262 Capital lease obligation-meters Various dates 28,042 27,895 Less: Debt issuance costs (6,262 ) (7,659 ) Less: Current maturities of long-term debt (135,800 ) (11,452 ) Total NJNG long-term debt 569,642 730,891 NJR 6.05% Unsecured senior notes September 24, 2017 — 50,000 2.51% Unsecured senior notes September 15, 2018 25,000 25,000 3.25% Unsecured senior notes September 17, 2022 50,000 50,000 3.48% Unsecured senior notes November 7, 2024 100,000 100,000 3.20% Unsecured senior notes August 18, 2023 50,000 50,000 3.54% Unsecured senior notes August 18, 2026 100,000 100,000 Variable Term loan August 16, 2019 100,000 — Less: Debt issuance costs (770 ) (853 ) Less: Current maturities of long-term debt (25,000 ) (50,000 ) Total NJR long-term debt 399,230 324,147 Clean Energy Ventures Solar asset financing obligation Various dates 32,790 — Less: Current maturities of long-term debt (4,582 ) — Total Clean Energy Ventures long-term debt 28,208 — Total long-term debt $ 997,080 $ 1,055,038 Annual long-term debt redemption requirements, excluding capital leases, debt issuance costs and solar asset financing obligations, as of September 30 , are as follows: (Thousands) NJNG NJR 2018 $ 125,000 $ 25,000 2019 $ — $ 100,000 2020 $ — $ — 2021 $ — $ — 2022 $ — $ 50,000 Thereafter $ 547,045 $ 250,000 NJNG First Mortgage Bonds NJNG and Trustee entered into the Mortgage Indenture, dated September 1, 2014, which secures all of the outstanding First Mortgage Bonds issued by NJNG. The Mortgage Indenture provides a direct first mortgage lien upon substantially all of the operating properties and franchises of NJNG (other than excepted property, such as cash on hand, choses-in-action, securities, rent, natural gas meters and certain materials, supplies, appliances and vehicles), subject only to certain permitted encumbrances. The Mortgage Indenture contains provisions subjecting after-acquired property (other than excepted property and subject to pre-existing liens, if any, at the time of acquisition) to the lien thereof. NJNG’s Mortgage Indenture no longer contains a restriction on NJNG's ability to pay dividends. New Jersey Administrative Code 14:4-4.7 states that a public utility cannot issue dividends, without regulatory approval, if its equity to total capitalization ratio falls below 30 percent . As of September 30, 2017 , NJNG’s equity to total capitalization ratio is 55.6 percent and has the ability to issue up to $960 million of FMB under the terms of the Mortgage Indenture. NJNG has variable rate EDA Bonds with a total principal amount of $97 million and maturity dates ranging from September 2027 to August 2041 . The EDA Bonds are not subject to optional tender while they bear interest at a LIBOR index rate. As of September 30, 2017 , the interest rate on the EDA Bonds was 1.42 percent . In June 2016 , NJNG entered into a Note Purchase Agreement, under which NJNG issued $125 million of its 3.63 percent senior notes due June 2046 . The notes are secured by an equal principal amount of NJNG’s FMB (series UU) issued under NJNG’s Mortgage Indenture. The proceeds of the notes will be used for general corporate purposes, including, but not limited to, refinancing or retiring short-term debt and funding capital expenditures. On January 17, 2017, the Company completed the purchase of three FMBs in lieu of redemption with an aggregate principal amount totaling $35.8 million . The FMBs bore interest at rates ranging from 4.5 percent to 4.9 percent . The bonds purchased in lieu of redemption are being held by the Company to provide an opportunity to evaluate remarketing alternatives. As of September 30, 2017 , NJNG's $125 million , 5.6 percent senior notes, which will mature in May 2018 , were classified as a current maturity of long-term debt. Sale-Leasebacks NJNG has entered into a sale-leaseback for its headquarters building, which has a 25.5 -year term that expires in June 2021 , subject to an option by NJNG to renew the lease for additional five -year terms a maximum of four times. The present value of the agreement’s minimum lease payments is reflected as both a capital lease asset and a capital lease obligation, which are included in utility plant and long-term debt, respectively, on the Consolidated Balance Sheets. NJNG received $9.6 million , $7.1 million and $7.2 million for fiscal 2017 , 2016 and 2015 , respectively, in connection with the sale-leaseback of its natural gas meters. NJNG records a capital lease obligation that is paid over the term of the lease and has the option to purchase the meters back at fair value upon expiration of the lease. During fiscal 2017 , 2016 and 2015 , NJNG exercised early purchase options with respect to meter leases by making final principal payments of $2.4 million , $1.9 million and $768,000 , respectively. NJNG continues to evaluate this sale-leaseback program based on current market conditions. Contractual commitments for capital lease payments, as of the fiscal years ended September 30, are as follows: (Thousands) Lease Payments 2018 $ 12,436 2019 9,675 2020 8,849 2021 5,862 2022 2,518 Thereafter 4,914 Subtotal 44,200 Less: Interest component (4,494 ) Total $ 39,700 NJR In March 2016 , NJR entered into a Note Purchase Agreement, under which the Company issued, in August 2016 , $50 million of the Company’s 3.2 percent senior notes due August 2023 , and $100 million of the Company’s 3.54 percent senior notes due August 2026 . The notes are not secured by assets, but are instead guaranteed by certain unregulated subsidiaries of the Company. The proceeds of the notes will be used for general corporate purposes, including working capital and capital expenditures. On August 18, 2017 , NJR entered into a $100 million credit agreement due August 16, 2019 . The term loan will accrue interest at a variable rate determined monthly, which is LIBOR plus 70 basis points. The weighted average interest rate on the term loan as of September 30, 2017 , was 1.95 percent . NJR had no long-term, variable-rate debt outstanding as of September 30, 2016 . As of September 30, 2017 , NJR's $25 million , 2.51 percent debt shelf notes, which will mature in September 2018 , were classified as a current maturity of long-term debt. Clean Energy Ventures During September 2017, Clean Energy Ventures entered into transactions to sell two commercial solar assets concurrent with agreements to lease the assets back over a period of seven years. These sale-leasebacks are treated as financing obligations, which are typically secured by the renewable energy facility asset and its future cash flows from SREC and energy sales. ITCs and other tax benefits associated with these solar projects will be transferred to the buyer. Clean Energy Ventures will continue to operate the solar assets, including related expenses, and retain the revenue generated from SRECs and energy sales. and has the option to renew the lease or repurchase the assets sold at the end of the lease term. Clean Energy Ventures received proceeds of $32.9 million in connection with these sale-leasebacks. Contractual commitments for the sale-leasebacks will be $2.7 million annually for the next five years and $5.3 million in the aggregate for all years thereafter. Short-term Debt A summary of NJR’s and NJNG’s short-term bank facilities as of September 30, are as follows: (Thousands) 2017 2016 NJR Bank revolving credit facilities: (1) $ 425,000 $ 425,000 Notes outstanding at end of period $ 255,000 $ 121,700 Weighted average interest rate at end of period 2.14 % 1.43 % Amount available at end of period (2) $ 156,601 $ 288,910 NJNG Bank revolving credit facilities: (3) $ 250,000 $ 250,000 Commercial paper outstanding at end of period $ 11,000 $ — Weighted average interest rate at end of period 1.13 % — % Amount available at end of period (4) $ 238,269 $ 249,269 (1) Committed credit facilities, which require commitment fees of .075 percent on the unused amounts. (2) Letters of credit outstanding total $13.4 million and $14.4 million as of September 30, 2017 and 2016 , respectively, which reduces amount available by the same amount. (3) Committed credit facilities, which require commitment fees of .075 percent on the unused amounts. (4) Letters of credit outstanding total $731,000 as of September 30, 2017 and 2016 , which reduces amount available by the same amount. NJR On September 28, 2015 , NJR entered into a $425 million unsecured, committed credit facility scheduled to expire on September 28, 2020 , subject to two mutual options for a one-year extension beyond that date. The NJR Credit Facility includes an accordion feature, which would allow NJR, in the absence of a default or event of default, to increase from time to time, with the existing or new lenders, the revolving credit commitments under the NJR Credit Facility in minimum $5 million increments up to a maximum of $100 million . The credit facility is used primarily to finance its share repurchases, to satisfy Energy Services’ short-term liquidity needs and to finance, on an initial basis, unregulated investments. As of September 30, 2017 , NJR had six letters of credit outstanding totaling $13.4 million . Three letters of credit totaling $10.4 million are issued on behalf of Energy Services and three letters of credit, which total $3 million , are issued on behalf of Clean Energy Ventures. These letters of credit reduce the amount available under NJR’s committed credit facility by the same amount. NJR does not anticipate that these letters of credit will be drawn upon by the counterparties, and they will be renewed as necessary. Energy Services’ letters of credit are used for margin requirements for natural gas transactions, collateral and security deposit for retail gas sales and expire on dates ranging from December 2017 to September 2018 . Clean Energy Ventures’ letters of credit are used to secure construction of ground-mounted solar projects and to secure obligations pursuant to an Interconnection Services Agreement. They expire on dates ranging from May 2018 to August 2018 . Neither NJNG nor the results of its operations are obligated or pledged to support the NJR credit or debt shelf facilities. NJNG NJNG has a $250 million , five -year, revolving, unsecured credit facility, which expires in May 2019 . The NJNG Credit Facility permits the borrowing of revolving loans and swing loans, as well as the issuance of letters of credit. It also permits an increase to the facility, from time to time, with the existing or new lenders, in a minimum of $15 million increments up to a maximum of $50 million at the lending banks’ discretion. As of September 30, 2017 , NJNG has two letters of credit outstanding for $731,000 . NJNG’s letters of credit are used as collateral for remediation projects and expire in August 2018 . These letters of credit reduce the amount available under NJNG’s committed credit facility by the same amount. NJNG does not anticipate that these letters of credit will be drawn upon by the counterparty and will be renewed as necessary.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
STOCK-BASED COMPENSATION	10. STOCK-BASED COMPENSATION Effective January 25, 2017, the shareholders of the Company approved the NJR 2017 Stock Award and Incentive Plan, which replaced the NJR 2007 Stock Award and Incentive Plan. The 2007 plan had 914,169 shares granted but not issued as of September 30, 2016 , which were transferred into the 2017 plan. The 2017 plan added an additional 3,135,000 shares available for issuance. Shares have been issued in the form of performance shares, restricted stock, deferred retention stock and unrestricted common stock to non-employee directors. As of September 30, 2017 , 3,119,878 shares remain available for future issuance. The following table summarizes all stock-based compensation expense recognized during the following fiscal years: (Thousands) 2017 2016 2015 Stock-based compensation expense: Performance share awards $ 2,614 $ 3,188 $ 2,473 Restricted and non-restricted stock 1,732 2,161 1,899 Deferred retention stock 1,461 1,885 5,273 Compensation expense included in operation and maintenance expense 5,807 7,234 9,645 Income tax benefit (1) (2,372 ) (2,955 ) (3,940 ) Total, net of tax $ 3,435 $ 4,279 $ 5,705 (1) Excludes additional tax benefit related to delivered shares of $1.3 million , $1.8 million and $881,000 as of September 30, 2017 , 2016 and 2015 , respectively. Performance Shares In fiscal 2017, the Company granted to various officers 44,576 performance shares, which are market condition awards that vest on September 30, 2019 , subject to the Company meeting certain performance conditions. In fiscal 2017, the Company also granted to various officers 51,931 performance shares, of which 25,806 vest on September 30, 2019 and 26,125 vest annually over a three year period beginning on September 30, 2017 , both of which are subject to the Company meeting certain performance conditions. In fiscal 2016, the Company granted to various officers 46,175 performance shares, which are market condition awards that vest on September 30, 2018 , subject to the Company meeting certain performance conditions. In fiscal 2016, the Company also granted to various officers 69,305 performance shares, of which 38,789 vest on September 30, 2018 and 30,516 vest annually over a three year period beginning in September 2016 , both of which are subject to the Company meeting certain performance conditions. In fiscal 2015, the Company granted to various officers 41,214 performance shares, which are market condition awards that vested on September 30, 2017 , subject to the Company meeting certain performance conditions. In fiscal 2015, the Company also granted to various officers 61,576 performance shares, of which 34,622 vested in September 30, 2017 and 26,954 vest annually over a three year period beginning in September 2015 , both of which were subject to the Company meeting certain performance conditions. The vesting of these awards are shown in the table below. There is approximately $2.9 million of deferred compensation related to unvested performance shares that is expected to be recognized over the weighted average period of 1.7 years. The following table summarizes the performance share activity under the stock award and incentive plans for the past three fiscal years: Shares (1) Weighted Average Grant Date Fair Value Total Fair Value of Vested Shares (in Thousands) Non-vested and outstanding at September 30, 2014 247,536 $18.30 — Granted 102,790 $28.25 — Vested (2) (112,446 ) $17.10 $ 4,318 Cancelled/forfeited (3) (23,416 ) $17.98 — Non-vested and outstanding at September 30, 2015 214,464 $23.40 — Granted 115,480 $27.37 — Vested (4) (137,053 ) $21.40 $ 5,657 Cancelled/forfeited (5) (12,975 ) $23.40 — Non-vested and outstanding at September 30, 2016 179,916 $27.47 — Granted 96,507 $33.57 — Vested (6) (95,407 ) $28.88 $ 4,179 Cancelled/forfeited (24,429 ) $29.14 — Non-vested and outstanding at September 30, 2017 156,587 $30.12 — (1) The number of common shares issued related to certain performance shares may range from zero to 150 percent of the number of shares shown in the table above based on the Company’s achievement of performance goals . (2) As certified by the Company’s Leadership and Compensation Committee on November 10, 2015, the number of common shares related to performance shares earned was 120 percent , or 112,918 shares, excluding accumulated dividends. The number represented on this line is the target number of 100 percent . See footnote (1) above. Also included in the vested number are 9,364 shares certified by the Leadership and Compensation Committee on November 11, 2014 and 8,984 shares certified by the Leadership and Compensation Committee on November 10, 2015. (3) As certified by the Company’s Leadership and Compensation Committee on November 10, 2015, 9,364 shares were canceled due to not achieving a certain performance target. The remainder were forfeitures due to individuals departing the company. (4) As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, the number of common shares earned related to TSR performance was 85 percent or 55,702 shares, the number of common shares earned related to NFE performance was 150 percent or 71,808 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 23,649 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent . (5) As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, 9,366 shares were canceled due to not achieving a certain performance target. The remainder were forfeitures due to individuals departing the company. (6) As certified by the Company’s Leadership and Compensation Committee on November 14, 2017, the number of common shares earned related to TSR performance was 108.44 percent or 39,595 shares, the number of common shares earned related to NFE performance was 119 percent or 36,498 shares and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 28,223 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent . The Company measures compensation expense related to performance shares based on the fair value of these awards at their date of grant. In accordance with ASC 718, Compensation - Stock Compensation , compensation expense for market condition grants are recognized for awards granted, and are not adjusted based on actual achievement of the performance goals. The Company estimated the fair value of these grants on the date of grant using a lattice model. Performance condition grants are initially fair valued at the company’s stock price on grant date, and are subsequently adjusted for actual achievement of the performance goals. Restricted Stock In fiscal 2017 , the Company granted 22,591 shares of restricted stock that vest annually over a three year period beginning October 15, 2017 . In fiscal 2017 , the Company also granted 6,143 shares of restricted stock that vest annually over a three year period beginning May 8, 2018 . In fiscal 2016, the Company granted 41,909 shares of restricted stock that vest annually over a three year period beginning in October 2016 . In fiscal 2015, the Company granted 48,542 shares of restricted stock that vest annually over a three year period beginning in October 2015 . In fiscal 2015, the Company also granted 10,236 shares of restricted stock that will vest October 15, 2017 and 3,194 that vested September 30, 2015 . There is approximately $511,409 of deferred compensation related to unvested restricted stock shares that is expected to be recognized over the weighted average period of two years. The following table summarizes the restricted stock activity under the stock award and incentive plans for the past three fiscal years: Shares Weighted Average Grant Date Fair Value Total Fair Value of Vested Shares (in Thousands) Non-vested and outstanding at September 30, 2014 41,491 $22.60 — Granted 61,972 $29.41 — Vested (18,170 ) $24.45 $ 510 Cancelled/forfeited (3,801 ) $26.79 — Non-vested and outstanding at September 30, 2015 81,492 $27.17 — Granted 41,909 $30.03 — Vested (48,089 ) $26.66 $ 1,469 Cancelled/forfeited (2,241 ) $29.21 — Non-vested and outstanding at September 30, 2016 73,071 $29.09 — Granted 28,734 $35.79 Vested (38,752 ) $28.92 $ 1,344 Cancelled/forfeited (11,899 ) $31.56 Non-vested and outstanding at September 30, 2017 51,154 $32.40 — Deferred Retention Stock Deferred retention stock awards vest immediately when granted, with shares delivered at a future date in accordance with the terms of the underlying agreements. The expense for these awards is recognized in the fiscal year in which services are rendered. The related shares are granted upon approval by the Board of Directors, which generally occurs subsequent to the fiscal year end. The following table summarizes the deferred retention stock award under the stock award and incentive plans for the past three fiscal years: Shares Weighted Average Grant Date Fair Value Total Fair Value of Vested Shares (in Thousands) Outstanding at September 30, 2014 276,782 $21.95 — Granted/Vested 462,790 $29.32 — Delivered (95,098 ) $23.62 $ 2,519 Forfeited (11,744 ) $24.69 — Outstanding at September 30, 2015 632,730 $27.03 — Granted/Vested 159,831 $30.37 — Delivered (121,764 ) $20.31 $ 3,751 Forfeited (8,318 ) $28.14 — Outstanding at September 30, 2016 662,479 $29.06 — Granted/Vested 63,977 $35.64 — Delivered (53,878 ) $23.11 $ 1,774 Outstanding at September 30, 2017 672,578 $29.54 — Stock Options The following table summarizes the stock option activity: Shares Weighted Average Exercise Price Outstanding at September 30, 2014 48,250 $15.00 Exercised (48,250 ) $15.00 Outstanding at September 30, 2015 — $0.00 NJR received proceeds of $724,000 from the stock options exercised during fiscal 2015 . There were no remaining stock options outstanding as of September 30, 2015, and therefore NJR received no proceeds from stock options exercised during fiscal 2017 and 2016 . There were no stock options granted during fiscal 2017 , 2016 and 2015 . Non-Employee Director Stock Non-employee director compensation includes an annual January retainer that is awarded in stock. The shares vest immediately and are subsequently amortized to expense over a 12-month period. The following summarizes non-employee director share awards for the past three fiscal years: 2017 2016 2015 Shares granted 27,972 (1) 27,481 26,122 Weighted average grant date fair value $35.59 $32.75 $30.63 (1) $280,000 of expense remains as of September 30, 2017 , to be recognized through December 31, 2017 .

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Sep. 30, 2017
Retirement Benefits [Abstract]
EMPLOYEE BENEFIT PLANS	11. EMPLOYEE BENEFIT PLANS Pension and Other Postemployment Benefit Plans The Company has two trusteed, noncontributory defined benefit retirement plans covering eligible regular represented and nonrepresented employees with more than one year of service. Defined benefit plan benefits are based on years of service and average compensation during the highest 60 consecutive months of employment. The Company also provides postemployment medical and life insurance benefits to employees who meet certain eligibility requirements. All represented employees of NJRHS hired on or after October 1, 2000, non-represented employees hired on or after October 1, 2009 and NJNG represented employees hired on or after January 1, 2012, are covered by an enhanced defined contribution plan instead of the defined benefit plan. Participation in the postemployment medical and life insurance plan was also frozen to new employees as of the same dates, with the exception of new NJRHS represented employees, for which benefits were frozen beginning April 3, 2012. The Company maintains an unfunded nonqualified PEP that was established to provide employees with the full level of benefits as stated in the qualified plan without reductions due to various limitations imposed by the provisions of federal income tax laws and regulations. There were no plan assets in the nonqualified plan due to the nature of the plan. The Company’s funding policy for its pension plans is to contribute at least the minimum amount required by the Employee Retirement Income Security Act of 1974, as amended. In fiscal 2017 and 2016 , the Company had no minimum funding requirements. The Company made a discretionary contribution of $30 million during the first quarter of fiscal 2016 to improve the funded status of the pension plans based on current actuarial assumptions. The Company made no discretionary contributions to the pension plans in fiscal 2017 . The Company does not expect to be required to make additional contributions to fund the pension plans over the following two fiscal years based on current actuarial assumptions; however, funding requirements are uncertain and can depend significantly on changes in actuarial assumptions, returns on plan assets and changes in the demographics of eligible employees and covered dependents. There are no Federal requirements to pre-fund OPEB benefits. However, the Company is required to fund certain amounts due to regulatory agreements with the BPU. The Company contributed $6 million and $3.2 million , in fiscal 2017 and 2016 , respectively, and estimates that it will contribute between $4 million to $7 million over each of the next five years . Additional contributions may be required based on market conditions and changes to assumptions. The following summarizes the changes in the funded status of the plans and the related liabilities recognized on the Consolidated Balance Sheets as of September 30 : Pension (1) OPEB (Thousands) 2017 2016 2017 2016 Change in Benefit Obligation Benefit obligation at beginning of year $ 293,654 $ 255,987 $ 160,393 $ 138,367 Service cost 8,347 7,591 4,380 4,521 Interest cost 9,771 11,342 5,545 6,256 Plan participants’ contributions (2) 45 47 120 104 Actuarial (gain) loss (5,995 ) 26,369 8,985 15,590 Benefits paid, net of retiree subsidies received (7,987 ) (7,682 ) (4,333 ) (4,445 ) Benefit obligation at end of year $ 297,835 $ 293,654 $ 175,090 $ 160,393 Change in plan assets Fair value of plan assets at beginning of year $ 249,875 $ 199,123 $ 62,035 $ 57,269 Actual return on plan assets 29,736 28,316 7,953 5,872 Employer contributions 74 30,071 6,049 3,235 Benefits paid, net of plan participants’ contributions (2) (7,942 ) (7,635 ) (4,503 ) (4,341 ) Fair value of plan assets at end of year $ 271,743 $ 249,875 $ 71,534 $ 62,035 Funded status $ (26,092 ) $ (43,779 ) $ (103,556 ) $ (98,358 ) Amounts recognized on Consolidated Balance Sheets Postemployment employee (liability) Current $ (158 ) $ (79 ) $ (602 ) $ (454 ) Noncurrent (25,934 ) (43,700 ) (102,954 ) (97,904 ) Total $ (26,092 ) $ (43,779 ) $ (103,556 ) $ (98,358 ) (1) Includes the Company’s PEP. (2) Prior to July 1, 1998, employees were eligible to elect an additional participant contribution to enhance their benefits and contributions made during the periods were insignificant. The actuarial gain on the Company’s pension plans is primarily due to an increase in the discount rate and the adoption of the MP-2016 mortality table. The actuarial loss related to the OPEB plans is primarily due to an increase in expected retiree healthcare claims, partially offset by an increase in the discount rate and the adoption of the MP-2016 mortality table. The Company recognizes a liability for its underfunded benefit plans as required by the Compensation - Retirement Benefits Topic of the ASC. The Company records the offset to regulatory assets for the portion of liability relating to NJNG and to accumulated other comprehensive income for the portion of the liability related to its unregulated operations. The following table summarizes the amounts recognized in regulatory assets and accumulated other comprehensive income as of September 30 : Regulatory Assets Accumulated Other Comprehensive Income (Loss) Pension OPEB Pension OPEB Balance at September 30, 2015 $ 86,960 $ 50,737 $ 25,640 $ 1,242 Amounts arising during the period: Net actuarial loss 13,696 11,274 4,475 3,289 Amounts amortized to net periodic costs: Net actuarial (loss) (5,607 ) (3,175 ) (1,676 ) (99 ) Prior service (cost) credit (108 ) 311 (3 ) 54 Balance at September 30, 2016 $ 94,941 $ 59,147 $ 28,436 $ 4,486 Amounts arising during the period: Net actuarial (gain) loss (9,429 ) 5,211 (6,990 ) 587 Amounts amortized to net periodic costs: Net actuarial (loss) (6,799 ) (4,209 ) (2,028 ) (160 ) Prior service (cost) credit (108 ) 311 (3 ) 54 Balance at September 30, 2017 $ 78,605 $ 60,460 $ 19,415 $ 4,967 The amounts in regulatory assets and accumulated other comprehensive income not yet recognized as components of net periodic benefit cost as of September 30 are: Regulatory Assets Accumulated Other Comprehensive Income (Loss) Pension OPEB Pension OPEB (Thousands) 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 77,930 $ 94,158 $ 61,563 $ 60,561 $ 19,414 $ 28,432 $ 5,113 $ 4,686 Prior service cost (credit) 675 783 (1,103 ) (1,414 ) 1 4 (146 ) (200 ) Total $ 78,605 $ 94,941 $ 60,460 $ 59,147 $ 19,415 $ 28,436 $ 4,967 $ 4,486 To the extent the unrecognized amounts in accumulated other comprehensive income or regulatory assets exceed 10 percent of the greater of the benefit obligation or the fair value of plan assets, an amortized amount over the average expected future working lifetime of the active plan participants is recognized. Amounts included in regulatory assets and accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost in fiscal 2018 are as follows: Regulatory Assets Accumulated Other Comprehensive Income (Loss) (Thousands) Pension OPEB Pension OPEB Net actuarial loss $ 6,177 $ 4,464 $ 1,360 $ 196 Prior service cost (credit) 105 (311 ) 1 (53 ) Total $ 6,282 $ 4,153 $ 1,361 $ 143 The accumulated benefit obligation for the pension plans, including the PEP, exceeded the fair value of plan assets. The projected benefit and accumulated benefit obligations and the fair value of plan assets as of September 30, are as follows: Pension (Thousands) 2017 2016 Projected benefit obligation $ 297,835 $ 293,654 Accumulated benefit obligation $ 258,514 $ 252,077 Fair value of plan assets $ 271,743 $ 249,875 The components of the net periodic cost for pension benefits, including the Company’s PEP, and OPEB costs (principally health care and life insurance) for employees and covered dependents for fiscal years ended September 30, are as follows: Pension OPEB (Thousands) 2017 2016 2015 2017 2016 2015 Service cost $ 8,347 $ 7,591 $ 7,485 $ 4,380 $ 4,521 $ 4,253 Interest cost 9,771 11,342 10,199 5,545 6,256 5,739 Expected return on plan assets (19,313 ) (20,118 ) (17,090 ) (4,767 ) (4,845 ) (4,977 ) Recognized actuarial loss 8,827 7,281 6,985 4,370 3,274 2,943 Prior service cost (credit) amortization 111 111 111 (365 ) (365 ) (364 ) Net periodic benefit cost recognized as expense $ 7,743 $ 6,207 $ 7,690 $ 9,163 $ 8,841 $ 7,594 Assumptions The weighted average assumptions used to determine the Company’s benefit costs during the fiscal years below and obligations as of September 30, are as follows: Pension OPEB 2017 2016 2015 2017 2016 2015 Benefit costs: Discount rate 3.96/3.94% 4.50 % 4.55 % 4.08/4.01% (1) 4.60/4.55% (1) 4.55 % Expected asset return 7.75 % 8.75 % 8.75 % 7.75 % 8.75 % 8.75 % Compensation increase 3.25/3.50% (1) 3.25/3.50% (1) 3.25 % 3.25/3.50% (1) 3.50 % 3.50 % Obligations: Discount rate 4.03 % 3.96/3.94% (1) 4.50 % 4.12/4.08% (1) 4.08/4.01% (1) 4.60/4.55% (1) Compensation increase 3.25/3.50% (1) 3.25/3.50% (1) 3.25/3.50% (1) 3.25/3.50% (1) 3.50 % 3.50 % (1) Percentages for represented and nonrepresented plans, respectively. When measuring its projected benefit obligations, the Company uses an aggregate discount rate at which its obligation could be effectively settled. The Company determines a single weighted average discount rate based on a yield curve comprised of rates of return on a population of high quality debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of its expected future benefit payments. Prior to October 1, 2016, the Company used the same assumed rate to measure the service and interest cost components of its net periodic benefit costs. Effective October 1, 2016, the Company changed its method of measuring its service and interest costs from the aggregate approach to a disaggregated, or spot rate, approach. Under the new approach, the Company applies the duration specific spot rates from the full yield curve, as of the measurement date, to each year’s future benefit payments. The Company believes that the new method provides for a more precise measurement of its service and interest costs by aligning the timing of the plans’ separate future cash flows to the corresponding spot rates on the yield curve. Accordingly, the Company accounted for this change prospectively as a change in accounting estimate. Information relating to the assumed HCCTR used to determine expected OPEB benefits as of September 30, and the effect of a one percent change in the rate, are as follows: ($ in thousands) 2017 2016 2015 HCCTR 8.3 % 8.5 % 6.7 % Ultimate HCCTR 4.5 % 4.5 % 4.8 % Year ultimate HCCTR reached 2025 2025 2022 Effect of a 1 percentage point increase in the HCCTR on: Year-end benefit obligation $ 32,019 $ 28,803 $ 26,025 Total service and interest cost $ 2,468 $ 2,331 $ 2,026 Effect of a 1 percentage point decrease in the HCCTR on: Year-end benefit obligation $ (25,466 ) $ (22,862 ) $ (20,427 ) Total service and interest costs $ (1,909 ) $ (1,801 ) $ (1,593 ) The Company’s investment objective is a long-term real rate of return on assets before permissible expenses that is approximately 5 percent greater than the assumed rate of inflation, as measured by the consumer price index. The expected long-term rate of return is based on the asset categories in which the Company invests and the current expectations and historical performance for these categories. The mix and targeted allocation of the pension and OPEB plans’ assets are as follows: 2018 Assets at Target September 30, Asset Allocation Allocation 2017 2016 U.S. equity securities 40 % 39 % 38 % International equity securities 20 21 20 Fixed income 40 40 42 Total 100 % 100 % 100 % The Company adopted the revised mortality assumptions published by the Society of Actuaries for its pension and other postemployment benefit obligations, which reflected increased life expectancies in the United States. The adoption of the new mortality tables resulted in an increase to the projected benefit obligation for the plans. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid during the following years: (Thousands) Pension OPEB 2018 $ 8,928 $ 4,230 2019 $ 9,712 $ 4,807 2020 $ 10,549 $ 5,435 2021 $ 11,502 $ 6,061 2022 $ 12,469 $ 6,755 2023 - 2027 $ 79,081 $ 43,267 The Company’s OPEB plans provide prescription drug benefits that are actuarially equivalent to those provided by Medicare Part D. Therefore, under the Medicare Prescription Drug, Improvement and Modernization Act of 2003, the Company qualifies for federal subsidies. The estimated subsidy payments are as follows: Estimated Subsidy Payment Fiscal Year (Thousands) 2018 $262 2019 $283 2020 $311 2021 $342 2022 $373 2023 - 2027 $2,574 Pension and OPEB assets held in the master trust, measured at fair value, as of September 30, are summarized as follows: Quoted Prices in Active Markets for Identical Assets (Level 1) (Thousands) Pension OPEB Assets 2017 2016 2017 2016 Money market funds $ — $ — $ 11 $ 9 Registered Investment Companies: Equity Funds: Large Cap Index 88,321 78,306 23,986 19,532 Extended Market Index 16,329 16,250 4,409 4,114 International Stock 56,446 50,702 15,000 12,997 Fixed Income Funds: Emerging Markets 13,516 12,906 3,551 3,294 Core Fixed Income — — 8,082 7,177 Opportunistic Income — — 4,744 4,155 Ultra Short Duration — — 4,673 4,082 High Yield Bond Fund 26,540 25,976 7,078 6,675 Long Duration Fund 70,591 65,735 — — Total assets at fair value $ 271,743 $ 249,875 $ 71,534 $ 62,035 The Plan had no Level 2 or Level 3 fair value measurements during fiscal 2017 and 2016 , and there have been no changes in valuation methodologies as of September 30, 2017 . The following is a description of the valuation methodologies used for assets measured at fair value: Money Market funds — Represents bank balances and money market funds that are valued based on the net asset value of shares held at year end. Registered Investment Companies — Equity and fixed income funds valued at the net asset value of shares held by the plan at year end as reported on the active market on which the individual securities are traded. The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Plan believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. Defined Contribution Plan The Company offers a Savings Plan to eligible employees. As of January 1, 2015, the Company matches 65 percent of participants’ contributions up to 6 percent of base compensation. Represented NJRHS employees, non-represented employees hired on or after October 1, 2009 , and NJNG represented employees hired on or after January 1, 2012 , are eligible for an employer special contribution of between 3 and 4 percent of base compensation, depending on years of service, into the Savings Plan on their behalf. The amount expensed and contributed for the matching provision of the Savings Plan was $2.9 million in fiscal 2017 , $2.8 million in fiscal 2016 and $2.6 million in fiscal 2015 . The amount contributed for the employer special contribution of the Savings Plan was $781,000 in fiscal 2017 , $571,000 in fiscal 2016 and $461,000 in fiscal 2015 .

