New Jersey Resources (NJR) 10-K 21 Nov 23 2023 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Sep. 30, 2023	Nov. 17, 2023	Mar. 31, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Sep. 30, 2023
Current Fiscal Year End Date	--09-30
Document Transition Report	false
Entity File Number	001-08359
Entity Registrant Name	NEW JERSEY RESOURCES CORPORATION
Entity Incorporation, State or Country Code	NJ
Entity Tax Identification Number	22-2376465
Entity Address, Address Line One	1415 Wyckoff Road,
Entity Address, City or Town	Wall,
Entity Address, State or Province	NJ
Entity Address, Postal Zip Code	07719
City Area Code	(732)
Local Phone Number	938‑1000
Title of 12(b) Security	Common Stock ‑ $2.50 Par Value
Trading Symbol	NJR
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 5,138,493,161
Entity Common Stock, Shares Outstanding		97,707,564
Documents Incorporated by Reference	Portions of the registrant’s definitive Proxy Statement for the Annual Meeting of Shareowners (Proxy Statement) to be held on January 24, 2024, are incorporated by reference into Part I and Part III of this report.
Entity Central Index Key	0000356309
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information

Audit Information	12 Months Ended
	Sep. 30, 2023
Audit Information [Abstract]
Auditor Firm ID	34
Auditor Name	Deloitte & Touche LLP
Auditor Location	Morristown, New Jersey

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
OPERATING REVENUES
Utility	$ 1,011,284	$ 1,127,417	$ 731,459
Nonutility	951,710	1,778,562	1,425,154
Total operating revenues	1,962,994	2,905,979	2,156,613
Natural gas purchases:
Related parties	7,206	7,395	7,013
Operation and maintenance	373,568	361,866	366,905
Regulatory rider expenses	50,542	59,437	38,304
Depreciation and amortization	152,941	129,249	111,387
Total operating expenses	1,555,994	2,499,504	1,868,263
OPERATING INCOME	407,000	406,475	288,350
Other income, net	26,083	22,295	24,597
Interest expense, net of capitalized interest	123,014	85,830	78,559
INCOME BEFORE INCOME TAXES AND EQUITY IN EARNINGS OF AFFILIATES	310,069	342,940	234,388
Income tax provision	49,275	76,195	33,286
Equity in earnings (loss) of affiliates	3,930	8,177	(83,212)
NET INCOME	$ 264,724	$ 274,922	$ 117,890
EARNINGS PER COMMON SHARE
Basic (usd per share)	$ 2.73	$ 2.86	$ 1.23
Diluted (usd per share)	$ 2.71	$ 2.85	$ 1.22
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic (in shares)	97,028	96,100	96,227
Diluted (in shares)	97,627	96,488	96,560
Regulated
Natural gas purchases:
Gas purchases - Utility and Nonutility	$ 416,158	$ 547,901	$ 247,734
Unregulated
Natural gas purchases:
Gas purchases - Utility and Nonutility	$ 555,579	$ 1,393,656	$ 1,096,920

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Statement of Comprehensive Income [Abstract]
Net income	$ 264,724	$ 274,922	$ 117,890
Other comprehensive (loss) income, net of tax
Reclassifications of losses to net income on derivatives designated as hedging instruments, net of tax of $(317), $(317) and $(350), respectively	1,053	1,054	1,021
Adjustment to postemployment benefit obligation, net of tax of $1,873, $(8,657) and $(2,575), respectively	(6,186)	28,648	8,766
Other comprehensive (loss) income, net of tax	(5,133)	29,702	9,787
Comprehensive income	$ 259,591	$ 304,624	$ 127,677

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Statement of Comprehensive Income [Abstract]
Tax on reclassifications of losses to net income on derivatives	$ (317)	$ (317)	$ (350)
Tax on adjustment to postemployment benefit obligation	$ 1,873	$ (8,657)	$ (2,575)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 264,724	$ 274,922	$ 117,890
Adjustments to reconcile net income to cash flows from operating activities
Unrealized (gain) loss on derivative instruments	(38,081)	(59,906)	54,203
Impairment of equity method investment	0	0	92,000
Depreciation and amortization	152,941	129,249	111,387
Amortization of acquired wholesale energy contracts	2,271	2,561	4,604
Allowance for equity used during construction	(7,137)	(11,243)	(20,303)
Allowance for doubtful accounts	1,570	2,401	18,986
Non-cash lease expense	3,708	4,850	3,920
Deferred income taxes	30,462	81,659	23,796
Equivalent value of ITCs recognized on equipment financing	(6,986)	(7,542)	(6,482)
Manufactured gas plant remediation costs	(9,571)	(17,538)	(17,532)
Equity in earnings, net of distributions received from equity investees	0	0	(3,046)
Cost of removal - asset retirement obligations	(1,526)	(1,289)	(1,129)
Contributions to postemployment benefit plans	(4,706)	(6,785)	(7,669)
Taxes related to stock-based compensation	(588)	(144)	(159)
Changes in:
Components of working capital	61,525	(77,687)	10,254
Other noncurrent assets	(97,753)	(38,424)	13,715
Other noncurrent liabilities	128,140	48,396	(3,481)
Cash flows from operating activities	478,993	323,480	390,954
Expenditures for:
Cost of removal	(40,555)	(39,293)	(50,316)
Distribution from equity investees in excess of equity in earnings	2,294	2,336	3,183
Investments in equity investees, net of return of capital	0	5,479
Investments in equity investees, net of return of capital			(690)
Cash flows used in investing activities	(538,625)	(590,613)	(622,117)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	225,000	360,000	0
Payments of long-term debt	(71,934)	(68,343)	(18,007)
Proceeds from term loan	0	150,000	0
Payments of term loan	(150,000)	0	0
(Payments of) proceeds from short-term debt, net	(21,850)	(103,350)	251,950
Proceeds from sale leaseback transactions - solar	167,790	24,071	17,673
Proceeds from sale leaseback transactions - natural gas meters	8,441	17,300	0
Payments of common stock dividends	(150,973)	(127,704)	(116,960)
Cash settlement of equity forward agreement	0	0	(2,823)
Proceeds from waiver discount issuance of common stock	42,807	0	0
Proceeds from issuance of common stock - DRP	14,993	14,745	15,105
Purchases of treasury stock	0	0	(27,217)
Tax withholding payments related to net settled stock compensation	(4,577)	(4,177)	(1,938)
Cash flows from financing activities	59,697	262,542	117,783
Change in cash, cash equivalents and restricted cash	65	(4,591)	(113,380)
Cash, cash equivalents and restricted cash at beginning of period	1,452	6,043	119,423
Cash, cash equivalents and restricted cash at end of period	1,517	1,452	6,043
CHANGES IN COMPONENTS OF WORKING CAPITAL
Receivables	112,628	(16,658)	(81,366)
Inventories	67,445	(80,801)	(25,257)
Recovery of natural gas costs	(14,427)	1,037	(13,124)
Natural gas purchases payable	(183,772)	66,352	72,752
Natural gas purchases payable - related parties	8	(10)	70
Deferred revenue	934	33,802	(1,763)
Accounts payable and other	7,537	(34,259)	31,826
Prepaid expenses	(1,169)	(406)	(1,527)
Prepaid and accrued taxes	16,415	(1,516)	(3,449)
Restricted broker margin accounts	46,364	(51,165)	28,013
Customers’ credit balances and deposits	11,664	660	6,652
Other current assets (liabilities)	(2,102)	5,277	(2,573)
Total	61,525	(77,687)	10,254
Cash paid for:
Interest (net of amounts capitalized)	108,194	84,375	78,650
Income taxes	4,282	4,252	6,381
Accrued capital expenditures	25,867	34,674	64,626
Utility plant
Expenditures for:
Payments to acquire PP&E	(350,304)	(259,081)	(376,312)
Solar equipment
Expenditures for:
Payments to acquire PP&E	(107,303)	(146,676)	(87,852)
Storage and transportation and other
Expenditures for:
Payments to acquire PP&E	$ (42,757)	$ (153,378)	$ (110,130)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
PROPERTY, PLANT AND EQUIPMENT
Utility plant, at cost	$ 3,843,037	$ 3,576,691
Construction work in progress	237,428	162,087
Nonutility plant and equipment, at cost	1,767,306	1,577,259
Construction work in progress	142,768	199,679
Total property, plant and equipment	5,990,539	5,515,716
Accumulated depreciation and amortization, utility plant	(714,087)	(659,737)
Accumulated depreciation and amortization, nonutility plant and equipment	(254,397)	(206,053)
Property, plant and equipment, net	5,022,055	4,649,926
CURRENT ASSETS
Cash and cash equivalents	954	1,107
Customer accounts receivable:
Billed	97,540	222,297
Unbilled revenues	19,100	13,769
Allowance for doubtful accounts	(11,036)	(19,379)
Regulatory assets	73,587	40,086
Natural gas in storage, at average cost	199,501	273,644
Materials and supplies, at average cost	27,022	20,324
Prepaid expenses	9,741	8,572
Prepaid taxes	43,046	54,501
Derivatives, at fair value	30,755	24,635
Restricted broker margin accounts	20,796	94,261
Other current assets	21,071	22,270
Total current assets	532,077	756,087
NONCURRENT ASSETS
Investments in equity method investees	104,134	106,571
Regulatory assets	584,830	500,666
Operating lease assets	175,740	168,520
Derivatives, at fair value	1,564	6,385
Intangible assets, net	77	2,348
Software costs	8,375	6,120
Deferred income taxes	28,383	2,928
Postemployment employee benefit assets	18,684	4,388
Other noncurrent assets	61,577	57,477
Total noncurrent assets	983,364	855,403
Total assets	6,537,496	6,261,416
CAPITALIZATION
Common stock, $2.50 par value; authorized 150,000,000 shares; outstanding shares September 30, 2023 — 97,584,455; September 30, 2022 — 96,249,859	243,458	241,616
Premium on common stock	558,654	519,697
Accumulated other comprehensive loss, net of tax	(9,959)	(4,826)
Treasury stock at cost and other; shares September 30, 2023 — 13,041; September 30, 2022 — 611,045	20,748	(6,805)
Retained earnings	1,177,834	1,067,528
Common stock equity	1,990,735	1,817,210
Long-term debt	2,768,017	2,485,402
Total capitalization	4,758,752	4,302,612
CURRENT LIABILITIES
Current maturities of long-term debt	116,155	75,069
Short-term debt	252,100	423,950
Natural gas purchases payable	51,277	235,049
Deferred revenue	61,404	35,547
Accounts payable and other	151,790	156,580
Dividends payable	40,981	37,534
Accrued taxes	10,090	5,130
Regulatory liabilities	32,287	31,090
New Jersey Clean Energy Program	15,804	15,697
Derivatives, at fair value	16,145	49,848
Restricted broker margin accounts	8,029	0
Operating lease liabilities	4,772	4,562
Customers’ credit balances and deposits	44,910	33,246
Current liabilities	806,603	1,104,153
NONCURRENT LIABILITIES
Deferred income taxes	285,427	238,928
Deferred investment tax credits	2,434	2,710
Deferred revenue	659	753
Derivatives, at fair value	7,967	14,191
Manufactured gas plant remediation	169,390	127,060
Postemployment employee benefit liabilities	102,528	82,867
Regulatory liabilities	180,458	185,634
Operating lease liabilities	148,023	138,382
Asset retirement obligation	61,993	55,035
Other noncurrent liabilities	13,262	9,091
Total noncurrent liabilities	972,141	854,651
Commitments and contingent liabilities (Note 14)
Total capitalization and liabilities	6,537,496	6,261,416
Related Party
CURRENT LIABILITIES
Natural gas purchases payable to related parties	$ 859	$ 851

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2023	Sep. 30, 2022
Statement of Financial Position [Abstract]
Common stock, par value (usd per share)	$ 2.50	$ 2.50
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	97,584,455	96,249,859
Treasury stock at cost and other, shares (in shares)	13,041	611,045

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
Balance as of beginning of period (in shares) at Sep. 30, 2020			95,949,000
Balance as of beginning of period at Sep. 30, 2020		$ 1,643,896	$ 240,243	$ 491,982	$ (44,315)	$ 8,485	$ 947,501
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		117,890					117,890
Other comprehensive income (loss)		9,787			9,787
Common stock issued:
Common stock offering		(2,823)		(2,823)
Incentive compensation plan (in shares)			84,000
Incentive compensation plan		4,263	$ 210	4,053
Dividend reinvestment plan (in shares)	[1]		431,000
Dividend reinvestment plan	[1]	15,156	$ 191	9,372		5,593
Cash dividend declared		(130,781)					(130,781)
Treasury stock and other (in shares)			(754,000)
Treasury stock and other		(26,526)				(26,526)
Balance as of end of period (in shares) at Sep. 30, 2021			95,710,000
Balance as of end of period at Sep. 30, 2021		1,630,862	$ 240,644	502,584	(34,528)	(12,448)	934,610
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		274,922					274,922
Other comprehensive income (loss)		29,702			29,702
Common stock issued:
Incentive compensation plan (in shares)			193,000
Incentive compensation plan		9,146	$ 481	8,665
Dividend reinvestment plan (in shares)	[1]		355,000
Dividend reinvestment plan	[1]	14,741	$ 491	8,450		5,800
Cash dividend declared		(142,004)					(142,004)
Treasury stock and other (in shares)			(8,000)
Treasury stock and other		$ (159)		(2)		(157)
Balance as of end of period (in shares) at Sep. 30, 2022		96,249,859	96,250,000
Balance as of end of period at Sep. 30, 2022		$ 1,817,210	$ 241,616	519,697	(4,826)	(6,805)	1,067,528
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		264,724					264,724
Other comprehensive income (loss)		(5,133)			(5,133)
Common stock issued:
Incentive compensation plan (in shares)			136,000
Incentive compensation plan		5,168	$ 339	4,829
Dividend reinvestment plan (in shares)	[1]		258,000
Dividend reinvestment plan	[1]	15,034	$ 205	6,069		8,760
Waiver discount (in shares)			948,000
Waiver discount		42,807	$ 1,298	28,059		13,450
Cash dividend declared		(154,418)					(154,418)
Treasury stock and other (in shares)			(8,000)
Treasury stock and other		$ 5,343				5,343
Balance as of end of period (in shares) at Sep. 30, 2023		97,584,455	97,584,000
Balance as of end of period at Sep. 30, 2023		$ 1,990,735	$ 243,458	$ 558,654	$ (9,959)	$ 20,748	$ 1,177,834
[1]Certain shares sold through the DRP issued from treasury stock are at average cost, which may differ from the actual market price paid.

CONSOLIDATED STATEMENTS OF CO_3

CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Statement of Stockholders' Equity [Abstract]
Cash dividend declared per share (usd per share)	$ 1.59	$ 1.4775	$ 1.36

NATURE OF THE BUSINESS

NATURE OF THE BUSINESS	12 Months Ended
	Sep. 30, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF THE BUSINESS	1. NATURE OF THE BUSINESS The Company provides regulated natural gas distribution services, transmission and storage services and operates certain unregulated businesses primarily through the following: NJNG provides natural gas utility service to approximately 576,000 customers throughout Burlington, Middlesex, Monmouth, Morris, Ocean and Sussex counties in New Jersey and is subject to rate regulation by the BPU. NJNG comprises the Natural Gas Distribution segment. NJRCEV, the Company’s clean energy subsidiary, comprises the CEV segment and invests in, owns and operates clean energy projects, including commercial and residential solar installations located in New Jersey, Rhode Island, New York, Connecticut, Michigan and Indiana. NJRES comprises the ES segment. ES maintains and transacts around a portfolio of natural gas transportation and storage capacity contracts and provides physical wholesale energy, retail energy and energy management services in the U.S. and Canada. NJR Midstream Holdings Corporation, which comprises the Storage and Transportation segment, invests in energy-related ventures through its subsidiaries. The Company operates natural gas storage and transmission assets through the wholly-owned subsidiaries of Leaf River and Adelphia and is subject to rate regulation by FERC. The Company holds a 50% combined ownership interest in Steckman Ridge, located in Pennsylvania, which is accounted for under the equity method of accounting, and 20% ownership interest in PennEast, which ceased operations in fiscal 2022. NJR Retail Holdings Corporation has one principal subsidiary: NJRHS, which provides heating, central air conditioning, standby generators, solar and other indoor and outdoor comfort products to residential homes throughout New Jersey. NJRHS is included in HSO operations.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Sep. 30, 2023
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 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 the entity 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, 2023, 2022 and 2021. Investments in entities over which the Company does not have a controlling financial interest are accounted for under the equity method. 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 quarterly basis, or more frequently whenever events or changes in circumstances indicate a need, the Company evaluates its estimates, including those related to the calculation of the fair value of derivative instruments, debt, equity method investments, lease liabilities, unbilled revenues, allowance for doubtful accounts, provisions for depreciation and amortization, long-lived assets, regulatory assets and liabilities, income taxes, pensions and other postemployment benefits, contingencies related to environmental matters and litigation. ARO are evaluated periodically as required. 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. Revenues Revenues from the sale of natural gas to NJNG customers are recognized in the period that natural 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 natural gas and the most current tariff rates. CEV recognizes revenue when SRECs are transferred to counterparties. SRECs are physically delivered through the transfer of certificates as per contractual settlement schedules. The Clean Energy Act of 2018 established guidelines for the closure of the SREC registration program to new applicants in New Jersey. The SREC program officially closed to new qualified solar projects on April 30, 2020. In December 2019, the BPU established the TREC as the successor to the SREC program. TRECs provide a fixed compensation base multiplied by an assigned project factor in order to determine their value. The project factor is determined by the type and location of the project, as defined. In July 2021, the BPU established a new successor solar incentive program. The Administratively Determined Incentive Program provides administratively set incentives for net metered residential projects and net metered non-residential projects of 5 MW or less. RECs generated through the production of electricity under this program are known as SREC IIs. TRECs and SREC IIs generated are required to be purchased monthly by a REC program administrator as appointed by the BPU. Revenue is recognized when RECs are generated and are transferred monthly based upon metered solar electricity activity. Revenues for ES 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. ES also recognizes changes in the fair value of SREC derivative contracts as a component of operating revenues. During December 2020, ES entered into a series of AMAs with an investment grade public utility to release pipeline capacity associated with certain natural gas transportation contracts, which commenced in November 2021. The AMAs include a series of temporary and permanent releases, and revenue under these agreements is recognized as the performance obligations are satisfied. For temporary releases of pipeline capacity, revenue is recognized on a straight-line basis over the agreed-upon term. For permanent releases of pipeline capacity, which represent a transfer of contractual rights for such capacity, revenue is recognized upon the transfer of the underlying contractual rights. ES recognized $48.5M and $53.0M of operating revenue on the Consolidated Statements of Operations during fiscal 2023 and 2022, respectively. Amounts received in excess of revenue recognized totaling $58.7M and $33.8M are included in deferred revenue on the Consolidated Balance Sheets as of September 30, 2023 and 2022, respectively. S&T generates revenues from firm storage contracts and transportation contracts, related usage fees and hub services for the use of storage space, injections and withdrawals from their natural gas storage facility and the delivery of natural gas to customers. Demand fees are recognized as revenue over the term of the related agreement while usage fees and hub services revenues are recognized as services are performed. 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. See Note 3. Revenue for further information. Natural 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. Natural gas purchases at ES are composed of natural 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 natural gas purchases as they occur. Demand Fees For the purpose of securing storage and pipeline capacity in support of their respective businesses, ES and NJNG 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 The following table summarizes the demand charges, which are net of capacity releases, and are included as a component of natural gas purchases on the Consolidated Statements of Operations for the fiscal years ended September 30: (Millions) 2023 2022 2021 ES $ 74.6 $ 95.4 $ 120.5 NJNG 183.4 170.3 123.2 Total $ 258.0 $ 265.7 $ 243.7 ES expenses demand charges over the term of the service being provided. NJNG’s costs associated with demand charges are included in its weighted average cost of natural gas. The demand charges are expensed based on NJNG’s BGSS sales and recovered as part of the natural gas commodity component of its BGSS tariff. Operations and Maintenance Expenses Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, amortization of software costs for unregulated entities, customer service, professional fees and other outside services, insurance expense, accretion of cost of removal for future retirements of utility assets and other administrative expenses and are expensed as incurred. Stock-Based Compensation Stock-based compensation represents costs related to stock-based awards granted to employees and members of NJR’s Board of Directors. NJR recognizes stock-based compensation based upon the estimated fair value of awards. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period. The related compensation cost is recognized as O&M expense on the Consolidated Statements of Operations. See Note 10. Stock-Based Compensation for further information. 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 12. 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. NJR evaluates its tax positions to determine the appropriate accounting and recognition of potential future obligations associated with unrecognized tax benefits. A tax benefit claimed, or expected to be claimed, on a tax return may be recognized if it is more likely than not that the position will be upheld upon examination by the applicable taxing authority. Interest and penalties related to unrecognized tax benefits, if any, are recognized within income tax expense and accrued interest, and penalties are recognized within other noncurrent liabilities on the Consolidated Balance Sheets. To the extent that NJNG invests in property that qualifies for ITCs, the ITC is deferred and amortized to income over the life of the equipment in accordance with regulatory treatment. ITCs at the unregulated subsidiaries of NJR are recorded on the balance sheet as a reduction to property, plant and equipment when the property is placed in service, and recognized in earnings as a reduction of depreciation expense over the useful lives of the related assets. Investments in Equity Investees The Company accounts for its investment in Steckman Ridge using the equity method of accounting where it is not the primary beneficiary, as defined under ASC 810, Consolidation ; its respective ownership interests are 50% or less and/or it has significant influence over operating and management decisions. The Company’s share of earnings is recognized as equity in earnings of affiliates on the Consolidated Statements of Operations. Equity method investments are reviewed for impairment when changes in facts and circumstances indicate that the current fair value may be less than the asset’s carrying amount. If the Company determines the decline in the value of its equity method investment is other than temporary, an impairment charge is recorded in an amount equal to the excess of the carrying value of the asset over its fair value. See Note 7. Investments in Equity Investees for more information regarding impairments. Property Plant and Equipment Property, plant and equipment is stated at original cost. Costs include direct labor, materials and third-party construction contractor costs, capitalized interest and certain indirect costs related to equipment and employees engaged in construction. Utility plant and nonutility plant for Adelphia also includes AFUDC. Upon retirement, the cost of depreciable 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 the Company’s nonutility entities, and is computed 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 2.68% of average depreciable property in fiscal 2023, 2.66% in fiscal 2022 and 2.42% in fiscal 2021. The Company recorded $152.9M, $129.2M and $111.4M in depreciation expense during fiscal 2023, 2022 and 2021, respectively. Property, plant and equipment was comprised of the following as of September 30: (Thousands) Estimated Property Classifications Useful Lives 2023 2022 Distribution facilities 11 to 54 years $ 3,063,111 $ 2,797,936 Transmission facilities 28 to 42 years 650,817 649,241 Storage facilities 27 to 86 years 85,603 85,449 Solar property 20 to 35 years 864,838 710,224 Storage and transportation property 5 to 50 years 884,647 850,186 All other property 5 to 40 years 61,327 60,914 Construction work in progress 380,196 361,766 Total property, plant and equipment 5,990,539 5,515,716 Accumulated depreciation and amortization (968,484) (865,790) Property, plant and equipment, net $ 5,022,055 $ 4,649,926 Within storage and transportation property, base gas is required to maintain the necessary pressure and to allow for efficient operation of the Leaf River storage facility. The base gas is determined to be recoverable and is considered part of the facility and thus presented as a component in property, plant and equipment. This natural gas is not depreciated, as it is expected to be recovered and sold. As of September 30, 2023 and 2022, the base gas had a cost basis of $20.9M and $15.1M, respectively. Capitalized and Deferred Interest NJNG’s base rates include the ability to recover AFUDC on its construction work in progress. For all NJNG construction projects, an incremental cost of equity is recoverable during periods when NJNG’s short-term debt balances are lower than its construction work in progress. For more information on AFUDC treatment with respect to certain accelerated infrastructure projects, see Note 4. Regulation - Infrastructure Programs. Capitalized amounts associated with the debt and equity components of NJNG’s AFUDC are recorded in utility plant on the Consolidated Balance Sheets. Corresponding amounts for the debt component are recognized in interest expense and in other income for the equity component on the Consolidated Statements of Operations. Adelphia’s base rates include the ability to recover AFUDC on its construction work in progress. Capitalized amounts associated with Adelphia’s AFUDC are recorded in nonutility plant on the Consolidated Balance Sheets. Corresponding amounts for the debt component are recognized in interest expense and in other income for the equity component on the Consolidated Statements of Operations. Capitalized and deferred interest include the following for the fiscal years ended September 30: ($ in thousands) 2023 2022 2021 AFUDC: NJNG Adelphia NJNG Adelphia NJNG Adelphia Debt $ 3,546 $ 90 $ 1,648 $ 4,019 $ 5,648 $ 2,101 Equity 6,979 158 4,169 7,074 16,605 3,698 Total $ 10,525 $ 248 $ 5,817 $ 11,093 $ 22,253 $ 5,799 Weighted average interest rate 6.41 % 8.28 % 4.91 % 8.28 % 5.97 % 8.28 % 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. 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 4.79%, 3.85% and 1.68% for the fiscal years ended September 30, 2023, 2022 and 2021, respectively. Accordingly, other income included $1.8M, $0.9M and $0.3M in the fiscal years ended September 30, 2023, 2022 and 2021, respectively. CEV capitalizes interest on the allocation of the costs of debt borrowed for the financing of solar investments. Capitalized amounts are included in nonutility plant and equipment on the Consolidated Balance Sheets. Corresponding amounts are recognized in interest expense on the Consolidated Statements of Operations. 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 related to escrow balances for utility plant projects at NJNG, which are recorded in other noncurrent assets on the Consolidated Balance Sheets. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the total amounts in the Consolidated Statements of Cash Flows, as of September 30: (Thousands) 2023 2022 2021 Balance Sheet Cash and cash equivalents $ 954 $ 1,107 $ 4,749 Restricted cash in other noncurrent assets $ 563 $ 345 $ 1,294 Statements of Cash Flow Cash, cash equivalents and restricted cash $ 1,517 $ 1,452 $ 6,043 Allowance for Doubtful Accounts The Company segregates financial assets, primarily trade receivables and unbilled revenues due in one year or less, into portfolio segments based on shared risk characteristics, such as geographical location and regulatory environment, for evaluation of expected credit losses. Historical and current information, such as average write-offs, are applied to each portfolio segment to estimate the allowance for losses on uncollectible receivables. Additionally, the allowance for losses on uncollectible receivables is adjusted for reasonable and supportable forecasts of future economic conditions, which can include changing weather, commodity prices, regulations and macroeconomic factors, such as unemployment rates among others. Loans Receivable NJNG currently provides loans, with terms ranging from two 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. NJNG is subject to accounting requirements resulting from the effects of rate regulation by the BPU. 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. Adelphia 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 Adelphia’s regulatory assets and liabilities. Natural Gas in Storage Natural 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 natural gas in storage, at average cost by company, as of September 30: 2023 2022 ($ in thousands) Natural Gas in Storage Bcf Natural Gas in Storage Bcf NJNG $ 175,025 29.1 $ 191,175 29.0 ES 24,476 14.6 82,469 10.8 Total $ 199,501 43.7 $ 273,644 39.8 Derivative Instruments The Company accounts for its financial instruments, such as futures, options, foreign exchange contracts and interest rate contracts, as well as its physical commodity contracts related to the purchase and sale of natural gas at ES, 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 natural gas purchases and changes in the fair value of their physical forward contracts in natural gas purchases or operating revenues, as appropriate, on the Consolidated Statements of Operations. Ineffective portions of the cash flow hedges are recognized immediately in earnings. Cash flows from derivative financial instruments are included in cash flows from operating activities on the Consolidated Statements of Cash Flows. ASC 815, Derivatives and Hedging also provides for a NPNS scope exception for qualifying physical commodity contracts for which physical delivery is probable and the quantities delivered are expected to be used or sold over a reasonable period of time in the normal course of business. 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 PPAs at CEV. When applied, it does not account for these contracts until the contract settles and the related underlying natural gas or power 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 and swaps, 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 ES and interest rate contracts 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. During fiscal 2020, the Company entered into treasury lock transactions to fix the benchmark treasury rate associated with debt issuances for NJNG and NJR that occurred during the fiscal year. Settlement of the NJNG treasury locks resulted in a loss, which was recorded as a component of regulatory assets on the Consolidated Balance Sheets and will be amortized in earnings over the term of the debt as a component of interest expense on the Consolidated Statements of Operations. NJR designated its treasury lock contracts as cash flow hedges; therefore, changes in fair value of the effective portion of the hedges were recorded in OCI. Settlement of the treasury locks resulted in a loss, which was recorded within OCI and is amortized into earnings over the term of the associated debt as a component of interest expense on the Consolidated Statements of Operations. As of both September 30, 2023 and 2022, amounts recognized in interest expense related to the amortization of the loss on treasury lock transactions totaled $0.2M for NJNG and $1.1M for NJR. Software Costs The Company capitalizes certain costs, such as software design and configuration, coding, testing and installation, that are incurred to purchase or create and implement computer software for internal use. Capitalized costs include external costs of materials and services utilized in developing or obtaining internal-use software and payroll and payroll-related costs for employees who are directly associated with and devote time to the internal-use software project. Maintenance costs are expensed as incurred. Upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Amortization is recorded on the straight-line basis over the estimated useful lives. The following table presents the software costs included in the Consolidated Financial Statements, as of September 30: (Thousands) 2023 2022 Balance Sheets Utility plant, at cost $ 51,282 $ 40,437 Construction work in progress $ 55,012 $ 14,381 Nonutility plant and equipment, at cost $ 344 $ 344 Accumulated depreciation and amortization, utility plant $ (7,480) $ (3,361) Accumulated depreciation and amortization, nonutility plant and equipment $ (36) $ (25) Software costs $ 8,375 $ 6,120 Statements of Operations Operation and maintenance (1) $ 14,299 $ 11,141 Depreciation and amortization $ 4,130 $ 2,024 (1) During both fiscal 2023 and 2022, $0.5M was amortized from software costs into O&M. 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, 2023, intangible assets consist primarily of acquired wholesale natural gas energy contracts totaling $0.1M, which will be fully amortized during fiscal 2024. 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 may not be recoverable, such as significant adverse changes in regulation, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices. 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. Factors that the Company analyzes in determining whether an impairment in its long-lived assets exists include: a significant decrease in the market price of a long-lived asset; a significant adverse change in the extent in which a long-lived asset is being used in its physical condition; legal proceedings or other contributing factors; significant business climate changes; accumulations of costs in significant excess of the amounts expected; a current-period operating or cash flow loss combined with a history of such events; and current expectations that more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its estimated useful life. During fiscal 2023 and 2022, there were no events or circumstances that indicated that the carrying value of long-lived assets or finite-lived intangibles was not recoverable. Debt Issuance Costs Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt. See Note 9. Debt for the total unamortized debt issuance costs that are recorded as a reduction to long-term debt on the Consolidated Balance Sheets. Sale Leasebacks NJNG utilizes sale leaseback arrangements as a financing mechanism to fund certain of its capital expenditures related to natural gas meters, whereby the physical asset is sold concurrent with an agreement to lease the asset back. These agreements include options to renew the lease or repurchase the asset at the end of the term. Proceeds from sale leaseback transactions are accounted for as financing arrangements and are included in long-term debt on the Consolidated Balance Sheets. In addition, 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 arrangement does not qualify as a sale as the Company retains control of the underlying assets, the Company uses the financing method to account for the transaction. Under the financing method, the Company recognizes the proceeds received from the buyer-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. The Company continues to operate the solar assets and is responsible for related expenses and entitled to retain the revenue generated from SRECs, TRECs, SREC IIs and energy sales. The ITCs and other tax benefits associated with these solar projects transfer to the buyer; however, the payments are structured so that CEV is compensated for the transfer of the related tax attributes. Accordingly, CEV recognizes the equivalent value of the tax attributes in other income on the Consolidated Statements of Operations over the respective five-year ITC recapture periods, starting with the second year of the lease. See Note 9. Debt for more details regarding sale leaseback transactions recorded as financing arrangements. Environmental Contingencies Loss contingencies are recorded as liabilities when it is probable a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties. Accruals for loss contingencies are recorded based on an analysis of potential results. With respect to environmental liabilities and related costs, NJNG periodically, and at least annually, performs an environmental review of MGP sites, including a review of potential liability for investigation and remedial action. 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. 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. See Note 14. Commitments and Contingent Liabilities for more details. 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 the Employee Retirement

REVENUE

REVENUE	12 Months Ended
	Sep. 30, 2023
Revenue from Contract with Customer [Abstract]
REVENUE	3. REVENUE Revenue is recognized when a performance obligation is satisfied by transferring control of a product or service to a customer. Revenue is measured based on consideration specified in a contract with a customer using the output method of progress. The Company elected to apply the invoice practical expedient for recognizing revenue, whereby the amounts invoiced to customers represent the value to the customer and the Company’s performance completion as of the invoice date. Therefore the Company does not disclose related unsatisfied performance obligations. The Company also elected the practical expedient to exclude from the transaction price all sales taxes that are assessed by a governmental authority and therefore presents sales tax net in operating revenues on the Consolidated Statements of Operations. Below is a listing of performance obligations that arise from contracts with customers, along with details on the satisfaction of each performance obligation, the significant payment terms and the nature of the goods and services being transferred, by reporting segment and other business operations: Revenue Recognized Over Time: Segment/ Operations Performance Obligation Description NJNG Natural gas utility sales NJNG’s performance obligation is to provide natural gas to residential, commercial and industrial customers as demanded, based on regulated tariff rates, which are established by the BPU. Revenues from the sale of natural gas are recognized in the period that natural gas is delivered and consumed by customers, including an estimate for quantities consumed but not billed during the period. Payment is due each month for the previous month’s deliveries. Natural gas sales to individual customers are based on meter readings, which are performed on a systematic basis throughout the billing period. The unbilled revenue estimates are based on estimated customer usage by customer type, weather effects and the most current tariff rates. NJNG is entitled to be compensated for performance completed until service is terminated. Customers may elect to purchase the natural gas commodity from NJNG or may contract separately to purchase natural gas directly from third-party suppliers. As NJNG is acting as an agent on behalf of the third-party supplier, revenue is recorded for the delivery of natural gas to the customer. CEV Commercial solar electricity CEV operates wholly-owned solar projects that recognize revenue as electricity is generated and transferred to the customer. The performance obligation is to provide electricity to the customer in accordance with contract terms or the interconnection agreement and is satisfied upon transfer of electricity generated. Revenue is recognized as invoiced and the payment is due each month for the previous month's services. CEV Residential solar electricity CEV provides access to residential rooftop and ground-mount solar equipment to customers who then pay the Company a monthly fee. The performance obligation is to provide electricity to the customer based on generation from the underlying residential solar asset and is satisfied upon transfer of electricity generated. Revenue is derived from the contract terms and is recognized as invoiced, with the payment due each month for the previous month’s services. Revenue Recognized Over Time (continued): Segment/ Performance Obligation Description CEV Renewable energy certificates Certain CEV projects generate TRECs and SREC IIs under the established Administratively Determined Incentive Program. A TREC or SREC II is created for every MWh of electricity produced by a solar generator. The performance obligation of CEV is to generate electricity. TRECs and SREC IIs under the Administratively Determined Incentive Program are purchased monthly by a REC Administrator. Revenue is recognized upon generation. ES Natural gas services The performance obligation of ES is to provide the customer transportation, storage and asset management services on an as-needed basis. ES generates revenue through management fees, demand charges, reservation fees and transportation charges centered around the buying and selling of the natural gas commodity, representing one series of distinct performance obligations. Revenue is recognized based upon the underlying natural gas quantities physically delivered and the customer obtaining control. ES invoices customers in line with the terms of the contract and based on the services provided. Payment is due upon receipt of the invoice. For temporary releases of pipeline capacity, revenue is recognized on a straight-line basis over the agreed upon term. S&T Natural gas services The performance obligation of S&T is to provide the customer with storage and transportation services. S&T generates revenues from firm storage contracts and transportation contracts, injection and withdrawal at the storage facility and the delivery of natural gas to customers. Revenue is recognized over time as customers receive the benefits of its service as it is performed on their behalf using an output method based on actual deliveries. Demand fees are recognized as revenue over the term of the related agreement. HSO Service contracts Home Services enters into service contracts with homeowners to provide maintenance and replacement of applicable heating, cooling or ventilation equipment. NJR Retail enters into warranty contracts with homeowners for various appliances. All services provided relate to a distinct performance obligation which is to provide services for the specific equipment over the term of the contract. Revenue is recognized on a straight-line basis over the term of the contract and payment is due upon receipt of the invoice. Revenue Recognized at a Point in Time: ES Natural gas services For a permanent release of pipeline capacity, the performance obligation of ES is the release of the pipeline capacity associated with certain natural gas transportation contracts and the transfer of the underlying contractual rights to the counterparty. Revenue is recognized upon the transfer of the underlying contractual rights. S&T Natural gas services The performance obligation of S&T is to provide the customer with storage and transportation services. S&T generates revenues from usage fees and hub services for the use of storage space, injection and withdrawal from the storage facility. Hub services include park and loan transactions and wheeling. Usage fees and hub services revenues are recognized as services are performed. HSO Installations Home Services installs appliances, including but not limited to, furnaces, air conditioning units, boilers and generators for customers. The distinct performance obligation is the installation of the contracted appliance, which is satisfied at the point in time the item is installed. The transaction price for each installation differs accordingly. Revenue is recognized at a point in time upon completion of the installation, which is when the customer is billed. Disaggregated revenues from contracts with customers by product line and by reporting segment and other business operations during fiscal 2023, 2022 and 2021 are as follows: (Thousands) NJNG CEV ES S&T HSO Total 2023 Natural gas utility sales (1) $ 845,392 — — — — $ 845,392 Natural gas services — — 76,975 92,859 — 169,834 Service contracts — — — — 35,210 35,210 Installations and maintenance — — — — 22,428 22,428 Renewable energy certificates — 12,636 — — — 12,636 Electricity sales — 31,733 — — — 31,733 Eliminations (2) (1,349) — — (4,159) (205) (5,713) Revenues from contracts with customers 844,043 44,369 76,975 88,700 57,433 1,111,520 Alternative revenue programs (3) 27,257 — — — — 27,257 Derivative instruments 139,984 79,762 (4) 614,641 — — 834,387 Eliminations (2) — — (10,170) — — (10,170) Revenues out of scope 167,241 79,762 604,471 — — 851,474 Total operating revenues $ 1,011,284 124,131 681,446 88,700 57,433 $ 1,962,994 2022 Natural gas utility sales (1) $ 951,626 — — — — $ 951,626 Natural gas services — — 83,801 67,735 — 151,536 Service contracts — — — — 33,932 33,932 Installations and maintenance — — — — 22,250 22,250 Renewable energy certificates — 5,487 — — — 5,487 Electricity sales — 38,317 — — — 38,317 Eliminations (2) (1,350) — — (2,449) (364) (4,163) Revenues from contracts with customers 950,276 43,804 83,801 65,286 55,818 1,198,985 Alternative revenue programs (3) 11,259 — — — — 11,259 Derivative instruments 165,882 84,476 (4) 1,445,471 — — 1,695,829 Eliminations (2) — — (94) — — (94) Revenues out of scope 177,141 84,476 1,445,377 — — 1,706,994 Total operating revenues $ 1,127,417 128,280 1,529,178 65,286 55,818 $ 2,905,979 2021 Natural gas utility sales $ 694,635 — — — — 694,635 Natural gas services — — 26,933 51,020 — 77,953 Service contracts — — — — 33,250 33,250 Installations and maintenance — — — — 18,979 18,979 Renewable energy certificates — 4,571 — — — 4,571 Electricity sales — 25,270 — — — 25,270 Eliminations (2) — — — (1,768) (785) (2,553) Revenues from contracts with customers 694,635 29,841 26,933 49,252 51,444 852,105 Alternative revenue programs (3) (7,282) — — — — (7,282) Derivative instruments 44,443 65,434 (4) 1,201,487 — — 1,311,364 Eliminations (2) — — 426 — — 426 Revenues out of scope 37,161 65,434 1,201,913 — — 1,304,508 Total operating revenues $ 731,796 95,275 1,228,846 49,252 51,444 2,156,613 (1) Includes building rent related to the Wall headquarters, which is eliminated in consolidation. (2) Consists of transactions between subsidiaries that are eliminated in consolidation. (3) Includes CIP revenue. (4) Includes SREC revenue. Disaggregated revenues from contracts with customers by customer type and by reporting segment and other business operations during the fiscal years ended September 30, are as follows: (Thousands) NJNG CEV ES S&T HSO Total 2023 Residential $ 621,663 13,668 — — 57,091 $ 692,422 Commercial and industrial 136,011 30,701 76,975 88,700 342 332,729 Firm transportation 77,722 — — — — 77,722 Interruptible, off-tariff and other 8,647 — — — — 8,647 Revenues out of scope 167,241 79,762 604,471 — — 851,474 Total operating revenues $ 1,011,284 124,131 681,446 88,700 57,433 $ 1,962,994 2022 Residential $ 586,678 12,579 — — 55,629 $ 654,886 Commercial and industrial 265,970 31,225 83,801 65,286 189 446,471 Firm transportation 92,531 — — — — 92,531 Interruptible, off-tariff and other 5,097 — — — — 5,097 Revenues out of scope 177,141 84,476 1,445,377 — — 1,706,994 Total operating revenues $ 1,127,417 128,280 1,529,178 65,286 55,818 $ 2,905,979 2021 Residential $ 487,018 11,319 — — 50,689 $ 549,026 Commercial and industrial 124,519 18,522 26,933 49,252 755 219,981 Firm transportation 79,256 — — — — 79,256 Interruptible, off-tariff and other 3,842 — — — — 3,842 Revenues out of scope 37,161 65,434 1,201,913 — — 1,304,508 Total operating revenues $ 731,796 95,275 1,228,846 49,252 51,444 $ 2,156,613 Customer Accounts Receivable/Credit Balances and Deposits The timing of revenue recognition, customer billings and cash collections resulting in accounts receivables, billed and unbilled, and customers’ credit balances and deposits on the Consolidated Balance Sheets are as follows: Customer Accounts Receivable Customers’Credit (Thousands) Billed Unbilled Balances and Deposits Balance as of September 30, 2021 $ 212,838 $ 10,351 $ 32,586 Increase 9,459 3,418 660 Balance as of September 30, 2022 222,297 13,769 33,246 (Decrease) increase (124,757) 5,331 11,664 Balance as of September 30, 2023 $ 97,540 $ 19,100 $ 44,910 The following table provides information about receivables, which are included within accounts receivable, billed and unbilled, and customers’ credit balances and deposits, respectively, on the Consolidated Balance Sheets as of September 30: (Thousands) NJNG CEV ES S&T HSO Total 2023 Customer accounts receivable Billed $ 55,234 9,962 23,716 6,577 2,051 $ 97,540 Unbilled 10,784 8,316 — — — 19,100 Customers’ credit balances and deposits (44,898) — — (12) — (44,910) Total $ 21,120 18,278 23,716 6,565 2,051 $ 71,730 2022 Customer accounts receivable Billed $ 78,508 5,566 129,199 7,012 2,012 $ 222,297 Unbilled 10,814 2,955 — — — 13,769 Customers’ credit balances and deposits (33,246) — — — — (33,246) Total $ 56,076 8,521 129,199 7,012 2,012 $ 202,820

REGULATION

REGULATION	12 Months Ended
	Sep. 30, 2023
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 natural gas to NJNG’s service territory; and the delivery portion, which represents the transportation of the commodity portion through NJNG’s natural 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 on August 1, 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 filings to the BPU for review of its BGSS, CIP and other programs and related rates. Annual rate changes are typically requested to be effective at the beginning of the following fiscal year. The current base rates include a weighted average cost of capital of 6.84% and a return on common equity of 9.6%. All rate and program changes are subject to proper notification and BPU review and approval. In addition, NJNG is permitted to implement certain BGSS rate changes on a provisional basis with proper notification to the BPU. Regulatory assets and liabilities included on the Consolidated Balance Sheets for NJNG are comprised of the following, as of September 30: (Thousands) 2023 2022 Regulatory assets-current New Jersey Clean Energy Program $ 15,804 $ 15,697 Conservation Incentive Program 50,356 23,099 Derivatives at fair value, net 6,017 — Other current regulatory assets 1,410 1,290 Total current regulatory assets $ 73,587 $ 40,086 Regulatory assets-noncurrent Environmental remediation costs: Expended, net of recoveries $ 66,298 $ 66,149 Liability for future expenditures 169,390 127,070 Deferred income taxes 41,667 40,520 SAVEGREEN 83,589 52,690 Postemployment and other benefit costs 55,274 56,021 Deferred storm damage costs — 2,172 Cost of removal 112,362 104,850 Other noncurrent regulatory assets 51,019 45,828 Total noncurrent regulatory assets $ 579,599 $ 495,300 Regulatory liability-current Overrecovered natural gas costs $ 30,637 $ 17,807 Derivatives at fair value, net — 7,972 Total current regulatory liabilities $ 30,637 $ 25,779 Regulatory liabilities-noncurrent Tax Act impact (1) $ 180,347 $ 185,367 Derivatives at fair value, net — 116 Other noncurrent regulatory liabilities 111 151 Total noncurrent regulatory liabilities $ 180,458 $ 185,634 (1) Reflects the re-measurement and subsequent amortization of NJNG’s net deferred tax liabilities as a result of the change in federal tax rates enacted in the Tax Act. The Tax Act is an Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018, previously known as The Tax Cuts and Jobs Act of 2017. Other noncurrent regulatory assets include deferred pandemic costs of approximately $3.9M and $6.9M as of September 30, 2023 and 2022, respectively, primarily related to a portion of bad debt associated with customer accounts receivable resulting from the impacts of the COVID-19 pandemic. These costs are eligible for future regulatory recovery. On January 5, 2023, NJNG advised the BPU that it will cease deferring COVID-19 costs as of December 31, 2022, and will seek recovery of its regulatory asset balance in its next base rate proceeding. Regulatory assets and liabilities included on the Consolidated Balance Sheets for Adelphia are comprised of the following, as of September 30: (Thousands) 2023 2022 Total noncurrent regulatory assets $ 5,231 $ 5,366 Total current regulatory liabilities $ 1,650 $ 5,311 The assets are comprised primarily of the tax benefit associated with the equity component of AFUDC and the liability consists primarily of scheduling penalties. Recovery of regulatory assets is subject to FERC approval. 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 2024. NJNG recovers the costs associated with its portion of the NJCEP obligation through its NJCEP rider, with interest. 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 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. 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 Upon adoption of a 1993 provision of ASC 740, Income Taxes , 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, with interest, as approved by the BPU, over a two Postemployment and Other Benefit Costs Postemployment and Other Benefit Costs represents NJNG’s underfunded postemployment benefit obligations, as well as a 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. The BPU approved the recovery of the tax charge through NJNG’s base rates effective October 2016 over a seven-year amortization period. See Note 11. Employee Benefit Plans . Deferred Storm Damage Costs Portions of NJNG’s distribution system incurred significant damage as a result of Post-Tropical Cyclone Sandy in October 2012. NJNG deferred the uninsured incremental O&M costs associated with its restoration efforts, which were approved for recovery by the BPU through NJNG’s base rates, without interest, effective October 2016 over a seven-year amortization period. Cost of Removal NJNG accrues and collects for cost of removal in base rates on its utility property, without interest. These costs are recorded in accumulated depreciation for regulatory reporting purposes, and actual costs of removal, without interest, will be recovered in subsequent rates, pursuant to the BPU order. Consistent with GAAP, amounts recorded within accumulated depreciation for regulatory accounting purposes are reclassified out of accumulated depreciation to either a regulatory asset or a regulatory liability depending on whether actual cost of removal is still subject to collection or amounts overcollected will be refunded back to customers. Other Regulatory Assets Other regulatory assets consist primarily of deferred costs associated with certain components of NJNG’s SBC, as discussed further in the regulatory proceedings section, 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, without interest, subject to BPU review and approval. Overrecovered Natural Gas Costs NJNG recovers its cost of natural gas through the BGSS rate component of its customers’ bills. NJNG’s cost of natural 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 natural gas costs represent a regulatory liability that generally occurs when NJNG’s BGSS rates are higher than actual costs and returns to customers, including interest when applicable, in accordance with NJNG’s approved BGSS tariff. Conversely, underrecovered natural 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. The following is a description of certain regulatory proceedings during fiscal 2022 and 2023: On November 2021, the BPU issued an order adopting a stipulation of settlement approving a $79.0M increase to base rates, effective December 1, 2021. The increase includes an overall rate of return on rate base of 6.84%, return on common equity of 9.6%, a common equity ratio of 54.0% and a depreciation rate of 2.78%. 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: • In November 2020, NJNG notified the BPU of its intent to provide BGSS bill credits to residential and small commercial sales customers effective December 1, 2020 to December 31, 2020. In December 2020, NJNG notified the BPU of the extension of the BGSS bill credits through January 2021. The actual bill credits given to customers totaled $20.6M, $19.3M net of tax. • 2021 BGSS/CIP filing — In May 2021, NJNG submitted to the BPU the annual petition to modify its BGSS, balancing charge and CIP rates. In November 2021, the BPU approved a $2.9M increase to the annual revenues credited to BGSS and a $13.0M annual increase related to its balancing charge, as well as changes to CIP rates, which will result in a $6.3M decrease to the annual recovery, effective December 1, 2021. • In November 2021, the BPU approved, on a preliminary basis, NJNG’s annual petition to modify its BGSS, balancing charge and CIP rates for residential and small commercial customers. The rate changes resulted in a $2.9M increase to the annual revenues credited to BGSS and a $13.0M annual increase related to its balancing charge, as well as changes to CIP rates, which resulted in a $6.3M annual recovery decrease, effective December 1, 2021, and was approved on a final basis in May 2022. • In November 2021, NJNG submitted notification of its intent to self-implement an increase to its BGSS rate which results in an approximate $24.2M increase to annual revenues credited to BGSS, effective December 1, 2021. • 2022 BGSS/CIP filing — In June 2022, NJNG submitted its annual petition to modify its BGSS, balancing charge and CIP rates for residential and small commercial customers. In September 2022, the BPU approved, on a preliminary basis, an $81.9M increase to the annual revenues credited to BGSS and a $9.0M annual increase related to its balancing charge, as well as a $10.2M increase to CIP rates, effective October 1, 2022, which was approved on a final basis on April 12, 2023. • On February 22, 2023, NJNG advised the BPU of a bill credit and a reduction to the BGSS rate for residential and small commercial customers, which reduced recoveries by approximately $29.9M, effective March 1, 2023, and was approved on a final basis by the BPU on April 12, 2023. Bill credits provided to customers from March 2023 through May 2023, totaled approximately $32.4M. • 2023 BGSS/CIP filing — On June 1, 2023, NJNG filed its annual petition to modify its BGSS, balancing charge and CIP rates for residential and small business customers. This includes a $38.6M decrease to the annual revenues credited to BGSS, a $7.4M annual decrease related to its balancing charge and a $27.5M increase to CIP rates, effective October 1, 2023. On September 18, 2023, the BPU approved, on a provisional basis, the filed BGSS and balancing charge changes and a $27.0M increase to CIP rates, based on updated information since the initial filing. 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 and storage incentive programs. 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. 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 upgrades to promote energy efficiency 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 three SAVEGREEN investments and costs are filed with the BPU on an annual basis. NJNG’s annual EE filings are summarized as follows: • 2020 EE filing — In May 2020, NJNG filed a petition with the BPU to minimally decrease its EE recovery rate. Throughout the course of the proceeding, the Company updated the filing for additional actual information. Based on the updated information, the BPU approved the request to maintain its existing rate, which results in an annual recovery of approximately $11.4M, effective November 1, 2020. • 2021 EE filing — In June 2021, NJNG submitted its annual cost recovery filing for the SAVEGREEN programs established from 2010 through 2018. In January 2022, the BPU approved the stipulation to resolve the current EE annual cost recovery filing, which increases annual recoveries by $2.2M, effective February 1, 2022. • 2022 EE filing — In June 2022, NJNG submitted its annual cost recovery filing for the SAVEGREEN programs established from 2010 through the present. In September 2022, the BPU approved the filing, which decreases annual recoveries by $3.5M, effective October 1, 2022. • 2023 EE filing — On June 1, 2023, NJNG submitted its annual EE filing with the BPU for the recovery of SAVEGREEN costs, proposing an increase in annual recoveries of approximately $10.7M. On September 27, 2023, the BPU approved an increase to the EE rate increasing annual recoveries by $9.0M based on updated information since the initial filing, effective October 1, 2023 Societal Benefits Charge 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: • 2020 SBC filing — In April 2021, the BPU approved a stipulation resolving NJNG’s annual SBC application requesting to recover remediation expenses, including an increase in the RAC of approximately $1.3M annually and an increase to the NJCEP factor, which resulted in an annual increase of approximately $6.0M, effective May 1, 2021. • 2021 USF filing — In June 2021, NJNG filed its annual USF compliance filing proposing an annual increase to the statewide USF rate of approximately $4.9M. In September 2021, the BPU approved the increase, effective October 1, 2021. • 2021 SBC filing — In March 2022, the BPU approved NJNG’s annual filing to increase the RAC by $0.6M and decrease the NJCEP by $2.9M, effective April 1, 2022. • 2022 USF filing — In June 2022, NJNG filed its annual USF compliance filing proposing a decrease to the statewide USF rate. In August 2022, an additional update was submitted on behalf of all NJ utilities with actual information through July 31, 2022. In September 2022, the BPU approved a decrease based on the August update, which resulted in an annual decrease of approximately $1.6M, effective October 1, 2022. • 2022 SBC filing — In September 2022, NJNG submitted its annual SBC filing to the BPU requesting approval of RAC expenditures through June 30, 2022, as well as an increase to the RAC annual recoveries of $3.8M and an increase to the NJCEP annual recoveries of $2.2M, with a proposed effective date of April 1, 2023. On April 12, 2023, the BPU approved on a final basis an increase to the RAC annual recoveries of $3.7M and a decrease to the NJCEP annual recoveries of $0.9M, effective May 1, 2023. • 2023 USF filing — On June 28, 2023, NJNG submitted its annual USF filing to the BPU requesting an increase to the statewide USF rate, which will result in a $0.7M increase to annual recoveries. The BPU approved this matter on September 27, 2023, effective October 1, 2023. • 2023 SBC filing — On September 11, 2023 , NJNG submitted its annual SBC filing to the BPU requesting approval of RAC expenditures through June 2023, as well as an increase to the RAC annual recoveries of $2.4M and an increase to the NJCEP annual recoveries of $5.0M, which would be effective April 1, 2024. 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 natural gas distribution system, including SAFE and NJ RISE. SAFE/NJ RISE The SAFE program replaced portions of NJNG’s natural gas distribution unprotected steel, cast iron infrastructure and associated services to improve the safety and reliability of the natural gas distribution system. SAFE I was approved to invest up to $130.0M, exclusive of AFUDC, over a four-year period. SAFE II was approved to invest up to $200.0M, excluding AFUDC, over a five-year period. NJNG recovered approximately $157.5M through annual rate filings, with the remainder recovered through subsequent rate cases. As a condition of approval of the program, NJNG was required to file a base rate case no later than November 2019 and satisfied this requirement with its March 29, 2019 base rate case filing. NJ RISE consisted of six capital investment projects estimated to cost $102.5M over a five-year period, excluding AFUDC, for natural gas distribution storm-hardening and mitigation projects, along with incremental depreciation expense. NJ RISE includes a weighted average cost of capital that ranges from 6.74% to 6.9% and a return on equity of 9.75%. Requests for recovery of future NJ RISE capital costs occurred in conjunction with SAFE II. In March 2021, NJNG filed a petition with the BPU requesting the final base rate increase for the recovery associated with NJ RISE and SAFE II capital investments cost of approximately $3.4M made through June 30, 2021. In June 2021, this filing was consolidated with the 2021 base rate case. In November 2021, the BPU issued an order for the consolidated matter which included approval for the final increase for the NJ RISE and SAFE II programs of $0.3M. With this approval, the BPU filings with respect to NJ RISE and SAFE II are complete. Infrastructure Investment Program In February 2019, NJNG filed a petition with the BPU seeking authority to implement a five-year IIP. The IIP consists of two components, transmission and distribution investments and information technology replacement and enhancements. The total investment for the IIP is approximately $507.0M. Upon approval from the BPU, investments will be recovered through annual filings to adjust base rates. In October 2020, the BPU approved the Company’s transmission and distribution component of the IIP for $150.0M over five years, effective November 1, 2020. The recovery of information technology replacement and enhancements that was included in the original IIP filing will be included as part of base rate filings as projects are placed in service. In March 2022, NJNG filed its first rate recovery request for its BPU-approved IIP with capital expenditures estimated through June 30, 2022, including AFUDC. In July 2022, NJNG filed its update with actual capital expenditures of $28.9M through June 30, 2022. In September 2022, the BPU approved the rate increase resulting in a $3.2M revenue increase, effective October 1, 2022. On March 30, 2023, NJNG submitted its annual IIP filing to the BPU requesting a rate increase for estimated capital expenditures of $31.4M through June 30, 2023. This filing was updated on July 28, 2023, with actual expenses of approximately $28.2M through June 30, 2023. The BPU approved this filing on September 27, 2023, which resulted in a $3.2M revenue increase, effective October 1, 2023.

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS	12 Months Ended
	Sep. 30, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	5. DERIVATIVE INSTRUMENTS The Company is subject primarily 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 is exposed to foreign currency and interest rate risk and may utilize foreign currency derivatives to hedge Canadian dollar-denominated natural gas purchases and/or sales and interest rate derivatives to reduce exposure to fluctuations in interest rates. All of these types of contracts are accounted for as derivatives, unless the Company elects NPNS, which is done on a contract-by-contract election. 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 ES chooses not to designate its financial commodity and physical forward commodity derivatives as accounting hedges or to elect NPNS. The changes in the fair value of these derivatives are recorded as a component of natural gas purchases or operating revenues, as appropriate for ES, on the Consolidated Statements of Operations as unrealized gains or losses. For ES at settlement, realized gains and losses on all financial derivative instruments are recognized as a component of natural 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 natural gas purchases or operating revenues. ES 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. ES may utilize foreign currency derivatives to lock in the exchange rates 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 natural gas purchase agreements. As a result of ES 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 natural 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. ES 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. 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 charged to expense in the current period earnings based on the BGSS factor times the therm sales. Effective for contracts executed on or after January 1, 2016, NJNG no longer elects NPNS accounting treatment on a portfolio basis. However, since NPNS is a contract-by-contract election, where it makes sense to do so, NJNG can and may elect to treat certain contracts as 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 natural 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. Clean Energy Ventures The Company elects NPNS accounting treatment on PPA contracts executed by CEV that meet the definition of a derivative and accounts for the contract on an accrual basis. Accordingly, electricity sales are recognized in revenues throughout the term of the PPA as electricity is delivered. NPNS is a contract-by-contract election and where it makes sense to do so, the Company can and may elect to treat certain contracts as normal. Fair Value of Derivatives The following table presents the fair value of the Company’s derivative assets and liabilities recognized on the Consolidated Balance Sheets as of September 30: Derivatives at Fair Value 2023 2022 (Thousands) Balance Sheet Location Assets Liabilities Assets Liabilities Derivatives not designated as hedging instruments: NJNG: Physical commodity contracts Derivatives - current $ 43 $ 488 $ 252 $ 11 Financial commodity contracts Derivatives - current 6,110 20 85 6,281 ES: Physical commodity contracts Derivatives - current 6,209 12,757 9,857 17,051 Derivatives - noncurrent 802 7,870 376 13,561 Financial commodity contracts Derivatives - current 18,393 2,880 14,423 26,488 Derivatives - noncurrent 762 97 6,009 630 Foreign currency contracts Derivatives - current — — 18 17 Total fair value of derivatives $ 32,319 $ 24,112 $ 31,020 $ 64,039 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 and the net amounts the Company could present on the Consolidated Balance Sheets but elects not to. Asset Derivatives Liability Derivatives (Thousands) Fair Value (1) Amounts Offset (2) Collateral Received/Pledged (3) Net Value (4) Fair Value (1) Amounts Offset (2) Collateral Received/Pledged (3) Net Value (4) As of September 30, 2023 ES Contracts Physical commodity $ 7,011 (1,236) — $ 5,775 $ 20,627 (1,236) (9,728) $ 9,663 Financial commodity 19,155 (2,977) (16,178) — 2,977 (2,977) — — Total ES $ 26,166 (4,213) (16,178) $ 5,775 $ 23,604 (4,213) (9,728) $ 9,663 NJNG Contracts Physical commodity $ 43 (3) — $ 40 $ 488 (3) — $ 485 Financial commodity 6,110 (20) — 6,090 20 (20) — — Total NJNG $ 6,153 (23) — $ 6,130 $ 508 (23) — $ 485 As of September 30, 2022 ES Contracts Physical commodity $ 10,233 (404) (200) $ 9,629 $ 30,612 (404) — $ 30,208 Financial commodity 20,432 (12,198) — 8,234 27,118 (12,198) — 14,920 Foreign currency 18 (17) — 1 17 (17) — — Total ES $ 30,683 (12,619) (200) $ 17,864 $ 57,747 (12,619) — $ 45,128 NJNG Contracts Physical commodity $ 252 — — $ 252 $ 11 — — $ 11 Financial commodity 85 (85) — — 6,281 (85) — 6,196 Total NJNG $ 337 (85) — $ 252 $ 6,292 (85) — $ 6,207 (1) Derivative assets and liabilities are presented on a gross basis on the Consolidated Balance Sheets, as the Company does not elect balance sheet offsetting under ASC 210-20. (2) Includes 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. ES utilizes financial derivatives to economically hedge the gross margin associated with the purchase of physical natural 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 natural 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 ES, although the Company’s intended economic results relating to the entire transaction are unaffected. The following table presents the effect of derivative instruments recognized 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 Derivatives not designated as hedging instruments: 2023 2022 2021 ES: Physical commodity contracts Operating revenues $ 33,610 $ (8,569) $ 30,011 Physical commodity contracts Natural gas purchases (6,846) 3,580 1,052 Financial commodity contracts Natural gas purchases 80,406 14,403 (43,997) Foreign currency contracts Natural gas purchases — (14) 238 Total unrealized and realized gain (loss) $ 107,170 $ 9,400 $ (12,696) NJNG’s derivative contracts are part of the Company’s risk management activities that relate to its natural gas purchases and BGSS incentive programs. At settlement, the resulting gains and/or losses are payable to or recoverable from utility customers and are deferred in regulatory assets or liabilities resulting in no impact to earnings. The following table reflects the gains and/or (losses) associated with NJNG’s derivative instruments as of September 30: (Thousands) 2023 2022 2021 NJNG: Physical commodity contracts $ (34,241) $ 7,116 $ 2,174 Financial commodity contracts (50,130) 32,868 32,725 Total unrealized and realized (loss) gain $ (84,371) $ 39,984 $ 34,899 During fiscal 2020, NJR entered into treasury lock transactions to fix the benchmark treasury rate associated with debt issuances that were finalized in 2020. NJR designates its treasury lock contracts as cash flow hedges; therefore, 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 OCI to interest expense on the Consolidated Statements of Operations ratable over the term of the associated debt. Pre-tax losses of $1.4M were reclassified during both fiscal 2023 and 2022. NJNG and ES had the following outstanding long (short) derivatives as of September 30: Natural Gas Distribution Energy Services Volumes (Bcf) Futures Physical Commodity Futures Physical Commodity 2023 32.1 12.1 (6.9) 0.2 2022 30.5 6.8 (0.7) 2.7 Broker Margin Futures exchanges have contract-specific 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 ES. The balances as of September 30, by reporting segment, are as follows: (Thousands) Balance Sheet Location 2023 2022 NJNG Restricted broker margin accounts - current assets $ 5,915 $ 26,138 ES Restricted broker margin accounts - current assets $ 14,881 $ 68,123 Restricted broker margin accounts - current liabilities $ 8,029 $ — Wholesale Credit Risk NJNG, ES, CEV and S&T are exposed to credit risk as a result of their sales/wholesale marketing activities. As a result of the inherent volatility in the prices of natural gas commodities, derivatives and SRECs, 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, then 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 Fitch or Moody’s. In these cases, the counterparty’s or guarantor’s financial statements are reviewed, and similar methodologies and ratios used by Fitch 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, 2023. 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 CEV residential solar installations. (Thousands) Gross Credit Investment grade $ 119,229 Noninvestment grade 4,775 Internally-rated investment grade 20,343 Internally-rated noninvestment grade 20,153 Total $ 164,500 Conversely, certain of NJNG’s and ES’s 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. 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. There was approximately $0.1M and $0.2M of derivative instruments with credit-risk-related contingent features that were in a liability position for which collateral is required as of September 30, 2023 and 2022, respectively. 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, 2023
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 loans receivable, 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 loans receivable are recorded based on what the Company expects to receive, which approximates fair value, in other noncurrent assets on the Consolidated Balance Sheets. 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, including current maturities, excluding natural gas meter sale leasebacks, debt issuance costs and solar asset sale leasebacks, is as follows (1) : (Thousands) 2023 2022 NJNG (2) (3) Carrying value $ 1,467,845 $ 1,292,845 Fair market value $ 1,097,088 $ 979,388 NJR (4) Carrying value $ 1,120,000 $ 1,070,000 Fair market value $ 1,009,448 $ 966,968 (1) See Note 9. Debt f or a reconciliation to long-term and short-term debt . (2) Excludes the sale leasebacks of natural gas meters of $31.4M and $30.3M as of September 30, 2023 and 2022, respectively. The fair value of certain sale leasebacks of natural gas meters amounted to $20.9M and $15.7M as of September 30, 2023 and 2022, respectively. (3) Excludes NJNG’s debt issuance costs of $9.8M and $9.5M as of September 30, 2023 and September 30, 2022, respectively. (4) Excludes NJR’s debt issuance costs of $3.7M and $3.8M as of September 30, 2023 and September 30, 2022, respectively. CEV enters into transactions to sell certain commercial solar assets and lease the assets back for a term specified in the lease. These transactions are considered financing obligations for accounting purposes and are recorded within long-term debt on the Consolidated Balance Sheets. The estimated fair value of solar asset financing obligations as of September 30, 2023 and 2022 was $268.1M and $124.1M, 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, 2023, the Company discloses 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, investments in equity 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: Fair Value Hierarchy Description of Fair Value Level Fair Value Technique 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 to internally as basis swaps, fixed swaps, futures and financial options that are cleared through an 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). 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 ES 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. ES uses Platts and Natural Gas Exchange for Canadian delivery points. However, ES 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, ES’s 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 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 (Thousands) (Level 1) (Level 2) (Level 3) Total As of September 30, 2023 Assets Physical commodity contracts $ — $ 7,054 $ — $ 7,054 Financial commodity contracts 25,265 — — 25,265 Money market funds 145 — — 145 Other 2,641 — — 2,641 Total assets at fair value $ 28,051 $ 7,054 $ — $ 35,105 Liabilities Physical commodity contracts $ — $ 21,115 $ — $ 21,115 Financial commodity contracts 2,997 — — 2,997 Total liabilities at fair value $ 2,997 $ 21,115 $ — $ 24,112 As of September 30, 2022 Assets Physical commodity contracts $ — $ 10,485 $ — $ 10,485 Financial commodity contracts 20,517 — — 20,517 Financial commodity contracts - foreign exchange — 18 — 18 Money market funds 59 — — 59 Other 1,884 — — 1,884 Total assets at fair value $ 22,460 $ 10,503 $ — $ 32,963 Liabilities Physical commodity contracts $ — $ 30,623 $ — $ 30,623 Financial commodity contracts 33,231 168 — 33,399 Financial commodity contracts - foreign exchange — 17 — 17 Total liabilities at fair value $ 33,231 $ 30,808 $ — $ 64,039