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	12. ASSET RETIREMENT OBLIGATIONS The Company recognizes AROs when the legal obligation to retire an asset has been incurred and a reasonable estimate of fair value can be made. Accordingly, the Company recognizes AROs related to the costs associated with cutting and capping its main and service gas distribution pipelines of NJNG, which is required by New Jersey law when taking such gas distribution pipeline out of service. The Company also recognizes AROs related to Clean Energy Ventures’ solar and wind assets when there are decommissioning provisions in Clean Energy Ventures’ lease agreements that require removal of the asset. Accretion amounts associated with NJNG’s ARO is recognized as part of its depreciation expense and the corresponding regulatory asset and liability will be shown gross on the Consolidated Balance Sheets. During fiscal 2016, accretion amounts were not reflected as an expense, but rather were deferred as a regulatory asset and netted against NJNG’s regulatory liabilities, for presentation purposes, on the Consolidated Balance Sheets. Accretion amounts associated with Clean Energy Ventures’ ARO are recognized as a component of operations and maintenance expense on the Consolidated Statements of Operations. The following is an analysis of the change in the Company’s AROs for the fiscal year ended September 30 : (Thousands) 2017 2016 NJNG NJRCEV NJNG NJRCEV Balance at October 1 $ 23,521 $ 4,858 $ 16,773 $ 2,372 Accretion 1,304 245 1,048 158 Additions 729 1,492 783 2,328 Revisions in estimated cash flows (245 ) — 5,320 — Retirements (484 ) — (403 ) — Balance at period end $ 24,825 $ 6,595 $ 23,521 $ 4,858 During fiscal 2016, NJNG revised its retirement assumptions to reflect an increase in inflation rates and construction costs. These increases, were discounted using the current credit adjusted risk free rate, resulting in an increase of approximately $5.3 million to the ARO liability. Accretion for the next five years is estimated to be as follows: (Thousands) Fiscal Year Ended September 30, Estimated Accretion 2018 $ 1,644 2019 1,718 2020 1,795 2021 1,877 2022 1,960 Total $ 8,994

INCOME TAXES

INCOME TAXES	12 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
INCOME TAXES	13. INCOME TAXES A reconciliation of the U.S. federal statutory rate of 35 percent to the effective rate from operations for the fiscal years ended September 30, 2017 , 2016 and 2015 is as follows: (Thousands) 2017 2016 2015 Statutory income tax expense $ 52,643 $ 54,321 $ 84,239 Change resulting from: State income taxes 8,222 6,044 8,233 Cost of removal of assets placed in service prior to1981 (6,886 ) (5,738 ) (5,149 ) Investment/production tax credits (34,526 ) (32,491 ) (30,096 ) Basis adjustment of solar assets due to ITC 4,256 4,453 4,861 AFUDC equity (2,624 ) (1,531 ) (1,339 ) Other (2,742 ) (1,528 ) (1,025 ) Income tax provision $ 18,343 $ 23,530 $ 59,724 Effective income tax rate 12.2 % 15.2 % 24.8 % The income tax (benefit) provision from operations consists of the following: (Thousands) 2017 2016 2015 Current: Federal $ (16,023 ) $ (23,597 ) $ 20,492 State 2,470 (2,209 ) 5,473 Deferred: Federal 54,965 70,386 56,480 State 11,457 11,441 7,375 Investment/production tax credits (34,526 ) (32,491 ) (30,096 ) Income tax provision $ 18,343 $ 23,530 $ 59,724 The temporary differences, which give rise to deferred tax assets and (liabilities), consist of the following: (Thousands) 2017 2016 Deferred tax assets Investment tax credits (1) $ 111,642 $ 76,517 Deferred service contract revenue 3,877 3,601 Incentive compensation 6,260 8,128 Fair value of derivatives 11,519 1,179 Federal net operating losses 28,487 27,541 State net operating losses 23,597 18,113 Overrecovered gas costs — 3,831 Other 13,845 11,668 Total deferred tax assets $ 199,227 $ 150,578 Deferred tax liabilities Property related items $ (620,850 ) $ (532,027 ) Remediation costs (11,625 ) (7,928 ) Equity investments (38,370 ) (37,740 ) Postemployment benefits (6,855 ) (7,902 ) Conservation incentive plan (7,195 ) (14,953 ) Underrecovered gas costs (4,035 ) — Other (16,643 ) (14,610 ) Total deferred tax liabilities $ (705,573 ) $ (615,160 ) Total net deferred tax liabilities $ (506,346 ) $ (464,582 ) (1) Includes $2.3 million and $2.5 million for NJNG for fiscal 2017 and 2016 , respectively , which is being amortized over the life of the related assets, and $109.3 million and $74 million for Clean Energy Ventures for fiscal 2017 and 2016 , respectively , which is ITC carryforward. The Company and one or more of its subsidiaries files or expects to file income and/or franchise tax returns in the U.S. Federal jurisdiction and in the states of Colorado, Connecticut, Delaware, Iowa, Kansas, Louisiana, Maryland, Montana, New Jersey, New York, North Carolina, Pennsylvania, South Carolina, Texas, Utah, Virginia and the City of New York. The Company neither files in, nor believes it has a filing requirement in, any foreign jurisdictions other than Canada. Due to certain available tax treaty benefits, the Company incurs no tax liability in Canada. The Company’s federal income tax returns through fiscal 2013 have either been reviewed by the IRS, or the related statute of limitations has expired and all matters have been settled. Federal income tax returns for periods subsequent to fiscal 2013 are not currently under examination by the IRS. The State of New Jersey is currently conducting a sales and use tax examination for the period from July 1, 2011 through June 30, 2016 . All periods subsequent to those ended September 30, 2013 , are statutorily open to examination in all applicable states with the exception of New York. In New York, all periods subsequent to September 30, 2014 , are statutorily open to examination. The Company evaluates its tax positions to determine the appropriate accounting and recognition of potential future obligations associated with unrecognized tax benefits. As of September 30, 2017 and 2016 , based on its analysis, the Company determined there was no need to recognize any liabilities associated with uncertain tax positions. As of September 30, 2017 and 2016 , the Company has consolidated federal income tax net operating losses of approximately $125.3 million and $78.7 million , respectively, which generally can be carried back two years and forward 20 years. The Company plans to exercise its ability to carryback its federal net operating losses. Additionally, as of September 30, 2017 and 2016 , the Company has state income tax net operating losses of approximately $471.7 million and $310.6 million , respectively. These state net operating losses have varying carry forward periods dictated by the state in which they were incurred; these state carry forward periods range from seven to 20 years. The Company has recorded deferred federal and state tax assets of approximately $52.1 million and federal income tax receivables of approximately $15.4 million on the Consolidated Balance Sheets, reflecting the tax benefit associated with the loss carrybacks. The Company recorded a valuation allowance associated with state net operating loss carryforwards of $1 million related to NJRCEV in the state of Montana, as of September 30, 2017 , and $262,000 related to CR&R in the state of New Jersey, as of September 30, 2016 , which was deemed more likely than not to be realized prior to expiration and therefore was released during fiscal 2017. In addition, as of September 30, 2017 , the Company has an ITC/PTC carryforward of approximately $109.3 million , which has a life of 20 years. This carryforward will begin to expire in fiscal 2035. The Company expects to utilize this entire carryforward. The deferred tax assets will expire as follows: (Thousands) Fiscal years 2018 - 2022 $ 313 Fiscal years 2023 - 2027 1,051 Fiscal years 2028 - 2032 796 Fiscal years 2033 - 2037 159,237 Total $ 161,397 In December 2015, the Consolidated Appropriations Act extended the 30 percent ITC for solar property that is under construction on or before December 31, 2019. The credit will decline to 26 percent for property under construction during 2020, and to 22 percent for property under construction during 2021. For any property that is under construction before 2022, but not placed in service before 2024, the ITC will be reduced to 10 percent. In addition, the Consolidated Appropriations Act retroactively extended the PTC for five years through December 31, 2019, with a gradual three-year phase out for any project for which construction of the facility begins after December 31, 2016.

COMMITMENTS AND CONTINGENT LIAB

COMMITMENTS AND CONTINGENT LIABILITIES	12 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENT LIABILITIES	14. COMMITMENTS AND CONTINGENT LIABILITIES Cash Commitments NJNG has entered into long-term contracts, expiring at various dates through October 2033 , for the supply, storage and transportation of natural gas. These contracts include annual fixed charges of approximately $98.6 million at current contract rates and volumes, which are recoverable through BGSS. For the purpose of securing storage and pipeline capacity, our Energy Services segment enters into storage and pipeline capacity contracts, which require the payment of certain demand charges by Energy Services to maintain the ability to access such natural gas storage or pipeline capacity, during a fixed time period, which generally ranges from one to 10 years. Demand charges are established by interstate storage and pipeline operators and are regulated by FERC. These demand charges represent commitments to pay storage providers or pipeline companies for the right to store and/or transport natural gas utilizing their respective assets. Commitments as of September 30, 2017 , for natural gas purchases and future demand fees for the next five fiscal year periods, are as follows: (Thousands) 2018 2019 2020 2021 2022 Thereafter Energy Services: Natural gas purchases $ 296,491 $ 114,817 $ 22,270 $ 11,488 $ — $ — Storage demand fees 32,870 22,638 13,350 9,041 5,833 2,746 Pipeline demand fees 55,916 32,412 23,804 21,621 19,653 19,311 Sub-total Energy Services $ 385,277 $ 169,867 $ 59,424 $ 42,150 $ 25,486 $ 22,057 NJNG: Natural gas purchases $ 51,050 $ 41,156 $ 2,514 $ — $ — $ — Storage demand fees 30,042 26,628 15,331 8,231 7,804 3,903 Pipeline demand fees 68,544 102,091 100,909 91,231 89,859 642,481 Sub-total NJNG $ 149,636 $ 169,875 $ 118,754 $ 99,462 $ 97,663 $ 646,384 Total $ 534,913 $ 339,742 $ 178,178 $ 141,612 $ 123,149 $ 668,441 As of September 30, 2017 , the Company’s future minimum lease payments under various operating leases will not be more than $2.6 million annually for the next five years and $38.3 million in the aggregate for all years thereafter. Guarantees As of September 30, 2017 , there were NJR guarantees covering approximately $331.4 million of Energy Services’ natural gas purchases and demand fee commitments not yet reflected in accounts payable on the Consolidated Balance Sheets. Legal Proceedings Manufactured Gas Plant Remediation NJNG is responsible for the remedial cleanup of five MGP sites, dating back to gas operations in the late 1800s and early 1900s, which contain contaminated residues from former gas manufacturing operations. NJNG is currently involved in administrative proceedings with the NJDEP, and participating in various studies and investigations by outside consultants, to determine the nature and extent of any such contaminated residues and to develop appropriate programs of remedial action, where warranted, under Administrative Consent Orders or Memoranda of Agreement with the NJDEP. NJNG may recover its remediation expenditures, including carrying costs, over rolling seven -year periods pursuant to a RAC approved by the BPU. NJNG currently recovers approximately $9.4 million annually through its SBC RAC. On November 17, 2017 , NJNG filed it's annual SBC application requesting a reduction in the RAC, which will decrease the annual recovery to $7 million , effective April 1, 2018 . As of September 30, 2017 , $28.5 million of previously incurred remediation costs, net of recoveries from customers and insurance proceeds, are included in regulatory assets on the Consolidated Balance Sheets. NJNG periodically, and at least annually, performs an environmental review of the MGP sites, including a review of potential liability for investigation and remedial action. NJNG estimated at the time of the most recent review that total future expenditures to remediate and monitor the five MGP sites for which it is responsible, including potential liabilities for Natural Resource Damages that might be brought by the NJDEP for alleged injury to groundwater or other natural resources concerning these sites, will range from approximately $117.6 million to $205.2 million . NJNG’s estimate of these liabilities is based upon known facts, existing technology and enacted laws and regulations in place when the review was completed. Where it is probable that costs will be incurred, and the information is sufficient to establish a range of possible liability, NJNG accrues the most likely amount in the range. If no point within the range is more likely than the other, it is NJNG’s policy to accrue the lower end of the range. Accordingly, as of September 30, 2017 , NJNG recorded an MGP remediation liability and a corresponding regulatory asset of $149 million on the Consolidated Balance Sheets, based on the most likely amount. This was reduced from $172 million in fiscal 2016, due to the completion of remediation work at some of sites and a reduction to the remediation scope at another site. The actual costs to be incurred by NJNG are dependent upon several factors, including final determination of remedial action, changing technologies and governmental regulations, the ultimate ability of other responsible parties to pay and any insurance recoveries. NJNG will continue to seek recovery of MGP-related costs through the RAC. If any future regulatory position indicates that the recovery of such costs is not probable, the related non-recoverable costs would be charged to income in the period of such determination. Litigation The Company is involved, and from time to time in the future may be involved, in a number of pending and threatened judicial, regulatory and arbitration proceedings relating to matters that arise in connection with the conduct of its business. In view of the inherent difficulty of predicting the outcome of litigation matters, particularly when such matters are in their early stages or where the claimants seek indeterminate damages, the Company cannot state with confidence what the eventual outcome of the pending litigation will be, what the timing of the ultimate resolution of these matters will be, or what the eventual loss, fines or penalties related to each pending matter will be, if any. In accordance with applicable accounting guidance, NJR establishes reserves for litigation for those matters that present loss contingencies as to which it is both probable that a loss will be incurred and the amount of such loss can be reasonably estimated. Based upon currently available information, NJR believes that the results of litigation that is currently pending, taken together, will not have a materially adverse effect on the Company’s financial condition, results of operations or cash flows. The actual results of resolving the pending litigation matters may be substantially higher than the amounts reserved. The foregoing statements about NJR’s litigation are based upon the Company’s judgments, assumptions and estimates and are necessarily subjective and uncertain. The Company has a number of threatened and pending litigation matters at various stages. Certain of the Company’s significant litigation is described below. On February 24, 2015, a natural gas fire and explosion occurred in Stafford Township, New Jersey as a result of a natural gas leak emanating from an underground pipe. There were no fatalities, although several employees of NJNG were injured and several homes were damaged. NJNG notified its insurance carrier and believes that any costs associated with the incident, including attorneys’ fees, property damage and other losses, will be substantially covered by insurance. The Company believes the resolution of any potential claims associated with the incident will not have a material effect on its financial condition, results of operations or cash flows. As of September 30, 2017 , NJNG estimates that liabilities associated with claims will range between $600,000 and $3.2 million and has accrued the lower end of the range.

BUSINESS SEGMENT AND OTHER OPER

BUSINESS SEGMENT AND OTHER OPERATIONS DATA	12 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
BUSINESS SEGMENT AND OTHER OPERATIONS DATA	15. REPORTING SEGMENT AND OTHER OPERATIONS DATA The Company organizes its businesses based on a combination of factors, including its products and its regulatory environment. As a result, the Company manages its businesses through the following reporting segments and other operations: the Natural Gas Distribution segment consists of regulated energy and off-system, capacity and storage management operations; the Clean Energy Ventures segment consists of capital investments in clean energy projects; the Energy Services segment consists of unregulated wholesale and retail energy operations; the Midstream segment consists of the Company’s investments in natural gas transportation and storage facilities; the Home Services and Other operations consist of heating, cooling and water appliance sales, installations and services, other investments and general corporate activities. Information related to the Company’s various reporting segments and other operations is detailed below: (Thousands) Fiscal Years Ended September 30, 2017 2016 2015 Operating revenues Natural Gas Distribution External customers $ 695,637 $ 594,346 $ 781,970 Clean Energy Ventures External customers 64,394 53,540 32,513 Energy Services External customers (1) 1,462,365 1,187,754 1,872,781 Intercompany 316 9,499 61,526 Subtotal 2,222,712 1,845,139 2,748,790 Home Services and Other External customers 46,221 45,265 46,723 Intercompany 3,370 3,232 1,980 Eliminations (3,686 ) (12,731 ) (63,506 ) Total $ 2,268,617 $ 1,880,905 $ 2,733,987 Depreciation and amortization Natural Gas Distribution $ 49,347 $ 47,828 $ 43,085 Clean Energy Ventures 31,834 23,971 17,297 Energy Services 63 88 90 Midstream 6 6 6 Subtotal 81,250 71,893 60,478 Home Services and Other 798 981 952 Eliminations (207 ) (126 ) (31 ) Total $ 81,841 $ 72,748 $ 61,399 Interest income (2) Natural Gas Distribution $ 555 $ 115 $ 336 Clean Energy Ventures — — 26 Energy Services 6 98 438 Midstream 2,195 1,524 977 Subtotal 2,756 1,737 1,777 Home Services and Other 590 397 217 Eliminations (1,312 ) (2,006 ) (1,414 ) Total $ 2,034 $ 128 $ 580 (1) Includes sales to Canada, which accounted for .8 , 2 and 3.7 percent of total operating revenues during fiscal 2017 , 2016 and 2015 , respectively . (2) Included in other income, net on the Consolidated Statements of Operations. (Thousands) Fiscal Years Ended September 30, 2017 2016 2015 Interest expense, net of capitalized interest Natural Gas Distribution $ 25,818 $ 19,930 $ 18,534 Clean Energy Ventures 16,263 10,304 7,635 Energy Services 2,747 1,095 1,209 Midstream 960 287 717 Subtotal 45,788 31,616 28,095 Home Services and Other 410 252 49 Eliminations (1,312 ) (824 ) (423 ) Total $ 44,886 $ 31,044 $ 27,721 Income tax (benefit) provision Natural Gas Distribution $ 43,485 $ 34,951 $ 39,544 Clean Energy Ventures (31,161 ) (26,592 ) (26,968 ) Energy Services (4,015 ) 7,030 39,043 Midstream 5,820 6,130 6,849 Subtotal 14,129 21,519 58,468 Home Services and Other 3,857 1,387 1,551 Eliminations 357 624 (295 ) Total $ 18,343 $ 23,530 $ 59,724 Equity in earnings of affiliates Midstream $ 17,797 $ 13,936 $ 17,487 Eliminations (3,984 ) (4,421 ) (4,078 ) Total $ 13,813 $ 9,515 $ 13,409 Net financial earnings Natural Gas Distribution $ 86,930 $ 76,104 $ 76,287 Clean Energy Ventures 24,873 28,393 20,101 Energy Services 18,554 21,934 42,122 Midstream 12,857 9,406 9,780 Subtotal 143,214 135,837 148,290 Home Services and Other 6,811 2,882 3,420 Eliminations (633 ) (634 ) (207 ) Total $ 149,392 $ 138,085 $ 151,503 Capital expenditures Natural Gas Distribution $ 176,249 $ 205,133 $ 168,875 Clean Energy Ventures 149,400 149,063 151,002 Subtotal 325,649 354,196 319,877 Home Services and Other 2,434 1,896 209 Total $ 328,083 $ 356,092 $ 320,086 Investments in equity investees Midstream 27,070 11,176 5,780 Total $ 27,070 $ 11,176 $ 5,780 The Chief Executive Officer, who uses NFE as a measure of profit or loss in measuring the results of the Company’s reporting segments and operations, is the chief operating decision maker of the Company. A reconciliation of consolidated NFE to consolidated net income is as follows: (Thousands) 2017 2016 2015 Consolidated net financial earnings $ 149,392 $ 138,085 $ 151,503 Less: Unrealized (gain) loss on derivative instruments and related transactions (11,241 ) 46,883 (38,681 ) Tax effect 4,062 (17,018 ) 14,391 Effects of economic hedging related to natural gas inventory 38,470 (36,816 ) (8,225 ) Tax effect (13,964 ) 13,364 3,058 Consolidated net income $ 132,065 $ 131,672 $ 180,960 The Company uses derivative instruments as economic hedges of purchases and sales of physical gas inventory. For GAAP purposes, these derivatives are recorded at fair value and related changes in fair value are included in reported earnings. Revenues and cost of gas related to physical gas flow is recognized when the gas is delivered to customers. Consequently, there is a mismatch in the timing of earnings recognition between the economic hedges and physical gas flows. Timing differences occur in two ways: • Unrealized gains and losses on derivatives are recognized in reported earnings in periods prior to physical gas inventory flows; and • Unrealized gains and losses of prior periods are reclassified as realized gains and losses when derivatives are settled in the same period as physical gas inventory movements occur. NFE is a measure of the earnings based on eliminating these timing differences, to effectively match the earnings effects of the economic hedges with the physical sale of gas, SRECs and foreign currency contracts. Consequently, to reconcile between net income and NFE, current period unrealized gains and losses on the derivatives are excluded from NFE as a reconciling item. Additionally, realized derivative gains and losses are also included in current period net income. However, NFE includes only realized gains and losses related to natural gas sold out of inventory, effectively matching the full earnings effects of the derivatives with realized margins on physical gas flows. The Company also calculates a quarterly tax adjustment based on an estimated annual effective tax rate for NFE purposes. The Company’s assets for the various reporting segments and business operations are detailed below: (Thousands) 2017 2016 2015 Assets at end of period: Natural Gas Distribution $ 2,519,578 $ 2,517,401 $ 2,305,293 Clean Energy Ventures 771,340 665,696 504,885 Energy Services 398,277 327,626 260,021 Midstream 232,806 186,259 182,007 Subtotal 3,922,001 3,696,982 3,252,206 Home Services and Other 114,801 109,487 88,880 Intercompany assets (1) (108,295 ) (87,899 ) (56,729 ) Total $ 3,928,507 $ 3,718,570 $ 3,284,357 (1) Consists of transactions between subsidiaries that are eliminated and reclassified in consolidation.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	16. RELATED PARTY TRANSACTIONS In January 2010 , NJNG entered into a 10 -year agreement effective April 1, 2010 , for 3 Bcf of firm storage capacity with Steckman Ridge. Under the terms of the agreement, NJNG incurs demand fees, at market rates, of approximately $9.3 million annually, a portion of which is eliminated in consolidation. These fees are recoverable through NJNG’s BGSS mechanism and are included in regulatory assets. Energy Services may periodically enter into storage or park and loan agreements with its affiliated FERC-regulated natural gas storage facility, Steckman Ridge. As of September 30, 2017 , Energy Services has entered into storage and park and loan transactions with Steckman Ridge for varying terms, all of which expire by October 31, 2020 . Demand fees, net of eliminations, associated with Steckman Ridge during the fiscal years ended September 30 , are as follows: (Thousands) 2017 2016 2015 NJNG $ 5,590 $ 5,562 $ 5,700 Energy Services 2,750 2,789 1,957 Total $ 8,340 $ 8,351 $ 7,657 The following table summarizes demand fees payable to Steckman Ridge as of September 30 : (Thousands) 2017 2016 NJNG $ 775 $ 775 Energy Services 377 375 Total $ 1,152 $ 1,150 NJNG and Energy Services have entered into various asset management agreements, the effects of which are eliminated in consolidation. Under the terms of these agreements, NJNG releases certain transportation and storage contracts to Energy Services. NJNG retains the right to purchase market priced gas or fixed price storage gas from Energy Services. As of September 30, 2017 , NJNG and Energy Services had four asset management agreements with expiration dates ranging from October 31, 2017 through October 31, 2020 . NJNG has entered into a 15 -year transportation precedent agreement for committed capacity of 180,000 Dths per day with PennEast, to commence when in service.

SELECTED QUARTERLY FINANCIAL DA

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Sep. 30, 2017
Quarterly Financial Information Disclosure [Abstract]
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)	17. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) A summary of financial data for each quarter of fiscal 2017 and 2016 follows. Due to the seasonal nature of the Company’s businesses, quarterly amounts vary significantly during the fiscal year. In the opinion of management, the information furnished reflects all adjustments necessary for a fair presentation of the results of the interim periods. First Second Third Fourth (Thousands, except per share data) Quarter Quarter Quarter Quarter 2017 Operating revenues $ 541,028 $ 733,546 $ 457,523 $ 536,520 Operating income (loss) $ 41,475 $ 139,653 $ 17,967 $ (32,051 ) Net income (loss) $ 34,929 $ 114,702 $ 18,957 $ (36,523 ) Earnings (loss) per share (1) Basic $0.41 $1.33 $0.22 $(0.42) Diluted $0.40 $1.32 $0.22 $(0.42) 2016 Operating revenues $ 444,258 $ 574,193 $ 393,213 $ 469,241 Operating income (loss) $ 59,451 $ 93,933 $ (28,329 ) $ 42,480 Net income (loss) $ 50,281 $ 73,354 $ (17,363 ) $ 25,400 Earnings (loss) per share (1) Basic $0.59 $0.85 $(0.20) $0.30 Diluted $0.58 $0.84 $(0.20) $0.29 (1) The sum of quarterly amounts may not equal the annual amounts due to rounding.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Sep. 30, 2017
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	18. SUBSEQUENT EVENTS Acquisition On October 27, 2017 , Adelphia, an indirect wholly owned subsidiary of NJR, entered into a Purchase and Sale Agreement with Talen pursuant to which Adelphia will acquire all of Talen’s membership interests in IEC for a base purchase price of $166 million . which includes a $10 million initial payment. As additional consideration, Adelphia will pay Talen specified amounts of up to $23 million contingent upon the achievement of certain regulatory approvals and binding natural gas capacity commitments. IEC owns an existing 84 -mile pipeline in southeastern Pennsylvania. The transaction is expected to close following receipt of necessary permits and regulatory actions including those from the FERC and the Pennsylvania Public Utility Commission. Upon the closing of the transactions contemplated by the purchase and sale agreement, Adelphia will acquire IEC and, with it, IEC’s existing pipeline, related assets and rights of way. Adelphia has also agreed to provide firm natural gas transportation service for ten years following the closing to two power generators owned by affiliates of Talen that are currently served by IEC.

VALUATION AND QUALIFYING ACCOUN

VALUATION AND QUALIFYING ACCOUNTS	12 Months Ended
	Sep. 30, 2017
Valuation and Qualifying Accounts [Abstract]
VALUATION AND QUALIFYING ACCOUNTS	VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED SEPTEMBER 30, 2017 , 2016 and 2015 (Thousands) ADDITIONS CLASSIFICATION BEGINNING BALANCE CHARGED TO EXPENSE OTHER (1) ENDING BALANCE 2017 Allowance for doubtful accounts $ 4,865 2,023 (1,707 ) $ 5,181 2016 Allowance for doubtful accounts $ 5,189 1,616 (1,940 ) $ 4,865 2015 Allowance for doubtful accounts $ 5,357 2,859 (3,027 ) $ 5,189 (1) Uncollectible accounts written off, less recoveries and adjustments.