INVESTMENTS IN EQUITY INVESTEES

INVESTMENTS IN EQUITY INVESTEES	12 Months Ended
	Sep. 30, 2023
Investments, All Other Investments [Abstract]
INVESTMENTS IN EQUITY INVESTEES	7. INVESTMENTS IN EQUITY INVESTEES Steckman Ridge The Company holds a 50% equity method investment in Steckman Ridge, a jointly owned and controlled natural gas storage facility located in Bedford County, Pennsylvania. The Company’s investment in Steckman Ridge was $104.1M and $106.6M as of September 30, 2023 and 2022, respectively, which includes loans with a total outstanding principal balance of $70.4M for both September 30, 2023 and 2022. On October 1, 2023, we entered into an Amended and Restated Loan Agreement with Steckman Ridge to extend the existing loan agreement for an additional five years and moved from London Interbank Offered Rate to SOFR. These loans accrue interest at a variable rate that resets quarterly and are now due October 1, 2027. NJNG and ES have entered into storage and park and loan agreements with Steckman Ridge. See Note 16. Related Party Transactions for more information on these intercompany transactions. PennEast The Company, through its subsidiary NJR Midstream Company, is a 20% investor in PennEast, a partnership whose purpose was to construct and operate a 120-mile natural gas pipeline that would have extended from northeast Pennsylvania to western New Jersey. During the third quarter of fiscal 2021, the Company recognized an other-than-temporary impairment charge of $92.0M, or approximately $74.5M, net of income taxes, which represented the best estimate of the salvage value of the remaining assets of the project and was recorded in equity in earnings of affiliates in the Consolidated Statements of Operations. In September 2021, the PennEast partnership determined that this project was no longer supported, and all further development ceased. In March 2022, the PennEast board of managers approved cash distributions to members of the partnership following the sale of certain project-related assets and refunds of interconnection fees received from interstate pipelines. The return of capital received by the Company from March 2022 through September 2022 totaled $11.0M and reduced the remaining carrying value of its equity method investment in PennEast to zero in the Consolidated Balance Sheets, with the excess recorded in equity in earnings of affiliates in the Consolidated Statements of Operations. The Company received additional return of capital of $0.3M during fiscal 2023, which is recognized in equity in earnings of affiliates in the Consolidated Statements of Operations. The following is the summarized financial information for Steckman Ridge and PennEast for fiscal years ended September 30: (Thousands) 2023 2022 2021 Steckman Ridge Operating revenues $ 22,659 $ 19,812 $ 21,847 Gross profit $ 13,385 $ 11,349 $ 13,350 Income from continuing operations $ 5,769 $ 8,686 $ 11,483 Net income $ 5,769 $ 8,686 $ 11,483 Net income attributable to NJR $ 2,884 $ 4,343 $ 5,741 Current assets $ 12,724 $ 28,609 Noncurrent assets $ 193,779 $ 198,052 Current liabilities $ 148,577 $ 23,618 Noncurrent liabilities $ — $ 140,810 PennEast Operating revenues $ — $ — $ — Gross profit $ — $ — $ — Loss from continuing operations $ (9,543) $ (3,778) $ (406,305) Net loss $ (9,543) $ (3,778) $ (406,305) Net loss attributable to NJR $ (1,909) $ (756) $ (81,261) Current assets $ 1,481 $ 1,801 Noncurrent assets $ — $ — Current liabilities $ 127 $ 82 Noncurrent liabilities $ — $ 500

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Sep. 30, 2023
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) 2023 2022 2021 Net income, as reported $ 264,724 $ 274,922 $ 117,890 Basic earnings per share Weighted average shares of common stock outstanding-basic 97,028 96,100 96,227 Basic earnings per common share $2.73 $2.86 $1.23 Diluted earnings per share Weighted average shares of common stock outstanding-basic 97,028 96,100 96,227 Incremental shares (1) 599 388 333 Weighted average shares of common stock outstanding-diluted 97,627 96,488 96,560 Diluted earnings per common share $2.71 $2.85 $1.22 (1) Incremental shares consist primarily of unvested stock awards and performance units, which are calculated using the treasury stock method.

DEBT

DEBT	12 Months Ended
	Sep. 30, 2023
Debt Disclosure [Abstract]
DEBT	9. DEBT NJNG and NJR finance working capital requirements and capital expenditures through various short-term debt and long-term financing arrangements, including a commercial paper program and committed unsecured credit facilities. Long-term Debt The following table presents the long-term debt of the Company as of September 30: (Thousands) 2023 2022 NJNG First mortgage bonds: Maturity date: Series OO 3.00% August 1, 2041 46,500 46,500 Series PP 3.15% April 15, 2028 50,000 50,000 Series QQ 3.58% March 13, 2024 70,000 70,000 Series RR 4.61% March 13, 2044 55,000 55,000 Series SS 2.82% April 15, 2025 50,000 50,000 Series TT 3.66% April 15, 2045 100,000 100,000 Series UU 3.63% June 21, 2046 125,000 125,000 Series VV 4.01% May 11, 2048 125,000 125,000 Series WW 3.50% April 1, 2042 10,300 10,300 Series XX 3.38% April 1, 2038 10,500 10,500 Series YY 2.45% April 1, 2059 15,000 15,000 Series ZZ 3.76% July 17, 2049 100,000 100,000 Series AAA 3.86% July 17, 2059 85,000 85,000 Series BBB 2.75% August 1, 2039 9,545 9,545 Series CCC 3.00% August 1, 2043 41,000 41,000 Series DDD 3.13% June 30, 2050 50,000 50,000 Series EEE 3.13% July 23, 2050 50,000 50,000 Series FFF 3.33% July 23, 2060 25,000 25,000 Series GGG 2.87% September 1, 2050 25,000 25,000 Series HHH 2.97% September 1, 2060 50,000 50,000 Series III 2.97% October 28, 2051 50,000 50,000 Series JJJ 3.07% October 28, 2061 50,000 50,000 Series LLL 4.37% May 27, 2037 50,000 50,000 Series MMM 4.71% May 27, 2052 50,000 50,000 Series NNN 5.47% October 24, 2052 125,000 — Series OOO 5.56% September 28, 2033 50,000 — Meter financing obligation Various dates 31,352 30,290 Less: Debt issuance costs (9,770) (9,528) Less: Current maturities of long-term debt (78,477) (6,538) Total NJNG long-term debt 1,410,950 1,307,069 NJR Unsecured senior notes 3.20% August 18, 2023 — 50,000 Unsecured senior notes 3.48% November 7, 2024 100,000 100,000 Unsecured senior notes 3.54% August 18, 2026 100,000 100,000 Unsecured senior notes 3.96% June 8, 2028 100,000 100,000 Unsecured senior notes 3.29% July 17, 2029 150,000 150,000 Unsecured senior notes 3.60% July 23, 2032 130,000 130,000 Unsecured senior notes 3.50% July 23, 2030 130,000 130,000 Unsecured senior notes 3.25% September 1, 2033 80,000 80,000 Unsecured senior notes 3.13% September 1, 2031 120,000 120,000 Unsecured senior notes 4.38% June 23, 2027 110,000 110,000 Unsecured senior notes 3.64% September 19, 2034 50,000 50,000 Unsecured senior notes 6.14% December 15, 2032 50,000 — Less: Debt issuance costs (3,656) (3,753) Less: Current maturities of long-term debt — (50,000) Total NJR long-term debt 1,116,344 1,066,247 CEV Solar asset financing obligation Various dates 278,401 130,618 Less: Current maturities of long-term debt (37,678) (18,532) Total CEV long-term debt 240,723 112,086 Total long-term debt $ 2,768,017 $ 2,485,402 Annual long-term debt redemption requirements, excluding meter financing obligations, debt issuance costs and solar asset financing obligations, as of September 30, are as follows: (Thousands) 2024 2025 2026 2027 2028 Thereafter NJR $ — $ 100,000 $ 100,000 $ 110,000 $ 100,000 $ 710,000 NJNG $ 70,000 $ 50,000 $ — $ — $ 50,000 $ 1,297,845 NJR On October 24, 2022, NJR entered into a Note Purchase Agreement, which closed on December 15, 2022, under which NJR issued $50M, senior notes at a fixed rate of 6.14%, maturing in 2032. The senior notes are unsecured and guaranteed by certain unregulated subsidiaries of NJR. NJNG First Mortgage Bonds NJNG and Trustee entered into the Mortgage Indenture, dated September 1, 2014, which secures all the outstanding FMBs issued by NJNG. The Mortgage Indenture provides a direct first mortgage lien upon substantially all 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 does not restrict 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%. As of September 30, 2023, NJNG’s equity-to-total-capitalization ratio is 54.4% and NJNG has the capacity to issue up to $1.4B of FMB under the terms of the Mortgage Indenture. On October 24, 2022, NJNG entered into a Note Purchase Agreement under which it sold $125M of its senior notes at an interest rate of 5.47%, maturing in 2052. On September 28, 2023, NJNG entered into a Note Purchase Agreement for $100M aggregate principal amount of its senior notes consisting of $50M of 5.56% senior notes due September 28, 2033, which closed on September 28, 2023, and $50M of 5.85% senior notes due October 30, 2053, which closed on October 30, 2023. The senior notes are secured by an equal principal amount of NJNG’s FMBs issued under NJNG’s Mortgage Indenture. Sale Leasebacks NJNG received $8.4M and $17.3M during fiscal 2023 and 2022, respectively, in connection with the sale leaseback of its natural gas meters, with terms ranging from seven Contractual commitments for meter financing obligation payments, which include the most likely outcome of cash payments to the lessor, as of the fiscal years ended September 30, are as follows: (Thousands) 2024 2025 2026 2027 2028 Thereafter Subtotal Lease Payments $ 9,362 7,479 6,407 4,083 4,715 1,676 $ 33,722 Less: Interest component (2,370) Total $ 31,352 Clean Energy Ventures CEV enters into transactions to sell the commercial solar assets concurrent with agreements to lease the assets back over a period of five Contractual commitments for the solar asset financing obligation payments, as of the fiscal years ended September 30, are as follows: (Thousands) 2024 2025 2026 2027 2028 Thereafter Subtotal Lease Payments $ 54,033 50,663 13,875 16,385 26,392 87,881 $ 249,229 Less: Interest component (42,942) Total $ 206,287 Credit Facilities and Short-term Debt On February 7, 2023, NJR's 364-day $150M term loan credit agreement, that was entered into in February 2022, expired. The Company had $50M that was borrowed on February 9, 2022 and $100M that was borrowed on February 14, 2022, which was paid in full at expiration of the term loan agreement. The following table summarizes NJR’s credit facility and NJNG’s commercial paper program and credit facility as of September 30: At end of period (Thousands) Total borrowing capacity Loans outstanding Weighted average interest rate Remaining borrowing capacity Expiration dates 2023 NJR Bank revolving credit facilities (1) $ 650,000 $ 217,300 6.53 % $ 426,967 (2) Sep 2027 NJNG Bank revolving credit facilities (3) $ 250,000 $ 34,800 5.48 % $ 214,469 (4) Sep 2027 2022 NJR Bank revolving credit facilities (1) $ 650,000 $ 200,150 3.97 % $ 440,177 (2) Sep 2027 Bank term loan credit agreement $ 150,000 $ 150,000 3.81 % $ — Feb 2023 NJNG Bank revolving credit facilities (3) $ 250,000 $ 73,800 3.34 % $ 175,469 (4) Sep 2027 (1) Committed credit facilities, which require commitment fees of 0.10% on the unused amounts. (2) Letters of credit outstanding total $5.7M and $9.7M as of September 30, 2023 and September 30, 2022, respectively, which reduces amount available by the same amount. (3) Committed credit facilities, which require commitment fees of 0.075% on the unused amounts. (4) Letters of credit outstanding total $0.7M as of both September 30, 2023 and 2022, which reduces amount available by the same amount. Amounts available under credit facilities are reduced by bank or commercial paper borrowings, as applicable, and any outstanding letters of credit. Neither NJNG nor the results of its operations are obligated or pledged to support the NJR credit or debt shelf facilities. NJR On August 30, 2022, NJR entered into a First Amendment to NJR’s Second Amended and Restated Credit Agreement governing a $650M NJR Credit Facility with a maturity date of September 2, 2027. The NJR Credit Facility is subject to a one-year extension beyond that date and includes an accordion feature, which allows 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 increments of $50M, with the total revolving credit commitments not exceeding $750M. The NJR Credit Facility also permits the borrowing of revolving loans and swingline loans, as well as a $75M sublimit for the issuance of letters of credit. Certain of NJR’s unregulated subsidiaries have guaranteed all of NJR’s obligations under the NJR Credit Facility. The credit facility is used primarily to finance its share repurchases, to satisfy ES’s short-term liquidity needs and to finance, on an initial basis, unregulated investments. As of September 30, 2023, NJR had seven letters of credit outstanding totaling $5.7M on behalf of ES and CEV. 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. ES’s letters of credit are used for margin requirements for natural gas transactions, collateral and security deposit for retail natural gas sales, and they expire on dates ranging from September 2024 to December 2024. Neither NJNG nor the results of its operations are obligated or pledged to support the NJR credit or debt shelf facilities. NJNG On August 30, 2022, NJNG amended the Second Amended and Restated Credit Agreement governing a $250M NJNG Credit Facility with a maturity date of September 2, 2027. The NJNG Credit Facility is subject to a one-year extension beyond that date and includes an accordion feature, which allows NJNG, 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 NJNG Credit Facility in minimum increments of $50M up to a maximum of $100M. The NJNG Credit Facility also permits the borrowing of revolving loans and swingline loans, as well as a $30M sublimit for the issuance of letters of credit. As of September 30, 2023, NJNG has two letters of credit outstanding for $0.7M, which reduced the amount available under the NJNG Credit Facility by the same amount. NJNG does not anticipate that these letters of credit will be drawn upon by the counterparties.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Sep. 30, 2023
Share-Based Payment Arrangement [Abstract]
STOCK-BASED COMPENSATION	10. STOCK-BASED COMPENSATION In January 2017, the NJR 2017 Stock Award and Incentive Plan replaced the NJR 2007 Stock Award and Incentive Plan. Shares have been issued in the form of performance share units, restricted stock units, deferred retention stock units and unrestricted common stock to non-employee directors. As of September 30, 2023, 2,774,527 shares remain available for future issuance. The following table summarizes all stock-based compensation expense recognized during the following fiscal years: (Thousands) 2023 2022 2021 Stock-based compensation expense: Performance share awards $ 4,882 $ 4,131 $ 3,856 Restricted and non-restricted stock 3,647 3,189 3,193 Deferred retention stock 6,187 7,507 100 Compensation expense included in operation and maintenance expense 14,716 14,827 7,149 Income tax benefit (1) (3,563) (3,624) (1,613) Total, net of tax $ 11,153 $ 11,203 $ 5,536 (1) Excludes additional tax (expense) benefit related to delivered shares of $(0.6)M, $(0.1)M and $(0.2)M as of September 30, 2023, 2022 and 2021, respectively. Performance Share Units In fiscal 2023, the Company granted to certain officers 39,614 performance shares, which are market condition awards that vest on September 30, 2025, subject to the Company meeting certain conditions. In fiscal 2023, the Company also granted to certain officers 73,047 performance shares, of which 42,449 vest on September 30, 2025 and 30,598 vest annually over a three-year period beginning in September 2023, both of which are subject to the Company meeting certain performance conditions. In fiscal 2022, the Company granted to certain officers 44,965 performance shares, which are market condition awards that vest on September 30, 2024, subject to the Company meeting certain conditions. In fiscal 2022, the Company also granted to certain officers 73,561 performance shares, of which 44,596 vest on September 30, 2024 and 28,965 vest annually over a three-year period beginning in September 2022, both of which are subject to the Company meeting certain performance conditions. In fiscal 2021, the Company granted to certain officers 46,813 performance shares, which are market condition awards that vested on September 30, 2023, subject to the Company meeting certain conditions. In fiscal 2021, the Company also granted to certain officers 70,138 performance shares, of which 44,156 vested in September 30, 2023 and 25,982 vest annually over a three-year period beginning in September 2021, 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 $5.2M 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 Total Fair Value of Vested Shares (in Thousands) Non-vested and outstanding at September 30, 2020 155,731 $44.22 — Granted 116,951 $33.34 — Vested (2) (54,918) $44.64 $ 1,673 Cancelled/forfeited (51,673) $45.32 — Non-vested and outstanding at September 30, 2021 166,091 $36.08 — Granted 118,526 $38.84 — Vested (3) (76,708) $39.57 $ 2,765 Cancelled/forfeited (15,788) $37.33 — Non-vested and outstanding at September 30, 2022 192,121 $36.29 — Granted 112,661 $46.00 — Vested (4) (105,197) $35.07 $ 4,126 Cancelled/forfeited (9,330) $38.64 — Non-vested and outstanding at September 30, 2023 190,255 $42.60 — (1) The number of common shares issued related to certain performance shares may range from zero to 150% 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, 2021, there were no common shares earned related to TSR performance, the number of common shares earned related to NFE performance was 93% or 31,116 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100% or 25,982 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100%. (3) As certified by the Company’s Leadership and Compensation Committee on November 9, 2022, the number of common shares earned related to TSR performance was 112% or 30,472 shares, the number of common shares earned related to NFE performance was 105% or 26,282 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100% or 28,965 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100%. (4) As certified by the Company’s Leadership and Compensation Committee on November 15, 2023, the number of common shares earned related to TSR performance was 150% or 59,192 shares, the number of common shares earned related to NFE performance was 150% or 55,832 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100% or 30,598 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100%. 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 the grant date and are subsequently adjusted for actual achievement of the performance goals. Restricted Stock Units The Company granted 64,080, 54,826 and 67,726 shares of restricted stock during fiscal 2023, 2022 and 2021, respectively. The shares vest annually over a three-year period beginning in October of the fiscal year in which they were granted. There is approximately $1.4M of deferred compensation related to unvested restricted stock shares that is expected to be recognized over the weighted average period of 1.8 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 Total Fair Value of Vested Shares (in Thousands) Non-vested and outstanding at September 30, 2020 73,486 $43.52 — Granted 67,726 $33.34 — Vested (34,000) $44.30 $ 996 Cancelled/forfeited (5,591) $36.34 — Non-vested and outstanding at September 30, 2021 101,621 $36.87 — Granted 54,826 $38.84 — Vested (47,867) $39.01 $ 1,824 Cancelled/forfeited (10,756) $37.06 — Non-vested and outstanding at September 30, 2022 97,824 $36.90 — Granted 64,080 $46.00 — Vested (48,312) $40.30 $ 1,910 Cancelled/forfeited (4,716) $38.77 — Non-vested and outstanding at September 30, 2023 108,876 $41.55 — Deferred Retention Stock Units Deferred retention stock awards are granted upon approval by the Board of Directors, which generally occurs subsequent to the fiscal year end. 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 following table summarizes the deferred retention stock award under the stock award and incentive plans for the past three fiscal years: Shares Weighted Average Total Fair Value of Vested Shares (in Thousands) Outstanding at September 30, 2020 228,246 $46.32 — Granted/Vested 2,999 $33.34 — Delivered (22,389) $45.00 $ 641 Outstanding at September 30, 2021 208,856 $46.28 — Granted/Vested 192,728 $38.95 — Delivered (163,499) $47.95 $ 6,167 Forfeited (6,818) $40.33 — Outstanding at September 30, 2022 231,267 $39.16 — Granted/Vested 134,941 $45.85 — Delivered (38,115) $40.67 $ 1,517 Outstanding at September 30, 2023 328,093 $41.74 — Non-Employee Director Stock Non-employee director compensation includes an annual equity retainer that is awarded at the time of the Company’s annual meeting of shareowners. The shares vest upon the earlier of the first anniversary of the grant date or the date of the Company’s next annual meeting of shareowners following the grant date 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: 2023 2022 2021 Shares granted 24,044 (1) 30,908 34,994 Weighted average grant date fair value $49.58 $39.09 $35.72 (1) Approximately $0.3M of expense remains as of September 30, 2023, to be recognized through December 31, 2023.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Sep. 30, 2023
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 non-represented 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 are 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 2023 and 2022, the Company had no minimum funding requirements and did not make any discretionary contributions to the pension plans. The Company does not expect to be required to make additional contributions to fund the pension plans during the next fiscal year 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 $4.2M and $6.1M in fiscal 2023 and 2022, respectively, and estimates that it will contribute between $5M and $10M 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) 2023 2022 2023 2022 Change in Benefit Obligation Benefit obligation at beginning of year $ 290,823 $ 395,547 $ 173,217 $ 244,674 Service cost 5,402 8,291 2,471 4,305 Interest cost 15,174 9,632 9,146 6,355 Plan participants’ contributions (2) 32 59 552 423 Actuarial (gain) loss (7,057) (109,320) 25,363 (77,775) Benefits paid, net of retiree subsidies received (14,053) (13,386) (7,343) (4,765) Benefit obligation at end of year $ 290,321 $ 290,823 $ 203,406 $ 173,217 Change in plan assets Fair value of plan assets at beginning of year $ 284,347 $ 355,284 $ 99,736 $ 114,183 Actual return (loss) on plan assets 27,456 (58,239) 9,826 (15,996) Employer contributions 579 628 4,192 6,082 Benefits paid, net of plan participants’ contributions (2) (14,021) (13,326) (6,971) (4,533) Fair value of plan assets at end of year $ 298,361 $ 284,347 $ 106,783 $ 99,736 Funded status $ 8,040 $ (6,476) $ (96,623) $ (73,481) Amounts recognized on Consolidated Balance Sheets Postemployment employee benefit asset Noncurrent $ 18,684 $ 4,388 $ — $ — Postemployment employee benefit liability Current $ (538) $ (578) $ (4,201) $ (900) Noncurrent (10,106) (10,286) (92,422) (72,581) Total $ 8,040 $ (6,476) $ (96,623) $ (73,481) (1) Includes the Company’s PEP. (2) Employees hired prior to July 1, 1998, that were eligible to elect an additional participant contribution to enhance their benefits, and contributions made during the periods were immaterial. The Company recognizes a liability for its underfunded benefit plans as required by ASC 715, Compensation - Retirement Benefits . The Company records the offset to regulatory assets for the portion of liability relating to NJNG and to accumulated OCI for the portion of the liability related to its unregulated operations. The following table summarizes the amounts recognized in regulatory assets and accumulated OCI as of September 30: Regulatory Assets Accumulated Other Comprehensive Income (Loss) (Thousands) Pension OPEB Pension OPEB Balance at September 30, 2021 $ 56,187 $ 60,335 $ 22,790 $ 12,696 Amounts arising during the period: Net actuarial (gain) (14,922) (35,781) (14,885) (18,422) Amounts amortized to net periodic costs: Net actuarial (loss) (5,843) (4,577) (2,902) (1,107) Prior service (cost) credit (101) 133 — 11 Balance at September 30, 2022 $ 35,321 $ 20,110 $ 5,003 $ (6,822) Amounts arising during the period: Net actuarial (gain) loss (10,493) 9,936 (4,048) 12,320 Amounts amortized to net periodic costs: Net actuarial (loss) (87) — (213) — Prior service (cost) (103) — — — Balance at September 30, 2023 $ 24,638 $ 30,046 $ 742 $ 5,498 The amounts in regulatory assets and accumulated OCI not yet recognized as components of net periodic benefit cost as of September 30 are: Regulatory Assets Accumulated Other Comprehensive Pension OPEB Pension OPEB (Thousands) 2023 2022 2023 2022 2023 2022 2023 2022 Net actuarial loss (gain) $ 24,577 $ 35,157 $ 30,046 $ 20,110 $ 742 $ 5,003 $ 5,498 $ (6,822) Prior service cost 61 164 — — — — — — Total $ 24,638 $ 35,321 $ 30,046 $ 20,110 $ 742 $ 5,003 $ 5,498 $ (6,822) To the extent the unrecognized amounts in accumulated OCI or regulatory assets exceed 10% 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 OCI expected to be recognized as components of net periodic benefit cost in fiscal 2024 are as follows: Regulatory Assets Accumulated Other Comprehensive Income (Loss) (Thousands) Pension OPEB Pension OPEB Net actuarial loss (gain) $ 815 $ 667 $ (12) $ 661 Prior service cost 62 — — — Total $ 877 $ 667 $ (12) $ 661 The projected benefit and accumulated benefit obligations and the fair value of plan assets as of September 30, are as follows: Pension (Thousands) 2023 2022 Projected benefit obligation $ 290,321 $ 290,823 Accumulated benefit obligation $ 267,794 $ 265,933 Fair value of plan assets $ 298,361 $ 284,347 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) 2023 2022 2021 2023 2022 2021 Service cost $ 5,402 $ 8,291 $ 8,730 $ 2,471 $ 4,305 $ 4,844 Interest cost 15,174 9,632 9,112 9,146 6,355 6,071 Expected return on plan assets (19,972) (21,275) (20,150) (6,721) (7,575) (6,497) Recognized actuarial loss 300 8,745 11,446 — 5,684 7,909 Prior service cost (credit) amortization 103 101 102 — (144) (179) Net periodic benefit cost recognized as expense $ 1,007 $ 5,494 $ 9,240 $ 4,896 $ 8,625 $ 12,148 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 2023 2022 2021 2023 2022 2021 Benefit costs: Discount rate 5.50/5.50% (1) 3.10/3.07% (1) 2.95/2.92% (1) 5.51/5.51% (1) 3.24/3.17% (1) 3.08/3.03% (1) Expected asset return 7.00 % 6.75 % 6.75 % 7.00 % 6.75 % 6.75 % Compensation increase 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) Obligations: Discount rate 5.89/5.87% (1) 5.50/5.50% (1) 3.10/3.07% (1) 5.97/5.94% (1) 5.51/5.51% (1) 3.24/3.17% (1) Compensation increase 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) (1) Percentages for represented and non-represented plans, respectively. When measuring its PBO, 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. The Company measures its service and interest costs using a disaggregated, or spot rate, 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, which aligns the timing of the plans’ separate future cash flows to the corresponding spot rates on the yield curve. Information relating to the assumed HCCTR used to determine expected OPEB benefits as of September 30, and the effect of a 1% change in the rate, are as follows: ($ in thousands) 2023 2022 2021 HCCTR 7.4% 6.6% 6.9% Ultimate HCCTR 4.5% 4.5% 4.5% Year ultimate HCCTR reached 2032 2027 2027 Effect of a 1 percentage point increase in the HCCTR on: Year-end benefit obligation $ 30,818 $ 26,710 $ 43,217 Total service and interest cost $ 2,117 $ 2,544 $ 2,959 Effect of a 1 percentage point decrease in the HCCTR on: Year-end benefit obligation $ (25,283) $ (21,853) $ (34,669) Total service and interest costs $ (1,700) $ (1,966) $ (2,253) The Company’s investment objective is a long-term real rate of return on assets before permissible expenses that is approximately 5% 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: 2024 Assets at Target September 30, Asset Allocation Allocation 2023 2022 U.S. equity securities 34 % 34 % 32 % International equity securities 17 16 16 Fixed income 33 31 32 Collective investment trusts at NAV 16 19 20 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 U.S. The adoption of the new mortality projection scale, MP-2021, and the Pri-2012 mortality study, did not materially impact 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 fiscal years: (Thousands) 2024 2025 2026 2027 2028 2029 - 2033 Pension $ 15,227 $ 16,233 $ 17,255 $ 18,246 $ 19,219 $ 110,341 OPEB $ 6,925 $ 7,602 $ 8,481 $ 9,337 $ 10,211 $ 63,780 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. Estimated subsidy payments for fiscal 2024 and 2025 are immaterial and zero thereafter. Pension and OPEB assets held in the master trust, measured at fair value, are summarized as follows: Pension OPEB (Thousands) Quoted Prices in Active Markets for Identical Assets Total Quoted Prices in Active Markets for Identical Assets Total As of September 30, 2023 Assets Registered Investment Companies: Equity Funds: Large Cap Index 81,171 81,171 30,884 30,884 Extended Market Index 17,256 17,256 6,444 6,444 International Stock 48,557 48,557 17,966 17,966 Fixed Income Funds: Emerging Markets 11,471 11,471 4,306 4,306 Core Fixed Income — — 22,241 22,241 High Yield Bond Fund 20,685 20,685 7,651 7,651 Long Duration Fund 58,484 58,484 — — Total assets in the fair value hierarchy $ 237,624 237,624 $ 89,492 89,492 Investments measured at net asset value Collective investment trusts 60,737 17,291 Total assets at fair value $ 298,361 $ 106,783 As of September 30, 2022 Assets Money market funds $ — $ — $ 28 $ 28 Registered Investment Companies: Equity Funds: Large Cap Index 75,394 75,394 26,939 26,939 Extended Market Index 15,783 15,783 5,578 5,578 International Stock 44,846 44,846 16,106 16,106 Fixed Income Funds: Emerging Markets 11,074 11,074 4,026 4,026 Core Fixed Income — — 16,594 16,594 Opportunistic Income — — 3,283 3,283 Ultra Short Duration — — 3,296 3,296 High Yield Bond Fund 19,816 19,816 7,320 7,320 Long Duration Fund 59,084 59,084 — — Total assets in the fair value hierarchy $ 225,997 225,997 $ 83,170 83,170 Investments measured at net asset value Collective investment trusts 58,350 16,566 Total assets at fair value $ 284,347 $ 99,736 The Plan had no Level 2 or Level 3 fair value measurements during fiscal 2023 and 2022, and there have been no changes in valuation methodologies as of September 30, 2023. The Plan held assets that are valued using NAV as a practical expedient, which are excluded from the fair value hierarchy. The following is a description of the valuation methodologies used for assets measured at fair value: Asset Types Description of the Valuation Methodologies Money Market funds Represents bank balances and money market funds that are valued based on the NAV of shares held at year end. Registered Investment Companies Equity and fixed income funds valued at the NAV of shares held by the plan at year end as reported on the active market on which the individual securities are traded. Collective investment trusts The NAV for collective investment trusts is provided by the Trustee and is used as a practical expedient to estimate fair value. The NAV is based on the value of the underlying assets owned by the fund less liabilities. 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. The Company matches 85% of participants’ contributions up to 6% 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 3.5% and 4.5% 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 $5.9M in fiscal 2023, $5.5M in fiscal 2022 and $5.1M in fiscal 2021. The amount contributed for the employer special contribution of the Savings Plan was $2.1M in fiscal 2023, $2.4M in fiscal 2022 and $2.1M in fiscal 2021.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Sep. 30, 2023
Income Tax Disclosure [Abstract]
INCOME TAXES	12. INCOME TAXES The income tax provision from operations for the fiscal years ended September 30, consists of the following: (Thousands) 2023 2022 2021 Current: Federal $ 13,393 $ 4,238 $ 651 State 7,716 2,104 1,703 Deferred: Federal 36,825 55,968 25,030 State (8,381) 14,185 6,224 Investment/production tax credits (278) (300) (322) Income tax provision $ 49,275 $ 76,195 $ 33,286 As of September 30, the temporary differences, which give rise to deferred tax assets (liabilities), consist of the following: (Thousands) 2023 2022 Deferred tax assets Investment tax credits (1) $ 191,948 $ 212,506 State net operating losses 39,612 36,950 Deferred revenue 8,205 — Fair value of derivatives 5,386 6,506 Impairment of equity method investment 14,004 14,124 Postemployment benefits 6,502 2,751 Incentive compensation 8,949 7,297 Amortization of intangibles 6,308 6,474 Overrecovered natural gas costs 8,564 4,977 Allowance for doubtful accounts 4,485 5,761 Other 7,636 5,748 Total deferred tax assets 301,599 303,094 Less: Valuation allowance (5,747) (22,241) Total deferred tax assets net of valuation allowance $ 295,852 $ 280,853 Deferred tax liabilities Property-related items $ (487,294) $ (468,115) Remediation costs (18,532) (18,490) Investments in equity investees (28,325) (19,176) Conservation incentive program (14,075) (6,457) Other (4,670) (4,615) Total deferred tax liabilities $ (552,896) $ (516,853) Total net deferred tax liabilities $ (257,044) $ (236,000) (1) Includes approximately $0.7M for NJNG for both fiscal 2023 and 2022, which is being amortized over the life of the related assets. A reconciliation of the U.S. federal statutory rate to the effective rate from operations for the fiscal years ended September 30, is as follows: (Thousands) 2023 2022 2021 Statutory income tax expense $ 65,940 $ 73,735 $ 31,747 Change resulting from: Investment/production tax credits (278) (300) (322) Cost of removal of assets placed in service prior to 1981 (4,758) (3,533) (5,366) AFUDC equity (1,499) (2,361) (786) State income taxes, net of federal benefit 13,293 13,072 6,124 Valuation allowance (16,494) (1,372) 5,974 Tax Act - utility excess deferred income taxes amortized (3,573) (3,573) (3,573) Other (3,356) 527 (512) Income tax provision $ 49,275 $ 76,195 $ 33,286 Effective income tax rate 15.7 % 21.7 % 22.0 % 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, Florida, Indiana, Louisiana, Maryland, Michigan, Mississippi, New Jersey, New York, North Carolina, Pennsylvania, Rhode Island, Texas and Virginia. 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 U.S. federal income tax returns through fiscal 2019 have either been reviewed by the IRS, or the related statute of limitations has expired and all matters have been settled. U.S. federal income tax returns for periods subsequent to fiscal 2019 are open to examination by the IRS. For all periods subsequent to those ended September 30, 2019, the Company’s state income tax returns are statutorily open to examination in all applicable states with the exception of Colorado, New Jersey and Texas. In Colorado, New Jersey and Texas, all periods subsequent to September 30, 2018, are statutorily open to examination. NJR evaluates its tax positions to determine the appropriate accounting and recognition of potential future obligations associated with uncertain tax positions. A tax benefit claimed, or expected to be claimed, on a tax return may be recognized only if it is more likely than not that the tax position will be upheld upon examination by the applicable taxing authority and is measured based on the largest tax benefit that is more than 50% likely to be realized. Interest and penalties related to unrecognized tax benefits, if any, are recognized within income tax expense, and accrued interest and penalties are recognized within other noncurrent liabilities on the Consolidated Balance Sheets. CARES Act On March 27, 2020, the President of the U.S. signed the CARES Act, which is aimed at providing emergency assistance and health care for individuals, families, and businesses affected by the COVID-19 pandemic and generally supporting the U.S. economy. The CARES Act provided for the delay in the required deposit of the employer portion of the OASDI payroll tax from the date of enactment through the end of 2020. Of the taxes that the Company can defer, 50% of the deferred taxes were required to be deposited by the end of 2021 and the remaining 50% were required to be deposited by the end of 2022. As of September 30, 2021, the Company deferred approximately $5.1M related to the employer portion of the OASDI tax. During fiscal 2022, the Company made the first of two installment payments, which reduced the balance to approximately $2.7M. The second installment payment was made during the first quarter of fiscal 2023, which reduced the balance to zero as of September 30, 2023. Inflation Reduction Act In August 2022, the President of the U.S. signed the Inflation Reduction Act, which contains provisions addressing inflation, clean energy, healthcare and taxes beginning in 2023. The Inflation Reduction Act imposes a 15% minimum tax rate on corporations with higher than $1B of annual income, along with a 1% excise tax on corporate stock repurchases. The Inflation Reduction Act raised the ITC from 26% to 30% through the end of 2032, dropping to 26% for property under construction before the end of 2033 and to 22% for property under construction before the end of 2034. The ITC expires starting in 2035 unless it is renewed. There are additional opportunities to increase the credit amount for certain facilities that are placed in service after December 31, 2022. The credit amount can be increased by 10% if certain domestic content requirements are satisfied or if the facility is located in an energy community, such as a brownfield site. ITCs are also expanded to include stand-alone energy storage projects without being integrated into a solar facility, allowing solar to claim production tax credits that are a production-based credit extending for 10 years following the placed-in-service date of the facility, and introducing the concept of transferability of tax credits, providing an additional option to monetize such credits. The Company evaluated the impacts of the Inflation Reduction Act on its financial position, results of operations and cash flows, noting the corporate alternative minimum tax does not impact the Company as the applicable income thresholds have not been met. Upon the repurchase of common stock through the Company’s share repurchase program, the Company would be subject to the 1% excise tax. Other Tax Items As of September 30, 2023 and 2022, the Company has tax credit carryforwards of approximately $191.2M and $211.8M, respectively, which each have a life of 20 years. The Company expects to utilize this entire carryforward prior to expiration, which would begin in fiscal 2036. The impairment of the equity method investment in PennEast created net capital loss attributes totaling approximately $56.6M, which could only be utilized to offset capital gains income and carried back three years and forward five years prior to expiration. During the fourth quarter of fiscal 2023, the Company determined that the tax losses created by the impairment may qualify as an ordinary loss, rather than a capital loss. As of September 30, 2023 and 2022, the Company had a valuation allowance of approximately $5.0M and $5.1M, respectively. As of September 30, 2023, the Company evaluated certain tax benefits recorded in the Consolidated Financial Statements and concluded that a portion of the tax benefits are uncertain at this time. As a result, the Company recorded a reserve for uncertain tax benefits. The reserve for uncertain tax benefits is as follows: (Thousands) 2023 2022 Balance at October 1, $ — $ — Additions based on tax positions related to the current fiscal period 4,978 — Balance at September 30, $ 4,978 $ — As of September 30, 2023, there are $5.0M of unrecognized tax benefits that if recognized would affect the annual effective tax rate. The tax benefits relate to fiscal tax years open to examination by the IRS and the state of Pennsylvania and may be subject to subsequent adjustment. As of September 30, 2023 and 2022, the Company has state income tax net operating losses of approximately $631.2M and $544.4M, 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 As of September 30, 2022, the Company had a valuation allowance of approximately $17.2M related to the recognition of state net operating loss carryforwards. As of September 30, 2023, it was determined that the realization of certain deferred tax assets was more likely than not, and thus the associated valuation allowance of approximately $15.8M was no longer required. Reversal of the valuation allowance resulted in a corresponding income tax benefit on the Consolidated Statement of Operations. As of September 30, 2023, the remaining valuation allowance of approximately $0.7M related primarily to other state income tax attributes which the Company could not conclude were realizable on a more-likely-than-not basis. The Consolidated Appropriations Act extended the 30% ITC for solar property that is under construction on or before December 31, 2019. Projects placed in service after December 31, 2019, may also qualify for a 30% federal ITC if 5% or more of the total costs of a solar property are incurred before the end of the applicable year and there are continuous efforts to advance toward completion of the project, based on the IRS guidance around ITC safe harbor determination. The credit declined to 26% for property under construction before the end of 2020. The Consolidated Appropriations Act of 2021 extended the 26% tax credit for property under construction during 2021 and 2022. The Inflation Reduction Act raised the ITC from 26% to 30% through the end of 2032, as previously stated.