SUMMARY OF SIGNIFICANT ACCOUN29

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The Consolidated Financial Statements include the accounts of the Company and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated. Other financial investments or contractual interests that lack the characteristics of a voting interest entity, which are commonly referred to as variable interest entities, are evaluated by the Company to determine if it has the power to direct business activities and, therefore, would be considered a controlling interest that the Company would have to consolidate. Based on those evaluations, NJR has determined that it does not have any investments in variable interest entities as of September 30, 2017 , 2016 and 2015 . Investments in entities over which the Company does not have a controlling financial interest are either accounted for under the equity method or cost method of accounting.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires the Company to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a monthly basis, the Company evaluates its estimates, including those related to the calculation of the fair value of derivative instruments, debt, unbilled revenues, allowance for doubtful accounts, provisions for depreciation and amortization, regulatory assets and liabilities, income taxes, pensions and other postemployment benefits, contingencies related to environmental matters and litigation. AROs are evaluated as often as needed. The Company’s estimates are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. The Company has legal, regulatory and environmental proceedings during the normal course of business that can result in loss contingencies. When evaluating the potential for a loss, the Company will establish a reserve if a loss is probable and can be reasonably estimated, in which case it is the Company’s policy to accrue the full amount of such estimates. Where the information is sufficient only to establish a range of probable liability, and no point within the range is more likely than any other, it is the Company’s policy to accrue the lower end of the range. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from estimates.
Business Combinations	Business Combinations The Company accounts for business combinations by applying the acquisition method of accounting. Identifiable assets acquired and liabilities assumed are measured separately at their fair value as of the acquisition date and associated transactions costs are expensed as incurred. The determination and allocation of fair values to the identifiable assets acquired and liabilities assumed are based on various assumptions and valuation methodologies requiring considerable management judgment. The most significant variables in these valuations are discount rates, the number of years on which to base the cash flow projections, as well as other assumptions and estimates used to determine the cash inflows and outflows. Management determines discount rates based on the risk inherent in the acquired assets and related cash flows. Our valuation of an acquired business is based on available information at the acquisition date and assumptions that we believe are reasonable. However, a change in facts and circumstances as of the acquisition date can result in subsequent adjustments during the measurement period, but no later than one year from the acquisition date.
Regulatory Assets & Liabilities	Regulatory Assets & Liabilities Under cost-based regulation, regulated utility enterprises generally are permitted to recover their operating expenses and earn a reasonable rate of return on their utility investment. Our Natural Gas Distribution segment maintains its accounts in accordance with the FERC Uniform System of Accounts as prescribed by the BPU and in accordance with the Regulated Operations Topic of the FASB ASC. As a result of the impact of the ratemaking process and regulatory actions of the BPU, NJNG is required to recognize the economic effects of rate regulation. Accordingly, NJNG capitalizes or defers certain costs that are expected to be recovered from its customers as regulatory assets and recognizes certain obligations representing probable future expenditures as regulatory liabilities on the Consolidated Balance Sheets.
Gas in Storage	Gas in Storage Gas in storage is reflected at average cost on the Consolidated Balance Sheets, and represents natural gas and LNG that will be utilized in the ordinary course of business.
Demand Fees	Energy Services expenses demand charges ratably over the term of the service being provided. Our Natural Gas Distribution segment’s costs associated with demand charges are included in its weighted average cost of gas. The demand charges are expensed based on NJNG’s BGSS sales and recovered as part of its gas commodity component of its BGSS tariff. Demand Fees For the purpose of securing storage and pipeline capacity in support of their respective businesses, our Energy Services and Natural Gas Distribution segments enter into storage and pipeline capacity contracts, which require the payment of associated demand fees and charges that allow them access to a high priority of service in order to maintain the ability to access storage or pipeline capacity during a fixed time period, which generally ranges from one to 10 years. Many of these demand fees and charges are based on established tariff rates as established and regulated by FERC. These charges represent commitments to pay storage providers and pipeline companies for the priority right to transport and/or store natural gas utilizing their respective assets.
Derivative Instruments	Derivative Instruments The Company accounts for its financial instruments, such as futures, options, foreign exchange contracts, interest rate contracts, as well as its physical commodity contracts related to the purchase and sale of natural gas at Energy Services, as derivatives, and therefore recognizes them at fair value on the Consolidated Balance Sheets. The Company’s unregulated subsidiaries record changes in the fair value of their financial commodity derivatives in gas purchases and changes in the fair value of their physical forward contracts in gas purchases or operating revenues, as appropriate, on the Consolidated Statements of Operations. Energy Services designated its foreign exchange contracts, entered into prior to January 1, 2016, as cash flow hedges of Canadian dollar denominated gas purchases. Changes in the fair value of the effective portion of these hedges are recorded to AOCI, a component of stockholders’ equity, and reclassified to gas purchases on the Consolidated Statements of Operations when they settle. Ineffective portions of the cash flow hedges are recognized immediately in earnings. The Company did not have derivatives designated as fair value hedges during fiscal 2016 and 2017 . The Derivatives and Hedging Topic of the ASC also provides for a NPNS scope exception for qualifying physical commodity contracts that are intended for purchases and sales during the normal course of business and for which physical delivery is probable. Effective January 1, 2016, the Company prospectively applies this normal scope exception on a case-by-case basis to physical commodity contracts at NJNG and forward SREC contracts at Clean Energy Ventures. When applied, it does not record changes in the fair value of these contracts until the contract settles and the related underlying natural gas or SREC is delivered. Gains and/or losses on NJNG’s derivatives used to economically hedge its regulated natural gas supply obligations, as well as its exposure to interest rate variability, are recoverable through its BGSS, a component of its tariff. Accordingly, the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability on the Consolidated Balance Sheets. See Note 5. Derivative Instruments for additional details regarding natural gas trading and hedging activities. Fair values of exchange-traded instruments, including futures, swaps, and certain options, are based on unadjusted, quoted prices in active markets. The Company’s non-exchange-traded financial instruments, foreign currency derivatives, over-the-counter physical commodity contracts at Energy Services and NJNG’s Treasury Lock are valued using observable, quoted prices for similar or identical assets when available. In establishing the fair value of contracts for which a quoted basis price is not available at the measurement date, management utilizes available market data and pricing models to estimate fair values. Fair values are subject to change in the near term and reflect management’s best estimate based on a variety of factors. Estimating fair values of instruments that do not have quoted market prices requires management’s judgment in determining amounts that could reasonably be expected to be received from, or paid to, a third party in settlement of the instruments. These amounts could be materially different from amounts that might be realized in an actual sale transaction. The Company is subject to commodity price risk due to fluctuations in the market price of natural gas, SRECs and electricity. To manage this risk, the Company enters into a variety of derivative instruments including, but not limited to, futures contracts, physical forward contracts, financial options and swaps to economically hedge the commodity price risk associated with its existing and anticipated commitments to purchase and sell natural gas, SRECs and electricity. In addition, the Company may utilize foreign currency derivatives to hedge Canadian dollar denominated gas purchases and/or sales. Therefore, the Company’s primary underlying risks include commodity prices, interest rates and foreign currency. These contracts, with a few exceptions as described below, are accounted for as derivatives. Accordingly, all of the financial and certain of the Company’s physical derivative instruments are recorded at fair value on the Consolidated Balance Sheets. For a more detailed discussion of the Company’s fair value measurement policies and level disclosures associated with the Company’s derivative instruments, see Note 6. Fair Value . Energy Services Energy Services chooses not to designate its financial commodity and physical forward commodity derivatives as accounting hedges or to elect NPNS, and therefore changes in the fair value of these derivatives are recorded as a component of gas purchases or operating revenues, as appropriate for Energy Services, on the Consolidated Statements of Operations as unrealized gains or (losses). For Energy Services at settlement, realized gains and (losses) on all financial derivative instruments are recognized as a component of gas purchases and realized gains and (losses) on all physical derivatives follow the presentation of the related unrealized gains and (losses) as a component of either gas purchases or operating revenues. Energy Services also enters into natural gas transactions in Canada and, consequently, is exposed to fluctuations in the value of Canadian currency relative to the U.S. dollar. Energy Services may utilize foreign currency derivatives to lock in the exchange rate associated with natural gas transactions denominated in Canadian currency. The derivatives may include currency forwards, futures, or swaps and are accounted for as derivatives. These derivatives are typically used to hedge demand fee payments on pipeline capacity, storage and gas purchase agreements. For transactions occurring on or before December 31, 2015, Energy Services designates its foreign exchange contracts as cash flow hedges, and the effective portion of the hedges are recorded in OCI. Effective January 1, 2016, on a prospective basis, the Company has elected not to designate its foreign currency derivatives as accounting hedges. Accordingly, changes in the fair value of foreign exchange contracts entered into from January 1, 2016, are recognized in gas purchases on the Consolidated Statements of Operations. As a result of Energy Services entering into transactions to borrow natural gas, commonly referred to as “park and loans,” an embedded derivative is recognized relating to differences between the fair value of the amount borrowed and the fair value of the amount that will ultimately be repaid, based on changes in the forward price for natural gas prices at the borrowed location over the contract term. This embedded derivative is accounted for as a forward sale in the month in which the repayment of the borrowed gas is expected to occur, and is considered a derivative transaction that is recorded at fair value on the Consolidated Balance Sheets, with changes in value recognized in current period earnings. Expected production of SRECs is hedged through the use of forward and futures contracts. All contracts require the Company to physically deliver SRECs through the transfer of certificates as per contractual settlement schedules. For transactions occurring on or before December 31, 2015, the Company elected NPNS accounting treatment on SREC forward and futures contracts. Effective January 1, 2016, on a prospective basis, Energy Services no longer elects NPNS accounting treatment on SREC contracts entered into from January 1, 2016, and recognizes changes in the fair value of these derivatives as a component of operating revenues. Upon settlement of the contract, the related revenue is recognized when the SREC is transferred to the counterparty. NPNS is a contract-by-contract election and, where it makes sense to do so, we can and may elect certain contracts to be normal. Natural Gas Distribution Changes in fair value of NJNG’s financial commodity derivatives are recorded as a component of regulatory assets or liabilities on the Consolidated Balance Sheets. The Company elects NPNS accounting treatment on all physical commodity contracts that NJNG entered into on or before December 31, 2015, and accounts for these contracts on an accrual basis. Accordingly, physical natural gas purchases are recognized in regulatory assets or liabilities on the Consolidated Balance Sheets when the contract settles and the natural gas is delivered. The average cost of natural gas is amortized in current period earnings based on the current BPU BGSS factor and therm sales. Effective January 1, 2016, on a prospective basis, NJNG no longer elects NPNS accounting treatment on all of its physical commodity contracts entered into from January 1, 2016. However, since NPNS is a contract-by-contract election, where it makes sense to do so, we can and may elect certain contracts to be normal. Because NJNG recovers these amounts through future BGSS rates as increases or decreases to the cost of natural gas in NJNG’s tariff for gas service, the changes in fair value of these contracts are deferred as a component of regulatory assets or liabilities on the Consolidated Balance Sheets.
Revenues	Revenues Revenues from the sale of natural gas to NJNG customers are recognized in the period that gas is delivered and consumed by customers, including an estimate for unbilled revenue. NJNG records unbilled revenue for natural gas services. Natural gas sales to individual customers are based on meter readings, which are performed on a systematic basis throughout the month. At the end of each month, the amount of natural gas delivered to each customer after the last meter reading through the end of the respective accounting period is estimated, and recognizes unbilled revenues related to these amounts. The unbilled revenue estimates are based on estimated customer usage by customer type, weather effects, unaccounted-for gas and the most current tariff rates. Clean Energy Ventures recognizes revenue when SRECs are transferred to counterparties. SRECs are physically delivered through the transfer of certificates as per contractual settlement schedules. Revenues for Energy Services are recognized when the natural gas is physically delivered to the customer. In addition, changes in the fair value of derivatives that economically hedge the forecasted sales of the natural gas are recognized in operating revenues as they occur, as noted above. Energy Services also recognizes changes in the fair value of SREC derivative contracts as a component of operating revenues. Revenues from all other activities are recorded in the period during which products or services are delivered and accepted by customers, or over the related contractual term.
Gas Purchases	Gas Purchases NJNG’s tariff includes a component for BGSS, which is designed to allow it to recover the cost of natural gas through rates charged to its customers and is typically revised on an annual basis. As part of computing its BGSS rate, NJNG projects its cost of natural gas, net of supplier refunds, the impact of hedging activities and cost savings created by BGSS incentive programs. NJNG subsequently recovers or credits the difference, if any, of actual costs compared with those included in current rates. Any underrecoveries or overrecoveries are either credited to customers or deferred and, subject to BPU approval, reflected in the BGSS rates in subsequent years. Gas purchases at Energy Services are comprised of gas costs to be paid upon completion of a variety of transactions, as well as realized gains and losses from settled derivative instruments and unrealized gains and losses on the change in fair value of derivative instruments that have not yet settled. Changes in the fair value of derivatives that economically hedge the forecasted purchases of natural gas are recognized in gas purchases as they occur.
Income Taxes	Income Taxes The Company computes income taxes using the asset and liability method, whereby deferred income taxes are generally determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. See Note 13. Income Taxes . In addition, the Company evaluates its tax positions to determine the appropriate accounting and recognition of future obligations associated with unrecognized tax benefits. The Company invests in property that qualifies for federal ITCs and utilizes the ITCs, as allowed, based on the cost and life of the assets. ITCs at NJNG are deferred and amortized as a reduction to the tax provision over the average lives of the related equipment in accordance with regulatory treatment. ITCs at NJR’s unregulated subsidiaries are recognized as a reduction to income tax expense when the property is placed in service. The Company invests in property that qualifies for PTCs. PTCs are recognized as reductions to current federal income tax expense as PTCs are generated through the production activities of the assets. Changes to the federal statutes related to ITCs and PTCs, which have the effect of reducing or eliminating the credits, could have a negative impact on earnings and cash flows.
Capitalized and Deferred Interest	Capitalized and Deferred Interest NJNG’s base rates include the ability to recover AFUDC on its construction work in progress. For all NJNG construction projects, an incremental cost of equity is recoverable during periods when NJNG’s short-term debt balances are lower than its construction work in progress. For more information on AFUDC treatment with respect to certain accelerated infrastructure projects, see Note 4. Regulation - Infrastructure programs. Capitalized amounts associated with the debt and equity components of NJNG’s AFUDC are recorded in utility plant on the Consolidated Balance Sheets. Corresponding amounts for the debt component is recognized in interest expense and in other income for the equity component on the Consolidated Statements of Operations and include the following for the fiscal years ended September 30: ($ in thousands) 2017 2016 2015 AFUDC: Debt $ 1,311 $ 5,009 $ 2,472 Equity 3,867 4,375 3,825 Total $ 5,178 $ 9,384 $ 6,297 Weighted average interest rate 6.90 % 5.06 % 4.63 % Pursuant to a BPU order, NJNG is permitted to recover carrying costs on uncollected balances related to SBC program costs, which include NJCEP, RAC and USF expenditures.
Sale-Leasebacks	Sale-Leasebacks The Company utilizes sale-leaseback arrangements to fund certain of its capital expenditures, whereby the physical asset is sold concurrent with an agreement to lease the asset back, with options that allow the Company to renew the lease at the end of the term or repurchase the asset. Proceeds from sale-leaseback transactions are included in long-term debt on the Consolidated Balance Sheets. For certain of its commercial solar energy projects, the Company enters into lease agreements that provide for the sale of commercial solar energy assets to third-parties and the concurrent leaseback of the assets. For sale-leaseback transactions where the Company has concluded that the terms of the arrangement create a continuing involvement in the asset and the asset is considered integral equipment, the Company uses the financing method to account for the transaction. Under the financing method, the Company recognizes the proceeds received from the lessor that constitute a payment to acquire the solar energy asset as a financing arrangement, which is recorded as a component of debt on the Consolidated Balance Sheets. During fiscal 2017 and 2016 , NJNG received $9.6 million and $7.1 million , respectively, in connection with the sale-leaseback of its natural gas meters with terms ranging from seven to 11 years. In September 2017, Clean Energy Ventures received $32.9 million in proceeds related to the sale of two commercial solar assets. Clean Energy Ventures simultaneously entered into an agreement to lease the assets back over seven -year terms. The Company will continue to operate the solar assets including related expenses and retain the revenue generated from SRECs and energy sales. The ITCs and other tax benefits associated with these solar projects were transferred to the buyer, however, the lease payments are structured so that Clean Energy Ventures is compensated for the transfer of the related tax incentives. Accordingly, Clean Energy Ventures will recognize the equivalent value of the ITC in other income on the Consolidated Statements of Operations over the respective five-year ITC recapture periods that are recognized as the recapture periods expire, starting at the beginning of the second year of the lease.
Sales Tax Accounting	Sales Tax Accounting Sales tax that is collected from customers is presented in both operating revenues and operating expenses on the Consolidated Statements of Operations.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of cash on deposit and temporary investments with maturities of three months or less, and excludes restricted cash of $243,000 and $1.6 million as of September 30, 2017 and 2016 , respectively, related to escrow balances for utility plant projects, which is recorded in other current and noncurrent assets on the Consolidated Balance Sheets.
Property Plant and Equipment	Property Plant and Equipment Regulated property, plant and equipment and solar and wind equipment are stated at original cost. Regulated property, plant and equipment costs include direct labor, materials and third-party construction contractor costs, AFUDC and certain indirect costs related to equipment and employees engaged in construction. Upon retirement, the cost of depreciable regulated property, plus removal costs less salvage, is charged to accumulated depreciation with no gain or loss recorded. Depreciation is computed on a straight-line basis over the useful life of the assets for unregulated assets, and using rates based on the estimated average lives of the various classes of depreciable property for NJNG.
Intangible Assets and Long-Lived Assets	Intangible Assets Finite-lived intangible assets are stated at cost less accumulated amortization. The Company amortizes intangible assets based upon the pattern in which the economic benefits are consumed over the life of the asset unless a pattern cannot be reliably determined, in which case the Company uses a straight-line amortization method. As of September 30, 2017, the Company has an intangible asset, net of amortization, of $41.1 million related to its acquisition of Talen's wholesale natural gas energy contracts. These contracts are being amortized based upon expected cash flows over the respective terms of the agreements. The estimated future amortization expense for the next five years as of September 30, is as follows: (Thousands) 2018 $ 18,222 2019 $ 8,424 2020 $ 4,925 2021 $ 4,604 2022 $ 2,561 Thereafter $ 2,348 See Note 3. Acquisition for more information about the acquisition of Talen's gas marketing business. Long-lived Assets The Company reviews the recoverability of long-lived assets and finite-lived intangible assets whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. If there are changes indicating that the carrying value of such assets may not be recoverable, an undiscounted cash flows test is performed. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, an impairment loss is recognized by reducing the recorded value of the asset to its fair value.
Investments in Equity Investees	Investments in Equity Investees The Company accounts for its investments in Steckman Ridge, PennEast and Iroquois (through September 29, 2015), using the equity method of accounting, where its respective ownership interests are 50 percent or less and/or it has significant influence over operating and management decisions, but is not the primary beneficiary, as defined under ASC 810, Consolidation . The Company’s share of earnings is recognized as equity in earnings of affiliates on the Consolidated Statements of Operations.
Available for Sale Securities	Available for Sale Securities The Company had investments in two publicly traded energy companies that have a fair value of $65.8 million and $55.8 million as of September 30, 2017 and 2016 , respectively, which are included in available for sale securities on the Consolidated Balance Sheets. Total unrealized gains associated with these investments are included as a part of accumulated other comprehensive income, a component of common stock equity, and were $18.4 million , $11 million after tax, and $7.2 million , $4.2 million after tax, as of September 30, 2017 and 2016 , respectively. During fiscal 2017 , the Company received proceeds of approximately $6.6 million from the sale of available for sale securities and realized a pre-tax gain of approximately $5.4 million , which is included in other income, net on the Consolidated Statements of Operations. Reclassifications of realized gains out of other comprehensive income into income are determined based on average cost.
Customer Accounts Receivable and Allowance for Doubtful Accounts and Loan Receivable	Customer Accounts Receivable and Allowance for Doubtful Accounts Receivables consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers, as well as equipment sales, installations, solar leases and PPAs to commercial and residential customers. The Company evaluates its accounts receivables and, to the extent customer account balances are outstanding for more than 60 days , establishes an allowance for doubtful accounts. The allowance is based on a combination of factors including historical collection experience and trends, aging of receivables, general economic conditions in the company’s distribution or sales territories, and customer specific information. The Company writes-off customers’ accounts once it is determined they are uncollectible. The following table summarizes customer accounts receivable by company as of September 30 : (Thousands) 2017 2016 Energy Services $ 150,322 77 % $ 102,884 72 % NJNG (1) 37,432 19 30,951 22 Clean Energy Ventures 2,655 1 1,807 1 NJRHS and other 6,058 3 7,016 5 Total $ 196,467 100 % $ 142,658 100 % (1) Does not include unbilled revenues of $7.2 million and $5.7 million as of September 30, 2017 and 2016 , respectively. Loans Receivable NJNG currently provides loans, with terms ranging from three to 10 years, to customers that elect to purchase and install certain energy efficient equipment in accordance with its BPU-approved SAVEGREEN program. The loans are recognized at net present value on the Consolidated Balance Sheets. Refer to Note 6. Fair Value for a discussion of the Company’s fair value measurement policies and level disclosures. The Company has recorded $8.9 million and $7.8 million in other current assets and $40.4 million and $39.5 million in other noncurrent assets as of September 30, 2017 and 2016 , respectively, on the Consolidated Balance Sheets, related to the loans. NJNG’s policy is to establish an allowance for doubtful accounts when loan balances are in arrears for more than 60 days .
Asset Retirement Obligations	Asset Retirement Obligations The Company recognizes a liability for its AROs based on the fair value of the liability when incurred, which is generally upon acquisition, construction, development and/or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost by increasing the carrying amount of the related asset by the same amount as the liability. In periods subsequent to the initial measurement, the Company is required to recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either timing or the amount of the originally estimated cash flows to settle the conditional ARO.
Pension and Postemployment Plans	Pension and Postemployment Plans The Company has two noncontributory defined pension plans covering eligible employees, including officers. Benefits are based on each employee’s years of service and compensation. The Company’s funding policy is to contribute annually to these plans at least the minimum amount required under Employee Retirement Income Security Act, as amended, and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments. The Company made a discretionary contribution of $30 million during the first quarter of fiscal 2016 to improve the funded status of the pension plans based on the current actuarial assumptions, which included the adoption of the most recent mortality table. The Company made no discretionary contributions to the pension plans in fiscal 2017 and 2015 . The Company also provides two primarily noncontributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds.
Foreign Currency Transactions	Foreign Currency Transactions Energy Services’ market area includes Canadian delivery points and as a result, Energy Services incurs certain natural gas commodity costs and demand fees denominated in Canadian dollars. Gains or losses that occur as a result of these foreign currency transactions are reported as a component of gas purchases on the Consolidated Statements of Operations and were not material during the fiscal years ended September 30, 2017 , 2016 and 2015 .
Recent Updates to the Accounting Standards Codification	Recently Adopted Updates to the Accounting Standards Codification Stock Compensation In June 2014, the FASB issued ASU No. 2014-12, an amendment to ASC 718, Compensation - Stock Compensation , which clarifies the accounting for performance awards when the terms of the award provide that a performance target could be achieved after the requisite service period. The Company adopted the new guidance in the first quarter of fiscal 2017 and applied the new provisions on a prospective basis, which did not impact its financial position, results of operations or cash flows upon adoption. Consolidation In February 2015, the FASB issued ASU No. 2015-02, an amendment to ASC 810, Consolidation , which changes the consolidation analysis required under GAAP and reevaluates whether limited partnerships and similar entities must be consolidated. The Company adopted the new guidance in the first quarter of fiscal 2017 and applied the new provisions on a full retrospective basis, which did not impact its financial position, results of operations or cash flows upon adoption. Interest In April 2015, the FASB issued ASU No. 2015-03, an amendment to ASC 835, Interest - Imputation of Interest, which simplifies the presentation of debt issuance costs by requiring them to be presented on the balance sheet as a deduction from the carrying amount of the liability. The amendment does not affect the recognition and measurement guidance for debt issuance costs. In August 2015, the FASB issued ASU No. 2015-15, which clarified that the amendment contained within ASU No. 2015-03 does not require companies to modify their accounting for costs incurred in obtaining revolving credit facilities. The Company adopted the new guidance in the first quarter of fiscal 2017 and applied the new provisions on a full retrospective basis. In addition, the following amounts on the Consolidated Balance Sheets have been adjusted, retrospectively, as of September 30, 2016. (Thousands) As Previously Reported Effect of Change As Adjusted Assets Other noncurrent assets $ 68,708 $ (8,512 ) $ 60,196 Total noncurrent assets $ 712,166 $ (8,512 ) $ 703,654 Total assets $ 3,727,082 $ (8,512 ) $ 3,718,570 Capitalization and Liabilities Long-term debt $ 1,063,550 $ (8,512 ) $ 1,055,038 Total capitalization $ 2,230,141 $ (8,512 ) $ 2,221,629 Total capitalization and liabilities $ 3,727,082 $ (8,512 ) $ 3,718,570 Intangibles In April 2015, the FASB issued ASU No. 2015-05, an amendment to ASC 350, Intangibles - Goodwill and Other - Internal-Use Software, which clarifies the accounting for fees in a cloud computing arrangement. The amendment provides guidance on how an entity should evaluate the accounting for fees paid in a cloud computing arrangement to determine whether an arrangement includes the sale or license of software. The Company adopted the new guidance in the first quarter of fiscal 2017 and applied the new provisions on a prospective basis, which did not impact its financial position, results of operations or cash flows upon adoption. Other Recent Updates to the Accounting Standards Codification Revenue In May 2014, the FASB issued ASU No. 2014-09, and added Topic 606, Revenue from Contracts with Customers , to the ASC. ASC 606 supersedes ASC 605, Revenue Recognition , as well as most industry-specific guidance, and prescribes a single, comprehensive revenue recognition model designed to improve financial reporting comparability across entities, industries, jurisdictions and capital markets. In August 2015, the FASB issued ASU No. 2015-14, which defers the implementation of the new guidance for one year. The new guidance will not be early adopted and will be effective for the Company’s fiscal year ending September 30, 2019, and interim periods within that year. The Company continues to evaluate the provisions of ASC 606; however, based on the review of customer contracts to date, it is not anticipating a material impact to its financial position, results of operations or cash flows upon adoption. The Company anticipates significant new disclosures as a result of the new standard and expects to transition to the new guidance using the modified retrospective approach. The Company is also monitoring industry specific developments that may have an impact on its financial position, results of operation and cash flows. Inventory In July 2015, the FASB issued ASU No. 2015-11, an amendment to ASC 330, Inventory , which requires entities to measure most inventory “at the lower of cost or net realizable value,” thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. The guidance is effective for the Company’s fiscal year ending September 30, 2018, and interim periods within that year. Upon adoption, the amendment will be applied on a prospective basis. The Company does not expect any impact on its financial position, results of operations and cash flows upon adoption. Financial Instruments In January 2016, the FASB issued ASU No. 2016-01, an amendment to ASC 825, Financial Instruments , to address certain aspects of the recognition, measurement, presentation and disclosure of financial instruments. The standard affects investments in equity securities that do not result in consolidation and are not accounted for under the equity method and the presentation of certain fair value changes for financial liabilities measured at fair value. It also simplifies the impairment assessment of equity investments without a readily determinable fair value by requiring a qualitative assessment. The guidance is effective for the Company’s fiscal year ending September 30, 2019, and interim periods within that year. Upon adoption, the amendment will be applied on a modified retrospective basis. The Company evaluated the amendment and noted that, upon adoption, subsequent changes to the fair value of the Company’s available for sale securities will be recorded in the Consolidated Statement of Operations as opposed to other comprehensive income. The Company does not expect any other material impacts to its financial position, results of operations or cash flows upon adoption. In June 2016, the FASB issued ASU No. 2016-13, an amendment to ASC 326, Financial Instruments - Credit Losses, which changes the impairment model for certain financial assets that have a contractual right to receive cash, including trade and loan receivables. The new model requires recognition based upon an estimation of expected credit losses rather than recognition of losses when it is probable that they have been incurred. The guidance is effective for the Company’s fiscal year ending September 30, 2021, and interim periods within that year, with early adoption permitted. The Company is currently evaluating the amendment to understand the impact on its financial position, results of operations and cash flows upon adoption and will apply the new guidance to its trade and loan receivables on a modified retrospective basis. Leases In February 2016, the FASB issued ASU No. 2016-02, an amendment to ASC 842, Leases , which provides for a comprehensive overhaul of the lease accounting model and changes the definition of a lease within the accounting literature. Under the new standard, all leases with a term greater than one year will be recorded on the balance sheet. Amortization of the related asset will be accounted for using one of two approaches prescribed by the guidance. Additional disclosures will be required to allow the user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach is required for leases existing at the time of adoption. The guidance is effective for the Company’s fiscal year ending September 30, 2020, and interim periods within that year, with early adoption permitted. The Company continues to evaluate the provisions of ASC 842 and is actively monitoring industry specific developments including the exposure draft issued by the FASB that would introduce a land easement practical expedient to ASC 842. At this time the Company does not plan to early adopt the new guidance and expects to elect the practical expedient package in the new guidance during transition. Statement of Cash Flows In August 2016, the FASB issued ASU No. 2016-15, an amendment to ASC 230, Statement of Cash Flows , which addresses eight specific cash flow issues for which there has been diversity in practice. The guidance is effective for the Company’s fiscal year ending September 30, 2019, and interim periods within that year with early adoption permitted. Upon adoption, the amendment will be applied on a retrospective basis. The Company does not expect any material impacts to its cash flows upon adoption. In November 2016, the FASB issued ASU No. 2016-18, an amendment to ASC 230, Statement of Cash Flows , which requires that any amounts that are deemed to be restricted cash or restricted cash-equivalents be included in cash and cash-equivalent balances on the cash flow statement and, therefore, transfers between cash and restricted cash accounts will no longer be recognized within the statement of cash flows. The guidance is effective for the Company’s fiscal year ending September 30, 2019, with early adoption permitted. Upon adoption, the amendment will be applied on a retrospective basis. Based on the Company's historical restricted cash balances, it does not expect any material impacts to its financial position, results of operations or cash flows upon adoption. Business Combinations In January 2017, the FASB issued ASU No. 2017-01, an amendment to ASC 805, Business Combinations , clarifying the definition of a business in the ASC, which is intended to reduce the complexity surrounding the assessment of a transaction as an asset acquisition or business combination. The amendment provides an initial fair value screen to reduce the number of transactions that would fit the definition of a business, and when the screen threshold is not met, provides an updated model that further clarifies the characteristics of a business. The guidance is effective for the Company’s fiscal year ending September 30, 2019, and interim periods within that year, with early adoption permitted. Upon adoption, the amendment will be applied on a prospective basis. The amendment could potentially have material impacts on future transactions that the Company may enter into by altering the Company’s conclusion on what accounting to apply to acquisitions. Gains and Losses from the Derecognition of Nonfinancial Assets In February 2017, the FASB issued ASU No. 2017-05, an amendment to ASC 610-20, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets , which clarifies the scope and accounting related to the derecognition of nonfinancial assets, including partial sales and contributions of nonfinancial assets to a joint venture or other non-controlled investee. The guidance is effective concurrently with ASC 606, which is effective for the Company’s fiscal year ending September 30, 2019, and interim periods within that year with early adoption permitted. ASU No. 2017-05 may be applied retrospectively for all periods presented or retrospectively with a cumulative-effect adjustment at the date of adoption. The Company has determined that to the extent a deferred gain exists related to nonfinancial assets on the balance sheet upon adoption, it would be recognized under the new accounting guidance as a cumulative effect adjustment to the opening balance of retained earnings for the earliest period presented. Compensation - Retirement Benefits In March 2017, the FASB issued ASU No. 2017-07, an amendment to ASC 715, Compensation - Retirement Benefits , which changes the presentation of net periodic benefit cost on the income statement by requiring companies to present all components of net periodic benefit cost, other than service cost, outside a subtotal of income from operations. The amendment also states that only the service cost component of net periodic benefits costs is eligible for capitalization, when applicable. The guidance is effective for the Company’s fiscal year ending September 30, 2019, and interim periods within that year, with early adoption permitted. Upon adoption, the amendment will be applied on a retrospective basis for presentation and changes to capitalization of costs will be applied on a prospective basis. The Company is continuing to evaluate the amendment to fully understand the impact on its financial position, results of operations and cash flows upon adoption. The Company is also monitoring industry specific developments on the new guidance to determine the appropriate treatment of these changes in a rate regulated environment. Stock Compensation In May 2017, the FASB issued ASU No. 2017-09, an amendment to ASC 718, Compensation - Stock Compensation , which clarifies the accounting for changes to the terms or conditions of share-based payments. The guidance is effective for the Company’s fiscal year ending September 30, 2019, and interim periods within that year, with early adoption permitted. Upon adoption, the amendments will be applied prospectively to awards modified on or after the adoption date. The Company is currently evaluating the amendments to understand the impact on its financial position, results of operations and cash flows upon adoption. Derivatives and Hedging In August 2017, the FASB issued ASU No. 2017-12, an amendment to ASC 815, Derivatives and Hedging , which is intended to make targeted improvements to the accounting for hedging activities by better aligning an entity’s risk management activities and financial reporting for hedging relationships. These amendments modify the accounting for both nonfinancial and financial risk components and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. Additionally, the amendments are intended to simplify the application of the hedge accounting guidance and provide relief to companies by easing certain hedge documentation requirements. The guidance is effective for the Company’s fiscal year ending September 30, 2020, and interim periods within that year, with early adoption permitted. Upon adoption, the transition requirements and elections will be applied to hedging relationships existing on the date of adoption. The Company does not currently apply hedge accounting to any of its risk management activities and thus does not expect the amendments to have any impact on its financial position, results of operations and cash flows upon adoption.
Fair Value Hierarchy	Fair Value Hierarchy The Company applies fair value measurement guidance to its financial assets and liabilities, as appropriate, which include financial derivatives and physical commodity contracts qualifying as derivatives, available for sale securities and other financial assets and liabilities. In addition, authoritative accounting literature prescribes the use of a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value based on the source of the data used to develop the price inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to inputs that are based on unobservable market data and includes the following: Level 1 Unadjusted quoted prices for identical assets or liabilities in active markets. The Company’s Level 1 assets and liabilities include exchange traded natural gas futures and options contracts, listed equities and money market funds. Exchange traded futures and options contracts include all energy contracts traded on the NYMEX, CME and ICE that the Company refers internally to as basis swaps, fixed swaps, futures and financial options that are cleared through a FCM. Level 2 Other significant observable inputs, such as interest rates or price data, including both commodity and basis pricing that is observed either directly or indirectly from publications or pricing services. The Company’s Level 2 assets and liabilities include over-the-counter physical forward commodity contracts and swap contracts, SREC forward sales or derivatives that are initially valued using observable quotes and are subsequently adjusted to include time value, credit risk or estimated transport pricing components for which no basis price is available. Level 2 financial derivatives consist of transactions with non-FCM counterparties (basis swaps, fixed swaps and/or options). NJNG’s treasury lock is also considered Level 2 as valuation is based on quoted market interest and swap rates as inputs to the valuation model. Inputs are verifiable and do not require significant management judgment. For some physical commodity contracts, the Company utilizes transportation tariff rates that are publicly available and that it considers to be observable inputs that are equivalent to market data received from an independent source. There are no significant judgments or adjustments applied to the transportation tariff inputs and no market perspective is required. Even if the transportation tariff input were considered to be a “model,” it would still be considered to be a Level 2 input as the data is: • widely accepted and public; • non-proprietary and sourced from an independent third party; and • observable and published. These additional adjustments are generally not considered to be significant to the ultimate recognized values. Level 3 Inputs derived from a significant amount of unobservable market data. These include the Company’s best estimate of fair value and are derived primarily through the use of internal valuation methodologies. Financial derivative portfolios of NJNG and Energy Services consist mainly of futures, options and swaps. The Company primarily uses the market approach and its policy is to use actively quoted market prices when available. The principal market for its derivative transactions is the natural gas wholesale market, therefore, the primary sources for its price inputs are CME, NYMEX and ICE. Energy Services uses Platts and Natural Gas Exchange for Canadian delivery points. However, Energy Services also engages in transactions that result in transporting natural gas to delivery points for which there is no actively quoted market price. In most instances, the transportation cost to the final delivery location is not significant to the overall valuation. If required, Energy Services’ policy is to use the best information available to determine fair value based on internal pricing models, which would include estimates extrapolated from broker quotes or other pricing services. The Company also has available for sale securities and other financial assets that include listed equities, mutual funds and money market funds for which there are active exchange quotes available. When the Company determines fair values, measurements are adjusted, as needed, for credit risk associated with its counterparties, as well as its own credit risk. The Company determines these adjustments by using historical default probabilities that correspond to the applicable S&P issuer ratings, while also taking into consideration collateral and netting arrangements that serve to mitigate risk.