LEASES

LEASES	12 Months Ended
	Sep. 30, 2023
Leases [Abstract]
LEASES	13. LEASES Lessee Accounting The Company determines if an arrangement is a lease at inception based on whether the Company has the right to control the use of an identified asset, the right to obtain substantially all of the economic benefits from the use of the asset and the right to direct the use of the asset. After the criteria are satisfied, the Company accounts for these arrangements as leases in accordance with ASC 842, Leases . Right-of-use assets represent the Company’s right to use the underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. Right-of-use assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Company is the lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement date, is utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. The Company uses the implicit rate for agreements in which it is a lessor. The Company has not entered into any material agreements in which it is a lessor. Lease expense and lease income are recognized on a straight-line basis over the lease term for operating leases. The Company’s lease agreements primarily consist of commercial solar land leases, storage and capacity leases, equipment and real property, including land and office facilities, office equipment and the sale leaseback of certain natural gas meters. Certain leases contain escalation provisions for inflation metrics. The storage leases contain a variable payment component that relates to the change in the inflation metrics that are not known past the current payment period. The variable components of these lease payments are excluded from the lease payments that are used to determine the related right-of-use lease asset and liability. The variable portion of these leases are recognized as leasing expenses when they are incurred. The capacity lease payments are fully variable and based on the amount of natural gas stored in the storage caverns. Generally, the Company’s solar land lease terms are between 20 and 50 years and may include multiple options to extend the terms for an additional five two seven Leases . The Company has lease agreements with lease and non-lease components and has elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings, solar land leases and office equipment. Variable payments are not considered material to the Company. The Company’s lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. In July 2021, NJNG entered into 16-year lease agreements, as Lessor, with various NJR subsidiaries, as Lessees, for office space at the Company’s headquarters in Wall, New Jersey, the effects of which are eliminated in consolidation. The following table presents the Company’s lease costs included in the Consolidated Statements of Operations for the fiscal year ended September 30: (Thousands) Income Statement Location 2023 2022 2021 Operating lease cost (1) Operation and maintenance $ 9,336 $ 9,702 $ 8,182 Finance lease cost Amortization of right-of-use assets Depreciation and amortization 2,105 1,769 $ 3,442 Interest on lease liabilities Interest expense, net of capitalized interest 1,084 612 710 Total finance lease cost $ 3,189 $ 2,381 4,152 Short-term lease cost Operation and maintenance — 34 543 Variable lease cost Operation and maintenance 1,128 781 1,381 Total lease cost $ 13,653 $ 12,898 $ 14,258 (1) Net of capitalized costs. The following table presents supplemental cash flow information related to leases for the fiscal year ended September 30: (Thousands) 2023 2022 2021 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for operating leases $ 8,942 $ 7,417 $ 6,675 Operating cash flows for finance leases $ 1,084 $ 831 $ 1,167 Financing cash flows for finance leases $ 7,379 $ 7,145 $ 8,180 Assets obtained or modified for operating lease liabilities totaled approximately $13.2M and $0.9M during fiscal 2023 and 2022, respectively. Assets obtained or modified through other leases, including those which are finance leases and financing transactions for accounting purposes, totaled approximately $8.4M and $17.3M during fiscal 2023 and 2022, respectively. The following table presents the balance and classifications of the Company’s right of use assets and lease liabilities included in the Consolidated Balance Sheets for the fiscal year ended September 30: (Thousands) Balance Sheet Location 2023 2022 Assets Noncurrent Operating lease assets Operating lease assets $ 175,740 $ 168,520 Finance lease assets Utility plant 28,248 21,913 Total lease assets $ 203,988 $ 190,433 Liabilities Current Operating lease liabilities Operating lease liabilities $ 4,772 $ 4,562 Finance lease liabilities Current maturities of long-term debt 8,477 6,538 Noncurrent Operating lease liabilities Operating lease liabilities 148,023 138,382 Finance lease liabilities Long-term debt 22,875 23,752 Total lease liabilities $ 184,147 $ 173,234 For operating lease assets and liabilities, the weighted average remaining lease term was 29.2 years for both September 30, 2023 and 2022, and the weighted average discount rate used in the valuation over the remaining lease term was 3.5% and 3.2% for September 30, 2023 and 2022, respectively. For finance lease assets and liabilities as of September 30, 2023 and 2022, the weighted average remaining lease term was 3.3 years and 4.0 years, respectively, and the weighted average discount rate used in the valuation over the remaining lease term was 2.7% as of both September 30, 2023 and 2022. The following table presents the Company’s maturities of lease liabilities as of September 30, 2023: (Thousands) Operating Finance 2024 $ 7,913 $ 9,362 2025 7,875 7,479 2026 7,799 6,407 2027 7,743 4,083 2028 7,803 4,715 Thereafter 213,927 1,676 Total future payments 253,060 33,722 Less: interest (100,265) (2,370) Total liability $ 152,795 $ 31,352
LEASES	13. LEASES Lessee Accounting The Company determines if an arrangement is a lease at inception based on whether the Company has the right to control the use of an identified asset, the right to obtain substantially all of the economic benefits from the use of the asset and the right to direct the use of the asset. After the criteria are satisfied, the Company accounts for these arrangements as leases in accordance with ASC 842, Leases . Right-of-use assets represent the Company’s right to use the underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. Right-of-use assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Company is the lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement date, is utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. The Company uses the implicit rate for agreements in which it is a lessor. The Company has not entered into any material agreements in which it is a lessor. Lease expense and lease income are recognized on a straight-line basis over the lease term for operating leases. The Company’s lease agreements primarily consist of commercial solar land leases, storage and capacity leases, equipment and real property, including land and office facilities, office equipment and the sale leaseback of certain natural gas meters. Certain leases contain escalation provisions for inflation metrics. The storage leases contain a variable payment component that relates to the change in the inflation metrics that are not known past the current payment period. The variable components of these lease payments are excluded from the lease payments that are used to determine the related right-of-use lease asset and liability. The variable portion of these leases are recognized as leasing expenses when they are incurred. The capacity lease payments are fully variable and based on the amount of natural gas stored in the storage caverns. Generally, the Company’s solar land lease terms are between 20 and 50 years and may include multiple options to extend the terms for an additional five two seven Leases . The Company has lease agreements with lease and non-lease components and has elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings, solar land leases and office equipment. Variable payments are not considered material to the Company. The Company’s lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. In July 2021, NJNG entered into 16-year lease agreements, as Lessor, with various NJR subsidiaries, as Lessees, for office space at the Company’s headquarters in Wall, New Jersey, the effects of which are eliminated in consolidation. The following table presents the Company’s lease costs included in the Consolidated Statements of Operations for the fiscal year ended September 30: (Thousands) Income Statement Location 2023 2022 2021 Operating lease cost (1) Operation and maintenance $ 9,336 $ 9,702 $ 8,182 Finance lease cost Amortization of right-of-use assets Depreciation and amortization 2,105 1,769 $ 3,442 Interest on lease liabilities Interest expense, net of capitalized interest 1,084 612 710 Total finance lease cost $ 3,189 $ 2,381 4,152 Short-term lease cost Operation and maintenance — 34 543 Variable lease cost Operation and maintenance 1,128 781 1,381 Total lease cost $ 13,653 $ 12,898 $ 14,258 (1) Net of capitalized costs. The following table presents supplemental cash flow information related to leases for the fiscal year ended September 30: (Thousands) 2023 2022 2021 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for operating leases $ 8,942 $ 7,417 $ 6,675 Operating cash flows for finance leases $ 1,084 $ 831 $ 1,167 Financing cash flows for finance leases $ 7,379 $ 7,145 $ 8,180 Assets obtained or modified for operating lease liabilities totaled approximately $13.2M and $0.9M during fiscal 2023 and 2022, respectively. Assets obtained or modified through other leases, including those which are finance leases and financing transactions for accounting purposes, totaled approximately $8.4M and $17.3M during fiscal 2023 and 2022, respectively. The following table presents the balance and classifications of the Company’s right of use assets and lease liabilities included in the Consolidated Balance Sheets for the fiscal year ended September 30: (Thousands) Balance Sheet Location 2023 2022 Assets Noncurrent Operating lease assets Operating lease assets $ 175,740 $ 168,520 Finance lease assets Utility plant 28,248 21,913 Total lease assets $ 203,988 $ 190,433 Liabilities Current Operating lease liabilities Operating lease liabilities $ 4,772 $ 4,562 Finance lease liabilities Current maturities of long-term debt 8,477 6,538 Noncurrent Operating lease liabilities Operating lease liabilities 148,023 138,382 Finance lease liabilities Long-term debt 22,875 23,752 Total lease liabilities $ 184,147 $ 173,234 For operating lease assets and liabilities, the weighted average remaining lease term was 29.2 years for both September 30, 2023 and 2022, and the weighted average discount rate used in the valuation over the remaining lease term was 3.5% and 3.2% for September 30, 2023 and 2022, respectively. For finance lease assets and liabilities as of September 30, 2023 and 2022, the weighted average remaining lease term was 3.3 years and 4.0 years, respectively, and the weighted average discount rate used in the valuation over the remaining lease term was 2.7% as of both September 30, 2023 and 2022. The following table presents the Company’s maturities of lease liabilities as of September 30, 2023: (Thousands) Operating Finance 2024 $ 7,913 $ 9,362 2025 7,875 7,479 2026 7,799 6,407 2027 7,743 4,083 2028 7,803 4,715 Thereafter 213,927 1,676 Total future payments 253,060 33,722 Less: interest (100,265) (2,370) Total liability $ 152,795 $ 31,352

COMMITMENTS AND CONTINGENT LIAB

COMMITMENTS AND CONTINGENT LIABILITIES	12 Months Ended
	Sep. 30, 2023
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 September 2039, for the supply, transportation and storage of natural gas. These contracts include annual fixed charges of approximately $198.3M at current contract rates and volumes, which are recoverable through BGSS. For the purpose of securing storage and pipeline capacity, ES enters into storage and pipeline capacity contracts, which require the payment of certain demand charges by ES to maintain the ability to access such natural gas storage or pipeline capacity, during a fixed time period, which generally ranges from one Commitments as of September 30, 2023, for natural gas purchases and future demand fees for the next five fiscal year periods, are as follows: (Thousands) 2024 2025 2026 2027 2028 Thereafter ES: Natural gas purchases $ 66,525 $ 2,498 $ — $ — $ — $ — Storage demand fees 16,944 8,099 6,010 4,878 3,505 6,780 Pipeline demand fees 43,755 43,271 31,749 24,234 13,719 14,457 Sub-total ES $ 127,224 $ 53,868 $ 37,759 $ 29,112 $ 17,224 $ 21,237 NJNG: Natural gas purchases $ 23,952 $ — $ — $ — $ — $ — Storage demand fees 42,469 30,673 14,975 10,163 5,084 — Pipeline demand fees 155,875 155,559 134,555 128,651 113,998 966,963 Sub-total NJNG $ 222,296 $ 186,232 $ 149,530 $ 138,814 $ 119,082 $ 966,963 Total $ 349,520 $ 240,100 $ 187,289 $ 167,926 $ 136,306 $ 988,200 Certain pipeline demand fees totaling approximately $4.0M per year, for which ES is the responsible party, are being paid for by the counterparty to a capacity release transaction beginning November 1, 2021 for a period of 10 years. As of September 30, 2023, the Company’s future minimum lease payments under various operating leases will not be more than $7.9M annually for the next five years and $213.9M in the aggregate for all years thereafter. Guarantees As of September 30, 2023, there were NJR guarantees covering approximately $192.3M of ES’s 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 certain former 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 is 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 NJDEP regulations. NJNG periodically, and at least annually, performs an environmental review of former MGP sites located in Atlantic Highlands, Berkeley, Long Branch, Manchester, Toms River, Freehold and Aberdeen, New Jersey, 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 at the former 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 $137.3M to $201.5M. 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, 2023, NJNG recorded a MGP remediation liability and a corresponding regulatory asset of approximately $169.4M on the Consolidated Balance Sheets based on the most likely amount. 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 insurance recoveries, if any. NJNG recovers its remediation expenditures, including carrying costs, over rolling seven-year periods pursuant to a RAC approved by the BPU. In March 2022, the BPU approved an increase in the RAC, which increased the pre-tax annual recovery from $11.1M to $11.7M, effective April 1, 2022. On April 12, 2023, the BPU approved on a final basis NJNG’s annual SBC filing of RAC expenditures through June 30, 2022, as well as an increase to the RAC annual recoveries of $3.7M, which increased the pre-tax annual recovery to $15.4M, effective May 1, 2023. As of September 30, 2023, $66.3M of previously incurred remediation costs, net of recoveries from customers and insurance proceeds, are included in regulatory assets on the Consolidated Balance Sheets. 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. General 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 the ordinary course of 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, the Company establishes accruals 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. The Company also discloses contingent matters for which there is a reasonable possibility of a loss. Based upon currently available information, the Company believes that the results of litigation that are 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 accrued. The foregoing statements about the Company’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.

REPORTING SEGMENT AND OTHER OPE

REPORTING SEGMENT AND OTHER OPERATIONS DATA	12 Months Ended
	Sep. 30, 2023
Segment Reporting [Abstract]
REPORTING 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 business operations: NJNG consists of regulated energy and off-system, capacity and storage management operations; CEV consists of capital investments in clean energy projects; ES consists of unregulated wholesale and retail energy operations; S&T consists of the Company’s investments in natural gas transportation and storage facilities; the HSO business 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 business operations, as of September 30, is detailed below: Segments (Thousands) NJNG CEV ES S&T Subtotal HSO Elims Total 2023 Operating revenues External customers $ 1,011,284 124,131 681,446 (1) 88,700 $ 1,905,561 57,433 — $ 1,962,994 Intercompany $ 1,349 — 10,170 4,159 $ 15,678 205 (15,883) $ — Depreciation and amortization $ 102,326 25,320 221 (2) 24,185 $ 152,052 889 — $ 152,941 Interest income (3) $ 1,713 — 1,119 6,957 $ 9,789 2,977 (3,847) $ 8,919 Interest expense, net of capitalized interest $ 56,595 28,569 11,400 25,803 $ 122,367 647 — $ 123,014 Income tax provision (benefit) $ 33,065 (7,683) 24,343 3,444 $ 53,169 (1,477) (2,417) $ 49,275 Equity in earnings of affiliates $ — — — 3,126 $ 3,126 — 804 $ 3,930 Net financial earnings $ 131,414 44,458 68,517 12,835 $ 257,224 4,758 (155) $ 261,827 Capital expenditures $ 390,394 107,303 — 40,916 $ 538,613 2,306 — $ 540,919 2022 Operating revenues External customers $ 1,127,417 128,280 1,529,178 (1) 65,286 $ 2,850,161 55,818 — $ 2,905,979 Intercompany $ 1,350 — 94 2,449 $ 3,893 364 (4,257) $ — Depreciation and amortization $ 94,579 21,396 148 (2) 12,302 $ 128,425 824 — $ 129,249 Interest income (3) $ 895 — 16 2,110 $ 3,021 944 (1,249) $ 2,716 Interest expense, net of capitalized interest $ 46,394 21,968 4,725 12,097 $ 85,184 646 — $ 85,830 Income tax provision $ 40,141 11,361 21,776 1,879 $ 75,157 1,059 (21) $ 76,195 Equity in earnings of affiliates $ — — — 9,865 $ 9,865 — (1,688) $ 8,177 Net financial earnings (loss) $ 140,124 39,403 39,121 22,454 $ 241,102 (781) — $ 240,321 Capital expenditures $ 298,374 146,676 — 151,988 $ 597,038 1,390 — $ 598,428 Return of capital from equity investees $ — — — (5,479) $ (5,479) — — $ (5,479) 2021 Operating revenues External customers $ 731,796 95,275 1,228,846 (1) 49,252 $ 2,105,169 51,444 — $ 2,156,613 Intercompany $ — — (426) 1,768 $ 1,342 785 (2,127) $ — Depreciation and amortization $ 80,045 20,567 111 (2) 9,960 $ 110,683 980 (276) $ 111,387 Interest income (3) $ 85 241 11 2,243 $ 2,580 522 (935) $ 2,167 Interest expense, net of capitalized interest $ 36,405 22,548 2,204 13,348 $ 74,505 4,054 — $ 78,559 Income tax provision (benefit) $ 19,054 5,048 18,371 (10,043) $ 32,430 (196) 1,052 $ 33,286 Equity in loss of affiliates $ — — — (81,072) $ (81,072) — (2,140) $ (83,212) Net financial earnings (loss) $ 107,375 16,789 71,117 13,046 $ 208,327 (826) 211 $ 207,712 Capital expenditures $ 426,628 87,852 — 107,500 $ 621,980 2,630 — $ 624,610 Investments in equity investees $ — — — 690 $ 690 — — $ 690 (1) Includes sales to Canada for ES, which are $8.4M, $2.4M and $0.1M in the fiscal years ended September 30, 2023, 2022 and 2021, respectively. (2) The amortization of acquired wholesale energy contracts is excluded above and is included in natural gas purchases - nonutility on the Consolidated Statements of Operations. (3) Included in other income, net on the Consolidated Statements of Operations. The Company’s assets at end of period for the various reporting segments and other business operations, as of September 30, are detailed below: Segments Intercompany (Thousands) NJNG CEV ES S&T Subtotal HSO Assets (1) Total 2023 $ 4,414,829 1,128,577 123,775 1,011,959 $ 6,679,140 171,275 (312,919) $ 6,537,496 2022 $ 4,030,686 1,015,065 333,064 999,520 $ 6,378,335 159,068 (275,987) $ 6,261,416 2021 $ 3,707,461 914,788 365,423 862,407 $ 5,850,079 162,134 (289,935) $ 5,722,278 (1) Consists of transactions between subsidiaries that are eliminated and reclassified in consolidation. 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 other business operations, is the chief operating decision maker of the Company. A reconciliation of consolidated NFE to consolidated net income, as of September 30, is as follows: (Thousands) 2023 2022 2021 Net financial earnings $ 261,827 $ 240,321 $ 207,712 Less: Unrealized (gain) loss on derivative instruments and related transactions (38,081) (59,906) 54,203 Tax effect 9,050 14,248 (12,887) Effects of economic hedging related to natural gas inventory 34,699 19,939 (42,405) Tax effect (8,246) (4,738) 10,078 (Gain on) impairment of equity method investment (300) (5,521) 92,000 Tax effect (19) 1,377 (11,167) Net income $ 264,724 $ 274,922 $ 117,890 The Company uses derivative instruments as economic hedges of purchases and sales of physical natural 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 natural gas related to physical natural gas flow are recognized when the natural gas is delivered to customers. Consequently, there is a mismatch in the timing of earnings recognition between the economic hedges and physical natural gas flows. Timing differences occur in two ways: • unrealized gains and losses on derivatives are recognized in reported earnings in periods prior to physical natural 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 natural 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 natural 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. 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 natural gas flows. NFE also excludes certain transactions associated with equity method investments, including impairment charges, which are non-cash charges, and return of capital in excess of the carrying value of our investment. These are considered unusual in nature and occur infrequently such that they are not indicative of the Company’s performance for its ongoing operations. Included in the tax effects are current and deferred income tax expense corresponding with the components of NFE.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Sep. 30, 2023
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	16. RELATED PARTY TRANSACTIONS Effective April 1, 2020, NJNG entered into a 5-year agreement for 3 Bcf of firm storage capacity with Steckman Ridge, which expires on March 31, 2025. Under the terms of the agreement, NJNG incurs demand fees, at market rates, of approximately $9.3M annually, a portion of which is eliminated in consolidation. These fees are recoverable through NJNG’s BGSS mechanism and are included as a component of regulatory assets. ES may periodically enter into storage or park and loan agreements with an affiliated FERC-jurisdictional natural gas storage facility, Steckman Ridge. As of September 30, 2023, ES has entered into transactions with Steckman Ridge for varying terms, all of which expire by March 31, 2024. Demand fees, net of eliminations, associated with Steckman Ridge during the fiscal years ended September 30, were as follows: (Thousands) 2023 2022 2021 NJNG $ 6,549 $ 6,663 $ 6,449 ES 657 732 564 Total $ 7,206 $ 7,395 $ 7,013 The following table summarizes demand fees payable to Steckman Ridge as of September 30: (Thousands) 2023 2022 NJNG $ 775 $ 775 ES 84 76 Total $ 859 $ 851 NJNG and ES enter into various AMAs, the effects of which are eliminated in consolidation. Under the terms of these agreements, NJNG releases certain transportation and storage contracts to ES. As of September 30, 2023, NJNG and ES had one AMA with an expiration date of March 31, 2024. NJNG entered into a 5-year transportation agreement with Adelphia for committed capacity of 130,000 Dths per day in Zone South, which began on August 9, 2022. ES has a 5-year agreement for 3 Bcf of firm storage capacity with Leaf River, which is eliminated in consolidation and expires in March 2024. In March 2021, NJNG and CEV entered into a 15-year sublease and PPA related to an onsite solar array and the related energy output at the Company’s headquarters in Wall, New Jersey, the effects of which are immaterial to the consolidated financial statements. In July 2021, NJNG entered into 16-year lease agreements, as Lessor, with various NJR subsidiaries, as Lessees, for office space at the Company’s headquarters in Wall, New Jersey, the effects of which are eliminated in consolidation. In June 2022, NJNG and CEV entered into a 20-year sublease and PPA related to an onsite solar array and the related energy output at the Company’s LNG plant in Howell, New Jersey, the effects of which are immaterial to the consolidated financial statements. NJNG entered into a 15-year transportation agreement with Adelphia for committed capacity of 130,000 Dth per day in Zone North, beginning November 1, 2023. The intercompany profits for certain transactions between NJNG and ES and NJNG and Adelphia are not eliminated in accordance with ASC 980, Regulated Operations.