SUMMARY OF SIGNIFICANT ACCOUN30

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Summary of Gas in Storage	The following table summarizes gas in storage, at average cost by company, as of September 30 : 2017 2016 ($ in thousands) Gas in Storage Bcf Gas in Storage Bcf Energy Services $ 122,884 53.9 $ 130,493 62.0 Natural Gas Distribution 79,179 21.8 75,758 21.3 Total $ 202,063 75.7 $ 206,251 83.3
Schedule of Demand Charges	The following table summarizes the demand charges, which are net of capacity releases, and are included as a component of gas purchases on the Consolidated Statements of Operations for the fiscal years ended September 30: (Millions) 2017 2016 2015 Energy Services $ 126.4 $ 141.0 $ 130.6 Natural Gas Distribution 80.2 77.8 80.5 Total $ 206.6 $ 218.8 $ 211.1
Schedule of Capitalized Amounts Associated with Debt and Equity Component of AFUDC	Corresponding amounts for the debt component is recognized in interest expense and in other income for the equity component on the Consolidated Statements of Operations and include the following for the fiscal years ended September 30: ($ in thousands) 2017 2016 2015 AFUDC: Debt $ 1,311 $ 5,009 $ 2,472 Equity 3,867 4,375 3,825 Total $ 5,178 $ 9,384 $ 6,297 Weighted average interest rate 6.90 % 5.06 % 4.63 %
Schedule of Property, Plant and Equipment	Property, plant and equipment was comprised of the following as of September 30 : (Thousands) Property Classifications Estimated Useful Lives 2017 2016 Distribution facilities 38 to 74 years $ 1,952,697 $ 1,823,672 Transmission facilities 35 to 56 years 294,586 292,433 Storage facilities 34 to 47 years 78,245 78,238 Solar property 20 to 25 years 587,345 479,948 Wind property 25 years 244,764 228,644 All other property 5 to 35 years 53,433 52,195 Total property, plant and equipment 3,211,070 2,955,130 Accumulated depreciation and amortization (601,329 ) (547,478 ) Property, plant and equipment, net $ 2,609,741 $ 2,407,652
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense	The estimated future amortization expense for the next five years as of September 30, is as follows: (Thousands) 2018 $ 18,222 2019 $ 8,424 2020 $ 4,925 2021 $ 4,604 2022 $ 2,561 Thereafter $ 2,348
Summary of Customer Accounts Receivable by Company	The following table summarizes customer accounts receivable by company as of September 30 : (Thousands) 2017 2016 Energy Services $ 150,322 77 % $ 102,884 72 % NJNG (1) 37,432 19 30,951 22 Clean Energy Ventures 2,655 1 1,807 1 NJRHS and other 6,058 3 7,016 5 Total $ 196,467 100 % $ 142,658 100 % (1) Does not include unbilled revenues of $7.2 million and $5.7 million as of September 30, 2017 and 2016 , respectively.
Changes in Components of Accumulated Other Comprehensive Income, Net	The following table presents the changes in the components of accumulated other comprehensive income, net of related tax effects, as of September 30 : (Thousands) Unrealized gain (loss) on available for sale securities Net unrealized gain (loss) on derivatives Adjustment to postemployment benefit obligation Total Balance as of September 30, 2015 $ 6,385 $ — $ (15,779 ) $ (9,394 ) Other comprehensive income, net of tax Other comprehensive (loss), before reclassifications, net of tax of $1,499, $10, $3,164, $4,673 (2,187 ) (17 ) (4,600 ) (6,804 ) Amounts reclassified from accumulated other comprehensive income, net of tax of $0, $(10), $(698), $(708) — 17 (1) 1,026 (2) 1,043 Net current-period other comprehensive (loss), net of tax of $1,499, $0, $2,466, $3,965 (2,187 ) — (3,574 ) (5,761 ) Balance at September 30, 2016 $ 4,198 $ — $ (19,353 ) $ (15,155 ) Other comprehensive income, net of tax Other comprehensive income, before reclassifications, net of tax of $(6,593), $0, $(2,619), $(9,212) 10,019 — 3,783 13,802 Amounts reclassified from accumulated other comprehensive (loss) income, net of tax of $2,192, $0, $(868), $1,324 (3,173 ) — (1) 1,270 (2) (1,903 ) Net current-period other comprehensive income, net of tax of $(4,401), $0, $(3,487), $(7,888) 6,846 — 5,053 11,899 Balance at September 30, 2017 $ 11,044 $ — $ (14,300 ) $ (3,256 ) (1) Consists of realized losses related to foreign currency derivatives, which are reclassified to gas purchases on the Consolidated Statements of Operations. (2) Included in the computation of net periodic pension cost, a component of O&M expense on the Consolidated Statements of Operations. For more details, see Note 11. Employee Benefit Plans .
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	In addition, the following amounts on the Consolidated Balance Sheets have been adjusted, retrospectively, as of September 30, 2016. (Thousands) As Previously Reported Effect of Change As Adjusted Assets Other noncurrent assets $ 68,708 $ (8,512 ) $ 60,196 Total noncurrent assets $ 712,166 $ (8,512 ) $ 703,654 Total assets $ 3,727,082 $ (8,512 ) $ 3,718,570 Capitalization and Liabilities Long-term debt $ 1,063,550 $ (8,512 ) $ 1,055,038 Total capitalization $ 2,230,141 $ (8,512 ) $ 2,221,629 Total capitalization and liabilities $ 3,727,082 $ (8,512 ) $ 3,718,570

ACQUISITION (Tables)

ACQUISITION (Tables)	12 Months Ended
	Sep. 30, 2017
Business Combinations [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table summarizes the purchase price allocation for the fair value of the assets acquired and liabilities assumed as of July 27, 2017 : (Thousands) Estimated Fair Value Total purchase price consideration transferred $ 55,661 Identifiable assets acquired Wholesale energy contracts (1) $ 41,846 Retail energy contracts (2) 13,815 Net assets acquired $ 55,661 (1) Wholesale energy contracts are presented within Intangible assets, net on the Consolidated Balance Sheets. (2) Retail energy contracts are presented within the Derivatives, at fair value line items on the Consolidated Balance Sheets.

REGULATION (Tables)

REGULATION (Tables)	12 Months Ended
	Sep. 30, 2017
Regulated Operations [Abstract]
Schedule of Regulatory Assets	Regulatory assets and liabilities included on the Consolidated Balance Sheets as of September 30, are comprised of the following: (Thousands) 2017 2016 Regulatory assets-current Conservation Incentive Program $ 17,669 $ 36,957 New Jersey Clean Energy Program 14,202 14,232 Underrecovered gas costs 9,910 — Derivatives at fair value, net 9,010 3,097 Total current regulatory assets $ 50,791 $ 54,286 Regulatory assets-noncurrent Environmental remediation costs: Expended, net of recoveries $ 28,547 $ 19,595 Liability for future expenditures 149,000 172,000 Deferred income taxes 21,795 20,273 Derivatives at fair value, net — 23,384 SAVEGREEN 16,302 25,208 Postemployment and other benefit costs 141,433 157,027 Deferred Superstorm Sandy costs 13,030 15,201 Other noncurrent regulatory assets 5,812 8,606 Total noncurrent regulatory assets $ 375,919 $ 441,294 Regulatory liability-current Derivatives at fair value, net 78 — Overrecovered gas costs — 9,469 Total current regulatory liabilities $ 78 $ 9,469 Regulatory liabilities-noncurrent Cost of removal obligation $ 7,902 $ 30,549 New Jersey Clean Energy Program 5,795 10,657 Other noncurrent regulatory liabilities 664 205 Derivatives at fair value, net 146 — Total noncurrent regulatory liabilities $ 14,507 $ 41,411
Schedule of Regulatory Liabilities	Regulatory assets and liabilities included on the Consolidated Balance Sheets as of September 30, are comprised of the following: (Thousands) 2017 2016 Regulatory assets-current Conservation Incentive Program $ 17,669 $ 36,957 New Jersey Clean Energy Program 14,202 14,232 Underrecovered gas costs 9,910 — Derivatives at fair value, net 9,010 3,097 Total current regulatory assets $ 50,791 $ 54,286 Regulatory assets-noncurrent Environmental remediation costs: Expended, net of recoveries $ 28,547 $ 19,595 Liability for future expenditures 149,000 172,000 Deferred income taxes 21,795 20,273 Derivatives at fair value, net — 23,384 SAVEGREEN 16,302 25,208 Postemployment and other benefit costs 141,433 157,027 Deferred Superstorm Sandy costs 13,030 15,201 Other noncurrent regulatory assets 5,812 8,606 Total noncurrent regulatory assets $ 375,919 $ 441,294 Regulatory liability-current Derivatives at fair value, net 78 — Overrecovered gas costs — 9,469 Total current regulatory liabilities $ 78 $ 9,469 Regulatory liabilities-noncurrent Cost of removal obligation $ 7,902 $ 30,549 New Jersey Clean Energy Program 5,795 10,657 Other noncurrent regulatory liabilities 664 205 Derivatives at fair value, net 146 — Total noncurrent regulatory liabilities $ 14,507 $ 41,411

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair Value of Derivative Assets and Liabilities	The following table reflects the fair value of the Company’s derivative assets and liabilities recognized on the Consolidated Balance Sheets as of September 30 : Fair Value 2017 2016 (Thousands) Balance Sheet Location Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives Derivatives not designated as hedging instruments: NJNG: Physical commodity contracts Derivatives - current $ 151 $ 72 $ 235 $ 1,154 Financial commodity contracts Derivatives - current — 1,149 805 2,979 Derivatives - noncurrent — — 75 386 Interest rate contracts Derivatives - current — 8,467 — — Interest rate contracts Derivatives - noncurrent — — — 23,073 Energy Services: Physical commodity contracts Derivatives - current 14,588 16,589 5,994 11,660 Derivatives - noncurrent 7,127 8,710 3,987 1,212 Financial commodity contracts Derivatives - current 15,302 20,267 22,929 45,255 Derivatives - noncurrent 2,033 2,620 1,165 581 Foreign currency contracts Derivatives - current 40 — 1 32 Derivatives - noncurrent 4 — — — Total fair value of derivatives $ 39,245 $ 57,874 $ 35,191 $ 86,332
Offsetting Assets	The following table summarizes the reported gross amounts, the amounts that the Company has the right to offset but elects not to, financial collateral, as well as the net amounts the Company could present on the Consolidated Balance Sheets but elects not to. (Thousands) Amounts Presented in Balance Sheets (1) Offsetting Derivative Instruments (2) Financial Collateral Received/Pledged (3) Net Amounts (4) As of September 30, 2017: Derivative assets: Energy Services Physical commodity contracts $ 21,715 $ (2,173 ) $ (200 ) $ 19,342 Financial commodity contracts 17,335 (14,121 ) — 3,214 Foreign currency contracts 44 — — 44 Total Energy Services $ 39,094 $ (16,294 ) $ (200 ) $ 22,600 NJNG Physical commodity contracts $ 151 $ (20 ) $ — $ 131 Financial commodity contracts — — — — Interest rate contracts — — — — Total NJNG $ 151 $ (20 ) $ — $ 131 Derivative liabilities: Energy Services Physical commodity contracts $ 25,299 $ (2,173 ) $ — $ 23,126 Financial commodity contracts 22,887 (14,121 ) (8,766 ) — Foreign currency contracts — — — — Total Energy Services $ 48,186 $ (16,294 ) $ (8,766 ) $ 23,126 NJNG Physical commodity contracts $ 72 $ (20 ) $ — $ 52 Financial commodity contracts 1,149 — (1,149 ) — Interest rate contracts 8,467 — — 8,467 Total NJNG $ 9,688 $ (20 ) $ (1,149 ) $ 8,519 As of September 30, 2016: Derivative assets: Energy Services Physical commodity contracts $ 9,981 $ (2,837 ) $ (755 ) $ 6,389 Financial commodity contracts 24,094 (17,945 ) (6,149 ) — Foreign currency contracts 1 (1 ) — — Total Energy Services $ 34,076 $ (20,783 ) $ (6,904 ) $ 6,389 NJNG Physical commodity contracts $ 235 $ (31 ) $ — $ 204 Financial commodity contracts 880 (880 ) — — Interest rate contracts — — — — Total NJNG $ 1,115 $ (911 ) $ — $ 204 Derivative liabilities: Energy Services Physical commodity contracts $ 12,872 $ (2,837 ) $ 1,200 $ 11,235 Financial commodity contracts 45,836 (17,945 ) (27,891 ) — Foreign currency contracts 32 (1 ) — 31 Total Energy Services $ 58,740 $ (20,783 ) $ (26,691 ) $ 11,266 NJNG Physical commodity contracts $ 1,154 $ (31 ) $ — $ 1,123 Financial commodity contracts 3,365 (880 ) (2,485 ) — Interest rate contracts 23,073 — — 23,073 Total NJNG $ 27,592 $ (911 ) $ (2,485 ) $ 24,196 (1) Derivative assets and liabilities are presented on a gross basis in the balance sheet as the Company does not elect balance sheet offsetting under ASC 210-20. (2) Offsetting derivative instruments include transactions with NAESB netting election, transactions held by FCMs with net margining and transactions with ISDA netting. (3) Financial collateral includes cash balances at FCMs, as well as cash received from or pledged to other counterparties. (4) Net amounts represent presentation of derivative assets and liabilities if the Company were to elect balance sheet offsetting under ASC 210-20.
Offsetting Liabilities	The following table summarizes the reported gross amounts, the amounts that the Company has the right to offset but elects not to, financial collateral, as well as the net amounts the Company could present on the Consolidated Balance Sheets but elects not to. (Thousands) Amounts Presented in Balance Sheets (1) Offsetting Derivative Instruments (2) Financial Collateral Received/Pledged (3) Net Amounts (4) As of September 30, 2017: Derivative assets: Energy Services Physical commodity contracts $ 21,715 $ (2,173 ) $ (200 ) $ 19,342 Financial commodity contracts 17,335 (14,121 ) — 3,214 Foreign currency contracts 44 — — 44 Total Energy Services $ 39,094 $ (16,294 ) $ (200 ) $ 22,600 NJNG Physical commodity contracts $ 151 $ (20 ) $ — $ 131 Financial commodity contracts — — — — Interest rate contracts — — — — Total NJNG $ 151 $ (20 ) $ — $ 131 Derivative liabilities: Energy Services Physical commodity contracts $ 25,299 $ (2,173 ) $ — $ 23,126 Financial commodity contracts 22,887 (14,121 ) (8,766 ) — Foreign currency contracts — — — — Total Energy Services $ 48,186 $ (16,294 ) $ (8,766 ) $ 23,126 NJNG Physical commodity contracts $ 72 $ (20 ) $ — $ 52 Financial commodity contracts 1,149 — (1,149 ) — Interest rate contracts 8,467 — — 8,467 Total NJNG $ 9,688 $ (20 ) $ (1,149 ) $ 8,519 As of September 30, 2016: Derivative assets: Energy Services Physical commodity contracts $ 9,981 $ (2,837 ) $ (755 ) $ 6,389 Financial commodity contracts 24,094 (17,945 ) (6,149 ) — Foreign currency contracts 1 (1 ) — — Total Energy Services $ 34,076 $ (20,783 ) $ (6,904 ) $ 6,389 NJNG Physical commodity contracts $ 235 $ (31 ) $ — $ 204 Financial commodity contracts 880 (880 ) — — Interest rate contracts — — — — Total NJNG $ 1,115 $ (911 ) $ — $ 204 Derivative liabilities: Energy Services Physical commodity contracts $ 12,872 $ (2,837 ) $ 1,200 $ 11,235 Financial commodity contracts 45,836 (17,945 ) (27,891 ) — Foreign currency contracts 32 (1 ) — 31 Total Energy Services $ 58,740 $ (20,783 ) $ (26,691 ) $ 11,266 NJNG Physical commodity contracts $ 1,154 $ (31 ) $ — $ 1,123 Financial commodity contracts 3,365 (880 ) (2,485 ) — Interest rate contracts 23,073 — — 23,073 Total NJNG $ 27,592 $ (911 ) $ (2,485 ) $ 24,196 (1) Derivative assets and liabilities are presented on a gross basis in the balance sheet as the Company does not elect balance sheet offsetting under ASC 210-20. (2) Offsetting derivative instruments include transactions with NAESB netting election, transactions held by FCMs with net margining and transactions with ISDA netting. (3) Financial collateral includes cash balances at FCMs, as well as cash received from or pledged to other counterparties. (4) Net amounts represent presentation of derivative assets and liabilities if the Company were to elect balance sheet offsetting under ASC 210-20.
Effect of Derivative Instruments on the Consolidated Statements of Operations	The following table reflects the (losses) gains associated with NJNG’s derivative instruments as of September 30 : (Thousands) 2017 2016 2015 NJNG: Physical commodity contracts $ (12,303 ) $ (15,756 ) $ — Financial commodity contracts 5,595 (7,984 ) (33,428 ) Interest rate contracts 14,606 (18,845 ) (4,228 ) Total unrealized and realized (losses) gains $ 7,898 $ (42,585 ) $ (37,656 ) The following table reflects the effect of derivative instruments on the Consolidated Statements of Operations as of September 30 : (Thousands) Location of gain (loss) recognized in income on derivatives Amount of gain (loss) recognized in income on derivatives Derivatives not designated as hedging instruments: 2017 2016 2015 Energy Services: Physical commodity contracts Operating revenues $ 8,912 $ 33,034 $ 32,568 Physical commodity contracts Gas purchases (27,461 ) (45,637 ) (34,438 ) Financial commodity contracts Gas purchases 26,563 45,579 109,082 Foreign currency contracts Gas purchases 41 (34 ) — Total unrealized and realized gains (losses) $ 8,055 $ 32,942 $ 107,212
Effect of Derivative Instruments Designated as Cash Flow Hedges on OCI	The following table reflects the effect of derivative instruments designated as cash flow hedges on OCI as of September 30 : (Thousands) Amount of Gain or (Loss) Recognized in OCI on Derivatives (Effective Portion) Amount of Gain or (Loss) Reclassified from OCI into Income (Effective Portion) Amount of Gain or (Loss) Recognized on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) Derivatives in cash flow hedging relationships: 2017 2016 2017 2016 2017 2016 Foreign currency contracts $ — $ (27 ) $ — $ 27 $ — $ —
Schedule of Outstanding Long (Short) Derivatives	NJNG and Energy Services had the following outstanding long (short) derivatives as of September 30 : Volume (Bcf) 2017 2016 NJNG Futures 18.2 23.6 Physical 32.1 9.2 Energy Services Futures (16.4 ) (79.1 ) Financial Options — 1.2 Physical (13.1 ) 94.6
Schedule of Due to (from) Broker-Dealers and Clearing Organizations	The balances as of September 30 , by company, are as follows: (Thousands) Balance Sheet Location 2017 2016 NJNG Broker margin - Current assets $ 2,661 $ 4,822 Energy Services Broker margin - Current assets $ 23,166 $ 42,822
Schedules of Concentration of Risk, by Risk Factor	The following is a summary of gross credit exposures grouped by investment and noninvestment grade counterparties, as of September 30, 2017 .The amounts presented below have not been reduced by any collateral received or netting and exclude accounts receivable for NJNG retail natural gas sales and services and Clean Energy Ventures residential solar installations. (Thousands) Gross Credit Exposure Investment grade $ 136,804 Noninvestment grade 16,889 Internally-rated investment grade 16,378 Internally-rated noninvestment grade 68,498 Total $ 238,569

FAIR VALUE (Tables)

FAIR VALUE (Tables)	12 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Estimated Fair Value of Long-term Debt	As of September 30, the estimated fair value of long-term debt at NJNG and NJR, including current maturities, excluding capital leases, debt issuance costs and solar asset financing obligations, is as follows: (Thousands) 2017 2016 NJNG Carrying value (1) (2) $ 672,045 $ 707,845 Fair market value $ 673,051 $ 731,615 NJR Carrying value (3) $ 425,000 $ 375,000 Fair market value $ 434,625 $ 399,462 (1) Excludes capital leases of $39.7 million and $42.2 million as of September 30, 2017 and 2016 , respectively. (2) Excludes debt issuance costs of $6.3 million and $7.7 million as of September 30, 2017 and 2016 , respectively. (3) Excludes debt issuance costs of $770,000 and $853,000 as of September 30, 2017 and 2016 , respectively.
Assets and Liabilities Measured at Fair Value on Recurring Basis	Assets and liabilities measured at fair value on a recurring basis are summarized as follows: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs (Thousands) (Level 1) (Level 2) (Level 3) Total As of September 30, 2017: Assets Physical commodity contracts $ — $ 21,866 $ — $ 21,866 Financial commodity contracts 17,335 — — 17,335 Financial commodity contracts - foreign exchange — 44 — 44 Available for sale equity securities 65,752 — — 65,752 Money market funds 112 — — 112 Other 1,090 — — 1,090 Total assets at fair value $ 84,289 $ 21,910 $ — $ 106,199 Liabilities Physical commodity contracts $ — $ 25,371 $ — $ 25,371 Financial commodity contracts 24,036 — — 24,036 Financial commodity contracts - foreign exchange — — — — Interest rate contracts — 8,467 — 8,467 Total liabilities at fair value $ 24,036 $ 33,838 $ — $ 57,874 As of September 30, 2016: Assets Physical commodity contracts $ — $ 10,216 $ — $ 10,216 Financial commodity contracts 24,974 — — 24,974 Financial commodity contracts - foreign exchange — 1 — 1 Available for sale equity securities 55,789 — — 55,789 Money market funds 34,072 — — 34,072 Other 1,444 — — 1,444 Total assets at fair value $ 116,279 $ 10,217 $ — $ 126,496 Liabilities Physical commodity contracts $ — $ 14,026 $ — $ 14,026 Financial commodity contracts 49,201 — — 49,201 Financial commodity contracts - foreign exchange — 32 — 32 Interest rate contracts — 23,073 — 23,073 Total liabilities at fair value $ 49,201 $ 37,131 $ — $ 86,332
Schedule of Fair Value, Assets and Liabilities Measured on Nonrecurring Basis	Assets measured at fair value on a non-recurring basis are summarized as follows: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs (Thousands) (Level 1) (Level 2) (Level 3) Total As of September 30, 2017: Assets Acquired wholesale energy contracts (1) $ — $ 41,084 $ — $ 41,084 Total assets at fair value $ — $ 41,084 $ — $ 41,084 (1) Included in intangible asset on the Consolidated Balance Sheets, see Note 3. Acquisition for more information regarding the acquired contracts.

INVESTMENTS IN EQUITY INVESTE35

INVESTMENTS IN EQUITY INVESTEES (Tables)	12 Months Ended
	Sep. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	As of September 30 , the Company’s investments in equity method investees includes the following: (Thousands) 2017 2016 Steckman Ridge (1) $ 120,262 $ 123,155 PennEast 52,323 17,993 Total $ 172,585 $ 141,148 (1) Includes loans with a total outstanding principal balance of $70.4 million for both fiscal 2017 and 2016 , which accrue interest at a variable rate that resets quarterly and are due October 1, 2023 .

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
Schedule of Basic and Diluted Earnings Per Share	The following table presents the calculation of the Company’s basic and diluted earnings per share for the fiscal years ended September 30 : (Thousands, except per share amounts) 2017 2016 2015 Net income, as reported $ 132,065 $ 131,672 $ 180,960 Basic earnings per share Weighted average shares of common stock outstanding-basic 86,321 85,884 85,186 Basic earnings per common share $1.53 $1.53 $2.12 Diluted earnings per share Weighted average shares of common stock outstanding-basic 86,321 85,884 85,186 Incremental shares (1) 823 847 1,079 Weighted average shares of common stock outstanding-diluted 87,144 86,731 86,265 Diluted earnings per common share (2) $1.52 $1.52 $2.10 (1) Incremental shares consist primarily of unvested stock awards and performance units. (2) There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2017 , 2016 and 2015 .