VALUATION AND QUALIFYING ACCOUN

VALUATION AND QUALIFYING ACCOUNTS	12 Months Ended
	Sep. 30, 2023
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
VALUATION AND QUALIFYING ACCOUNTS	VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED SEPTEMBER 30, 2023, 2022 and 2021 (Thousands) ADDITIONS/ (DEDUCTIONS), NET TO CLASSIFICATION BEGINNING OTHER ENDING BALANCE 2023 Valuation allowance for deferred tax assets $ 22,241 (16,494) (1) — $ 5,747 Allowance for doubtful accounts $ 19,379 1,570 (9,913) (2) $ 11,036 2022 Valuation allowance for deferred tax assets $ 23,613 (1,372) — $ 22,241 Allowance for doubtful accounts $ 24,652 2,401 (7,674) (2) $ 19,379 2021 Valuation allowance for deferred tax assets $ 17,639 6,355 (381) $ 23,613 Allowance for doubtful accounts $ 7,242 18,986 (1,576) (2) $ 24,652 (1) Includes valuation allowance release for CEV, see Note 12. Income Taxes for more details. (2) Uncollectible accounts written off, less recoveries and adjustments.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Pay vs Performance Disclosure
Net income (loss)	$ 264,724	$ 274,922	$ 117,890

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Sep. 30, 2023
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The Consolidated Financial Statements include the accounts of the Company and its 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 the entity 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, 2023, 2022 and 2021. Investments in entities over which the Company does not have a controlling financial interest are accounted for under the equity method.
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 quarterly basis, or more frequently whenever events or changes in circumstances indicate a need, the Company evaluates its estimates, including those related to the calculation of the fair value of derivative instruments, debt, equity method investments, lease liabilities, unbilled revenues, allowance for doubtful accounts, provisions for depreciation and amortization, long-lived assets, regulatory assets and liabilities, income taxes, pensions and other postemployment benefits, contingencies related to environmental matters and litigation. ARO are evaluated periodically as required. 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.
Revenues	Revenues Revenues from the sale of natural gas to NJNG customers are recognized in the period that natural 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 natural gas and the most current tariff rates. CEV recognizes revenue when SRECs are transferred to counterparties. SRECs are physically delivered through the transfer of certificates as per contractual settlement schedules. The Clean Energy Act of 2018 established guidelines for the closure of the SREC registration program to new applicants in New Jersey. The SREC program officially closed to new qualified solar projects on April 30, 2020. In December 2019, the BPU established the TREC as the successor to the SREC program. TRECs provide a fixed compensation base multiplied by an assigned project factor in order to determine their value. The project factor is determined by the type and location of the project, as defined. In July 2021, the BPU established a new successor solar incentive program. The Administratively Determined Incentive Program provides administratively set incentives for net metered residential projects and net metered non-residential projects of 5 MW or less. RECs generated through the production of electricity under this program are known as SREC IIs. TRECs and SREC IIs generated are required to be purchased monthly by a REC program administrator as appointed by the BPU. Revenue is recognized when RECs are generated and are transferred monthly based upon metered solar electricity activity. Revenues for ES 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. ES also recognizes changes in the fair value of SREC derivative contracts as a component of operating revenues. During December 2020, ES entered into a series of AMAs with an investment grade public utility to release pipeline capacity associated with certain natural gas transportation contracts, which commenced in November 2021. The AMAs include a series of temporary and permanent releases, and revenue under these agreements is recognized as the performance obligations are satisfied. For temporary releases of pipeline capacity, revenue is recognized on a straight-line basis over the agreed-upon term. For permanent releases of pipeline capacity, which represent a transfer of contractual rights for such capacity, revenue is recognized upon the transfer of the underlying contractual rights. ES recognized $48.5M and $53.0M of operating revenue on the Consolidated Statements of Operations during fiscal 2023 and 2022, respectively. Amounts received in excess of revenue recognized totaling $58.7M and $33.8M are included in deferred revenue on the Consolidated Balance Sheets as of September 30, 2023 and 2022, respectively. S&T generates revenues from firm storage contracts and transportation contracts, related usage fees and hub services for the use of storage space, injections and withdrawals from their natural gas storage facility and the delivery of natural gas to customers. Demand fees are recognized as revenue over the term of the related agreement while usage fees and hub services revenues are recognized as services are performed. 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. See Note 3. Revenue for further information.
Natural Gas Purchases	Natural 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. Natural gas purchases at ES are composed of natural 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 natural gas purchases as they occur.
Demand Fees	Demand Fees For the purpose of securing storage and pipeline capacity in support of their respective businesses, ES and NJNG 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 ES expenses demand charges over the term of the service being provided. NJNG’s costs associated with demand charges are included in its weighted average cost of natural gas. The demand charges are expensed based on NJNG’s BGSS sales and recovered as part of the natural gas commodity component of its BGSS tariff.
Operations and Maintenance Expenses	Operations and Maintenance Expenses Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, amortization of software costs for unregulated entities, customer service, professional fees and other outside services, insurance expense, accretion of cost of removal for future retirements of utility assets and other administrative expenses and are expensed as incurred.
Stock Based Compensation	Stock-Based CompensationStock-based compensation represents costs related to stock-based awards granted to employees and members of NJR’s Board of Directors. NJR recognizes stock-based compensation based upon the estimated fair value of awards. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period. The related compensation cost is recognized as O&M expense on the Consolidated Statements of Operations.
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 12. 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. NJR evaluates its tax positions to determine the appropriate accounting and recognition of potential future obligations associated with unrecognized tax benefits. A tax benefit claimed, or expected to be claimed, on a tax return may be recognized if it is more likely than not that the position will be upheld upon examination by the applicable taxing authority. Interest and penalties related to unrecognized tax benefits, if any, are recognized within income tax expense and accrued interest, and penalties are recognized within other noncurrent liabilities on the Consolidated Balance Sheets. To the extent that NJNG invests in property that qualifies for ITCs, the ITC is deferred and amortized to income over the life of the equipment in accordance with regulatory treatment. ITCs at the unregulated subsidiaries of NJR are recorded on the balance sheet as a reduction to property, plant and equipment when the property is placed in service, and recognized in earnings as a reduction of depreciation expense over the useful lives of the related assets.
Investments in Equity Investees	Investments in Equity Investees The Company accounts for its investment in Steckman Ridge using the equity method of accounting where it is not the primary beneficiary, as defined under ASC 810, Consolidation ; its respective ownership interests are 50% or less and/or it has significant influence over operating and management decisions. The Company’s share of earnings is recognized as equity in earnings of affiliates on the Consolidated Statements of Operations. Equity method investments are reviewed for impairment when changes in facts and circumstances indicate that the current fair value may be less than the asset’s carrying amount. If the Company determines the decline in the value of its equity method investment is other than temporary, an impairment charge is recorded in an amount equal to the excess of the carrying value of the asset over its fair value. See Note 7. Investments in Equity Investees for more information regarding impairments.
Property Plant and Equipment	Property Plant and Equipment Property, plant and equipment is stated at original cost. Costs include direct labor, materials and third-party construction contractor costs, capitalized interest and certain indirect costs related to equipment and employees engaged in construction. Utility plant and nonutility plant for Adelphia also includes AFUDC. Upon retirement, the cost of depreciable property, plus removal costs less salvage, is charged to accumulated depreciation with no gain or loss recorded.
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 are recognized in interest expense and in other income for the equity component on the Consolidated Statements of Operations. Adelphia’s base rates include the ability to recover AFUDC on its construction work in progress. Capitalized amounts associated with Adelphia’s AFUDC are recorded in nonutility plant on the Consolidated Balance Sheets. Corresponding amounts for the debt component are recognized in interest expense and in other income for the equity component 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 related to escrow balances for utility plant projects at NJNG, which are recorded in other noncurrent assets on the Consolidated Balance Sheets.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts The Company segregates financial assets, primarily trade receivables and unbilled revenues due in one year or less, into portfolio segments based on shared risk characteristics, such as geographical location and regulatory environment, for evaluation of expected credit losses. Historical and current information, such as average write-offs, are applied to each portfolio segment to estimate the allowance for losses on uncollectible receivables. Additionally, the allowance for losses on uncollectible receivables is adjusted for reasonable and supportable forecasts of future economic conditions, which can include changing weather, commodity prices, regulations and macroeconomic factors, such as unemployment rates among others.
Loans Receivable	Loans ReceivableNJNG currently provides loans, with terms ranging from two
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. NJNG is subject to accounting requirements resulting from the effects of rate regulation by the BPU. 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. Adelphia 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 Adelphia’s regulatory assets and liabilities.
Natural Gas in Storage	Natural Gas in StorageNatural 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.
Derivative Instruments	Derivative Instruments The Company accounts for its financial instruments, such as futures, options, foreign exchange contracts and interest rate contracts, as well as its physical commodity contracts related to the purchase and sale of natural gas at ES, 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 natural gas purchases and changes in the fair value of their physical forward contracts in natural gas purchases or operating revenues, as appropriate, on the Consolidated Statements of Operations. Ineffective portions of the cash flow hedges are recognized immediately in earnings. Cash flows from derivative financial instruments are included in cash flows from operating activities on the Consolidated Statements of Cash Flows. ASC 815, Derivatives and Hedging also provides for a NPNS scope exception for qualifying physical commodity contracts for which physical delivery is probable and the quantities delivered are expected to be used or sold over a reasonable period of time in the normal course of business. 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 PPAs at CEV. When applied, it does not account for these contracts until the contract settles and the related underlying natural gas or power 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 and swaps, 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 ES and interest rate contracts 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. During fiscal 2020, the Company entered into treasury lock transactions to fix the benchmark treasury rate associated with debt issuances for NJNG and NJR that occurred during the fiscal year. Settlement of the NJNG treasury locks resulted in a loss, which was recorded as a component of regulatory assets on the Consolidated Balance Sheets and will be amortized in earnings over the term of the debt as a component of interest expense on the Consolidated Statements of Operations. NJR designated its treasury lock contracts as cash flow hedges; therefore, changes in fair value of the effective portion of the hedges were recorded in OCI. Settlement of the treasury locks resulted in a loss, which was recorded within OCI and is amortized into earnings over the term of the associated debt as a component of interest expense on the Consolidated Statements of Operations. As of both September 30, 2023 and 2022, amounts recognized in interest expense related to the amortization of the loss on treasury lock transactions totaled $0.2M for NJNG and $1.1M for NJR. The Company is subject primarily 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 is exposed to foreign currency and interest rate risk and may utilize foreign currency derivatives to hedge Canadian dollar-denominated natural gas purchases and/or sales and interest rate derivatives to reduce exposure to fluctuations in interest rates. All of these types of contracts are accounted for as derivatives, unless the Company elects NPNS, which is done on a contract-by-contract election. 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 ES chooses not to designate its financial commodity and physical forward commodity derivatives as accounting hedges or to elect NPNS. The changes in the fair value of these derivatives are recorded as a component of natural gas purchases or operating revenues, as appropriate for ES, on the Consolidated Statements of Operations as unrealized gains or losses. For ES at settlement, realized gains and losses on all financial derivative instruments are recognized as a component of natural 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 natural gas purchases or operating revenues. ES 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. ES may utilize foreign currency derivatives to lock in the exchange rates 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 natural gas purchase agreements. As a result of ES 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 natural 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. ES 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. 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 charged to expense in the current period earnings based on the BGSS factor times the therm sales. Effective for contracts executed on or after January 1, 2016, NJNG no longer elects NPNS accounting treatment on a portfolio basis. However, since NPNS is a contract-by-contract election, where it makes sense to do so, NJNG can and may elect to treat certain contracts as 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 natural 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. Clean Energy Ventures The Company elects NPNS accounting treatment on PPA contracts executed by CEV that meet the definition of a derivative and accounts for the contract on an accrual basis. Accordingly, electricity sales are recognized in revenues throughout the term of the PPA as electricity is delivered. NPNS is a contract-by-contract election and where it makes sense to do so, the Company can and may elect to treat certain contracts as normal. 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.
Software Costs	Software Costs The Company capitalizes certain costs, such as software design and configuration, coding, testing and installation, that are incurred to purchase or create and implement computer software for internal use. Capitalized costs include external costs of materials and services utilized in developing or obtaining internal-use software and payroll and payroll-related costs for employees who are directly associated with and devote time to the internal-use software project. Maintenance costs are expensed as incurred. Upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Amortization is recorded on the straight-line basis over the estimated useful lives.
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, 2023, intangible assets consist primarily of acquired wholesale natural gas energy contracts totaling $0.1M, which will be fully amortized during fiscal 2024. 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 may not be recoverable, such as significant adverse changes in regulation, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices. 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. Factors that the Company analyzes in determining whether an impairment in its long-lived assets exists include: a significant decrease in the market price of a long-lived asset; a significant adverse change in the extent in which a long-lived asset is being used in its physical condition; legal proceedings or other contributing factors; significant business climate changes; accumulations of costs in significant excess of the amounts expected; a current-period operating or cash flow loss combined with a history of such events; and current expectations that more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its estimated useful life. During fiscal 2023 and 2022, there were no events or circumstances that indicated that the carrying value of long-lived assets or finite-lived intangibles was not recoverable.
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt. See Note 9. Debt for the total unamortized debt issuance costs that are recorded as a reduction to long-term debt on the Consolidated Balance Sheets.
Sale Leasebacks	Sale Leasebacks NJNG utilizes sale leaseback arrangements as a financing mechanism to fund certain of its capital expenditures related to natural gas meters, whereby the physical asset is sold concurrent with an agreement to lease the asset back. These agreements include options to renew the lease or repurchase the asset at the end of the term. Proceeds from sale leaseback transactions are accounted for as financing arrangements and are included in long-term debt on the Consolidated Balance Sheets. In addition, 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 arrangement does not qualify as a sale as the Company retains control of the underlying assets, the Company uses the financing method to account for the transaction. Under the financing method, the Company recognizes the proceeds received from the buyer-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. The Company continues to operate the solar assets and is responsible for related expenses and entitled to retain the revenue generated from SRECs, TRECs, SREC IIs and energy sales. The ITCs and other tax benefits associated with these solar projects transfer to the buyer; however, the payments are structured so that CEV is compensated for the transfer of the related tax attributes. Accordingly, CEV recognizes the equivalent value of the tax attributes in other income on the Consolidated Statements of Operations over the respective five-year ITC recapture periods, starting with the second year of the lease. See Note 9. Debt for more details regarding sale leaseback transactions recorded as financing arrangements.
Environmental Contingencies	Environmental Contingencies Loss contingencies are recorded as liabilities when it is probable a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties. Accruals for loss contingencies are recorded based on an analysis of potential results. With respect to environmental liabilities and related costs, NJNG periodically, and at least annually, performs an environmental review of MGP sites, including a review of potential liability for investigation and remedial action. 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. 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. See Note 14. Commitments and Contingent Liabilities for more details.
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 the 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 did not make any discretionary contributions to the pension plans during fiscal 2023 and 2022.
Asset Retirement Obligations	Asset Retirement Obligations The Company recognizes ARO related to the costs associated with cutting and capping NJNG’s main and service natural gas distribution mains, which is required by New Jersey law when taking such natural gas distribution mains out of service. The Company also recognizes ARO associated with CEV’s solar assets when there are decommissioning provisions in lease agreements that require removal of the asset at the end of the lease term. ARO are initially recognized when the legal obligation to retire an asset has been incurred and a reasonable estimate of fair value can be made. The discounted fair value is recognized as an ARO liability with a corresponding amount capitalized as part of the carrying cost of the underlying asset. The obligation is subsequently accreted to the future value of the expected retirement cost, and the corresponding asset retirement cost is depreciated over the life of the related asset. Accretion expense associated with CEV’s ARO is recognized as a component of operations and maintenance expense on the Consolidated Statements of Operations. Accretion amounts associated with NJNG’s ARO are recognized as part of its depreciation expense, and the corresponding regulatory asset and liability will be shown gross on the Consolidated Balance Sheets. Estimating future removal costs requires management to make significant judgments because most of the removal obligations span long time frames and removal may be conditioned upon future events. Asset removal technologies are also constantly changing, which makes it difficult to estimate removal costs. Accordingly, inherent in the estimate of ARO are various assumptions including the ultimate settlement date, expected cash outflows, inflation rates, credit-adjusted risk-free rates and consideration of potential outcomes where settlement of the ARO can be conditioned upon events. In the latter case, the Company develops possible retirement scenarios and assigns probabilities based on management’s reasonable judgment and knowledge of industry practice. Accordingly, ARO are subject to change.
Foreign Currency Transactions	Foreign Currency Transactions The market area of ES includes Canadian delivery points and, as a result, ES 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 natural gas purchases on the Consolidated Statements of Operations. Gains and losses recognized for the fiscal years ended September 30, 2023, 2022 and 2021, are considered immaterial.
Reclassification	Reclassification Certain prior period amounts have been reclassified to conform to the current period presentation. Deferred income taxes and postemployment employee benefit assets previously classified within other noncurrent assets on the Consolidated Balance Sheets have been reclassified to their own category.
Recently Adopted Updates to the Accounting Standards Codification	Recently Adopted Updates to the Accounting Standards Codification Debt and Other In August 2020, the FASB issued ASU No. 2020-06, an amendment to ASC 470, Debt , and ASC 815, Derivatives and Hedging , which changes the accounting for convertible instruments by reducing the number of acceptable accounting models to three models, including the embedded derivative, substantial premium and traditional no proceeds allocated models. The Company adopted this guidance on October 1, 2022. The Company does not currently have convertible debt instruments, and as a result there was no impact on its financial position, results of operations, cash flows and disclosures upon adoption. In May 2021, the FASB issued ASU No. 2021-04, an amendment to ASC 470, Debt , ASC 260, Earnings per Share , ASC 718, Stock Compensation , and ASC 815, Derivatives and Hedging. The update impacts equity-classified written call options that remain equity-classified after a modification or exchange. The Company adopted this guidance on October 1, 2022, on a prospective basis. As the Company does not currently have equity-classified written call options, there was no impact on its financial position, results of operations, cash flows and disclosures upon adoption. Leases In July 2021, the FASB issued ASU No. 2021-05, an amendment to ASC 842, Leases , which requires a lessor to classify a lease with entirely or partially variable payments that do not depend on an index or rate as an operating lease if another classification, including sales-type or direct financing, would trigger a loss at the lease commencement date. The Company adopted this guidance on October 1, 2022, on a prospective basis. The Company currently does not have any leases that meet this criteria, and as such there was no impact on its financial position, results of operations, cash flows and disclosures upon adoption. Other Recent Updates to the Accounting Standards Codification Business Combinations In October 2021, the FASB issued ASU No. 2021-08, an amendment to ASC 805, Business Combinations , which requires that an acquirer recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606, Revenue from Contracts with Customers . The guidance is effective for the Company beginning October 1, 2023, and the Company will apply the updated guidance on a prospective basis to new acquisitions following the date of adoption. In August 2023, the FASB issued ASU No. 2023-05, an amendment to ASC 805, Business Combinations , which addresses how a joint venture should recognize contributions received upon its formation. Joint ventures must account for initial assets and liabilities received at fair value on the date the joint venture is formed. The guidance is effective for the Company for joint ventures formed beginning January 1, 2025, and the Company can elect to apply it either prospectively or retrospectively back to a joint venture’s formation date provided adequate information is available. Early adoption is permitted. This amendment would only impact the Company upon adoption if, in the future, it entered into an applicable transaction. Derivatives and Hedging In March 2022, the FASB issued ASU No. 2022-01, an amendment to ASC 815, Derivatives and Hedging , which addresses fair value hedge accounting of interest rate risk for portfolios of financial assets. This update further clarifies guidance previously released in ASU 2017-12, which established the “last-of-layer” method, and this update renames that method as the “portfolio layer” method. The guidance is effective for the Company beginning October 1, 2023, and the transition method can be on a prospective basis for a multiple-layer hedging strategy or a modified retrospective basis for a portfolio layer method. As the Company does not currently apply hedge accounting to any of its risk management activities, the amendment will have no impact on its financial position, results of operations, cash flows and disclosures upon adoption. Financial Instruments In March 2022, the FASB issued ASU No. 2022-02, an amendment to ASC 326, Financial Instruments-Credit Losses , which eliminates the accounting guidance for creditors in troubled debt restructuring. It also aligns conflicting disclosure requirement guidance in ASC 326 by requiring disclosure of current-period gross write-offs by year of origination. The amendment also adds new disclosures for creditors with loan refinancing and restructuring for borrowers experiencing financial difficulty. The guidance is effective for the Company beginning October 1, 2023, and the Company can elect to apply it on either a modified retrospective or prospective basis. At this time, the Company has not experienced a troubled debt restructuring, and therefore the amendments will have no impact on its financial position, results of operations, cash flows and disclosures upon adoption. Fair Value Measurement In June 2022, the FASB issued ASU No. 2022-03, an amendment to ASC 820, Fair Value Measurement. The amendment clarifies the fair value principles when measuring the fair value of an equity security subject to a contractual sale restriction. The guidance is effective for the Company on October 1, 2024, and will be applied on a prospective basis. At this time, the Company does not have equity securities subject to contractual sale restrictions, and therefore this amendment would only impact the Company upon adoption if, in the future, it entered into such transactions. Leases In March 2023, the FASB issued ASU No. 2023-01, an amendment to ASC 842, Leases, which applies to arrangements between related parties under common control. This update requires that all entities with common control arrangements classify and account for these leases on the same basis as an arrangement with an unrelated party. If the lessee in these types of arrangements continues to control the use of the underlying asset through a lease, the leasehold improvements are to be amortized over the improvements’ useful life to the common control group, regardless of the lease term. The guidance is effective for the Company on October 1, 2024, and the Company can elect to apply it either on a prospective basis or retrospectively beginning October 1, 2019, representing the date which the Company adopted ASC 842. The Company is currently evaluating the amendment to understand the impact on its financial position, results of operations, cash flows and disclosures 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, investments in equity 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: Fair Value Hierarchy Description of Fair Value Level Fair Value Technique 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 to internally as basis swaps, fixed swaps, futures and financial options that are cleared through an 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). 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 ES 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. ES uses Platts and Natural Gas Exchange for Canadian delivery points. However, ES 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, ES’s 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 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.
Lessee Accounting	Lessee Accounting The Company determines if an arrangement is a lease at inception based on whether the Company has the right to control the use of an identified asset, the right to obtain substantially all of the economic benefits from the use of the asset and the right to direct the use of the asset. After the criteria are satisfied, the Company accounts for these arrangements as leases in accordance with ASC 842, Leases . Right-of-use assets represent the Company’s right to use the underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. Right-of-use assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Company is the lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement date, is utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. The Company uses the implicit rate for agreements in which it is a lessor. The Company has not entered into any material agreements in which it is a lessor. Lease expense and lease income are recognized on a straight-line basis over the lease term for operating leases. The Company’s lease agreements primarily consist of commercial solar land leases, storage and capacity leases, equipment and real property, including land and office facilities, office equipment and the sale leaseback of certain natural gas meters. Certain leases contain escalation provisions for inflation metrics. The storage leases contain a variable payment component that relates to the change in the inflation metrics that are not known past the current payment period. The variable components of these lease payments are excluded from the lease payments that are used to determine the related right-of-use lease asset and liability. The variable portion of these leases are recognized as leasing expenses when they are incurred. The capacity lease payments are fully variable and based on the amount of natural gas stored in the storage caverns. Generally, the Company’s solar land lease terms are between 20 and 50 years and may include multiple options to extend the terms for an additional five two seven Leases . The Company has lease agreements with lease and non-lease components and has elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings, solar land leases and office equipment. Variable payments are not considered material to the Company. The Company’s lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. In July 2021, NJNG entered into 16-year lease agreements, as Lessor, with various NJR subsidiaries, as Lessees, for office space at the Company’s headquarters in Wall, New Jersey, the effects of which are eliminated in consolidation.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Sep. 30, 2023
Accounting Policies [Abstract]
Schedule of Demand Charges	The following table summarizes the demand charges, which are net of capacity releases, and are included as a component of natural gas purchases on the Consolidated Statements of Operations for the fiscal years ended September 30: (Millions) 2023 2022 2021 ES $ 74.6 $ 95.4 $ 120.5 NJNG 183.4 170.3 123.2 Total $ 258.0 $ 265.7 $ 243.7
Schedule of Property, Plant and Equipment	Property, plant and equipment was comprised of the following as of September 30: (Thousands) Estimated Property Classifications Useful Lives 2023 2022 Distribution facilities 11 to 54 years $ 3,063,111 $ 2,797,936 Transmission facilities 28 to 42 years 650,817 649,241 Storage facilities 27 to 86 years 85,603 85,449 Solar property 20 to 35 years 864,838 710,224 Storage and transportation property 5 to 50 years 884,647 850,186 All other property 5 to 40 years 61,327 60,914 Construction work in progress 380,196 361,766 Total property, plant and equipment 5,990,539 5,515,716 Accumulated depreciation and amortization (968,484) (865,790) Property, plant and equipment, net $ 5,022,055 $ 4,649,926
Schedule of Capitalized Amounts Associated with Debt and Equity Component of AFUDC	Capitalized and deferred interest include the following for the fiscal years ended September 30: ($ in thousands) 2023 2022 2021 AFUDC: NJNG Adelphia NJNG Adelphia NJNG Adelphia Debt $ 3,546 $ 90 $ 1,648 $ 4,019 $ 5,648 $ 2,101 Equity 6,979 158 4,169 7,074 16,605 3,698 Total $ 10,525 $ 248 $ 5,817 $ 11,093 $ 22,253 $ 5,799 Weighted average interest rate 6.41 % 8.28 % 4.91 % 8.28 % 5.97 % 8.28 %
Schedule of Restricted Cash	The following table provides a reconciliation of cash and cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the total amounts in the Consolidated Statements of Cash Flows, as of September 30: (Thousands) 2023 2022 2021 Balance Sheet Cash and cash equivalents $ 954 $ 1,107 $ 4,749 Restricted cash in other noncurrent assets $ 563 $ 345 $ 1,294 Statements of Cash Flow Cash, cash equivalents and restricted cash $ 1,517 $ 1,452 $ 6,043
Schedule of Gas in Storage	The following table summarizes natural gas in storage, at average cost by company, as of September 30: 2023 2022 ($ in thousands) Natural Gas in Storage Bcf Natural Gas in Storage Bcf NJNG $ 175,025 29.1 $ 191,175 29.0 ES 24,476 14.6 82,469 10.8 Total $ 199,501 43.7 $ 273,644 39.8
Schedule of Software Costs Included in the Consolidated Financial Statements	The following table presents the software costs included in the Consolidated Financial Statements, as of September 30: (Thousands) 2023 2022 Balance Sheets Utility plant, at cost $ 51,282 $ 40,437 Construction work in progress $ 55,012 $ 14,381 Nonutility plant and equipment, at cost $ 344 $ 344 Accumulated depreciation and amortization, utility plant $ (7,480) $ (3,361) Accumulated depreciation and amortization, nonutility plant and equipment $ (36) $ (25) Software costs $ 8,375 $ 6,120 Statements of Operations Operation and maintenance (1) $ 14,299 $ 11,141 Depreciation and amortization $ 4,130 $ 2,024 (1) During both fiscal 2023 and 2022, $0.5M was amortized from software costs into O&M.
Schedule of Analysis of Change in ARO Liability	The following is an analysis of the change in the Company’s ARO for the fiscal years ended September 30: (Thousands) Balance at October 1 Accretion Additions Change in assumptions Retirements Balance at period end 2023 NJNG $ 49,874 2,693 155 4,089 (1,526) $ 55,285 NJRCEV $ 5,161 213 1,334 — — $ 6,708 2022 NJNG $ 41,611 2,052 161 7,339 (1,289) $ 49,874 NJRCEV $ 4,694 186 281 — — $ 5,161
Schedule of Future Accretion	Accretion for the next five years, for the fiscal years ended September 30, is estimated to be as follows: (Thousands) 2024 2025 2026 2027 2028 Total Estimated Accretion $ 3,114 3,268 3,429 3,597 3,781 $ 17,189
Schedule of Accumulated Other Comprehensive Income	The following table presents the changes in the components of accumulated other comprehensive income, net of related tax effects: (Thousands) Cash Flow Hedges Postemployment Benefit Obligation Total Balance as of September 30, 2021 $ (9,376) $ (25,152) $ (34,528) Other comprehensive income, net of tax Other comprehensive income, before reclassifications, net of tax of $0, $(7,727) and $(7,727), respectively — 25,580 25,580 Amounts reclassified from accumulated other comprehensive income, net of tax of $(317), $(930) and $(1,247), respectively 1,054 3,068 (1) 4,122 Net current-period other comprehensive income, net of tax of $(317), $(8,657) and $(8,974), respectively 1,054 28,648 29,702 Balance as of September 30, 2022 $ (8,322) $ 3,496 $ (4,826) Other comprehensive income, net of tax Other comprehensive income, before reclassifications, net of tax of $0, $1,922 and $1,922, respectively — (6,350) (6,350) Amounts reclassified from accumulated other comprehensive income, net of tax of $(317), $(49) and $(366), respectively 1,053 164 (1) 1,217 Net current-period other comprehensive income, net of tax of $(317), $1,873 and $1,556, respectively 1,053 (6,186) (5,133) Balance as of September 30, 2023 $ (7,269) $ (2,690) $ (9,959) (1) Included in the computation of net periodic pension cost, a component of operations and maintenance expense on the Consolidated Statements of Operations. For more details, see Note 11. Employee Benefit Plans .

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
	Sep. 30, 2023
Revenue from Contract with Customer [Abstract]
Performance Obligation, Recognition Period	Below is a listing of performance obligations that arise from contracts with customers, along with details on the satisfaction of each performance obligation, the significant payment terms and the nature of the goods and services being transferred, by reporting segment and other business operations: Revenue Recognized Over Time: Segment/ Operations Performance Obligation Description NJNG Natural gas utility sales NJNG’s performance obligation is to provide natural gas to residential, commercial and industrial customers as demanded, based on regulated tariff rates, which are established by the BPU. Revenues from the sale of natural gas are recognized in the period that natural gas is delivered and consumed by customers, including an estimate for quantities consumed but not billed during the period. Payment is due each month for the previous month’s deliveries. Natural gas sales to individual customers are based on meter readings, which are performed on a systematic basis throughout the billing period. The unbilled revenue estimates are based on estimated customer usage by customer type, weather effects and the most current tariff rates. NJNG is entitled to be compensated for performance completed until service is terminated. Customers may elect to purchase the natural gas commodity from NJNG or may contract separately to purchase natural gas directly from third-party suppliers. As NJNG is acting as an agent on behalf of the third-party supplier, revenue is recorded for the delivery of natural gas to the customer. CEV Commercial solar electricity CEV operates wholly-owned solar projects that recognize revenue as electricity is generated and transferred to the customer. The performance obligation is to provide electricity to the customer in accordance with contract terms or the interconnection agreement and is satisfied upon transfer of electricity generated. Revenue is recognized as invoiced and the payment is due each month for the previous month's services. CEV Residential solar electricity CEV provides access to residential rooftop and ground-mount solar equipment to customers who then pay the Company a monthly fee. The performance obligation is to provide electricity to the customer based on generation from the underlying residential solar asset and is satisfied upon transfer of electricity generated. Revenue is derived from the contract terms and is recognized as invoiced, with the payment due each month for the previous month’s services. Revenue Recognized Over Time (continued): Segment/ Performance Obligation Description CEV Renewable energy certificates Certain CEV projects generate TRECs and SREC IIs under the established Administratively Determined Incentive Program. A TREC or SREC II is created for every MWh of electricity produced by a solar generator. The performance obligation of CEV is to generate electricity. TRECs and SREC IIs under the Administratively Determined Incentive Program are purchased monthly by a REC Administrator. Revenue is recognized upon generation. ES Natural gas services The performance obligation of ES is to provide the customer transportation, storage and asset management services on an as-needed basis. ES generates revenue through management fees, demand charges, reservation fees and transportation charges centered around the buying and selling of the natural gas commodity, representing one series of distinct performance obligations. Revenue is recognized based upon the underlying natural gas quantities physically delivered and the customer obtaining control. ES invoices customers in line with the terms of the contract and based on the services provided. Payment is due upon receipt of the invoice. For temporary releases of pipeline capacity, revenue is recognized on a straight-line basis over the agreed upon term. S&T Natural gas services The performance obligation of S&T is to provide the customer with storage and transportation services. S&T generates revenues from firm storage contracts and transportation contracts, injection and withdrawal at the storage facility and the delivery of natural gas to customers. Revenue is recognized over time as customers receive the benefits of its service as it is performed on their behalf using an output method based on actual deliveries. Demand fees are recognized as revenue over the term of the related agreement. HSO Service contracts Home Services enters into service contracts with homeowners to provide maintenance and replacement of applicable heating, cooling or ventilation equipment. NJR Retail enters into warranty contracts with homeowners for various appliances. All services provided relate to a distinct performance obligation which is to provide services for the specific equipment over the term of the contract. Revenue is recognized on a straight-line basis over the term of the contract and payment is due upon receipt of the invoice. Revenue Recognized at a Point in Time: ES Natural gas services For a permanent release of pipeline capacity, the performance obligation of ES is the release of the pipeline capacity associated with certain natural gas transportation contracts and the transfer of the underlying contractual rights to the counterparty. Revenue is recognized upon the transfer of the underlying contractual rights. S&T Natural gas services The performance obligation of S&T is to provide the customer with storage and transportation services. S&T generates revenues from usage fees and hub services for the use of storage space, injection and withdrawal from the storage facility. Hub services include park and loan transactions and wheeling. Usage fees and hub services revenues are recognized as services are performed. HSO Installations Home Services installs appliances, including but not limited to, furnaces, air conditioning units, boilers and generators for customers. The distinct performance obligation is the installation of the contracted appliance, which is satisfied at the point in time the item is installed. The transaction price for each installation differs accordingly. Revenue is recognized at a point in time upon completion of the installation, which is when the customer is billed.
Disaggregation of Revenue	Disaggregated revenues from contracts with customers by product line and by reporting segment and other business operations during fiscal 2023, 2022 and 2021 are as follows: (Thousands) NJNG CEV ES S&T HSO Total 2023 Natural gas utility sales (1) $ 845,392 — — — — $ 845,392 Natural gas services — — 76,975 92,859 — 169,834 Service contracts — — — — 35,210 35,210 Installations and maintenance — — — — 22,428 22,428 Renewable energy certificates — 12,636 — — — 12,636 Electricity sales — 31,733 — — — 31,733 Eliminations (2) (1,349) — — (4,159) (205) (5,713) Revenues from contracts with customers 844,043 44,369 76,975 88,700 57,433 1,111,520 Alternative revenue programs (3) 27,257 — — — — 27,257 Derivative instruments 139,984 79,762 (4) 614,641 — — 834,387 Eliminations (2) — — (10,170) — — (10,170) Revenues out of scope 167,241 79,762 604,471 — — 851,474 Total operating revenues $ 1,011,284 124,131 681,446 88,700 57,433 $ 1,962,994 2022 Natural gas utility sales (1) $ 951,626 — — — — $ 951,626 Natural gas services — — 83,801 67,735 — 151,536 Service contracts — — — — 33,932 33,932 Installations and maintenance — — — — 22,250 22,250 Renewable energy certificates — 5,487 — — — 5,487 Electricity sales — 38,317 — — — 38,317 Eliminations (2) (1,350) — — (2,449) (364) (4,163) Revenues from contracts with customers 950,276 43,804 83,801 65,286 55,818 1,198,985 Alternative revenue programs (3) 11,259 — — — — 11,259 Derivative instruments 165,882 84,476 (4) 1,445,471 — — 1,695,829 Eliminations (2) — — (94) — — (94) Revenues out of scope 177,141 84,476 1,445,377 — — 1,706,994 Total operating revenues $ 1,127,417 128,280 1,529,178 65,286 55,818 $ 2,905,979 2021 Natural gas utility sales $ 694,635 — — — — 694,635 Natural gas services — — 26,933 51,020 — 77,953 Service contracts — — — — 33,250 33,250 Installations and maintenance — — — — 18,979 18,979 Renewable energy certificates — 4,571 — — — 4,571 Electricity sales — 25,270 — — — 25,270 Eliminations (2) — — — (1,768) (785) (2,553) Revenues from contracts with customers 694,635 29,841 26,933 49,252 51,444 852,105 Alternative revenue programs (3) (7,282) — — — — (7,282) Derivative instruments 44,443 65,434 (4) 1,201,487 — — 1,311,364 Eliminations (2) — — 426 — — 426 Revenues out of scope 37,161 65,434 1,201,913 — — 1,304,508 Total operating revenues $ 731,796 95,275 1,228,846 49,252 51,444 2,156,613 (1) Includes building rent related to the Wall headquarters, which is eliminated in consolidation. (2) Consists of transactions between subsidiaries that are eliminated in consolidation. (3) Includes CIP revenue. (4) Includes SREC revenue. Disaggregated revenues from contracts with customers by customer type and by reporting segment and other business operations during the fiscal years ended September 30, are as follows: (Thousands) NJNG CEV ES S&T HSO Total 2023 Residential $ 621,663 13,668 — — 57,091 $ 692,422 Commercial and industrial 136,011 30,701 76,975 88,700 342 332,729 Firm transportation 77,722 — — — — 77,722 Interruptible, off-tariff and other 8,647 — — — — 8,647 Revenues out of scope 167,241 79,762 604,471 — — 851,474 Total operating revenues $ 1,011,284 124,131 681,446 88,700 57,433 $ 1,962,994 2022 Residential $ 586,678 12,579 — — 55,629 $ 654,886 Commercial and industrial 265,970 31,225 83,801 65,286 189 446,471 Firm transportation 92,531 — — — — 92,531 Interruptible, off-tariff and other 5,097 — — — — 5,097 Revenues out of scope 177,141 84,476 1,445,377 — — 1,706,994 Total operating revenues $ 1,127,417 128,280 1,529,178 65,286 55,818 $ 2,905,979 2021 Residential $ 487,018 11,319 — — 50,689 $ 549,026 Commercial and industrial 124,519 18,522 26,933 49,252 755 219,981 Firm transportation 79,256 — — — — 79,256 Interruptible, off-tariff and other 3,842 — — — — 3,842 Revenues out of scope 37,161 65,434 1,201,913 — — 1,304,508 Total operating revenues $ 731,796 95,275 1,228,846 49,252 51,444 $ 2,156,613
Expected Timing of Performance	The timing of revenue recognition, customer billings and cash collections resulting in accounts receivables, billed and unbilled, and customers’ credit balances and deposits on the Consolidated Balance Sheets are as follows: Customer Accounts Receivable Customers’Credit (Thousands) Billed Unbilled Balances and Deposits Balance as of September 30, 2021 $ 212,838 $ 10,351 $ 32,586 Increase 9,459 3,418 660 Balance as of September 30, 2022 222,297 13,769 33,246 (Decrease) increase (124,757) 5,331 11,664 Balance as of September 30, 2023 $ 97,540 $ 19,100 $ 44,910
Performance Obligation, in Excess of Billings	The following table provides information about receivables, which are included within accounts receivable, billed and unbilled, and customers’ credit balances and deposits, respectively, on the Consolidated Balance Sheets as of September 30: (Thousands) NJNG CEV ES S&T HSO Total 2023 Customer accounts receivable Billed $ 55,234 9,962 23,716 6,577 2,051 $ 97,540 Unbilled 10,784 8,316 — — — 19,100 Customers’ credit balances and deposits (44,898) — — (12) — (44,910) Total $ 21,120 18,278 23,716 6,565 2,051 $ 71,730 2022 Customer accounts receivable Billed $ 78,508 5,566 129,199 7,012 2,012 $ 222,297 Unbilled 10,814 2,955 — — — 13,769 Customers’ credit balances and deposits (33,246) — — — — (33,246) Total $ 56,076 8,521 129,199 7,012 2,012 $ 202,820

REGULATION (Tables)

REGULATION (Tables)	12 Months Ended
	Sep. 30, 2023
Regulated Operations [Abstract]
Schedule of Regulatory Assets	Regulatory assets and liabilities included on the Consolidated Balance Sheets for NJNG are comprised of the following, as of September 30: (Thousands) 2023 2022 Regulatory assets-current New Jersey Clean Energy Program $ 15,804 $ 15,697 Conservation Incentive Program 50,356 23,099 Derivatives at fair value, net 6,017 — Other current regulatory assets 1,410 1,290 Total current regulatory assets $ 73,587 $ 40,086 Regulatory assets-noncurrent Environmental remediation costs: Expended, net of recoveries $ 66,298 $ 66,149 Liability for future expenditures 169,390 127,070 Deferred income taxes 41,667 40,520 SAVEGREEN 83,589 52,690 Postemployment and other benefit costs 55,274 56,021 Deferred storm damage costs — 2,172 Cost of removal 112,362 104,850 Other noncurrent regulatory assets 51,019 45,828 Total noncurrent regulatory assets $ 579,599 $ 495,300 Regulatory liability-current Overrecovered natural gas costs $ 30,637 $ 17,807 Derivatives at fair value, net — 7,972 Total current regulatory liabilities $ 30,637 $ 25,779 Regulatory liabilities-noncurrent Tax Act impact (1) $ 180,347 $ 185,367 Derivatives at fair value, net — 116 Other noncurrent regulatory liabilities 111 151 Total noncurrent regulatory liabilities $ 180,458 $ 185,634 (1) Reflects the re-measurement and subsequent amortization of NJNG’s net deferred tax liabilities as a result of the change in federal tax rates enacted in the Tax Act. The Tax Act is an Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018, previously known as The Tax Cuts and Jobs Act of 2017. Regulatory assets and liabilities included on the Consolidated Balance Sheets for Adelphia are comprised of the following, as of September 30: (Thousands) 2023 2022 Total noncurrent regulatory assets $ 5,231 $ 5,366 Total current regulatory liabilities $ 1,650 $ 5,311
Schedule of Regulatory Liabilities	Regulatory assets and liabilities included on the Consolidated Balance Sheets for NJNG are comprised of the following, as of September 30: (Thousands) 2023 2022 Regulatory assets-current New Jersey Clean Energy Program $ 15,804 $ 15,697 Conservation Incentive Program 50,356 23,099 Derivatives at fair value, net 6,017 — Other current regulatory assets 1,410 1,290 Total current regulatory assets $ 73,587 $ 40,086 Regulatory assets-noncurrent Environmental remediation costs: Expended, net of recoveries $ 66,298 $ 66,149 Liability for future expenditures 169,390 127,070 Deferred income taxes 41,667 40,520 SAVEGREEN 83,589 52,690 Postemployment and other benefit costs 55,274 56,021 Deferred storm damage costs — 2,172 Cost of removal 112,362 104,850 Other noncurrent regulatory assets 51,019 45,828 Total noncurrent regulatory assets $ 579,599 $ 495,300 Regulatory liability-current Overrecovered natural gas costs $ 30,637 $ 17,807 Derivatives at fair value, net — 7,972 Total current regulatory liabilities $ 30,637 $ 25,779 Regulatory liabilities-noncurrent Tax Act impact (1) $ 180,347 $ 185,367 Derivatives at fair value, net — 116 Other noncurrent regulatory liabilities 111 151 Total noncurrent regulatory liabilities $ 180,458 $ 185,634 (1) Reflects the re-measurement and subsequent amortization of NJNG’s net deferred tax liabilities as a result of the change in federal tax rates enacted in the Tax Act. The Tax Act is an Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018, previously known as The Tax Cuts and Jobs Act of 2017. Regulatory assets and liabilities included on the Consolidated Balance Sheets for Adelphia are comprised of the following, as of September 30: (Thousands) 2023 2022 Total noncurrent regulatory assets $ 5,231 $ 5,366 Total current regulatory liabilities $ 1,650 $ 5,311

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Sep. 30, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair Value of Derivative Assets and Liabilities	The following table presents the fair value of the Company’s derivative assets and liabilities recognized on the Consolidated Balance Sheets as of September 30: Derivatives at Fair Value 2023 2022 (Thousands) Balance Sheet Location Assets Liabilities Assets Liabilities Derivatives not designated as hedging instruments: NJNG: Physical commodity contracts Derivatives - current $ 43 $ 488 $ 252 $ 11 Financial commodity contracts Derivatives - current 6,110 20 85 6,281 ES: Physical commodity contracts Derivatives - current 6,209 12,757 9,857 17,051 Derivatives - noncurrent 802 7,870 376 13,561 Financial commodity contracts Derivatives - current 18,393 2,880 14,423 26,488 Derivatives - noncurrent 762 97 6,009 630 Foreign currency contracts Derivatives - current — — 18 17 Total fair value of derivatives $ 32,319 $ 24,112 $ 31,020 $ 64,039
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 and the net amounts the Company could present on the Consolidated Balance Sheets but elects not to. Asset Derivatives Liability Derivatives (Thousands) Fair Value (1) Amounts Offset (2) Collateral Received/Pledged (3) Net Value (4) Fair Value (1) Amounts Offset (2) Collateral Received/Pledged (3) Net Value (4) As of September 30, 2023 ES Contracts Physical commodity $ 7,011 (1,236) — $ 5,775 $ 20,627 (1,236) (9,728) $ 9,663 Financial commodity 19,155 (2,977) (16,178) — 2,977 (2,977) — — Total ES $ 26,166 (4,213) (16,178) $ 5,775 $ 23,604 (4,213) (9,728) $ 9,663 NJNG Contracts Physical commodity $ 43 (3) — $ 40 $ 488 (3) — $ 485 Financial commodity 6,110 (20) — 6,090 20 (20) — — Total NJNG $ 6,153 (23) — $ 6,130 $ 508 (23) — $ 485 As of September 30, 2022 ES Contracts Physical commodity $ 10,233 (404) (200) $ 9,629 $ 30,612 (404) — $ 30,208 Financial commodity 20,432 (12,198) — 8,234 27,118 (12,198) — 14,920 Foreign currency 18 (17) — 1 17 (17) — — Total ES $ 30,683 (12,619) (200) $ 17,864 $ 57,747 (12,619) — $ 45,128 NJNG Contracts Physical commodity $ 252 — — $ 252 $ 11 — — $ 11 Financial commodity 85 (85) — — 6,281 (85) — 6,196 Total NJNG $ 337 (85) — $ 252 $ 6,292 (85) — $ 6,207 (1) Derivative assets and liabilities are presented on a gross basis on the Consolidated Balance Sheets, as the Company does not elect balance sheet offsetting under ASC 210-20. (2) Includes 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 and the net amounts the Company could present on the Consolidated Balance Sheets but elects not to. Asset Derivatives Liability Derivatives (Thousands) Fair Value (1) Amounts Offset (2) Collateral Received/Pledged (3) Net Value (4) Fair Value (1) Amounts Offset (2) Collateral Received/Pledged (3) Net Value (4) As of September 30, 2023 ES Contracts Physical commodity $ 7,011 (1,236) — $ 5,775 $ 20,627 (1,236) (9,728) $ 9,663 Financial commodity 19,155 (2,977) (16,178) — 2,977 (2,977) — — Total ES $ 26,166 (4,213) (16,178) $ 5,775 $ 23,604 (4,213) (9,728) $ 9,663 NJNG Contracts Physical commodity $ 43 (3) — $ 40 $ 488 (3) — $ 485 Financial commodity 6,110 (20) — 6,090 20 (20) — — Total NJNG $ 6,153 (23) — $ 6,130 $ 508 (23) — $ 485 As of September 30, 2022 ES Contracts Physical commodity $ 10,233 (404) (200) $ 9,629 $ 30,612 (404) — $ 30,208 Financial commodity 20,432 (12,198) — 8,234 27,118 (12,198) — 14,920 Foreign currency 18 (17) — 1 17 (17) — — Total ES $ 30,683 (12,619) (200) $ 17,864 $ 57,747 (12,619) — $ 45,128 NJNG Contracts Physical commodity $ 252 — — $ 252 $ 11 — — $ 11 Financial commodity 85 (85) — — 6,281 (85) — 6,196 Total NJNG $ 337 (85) — $ 252 $ 6,292 (85) — $ 6,207 (1) Derivative assets and liabilities are presented on a gross basis on the Consolidated Balance Sheets, as the Company does not elect balance sheet offsetting under ASC 210-20. (2) Includes 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 Consolidated Statements of Operations	The following table presents the effect of derivative instruments recognized 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 Derivatives not designated as hedging instruments: 2023 2022 2021 ES: Physical commodity contracts Operating revenues $ 33,610 $ (8,569) $ 30,011 Physical commodity contracts Natural gas purchases (6,846) 3,580 1,052 Financial commodity contracts Natural gas purchases 80,406 14,403 (43,997) Foreign currency contracts Natural gas purchases — (14) 238 Total unrealized and realized gain (loss) $ 107,170 $ 9,400 $ (12,696)
Effect of Derivative Instruments Designated as Cash Flow Hedges on OCI	The following table reflects the gains and/or (losses) associated with NJNG’s derivative instruments as of September 30: (Thousands) 2023 2022 2021 NJNG: Physical commodity contracts $ (34,241) $ 7,116 $ 2,174 Financial commodity contracts (50,130) 32,868 32,725 Total unrealized and realized (loss) gain $ (84,371) $ 39,984 $ 34,899
Schedule of Outstanding Long (Short) Derivatives	NJNG and ES had the following outstanding long (short) derivatives as of September 30: Natural Gas Distribution Energy Services Volumes (Bcf) Futures Physical Commodity Futures Physical Commodity 2023 32.1 12.1 (6.9) 0.2 2022 30.5 6.8 (0.7) 2.7
Schedule of Broker Margin Accounts by Company	The balances as of September 30, by reporting segment, are as follows: (Thousands) Balance Sheet Location 2023 2022 NJNG Restricted broker margin accounts - current assets $ 5,915 $ 26,138 ES Restricted broker margin accounts - current assets $ 14,881 $ 68,123 Restricted broker margin accounts - current liabilities $ 8,029 $ —
Summary of Gross Credit Exposures	The following is a summary of gross credit exposures grouped by investment and noninvestment grade counterparties, as of September 30, 2023. 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 CEV residential solar installations. (Thousands) Gross Credit Investment grade $ 119,229 Noninvestment grade 4,775 Internally-rated investment grade 20,343 Internally-rated noninvestment grade 20,153 Total $ 164,500

FAIR VALUE (Tables)

FAIR VALUE (Tables)	12 Months Ended
	Sep. 30, 2023
Fair Value Disclosures [Abstract]
Fair Value, by Balance Sheet Grouping	As of September 30, the estimated fair value of long-term debt, including current maturities, excluding natural gas meter sale leasebacks, debt issuance costs and solar asset sale leasebacks, is as follows (1) : (Thousands) 2023 2022 NJNG (2) (3) Carrying value $ 1,467,845 $ 1,292,845 Fair market value $ 1,097,088 $ 979,388 NJR (4) Carrying value $ 1,120,000 $ 1,070,000 Fair market value $ 1,009,448 $ 966,968 (1) See Note 9. Debt f or a reconciliation to long-term and short-term debt . (2) Excludes the sale leasebacks of natural gas meters of $31.4M and $30.3M as of September 30, 2023 and 2022, respectively. The fair value of certain sale leasebacks of natural gas meters amounted to $20.9M and $15.7M as of September 30, 2023 and 2022, respectively. (3) Excludes NJNG’s debt issuance costs of $9.8M and $9.5M as of September 30, 2023 and September 30, 2022, respectively. (4) Excludes NJR’s debt issuance costs of $3.7M and $3.8M as of September 30, 2023 and September 30, 2022, respectively.
Schedule of Fair Value Hierarchy	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: Fair Value Hierarchy Description of Fair Value Level Fair Value Technique 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 to internally as basis swaps, fixed swaps, futures and financial options that are cleared through an 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). 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.
Schedule of Fair Value Assets and Liabilities Measured 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 (Thousands) (Level 1) (Level 2) (Level 3) Total As of September 30, 2023 Assets Physical commodity contracts $ — $ 7,054 $ — $ 7,054 Financial commodity contracts 25,265 — — 25,265 Money market funds 145 — — 145 Other 2,641 — — 2,641 Total assets at fair value $ 28,051 $ 7,054 $ — $ 35,105 Liabilities Physical commodity contracts $ — $ 21,115 $ — $ 21,115 Financial commodity contracts 2,997 — — 2,997 Total liabilities at fair value $ 2,997 $ 21,115 $ — $ 24,112 As of September 30, 2022 Assets Physical commodity contracts $ — $ 10,485 $ — $ 10,485 Financial commodity contracts 20,517 — — 20,517 Financial commodity contracts - foreign exchange — 18 — 18 Money market funds 59 — — 59 Other 1,884 — — 1,884 Total assets at fair value $ 22,460 $ 10,503 $ — $ 32,963 Liabilities Physical commodity contracts $ — $ 30,623 $ — $ 30,623 Financial commodity contracts 33,231 168 — 33,399 Financial commodity contracts - foreign exchange — 17 — 17 Total liabilities at fair value $ 33,231 $ 30,808 $ — $ 64,039

INVESTMENTS IN EQUITY INVESTE_2

INVESTMENTS IN EQUITY INVESTEES (Tables)	12 Months Ended
	Sep. 30, 2023
Investments, All Other Investments [Abstract]
Schedule of Equity Method Investments	The following is the summarized financial information for Steckman Ridge and PennEast for fiscal years ended September 30: (Thousands) 2023 2022 2021 Steckman Ridge Operating revenues $ 22,659 $ 19,812 $ 21,847 Gross profit $ 13,385 $ 11,349 $ 13,350 Income from continuing operations $ 5,769 $ 8,686 $ 11,483 Net income $ 5,769 $ 8,686 $ 11,483 Net income attributable to NJR $ 2,884 $ 4,343 $ 5,741 Current assets $ 12,724 $ 28,609 Noncurrent assets $ 193,779 $ 198,052 Current liabilities $ 148,577 $ 23,618 Noncurrent liabilities $ — $ 140,810 PennEast Operating revenues $ — $ — $ — Gross profit $ — $ — $ — Loss from continuing operations $ (9,543) $ (3,778) $ (406,305) Net loss $ (9,543) $ (3,778) $ (406,305) Net loss attributable to NJR $ (1,909) $ (756) $ (81,261) Current assets $ 1,481 $ 1,801 Noncurrent assets $ — $ — Current liabilities $ 127 $ 82 Noncurrent liabilities $ — $ 500

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Sep. 30, 2023
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Basic and Diluted	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) 2023 2022 2021 Net income, as reported $ 264,724 $ 274,922 $ 117,890 Basic earnings per share Weighted average shares of common stock outstanding-basic 97,028 96,100 96,227 Basic earnings per common share $2.73 $2.86 $1.23 Diluted earnings per share Weighted average shares of common stock outstanding-basic 97,028 96,100 96,227 Incremental shares (1) 599 388 333 Weighted average shares of common stock outstanding-diluted 97,627 96,488 96,560 Diluted earnings per common share $2.71 $2.85 $1.22 (1) Incremental shares consist primarily of unvested stock awards and performance units, which are calculated using the treasury stock method.

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Sep. 30, 2023
Debt Disclosure [Abstract]
Schedule of Long-term Debt	The following table presents the long-term debt of the Company as of September 30: (Thousands) 2023 2022 NJNG First mortgage bonds: Maturity date: Series OO 3.00% August 1, 2041 46,500 46,500 Series PP 3.15% April 15, 2028 50,000 50,000 Series QQ 3.58% March 13, 2024 70,000 70,000 Series RR 4.61% March 13, 2044 55,000 55,000 Series SS 2.82% April 15, 2025 50,000 50,000 Series TT 3.66% April 15, 2045 100,000 100,000 Series UU 3.63% June 21, 2046 125,000 125,000 Series VV 4.01% May 11, 2048 125,000 125,000 Series WW 3.50% April 1, 2042 10,300 10,300 Series XX 3.38% April 1, 2038 10,500 10,500 Series YY 2.45% April 1, 2059 15,000 15,000 Series ZZ 3.76% July 17, 2049 100,000 100,000 Series AAA 3.86% July 17, 2059 85,000 85,000 Series BBB 2.75% August 1, 2039 9,545 9,545 Series CCC 3.00% August 1, 2043 41,000 41,000 Series DDD 3.13% June 30, 2050 50,000 50,000 Series EEE 3.13% July 23, 2050 50,000 50,000 Series FFF 3.33% July 23, 2060 25,000 25,000 Series GGG 2.87% September 1, 2050 25,000 25,000 Series HHH 2.97% September 1, 2060 50,000 50,000 Series III 2.97% October 28, 2051 50,000 50,000 Series JJJ 3.07% October 28, 2061 50,000 50,000 Series LLL 4.37% May 27, 2037 50,000 50,000 Series MMM 4.71% May 27, 2052 50,000 50,000 Series NNN 5.47% October 24, 2052 125,000 — Series OOO 5.56% September 28, 2033 50,000 — Meter financing obligation Various dates 31,352 30,290 Less: Debt issuance costs (9,770) (9,528) Less: Current maturities of long-term debt (78,477) (6,538) Total NJNG long-term debt 1,410,950 1,307,069 NJR Unsecured senior notes 3.20% August 18, 2023 — 50,000 Unsecured senior notes 3.48% November 7, 2024 100,000 100,000 Unsecured senior notes 3.54% August 18, 2026 100,000 100,000 Unsecured senior notes 3.96% June 8, 2028 100,000 100,000 Unsecured senior notes 3.29% July 17, 2029 150,000 150,000 Unsecured senior notes 3.60% July 23, 2032 130,000 130,000 Unsecured senior notes 3.50% July 23, 2030 130,000 130,000 Unsecured senior notes 3.25% September 1, 2033 80,000 80,000 Unsecured senior notes 3.13% September 1, 2031 120,000 120,000 Unsecured senior notes 4.38% June 23, 2027 110,000 110,000 Unsecured senior notes 3.64% September 19, 2034 50,000 50,000 Unsecured senior notes 6.14% December 15, 2032 50,000 — Less: Debt issuance costs (3,656) (3,753) Less: Current maturities of long-term debt — (50,000) Total NJR long-term debt 1,116,344 1,066,247 CEV Solar asset financing obligation Various dates 278,401 130,618 Less: Current maturities of long-term debt (37,678) (18,532) Total CEV long-term debt 240,723 112,086 Total long-term debt $ 2,768,017 $ 2,485,402
Schedule of Long-term Debt Redemption Requirements	Annual long-term debt redemption requirements, excluding meter financing obligations, debt issuance costs and solar asset financing obligations, as of September 30, are as follows: (Thousands) 2024 2025 2026 2027 2028 Thereafter NJR $ — $ 100,000 $ 100,000 $ 110,000 $ 100,000 $ 710,000 NJNG $ 70,000 $ 50,000 $ — $ — $ 50,000 $ 1,297,845
Finance Lease Liability, Maturity	Contractual commitments for meter financing obligation payments, which include the most likely outcome of cash payments to the lessor, as of the fiscal years ended September 30, are as follows: (Thousands) 2024 2025 2026 2027 2028 Thereafter Subtotal Lease Payments $ 9,362 7,479 6,407 4,083 4,715 1,676 $ 33,722 Less: Interest component (2,370) Total $ 31,352 The following table presents the Company’s maturities of lease liabilities as of September 30, 2023: (Thousands) Operating Finance 2024 $ 7,913 $ 9,362 2025 7,875 7,479 2026 7,799 6,407 2027 7,743 4,083 2028 7,803 4,715 Thereafter 213,927 1,676 Total future payments 253,060 33,722 Less: interest (100,265) (2,370) Total liability $ 152,795 $ 31,352
Schedule of Contractual Commitments for Finance Lease Payments	Contractual commitments for the solar asset financing obligation payments, as of the fiscal years ended September 30, are as follows: (Thousands) 2024 2025 2026 2027 2028 Thereafter Subtotal Lease Payments $ 54,033 50,663 13,875 16,385 26,392 87,881 $ 249,229 Less: Interest component (42,942) Total $ 206,287
Schedule of Line of Credit Facilities	The following table summarizes NJR’s credit facility and NJNG’s commercial paper program and credit facility as of September 30: At end of period (Thousands) Total borrowing capacity Loans outstanding Weighted average interest rate Remaining borrowing capacity Expiration dates 2023 NJR Bank revolving credit facilities (1) $ 650,000 $ 217,300 6.53 % $ 426,967 (2) Sep 2027 NJNG Bank revolving credit facilities (3) $ 250,000 $ 34,800 5.48 % $ 214,469 (4) Sep 2027 2022 NJR Bank revolving credit facilities (1) $ 650,000 $ 200,150 3.97 % $ 440,177 (2) Sep 2027 Bank term loan credit agreement $ 150,000 $ 150,000 3.81 % $ — Feb 2023 NJNG Bank revolving credit facilities (3) $ 250,000 $ 73,800 3.34 % $ 175,469 (4) Sep 2027 (1) Committed credit facilities, which require commitment fees of 0.10% on the unused amounts. (2) Letters of credit outstanding total $5.7M and $9.7M as of September 30, 2023 and September 30, 2022, respectively, which reduces amount available by the same amount. (3) Committed credit facilities, which require commitment fees of 0.075% on the unused amounts. (4) Letters of credit outstanding total $0.7M as of both September 30, 2023 and 2022, which reduces amount available by the same amount.

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Sep. 30, 2023
Share-Based Payment Arrangement [Abstract]
Summary of Stock-based Compensation Expense Recognized	The following table summarizes all stock-based compensation expense recognized during the following fiscal years: (Thousands) 2023 2022 2021 Stock-based compensation expense: Performance share awards $ 4,882 $ 4,131 $ 3,856 Restricted and non-restricted stock 3,647 3,189 3,193 Deferred retention stock 6,187 7,507 100 Compensation expense included in operation and maintenance expense 14,716 14,827 7,149 Income tax benefit (1) (3,563) (3,624) (1,613) Total, net of tax $ 11,153 $ 11,203 $ 5,536 (1) Excludes additional tax (expense) benefit related to delivered shares of $(0.6)M, $(0.1)M and $(0.2)M as of September 30, 2023, 2022 and 2021, 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 Total Fair Value of Vested Shares (in Thousands) Non-vested and outstanding at September 30, 2020 155,731 $44.22 — Granted 116,951 $33.34 — Vested (2) (54,918) $44.64 $ 1,673 Cancelled/forfeited (51,673) $45.32 — Non-vested and outstanding at September 30, 2021 166,091 $36.08 — Granted 118,526 $38.84 — Vested (3) (76,708) $39.57 $ 2,765 Cancelled/forfeited (15,788) $37.33 — Non-vested and outstanding at September 30, 2022 192,121 $36.29 — Granted 112,661 $46.00 — Vested (4) (105,197) $35.07 $ 4,126 Cancelled/forfeited (9,330) $38.64 — Non-vested and outstanding at September 30, 2023 190,255 $42.60 — (1) The number of common shares issued related to certain performance shares may range from zero to 150% 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, 2021, there were no common shares earned related to TSR performance, the number of common shares earned related to NFE performance was 93% or 31,116 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100% or 25,982 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100%. (3) As certified by the Company’s Leadership and Compensation Committee on November 9, 2022, the number of common shares earned related to TSR performance was 112% or 30,472 shares, the number of common shares earned related to NFE performance was 105% or 26,282 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100% or 28,965 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100%. (4) As certified by the Company’s Leadership and Compensation Committee on November 15, 2023, the number of common shares earned related to TSR performance was 150% or 59,192 shares, the number of common shares earned related to NFE performance was 150% or 55,832 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100% or 30,598 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100%.
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 Total Fair Value of Vested Shares (in Thousands) Non-vested and outstanding at September 30, 2020 73,486 $43.52 — Granted 67,726 $33.34 — Vested (34,000) $44.30 $ 996 Cancelled/forfeited (5,591) $36.34 — Non-vested and outstanding at September 30, 2021 101,621 $36.87 — Granted 54,826 $38.84 — Vested (47,867) $39.01 $ 1,824 Cancelled/forfeited (10,756) $37.06 — Non-vested and outstanding at September 30, 2022 97,824 $36.90 — Granted 64,080 $46.00 — Vested (48,312) $40.30 $ 1,910 Cancelled/forfeited (4,716) $38.77 — Non-vested and outstanding at September 30, 2023 108,876 $41.55 —
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 Total Fair Value of Vested Shares (in Thousands) Outstanding at September 30, 2020 228,246 $46.32 — Granted/Vested 2,999 $33.34 — Delivered (22,389) $45.00 $ 641 Outstanding at September 30, 2021 208,856 $46.28 — Granted/Vested 192,728 $38.95 — Delivered (163,499) $47.95 $ 6,167 Forfeited (6,818) $40.33 — Outstanding at September 30, 2022 231,267 $39.16 — Granted/Vested 134,941 $45.85 — Delivered (38,115) $40.67 $ 1,517 Outstanding at September 30, 2023 328,093 $41.74 —
Schedule of Nonemployee Director Stock Award Plan Activity	The following summarizes non-employee director share awards for the past three fiscal years: 2023 2022 2021 Shares granted 24,044 (1) 30,908 34,994 Weighted average grant date fair value $49.58 $39.09 $35.72 (1) Approximately $0.3M of expense remains as of September 30, 2023, to be recognized through December 31, 2023.