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Schedule of Long-term Debt	The following table presents the long-term debt of the Company as of September 30 : (Thousands) 2017 2016 NJNG First mortgage bonds: Maturity date: 4.50% Series II August 1, 2023 $ — $ 10,300 4.60% Series JJ August 1, 2024 — 10,500 4.90% Series KK October 1, 2040 — 15,000 5.60% Series LL May 15, 2018 125,000 125,000 Variable Series MM September 1, 2027 9,545 9,545 Variable Series NN August 1, 2035 41,000 41,000 Variable Series OO August 1, 2041 46,500 46,500 3.15% Series PP April 15, 2028 50,000 50,000 3.58% Series QQ March 13, 2024 70,000 70,000 4.61% Series RR March 13, 2044 55,000 55,000 2.82% Series SS April 15, 2025 50,000 50,000 3.66% Series TT April 15, 2045 100,000 100,000 3.63% Series UU June 21, 2046 125,000 125,000 Capital lease obligation-buildings June 1, 2021 11,617 14,262 Capital lease obligation-meters Various dates 28,042 27,895 Less: Debt issuance costs (6,262 ) (7,659 ) Less: Current maturities of long-term debt (135,800 ) (11,452 ) Total NJNG long-term debt 569,642 730,891 NJR 6.05% Unsecured senior notes September 24, 2017 — 50,000 2.51% Unsecured senior notes September 15, 2018 25,000 25,000 3.25% Unsecured senior notes September 17, 2022 50,000 50,000 3.48% Unsecured senior notes November 7, 2024 100,000 100,000 3.20% Unsecured senior notes August 18, 2023 50,000 50,000 3.54% Unsecured senior notes August 18, 2026 100,000 100,000 Variable Term loan August 16, 2019 100,000 — Less: Debt issuance costs (770 ) (853 ) Less: Current maturities of long-term debt (25,000 ) (50,000 ) Total NJR long-term debt 399,230 324,147 Clean Energy Ventures Solar asset financing obligation Various dates 32,790 — Less: Current maturities of long-term debt (4,582 ) — Total Clean Energy Ventures long-term debt 28,208 — Total long-term debt $ 997,080 $ 1,055,038
Schedule of Long-term Debt Redemption Requirements	Annual long-term debt redemption requirements, excluding capital leases, debt issuance costs and solar asset financing obligations, as of September 30 , are as follows: (Thousands) NJNG NJR 2018 $ 125,000 $ 25,000 2019 $ — $ 100,000 2020 $ — $ — 2021 $ — $ — 2022 $ — $ 50,000 Thereafter $ 547,045 $ 250,000
Schedule of Contractual Commitments for Capital Lease Payments	Contractual commitments for capital lease payments, as of the fiscal years ended September 30, are as follows: (Thousands) Lease Payments 2018 $ 12,436 2019 9,675 2020 8,849 2021 5,862 2022 2,518 Thereafter 4,914 Subtotal 44,200 Less: Interest component (4,494 ) Total $ 39,700
Summary of Short-Term Bank Facilities	A summary of NJR’s and NJNG’s short-term bank facilities as of September 30, are as follows: (Thousands) 2017 2016 NJR Bank revolving credit facilities: (1) $ 425,000 $ 425,000 Notes outstanding at end of period $ 255,000 $ 121,700 Weighted average interest rate at end of period 2.14 % 1.43 % Amount available at end of period (2) $ 156,601 $ 288,910 NJNG Bank revolving credit facilities: (3) $ 250,000 $ 250,000 Commercial paper outstanding at end of period $ 11,000 $ — Weighted average interest rate at end of period 1.13 % — % Amount available at end of period (4) $ 238,269 $ 249,269 (1) Committed credit facilities, which require commitment fees of .075 percent on the unused amounts. (2) Letters of credit outstanding total $13.4 million and $14.4 million as of September 30, 2017 and 2016 , respectively, which reduces amount available by the same amount. (3) Committed credit facilities, which require commitment fees of .075 percent on the unused amounts. (4) Letters of credit outstanding total $731,000 as of September 30, 2017 and 2016 , which reduces amount available by the same amount.

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Stock-based Compensation Expense Recognized	The following table summarizes all stock-based compensation expense recognized during the following fiscal years: (Thousands) 2017 2016 2015 Stock-based compensation expense: Performance share awards $ 2,614 $ 3,188 $ 2,473 Restricted and non-restricted stock 1,732 2,161 1,899 Deferred retention stock 1,461 1,885 5,273 Compensation expense included in operation and maintenance expense 5,807 7,234 9,645 Income tax benefit (1) (2,372 ) (2,955 ) (3,940 ) Total, net of tax $ 3,435 $ 4,279 $ 5,705 (1) Excludes additional tax benefit related to delivered shares of $1.3 million , $1.8 million and $881,000 as of September 30, 2017 , 2016 and 2015 , respectively.
Summary of Performance Share Activity	The following table summarizes the performance share activity under the stock award and incentive plans for the past three fiscal years: Shares (1) Weighted Average Grant Date Fair Value Total Fair Value of Vested Shares (in Thousands) Non-vested and outstanding at September 30, 2014 247,536 $18.30 — Granted 102,790 $28.25 — Vested (2) (112,446 ) $17.10 $ 4,318 Cancelled/forfeited (3) (23,416 ) $17.98 — Non-vested and outstanding at September 30, 2015 214,464 $23.40 — Granted 115,480 $27.37 — Vested (4) (137,053 ) $21.40 $ 5,657 Cancelled/forfeited (5) (12,975 ) $23.40 — Non-vested and outstanding at September 30, 2016 179,916 $27.47 — Granted 96,507 $33.57 — Vested (6) (95,407 ) $28.88 $ 4,179 Cancelled/forfeited (24,429 ) $29.14 — Non-vested and outstanding at September 30, 2017 156,587 $30.12 — (1) The number of common shares issued related to certain performance shares may range from zero to 150 percent of the number of shares shown in the table above based on the Company’s achievement of performance goals . (2) As certified by the Company’s Leadership and Compensation Committee on November 10, 2015, the number of common shares related to performance shares earned was 120 percent , or 112,918 shares, excluding accumulated dividends. The number represented on this line is the target number of 100 percent . See footnote (1) above. Also included in the vested number are 9,364 shares certified by the Leadership and Compensation Committee on November 11, 2014 and 8,984 shares certified by the Leadership and Compensation Committee on November 10, 2015. (3) As certified by the Company’s Leadership and Compensation Committee on November 10, 2015, 9,364 shares were canceled due to not achieving a certain performance target. The remainder were forfeitures due to individuals departing the company. (4) As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, the number of common shares earned related to TSR performance was 85 percent or 55,702 shares, the number of common shares earned related to NFE performance was 150 percent or 71,808 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 23,649 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent . (5) As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, 9,366 shares were canceled due to not achieving a certain performance target. The remainder were forfeitures due to individuals departing the company. (6) As certified by the Company’s Leadership and Compensation Committee on November 14, 2017, the number of common shares earned related to TSR performance was 108.44 percent or 39,595 shares, the number of common shares earned related to NFE performance was 119 percent or 36,498 shares and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 28,223 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent .
Summary of Restricted Stock Activity	The following table summarizes the restricted stock activity under the stock award and incentive plans for the past three fiscal years: Shares Weighted Average Grant Date Fair Value Total Fair Value of Vested Shares (in Thousands) Non-vested and outstanding at September 30, 2014 41,491 $22.60 — Granted 61,972 $29.41 — Vested (18,170 ) $24.45 $ 510 Cancelled/forfeited (3,801 ) $26.79 — Non-vested and outstanding at September 30, 2015 81,492 $27.17 — Granted 41,909 $30.03 — Vested (48,089 ) $26.66 $ 1,469 Cancelled/forfeited (2,241 ) $29.21 — Non-vested and outstanding at September 30, 2016 73,071 $29.09 — Granted 28,734 $35.79 Vested (38,752 ) $28.92 $ 1,344 Cancelled/forfeited (11,899 ) $31.56 Non-vested and outstanding at September 30, 2017 51,154 $32.40 —
Summary of Deferred Retention Stock Award	The following table summarizes the deferred retention stock award under the stock award and incentive plans for the past three fiscal years: Shares Weighted Average Grant Date Fair Value Total Fair Value of Vested Shares (in Thousands) Outstanding at September 30, 2014 276,782 $21.95 — Granted/Vested 462,790 $29.32 — Delivered (95,098 ) $23.62 $ 2,519 Forfeited (11,744 ) $24.69 — Outstanding at September 30, 2015 632,730 $27.03 — Granted/Vested 159,831 $30.37 — Delivered (121,764 ) $20.31 $ 3,751 Forfeited (8,318 ) $28.14 — Outstanding at September 30, 2016 662,479 $29.06 — Granted/Vested 63,977 $35.64 — Delivered (53,878 ) $23.11 $ 1,774 Outstanding at September 30, 2017 672,578 $29.54 —
Summary of Stock Option Activity	The following table summarizes the stock option activity: Shares Weighted Average Exercise Price Outstanding at September 30, 2014 48,250 $15.00 Exercised (48,250 ) $15.00 Outstanding at September 30, 2015 — $0.00
Schedule of Nonemployee Director Stock Award Plan Activity	The following summarizes non-employee director share awards for the past three fiscal years: 2017 2016 2015 Shares granted 27,972 (1) 27,481 26,122 Weighted average grant date fair value $35.59 $32.75 $30.63 (1) $280,000 of expense remains as of September 30, 2017 , to be recognized through December 31, 2017 .

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Sep. 30, 2017
Retirement Benefits [Abstract]
Summary of Changes in Funded Status of Plans and Liabilities Recognized	The following summarizes the changes in the funded status of the plans and the related liabilities recognized on the Consolidated Balance Sheets as of September 30 : Pension (1) OPEB (Thousands) 2017 2016 2017 2016 Change in Benefit Obligation Benefit obligation at beginning of year $ 293,654 $ 255,987 $ 160,393 $ 138,367 Service cost 8,347 7,591 4,380 4,521 Interest cost 9,771 11,342 5,545 6,256 Plan participants’ contributions (2) 45 47 120 104 Actuarial (gain) loss (5,995 ) 26,369 8,985 15,590 Benefits paid, net of retiree subsidies received (7,987 ) (7,682 ) (4,333 ) (4,445 ) Benefit obligation at end of year $ 297,835 $ 293,654 $ 175,090 $ 160,393 Change in plan assets Fair value of plan assets at beginning of year $ 249,875 $ 199,123 $ 62,035 $ 57,269 Actual return on plan assets 29,736 28,316 7,953 5,872 Employer contributions 74 30,071 6,049 3,235 Benefits paid, net of plan participants’ contributions (2) (7,942 ) (7,635 ) (4,503 ) (4,341 ) Fair value of plan assets at end of year $ 271,743 $ 249,875 $ 71,534 $ 62,035 Funded status $ (26,092 ) $ (43,779 ) $ (103,556 ) $ (98,358 ) Amounts recognized on Consolidated Balance Sheets Postemployment employee (liability) Current $ (158 ) $ (79 ) $ (602 ) $ (454 ) Noncurrent (25,934 ) (43,700 ) (102,954 ) (97,904 ) Total $ (26,092 ) $ (43,779 ) $ (103,556 ) $ (98,358 ) (1) Includes the Company’s PEP. (2) Prior to July 1, 1998, employees were eligible to elect an additional participant contribution to enhance their benefits and contributions made during the periods were insignificant.
Summary of Regulatory Assets and Accumulated Other Comprehensive Income	The following table summarizes the amounts recognized in regulatory assets and accumulated other comprehensive income as of September 30 : Regulatory Assets Accumulated Other Comprehensive Income (Loss) Pension OPEB Pension OPEB Balance at September 30, 2015 $ 86,960 $ 50,737 $ 25,640 $ 1,242 Amounts arising during the period: Net actuarial loss 13,696 11,274 4,475 3,289 Amounts amortized to net periodic costs: Net actuarial (loss) (5,607 ) (3,175 ) (1,676 ) (99 ) Prior service (cost) credit (108 ) 311 (3 ) 54 Balance at September 30, 2016 $ 94,941 $ 59,147 $ 28,436 $ 4,486 Amounts arising during the period: Net actuarial (gain) loss (9,429 ) 5,211 (6,990 ) 587 Amounts amortized to net periodic costs: Net actuarial (loss) (6,799 ) (4,209 ) (2,028 ) (160 ) Prior service (cost) credit (108 ) 311 (3 ) 54 Balance at September 30, 2017 $ 78,605 $ 60,460 $ 19,415 $ 4,967 The amounts in regulatory assets and accumulated other comprehensive income not yet recognized as components of net periodic benefit cost as of September 30 are: Regulatory Assets Accumulated Other Comprehensive Income (Loss) Pension OPEB Pension OPEB (Thousands) 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 77,930 $ 94,158 $ 61,563 $ 60,561 $ 19,414 $ 28,432 $ 5,113 $ 4,686 Prior service cost (credit) 675 783 (1,103 ) (1,414 ) 1 4 (146 ) (200 ) Total $ 78,605 $ 94,941 $ 60,460 $ 59,147 $ 19,415 $ 28,436 $ 4,967 $ 4,486
Schedule of Amounts Expected to be Recognized as Components of Net Periodic Benefit Cost	Amounts included in regulatory assets and accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost in fiscal 2018 are as follows: Regulatory Assets Accumulated Other Comprehensive Income (Loss) (Thousands) Pension OPEB Pension OPEB Net actuarial loss $ 6,177 $ 4,464 $ 1,360 $ 196 Prior service cost (credit) 105 (311 ) 1 (53 ) Total $ 6,282 $ 4,153 $ 1,361 $ 143
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets	The accumulated benefit obligation for the pension plans, including the PEP, exceeded the fair value of plan assets. The projected benefit and accumulated benefit obligations and the fair value of plan assets as of September 30, are as follows: Pension (Thousands) 2017 2016 Projected benefit obligation $ 297,835 $ 293,654 Accumulated benefit obligation $ 258,514 $ 252,077 Fair value of plan assets $ 271,743 $ 249,875
Components of Net Periodic Cost	The components of the net periodic cost for pension benefits, including the Company’s PEP, and OPEB costs (principally health care and life insurance) for employees and covered dependents for fiscal years ended September 30, are as follows: Pension OPEB (Thousands) 2017 2016 2015 2017 2016 2015 Service cost $ 8,347 $ 7,591 $ 7,485 $ 4,380 $ 4,521 $ 4,253 Interest cost 9,771 11,342 10,199 5,545 6,256 5,739 Expected return on plan assets (19,313 ) (20,118 ) (17,090 ) (4,767 ) (4,845 ) (4,977 ) Recognized actuarial loss 8,827 7,281 6,985 4,370 3,274 2,943 Prior service cost (credit) amortization 111 111 111 (365 ) (365 ) (364 ) Net periodic benefit cost recognized as expense $ 7,743 $ 6,207 $ 7,690 $ 9,163 $ 8,841 $ 7,594
Schedule of Weighted Average Assumptions Used	The weighted average assumptions used to determine the Company’s benefit costs during the fiscal years below and obligations as of September 30, are as follows: Pension OPEB 2017 2016 2015 2017 2016 2015 Benefit costs: Discount rate 3.96/3.94% 4.50 % 4.55 % 4.08/4.01% (1) 4.60/4.55% (1) 4.55 % Expected asset return 7.75 % 8.75 % 8.75 % 7.75 % 8.75 % 8.75 % Compensation increase 3.25/3.50% (1) 3.25/3.50% (1) 3.25 % 3.25/3.50% (1) 3.50 % 3.50 % Obligations: Discount rate 4.03 % 3.96/3.94% (1) 4.50 % 4.12/4.08% (1) 4.08/4.01% (1) 4.60/4.55% (1) Compensation increase 3.25/3.50% (1) 3.25/3.50% (1) 3.25/3.50% (1) 3.25/3.50% (1) 3.50 % 3.50 % (1) Percentages for represented and nonrepresented plans, respectively.
Information on Assumed HCCTR Used to Determine Expected OPEB Benefits	Information relating to the assumed HCCTR used to determine expected OPEB benefits as of September 30, and the effect of a one percent change in the rate, are as follows: ($ in thousands) 2017 2016 2015 HCCTR 8.3 % 8.5 % 6.7 % Ultimate HCCTR 4.5 % 4.5 % 4.8 % Year ultimate HCCTR reached 2025 2025 2022 Effect of a 1 percentage point increase in the HCCTR on: Year-end benefit obligation $ 32,019 $ 28,803 $ 26,025 Total service and interest cost $ 2,468 $ 2,331 $ 2,026 Effect of a 1 percentage point decrease in the HCCTR on: Year-end benefit obligation $ (25,466 ) $ (22,862 ) $ (20,427 ) Total service and interest costs $ (1,909 ) $ (1,801 ) $ (1,593 )
Schedule of Mix and Targeted Allocation of Plan Assets	The mix and targeted allocation of the pension and OPEB plans’ assets are as follows: 2018 Assets at Target September 30, Asset Allocation Allocation 2017 2016 U.S. equity securities 40 % 39 % 38 % International equity securities 20 21 20 Fixed income 40 40 42 Total 100 % 100 % 100 %
Schedule of Expected Benefit Payments	The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid during the following years: (Thousands) Pension OPEB 2018 $ 8,928 $ 4,230 2019 $ 9,712 $ 4,807 2020 $ 10,549 $ 5,435 2021 $ 11,502 $ 6,061 2022 $ 12,469 $ 6,755 2023 - 2027 $ 79,081 $ 43,267
Schedule of Estimated Subsidy Payments	The estimated subsidy payments are as follows: Estimated Subsidy Payment Fiscal Year (Thousands) 2018 $262 2019 $283 2020 $311 2021 $342 2022 $373 2023 - 2027 $2,574
Summary of Pension and OPEB Assets Held in the Master Trust	Pension and OPEB assets held in the master trust, measured at fair value, as of September 30, are summarized as follows: Quoted Prices in Active Markets for Identical Assets (Level 1) (Thousands) Pension OPEB Assets 2017 2016 2017 2016 Money market funds $ — $ — $ 11 $ 9 Registered Investment Companies: Equity Funds: Large Cap Index 88,321 78,306 23,986 19,532 Extended Market Index 16,329 16,250 4,409 4,114 International Stock 56,446 50,702 15,000 12,997 Fixed Income Funds: Emerging Markets 13,516 12,906 3,551 3,294 Core Fixed Income — — 8,082 7,177 Opportunistic Income — — 4,744 4,155 Ultra Short Duration — — 4,673 4,082 High Yield Bond Fund 26,540 25,976 7,078 6,675 Long Duration Fund 70,591 65,735 — — Total assets at fair value $ 271,743 $ 249,875 $ 71,534 $ 62,035

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Analysis of Change in ARO Liability	The following is an analysis of the change in the Company’s AROs for the fiscal year ended September 30 : (Thousands) 2017 2016 NJNG NJRCEV NJNG NJRCEV Balance at October 1 $ 23,521 $ 4,858 $ 16,773 $ 2,372 Accretion 1,304 245 1,048 158 Additions 729 1,492 783 2,328 Revisions in estimated cash flows (245 ) — 5,320 — Retirements (484 ) — (403 ) — Balance at period end $ 24,825 $ 6,595 $ 23,521 $ 4,858
Schedule of Future Accretion	Accretion for the next five years is estimated to be as follows: (Thousands) Fiscal Year Ended September 30, Estimated Accretion 2018 $ 1,644 2019 1,718 2020 1,795 2021 1,877 2022 1,960 Total $ 8,994

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of the U.S. federal statutory rate of 35 percent to the effective rate from operations for the fiscal years ended September 30, 2017 , 2016 and 2015 is as follows: (Thousands) 2017 2016 2015 Statutory income tax expense $ 52,643 $ 54,321 $ 84,239 Change resulting from: State income taxes 8,222 6,044 8,233 Cost of removal of assets placed in service prior to1981 (6,886 ) (5,738 ) (5,149 ) Investment/production tax credits (34,526 ) (32,491 ) (30,096 ) Basis adjustment of solar assets due to ITC 4,256 4,453 4,861 AFUDC equity (2,624 ) (1,531 ) (1,339 ) Other (2,742 ) (1,528 ) (1,025 ) Income tax provision $ 18,343 $ 23,530 $ 59,724 Effective income tax rate 12.2 % 15.2 % 24.8 %
Schedule of Components of Income Tax Provision (Benefit)	The income tax (benefit) provision from operations consists of the following: (Thousands) 2017 2016 2015 Current: Federal $ (16,023 ) $ (23,597 ) $ 20,492 State 2,470 (2,209 ) 5,473 Deferred: Federal 54,965 70,386 56,480 State 11,457 11,441 7,375 Investment/production tax credits (34,526 ) (32,491 ) (30,096 ) Income tax provision $ 18,343 $ 23,530 $ 59,724
Schedule of Deferred Tax Assets and Liabilities	The temporary differences, which give rise to deferred tax assets and (liabilities), consist of the following: (Thousands) 2017 2016 Deferred tax assets Investment tax credits (1) $ 111,642 $ 76,517 Deferred service contract revenue 3,877 3,601 Incentive compensation 6,260 8,128 Fair value of derivatives 11,519 1,179 Federal net operating losses 28,487 27,541 State net operating losses 23,597 18,113 Overrecovered gas costs — 3,831 Other 13,845 11,668 Total deferred tax assets $ 199,227 $ 150,578 Deferred tax liabilities Property related items $ (620,850 ) $ (532,027 ) Remediation costs (11,625 ) (7,928 ) Equity investments (38,370 ) (37,740 ) Postemployment benefits (6,855 ) (7,902 ) Conservation incentive plan (7,195 ) (14,953 ) Underrecovered gas costs (4,035 ) — Other (16,643 ) (14,610 ) Total deferred tax liabilities $ (705,573 ) $ (615,160 ) Total net deferred tax liabilities $ (506,346 ) $ (464,582 ) (1) Includes $2.3 million and $2.5 million for NJNG for fiscal 2017 and 2016 , respectively , which is being amortized over the life of the related assets, and $109.3 million and $74 million for Clean Energy Ventures for fiscal 2017 and 2016 , respectively , which is ITC carryforward.
Schedule of Deferred Tax Assets Expiration	The deferred tax assets will expire as follows: (Thousands) Fiscal years 2018 - 2022 $ 313 Fiscal years 2023 - 2027 1,051 Fiscal years 2028 - 2032 796 Fiscal years 2033 - 2037 159,237 Total $ 161,397

COMMITMENTS AND CONTINGENT LI42

COMMITMENTS AND CONTINGENT LIABILITIES (Tables)	12 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of Commitments for Natural Gas Purchases and Future Demans Fees for the Next Five Years	Commitments as of September 30, 2017 , for natural gas purchases and future demand fees for the next five fiscal year periods, are as follows: (Thousands) 2018 2019 2020 2021 2022 Thereafter Energy Services: Natural gas purchases $ 296,491 $ 114,817 $ 22,270 $ 11,488 $ — $ — Storage demand fees 32,870 22,638 13,350 9,041 5,833 2,746 Pipeline demand fees 55,916 32,412 23,804 21,621 19,653 19,311 Sub-total Energy Services $ 385,277 $ 169,867 $ 59,424 $ 42,150 $ 25,486 $ 22,057 NJNG: Natural gas purchases $ 51,050 $ 41,156 $ 2,514 $ — $ — $ — Storage demand fees 30,042 26,628 15,331 8,231 7,804 3,903 Pipeline demand fees 68,544 102,091 100,909 91,231 89,859 642,481 Sub-total NJNG $ 149,636 $ 169,875 $ 118,754 $ 99,462 $ 97,663 $ 646,384 Total $ 534,913 $ 339,742 $ 178,178 $ 141,612 $ 123,149 $ 668,441

BUSINESS SEGMENT AND OTHER OP43

BUSINESS SEGMENT AND OTHER OPERATIONS DATA (Tables)	12 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Schedule of Business Segments and Other Operations	Information related to the Company’s various reporting segments and other operations is detailed below: (Thousands) Fiscal Years Ended September 30, 2017 2016 2015 Operating revenues Natural Gas Distribution External customers $ 695,637 $ 594,346 $ 781,970 Clean Energy Ventures External customers 64,394 53,540 32,513 Energy Services External customers (1) 1,462,365 1,187,754 1,872,781 Intercompany 316 9,499 61,526 Subtotal 2,222,712 1,845,139 2,748,790 Home Services and Other External customers 46,221 45,265 46,723 Intercompany 3,370 3,232 1,980 Eliminations (3,686 ) (12,731 ) (63,506 ) Total $ 2,268,617 $ 1,880,905 $ 2,733,987 Depreciation and amortization Natural Gas Distribution $ 49,347 $ 47,828 $ 43,085 Clean Energy Ventures 31,834 23,971 17,297 Energy Services 63 88 90 Midstream 6 6 6 Subtotal 81,250 71,893 60,478 Home Services and Other 798 981 952 Eliminations (207 ) (126 ) (31 ) Total $ 81,841 $ 72,748 $ 61,399 Interest income (2) Natural Gas Distribution $ 555 $ 115 $ 336 Clean Energy Ventures — — 26 Energy Services 6 98 438 Midstream 2,195 1,524 977 Subtotal 2,756 1,737 1,777 Home Services and Other 590 397 217 Eliminations (1,312 ) (2,006 ) (1,414 ) Total $ 2,034 $ 128 $ 580 (1) Includes sales to Canada, which accounted for .8 , 2 and 3.7 percent of total operating revenues during fiscal 2017 , 2016 and 2015 , respectively . (2) Included in other income, net on the Consolidated Statements of Operations. (Thousands) Fiscal Years Ended September 30, 2017 2016 2015 Interest expense, net of capitalized interest Natural Gas Distribution $ 25,818 $ 19,930 $ 18,534 Clean Energy Ventures 16,263 10,304 7,635 Energy Services 2,747 1,095 1,209 Midstream 960 287 717 Subtotal 45,788 31,616 28,095 Home Services and Other 410 252 49 Eliminations (1,312 ) (824 ) (423 ) Total $ 44,886 $ 31,044 $ 27,721 Income tax (benefit) provision Natural Gas Distribution $ 43,485 $ 34,951 $ 39,544 Clean Energy Ventures (31,161 ) (26,592 ) (26,968 ) Energy Services (4,015 ) 7,030 39,043 Midstream 5,820 6,130 6,849 Subtotal 14,129 21,519 58,468 Home Services and Other 3,857 1,387 1,551 Eliminations 357 624 (295 ) Total $ 18,343 $ 23,530 $ 59,724 Equity in earnings of affiliates Midstream $ 17,797 $ 13,936 $ 17,487 Eliminations (3,984 ) (4,421 ) (4,078 ) Total $ 13,813 $ 9,515 $ 13,409 Net financial earnings Natural Gas Distribution $ 86,930 $ 76,104 $ 76,287 Clean Energy Ventures 24,873 28,393 20,101 Energy Services 18,554 21,934 42,122 Midstream 12,857 9,406 9,780 Subtotal 143,214 135,837 148,290 Home Services and Other 6,811 2,882 3,420 Eliminations (633 ) (634 ) (207 ) Total $ 149,392 $ 138,085 $ 151,503 Capital expenditures Natural Gas Distribution $ 176,249 $ 205,133 $ 168,875 Clean Energy Ventures 149,400 149,063 151,002 Subtotal 325,649 354,196 319,877 Home Services and Other 2,434 1,896 209 Total $ 328,083 $ 356,092 $ 320,086 Investments in equity investees Midstream 27,070 11,176 5,780 Total $ 27,070 $ 11,176 $ 5,780
Reconciliation of Consolidated NFE to Consolidated Net Income	A reconciliation of consolidated NFE to consolidated net income is as follows: (Thousands) 2017 2016 2015 Consolidated net financial earnings $ 149,392 $ 138,085 $ 151,503 Less: Unrealized (gain) loss on derivative instruments and related transactions (11,241 ) 46,883 (38,681 ) Tax effect 4,062 (17,018 ) 14,391 Effects of economic hedging related to natural gas inventory 38,470 (36,816 ) (8,225 ) Tax effect (13,964 ) 13,364 3,058 Consolidated net income $ 132,065 $ 131,672 $ 180,960
Schedule of Assets for Business Segments and Business Operations	The Company’s assets for the various reporting segments and business operations are detailed below: (Thousands) 2017 2016 2015 Assets at end of period: Natural Gas Distribution $ 2,519,578 $ 2,517,401 $ 2,305,293 Clean Energy Ventures 771,340 665,696 504,885 Energy Services 398,277 327,626 260,021 Midstream 232,806 186,259 182,007 Subtotal 3,922,001 3,696,982 3,252,206 Home Services and Other 114,801 109,487 88,880 Intercompany assets (1) (108,295 ) (87,899 ) (56,729 ) Total $ 3,928,507 $ 3,718,570 $ 3,284,357 (1) Consists of transactions between subsidiaries that are eliminated and reclassified in consolidation.

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Demand fees, net of eliminations, associated with Steckman Ridge during the fiscal years ended September 30 , are as follows: (Thousands) 2017 2016 2015 NJNG $ 5,590 $ 5,562 $ 5,700 Energy Services 2,750 2,789 1,957 Total $ 8,340 $ 8,351 $ 7,657 The following table summarizes demand fees payable to Steckman Ridge as of September 30 : (Thousands) 2017 2016 NJNG $ 775 $ 775 Energy Services 377 375 Total $ 1,152 $ 1,150

SELECTED QUARTERLY FINANCIAL 45

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Sep. 30, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Data	A summary of financial data for each quarter of fiscal 2017 and 2016 follows. Due to the seasonal nature of the Company’s businesses, quarterly amounts vary significantly during the fiscal year. In the opinion of management, the information furnished reflects all adjustments necessary for a fair presentation of the results of the interim periods. First Second Third Fourth (Thousands, except per share data) Quarter Quarter Quarter Quarter 2017 Operating revenues $ 541,028 $ 733,546 $ 457,523 $ 536,520 Operating income (loss) $ 41,475 $ 139,653 $ 17,967 $ (32,051 ) Net income (loss) $ 34,929 $ 114,702 $ 18,957 $ (36,523 ) Earnings (loss) per share (1) Basic $0.41 $1.33 $0.22 $(0.42) Diluted $0.40 $1.32 $0.22 $(0.42) 2016 Operating revenues $ 444,258 $ 574,193 $ 393,213 $ 469,241 Operating income (loss) $ 59,451 $ 93,933 $ (28,329 ) $ 42,480 Net income (loss) $ 50,281 $ 73,354 $ (17,363 ) $ 25,400 Earnings (loss) per share (1) Basic $0.59 $0.85 $(0.20) $0.30 Diluted $0.58 $0.84 $(0.20) $0.29 (1) The sum of quarterly amounts may not equal the annual amounts due to rounding.