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Sep. 30, 2023
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) 2023 2022 2023 2022 Change in Benefit Obligation Benefit obligation at beginning of year $ 290,823 $ 395,547 $ 173,217 $ 244,674 Service cost 5,402 8,291 2,471 4,305 Interest cost 15,174 9,632 9,146 6,355 Plan participants’ contributions (2) 32 59 552 423 Actuarial (gain) loss (7,057) (109,320) 25,363 (77,775) Benefits paid, net of retiree subsidies received (14,053) (13,386) (7,343) (4,765) Benefit obligation at end of year $ 290,321 $ 290,823 $ 203,406 $ 173,217 Change in plan assets Fair value of plan assets at beginning of year $ 284,347 $ 355,284 $ 99,736 $ 114,183 Actual return (loss) on plan assets 27,456 (58,239) 9,826 (15,996) Employer contributions 579 628 4,192 6,082 Benefits paid, net of plan participants’ contributions (2) (14,021) (13,326) (6,971) (4,533) Fair value of plan assets at end of year $ 298,361 $ 284,347 $ 106,783 $ 99,736 Funded status $ 8,040 $ (6,476) $ (96,623) $ (73,481) Amounts recognized on Consolidated Balance Sheets Postemployment employee benefit asset Noncurrent $ 18,684 $ 4,388 $ — $ — Postemployment employee benefit liability Current $ (538) $ (578) $ (4,201) $ (900) Noncurrent (10,106) (10,286) (92,422) (72,581) Total $ 8,040 $ (6,476) $ (96,623) $ (73,481) (1) Includes the Company’s PEP. (2) Employees hired prior to July 1, 1998, that were eligible to elect an additional participant contribution to enhance their benefits, and contributions made during the periods were immaterial.
Summary of Regulatory Assets and Accumulated Other Comprehensive Income	The following table summarizes the amounts recognized in regulatory assets and accumulated OCI as of September 30: Regulatory Assets Accumulated Other Comprehensive Income (Loss) (Thousands) Pension OPEB Pension OPEB Balance at September 30, 2021 $ 56,187 $ 60,335 $ 22,790 $ 12,696 Amounts arising during the period: Net actuarial (gain) (14,922) (35,781) (14,885) (18,422) Amounts amortized to net periodic costs: Net actuarial (loss) (5,843) (4,577) (2,902) (1,107) Prior service (cost) credit (101) 133 — 11 Balance at September 30, 2022 $ 35,321 $ 20,110 $ 5,003 $ (6,822) Amounts arising during the period: Net actuarial (gain) loss (10,493) 9,936 (4,048) 12,320 Amounts amortized to net periodic costs: Net actuarial (loss) (87) — (213) — Prior service (cost) (103) — — — Balance at September 30, 2023 $ 24,638 $ 30,046 $ 742 $ 5,498 The amounts in regulatory assets and accumulated OCI not yet recognized as components of net periodic benefit cost as of September 30 are: Regulatory Assets Accumulated Other Comprehensive Pension OPEB Pension OPEB (Thousands) 2023 2022 2023 2022 2023 2022 2023 2022 Net actuarial loss (gain) $ 24,577 $ 35,157 $ 30,046 $ 20,110 $ 742 $ 5,003 $ 5,498 $ (6,822) Prior service cost 61 164 — — — — — — Total $ 24,638 $ 35,321 $ 30,046 $ 20,110 $ 742 $ 5,003 $ 5,498 $ (6,822) Regulatory Assets Accumulated Other Comprehensive Income (Loss) (Thousands) Pension OPEB Pension OPEB Net actuarial loss (gain) $ 815 $ 667 $ (12) $ 661 Prior service cost 62 — — — Total $ 877 $ 667 $ (12) $ 661
Schedule of Accumulated Benefit Obligations in Excess of 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) 2023 2022 Projected benefit obligation $ 290,321 $ 290,823 Accumulated benefit obligation $ 267,794 $ 265,933 Fair value of plan assets $ 298,361 $ 284,347
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) 2023 2022 2021 2023 2022 2021 Service cost $ 5,402 $ 8,291 $ 8,730 $ 2,471 $ 4,305 $ 4,844 Interest cost 15,174 9,632 9,112 9,146 6,355 6,071 Expected return on plan assets (19,972) (21,275) (20,150) (6,721) (7,575) (6,497) Recognized actuarial loss 300 8,745 11,446 — 5,684 7,909 Prior service cost (credit) amortization 103 101 102 — (144) (179) Net periodic benefit cost recognized as expense $ 1,007 $ 5,494 $ 9,240 $ 4,896 $ 8,625 $ 12,148
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 2023 2022 2021 2023 2022 2021 Benefit costs: Discount rate 5.50/5.50% (1) 3.10/3.07% (1) 2.95/2.92% (1) 5.51/5.51% (1) 3.24/3.17% (1) 3.08/3.03% (1) Expected asset return 7.00 % 6.75 % 6.75 % 7.00 % 6.75 % 6.75 % Compensation increase 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) Obligations: Discount rate 5.89/5.87% (1) 5.50/5.50% (1) 3.10/3.07% (1) 5.97/5.94% (1) 5.51/5.51% (1) 3.24/3.17% (1) Compensation increase 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) 3.00/3.50% (1) (1) Percentages for represented and non-represented plans, respectively.
Summary of Pension and OPEB Assets	Information relating to the assumed HCCTR used to determine expected OPEB benefits as of September 30, and the effect of a 1% change in the rate, are as follows: ($ in thousands) 2023 2022 2021 HCCTR 7.4% 6.6% 6.9% Ultimate HCCTR 4.5% 4.5% 4.5% Year ultimate HCCTR reached 2032 2027 2027 Effect of a 1 percentage point increase in the HCCTR on: Year-end benefit obligation $ 30,818 $ 26,710 $ 43,217 Total service and interest cost $ 2,117 $ 2,544 $ 2,959 Effect of a 1 percentage point decrease in the HCCTR on: Year-end benefit obligation $ (25,283) $ (21,853) $ (34,669) Total service and interest costs $ (1,700) $ (1,966) $ (2,253) Pension and OPEB assets held in the master trust, measured at fair value, are summarized as follows: Pension OPEB (Thousands) Quoted Prices in Active Markets for Identical Assets Total Quoted Prices in Active Markets for Identical Assets Total As of September 30, 2023 Assets Registered Investment Companies: Equity Funds: Large Cap Index 81,171 81,171 30,884 30,884 Extended Market Index 17,256 17,256 6,444 6,444 International Stock 48,557 48,557 17,966 17,966 Fixed Income Funds: Emerging Markets 11,471 11,471 4,306 4,306 Core Fixed Income — — 22,241 22,241 High Yield Bond Fund 20,685 20,685 7,651 7,651 Long Duration Fund 58,484 58,484 — — Total assets in the fair value hierarchy $ 237,624 237,624 $ 89,492 89,492 Investments measured at net asset value Collective investment trusts 60,737 17,291 Total assets at fair value $ 298,361 $ 106,783 As of September 30, 2022 Assets Money market funds $ — $ — $ 28 $ 28 Registered Investment Companies: Equity Funds: Large Cap Index 75,394 75,394 26,939 26,939 Extended Market Index 15,783 15,783 5,578 5,578 International Stock 44,846 44,846 16,106 16,106 Fixed Income Funds: Emerging Markets 11,074 11,074 4,026 4,026 Core Fixed Income — — 16,594 16,594 Opportunistic Income — — 3,283 3,283 Ultra Short Duration — — 3,296 3,296 High Yield Bond Fund 19,816 19,816 7,320 7,320 Long Duration Fund 59,084 59,084 — — Total assets in the fair value hierarchy $ 225,997 225,997 $ 83,170 83,170 Investments measured at net asset value Collective investment trusts 58,350 16,566 Total assets at fair value $ 284,347 $ 99,736
Schedule of Mix and Targeted Allocation of Plan Assets	The mix and targeted allocation of the pension and OPEB plans’ assets are as follows: 2024 Assets at Target September 30, Asset Allocation Allocation 2023 2022 U.S. equity securities 34 % 34 % 32 % International equity securities 17 16 16 Fixed income 33 31 32 Collective investment trusts at NAV 16 19 20 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 fiscal years: (Thousands) 2024 2025 2026 2027 2028 2029 - 2033 Pension $ 15,227 $ 16,233 $ 17,255 $ 18,246 $ 19,219 $ 110,341 OPEB $ 6,925 $ 7,602 $ 8,481 $ 9,337 $ 10,211 $ 63,780
Schedule of Valuation Methodologies Used for Assets Measured at Fair Value	The following is a description of the valuation methodologies used for assets measured at fair value: Asset Types Description of the Valuation Methodologies Money Market funds Represents bank balances and money market funds that are valued based on the NAV of shares held at year end. Registered Investment Companies Equity and fixed income funds valued at the NAV of shares held by the plan at year end as reported on the active market on which the individual securities are traded. Collective investment trusts The NAV for collective investment trusts is provided by the Trustee and is used as a practical expedient to estimate fair value. The NAV is based on the value of the underlying assets owned by the fund less liabilities.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Sep. 30, 2023
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Provision	The income tax provision from operations for the fiscal years ended September 30, consists of the following: (Thousands) 2023 2022 2021 Current: Federal $ 13,393 $ 4,238 $ 651 State 7,716 2,104 1,703 Deferred: Federal 36,825 55,968 25,030 State (8,381) 14,185 6,224 Investment/production tax credits (278) (300) (322) Income tax provision $ 49,275 $ 76,195 $ 33,286
Schedule of Deferred Tax Assets and Liabilities	As of September 30, the temporary differences, which give rise to deferred tax assets (liabilities), consist of the following: (Thousands) 2023 2022 Deferred tax assets Investment tax credits (1) $ 191,948 $ 212,506 State net operating losses 39,612 36,950 Deferred revenue 8,205 — Fair value of derivatives 5,386 6,506 Impairment of equity method investment 14,004 14,124 Postemployment benefits 6,502 2,751 Incentive compensation 8,949 7,297 Amortization of intangibles 6,308 6,474 Overrecovered natural gas costs 8,564 4,977 Allowance for doubtful accounts 4,485 5,761 Other 7,636 5,748 Total deferred tax assets 301,599 303,094 Less: Valuation allowance (5,747) (22,241) Total deferred tax assets net of valuation allowance $ 295,852 $ 280,853 Deferred tax liabilities Property-related items $ (487,294) $ (468,115) Remediation costs (18,532) (18,490) Investments in equity investees (28,325) (19,176) Conservation incentive program (14,075) (6,457) Other (4,670) (4,615) Total deferred tax liabilities $ (552,896) $ (516,853) Total net deferred tax liabilities $ (257,044) $ (236,000) (1) Includes approximately $0.7M for NJNG for both fiscal 2023 and 2022, which is being amortized over the life of the related assets.
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of the U.S. federal statutory rate to the effective rate from operations for the fiscal years ended September 30, is as follows: (Thousands) 2023 2022 2021 Statutory income tax expense $ 65,940 $ 73,735 $ 31,747 Change resulting from: Investment/production tax credits (278) (300) (322) Cost of removal of assets placed in service prior to 1981 (4,758) (3,533) (5,366) AFUDC equity (1,499) (2,361) (786) State income taxes, net of federal benefit 13,293 13,072 6,124 Valuation allowance (16,494) (1,372) 5,974 Tax Act - utility excess deferred income taxes amortized (3,573) (3,573) (3,573) Other (3,356) 527 (512) Income tax provision $ 49,275 $ 76,195 $ 33,286 Effective income tax rate 15.7 % 21.7 % 22.0 %
Schedule of Uncertain Tax Benefits	The reserve for uncertain tax benefits is as follows: (Thousands) 2023 2022 Balance at October 1, $ — $ — Additions based on tax positions related to the current fiscal period 4,978 — Balance at September 30, $ 4,978 $ —

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Sep. 30, 2023
Leases [Abstract]
Lease, Cost	The following table presents the Company’s lease costs included in the Consolidated Statements of Operations for the fiscal year ended September 30: (Thousands) Income Statement Location 2023 2022 2021 Operating lease cost (1) Operation and maintenance $ 9,336 $ 9,702 $ 8,182 Finance lease cost Amortization of right-of-use assets Depreciation and amortization 2,105 1,769 $ 3,442 Interest on lease liabilities Interest expense, net of capitalized interest 1,084 612 710 Total finance lease cost $ 3,189 $ 2,381 4,152 Short-term lease cost Operation and maintenance — 34 543 Variable lease cost Operation and maintenance 1,128 781 1,381 Total lease cost $ 13,653 $ 12,898 $ 14,258 (1) Net of capitalized costs. The following table presents supplemental cash flow information related to leases for the fiscal year ended September 30: (Thousands) 2023 2022 2021 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for operating leases $ 8,942 $ 7,417 $ 6,675 Operating cash flows for finance leases $ 1,084 $ 831 $ 1,167 Financing cash flows for finance leases $ 7,379 $ 7,145 $ 8,180
Assets and Liabilities, Lessee	The following table presents the balance and classifications of the Company’s right of use assets and lease liabilities included in the Consolidated Balance Sheets for the fiscal year ended September 30: (Thousands) Balance Sheet Location 2023 2022 Assets Noncurrent Operating lease assets Operating lease assets $ 175,740 $ 168,520 Finance lease assets Utility plant 28,248 21,913 Total lease assets $ 203,988 $ 190,433 Liabilities Current Operating lease liabilities Operating lease liabilities $ 4,772 $ 4,562 Finance lease liabilities Current maturities of long-term debt 8,477 6,538 Noncurrent Operating lease liabilities Operating lease liabilities 148,023 138,382 Finance lease liabilities Long-term debt 22,875 23,752 Total lease liabilities $ 184,147 $ 173,234
Operating Lease Liability, Maturity	The following table presents the Company’s maturities of lease liabilities as of September 30, 2023: (Thousands) Operating Finance 2024 $ 7,913 $ 9,362 2025 7,875 7,479 2026 7,799 6,407 2027 7,743 4,083 2028 7,803 4,715 Thereafter 213,927 1,676 Total future payments 253,060 33,722 Less: interest (100,265) (2,370) Total liability $ 152,795 $ 31,352
Finance Lease Liability, Maturity	Contractual commitments for meter financing obligation payments, which include the most likely outcome of cash payments to the lessor, as of the fiscal years ended September 30, are as follows: (Thousands) 2024 2025 2026 2027 2028 Thereafter Subtotal Lease Payments $ 9,362 7,479 6,407 4,083 4,715 1,676 $ 33,722 Less: Interest component (2,370) Total $ 31,352 The following table presents the Company’s maturities of lease liabilities as of September 30, 2023: (Thousands) Operating Finance 2024 $ 7,913 $ 9,362 2025 7,875 7,479 2026 7,799 6,407 2027 7,743 4,083 2028 7,803 4,715 Thereafter 213,927 1,676 Total future payments 253,060 33,722 Less: interest (100,265) (2,370) Total liability $ 152,795 $ 31,352

COMMITMENTS AND CONTINGENT LI_2

COMMITMENTS AND CONTINGENT LIABILITIES (Tables)	12 Months Ended
	Sep. 30, 2023
Commitments and Contingencies Disclosure [Abstract]
Schedule of Commitments for Natural Gas Purchases and Future Demands Fees for the Next Five Years	Commitments as of September 30, 2023, for natural gas purchases and future demand fees for the next five fiscal year periods, are as follows: (Thousands) 2024 2025 2026 2027 2028 Thereafter ES: Natural gas purchases $ 66,525 $ 2,498 $ — $ — $ — $ — Storage demand fees 16,944 8,099 6,010 4,878 3,505 6,780 Pipeline demand fees 43,755 43,271 31,749 24,234 13,719 14,457 Sub-total ES $ 127,224 $ 53,868 $ 37,759 $ 29,112 $ 17,224 $ 21,237 NJNG: Natural gas purchases $ 23,952 $ — $ — $ — $ — $ — Storage demand fees 42,469 30,673 14,975 10,163 5,084 — Pipeline demand fees 155,875 155,559 134,555 128,651 113,998 966,963 Sub-total NJNG $ 222,296 $ 186,232 $ 149,530 $ 138,814 $ 119,082 $ 966,963 Total $ 349,520 $ 240,100 $ 187,289 $ 167,926 $ 136,306 $ 988,200

REPORTING SEGMENT AND OTHER O_2

REPORTING SEGMENT AND OTHER OPERATIONS DATA (Tables)	12 Months Ended
	Sep. 30, 2023
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Information related to the Company’s various reporting segments and other business operations, as of September 30, is detailed below: Segments (Thousands) NJNG CEV ES S&T Subtotal HSO Elims Total 2023 Operating revenues External customers $ 1,011,284 124,131 681,446 (1) 88,700 $ 1,905,561 57,433 — $ 1,962,994 Intercompany $ 1,349 — 10,170 4,159 $ 15,678 205 (15,883) $ — Depreciation and amortization $ 102,326 25,320 221 (2) 24,185 $ 152,052 889 — $ 152,941 Interest income (3) $ 1,713 — 1,119 6,957 $ 9,789 2,977 (3,847) $ 8,919 Interest expense, net of capitalized interest $ 56,595 28,569 11,400 25,803 $ 122,367 647 — $ 123,014 Income tax provision (benefit) $ 33,065 (7,683) 24,343 3,444 $ 53,169 (1,477) (2,417) $ 49,275 Equity in earnings of affiliates $ — — — 3,126 $ 3,126 — 804 $ 3,930 Net financial earnings $ 131,414 44,458 68,517 12,835 $ 257,224 4,758 (155) $ 261,827 Capital expenditures $ 390,394 107,303 — 40,916 $ 538,613 2,306 — $ 540,919 2022 Operating revenues External customers $ 1,127,417 128,280 1,529,178 (1) 65,286 $ 2,850,161 55,818 — $ 2,905,979 Intercompany $ 1,350 — 94 2,449 $ 3,893 364 (4,257) $ — Depreciation and amortization $ 94,579 21,396 148 (2) 12,302 $ 128,425 824 — $ 129,249 Interest income (3) $ 895 — 16 2,110 $ 3,021 944 (1,249) $ 2,716 Interest expense, net of capitalized interest $ 46,394 21,968 4,725 12,097 $ 85,184 646 — $ 85,830 Income tax provision $ 40,141 11,361 21,776 1,879 $ 75,157 1,059 (21) $ 76,195 Equity in earnings of affiliates $ — — — 9,865 $ 9,865 — (1,688) $ 8,177 Net financial earnings (loss) $ 140,124 39,403 39,121 22,454 $ 241,102 (781) — $ 240,321 Capital expenditures $ 298,374 146,676 — 151,988 $ 597,038 1,390 — $ 598,428 Return of capital from equity investees $ — — — (5,479) $ (5,479) — — $ (5,479) 2021 Operating revenues External customers $ 731,796 95,275 1,228,846 (1) 49,252 $ 2,105,169 51,444 — $ 2,156,613 Intercompany $ — — (426) 1,768 $ 1,342 785 (2,127) $ — Depreciation and amortization $ 80,045 20,567 111 (2) 9,960 $ 110,683 980 (276) $ 111,387 Interest income (3) $ 85 241 11 2,243 $ 2,580 522 (935) $ 2,167 Interest expense, net of capitalized interest $ 36,405 22,548 2,204 13,348 $ 74,505 4,054 — $ 78,559 Income tax provision (benefit) $ 19,054 5,048 18,371 (10,043) $ 32,430 (196) 1,052 $ 33,286 Equity in loss of affiliates $ — — — (81,072) $ (81,072) — (2,140) $ (83,212) Net financial earnings (loss) $ 107,375 16,789 71,117 13,046 $ 208,327 (826) 211 $ 207,712 Capital expenditures $ 426,628 87,852 — 107,500 $ 621,980 2,630 — $ 624,610 Investments in equity investees $ — — — 690 $ 690 — — $ 690 (1) Includes sales to Canada for ES, which are $8.4M, $2.4M and $0.1M in the fiscal years ended September 30, 2023, 2022 and 2021, respectively. (2) The amortization of acquired wholesale energy contracts is excluded above and is included in natural gas purchases - nonutility on the Consolidated Statements of Operations. (3) Included in other income, net on the Consolidated Statements of Operations.
Schedule of Assets for Business Segments and Other Business Operations	The Company’s assets at end of period for the various reporting segments and other business operations, as of September 30, are detailed below: Segments Intercompany (Thousands) NJNG CEV ES S&T Subtotal HSO Assets (1) Total 2023 $ 4,414,829 1,128,577 123,775 1,011,959 $ 6,679,140 171,275 (312,919) $ 6,537,496 2022 $ 4,030,686 1,015,065 333,064 999,520 $ 6,378,335 159,068 (275,987) $ 6,261,416 2021 $ 3,707,461 914,788 365,423 862,407 $ 5,850,079 162,134 (289,935) $ 5,722,278 (1) Consists of transactions between subsidiaries that are eliminated and reclassified in consolidation.
Reconciliation of Consolidated NFE to Consolidated Net Income	A reconciliation of consolidated NFE to consolidated net income, as of September 30, is as follows: (Thousands) 2023 2022 2021 Net financial earnings $ 261,827 $ 240,321 $ 207,712 Less: Unrealized (gain) loss on derivative instruments and related transactions (38,081) (59,906) 54,203 Tax effect 9,050 14,248 (12,887) Effects of economic hedging related to natural gas inventory 34,699 19,939 (42,405) Tax effect (8,246) (4,738) 10,078 (Gain on) impairment of equity method investment (300) (5,521) 92,000 Tax effect (19) 1,377 (11,167) Net income $ 264,724 $ 274,922 $ 117,890

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Sep. 30, 2023
Related Party Transactions [Abstract]
Schedule of Demand Fees and Demand Fees Payable	Demand fees, net of eliminations, associated with Steckman Ridge during the fiscal years ended September 30, were as follows: (Thousands) 2023 2022 2021 NJNG $ 6,549 $ 6,663 $ 6,449 ES 657 732 564 Total $ 7,206 $ 7,395 $ 7,013 The following table summarizes demand fees payable to Steckman Ridge as of September 30: (Thousands) 2023 2022 NJNG $ 775 $ 775 ES 84 76 Total $ 859 $ 851

NATURE OF THE BUSINESS (Details

NATURE OF THE BUSINESS (Details)	12 Months Ended
	Sep. 30, 2023 subsidiary customer
Steckman Ridge
Nature of Business [Line Items]
Ownership percentage	50%
PennEast
Nature of Business [Line Items]
Ownership percentage	20%
NJNG
Nature of Business [Line Items]
Total retail customers | customer	576,000
NJR Retail Holdings Corporation
Nature of Business [Line Items]
Number of principal subsidiaries | subsidiary	1

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ADDITIONAL INFORMATION (Details)	1 Months Ended	12 Months Ended
	Jul. 31, 2021 Megawatt	Sep. 30, 2023 USD ($) plan	Sep. 30, 2022 USD ($)	Sep. 30, 2021 USD ($)
Finite-Lived Intangible Assets [Line Items]
Number of megawatts | Megawatt	5
Operating revenues		$ 1,962,994,000	$ 2,905,979,000	$ 2,156,613,000
Composite rate of depreciation		2.68%	2.66%	2.42%
Depreciation and amortization		$ 152,941,000	$ 129,249,000	$ 111,387,000
SBC interest rate		4.79%	3.85%	1.68%
Deferred interest		$ 1,800,000	$ 900,000	$ 300,000
Loans receivable in other noncurrent assets		39,000,000	34,700,000
Gain (loss) amortized in earning		200,000	200,000
Amounts reclassified from accumulated other comprehensive income, net of tax		1,217,000	4,122,000
Intangible assets, acquired wholesale natural gas energy		$ 100,000
Number of noncontributory defined benefit retirement plans (in plans) | plan		2
Number of noncontributory medical and life insurance plans (in plans) | plan		2
Pension
Finite-Lived Intangible Assets [Line Items]
Employer discretionary contributions		$ 0	0
Employer contributions		579,000	628,000
OPEB
Finite-Lived Intangible Assets [Line Items]
Employer contributions		4,192,000	6,082,000
Cash Flow Hedges
Finite-Lived Intangible Assets [Line Items]
Amounts reclassified from accumulated other comprehensive income, net of tax		1,053,000	1,054,000
Financial Asset, Not Past Due
Finite-Lived Intangible Assets [Line Items]
Loans receivable in other current assets		$ 15,100,000	14,500,000
Seven-Year Treasury Rate
Finite-Lived Intangible Assets [Line Items]
Debt instrument, term		7 years
Basis spread on variable rate		0.60%
Storage and Transportation Property, Base Gas | Unregulated
Finite-Lived Intangible Assets [Line Items]
Base gas cost		$ 20,900,000	15,100,000
Minimum
Finite-Lived Intangible Assets [Line Items]
Storage and pipeline capacity, contract term		1 year
Loans receivable term		2 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Storage and pipeline capacity, contract term		10 years
Loans receivable term		10 years
ES
Finite-Lived Intangible Assets [Line Items]
Operating revenues		$ 48,500,000	53,000,000
Deferred revenue		$ 58,700,000	$ 33,800,000
ES | Minimum
Finite-Lived Intangible Assets [Line Items]
Storage and pipeline capacity, contract term		1 year
ES | Maximum
Finite-Lived Intangible Assets [Line Items]
Storage and pipeline capacity, contract term		10 years

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - DEMAND FEES (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Demand fees	$ 258	$ 265.7	$ 243.7
ES
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Demand fees	74.6	95.4	120.5
NJNG
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Demand fees	$ 183.4	$ 170.3	$ 123.2

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - PROPERTY PLANT AND EQUIPMENT (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Property Classifications
Total property, plant and equipment	$ 5,990,539	$ 5,515,716
Accumulated depreciation and amortization	(968,484)	(865,790)
Property, plant and equipment, net	5,022,055	4,649,926
Distribution facilities
Property Classifications
Total property, plant and equipment	$ 3,063,111	2,797,936
Distribution facilities | Minimum
Property Classifications
Estimated Useful Lives	11 years
Distribution facilities | Maximum
Property Classifications
Estimated Useful Lives	54 years
Transmission facilities
Property Classifications
Total property, plant and equipment	$ 650,817	649,241
Transmission facilities | Minimum
Property Classifications
Estimated Useful Lives	28 years
Transmission facilities | Maximum
Property Classifications
Estimated Useful Lives	42 years
Storage facilities
Property Classifications
Total property, plant and equipment	$ 85,603	85,449
Storage facilities | Minimum
Property Classifications
Estimated Useful Lives	27 years
Storage facilities | Maximum
Property Classifications
Estimated Useful Lives	86 years
Solar property
Property Classifications
Total property, plant and equipment	$ 864,838	710,224
Solar property | Minimum
Property Classifications
Estimated Useful Lives	20 years
Solar property | Maximum
Property Classifications
Estimated Useful Lives	35 years
Storage and transportation property
Property Classifications
Total property, plant and equipment	$ 884,647	850,186
Storage and transportation property | Minimum
Property Classifications
Estimated Useful Lives	5 years
Storage and transportation property | Maximum
Property Classifications
Estimated Useful Lives	50 years
All other property
Property Classifications
Total property, plant and equipment	$ 61,327	60,914
All other property | Minimum
Property Classifications
Estimated Useful Lives	5 years
All other property | Maximum
Property Classifications
Estimated Useful Lives	40 years
Construction work in progress
Property Classifications
Total property, plant and equipment	$ 380,196	$ 361,766

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CAPITALIZED AND DEFERRED INTEREST (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
NJNG
AFUDC:
Debt	$ 3,546	$ 1,648	$ 5,648
Equity	6,979	4,169	16,605
Total	$ 10,525	$ 5,817	$ 22,253
Weighted average interest rate	6.41%	4.91%	5.97%
Adelphia
AFUDC:
Debt	$ 90	$ 4,019	$ 2,101
Equity	158	7,074	3,698
Total	$ 248	$ 11,093	$ 5,799
Weighted average interest rate	8.28%	8.28%	8.28%

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CASH, CASH EQUIVALENTS AND RESTRICTED CASH (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2020
Accounting Policies [Abstract]
Cash and cash equivalents	$ 954	$ 1,107	$ 4,749
Restricted cash in other noncurrent assets	563	345	1,294
Cash, cash equivalents and restricted cash	$ 1,517	$ 1,452	$ 6,043	$ 119,423

SUMMARY OF SIGNIFICANT ACCOUN_9

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - NATURAL GAS IN STORAGE (Details) $ in Thousands, Bcf in Millions	Sep. 30, 2023 USD ($) Bcf	Sep. 30, 2022 USD ($) Bcf
Inventory [Line Items]
Natural Gas in Storage, value | $	$ 199,501	$ 273,644
Natural Gas in Storage, Bcf | Bcf	43.7	39.8
NJNG
Inventory [Line Items]
Natural Gas in Storage, value | $	$ 175,025	$ 191,175
Natural Gas in Storage, Bcf | Bcf	29.1	29
ES
Inventory [Line Items]
Natural Gas in Storage, value | $	$ 24,476	$ 82,469
Natural Gas in Storage, Bcf | Bcf	14.6	10.8

SUMMARY OF SIGNIFICANT ACCOU_10

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - SOFTWARE COSTS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Capitalized software costs	$ 8,375	$ 6,120
Software amortization	500	500
Operation and maintenance
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Software costs	14,299	11,141
Depreciation and amortization
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Software costs	4,130	2,024
Utility plant, at cost
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Software costs	51,282	40,437
Construction work in progress | Regulated
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Software costs	55,012	14,381
Nonutility plant and equipment, at cost
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Software costs	344	344
Accumulated depreciation and amortization, utility plant
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Accumulated depreciation and amortization	(7,480)	(3,361)
Accumulated depreciation and amortization, nonutility plant and equipment
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Accumulated depreciation and amortization	$ (36)	$ (25)

SUMMARY OF SIGNIFICANT ACCOU_11

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES- ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Estimated Accretion
2024	$ 3,114
2025	3,268
2026	3,429
2027	3,597
2028	3,781
Future accretion	17,189
NJNG
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at period beginning	49,874	$ 41,611
Accretion	2,693	2,052
Additions	155	161
Change in assumptions	4,089	7,339
Retirements	(1,526)	(1,289)
Balance at period ending	55,285	49,874
NJRCEV
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at period beginning	5,161	4,694
Accretion	213	186
Additions	1,334	281
Change in assumptions	0	0
Retirements	0	0
Balance at period ending	$ 6,708	$ 5,161

SUMMARY OF SIGNIFICANT ACCOU_12

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance as of beginning of period	$ 1,817,210	$ 1,630,862	$ 1,643,896
Other comprehensive income, before reclassifications, net of tax	(6,350)	25,580
Amounts reclassified from accumulated other comprehensive income, net of tax	1,217	4,122
Other comprehensive (loss) income, net of tax	(5,133)	29,702	9,787
Balance as of end of period	1,990,735	1,817,210	1,630,862
Tax on other comprehensive income before reclassifications	1,922	(7,727)
Tax on amounts reclassified from accumulated other comprehensive income	(366)	(1,247)
Tax on net current-period other comprehensive income	1,556	(8,974)
Total
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance as of beginning of period	(4,826)	(34,528)	(44,315)
Other comprehensive (loss) income, net of tax	(5,133)	29,702	9,787
Balance as of end of period	(9,959)	(4,826)	(34,528)
Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance as of beginning of period	(8,322)	(9,376)
Other comprehensive income, before reclassifications, net of tax	0	0
Amounts reclassified from accumulated other comprehensive income, net of tax	1,053	1,054
Other comprehensive (loss) income, net of tax	1,053	1,054
Balance as of end of period	(7,269)	(8,322)	(9,376)
Tax on other comprehensive income before reclassifications	0	0
Tax on amounts reclassified from accumulated other comprehensive income	(317)	(317)
Tax on net current-period other comprehensive income	(317)	(317)
Postemployment Benefit Obligation
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance as of beginning of period	3,496	(25,152)
Other comprehensive income, before reclassifications, net of tax	(6,350)	25,580
Amounts reclassified from accumulated other comprehensive income, net of tax	164	3,068
Other comprehensive (loss) income, net of tax	(6,186)	28,648
Balance as of end of period	(2,690)	3,496	$ (25,152)
Tax on other comprehensive income before reclassifications	1,922	(7,727)
Tax on amounts reclassified from accumulated other comprehensive income	(49)	(930)
Tax on net current-period other comprehensive income	$ 1,873	$ (8,657)

REVENUE - DISAGGREGATED REVENUE

REVENUE - DISAGGREGATED REVENUE - PRODUCT (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 1,111,520	$ 1,198,985	$ 852,105
Alternative revenue programs	27,257	11,259	(7,282)
Derivative instruments	834,387	1,695,829	1,311,364
Revenues out of scope	851,474	1,706,994	1,304,508
Total operating revenues	1,962,994	2,905,979	2,156,613
Natural gas utility sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	845,392	951,626	694,635
Natural gas services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	169,834	151,536	77,953
Service contracts
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	35,210	33,932	33,250
Installations and maintenance
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	22,428	22,250	18,979
Renewable energy certificates
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	12,636	5,487	4,571
Electricity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	31,733	38,317	25,270
ES
Disaggregation of Revenue [Line Items]
Total operating revenues	48,500	53,000
Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues	1,905,561	2,850,161	2,105,169
Operating Segments | NJNG
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	844,043	950,276	694,635
Alternative revenue programs	27,257	11,259	(7,282)
Derivative instruments	139,984	165,882	44,443
Revenues out of scope	167,241	177,141	37,161
Total operating revenues	1,011,284	1,127,417	731,796
Operating Segments | NJNG | Natural gas utility sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	845,392	951,626	694,635
Operating Segments | NJNG | Natural gas services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | NJNG | Service contracts
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | NJNG | Installations and maintenance
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | NJNG | Renewable energy certificates
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | NJNG | Electricity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | CEV
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	44,369	43,804	29,841
Alternative revenue programs	0	0	0
Derivative instruments	79,762	84,476	65,434
Revenues out of scope	79,762	84,476	65,434
Total operating revenues	124,131	128,280	95,275
Operating Segments | CEV | Natural gas utility sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | CEV | Natural gas services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | CEV | Service contracts
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | CEV | Installations and maintenance
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | CEV | Renewable energy certificates
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	12,636	5,487	4,571
Operating Segments | CEV | Electricity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	31,733	38,317	25,270
Operating Segments | ES
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	76,975	83,801	26,933
Alternative revenue programs	0	0	0
Derivative instruments	614,641	1,445,471	1,201,487
Revenues out of scope	604,471	1,445,377	1,201,913
Total operating revenues	681,446	1,529,178	1,228,846
Operating Segments | ES | Natural gas utility sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | ES | Natural gas services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	76,975	83,801	26,933
Operating Segments | ES | Service contracts
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | ES | Installations and maintenance
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | ES | Renewable energy certificates
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | ES | Electricity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | S&T
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	88,700	65,286	49,252
Alternative revenue programs	0	0	0
Derivative instruments	0	0	0
Revenues out of scope	0	0	0
Total operating revenues	88,700	65,286	49,252
Operating Segments | S&T | Natural gas utility sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | S&T | Natural gas services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	92,859	67,735	51,020
Operating Segments | S&T | Service contracts
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | S&T | Installations and maintenance
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | S&T | Renewable energy certificates
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments | S&T | Electricity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Corporate, Non-Segment
Disaggregation of Revenue [Line Items]
Revenues out of scope	0	0	0
Total operating revenues	57,433	55,818	51,444
Corporate, Non-Segment | HSO
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	57,433	55,818	51,444
Alternative revenue programs	0	0	0
Derivative instruments	0	0	0
Revenues out of scope	0	0	0
Total operating revenues	57,433	55,818	51,444
Corporate, Non-Segment | HSO | Natural gas utility sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Corporate, Non-Segment | HSO | Natural gas services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Corporate, Non-Segment | HSO | Service contracts
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	35,210	33,932	33,250
Corporate, Non-Segment | HSO | Installations and maintenance
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	22,428	22,250	18,979
Corporate, Non-Segment | HSO | Renewable energy certificates
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Corporate, Non-Segment | HSO | Electricity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(5,713)	(4,163)	(2,553)
Revenues out of scope	(10,170)	(94)	426
Eliminations | NJNG
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(1,349)	(1,350)	0
Revenues out of scope	0	0	0
Eliminations | CEV
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Revenues out of scope	0	0	0
Eliminations | ES
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Revenues out of scope	(10,170)	(94)	426
Eliminations | S&T
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(4,159)	(2,449)	(1,768)
Revenues out of scope	0	0	0
Eliminations | HSO
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(205)	(364)	(785)
Revenues out of scope	$ 0	$ 0	$ 0