NATURE OF THE BUSINESS (Details

NATURE OF THE BUSINESS (Details) shares in Thousands	12 Months Ended
	Sep. 30, 2017subsidiarycustomershares
Natural Gas Distribution
Investment [Line Items]
Total retail customers (in customers) | customer	529,800
NJR Retail Holdings Corporation
Investment [Line Items]
Number of principal subsidiaries (in subsidiaries) | subsidiary	2
Steckman Ridge
Investment [Line Items]
Ownership interest, percent	50.00%
PennEast
Investment [Line Items]
Ownership interest, percent	20.00%
Common Units
Investment [Line Items]
Ownership interest exchanged (in shares) | shares	1,840

SUMMARY OF SIGNIFICANT ACCOUN47

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - GAS IN STORAGE (Details) $ in Thousands	Sep. 30, 2017USD ($)Bcf	Sep. 30, 2016USD ($)Bcf
Public Utilities, Inventory [Line Items]
Gas in Storage | $	$ 202,063	$ 206,251
Bcf | Bcf	75.7	83.3
Energy Services
Public Utilities, Inventory [Line Items]
Gas in Storage | $	$ 122,884	$ 130,493
Bcf | Bcf	53.9	62
Natural Gas Distribution
Public Utilities, Inventory [Line Items]
Gas in Storage | $	$ 79,179	$ 75,758
Bcf | Bcf	21.8	21.3

SUMMARY OF SIGNIFICANT ACCOUN48

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - DEMAND FEES (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Demand fees	$ 206.6	$ 218.8	$ 211.1
Energy Services
Demand fees	126.4	141	130.6
Natural Gas Distribution
Demand fees	$ 80.2	$ 77.8	$ 80.5
Minimum
Storage and pipeline capacity, contract term	1 year
Maximum
Storage and pipeline capacity, contract term	10 years

SUMMARY OF SIGNIFICANT ACCOUN49

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CAPITALIZED AND DEFERRED INTEREST (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
AFUDC:
SBC interest rate	2.55%	2.05%	2.54%
Deferred interest	$ 78	$ 54	$ 61
Seven-Year Treasury Rate
AFUDC:
Debt instrument, term	7 years
Basis spread on variable rate	60.00%
Natural Gas Distribution
AFUDC:
Debt	$ 1,311	5,009	2,472
Equity	3,867	4,375	3,825
Total	$ 5,178	$ 9,384	$ 6,297
Weighted average interest rate	6.90%	5.06%	4.63%

SUMMARY OF SIGNIFICANT ACCOUN50

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - SALE-LEASEBACKS (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 30, 2017USD ($)asset	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Sale Leaseback Transaction [Line Items]
Proceeds from sale-leaseback transaction		$ 9,587	$ 7,107	$ 7,216
Proceeds from sale-leaseback transaction - solar		32,901	0	0
NJNG
Sale Leaseback Transaction [Line Items]
Proceeds from sale-leaseback transaction		$ 9,587	$ 7,100	$ 7,200
Minimum | NJNG
Sale Leaseback Transaction [Line Items]
Term of lease		7 years
Maximum | NJNG
Sale Leaseback Transaction [Line Items]
Term of lease		11 years
Clean Energy Ventures
Sale Leaseback Transaction [Line Items]
Term of lease	7 years
Proceeds from sale-leaseback transaction - solar	$ 32,901
Number of commercial solar assets sold | asset	2

SUMMARY OF SIGNIFICANT ACCOUN51

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - SALES TAX ACCOUNTING (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Accounting Policies [Abstract]
Sales tax			$ 39.4	$ 31	$ 44.1
Sales tax, percentage	7.00%	6.875%

SUMMARY OF SIGNIFICANT ACCOUN52

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CASH AND CASH EQUIVALENTS (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Accounting Policies [Abstract]
Restricted cash	$ 243	$ 1,600

SUMMARY OF SIGNIFICANT ACCOUN53

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - PROPERTY PLANT AND EQUIPMENT (Details) - USD ($) $ in Thousands	Oct. 01, 2016	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Composite rate of depreciation		2.25%	2.32%	2.31%
Depreciation and amortization		$ 81,841	$ 72,748	$ 61,399
Property Classifications
Total property, plant and equipment		3,211,070	2,955,130
Accumulated depreciation and amortization		(601,329)	(547,478)
Property, plant and equipment, net		2,609,741	2,407,652
Composite rate of depreciation	2.40%
Regulated Operation | Distribution facilities
Property Classifications
Total property, plant and equipment		$ 1,952,697	1,823,672
Regulated Operation | Distribution facilities | Minimum
Property Classifications
Estimated Useful Lives		38 years
Regulated Operation | Distribution facilities | Maximum
Property Classifications
Estimated Useful Lives		74 years
Regulated Operation | Transmission facilities
Property Classifications
Total property, plant and equipment		$ 294,586	292,433
Regulated Operation | Transmission facilities | Minimum
Property Classifications
Estimated Useful Lives		35 years
Regulated Operation | Transmission facilities | Maximum
Property Classifications
Estimated Useful Lives		56 years
Regulated Operation | Storage facilities
Property Classifications
Total property, plant and equipment		$ 78,245	78,238
Regulated Operation | Storage facilities | Minimum
Property Classifications
Estimated Useful Lives		34 years
Regulated Operation | Storage facilities | Maximum
Property Classifications
Estimated Useful Lives		47 years
Unregulated Operation | Solar property
Property Classifications
Total property, plant and equipment		$ 587,345	479,948
Unregulated Operation | Solar property | Minimum
Property Classifications
Estimated Useful Lives		20 years
Unregulated Operation | Solar property | Maximum
Property Classifications
Estimated Useful Lives		25 years
Unregulated Operation | Wind property
Property Classifications
Estimated Useful Lives		25 years
Total property, plant and equipment		$ 244,764	228,644
Unregulated Operation | All other property
Property Classifications
Total property, plant and equipment		$ 53,433	$ 52,195
Unregulated Operation | All other property | Minimum
Property Classifications
Estimated Useful Lives		5 years
Unregulated Operation | All other property | Maximum
Property Classifications
Estimated Useful Lives		35 years

SUMMARY OF SIGNIFICANT ACCOUN54

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - INTANGIBLE ASSETS (Details) $ in Thousands	Sep. 30, 2017USD ($)
Business Acquisition [Line Items]
2,018	$ 18,222
2,019	8,424
2,020	4,925
2,021	4,604
2,022	2,561
Thereafter	2,348
Talen's Wholesale Natural Gas Energy Contracts
Business Acquisition [Line Items]
Intangible assets, net of amortization	$ 41,100

SUMMARY OF SIGNIFICANT ACCOUN55

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - SALE OF ASSET (Details) $ in Millions	Mar. 08, 2017USD ($)	Sep. 30, 2017a	Sep. 30, 2017ft²
Accounting Policies [Abstract]
Area of real estate property (in sqft or acres)		5	56,400
Proceeds from sale of real estate	$ 9.4
Gain (loss) on sale of properties	$ 1.9

SUMMARY OF SIGNIFICANT ACCOUN56

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - AVAILABLE FOR SALE SECURITIES (Details) - USD ($)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Accounting Policies [Abstract]
Available for sale securities	$ 65,752,000	$ 55,789,000
Unrealized gain	18,400,000	7,200,000
Unrealized gain, after tax	11,000,000	4,200,000
Proceeds from sale of available for sale securities	6,639,000	$ 0	$ 0
Available-for-sale securities, gross realized gain (loss)	$ 5,400,000

SUMMARY OF SIGNIFICANT ACCOUN57

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - RECEIVABLE BY SUBSIDIARY (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Establishment of allowance for doubtful accounts, customer account balances, days outstanding (more than)	60 days
Billed	$ 196,467	$ 142,658
Receivable by subsidiary percentage	100.00%	100.00%
Unbilled revenues	$ 7,202	$ 5,744
Energy Services
Accounts, Notes, Loans and Financing Receivable [Line Items]
Billed	$ 150,322	$ 102,884
Receivable by subsidiary percentage	77.00%	72.00%
Natural Gas Distribution
Accounts, Notes, Loans and Financing Receivable [Line Items]
Billed	$ 37,432	$ 30,951
Receivable by subsidiary percentage	19.00%	22.00%
Clean Energy Ventures
Accounts, Notes, Loans and Financing Receivable [Line Items]
Billed	$ 2,655	$ 1,807
Receivable by subsidiary percentage	1.00%	1.00%
NJRHS and other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Billed	$ 6,058	$ 7,016
Receivable by subsidiary percentage	3.00%	5.00%

SUMMARY OF SIGNIFICANT ACCOUN58

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - LOAN RECEIVABLE (Details) - USD ($)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loans receivable in other current assets	$ 8,900,000	$ 7,800,000
Loans receivable in other noncurrent assets	$ 40,400,000	39,500,000
Establishment of allowance for doubtful accounts, customer account balances, days outstanding (more than)	60 days
Allowance for doubtful accounts	$ 0	$ 0
Minimum
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loans receivable term	3 years
Maximum
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loans receivable term	10 years

SUMMARY OF SIGNIFICANT ACCOUN59

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance	$ 1,166,591	$ 1,106,956
Other comprehensive (loss), before reclassifications, net of tax	13,802	(6,804)
Amounts reclassified from accumulated other comprehensive income, net of tax	(1,903)	1,043
Net current-period other comprehensive (loss), net of tax	11,899	(5,761)
Ending Balance	1,236,643	1,166,591
Unrealized gain (loss) on available for sale securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance	4,198	6,385
Other comprehensive (loss), before reclassifications, net of tax	10,019	(2,187)
Amounts reclassified from accumulated other comprehensive income, net of tax	(3,173)	0
Net current-period other comprehensive (loss), net of tax	6,846	(2,187)
Ending Balance	11,044	4,198
Tax on other comprehensive income before reclassifications	6,593	(1,499)
Tax on amounts reclassified from accumulated other comprehensive income	(2,192)	0
Tax on net current-period other comprehensive income (loss)	4,401	(1,499)
Net unrealized gain (loss) on derivatives
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance	0	0
Other comprehensive (loss), before reclassifications, net of tax	0	(17)
Amounts reclassified from accumulated other comprehensive income, net of tax	0	17
Net current-period other comprehensive (loss), net of tax	0	0
Ending Balance	0	0
Tax on other comprehensive income before reclassifications	0	(10)
Tax on amounts reclassified from accumulated other comprehensive income	0	10
Tax on net current-period other comprehensive income (loss)	0	0
Adjustment to postemployment benefit obligation
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance	(19,353)	(15,779)
Other comprehensive (loss), before reclassifications, net of tax	3,783	(4,600)
Amounts reclassified from accumulated other comprehensive income, net of tax	1,270	1,026
Net current-period other comprehensive (loss), net of tax	5,053	(3,574)
Ending Balance	(14,300)	(19,353)
Tax on other comprehensive income before reclassifications	2,619	(3,164)
Tax on amounts reclassified from accumulated other comprehensive income	868	698
Tax on net current-period other comprehensive income (loss)	3,487	(2,466)
Total
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance	(15,155)	(9,394)
Ending Balance	(3,256)	(15,155)
Tax on other comprehensive income before reclassifications	9,212	(4,673)
Tax on amounts reclassified from accumulated other comprehensive income	(1,324)	708
Tax on net current-period other comprehensive income (loss)	$ 7,888	$ (3,965)

SUMMARY OF SIGNIFICANT ACCOUN60

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - PENSION AND POSTEMPLOYMENT PLANS (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2017USD ($)plan	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Defined Benefit Plan Disclosure [Line Items]
Number of noncontributory defined benefit retirement plans (in plans) | plan	2
Number of noncontributory medical and life insurance plans (in plans) | plan	2
Pension
Defined Benefit Plan Disclosure [Line Items]
Employer discretionary contributions	$ 0	$ 30,000	$ 0
Employer contributions	74	30,071
OPEB
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 6,049	$ 3,235	$ 5,700

SUMMARY OF SIGNIFICANT ACCOUN61

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - RECENTLY ADOPTED ACCOUNTING STANDARDS (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Other noncurrent assets	$ 74,818	$ 60,196
Total noncurrent assets	739,322	703,654
Total assets	3,928,507	3,718,570	$ 3,284,357
Long-term debt	997,080	1,055,038
Total capitalization	2,233,723	2,221,629
Total capitalization and liabilities	$ 3,928,507	3,718,570
As Previously Reported
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Other noncurrent assets		68,708
Total noncurrent assets		712,166
Total assets		3,727,082
Long-term debt		1,063,550
Total capitalization		2,230,141
Total capitalization and liabilities		3,727,082
Effect of Change
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Other noncurrent assets		(8,512)
Total noncurrent assets		(8,512)
Total assets		(8,512)
Long-term debt		(8,512)
Total capitalization		(8,512)
Total capitalization and liabilities		$ (8,512)

ACQUISITION (Details)

ACQUISITION (Details) - Talen's Wholesale Natural Gas Energy Contracts - USD ($) $ in Thousands	Jul. 27, 2017	Sep. 30, 2017
Business Acquisition [Line Items]
Total purchase price consideration transferred	$ 55,661
Net assets acquired	55,661
Goodwill		$ 0
Acquisition related transaction costs		300
Revenue attributable to the acquisition		20,500
Operating loss attributable to the acquisition		281
Wholesale Energy Contracts
Business Acquisition [Line Items]
Wholesale energy contracts	41,846
Amortization expense		$ 762
Retail Energy Contracts
Business Acquisition [Line Items]
Retail energy contracts	$ 13,815
Minimum | Wholesale Energy Contracts
Business Acquisition [Line Items]
Useful life	1 year
Minimum | Retail Energy Contracts
Business Acquisition [Line Items]
Useful life	0 years
Maximum | Wholesale Energy Contracts
Business Acquisition [Line Items]
Useful life	9 years
Maximum | Retail Energy Contracts
Business Acquisition [Line Items]
Useful life	4 years

REGULATION - REGULATORY ASSETS

REGULATION - REGULATORY ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Regulatory Assets [Line Items]
Regulatory assets-current	$ 50,791	$ 54,286
Regulatory assets-noncurrent	375,919	441,294
Regulatory Liabilities [Line Items]
Regulatory liability-current	78	9,469
Regulatory liabilities-noncurrent	14,507	41,411
Overrecovered gas costs
Regulatory Liabilities [Line Items]
Regulatory liability-current	0	9,469
Cost of removal obligation
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	7,902	30,549
New Jersey Clean Energy Program
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	5,795	10,657
Other noncurrent regulatory liabilities
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	664	205
Derivatives at fair value, net
Regulatory Liabilities [Line Items]
Regulatory liability-current	78	0
Regulatory liabilities-noncurrent	146	0
Conservation Incentive Program
Regulatory Assets [Line Items]
Regulatory assets-current	17,669	36,957
New Jersey Clean Energy Program
Regulatory Assets [Line Items]
Regulatory assets-current	14,202	14,232
Underrecovered gas costs
Regulatory Assets [Line Items]
Regulatory assets-current	9,910	0
Derivatives at fair value, net
Regulatory Assets [Line Items]
Regulatory assets-current	9,010	3,097
Regulatory assets-noncurrent	0	23,384
Environmental remediation costs, Expended, net of recoveries
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	28,547	19,595
Environmental remediation costs, Liability for future expenditures
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	149,000	172,000
Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	21,795	20,273
SAVEGREEN
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	16,302	25,208
Postemployment and other benefit costs
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	141,433	157,027
Deferred Superstorm Sandy costs
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	13,030	15,201
Other noncurrent regulatory assets
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	$ 5,812	$ 8,606

REGULATION - REGULATORY FILINGS

REGULATION - REGULATORY FILINGS (Details)

Apr. 01, 2018USD ($)

Nov. 01, 2017USD ($)

Sep. 22, 2017USD ($)

Jul. 20, 2017USD ($)

Oct. 01, 2016USD ($)

Nov. 01, 2015

Sep. 30, 2017USD ($)station

Sep. 30, 2016USD ($)

Oct. 31, 2015USD ($)

Sep. 30, 2015USD ($)

Jul. 31, 2014USD ($)project

Oct. 31, 2012USD ($)

Jun. 30, 2012USD ($)

Feb. 29, 2016USD ($)

Feb. 29, 2016USD ($)

Sep. 30, 2017USD ($)station

Sep. 30, 2010USD ($)

Public Utilities, General Disclosures [Line Items]

Return on equity

9.75%

Public utilities, approved equity capital structure, percentage

52.50%

Composite rate of depreciation

2.40%

Program recovery term

5 years

Tax charge resulting from a change in deductibility of federal subsidies

$ 2,400,000

Regulatory assets, noncurrent

$ 375,919,000

$ 441,294,000

$ 375,919,000

Number of NGV stations opened to the public | station

3

3

Other Regulatory Asset

Public Utilities, General Disclosures [Line Items]

Regulatory asset, maximum amount to be recorded annually

700,000

Regulatory asset, expense benchmark

1,400,000

Regulatory assets, threshold of recording regulatory liability when net liability exceeds amount

1,000,000

Other Regulatory Asset, PIM

Public Utilities, General Disclosures [Line Items]

Regulatory assets, noncurrent

$ 3,800,000

$ 3,800,000

Regulatory assets, amortization period

7 years

September 2016 Base Rate Case

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease), amount

$ 45,000,000

June 2015 BGSS/CIP Filing

Public Utilities, General Disclosures [Line Items]

Customer bill credits

$ 61,600,000

June 2016 BGSS/CIP Filing

Public Utilities, General Disclosures [Line Items]

Customer bill credits

48,000,000

$ 42,000,000

June 2016 BGSS/CIP Filing | Basic Gas Supply Service

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease), amount

(22,600,000)

June 2016 BGSS/CIP Filing | Conservation Incentive Program

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease), amount

43,900,000

June 2017 BGSS/CIP Filing

Public Utilities, General Disclosures [Line Items]

Increase in annual revenues

$ 3,700,000

June 2017 BGSS/CIP Filing | Conservation Incentive Program

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease), amount

$ (16,200,000)

Annual Petition With BPU

Public Utilities, General Disclosures [Line Items]

Requested base rate increase, amount

$ 4,100,000

SAFE Program

Public Utilities, General Disclosures [Line Items]

Capital investments approved by the BPU

200,000,000

$ 130,000,000

Capital investments to be recovered approved by the Board of Public Utilities

$ 157,500,000

Capital investments approved by the BPU, period

4 years

SAVEGREEN

Public Utilities, General Disclosures [Line Items]

Capital investments approved by the BPU

219,300,000

Grants, rebates and loans provided to customers

149,700,000

Increase in regulatory funding obligations

$ 20,000,000

SAVEGREEN | Minimum

Public Utilities, General Disclosures [Line Items]

Return on equity

9.75%

Public utilities, approved equity capital structure, percentage

6.69%

Program recovery term

2 years

Regulatory assets, amortization period

2 years

SAVEGREEN | Maximum

Public Utilities, General Disclosures [Line Items]

Return on equity

10.30%

Public utilities, approved equity capital structure, percentage

7.76%

Program recovery term

10 years

Regulatory assets, amortization period

10 years

NJ RISE Program

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease), amount

$ 390,000

Return on equity

9.75%

Public utilities, approved equity capital structure, percentage

6.74%

Program recovery term

5 years

Number of capital investment projects | project

6

Originally filed petition for capital investments to Board of Public Utilities

$ 102,500,000

SAFE II and NJ RISE [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity

9.75%

Public utilities, approved equity capital structure, percentage

6.90%

USF

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease), amount

$ (2,600,000)

$ 1,300,000

$ (3,900,000)

RAC

Public Utilities, General Disclosures [Line Items]

Approved rate, amount

$ 9,400,000

Compressed Natural Gas Vehicle Refueling Stations

Public Utilities, General Disclosures [Line Items]

Capital investments approved by the BPU

$ 10,000,000

SRL-Southern Reliability Link | Minimum

Public Utilities, General Disclosures [Line Items]

Estimated cost of the SRL

180,000,000

SRL-Southern Reliability Link | Maximum

Public Utilities, General Disclosures [Line Items]

Estimated cost of the SRL

$ 200,000,000

LNG-Liquefied Natural Gas

Public Utilities, General Disclosures [Line Items]

Capital investments to be recovered approved by the Board of Public Utilities

$ 36,500,000

NJNG | June 2015 BGSS/CIP Filing | Conservation Incentive Program

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease), amount

$ 1,100,000

Subsequent Event | SAVEGREEN

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease), amount

$ (3,900,000)

Scenario, Forecast | RAC

Public Utilities, General Disclosures [Line Items]

Approved rate, amount

$ 7,000,000

DERIVATIVE INSTRUMENTS - BALANC

DERIVATIVE INSTRUMENTS - BALANCE SHEET RELATED DISCLOSURES (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Jun. 01, 2015
Derivatives, Fair Value [Line Items]
Fixed treasury rate			3.26%
Notional amount of foreign currency derivatives			$ 125,000
Asset Derivatives, current	$ 30,081	$ 29,964
Asset Derivatives, noncurrent	9,164	5,227
Asset Derivatives	39,245	35,191
Liability Derivatives, current	46,544	61,080
Liability Derivatives, noncurrent	11,330	25,252
Liability Derivatives	57,874	86,332
Physical commodity contracts | Natural Gas Distribution | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current	151	235
Liability Derivatives, current	72	1,154
Physical commodity contracts | Energy Services | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current	14,588	5,994
Asset Derivatives, noncurrent	7,127	3,987
Liability Derivatives, current	16,589	11,660
Liability Derivatives, noncurrent	8,710	1,212
Financial commodity contracts | Natural Gas Distribution | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current	0	805
Asset Derivatives, noncurrent	0	75
Liability Derivatives, current	1,149	2,979
Liability Derivatives, noncurrent	0	386
Financial commodity contracts | Energy Services | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current	15,302	22,929
Asset Derivatives, noncurrent	2,033	1,165
Liability Derivatives, current	20,267	45,255
Liability Derivatives, noncurrent	2,620	581
Interest rate contracts | Natural Gas Distribution | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current	0	0
Asset Derivatives, noncurrent	0	0
Liability Derivatives, current	8,467	0
Liability Derivatives, noncurrent	0	23,073
Foreign currency contracts
Derivatives, Fair Value [Line Items]
Notional amount of foreign currency derivatives	4,500
Foreign currency contracts | Energy Services | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current	40	1
Asset Derivatives, noncurrent	4	0
Liability Derivatives, current	0	32
Liability Derivatives, noncurrent	0	$ 0
Series LL | Natural Gas Distribution
Derivatives, Fair Value [Line Items]
Long-term debt	$ 125,000
Stated interest rate	5.60%

- OFFSETTING OF ASSETS AND LIAB

- OFFSETTING OF ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands		Sep. 30, 2017		Sep. 30, 2016
Energy Services
Derivative assets:
Amounts Presented on the Balance Sheets		$ 39,094		$ 34,076
Offsetting Derivative Instruments		(16,294)		(20,783)
Financial Collateral Received/Pledged		(200)		(6,904)
Net Amounts	[1]	22,600		6,389
Derivative liabilities:
Amounts Presented in Balance Sheets		48,186		58,740
Offsetting Derivative Instruments		(16,294)		(20,783)
Financial Collateral Received/Pledged		(8,766)		(26,691)
Net Amounts	[1]	23,126		11,266
Energy Services | Physical commodity contracts
Derivative assets:
Amounts Presented on the Balance Sheets		21,715		9,981
Offsetting Derivative Instruments		(2,173)		(2,837)
Financial Collateral Received/Pledged		(200)		(755)
Net Amounts	[1]	19,342		6,389
Derivative liabilities:
Amounts Presented in Balance Sheets		25,299		12,872
Offsetting Derivative Instruments		(2,173)		(2,837)
Financial Collateral Received/Pledged		0		1,200
Net Amounts	[1]	23,126		11,235
Energy Services | Financial commodity contracts
Derivative assets:
Amounts Presented on the Balance Sheets		17,335		24,094
Offsetting Derivative Instruments		(14,121)		(17,945)
Financial Collateral Received/Pledged		0		(6,149)
Net Amounts	[1]	3,214		0
Derivative liabilities:
Amounts Presented in Balance Sheets		22,887		45,836
Offsetting Derivative Instruments		(14,121)		(17,945)
Financial Collateral Received/Pledged		(8,766)		(27,891)
Net Amounts	[1]	0		0
Energy Services | Foreign currency contracts
Derivative assets:
Amounts Presented on the Balance Sheets		44		1
Offsetting Derivative Instruments		0		(1)
Financial Collateral Received/Pledged		0		0
Net Amounts		44		0	[1]
Derivative liabilities:
Amounts Presented in Balance Sheets		0		32
Offsetting Derivative Instruments		0		(1)
Financial Collateral Received/Pledged		0		0
Net Amounts	[1]	0		31
Natural Gas Distribution
Derivative assets:
Amounts Presented on the Balance Sheets		151		1,115
Offsetting Derivative Instruments		(20)		(911)
Financial Collateral Received/Pledged		0		0
Net Amounts	[1]	131		204
Derivative liabilities:
Amounts Presented in Balance Sheets		9,688		27,592
Offsetting Derivative Instruments		(20)		(911)
Financial Collateral Received/Pledged		(1,149)		(2,485)
Net Amounts		8,519	[1]	24,196
Natural Gas Distribution | Physical commodity contracts
Derivative assets:
Amounts Presented on the Balance Sheets		151		235
Offsetting Derivative Instruments		(20)		(31)
Financial Collateral Received/Pledged		0		0
Net Amounts		131		204
Derivative liabilities:
Amounts Presented in Balance Sheets		72		1,154
Offsetting Derivative Instruments		(20)		(31)
Financial Collateral Received/Pledged		0		0
Net Amounts		52		1,123
Natural Gas Distribution | Financial commodity contracts
Derivative assets:
Amounts Presented on the Balance Sheets		0		880
Offsetting Derivative Instruments		0		(880)
Financial Collateral Received/Pledged		0		0
Net Amounts	[1]	0		0
Derivative liabilities:
Amounts Presented in Balance Sheets		1,149		3,365
Offsetting Derivative Instruments		0		(880)
Financial Collateral Received/Pledged		(1,149)		(2,485)
Net Amounts	[1]	0		0
Natural Gas Distribution | Interest rate contracts
Derivative assets:
Amounts Presented on the Balance Sheets		0		0
Offsetting Derivative Instruments		0		0
Financial Collateral Received/Pledged		0		0
Net Amounts	[1]	0		0
Derivative liabilities:
Amounts Presented in Balance Sheets		8,467		23,073
Offsetting Derivative Instruments		0		0
Financial Collateral Received/Pledged		0		0
Net Amounts		$ 8,467	[1]	$ 23,073
[1]	Net amounts represent presentation of derivative assets and liabilities if the Company were to elect balance sheet offsetting under ASC 210-20.

DERIVATIVE INSTRUMENTS - INCOME

DERIVATIVE INSTRUMENTS - INCOME STATEMENT RELATED DISCLOSURES (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Foreign currency contracts | Gas purchases | Derivatives in cash flow hedging relationships:
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ (27)
Amount of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)	0	27
Amount of Gain or (Loss) Recognized on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	0	0
Energy Services | Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	8,055	32,942	$ 107,212
Energy Services | Physical commodity contracts | Operating revenues | Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	8,912	33,034	32,568
Energy Services | Physical commodity contracts | Gas purchases | Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	(27,461)	(45,637)	(34,438)
Energy Services | Financial commodity contracts | Gas purchases | Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	26,563	45,579	109,082
Energy Services | Foreign currency contracts | Gas purchases | Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	41	(34)	0
Natural Gas Distribution | Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	7,898	(42,585)	(37,656)
Natural Gas Distribution | Physical commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives			0
Natural Gas Distribution | Physical commodity contracts | Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	(12,303)	(15,756)
Natural Gas Distribution | Financial commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives			(33,428)
Natural Gas Distribution | Financial commodity contracts | Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	5,595	(7,984)
Natural Gas Distribution | Interest rate contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives			$ (4,228)
Natural Gas Distribution | Interest rate contracts | Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 14,606	$ (18,845)

DERIVATIVE INSTRUMENTS - VOLUME

DERIVATIVE INSTRUMENTS - VOLUME (Details) certificate in Thousands, $ in Millions	Sep. 30, 2017USD ($)Bcfcertificate	Sep. 30, 2016Bcf	Jun. 01, 2015USD ($)
Derivative [Line Items]
Derivative, notional amount | $			$ 125
Foreign currency contracts
Derivative [Line Items]
Derivative, notional amount | $	$ 4.5
Energy Services | Physical commodity contracts
Derivative [Line Items]
Number of Solar Renewable Energy Certificates (in certificates) | certificate	283
Long | Natural Gas Distribution | Futures
Derivative [Line Items]
Outstanding long (short) derivatives (in Bcf)	18.2	23.6
Long | Natural Gas Distribution | Physical
Derivative [Line Items]
Outstanding long (short) derivatives (in Bcf)	32.1	9.2
Long | Energy Services | Physical
Derivative [Line Items]
Outstanding long (short) derivatives (in Bcf)		94.6
Long | Energy Services | Financial Options
Derivative [Line Items]
Outstanding long (short) derivatives (in Bcf)	0	1.2
Short | Energy Services | Futures
Derivative [Line Items]
Outstanding long (short) derivatives (in Bcf)	16.4	79.1
Short | Energy Services | Physical
Derivative [Line Items]
Outstanding long (short) derivatives (in Bcf)	13.1

DERIVATIVE INSTRUMENTS - BROKER

DERIVATIVE INSTRUMENTS - BROKER MARGIN DEPOSITS (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Natural Gas Distribution
Broker margin - Current assets	$ 2,661	$ 4,822
Energy Services
Broker margin - Current assets	$ 23,166	$ 42,822

DERIVATIVE INSTRUMENTS - CREDIT

DERIVATIVE INSTRUMENTS - CREDIT RISK EXPOSURE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Credit Risk Exposure [Line Items]
Gross Credit Exposure	$ 238,569
Derivative, net liability position, aggregate fair value	8,700	$ 23,100
Additional collateral, aggregate fair value	8,600	$ 23,100
Investment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	136,804
Noninvestment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	16,889
Internally-rated investment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	16,378
Internally-rated noninvestment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	$ 68,498

FAIR VALUE - DEBT (Details)

FAIR VALUE - DEBT (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Capital leases	$ 39,700	$ 42,200
Natural Gas Distribution
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt issuance costs	(6,262)	(7,659)
NJR
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt issuance costs	(770)	(853)
Significant Other Observable Inputs (Level 2) | Natural Gas Distribution | Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	672,045	707,845
Significant Other Observable Inputs (Level 2) | Natural Gas Distribution | Fair market value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	673,051	731,615
Significant Other Observable Inputs (Level 2) | NJR | Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	425,000	375,000
Significant Other Observable Inputs (Level 2) | NJR | Fair market value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 434,625	$ 399,462

FAIR VALUE - HIERARCHY (Details

FAIR VALUE - HIERARCHY (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Assets
Derivative assets	$ 39,245	$ 35,191
Liabilities
Derivative liabilities	57,874	86,332
Fair Value, Measurements, Recurring
Assets
Available for sale equity securities	65,752	55,789
Other	1,090	1,444
Total assets at fair value	106,199	126,496
Liabilities
Total liabilities at fair value	57,874	86,332
Fair Value, Measurements, Recurring | Physical commodity contracts
Assets
Derivative assets	21,866	10,216
Liabilities
Derivative liabilities	25,371	14,026
Fair Value, Measurements, Recurring | Financial commodity contracts
Assets
Derivative assets	17,335	24,974
Liabilities
Derivative liabilities	24,036	49,201
Fair Value, Measurements, Recurring | Foreign currency contracts
Assets
Derivative assets	44	1
Liabilities
Derivative liabilities	0	32
Fair Value, Measurements, Recurring | Interest rate contracts
Liabilities
Derivative liabilities	8,467	23,073
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Available for sale equity securities	65,752	55,789
Other	1,090	1,444
Total assets at fair value	84,289	116,279
Liabilities
Total liabilities at fair value	24,036	49,201
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Physical commodity contracts
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Financial commodity contracts
Assets
Derivative assets	17,335	24,974
Liabilities
Derivative liabilities	24,036	49,201
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign currency contracts
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate contracts
Liabilities
Derivative liabilities	0	0
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets
Available for sale equity securities	0	0
Other	0	0
Total assets at fair value	21,910	10,217
Liabilities
Total liabilities at fair value	33,838	37,131
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Physical commodity contracts
Assets
Derivative assets	21,866	10,216
Liabilities
Derivative liabilities	25,371	14,026
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Financial commodity contracts
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Foreign currency contracts
Assets
Derivative assets	44	1
Liabilities
Derivative liabilities	0	32
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Interest rate contracts
Liabilities
Derivative liabilities	8,467	23,073
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets
Available for sale equity securities	0	0
Other	0	0
Total assets at fair value	0	0
Liabilities
Total liabilities at fair value	0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Physical commodity contracts
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Financial commodity contracts
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Foreign currency contracts
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Interest rate contracts
Liabilities
Derivative liabilities	0	0
Fair Value, Measurements, Nonrecurring
Assets
Total assets at fair value	41,084
Liabilities
Acquired wholesale energy contracts	41,084
Fair Value, Measurements, Nonrecurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Total assets at fair value	0
Liabilities
Acquired wholesale energy contracts	0
Fair Value, Measurements, Nonrecurring | Significant Other Observable Inputs (Level 2)
Assets
Total assets at fair value	41,084
Liabilities
Acquired wholesale energy contracts	41,084
Fair Value, Measurements, Nonrecurring | Significant Unobservable Inputs (Level 3)
Assets
Total assets at fair value	0
Liabilities
Acquired wholesale energy contracts	0
Money market funds | Fair Value, Measurements, Recurring
Assets
Cash and cash equivalents	112	34,072
Money market funds | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Cash and cash equivalents	112	34,072
Money market funds | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets
Cash and cash equivalents	0	0
Money market funds | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets
Cash and cash equivalents	$ 0	$ 0

INVESTMENTS IN EQUITY INVESTE73

INVESTMENTS IN EQUITY INVESTEES (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2017USD ($)mi	Sep. 30, 2016USD ($)
Schedule of Equity Method Investments [Line Items]
Investments in equity investees	$ 172,585	$ 141,148
Steckman Ridge
Schedule of Equity Method Investments [Line Items]
Investments in equity investees	120,262	123,155
Steckman Ridge | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Outstanding principal balance	70,400	70,400
PennEast
Schedule of Equity Method Investments [Line Items]
Investments in equity investees	$ 52,323	$ 17,993
Construction plan, pipeline distance (in miles) | mi	120

EARNINGS PER SHARE (Details)

EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2017		Sep. 30, 2016		Sep. 30, 2015
Earnings Per Share [Abstract]
Net income, as reported	$ (36,523)	$ 18,957	$ 114,702	$ 34,929	$ 25,400	$ (17,363)	$ 73,354	$ 50,281	$ 132,065		$ 131,672		$ 180,960
Basic earnings per share
Weighted average shares of common stock outstanding-basic (in shares)									86,321,000		85,884,000		85,186,000
Basic earnings per common share (in dollars per share)	$ (0.42)	$ 0.22	$ 1.33	$ 0.41	$ 0.30	$ (0.20)	$ 0.85	$ 0.59	$ 1.53		$ 1.53		$ 2.12
Diluted earnings per share
Weighted average shares of common stock outstanding-basic (in shares)									86,321,000		85,884,000		85,186,000
Incremental shares (in shares)									823,000		847,000		1,079,000
Weighted average shares of common stock outstanding-diluted (in shares)									87,144,000		86,731,000		86,265,000
Diluted earnings per common share (in dollars per share)	$ (0.42)	$ 0.22	$ 1.32	$ 0.40	$ 0.29	$ (0.20)	$ 0.84	$ 0.58	$ 1.52	[1]	$ 1.52	[1]	$ 2.10	[1]
Anti-dilutive securities excluded from the calculation of diluted earnings per share (in shares)									0		0		0
[1]	There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2017, 2016 and 2015.

DEBT - SCHEDULE OF LONG-TERM DE

DEBT - SCHEDULE OF LONG-TERM DEBT (Details) - USD ($)	Sep. 30, 2017	Aug. 18, 2017	Sep. 30, 2016	Jun. 21, 2016	Mar. 22, 2016
Debt Instrument [Line Items]
Total long-term debt	$ 997,080,000		$ 1,055,038,000
Term loan | Credit Agreement Due August 16, 2019
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	100,000,000	$ 100,000,000
Natural Gas Distribution
Debt Instrument [Line Items]
Debt issuance costs	(6,262,000)		(7,659,000)
Less: Current maturities of long-term debt	(135,800,000)		(11,452,000)
Total long-term debt	569,642,000		730,891,000
Natural Gas Distribution | Series LL
Debt Instrument [Line Items]
Long-term debt	$ 125,000,000
Stated interest rate	5.60%
Natural Gas Distribution | First mortgage bonds: | Series II
Debt Instrument [Line Items]
Long-term debt	$ 0		10,300,000
Stated interest rate	4.50%
Natural Gas Distribution | First mortgage bonds: | Series JJ
Debt Instrument [Line Items]
Long-term debt	$ 0		10,500,000
Stated interest rate	4.60%
Natural Gas Distribution | First mortgage bonds: | Series KK
Debt Instrument [Line Items]
Long-term debt	$ 0		15,000,000
Stated interest rate	4.90%
Natural Gas Distribution | First mortgage bonds: | Series LL
Debt Instrument [Line Items]
Long-term debt			125,000,000
Stated interest rate	5.60%
Natural Gas Distribution | First mortgage bonds: | Series MM
Debt Instrument [Line Items]
Long-term debt	$ 9,545,000		9,545,000
Natural Gas Distribution | First mortgage bonds: | Series NN
Debt Instrument [Line Items]
Long-term debt	41,000,000		41,000,000
Natural Gas Distribution | First mortgage bonds: | Series OO
Debt Instrument [Line Items]
Long-term debt	46,500,000		46,500,000
Natural Gas Distribution | First mortgage bonds: | Series PP
Debt Instrument [Line Items]
Long-term debt	$ 50,000,000		50,000,000
Stated interest rate	3.15%
Natural Gas Distribution | First mortgage bonds: | Series QQ
Debt Instrument [Line Items]
Long-term debt	$ 70,000,000		70,000,000
Stated interest rate	3.58%
Natural Gas Distribution | First mortgage bonds: | Series RR
Debt Instrument [Line Items]
Long-term debt	$ 55,000,000		55,000,000
Stated interest rate	4.61%
Natural Gas Distribution | First mortgage bonds: | Series SS
Debt Instrument [Line Items]
Long-term debt	$ 50,000,000		50,000,000
Stated interest rate	2.82%
Natural Gas Distribution | First mortgage bonds: | Series TT
Debt Instrument [Line Items]
Long-term debt	$ 100,000,000		100,000,000
Stated interest rate	3.66%
Natural Gas Distribution | First mortgage bonds: | Series UU
Debt Instrument [Line Items]
Long-term debt	$ 125,000,000		125,000,000
Stated interest rate	3.63%			3.63%
Natural Gas Distribution | Capital lease obligations | Capital lease obligation-buildings
Debt Instrument [Line Items]
Long-term debt	$ 11,617,000		14,262,000
Natural Gas Distribution | Capital lease obligations | Capital lease obligation-meters
Debt Instrument [Line Items]
Long-term debt	28,042,000		27,895,000
NJR
Debt Instrument [Line Items]
Debt issuance costs	(770,000)		(853,000)
Less: Current maturities of long-term debt	(25,000,000)		(50,000,000)
Total long-term debt	399,230,000		324,147,000
NJR | Unsecured senior notes 6.05%
Debt Instrument [Line Items]
Long-term debt	$ 0		50,000,000
Stated interest rate	6.05%
NJR | Unsecured senior notes 2.51%
Debt Instrument [Line Items]
Long-term debt	$ 25,000,000		25,000,000
Stated interest rate	2.51%
NJR | Unsecured senior notes 3.25%
Debt Instrument [Line Items]
Long-term debt	$ 50,000,000		50,000,000
Stated interest rate	3.25%
NJR | Unsecured senior notes 3.48%
Debt Instrument [Line Items]
Long-term debt	$ 100,000,000		100,000,000
Stated interest rate	3.48%
NJR | Unsecured senior notes 3.20%
Debt Instrument [Line Items]
Long-term debt	$ 50,000,000		50,000,000
Stated interest rate	3.20%				3.20%
NJR | Unsecured senior notes 3.54%
Debt Instrument [Line Items]
Long-term debt	$ 100,000,000		100,000,000
Stated interest rate	3.54%				3.54%
Clean Energy Ventures
Debt Instrument [Line Items]
Long-term debt	$ 32,790,000		0
Less: Current maturities of long-term debt	(4,582,000)		0
Long-term debt, excluding current maturities	$ 28,208,000		$ 0

DEBT - REDEMPTION REQUIREMENTS

DEBT - REDEMPTION REQUIREMENTS (Details) $ in Thousands	Sep. 30, 2017USD ($)
Natural Gas Distribution
Debt Instrument [Line Items]
2,017	$ 125,000
2,018	0
2,019	0
2,020	0
2,021	0
Thereafter	547,045
NJR
Debt Instrument [Line Items]
2,017	25,000
2,018	100,000
2,019	0
2,020	0
2,021	50,000
Thereafter	$ 250,000

DEBT - FIRST MORTGAGE BONDS (De

DEBT - FIRST MORTGAGE BONDS (Details) $ in Thousands	Jan. 17, 2017USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Jun. 21, 2016	Aug. 31, 2011USD ($)
Debt Instrument [Line Items]
NJBPU dividend restriction, equity to capitalization ratio		0.3
Debt to equity ratio		0.556
Payment of long-term debt		$ 97,854	$ 13,289	$ 37,039
Variable Rate Debt
Debt Instrument [Line Items]
Long-term debt						$ 97,000
First mortgage bonds:
Debt Instrument [Line Items]
Maximum amount that can be issued		960,000
First mortgage bonds: | Natural Gas Distribution
Debt Instrument [Line Items]
Payment of long-term debt	$ 35,800
First mortgage bonds: | Series UU | Natural Gas Distribution
Debt Instrument [Line Items]
Long-term debt		$ 125,000	125,000
Stated interest rate		3.63%			3.63%
First mortgage bonds: | Series II | Natural Gas Distribution
Debt Instrument [Line Items]
Long-term debt		$ 0	$ 10,300
Stated interest rate		4.50%
Variable Demand Rate Notes | Natural Gas Distribution
Debt Instrument [Line Items]
Interest rate on EDA Bonds		1.42%
Minimum | First mortgage bonds: | Series II | Natural Gas Distribution
Debt Instrument [Line Items]
Stated interest rate	4.50%
Maximum | First mortgage bonds: | Series II | Natural Gas Distribution
Debt Instrument [Line Items]
Stated interest rate	4.90%

DEBT - SALE-LEASEBACKS (Details

DEBT - SALE-LEASEBACKS (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Debt Instrument [Line Items]
Proceeds from sale-leaseback transaction	$ 9,587	$ 7,107	$ 7,216
Natural Gas Distribution
Debt Instrument [Line Items]
Sale leaseback transaction, lease term	25 years 6 months
Sale leaseback transaction, lease renewal term	5 years
Sale leaseback transaction, maximum lease renewal term (as a percent)	4
Proceeds from sale-leaseback transaction	$ 9,587	7,100	7,200
Sale leaseback transaction, other payments required	$ 2,400	$ 1,900	$ 768

DEBT - CONTRACTUAL COMMITMENTS

DEBT - CONTRACTUAL COMMITMENTS (Details) - NJR $ in Thousands	Sep. 30, 2017USD ($)
Debt Instrument [Line Items]
2,018	$ 12,436
2,019	9,675
2,020	8,849
2,021	5,862
2,022	2,518
Thereafter	4,914
Subtotal	44,200
Less: Interest component	(4,494)
Total	$ 39,700

DEBT - NJR LONG-TERM DEBT (Deta

DEBT - NJR LONG-TERM DEBT (Details)	Aug. 18, 2017USD ($)	Sep. 30, 2017USD ($)asset	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Mar. 22, 2016
Debt Instrument [Line Items]
Proceeds from sale-leaseback transaction - solar			$ 32,901,000	$ 0	$ 0
Credit Agreement Due August 16, 2019 | Term loan
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 100,000,000	$ 100,000,000	100,000,000
NJR | Unsecured senior notes 3.25%
Debt Instrument [Line Items]
Long-term debt		$ 50,000,000	$ 50,000,000	50,000,000
Stated interest rate		3.25%	3.25%
NJR | Unsecured senior notes 3.48%
Debt Instrument [Line Items]
Long-term debt		$ 100,000,000	$ 100,000,000	100,000,000
Stated interest rate		3.48%	3.48%
NJR | Unsecured senior notes 2.51%
Debt Instrument [Line Items]
Long-term debt		$ 25,000,000	$ 25,000,000	25,000,000
Stated interest rate		2.51%	2.51%
NJR | Unsecured senior notes 3.20%
Debt Instrument [Line Items]
Long-term debt		$ 50,000,000	$ 50,000,000	50,000,000
Stated interest rate		3.20%	3.20%			3.20%
NJR | Unsecured senior notes 3.54%
Debt Instrument [Line Items]
Long-term debt		$ 100,000,000	$ 100,000,000	100,000,000
Stated interest rate		3.54%	3.54%			3.54%
NJR | Variable Demand Rate Notes
Debt Instrument [Line Items]
Interest rate, effective percentage		1.95%	1.95%
NJR | Variable Rate Debt
Debt Instrument [Line Items]
Long-term debt		$ 0	$ 0	$ 0
Clean Energy Ventures
Debt Instrument [Line Items]
Number of commercial solar assets sold | asset		2
Term of lease		7 years
Proceeds from sale-leaseback transaction - solar		$ 32,901,000
Annual rental payments (next 5 years)		$ 2,700,000
Annual contractual commitments, number of years		5 years
Annual contractual commitments, aggregate thereafter		$ 5,300,000	$ 5,300,000
London Interbank Offered Rate (LIBOR) | Credit Agreement Due August 16, 2019 | Term loan
Debt Instrument [Line Items]
Basis spread on variable rate	0.70%

DEBT - SHORT-TERM BANK FACILITI

DEBT - SHORT-TERM BANK FACILITIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
NJR | Letters of credit
Short-term Debt [Line Items]
Letters of credit outstanding, amount	$ 13,400	$ 14,400
NJR | Notes payable to banks
Short-term Debt [Line Items]
Outstanding at end of period	$ 255,000	$ 121,700
Weighted average interest rate at end of period	2.14%	1.43%
Amount available at end of period	$ 156,601	$ 288,910
NJR | Committed Credit Facilities Due September 2020 | Bank revolving credit facilities
Short-term Debt [Line Items]
Bank revolving credit facilities	$ 425,000	$ 425,000
NJR | Bank revolving credit facilities
Short-term Debt [Line Items]
Commitment fee percentage	0.075%	0.075%
Natural Gas Distribution | Commercial paper
Short-term Debt [Line Items]
Outstanding at end of period	$ 11,000	$ 0
Weighted average interest rate at end of period	1.13%	0.00%
Amount available at end of period	$ 238,269	$ 249,269
Natural Gas Distribution | Letters of credit
Short-term Debt [Line Items]
Letters of credit outstanding, amount	$ 731	731
Natural Gas Distribution | Bank revolving credit facilities
Short-term Debt [Line Items]
Commitment fee percentage	0.075%
Natural Gas Distribution | Committed Credit Facilities Due May 2019 | Bank revolving credit facilities
Short-term Debt [Line Items]
Bank revolving credit facilities	$ 250,000	$ 250,000

DEBT - NJR SHORT-TERM DEBT (Det

DEBT - NJR SHORT-TERM DEBT (Details) - NJR	12 Months Ended
	Sep. 30, 2017USD ($)debt_instrument	Sep. 30, 2016USD ($)
Letters of credit
Short-term Debt [Line Items]
Number of debt instruments (in debt instruments) | debt_instrument	6
Letters of credit outstanding, amount	$ 13,400,000	$ 14,400,000
Letters of Credit on Behalf of NJRES
Short-term Debt [Line Items]
Number of debt instruments (in debt instruments) | debt_instrument	3
Letters of credit outstanding, amount	$ 10,400,000
Letters of Credit on Behalf of NJRCEV
Short-term Debt [Line Items]
Number of debt instruments (in debt instruments) | debt_instrument	3
Letters of credit outstanding, amount	$ 3,000,000
Committed Credit Facilities Due September 2020 | Bank revolving credit facilities
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 425,000,000	$ 425,000,000
Bank revolving credit facilities
Short-term Debt [Line Items]
Commitment fee percentage	0.075%	0.075%
Line of credit facility, maximum borrowing capacity, incremental increase	$ 5,000,000
Line of credit facility, maximum borrowing capacity, maximum increase	$ 100,000,000

DEBT - NJNG SHORT-TERM DEBT (De

DEBT - NJNG SHORT-TERM DEBT (Details) - Natural Gas Distribution	12 Months Ended
	Sep. 30, 2017USD ($)debt_instrument	Sep. 30, 2016USD ($)
Letters of credit
Line of Credit Facility [Line Items]
Number of debt instruments (in debt instruments) | debt_instrument	2
Letters of credit outstanding, amount	$ 731,000	$ 731,000
Committed Credit Facilities Due May 2019 | Bank revolving credit facilities
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 250,000,000	$ 250,000,000
Bank revolving credit facilities
Line of Credit Facility [Line Items]
Debt instrument, term	5 years
Line of credit facility, maximum borrowing capacity, incremental increase	$ 15,000,000
Line of credit facility, maximum borrowing capacity, maximum increase	$ 50,000,000

STOCK-BASED COMPENSATION - NARR

STOCK-BASED COMPENSATION - NARRATIVE (Details) - USD ($)	1 Months Ended			12 Months Ended
	Jan. 31, 2016	Jan. 31, 2015	Jan. 31, 2014	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Proceeds from exercise of stock options				$ 0		$ 724,000
Performance Shares, Market Condition Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)				44,576
Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)				51,931	69,305	61,576
Deferred compensation related to unvested performance shares, period				1 year 8 months 12 days
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)				156,587	179,916	214,464	247,536
Number of shares granted (in shares)				96,507	115,480	102,790
Deferred compensation related to unvested restricted and performance shares				$ 2,900,000
Weighted average grant date fair value (in dollars per share)				$ 33.57	$ 27.37	$ 28.25
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)				51,154	73,071	81,492	41,491
Number of shares granted (in shares)				28,734	41,909	61,972
Deferred compensation related to unvested restricted and performance shares				$ 511,409
Deferred compensation related to unvested performance shares, period				2 years
Weighted average grant date fair value (in dollars per share)				$ 35.79	$ 30.03	$ 29.41
Vesting September 30, 2019 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)				25,806
Vesting Annually Over Three Year Period Beginning September 30, 2017 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)				26,125
Award vesting period				3 years
Vesting September 2017 | Performance Shares, Market Condition Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)					46,175
Vesting September 2017 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted and expected to be distributed (in shares)					38,789
Vesting Annually Over a Three Year Period Beginning in September 2015 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted and expected to be distributed (in shares)					30,516
Award vesting period						3 years
Vesting Annually Over Three Year Period Beginning October 15, 2017 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)				22,591
Award vesting period				3 years
Vesting Annually Over Three Year Period Beginning May 8, 2018 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)				6,143
Vesting Annually Over Three Year Period Beginning October 2016 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)					41,909
Award vesting period					3 years
Vesting September 2016 | Performance Shares, Market Condition Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)						41,214
Vesting September 2016 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted and expected to be distributed (in shares)						34,622
Vesting Annually Over a Three Year Period Beginning in September 2014 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted and expected to be distributed (in shares)						26,954
Vesting Annually Over a Three Year Period Beginning in October 2015 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)						48,542
Award vesting period						3 years
Vesting October 2015 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)						10,236
Vesting September 2015 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)						3,194
Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for future issuance (in shares)				3,119,878.1
Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation costs not yet recognized				$ 280,000
Director | Scheduled to Vest Immediately
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)	27,972	27,481	26,122
Weighted average grant date fair value (in dollars per share)	$ 35.59	$ 32.75	$ 30.63
NJR 2007 Stock Award And Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)					914,169
NJR 2017 Stock Award And Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional shares authorized for issuance (in shares)				3,135,000

STOCK-BASED COMPENSATION - STOC

STOCK-BASED COMPENSATION - STOCK-BASED COMPENSATION EXPENSE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense	$ 5,807	$ 7,234	$ 9,645
Income tax benefit	(2,372)	(2,955)	(3,940)
Total, net of tax	3,435	4,279	5,705
Tax benefit of delivered shares from stock based compensation	1,285	1,755	881
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred compensation related to unvested restricted and performance shares	2,900
Compensation expense included in operation and maintenance expense	2,614	3,188	2,473
Restricted and non-restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense	1,732	2,161	1,899
Deferred retention stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense	$ 1,461	$ 1,885	$ 5,273

STOCK-BASED COMPENSATION - PERF

STOCK-BASED COMPENSATION - PERFORMANCE SHARES AND RESTRICTED STOCK ACTIVITY (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015	Nov. 14, 2017	Nov. 15, 2016	Nov. 10, 2015	Nov. 11, 2014
Performance Shares, Market Condition Award
Shares
Granted (in shares)	44,576
Performance share awards
Shares
Outstanding at beginning of period (in shares)	179,916	214,464	247,536
Granted (in shares)	96,507	115,480	102,790
Vested (in shares)	(95,407)	(137,053)	(112,446)
Cancelled/forfeited (in shares)	(24,429)	(12,975)	(23,416)
Outstanding at end of period (in shares)	156,587	179,916	214,464
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)	$ 27.47	$ 23.40	$ 18.30
Granted (in dollars per share)	33.57	27.37	28.25
Vested (in dollars per share)	28.88	21.40	17.10
Cancelled/forfeited (in dollars per share)	29.14	23.40	17.98
Outstanding at end of period (in dollars per share)	$ 30.12	$ 27.47	$ 23.40
Total Fair Value of Vested Shares	$ 4,179	$ 5,657	$ 4,318
Number of common shared issued (in shares)					71,808
Percent of awards to common stock, target		100.00%			150.00%
Performance share awards | Minimum
Weighted Average Grant Date Fair Value
Percent of awards to common stock	0.00%
Performance share awards | Maximum
Weighted Average Grant Date Fair Value
Percent of awards to common stock	150.00%
Performance Shares, Subject to Performance Conditions
Shares
Granted (in shares)	51,931	69,305	61,576
Weighted Average Grant Date Fair Value
Percent of awards to common stock		120.00%			100.00%
Number of common shared issued (in shares)		112,917.6			23,649	8,984	9,364
Number of shares canceled (in shares)					9,366	9,364
Performance Shares, TSR
Weighted Average Grant Date Fair Value
Percent of awards to common stock					85.00%
Number of common shared issued (in shares)					55,702
Restricted Stock
Shares
Outstanding at beginning of period (in shares)	73,071	81,492	41,491
Granted (in shares)	28,734	41,909	61,972
Vested (in shares)	(38,752)	(48,089)	(18,170)
Cancelled/forfeited (in shares)	(11,899)	(2,241)	(3,801)
Outstanding at end of period (in shares)	51,154	73,071	81,492
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)	$ 29.09	$ 27.17	$ 22.60
Granted (in dollars per share)	35.79	30.03	29.41
Vested (in dollars per share)	28.92	26.66	24.45
Cancelled/forfeited (in dollars per share)	31.56	29.21	26.79
Outstanding at end of period (in dollars per share)	$ 32.40	$ 29.09	$ 27.17
Total Fair Value of Vested Shares	$ 1,344	$ 1,469	$ 510
Subsequent Event | Performance share awards
Weighted Average Grant Date Fair Value
Number of common shared issued (in shares)				36,498
Percent of awards to common stock, target				119.00%
Subsequent Event | Performance Shares, Subject to Performance Conditions
Weighted Average Grant Date Fair Value
Percent of awards to common stock				100.00%
Number of common shared issued (in shares)				28,223
Subsequent Event | Performance Shares, TSR
Weighted Average Grant Date Fair Value
Percent of awards to common stock				108.44%
Number of common shared issued (in shares)				39,595
Vesting September 30, 2019 | Performance Shares, Subject to Performance Conditions
Shares
Granted (in shares)	25,806
Vesting Annually Over Three Year Period Beginning September 30, 2017 | Performance Shares, Subject to Performance Conditions
Shares
Granted (in shares)	26,125

STOCK-BASED COMPENSATION - DEFE

STOCK-BASED COMPENSATION - DEFERRED RETENTION STOCK (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Deferred retention stock
Shares
Outstanding at beginning of period (in shares)	662,479	632,730	276,782
Granted/Vested (in shares)	63,977	159,831	462,790
Delivered (in shares)	(53,878)	(121,764)	(95,098)
Forfeited (in shares)		(8,318)	(11,744)
Outstanding at end of period (in shares)	672,578	662,479	632,730
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)	$ 29.06	$ 27.03	$ 21.95
Granted/Vested (in dollars per share)	35.64	30.37	29.32
Delivered (in dollars per share)	23.11	20.31	23.62
Forfeited (in dollars per share)		28.14	24.69
Outstanding at end of period (in dollars per share)	$ 29.54	$ 29.06	$ 27.03
Total Fair Value of Vested Shares
Delivered	$ 1,774	$ 3,751	$ 2,519
Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation costs not yet recognized	$ 280

STOCK-BASED COMPENSATION - ST88

STOCK-BASED COMPENSATION - STOCK OPTION ACTIVITY (Details)	12 Months Ended
	Sep. 30, 2015$ / sharesshares
Shares
Outstanding at beginning of period (in shares) | shares	48,250
Exercised (in shares) | shares	(48,250)
Outstanding at end of period (in shares) | shares	0
Weighted Average Exercise Price
Outstanding at beginning of period (in dollars per share) | $ / shares	$ 15
Exercised (in dollars per share) | $ / shares	15
Outstanding at end of period (in dollars per share) | $ / shares	$ 0

EMPLOYEE BENEFIT PLANS - PENSIO

EMPLOYEE BENEFIT PLANS - PENSION AND OTHER POSTEMPLOYMENT BENEFIT PLANS, NARRATIVE (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2017USD ($)plan	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Number of noncontributory defined benefit retirement plans (in plans) | plan	2
Required number of years of service (more than)	1 year
Years of service and average compensation, basis period for plan benefits	60 months
Long-term real rate of return on assets (as a percent)	5.00%
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	$ 6,049	$ 3,235	$ 5,700
OPEB | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated future employer contributions over the next five years	4,000
OPEB | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated future employer contributions over the next five years	7,000
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer discretionary contributions	0	30,000	$ 0
Employer contributions	$ 74	$ 30,071

EMPLOYEE BENEFIT PLANS - SUMMAR

EMPLOYEE BENEFIT PLANS - SUMMARY OF CHANGE IN FUNDED STATUS AND LIABILITIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Postemployment employee (liability)
Noncurrent	$ (128,888)	$ (141,604)
Pension
Change in Benefit Obligation
Benefit obligation at beginning of year	293,654	255,987
Service cost	8,347	7,591	$ 7,485
Interest cost	9,771	11,342	10,199
Plan participants’ contributions	45	47
Actuarial (gain) loss	(5,995)	26,369
Benefits paid, net of retiree subsidies received	(7,987)	(7,682)
Benefit obligation at end of year	297,835	293,654	255,987
Change in plan assets
Fair value of plan assets at beginning of year	249,875	199,123
Actual return on plan assets	29,736	28,316
Employer contributions	74	30,071
Benefits paid, net of plan participants’ contributions	(7,942)	(7,635)
Fair value of plan assets at end of year	271,743	249,875	199,123
Funded status	(26,092)	(43,779)
Postemployment employee (liability)
Current	(158)	(79)
Noncurrent	(25,934)	(43,700)
Total	(26,092)	(43,779)
OPEB
Change in Benefit Obligation
Benefit obligation at beginning of year	160,393	138,367
Service cost	4,380	4,521	4,253
Interest cost	5,545	6,256	5,739
Plan participants’ contributions	120	104
Actuarial (gain) loss	8,985	15,590
Benefits paid, net of retiree subsidies received	(4,333)	(4,445)
Benefit obligation at end of year	175,090	160,393	138,367
Change in plan assets
Fair value of plan assets at beginning of year	62,035	57,269
Actual return on plan assets	7,953	5,872
Employer contributions	6,049	3,235	5,700
Benefits paid, net of plan participants’ contributions	(4,503)	(4,341)
Fair value of plan assets at end of year	71,534	62,035	$ 57,269
Funded status	(103,556)	(98,358)
Postemployment employee (liability)
Current	(602)	(454)
Noncurrent	(102,954)	(97,904)
Total	$ (103,556)	$ (98,358)

EMPLOYEE BENEFIT PLANS - REGULA

EMPLOYEE BENEFIT PLANS - REGULATORY ASSETS AND AOCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Pension
Amounts amortized to net periodic costs:
Net actuarial (loss)	$ (8,827)	$ (7,281)	$ (6,985)
Prior service (cost) credit	(111)	(111)	(111)
OPEB
Amounts amortized to net periodic costs:
Net actuarial (loss)	(4,370)	(3,274)	(2,943)
Prior service (cost) credit	365	365	364
Regulatory Assets | Pension
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Regulatory Assets, Balance at beginning of period	94,941	86,960
Amounts arising during the period, Net actuarial loss (gain)	(9,429)	13,696
Amounts amortized to net periodic costs:
Net actuarial (loss)	(6,799)	(5,607)
Prior service (cost) credit	(108)	(108)
Regulatory Assets, Balance at end of period	78,605	94,941	86,960
Regulatory Assets | OPEB
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Regulatory Assets, Balance at beginning of period	59,147	50,737
Amounts arising during the period, Net actuarial loss (gain)	5,211	11,274
Amounts amortized to net periodic costs:
Net actuarial (loss)	(4,209)	(3,175)
Prior service (cost) credit	311	311
Regulatory Assets, Balance at end of period	60,460	59,147	50,737
Accumulated Other Comprehensive Income (Loss) | Pension
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss), Balance at beginning of period	28,436	25,640
Amounts arising during the period, Net actuarial loss (gain)	(6,990)	4,475
Amounts amortized to net periodic costs:
Net actuarial (loss)	(2,028)	(1,676)
Prior service (cost) credit	(3)	(3)
Accumulated Other Comprehensive Income (Loss), Balance at end of period	19,415	28,436	25,640
Accumulated Other Comprehensive Income (Loss) | OPEB
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss), Balance at beginning of period	4,486	1,242
Amounts arising during the period, Net actuarial loss (gain)	587	3,289
Amounts amortized to net periodic costs:
Net actuarial (loss)	(160)	(99)
Prior service (cost) credit	54	54
Accumulated Other Comprehensive Income (Loss), Balance at end of period	$ 4,967	$ 4,486	$ 1,242

EMPLOYEE BENEFIT PLANS - AMOUNT

EMPLOYEE BENEFIT PLANS - AMOUNTS NOT YET RECOGNIZED AS NET PERIODIC COST (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Regulatory Assets | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss	$ 77,930	$ 94,158
Prior service cost (credit)	675	783
Regulatory Assets, Total	78,605	94,941	$ 86,960
Regulatory Assets | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss	61,563	60,561
Prior service cost (credit)	(1,103)	(1,414)
Regulatory Assets, Total	60,460	59,147	50,737
Accumulated Other Comprehensive Income (Loss) | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss	19,414	28,432
Prior service cost (credit)	1	4
Accumulated Other Comprehensive Income (Loss), Total	19,415	28,436	25,640
Accumulated Other Comprehensive Income (Loss) | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss	5,113	4,686
Prior service cost (credit)	(146)	(200)
Accumulated Other Comprehensive Income (Loss), Total	$ 4,967	$ 4,486	$ 1,242

EMPLOYEE BENEFIT PLANS - AMOU93

EMPLOYEE BENEFIT PLANS - AMOUNTS EXPECTED TO BE RECOGNIZED IN NET PERIODIC BENEFIT COST (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2017USD ($)
Pension
Regulatory Assets
Net actuarial loss	$ 6,177
Prior service cost (credit)	105
Total	6,282
Accumulated Other Comprehensive Income (Loss)
Net actuarial loss	1,360
Prior service cost (credit)	1
Total	1,361
OPEB
Regulatory Assets
Net actuarial loss	4,464
Prior service cost (credit)	(311)
Total	4,153
Accumulated Other Comprehensive Income (Loss)
Net actuarial loss	196
Prior service cost (credit)	(53)
Total	$ 143

EMPLOYEE BENEFIT PLANS - ACCUMU

EMPLOYEE BENEFIT PLANS - ACCUMULATED BENEFIT OBLIGATION (Details) - Pension - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 297,835	$ 293,654
Accumulated benefit obligation	258,514	252,077
Fair value of plan assets	$ 271,743	$ 249,875

EMPLOYEE BENEFIT PLANS - COMPON

EMPLOYEE BENEFIT PLANS - COMPONENTS OF NET PERIODIC COST (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 8,347	$ 7,591	$ 7,485
Interest cost	9,771	11,342	10,199
Expected return on plan assets	(19,313)	(20,118)	(17,090)
Recognized actuarial loss	8,827	7,281	6,985
Prior service cost (credit) amortization	111	111	111
Net periodic benefit cost recognized as expense	7,743	6,207	7,690
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	4,380	4,521	4,253
Interest cost	5,545	6,256	5,739
Expected return on plan assets	(4,767)	(4,845)	(4,977)
Recognized actuarial loss	4,370	3,274	2,943
Prior service cost (credit) amortization	(365)	(365)	(364)
Net periodic benefit cost recognized as expense	$ 9,163	$ 8,841	$ 7,594

EMPLOYEE BENEFIT PLANS - WEIGHT

EMPLOYEE BENEFIT PLANS - WEIGHTED AVERAGE ASSUMPTIONS (Details)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Pension
Benefit costs:
Discount rate		4.50%	4.55%
Expected asset return	7.75%	8.75%	8.75%
Compensation increase			3.25%
Obligations:
Discount rate	4.03%		4.50%
Pension | Represented
Benefit costs:
Discount rate	3.96%
Compensation increase	3.25%	3.25%
Obligations:
Discount rate		3.96%
Compensation increase	3.25%	3.25%	3.25%
Pension | Nonrepresented
Benefit costs:
Discount rate	3.94%
Compensation increase	3.50%	3.50%
Obligations:
Discount rate		3.94%
Compensation increase	3.50%	3.50%	3.50%
OPEB
Benefit costs:
Discount rate			4.55%
Expected asset return	7.75%	8.75%	8.75%
Compensation increase		3.50%	3.50%
Obligations:
Compensation increase		3.50%	3.50%
OPEB | Represented
Benefit costs:
Discount rate	4.08%	4.60%
Compensation increase	3.25%
Obligations:
Discount rate	4.12%	4.08%	4.60%
Compensation increase	3.25%
OPEB | Nonrepresented
Benefit costs:
Discount rate	4.01%	4.55%
Compensation increase	3.50%
Obligations:
Discount rate	4.08%	4.01%	4.55%
Compensation increase	3.50%

EMPLOYEE BENEFIT PLANS - ASSUME

EMPLOYEE BENEFIT PLANS - ASSUMED HCCTR (Details) - OPEB - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
HCCTR	8.30%	8.50%	6.70%
Ultimate HCCTR	4.50%	4.50%	4.80%
Year ultimate HCCTR reached	2,025	2,025	2,022
Effect of a 1 percentage point increase in the HCCTR on:
Year-end benefit obligation	$ 32,019	$ 28,803	$ 26,025
Total service and interest cost	2,468	2,331	2,026
Effect of a 1 percentage point decrease in the HCCTR on:
Year-end benefit obligation	(25,466)	(22,862)	(20,427)
Total service and interest costs	$ (1,909)	$ (1,801)	$ (1,593)

EMPLOYEE BENEFIT PLANS - MIX AN

EMPLOYEE BENEFIT PLANS - MIX AND TARGETED ALLOCATION (Details)	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	100.00%
Assets	100.00%	100.00%
U.S. equity securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	40.00%
Assets	39.00%	38.00%
International equity securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	20.00%
Assets	21.00%	20.00%
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	40.00%
Assets	40.00%	42.00%

EMPLOYEE BENEFIT PLANS - EXPECT

EMPLOYEE BENEFIT PLANS - EXPECTED BENEFIT PAYMENTS (Details) $ in Thousands	Sep. 30, 2017USD ($)
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,018	$ 8,928
2,019	9,712
2,020	10,549
2,021	11,502
2,022	12,469
2023 - 2027	79,081
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,018	4,230
2,019	4,807
2,020	5,435
2,021	6,061
2,022	6,755
2023 - 2027	$ 43,267

EMPLOYEE BENEFIT PLANS - ESTIMA

EMPLOYEE BENEFIT PLANS - ESTIMATED SUBSIDY PAYMENTS (Details) $ in Thousands	Sep. 30, 2017USD ($)
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt [Abstract]
2,018	$ 262
2,019	283
2,020	311
2,021	342
2,022	373
2023 - 2027	$ 2,574

EMPLOYEE BENEFIT PLANS - FAIR V

EMPLOYEE BENEFIT PLANS - FAIR VALUE (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Pension
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	$ 271,743	$ 249,875	$ 199,123
OPEB
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	71,534	62,035	$ 57,269
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	271,743	249,875
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Money market funds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Large Cap Index
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	88,321	78,306
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Extended Market Index
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	16,329	16,250
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | International Stock
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	56,446	50,702
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Emerging Markets
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	13,516	12,906
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Core Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Opportunistic Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Ultra Short Duration
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | High Yield Bond Fund
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	26,540	25,976
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Long Duration Fund
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	70,591	65,735
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	71,534	62,035
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Money market funds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	11	9
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Large Cap Index
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	23,986	19,532
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Extended Market Index
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	4,409	4,114
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | International Stock
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	15,000	12,997
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Emerging Markets
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	3,551	3,294
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Core Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	8,082	7,177
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Opportunistic Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	4,744	4,155
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Ultra Short Duration
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	4,673	4,082
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | High Yield Bond Fund
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	7,078	6,675
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Long Duration Fund
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	$ 0	$ 0

EMPLOYEE BENEFIT PLANS - DEFINE

EMPLOYEE BENEFIT PLANS - DEFINED CONTRIBUTION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined contribution, company match of employee contribution	65.00%
Defined contribution plan, maximum employer contribution by percentage of employee salary	6.00%
Defined contribution plan, cost recognized	$ 2,900	$ 2,800	$ 2,600
Deferred compensation arrangement with individual, employer contribution	$ 781	$ 571	$ 461
NJRHS | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan, employer contribution for employees not qualifying for the defined benefit plan	3.00%
NJRHS | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan, employer contribution for employees not qualifying for the defined benefit plan	4.00%

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Revisions in estimated cash flows		$ 5,300
Estimated Accretion
2,018	$ 1,644
2,019	1,718
2,020	1,795
2,021	1,877
2,022	1,960
Total	8,994
NJNG
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at period beginning	23,521	16,773
Accretion	1,304	1,048
Additions	729	783
Revisions in estimated cash flows	(245)	5,320
Retirements	(484)	(403)
Balance at period end	24,825	23,521
NJRCEV
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at period beginning	4,858	2,372
Accretion	245	158
Additions	1,492	2,328
Revisions in estimated cash flows	0	0
Retirements	0	0
Balance at period end	$ 6,595	$ 4,858

INCOME TAXES - INCOME TAX RECON

INCOME TAXES - INCOME TAX RECONCILIATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Federal statutory rate	35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory income tax expense	$ 52,643	$ 54,321	$ 84,239
Change resulting from:
State income taxes	8,222	6,044	8,233
Cost of removal of assets placed in service prior to1981	(6,886)	(5,738)	(5,149)
Investment/production tax credits	(34,526)	(32,491)	(30,096)
Basis adjustment of solar assets due to ITC	4,256	4,453	4,861
AFUDC equity	(2,624)	(1,531)	(1,339)
Other	(2,742)	(1,528)	(1,025)
Income tax provision	$ 18,343	$ 23,530	$ 59,724
Effective income tax rate	12.20%	15.20%	24.80%

INCOME TAXES - COMPONENTS OF IN

INCOME TAXES - COMPONENTS OF INCOME TAX PROVISION (BENEFIT) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Current:
Federal	$ (16,023)	$ (23,597)	$ 20,492
State	2,470	(2,209)	5,473
Deferred:
Federal	54,965	70,386	56,480
State	11,457	11,441	7,375
Investment/production tax credits	(34,526)	(32,491)	(30,096)
Income tax provision	$ 18,343	$ 23,530	$ 59,724

INCOME TAXES - DEFERRED TAX ASS

INCOME TAXES - DEFERRED TAX ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Deferred tax assets
Investment tax credits	$ 111,642	$ 76,517
Deferred service contract revenue	3,877	3,601
Incentive compensation	6,260	8,128
Fair value of derivatives	11,519	1,179
Federal net operating losses	28,487	27,541
State net operating losses	23,597	18,113
Overrecovered gas costs	0	3,831
Other	13,845	11,668
Total deferred tax assets	199,227	150,578
Deferred tax liabilities
Property related items	(620,850)	(532,027)
Remediation costs	(11,625)	(7,928)
Equity investments	(38,370)	(37,740)
Postemployment benefits	(6,855)	(7,902)
Conservation incentive plan	(7,195)	(14,953)
Underrecovered gas costs	(4,035)	0
Other	(16,643)	(14,610)
Total deferred tax liabilities	(705,573)	(615,160)
Total net deferred tax liabilities	(506,346)	(464,582)
Natural Gas Distribution
Deferred tax liabilities
Tax credit carryforward	2,300	2,500
Clean Energy Ventures
Deferred tax liabilities
Tax credit carryforward	$ 109,300	$ 74,000

INCOME TAXES - INCOME TAX CARRY

INCOME TAXES - INCOME TAX CARRYFORWARDS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating Loss Carryforwards [Line Items]
Tax benefit associated with the loss carryforwards	$ 23,597	$ 18,113
Tax credit carryforward, expiration period	20 years
Deferred tax asset, loss carryforwards	$ 52,100
Natural Gas Distribution
Operating Loss Carryforwards [Line Items]
Tax credit carryforward	2,300	2,500
Clean Energy Ventures
Operating Loss Carryforwards [Line Items]
Tax credit carryforward	109,300	74,000
Domestic Tax Authority
Operating Loss Carryforwards [Line Items]
Net operating losses	125,300	78,700
Income taxes receivable	15,400
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Net operating losses	471,700	310,600
Deferred tax asset, loss carryforwards	161,397
State and Local Jurisdiction | Fiscal years 2018 - 2022
Operating Loss Carryforwards [Line Items]
Deferred tax asset, loss carryforwards	313
State and Local Jurisdiction | Fiscal years 2023 - 2027
Operating Loss Carryforwards [Line Items]
Deferred tax asset, loss carryforwards	1,051
State and Local Jurisdiction | Fiscal years 2028 - 2032
Operating Loss Carryforwards [Line Items]
Deferred tax asset, loss carryforwards	796
State and Local Jurisdiction | Fiscal years 2033 - 2037
Operating Loss Carryforwards [Line Items]
Deferred tax asset, loss carryforwards	$ 159,237
Minimum | State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Net operating losses, life	7 years
Maximum | State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Net operating losses, life	20 years
MONTANA
Operating Loss Carryforwards [Line Items]
Valuation allowance	$ 1,000
NEW JERSEY
Operating Loss Carryforwards [Line Items]
Valuation allowance		$ 262

COMMITMENTS AND CONTINGENT L108

COMMITMENTS AND CONTINGENT LIABILITIES - SCHEDULE OF FUTURE COMMITTED EXPENSES (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2017USD ($)
Long-term Purchase Commitment [Line Items]
Current charges recoverable through BGSS	$ 98,600
Purchase Obligation, Fiscal Year Maturity [Abstract]
2,018	534,913
2,019	339,742
2,020	178,178
2,021	141,612
2,022	123,149
Thereafter	668,441
Energy Services
Purchase Obligation, Fiscal Year Maturity [Abstract]
2,018	385,277
2,019	169,867
2,020	59,424
2,021	42,150
2,022	25,486
Thereafter	22,057
Energy Services | Natural gas purchases
Purchase Obligation, Fiscal Year Maturity [Abstract]
2,018	296,491
2,019	114,817
2,020	22,270
2,021	11,488
2,022	0
Thereafter	0
Energy Services | Storage demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2,018	32,870
2,019	22,638
2,020	13,350
2,021	9,041
2,022	5,833
Thereafter	2,746
Energy Services | Pipeline demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2,018	55,916
2,019	32,412
2,020	23,804
2,021	21,621
2,022	19,653
Thereafter	19,311
Natural Gas Distribution
Purchase Obligation, Fiscal Year Maturity [Abstract]
2,018	149,636
2,019	169,875
2,020	118,754
2,021	99,462
2,022	97,663
Thereafter	646,384
Natural Gas Distribution | Natural gas purchases
Purchase Obligation, Fiscal Year Maturity [Abstract]
2,018	51,050
2,019	41,156
2,020	2,514
2,021	0
2,022	0
Thereafter	0
Natural Gas Distribution | Storage demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2,018	30,042
2,019	26,628
2,020	15,331
2,021	8,231
2,022	7,804
Thereafter	3,903
Natural Gas Distribution | Pipeline demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2,018	68,544
2,019	102,091
2,020	100,909
2,021	91,231
2,022	89,859
Thereafter	$ 642,481
Minimum
Long-term Purchase Commitment [Line Items]
Storage and pipeline capacity, fixed period	1 year
Maximum
Long-term Purchase Commitment [Line Items]
Storage and pipeline capacity, fixed period	10 years

COMMITMENTS AND CONTINGENT L109

COMMITMENTS AND CONTINGENT LIABILITIES - CAPITAL EXPENDITURES (Details) $ in Millions	Sep. 30, 2017USD ($)
Commitments and Contingencies Disclosure [Abstract]
Operating leases, future minimum payments due, next five years (not more than)	$ 2.6
Operating leases, future minimum payments, due thereafter	$ 38.3

COMMITMENTS AND CONTINGENT L110

COMMITMENTS AND CONTINGENT LIABILITIES - GUARANTEES (Details) $ in Millions	Sep. 30, 2017USD ($)
Guarantee Obligations
Guarantor Obligations [Line Items]
Loss contingency, estimate of possible loss	$ 331.4

COMMITMENTS AND CONTINGENT L111

COMMITMENTS AND CONTINGENT LIABILITIES - LEGAL PROCEEDINGS (Details)	Apr. 01, 2018USD ($)	Sep. 30, 2017USD ($)site	Sep. 30, 2016USD ($)
Loss Contingencies [Line Items]
Number of manufactured gas plant sites (in sites) | site		5
Recovery period		7 years
Regulatory assets		$ 375,919,000	$ 441,294,000
Minimum
Loss Contingencies [Line Items]
Litigation settlement, gross		117,600,000
Loss contingency, estimate of possible loss		600,000
Maximum
Loss Contingencies [Line Items]
Litigation settlement, gross		205,200,000
Loss contingency, estimate of possible loss		3,200,000
Environmental remediation costs, Expended, net of recoveries
Loss Contingencies [Line Items]
Regulatory assets		28,547,000	19,595,000
Environmental remediation costs, Liability for future expenditures
Loss Contingencies [Line Items]
Regulatory assets		149,000,000	$ 172,000,000
RAC
Loss Contingencies [Line Items]
Approved rate, amount		$ 9,400,000
Scenario, Forecast | RAC
Loss Contingencies [Line Items]
Approved rate, amount	$ 7,000,000

BUSINESS SEGMENT AND OTHER O112

BUSINESS SEGMENT AND OTHER OPERATIONS DATA - RECONCILIATION OF SEGMENT INCOME TO CONSOLIDATED (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Segment Reporting Information [Line Items]
Utility									$ 695,637	$ 594,346	$ 781,970
Nonutility									1,572,980	1,286,559	1,952,017
Total operating revenues	$ 536,520	$ 457,523	$ 733,546	$ 541,028	$ 469,241	$ 393,213	$ 574,193	$ 444,258	2,268,617	1,880,905	2,733,987
Depreciation and amortization									81,841	72,748	61,399
Interest income									2,034	128	580
Interest expense, net of capitalized interest									44,886	31,044	27,721
Income tax (benefit) provision									18,343	23,530	59,724
Equity in earnings of affiliates									13,813	9,515	13,409
Net financial earnings									149,392	138,085	151,503
Capital expenditures									328,083	356,092	320,086
Investments in equity investees									$ 27,070	$ 11,176	$ 5,780
CANADA
Segment Reporting Information [Line Items]
Percentage to total operating revenues									0.80%	2.00%	3.70%
Operating Segments
Segment Reporting Information [Line Items]
Total operating revenues									$ 2,222,712	$ 1,845,139	$ 2,748,790
Depreciation and amortization									81,250	71,893	60,478
Interest income									2,756	1,737	1,777
Interest expense, net of capitalized interest									45,788	31,616	28,095
Income tax (benefit) provision									14,129	21,519	58,468
Net financial earnings									143,214	135,837	148,290
Capital expenditures									325,649	354,196	319,877
Operating Segments | Natural Gas Distribution
Segment Reporting Information [Line Items]
Utility									695,637	594,346	781,970
Depreciation and amortization									49,347	47,828	43,085
Interest income									555	115	336
Interest expense, net of capitalized interest									25,818	19,930	18,534
Income tax (benefit) provision									43,485	34,951	39,544
Net financial earnings									86,930	76,104	76,287
Capital expenditures									176,249	205,133	168,875
Operating Segments | Clean Energy Ventures
Segment Reporting Information [Line Items]
Nonutility									64,394	53,540	32,513
Depreciation and amortization									31,834	23,971	17,297
Interest income									0	0	26
Interest expense, net of capitalized interest									16,263	10,304	7,635
Income tax (benefit) provision									(31,161)	(26,592)	(26,968)
Net financial earnings									24,873	28,393	20,101
Capital expenditures									149,400	149,063	151,002
Operating Segments | Energy Services
Segment Reporting Information [Line Items]
Nonutility									1,462,365	1,187,754	1,872,781
Depreciation and amortization									63	88	90
Interest income									6	98	438
Interest expense, net of capitalized interest									2,747	1,095	1,209
Income tax (benefit) provision									(4,015)	7,030	39,043
Net financial earnings									18,554	21,934	42,122
Operating Segments | Midstream
Segment Reporting Information [Line Items]
Depreciation and amortization									6	6	6
Interest income									2,195	1,524	977
Interest expense, net of capitalized interest									960	287	717
Income tax (benefit) provision									5,820	6,130	6,849
Equity in earnings of affiliates									17,797	13,936	17,487
Net financial earnings									12,857	9,406	9,780
Investments in equity investees									27,070	11,176	5,780
Intercompany
Segment Reporting Information [Line Items]
Nonutility									3,370	3,232	1,980
Intercompany | Energy Services
Segment Reporting Information [Line Items]
Nonutility									316	9,499	61,526
Home Services and Other
Segment Reporting Information [Line Items]
Nonutility									46,221	45,265	46,723
Depreciation and amortization									798	981	952
Interest income									590	397	217
Interest expense, net of capitalized interest									410	252	49
Income tax (benefit) provision									3,857	1,387	1,551
Net financial earnings									6,811	2,882	3,420
Capital expenditures									2,434	1,896	209
Eliminations
Segment Reporting Information [Line Items]
Nonutility									(3,686)	(12,731)	(63,506)
Depreciation and amortization									(207)	(126)	(31)
Interest income									(1,312)	(2,006)	(1,414)
Interest expense, net of capitalized interest									(1,312)	(824)	(423)
Income tax (benefit) provision									357	624	(295)
Equity in earnings of affiliates									(3,984)	(4,421)	(4,078)
Net financial earnings									$ (633)	$ (634)	$ (207)

BUSINESS SEGMENT AND OTHER O113

BUSINESS SEGMENT AND OTHER OPERATIONS DATA - NET FINANCIAL EARNINGS LOSS RECONCILIATION (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Segment Reporting [Abstract]
Consolidated net financial earnings									$ 149,392	$ 138,085	$ 151,503
Less:
Unrealized (gain) loss on derivative instruments and related transactions									(11,241)	46,883	(38,681)
Unrealized Gain (Loss) on Derivatives and Commodity Contracts, Tax									4,062	(17,018)	14,391
Effects of economic hedging related to natural gas inventory									38,470	(36,816)	(8,225)
Tax effect									(13,964)	13,364	3,058
NET INCOME	$ (36,523)	$ 18,957	$ 114,702	$ 34,929	$ 25,400	$ (17,363)	$ 73,354	$ 50,281	$ 132,065	$ 131,672	$ 180,960

BUSINESS SEGMENT AND OTHER O114

BUSINESS SEGMENT AND OTHER OPERATIONS DATA - RECONCILIATION OF SEGMENT ASSETS TO CONSOLIDATED (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 3,928,507	$ 3,718,570	$ 3,284,357
Operating Segments
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	3,922,001	3,696,982	3,252,206
Operating Segments | Natural Gas Distribution
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	2,519,578	2,517,401	2,305,293
Operating Segments | Clean Energy Ventures
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	771,340	665,696	504,885
Operating Segments | Energy Services
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	398,277	327,626	260,021
Operating Segments | Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	232,806	186,259	182,007
Home Services and Other
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	114,801	109,487	88,880
Eliminations
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ (108,295)	$ (87,899)	$ (56,729)

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) $ in Thousands	Apr. 01, 2010USD ($)Bcf	Sep. 30, 2017USD ($)Bcf / dcontract	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Related Party Transaction [Line Items]
Demand fees recognized pertaining to related party agreement		$ 8,340	$ 8,351	$ 7,657
Due to related parties		$ 1,152	1,150
Number of asset management agreements | contract		4
NJNG to NJRES Affiliate
Related Party Transaction [Line Items]
Asset management agreement, period	10 years
NJNG to Steckman RIdge Affiliate
Related Party Transaction [Line Items]
Natural gas sold at cost under asset management agreement (in Bcf) | Bcf	3
Approximate annual demand fees under agreement	$ 9,300
Demand fees recognized pertaining to related party agreement		$ 5,590	5,562	5,700
Due to related parties		775	775
NJRES to Steckman Ridge Affiliate
Related Party Transaction [Line Items]
Demand fees recognized pertaining to related party agreement		2,750	2,789	$ 1,957
Due to related parties		$ 377	$ 375
NJNG to PennEast Affiliate
Related Party Transaction [Line Items]
Transportation precedent agreement, period		15 years
Transportation capacity under precedent agreement from NJNG with PennEast (in Bcf per day) | Bcf / d		0.18

SELECTED QUARTERLY FINANCIAL116

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2017		Sep. 30, 2016		Sep. 30, 2015
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 536,520	$ 457,523	$ 733,546	$ 541,028	$ 469,241	$ 393,213	$ 574,193	$ 444,258	$ 2,268,617		$ 1,880,905		$ 2,733,987
Operating income (loss)	(32,051)	17,967	139,653	41,475	42,480	(28,329)	93,933	59,451	167,044		167,535		248,451
Net income (loss)	$ (36,523)	$ 18,957	$ 114,702	$ 34,929	$ 25,400	$ (17,363)	$ 73,354	$ 50,281	$ 132,065		$ 131,672		$ 180,960
Earnings (loss) per share
Basic (in dollars per share)	$ (0.42)	$ 0.22	$ 1.33	$ 0.41	$ 0.30	$ (0.20)	$ 0.85	$ 0.59	$ 1.53		$ 1.53		$ 2.12
Diluted (in dollars per share)	$ (0.42)	$ 0.22	$ 1.32	$ 0.40	$ 0.29	$ (0.20)	$ 0.84	$ 0.58	$ 1.52	[1]	$ 1.52	[1]	$ 2.10	[1]
[1]	There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2017, 2016 and 2015.

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) $ in Thousands	Oct. 27, 2017USD ($)mi	Nov. 21, 2017USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Subsequent Event [Line Items]
Initial payment			$ 55,661	$ 0	$ 0
Adelphia | Talen's Membership Interests In IEC | Subsequent Event
Subsequent Event [Line Items]
Base purchase price	$ 166,000
Initial payment		$ 10,000
Additional contingent consideration (up to $23 million)	$ 23,000
Pipeline length owned | mi	84

VALUATION AND QUALIFYING ACC118

VALUATION AND QUALIFYING ACCOUNTS (Details) - Allowance for doubtful accounts - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Movement in Valuation Allowances and Reserves [Roll Forward]
BEGINNING BALANCE	$ 4,865	$ 5,189	$ 5,357
ADDITIONS CHARGED TO EXPENSE	2,023	1,616	2,859
OTHER	(1,707)	(1,940)	(3,027)
ENDING BALANCE	$ 5,181	$ 4,865	$ 5,189