REVENUE - DISAGGREGATED REVEN_2

REVENUE - DISAGGREGATED REVENUE - TYPE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 1,111,520	$ 1,198,985	$ 852,105
Revenues out of scope	851,474	1,706,994	1,304,508
Total operating revenues	1,962,994	2,905,979	2,156,613
Residential
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	692,422	654,886	549,026
Commercial and industrial
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	332,729	446,471	219,981
Firm transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	77,722	92,531	79,256
Interruptible, off-tariff and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	8,647	5,097	3,842
Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues	1,905,561	2,850,161	2,105,169
Corporate, Non-Segment
Disaggregation of Revenue [Line Items]
Revenues out of scope	0	0	0
Total operating revenues	57,433	55,818	51,444
Corporate, Non-Segment | Residential
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	57,091	55,629	50,689
Corporate, Non-Segment | Commercial and industrial
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	342	189	755
Corporate, Non-Segment | Firm transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Corporate, Non-Segment | Interruptible, off-tariff and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
NJNG | Operating Segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	844,043	950,276	694,635
Revenues out of scope	167,241	177,141	37,161
Total operating revenues	1,011,284	1,127,417	731,796
NJNG | Operating Segments | Residential
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	621,663	586,678	487,018
NJNG | Operating Segments | Commercial and industrial
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	136,011	265,970	124,519
NJNG | Operating Segments | Firm transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	77,722	92,531	79,256
NJNG | Operating Segments | Interruptible, off-tariff and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	8,647	5,097	3,842
CEV | Operating Segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	44,369	43,804	29,841
Revenues out of scope	79,762	84,476	65,434
Total operating revenues	124,131	128,280	95,275
CEV | Operating Segments | Residential
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	13,668	12,579	11,319
CEV | Operating Segments | Commercial and industrial
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	30,701	31,225	18,522
CEV | Operating Segments | Firm transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
CEV | Operating Segments | Interruptible, off-tariff and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
ES
Disaggregation of Revenue [Line Items]
Total operating revenues	48,500	53,000
ES | Operating Segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	76,975	83,801	26,933
Revenues out of scope	604,471	1,445,377	1,201,913
Total operating revenues	681,446	1,529,178	1,228,846
ES | Operating Segments | Residential
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
ES | Operating Segments | Commercial and industrial
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	76,975	83,801	26,933
ES | Operating Segments | Firm transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
ES | Operating Segments | Interruptible, off-tariff and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
S&T | Operating Segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	88,700	65,286	49,252
Revenues out of scope	0	0	0
Total operating revenues	88,700	65,286	49,252
S&T | Operating Segments | Residential
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
S&T | Operating Segments | Commercial and industrial
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	88,700	65,286	49,252
S&T | Operating Segments | Firm transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
S&T | Operating Segments | Interruptible, off-tariff and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 0	$ 0	$ 0

REVENUE - TIMING OF REVENUE REC

REVENUE - TIMING OF REVENUE RECOGNITION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Timing of Revenue Recognition [Roll Forward]
Billed, beginning balance	$ 222,297
Customers' credit, beginning balance	33,246	$ 32,586
Increase (decrease) for customers' credits	11,664	660
Billed, ending balance	97,540	222,297
Customers' credit, ending balance	44,910	33,246
Billed
Timing of Revenue Recognition [Roll Forward]
Billed, beginning balance	222,297	212,838
Increase (decrease) for customer accounts receivable	(124,757)	9,459
Billed, ending balance	97,540	222,297
Unbilled
Timing of Revenue Recognition [Roll Forward]
Billed, beginning balance	13,769	10,351
Increase (decrease) for customer accounts receivable	5,331	3,418
Billed, ending balance	$ 19,100	$ 13,769

REVENUE - TIMING OF REVENUE R_2

REVENUE - TIMING OF REVENUE RECOGNITION - BALANCE SHEET (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Disaggregation of Revenue [Line Items]
Customer accounts receivable	$ 97,540	$ 222,297
Unbilled revenues	19,100	13,769
Customers’ credit balances and deposits	(44,910)	(33,246)	$ (32,586)
Customers accounts receivables & Customers' credit balances and deposits	71,730	202,820
Operating Segments | NJNG
Disaggregation of Revenue [Line Items]
Customer accounts receivable	55,234	78,508
Unbilled revenues	10,784	10,814
Customers’ credit balances and deposits	(44,898)	(33,246)
Customers accounts receivables & Customers' credit balances and deposits	21,120	56,076
Operating Segments | CEV
Disaggregation of Revenue [Line Items]
Customer accounts receivable	9,962	5,566
Unbilled revenues	8,316	2,955
Customers’ credit balances and deposits	0	0
Customers accounts receivables & Customers' credit balances and deposits	18,278	8,521
Operating Segments | ES
Disaggregation of Revenue [Line Items]
Customer accounts receivable	23,716	129,199
Unbilled revenues	0	0
Customers’ credit balances and deposits	0	0
Customers accounts receivables & Customers' credit balances and deposits	23,716	129,199
Operating Segments | S&T
Disaggregation of Revenue [Line Items]
Customer accounts receivable	6,577	7,012
Unbilled revenues	0	0
Customers’ credit balances and deposits	(12)	0
Customers accounts receivables & Customers' credit balances and deposits	6,565	7,012
Corporate, Non-Segment
Disaggregation of Revenue [Line Items]
Customer accounts receivable	2,051	2,012
Unbilled revenues	0	0
Customers’ credit balances and deposits	0	0
Customers accounts receivables & Customers' credit balances and deposits	$ 2,051	$ 2,012

REGULATION - ADDITIONAL INFORMA

REGULATION - ADDITIONAL INFORMATION (Details) $ in Thousands

1 Months Ended

2 Months Ended

3 Months Ended

12 Months Ended

Sep. 27, 2023 USD ($)

Sep. 18, 2023 USD ($)

Sep. 11, 2023 USD ($)

Jul. 28, 2023 USD ($)

Jun. 28, 2023 USD ($)

Jun. 01, 2023 USD ($)

Apr. 12, 2023 USD ($)

Mar. 30, 2023 USD ($)

Feb. 22, 2023 USD ($)

Sep. 30, 2022 USD ($)

Jul. 31, 2022 USD ($)

Mar. 31, 2022 USD ($)

Jan. 31, 2022 USD ($)

Nov. 30, 2021 USD ($)

Jun. 30, 2021 USD ($)

Apr. 30, 2021 USD ($)

Mar. 31, 2021 USD ($)

Oct. 31, 2020 USD ($)

May 31, 2020 USD ($)

Feb. 28, 2019 USD ($) projectComponent

Jan. 31, 2021 USD ($)

May 31, 2023 USD ($)

Sep. 30, 2023 USD ($) project filing

Schedule of Regulatory Filings [Line Items]

Regulatory assets

$ 500,666

$ 584,830

Number of interim filings during each fiscal year | filing

2

Number of days notice for refund

5 days

NJNG

Schedule of Regulatory Filings [Line Items]

Regulatory assets

495,300

$ 579,599

Interim rate increase (decrease), amount

$ 28,200

Approved rate increase (decrease), amount

$ 31,400

$ 28,900

NJNG | COVID-19 Pandemic

Schedule of Regulatory Filings [Line Items]

Regulatory assets

6,900

$ 3,900

Environmental Remediation Costs

Schedule of Regulatory Filings [Line Items]

Regulatory assets, amortization period

7 years

Postemployment and Other Benefit Costs

Schedule of Regulatory Filings [Line Items]

Regulatory assets, amortization period

7 years

Deferred Storm Damage Costs

Schedule of Regulatory Filings [Line Items]

Regulatory assets, amortization period

7 years

Base Rate Stipulation

Schedule of Regulatory Filings [Line Items]

Weighted average cost of capital

6.84%

Approved return on equity

9.60%

Approved equity capital structure, percentage

54%

Public utilities, approved depreciation rate, percentage

2.78%

SAVEGREEN

Schedule of Regulatory Filings [Line Items]

Public utility extension term

3 years

Capital investments approved by the BPU

$ 126,100

Financing options

109,400

Operations and maintenance expense

23,400

Annual recovery increase

$ 9,000

$ 10,700

$ 2,200

SAVEGREEN | Minimum

Schedule of Regulatory Filings [Line Items]

Regulatory assets, amortization period

2 years

Program recovery term

3 years

SAVEGREEN | Maximum

Schedule of Regulatory Filings [Line Items]

Regulatory assets, amortization period

10 years

Program recovery term

10 years

BPU | NJNG

Schedule of Regulatory Filings [Line Items]

Annual recovery increase

$ 700

Approved rate increase (decrease), amount

$ 3,200

3,200

BPU | NJNG

Schedule of Regulatory Filings [Line Items]

Requested rate increase (decrease), amount

$ 79,000

BGSS | NJNG

Schedule of Regulatory Filings [Line Items]

Requested rate increase (decrease), amount

24,200

Interim rate increase (decrease), amount

$ (29,900)

$ (20,600)

$ (32,400)

Interim rate increase (decrease), amount, net of tax

$ (19,300)

BGSS | NJNG

Schedule of Regulatory Filings [Line Items]

Requested rate increase (decrease), amount

(38,600)

81,900

2,900

BGSS Balancing | NJNG

Schedule of Regulatory Filings [Line Items]

Requested rate increase (decrease), amount

(7,400)

9,000

13,000

Conservation Incentive Program | NJNG

Schedule of Regulatory Filings [Line Items]

Requested rate increase (decrease), amount

$ 27,000

$ 27,500

10,200

(6,300)

NJNG EE Recovery Rate | NJNG

Schedule of Regulatory Filings [Line Items]

Annual recovery increase

(3,500)

Approved rate increase (decrease), amount

$ 11,400

RAC

Schedule of Regulatory Filings [Line Items]

Approved rate increase (decrease), amount

$ 2,400

$ 3,700

3,800

$ 600

$ 1,300

NJCEP

Schedule of Regulatory Filings [Line Items]

Approved rate increase (decrease), amount

$ 5,000

$ (900)

2,200

$ (2,900)

$ 6,000

USF

Schedule of Regulatory Filings [Line Items]

Requested rate increase (decrease), amount

$ (1,600)

$ 4,900

SAFE Program

Schedule of Regulatory Filings [Line Items]

Capital investments approved by the BPU

$ 130,000

Capital investments approved by the BPU, period

4 years

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

$ 200,000

Recovery amount

$ 157,500

SAFE II

Schedule of Regulatory Filings [Line Items]

Capital investments approved by the BPU, period

5 years

NJ RISE Program

Schedule of Regulatory Filings [Line Items]

Approved return on equity

9.75%

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

NJ RISE Program | Minimum

Schedule of Regulatory Filings [Line Items]

Approved equity capital structure, percentage

6.74%

NJ RISE Program | Maximum

Schedule of Regulatory Filings [Line Items]

Approved equity capital structure, percentage

6.90%

NJ RISE And SAFE II Capital Investments | NJNG

Schedule of Regulatory Filings [Line Items]

Capital investment costs

$ 3,400

SAFE II and NJ RISE

Schedule of Regulatory Filings [Line Items]

Approved rate increase (decrease), amount

$ 300

Infrastructure Investment Program (IIP) | NJNG

Schedule of Regulatory Filings [Line Items]

Program recovery term

5 years

5 years

Number of project components | projectComponent

2

Public utilities, investments

$ 150,000

$ 507,000

REGULATION - REGULATORY ASSETS

REGULATION - REGULATORY ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-current	$ 73,587	$ 40,086
Regulatory assets-noncurrent	584,830	500,666
Regulatory liability-current	32,287	31,090
Regulatory liabilities-noncurrent	180,458	185,634
NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-current	73,587	40,086
Regulatory assets-noncurrent	579,599	495,300
Regulatory liability-current	30,637	25,779
Regulatory liabilities-noncurrent	180,458	185,634
Adelphia
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-noncurrent	5,231	5,366
Regulatory liability-current	1,650	5,311
Overrecovered natural gas costs | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory liability-current	30,637	17,807
Derivatives at fair value, net | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory liability-current	0	7,972
Regulatory liabilities-noncurrent	0	116
Tax Act impact | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities-noncurrent	180,347	185,367
Other noncurrent regulatory liabilities | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities-noncurrent	111	151
New Jersey Clean Energy Program | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-current	15,804	15,697
Conservation Incentive Program | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-current	50,356	23,099
Derivatives at fair value, net | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-current	6,017	0
Other current regulatory assets | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-current	1,410	1,290
Regulatory assets-noncurrent	51,019	45,828
Expended, net of recoveries
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-noncurrent	66,300
Expended, net of recoveries | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-noncurrent	66,298	66,149
Liability for future expenditures | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-noncurrent	169,390	127,070
Deferred income taxes | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-noncurrent	41,667	40,520
SAVEGREEN | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-noncurrent	83,589	52,690
Postemployment and other benefit costs | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-noncurrent	55,274	56,021
Deferred storm damage costs | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-noncurrent	0	2,172
Cost of removal | NJNG
Schedule of Regulatory Assets And Liabilities [Line Items]
Regulatory assets-noncurrent	$ 112,362	$ 104,850

DERIVATIVE INSTRUMENTS - BALANC

DERIVATIVE INSTRUMENTS - BALANCE SHEET RELATED DISCLOSURES (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Fair Value
Derivative assets, current	$ 30,755	$ 24,635
Derivative liability, current	16,145	49,848
Derivative assets, noncurrent	1,564	6,385
Derivative liabilities, noncurrent	7,967	14,191
Not Designated as Hedging Instrument
Fair Value
Derivative assets	32,319	31,020
Derivative liabilities	24,112	64,039
NJNG | Not Designated as Hedging Instrument | Physical commodity contracts
Fair Value
Derivative assets, current	43	252
Derivative liability, current	488	11
NJNG | Not Designated as Hedging Instrument | Financial commodity contracts
Fair Value
Derivative assets, current	6,110	85
Derivative liability, current	20	6,281
ES | Not Designated as Hedging Instrument | Physical commodity contracts
Fair Value
Derivative assets, current	6,209	9,857
Derivative liability, current	12,757	17,051
Derivative assets, noncurrent	802	376
Derivative liabilities, noncurrent	7,870	13,561
ES | Not Designated as Hedging Instrument | Financial commodity contracts
Fair Value
Derivative assets, current	18,393	14,423
Derivative liability, current	2,880	26,488
Derivative assets, noncurrent	762	6,009
Derivative liabilities, noncurrent	97	630
ES | Not Designated as Hedging Instrument | Foreign currency contracts
Fair Value
Derivative assets, current	0	18
Derivative liability, current	$ 0	$ 17

DERIVATIVE INSTRUMENTS - OFFSET

DERIVATIVE INSTRUMENTS - OFFSETTING OF ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
ES
Asset Derivatives
Fair Value	$ 26,166	$ 30,683
Amounts Offset	(4,213)	(12,619)
Collateral Received/Pledged	(16,178)	(200)
Net Value	5,775	17,864
Liability Derivatives
Fair Value	23,604	57,747
Amounts Offset	(4,213)	(12,619)
Collateral Received/Pledged	(9,728)	0
Net Value	9,663	45,128
ES | Physical commodity contracts
Asset Derivatives
Fair Value	7,011	10,233
Amounts Offset	(1,236)	(404)
Collateral Received/Pledged	0	(200)
Net Value	5,775	9,629
Liability Derivatives
Fair Value	20,627	30,612
Amounts Offset	(1,236)	(404)
Collateral Received/Pledged	(9,728)	0
Net Value	9,663	30,208
ES | Financial commodity contracts
Asset Derivatives
Fair Value	19,155	20,432
Amounts Offset	(2,977)	(12,198)
Collateral Received/Pledged	(16,178)	0
Net Value	0	8,234
Liability Derivatives
Fair Value	2,977	27,118
Amounts Offset	(2,977)	(12,198)
Collateral Received/Pledged	0	0
Net Value	0	14,920
ES | Foreign currency contracts
Asset Derivatives
Fair Value		18
Amounts Offset		(17)
Collateral Received/Pledged		0
Net Value		1
Liability Derivatives
Fair Value		17
Amounts Offset		(17)
Collateral Received/Pledged		0
Net Value		0
NJNG
Asset Derivatives
Fair Value	6,153	337
Amounts Offset	(23)	(85)
Collateral Received/Pledged	0	0
Net Value	6,130	252
Liability Derivatives
Fair Value	508	6,292
Amounts Offset	(23)	(85)
Collateral Received/Pledged	0	0
Net Value	485	6,207
NJNG | Physical commodity contracts
Asset Derivatives
Fair Value	43	252
Amounts Offset	(3)	0
Collateral Received/Pledged	0	0
Net Value	40	252
Liability Derivatives
Fair Value	488	11
Amounts Offset	(3)	0
Collateral Received/Pledged	0	0
Net Value	485	11
NJNG | Financial commodity contracts
Asset Derivatives
Fair Value	6,110	85
Amounts Offset	(20)	(85)
Collateral Received/Pledged	0	0
Net Value	6,090	0
Liability Derivatives
Fair Value	20	6,281
Amounts Offset	(20)	(85)
Collateral Received/Pledged	0	0
Net Value	$ 0	$ 6,196

DERIVATIVE INSTRUMENTS - INCOME

DERIVATIVE INSTRUMENTS - INCOME STATEMENT RELATED DISCLOSURES (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 107,170	$ 9,400	$ (12,696)
ES | Physical commodity contracts | Operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Nonutility	Nonutility	Nonutility
Amount of gain (loss) recognized in income on derivatives	$ 33,610	$ (8,569)	$ 30,011
ES | Physical commodity contracts | Natural gas purchases
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Gas purchases - Utility and Nonutility	Gas purchases - Utility and Nonutility	Gas purchases - Utility and Nonutility
Amount of gain (loss) recognized in income on derivatives	$ (6,846)	$ 3,580	$ 1,052
ES | Financial commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	80,406	14,403	(43,997)
ES | Foreign currency contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	0	(14)	238
NJNG
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	(84,371)	39,984	34,899
NJNG | Physical commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	(34,241)	7,116	2,174
NJNG | Financial commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ (50,130)	$ 32,868	$ 32,725

DERIVATIVE INSTRUMENTS - ADDITI

DERIVATIVE INSTRUMENTS - ADDITIONAL INFORMATION (Details) $ in Thousands, certificate in Millions	12 Months Ended
	Sep. 30, 2023 USD ($) certificate	Sep. 30, 2022 USD ($) certificate
Derivative [Line Items]
Derivative, net liability position, aggregate fair value	$ 100	$ 200
Treasury Lock | Interest expense
Derivative [Line Items]
Amount of pre-tax gain (loss) reclassified from OCI into income	$ (1,400)	$ (1,400)
Physical commodity contracts | ES
Derivative [Line Items]
Number of SRECs (in certificates) | certificate	1.3	1.2

DERIVATIVE INSTRUMENTS - VOLUME

DERIVATIVE INSTRUMENTS - VOLUME (Details) - Bcf	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
NJNG | Long | Futures
Derivative [Line Items]
Notional amount	32.1	30.5
NJNG | Long | Physical commodity contracts
Derivative [Line Items]
Notional amount	12.1	6.8
ES | Long | Physical commodity contracts
Derivative [Line Items]
Notional amount	0.2	2.7
ES | Short | Futures
Derivative [Line Items]
Notional amount	(6.9)	(0.7)

DERIVATIVE INSTRUMENTS - BROKER

DERIVATIVE INSTRUMENTS - BROKER MARGIN DEPOSITS (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
NJNG | Assets, Current
Derivative [Line Items]
Broker margin - current assets	$ 5,915	$ 26,138
ES | Assets, Current
Derivative [Line Items]
Broker margin - current assets	14,881	68,123
ES | Liabilities, Current
Derivative [Line Items]
Broker margin - current liabilities	$ 8,029	$ 0

DERIVATIVE INSTRUMENTS - CREDIT

DERIVATIVE INSTRUMENTS - CREDIT RISK EXPOSURE (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2023 USD ($)
Credit Risk Exposure [Line Items]
Gross Credit Exposure	$ 164,500
Investment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	119,229
Noninvestment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	4,775
Internally-rated investment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	20,343
Internally-rated noninvestment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	$ 20,153

FAIR VALUE - DEBT (Details)

FAIR VALUE - DEBT (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Finance leases	$ 31,352	$ 30,300
NJNG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Finance leases	31,352
Debt issuance costs	9,770	9,528
NJR
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt issuance costs	3,700	3,800
Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Finance leases	20,900	15,700
Level 2 | NJNG | Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	1,467,845	1,292,845
Level 2 | NJNG | Fair market value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	1,097,088	979,388
Level 2 | NJR | Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	1,120,000	1,070,000
Level 2 | NJR | Fair market value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 1,009,448	$ 966,968

FAIR VALUE - ADDITIONAL INFORMA

FAIR VALUE - ADDITIONAL INFORMATION (Details) - USD ($) $ in Millions	Sep. 30, 2023	Sep. 30, 2022
Solar Asset Financing | Fair market value | CEV
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 268.1	$ 124.1

FAIR VALUE - HIERARCHY (Details

FAIR VALUE - HIERARCHY (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Liabilities
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Liabilities and Equity
Fair Value, Measurements, Recurring
Assets
Other	$ 2,641	$ 1,884
Total assets at fair value	35,105	32,963
Liabilities
Total liabilities at fair value	24,112	64,039
Fair Value, Measurements, Recurring | Money market funds
Assets
Assets	145	59
Fair Value, Measurements, Recurring | Physical commodity contracts
Assets
Assets	7,054	10,485
Liabilities
liabilities	21,115	30,623
Fair Value, Measurements, Recurring | Financial commodity contracts
Assets
Assets	25,265	20,517
Liabilities
liabilities	2,997	33,399
Fair Value, Measurements, Recurring | Foreign currency contracts
Assets
Assets		18
Liabilities
liabilities		17
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Other	2,641	1,884
Total assets at fair value	28,051	22,460
Liabilities
Total liabilities at fair value	2,997	33,231
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Money market funds
Assets
Assets	145	59
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Physical commodity contracts
Assets
Assets	0	0
Liabilities
liabilities	0	0
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Financial commodity contracts
Assets
Assets	25,265	20,517
Liabilities
liabilities	2,997	33,231
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign currency contracts
Assets
Assets		0
Liabilities
liabilities		0
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets
Other	0	0
Total assets at fair value	7,054	10,503
Liabilities
Total liabilities at fair value	21,115	30,808
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Money market funds
Assets
Assets	0	0
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Physical commodity contracts
Assets
Assets	7,054	10,485
Liabilities
liabilities	21,115	30,623
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Financial commodity contracts
Assets
Assets	0	0
Liabilities
liabilities	0	168
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Foreign currency contracts
Assets
Assets		18
Liabilities
liabilities		17
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets
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) | Money market funds
Assets
Assets	0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Physical commodity contracts
Assets
Assets	0	0
Liabilities
liabilities	0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Financial commodity contracts
Assets
Assets	0	0
Liabilities
liabilities	$ 0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Foreign currency contracts
Assets
Assets		0
Liabilities
liabilities		$ 0

INVESTMENTS IN EQUITY INVESTE_3

INVESTMENTS IN EQUITY INVESTEES (Details) $ in Thousands	3 Months Ended	7 Months Ended	12 Months Ended
	Jun. 30, 2021 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($) mi	Sep. 30, 2022 USD ($)	Sep. 30, 2021 USD ($)
Schedule of Equity Method Investments [Line Items]
Investments in equity investees		$ 106,571	$ 104,134	$ 106,571
Impairment of equity method investment	$ 92,000		$ 0	0	$ 92,000
Other than temporary impairment, net of tax	$ 74,500
Steckman Ridge
Schedule of Equity Method Investments [Line Items]
Ownership percentage			50%
Investments in equity investees		106,600	$ 104,100	106,600
Steckman Ridge | Related Party
Schedule of Equity Method Investments [Line Items]
Total outstanding principal balance of loans		70,400	$ 70,400	$ 70,400
PennEast
Schedule of Equity Method Investments [Line Items]
Ownership percentage			20%
Construction plan, project area (in miles) | mi			120
PennEast | PennEast
Schedule of Equity Method Investments [Line Items]
Investments in equity investees			$ 0
Distribution		$ 11,000	$ 300

INVESTMENTS IN EQUITY INVESTE_4

INVESTMENTS IN EQUITY INVESTEES - FINANCIAL INFORMATION FOR STECKMAN RIDGE AND PENNEAST (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Income Statement [Abstract]
Operating revenues	$ 1,962,994	$ 2,905,979	$ 2,156,613
Net income (loss)	264,724	274,922	117,890
Assets
Current assets	532,077	756,087
Liabilities
Current liabilities	806,603	1,104,153
Noncurrent liabilities	972,141	854,651
Steckman Ridge
Income Statement [Abstract]
Operating revenues	22,659	19,812	21,847
Gross profit	13,385	11,349	13,350
Income (Loss) from continuing operations,	5,769	8,686	11,483
Net income (loss)	5,769	8,686	11,483
Net income (loss) attributable to NJR	2,884	4,343	5,741
Assets
Current assets	12,724	28,609
Noncurrent assets	193,779	198,052
Liabilities
Current liabilities	148,577	23,618
Noncurrent liabilities	0	140,810
PennEast
Income Statement [Abstract]
Operating revenues	0	0	0
Gross profit	0	0	0
Income (Loss) from continuing operations,	(9,543)	(3,778)	(406,305)
Net income (loss)	(9,543)	(3,778)	(406,305)
Net income (loss) attributable to NJR	(1,909)	(756)	$ (81,261)
Assets
Current assets	1,481	1,801
Noncurrent assets	0	0
Liabilities
Current liabilities	127	82
Noncurrent liabilities	$ 0	$ 500

EARNINGS PER SHARE (Details)

EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Earnings Per Share [Abstract]
Net income	$ 264,724	$ 274,922	$ 117,890
Basic earnings per share
Weighted average shares of common stock outstanding-basic (in shares)	97,028	96,100	96,227
Basic earnings per common share (usd per share)	$ 2.73	$ 2.86	$ 1.23
Diluted earnings per share
Weighted average shares of common stock outstanding-basic (in shares)	97,028	96,100	96,227
Incremental shares (in shares)	599	388	333
Weighted average shares of common stock outstanding-diluted (in shares)	97,627	96,488	96,560
Diluted earnings per common share (usd per share)	$ 2.71	$ 2.85	$ 1.22

DEBT - SCHEDULE OF LONG-TERM DE

DEBT - SCHEDULE OF LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Oct. 24, 2022	Sep. 30, 2022
Debt Instrument [Line Items]
Meter financing obligation	$ 22,875		$ 23,752
Total long-term debt	2,768,017		2,485,402
NJNG
Debt Instrument [Line Items]
Less: Debt issuance costs	(9,770)		(9,528)
Less: Current maturities of long-term debt	(78,477)		(6,538)
Total long-term debt	1,410,950		1,307,069
NJNG | Meter financing obligation
Debt Instrument [Line Items]
Meter financing obligation	$ 31,352		30,290
NJNG | First Mortgage Bonds | Series OO
Debt Instrument [Line Items]
Stated interest rate	3%
Long-term debt	$ 46,500		46,500
NJNG | First Mortgage Bonds | Series PP
Debt Instrument [Line Items]
Stated interest rate	3.15%
Long-term debt	$ 50,000		50,000
NJNG | First Mortgage Bonds | Series QQ
Debt Instrument [Line Items]
Stated interest rate	3.58%
Long-term debt	$ 70,000		70,000
NJNG | First Mortgage Bonds | Series RR
Debt Instrument [Line Items]
Stated interest rate	4.61%
Long-term debt	$ 55,000		55,000
NJNG | First Mortgage Bonds | Series SS
Debt Instrument [Line Items]
Stated interest rate	2.82%
Long-term debt	$ 50,000		50,000
NJNG | First Mortgage Bonds | Series TT
Debt Instrument [Line Items]
Stated interest rate	3.66%
Long-term debt	$ 100,000		100,000
NJNG | First Mortgage Bonds | Series UU
Debt Instrument [Line Items]
Stated interest rate	3.63%
Long-term debt	$ 125,000		125,000
NJNG | First Mortgage Bonds | Series VV
Debt Instrument [Line Items]
Stated interest rate	4.01%
Long-term debt	$ 125,000		125,000
NJNG | First Mortgage Bonds | Series WW
Debt Instrument [Line Items]
Stated interest rate	3.50%
Long-term debt	$ 10,300		10,300
NJNG | First Mortgage Bonds | Series XX
Debt Instrument [Line Items]
Stated interest rate	3.38%
Long-term debt	$ 10,500		10,500
NJNG | First Mortgage Bonds | Series YY
Debt Instrument [Line Items]
Stated interest rate	2.45%
Long-term debt	$ 15,000		15,000
NJNG | First Mortgage Bonds | Series ZZ
Debt Instrument [Line Items]
Stated interest rate	3.76%
Long-term debt	$ 100,000		100,000
NJNG | First Mortgage Bonds | Series AAA
Debt Instrument [Line Items]
Stated interest rate	3.86%
Long-term debt	$ 85,000		85,000
NJNG | First Mortgage Bonds | Series BBB
Debt Instrument [Line Items]
Stated interest rate	2.75%
Long-term debt	$ 9,545		9,545
NJNG | First Mortgage Bonds | Series CCC
Debt Instrument [Line Items]
Stated interest rate	3%
Long-term debt	$ 41,000		41,000
NJNG | First Mortgage Bonds | Series DDD
Debt Instrument [Line Items]
Stated interest rate	3.13%
Long-term debt	$ 50,000		50,000
NJNG | First Mortgage Bonds | Series EEE
Debt Instrument [Line Items]
Stated interest rate	3.13%
Long-term debt	$ 50,000		50,000
NJNG | First Mortgage Bonds | Series FFF
Debt Instrument [Line Items]
Stated interest rate	3.33%
Long-term debt	$ 25,000		25,000
NJNG | First Mortgage Bonds | Series GGG
Debt Instrument [Line Items]
Stated interest rate	2.87%
Long-term debt	$ 25,000		25,000
NJNG | First Mortgage Bonds | Series HHH
Debt Instrument [Line Items]
Stated interest rate	2.97%
Long-term debt	$ 50,000		50,000
NJNG | First Mortgage Bonds | Series III
Debt Instrument [Line Items]
Stated interest rate	2.97%
Long-term debt	$ 50,000		50,000
NJNG | First Mortgage Bonds | Series JJJ
Debt Instrument [Line Items]
Stated interest rate	3.07%
Long-term debt	$ 50,000		50,000
NJNG | First Mortgage Bonds | Series LLL
Debt Instrument [Line Items]
Stated interest rate	4.37%
Long-term debt	$ 50,000		50,000
NJNG | First Mortgage Bonds | Series MMM
Debt Instrument [Line Items]
Stated interest rate	4.71%
Long-term debt	$ 50,000		50,000
NJNG | First Mortgage Bonds | Series NNN
Debt Instrument [Line Items]
Stated interest rate	5.47%
Long-term debt	$ 125,000		0
NJNG | First Mortgage Bonds | Series OOO
Debt Instrument [Line Items]
Stated interest rate	5.56%
Long-term debt	$ 50,000		0
NJR
Debt Instrument [Line Items]
Less: Debt issuance costs	(3,656)		(3,753)
Less: Current maturities of long-term debt	0		(50,000)
Total long-term debt	$ 1,116,344		1,066,247
NJR | Unsecured senior notes 3.20%
Debt Instrument [Line Items]
Stated interest rate	3.20%
Long-term debt	$ 0		50,000
NJR | Unsecured senior notes 3.48%
Debt Instrument [Line Items]
Stated interest rate	3.48%
Long-term debt	$ 100,000		100,000
NJR | Unsecured senior notes 3.54%
Debt Instrument [Line Items]
Stated interest rate	3.54%
Long-term debt	$ 100,000		100,000
NJR | Unsecured senior notes 3.96%
Debt Instrument [Line Items]
Stated interest rate	3.96%
Long-term debt	$ 100,000		100,000
NJR | Unsecured senior notes 3.29%
Debt Instrument [Line Items]
Stated interest rate	3.29%
Long-term debt	$ 150,000		150,000
NJR | Unsecured senior note 3.60%
Debt Instrument [Line Items]
Stated interest rate	3.60%
Long-term debt	$ 130,000		130,000
NJR | Unsecured senior note 3.50%
Debt Instrument [Line Items]
Stated interest rate	3.50%
Long-term debt	$ 130,000		130,000
NJR | Unsecured senior notes 3.25%
Debt Instrument [Line Items]
Stated interest rate	3.25%
Long-term debt	$ 80,000		80,000
NJR | Unsecured senior note 3.13%
Debt Instrument [Line Items]
Stated interest rate	3.13%
Long-term debt	$ 120,000		120,000
NJR | Unsecured Senior Notes 4.38%
Debt Instrument [Line Items]
Stated interest rate	4.38%
Long-term debt	$ 110,000		110,000
NJR | Unsecured Senior Notes 3.64%
Debt Instrument [Line Items]
Stated interest rate	3.64%
Long-term debt	$ 50,000		50,000
NJR | Unsecured Senior Notes 6.14%, Maturing In 2032
Debt Instrument [Line Items]
Stated interest rate		6.14%
Long-term debt		$ 50,000	0
CEV
Debt Instrument [Line Items]
Long-term debt	278,401		130,618
Less: Current maturities of long-term debt	(37,678)		(18,532)
Total CEV long-term debt	$ 240,723		$ 112,086

DEBT - REDEMPTION REQUIREMENTS

DEBT - REDEMPTION REQUIREMENTS (Details) $ in Thousands	Sep. 30, 2023 USD ($)
NJR
Debt Instrument [Line Items]
2024	$ 0
2025	100,000
2026	100,000
2027	110,000
2028	100,000
Thereafter	710,000
NJNG
Debt Instrument [Line Items]
2024	70,000
2025	50,000
2026	0
2027	0
2028	50,000
Thereafter	$ 1,297,845

DEBT - NJR AND NJNG LONG-TERM D

DEBT - NJR AND NJNG LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 28, 2023	Oct. 24, 2022	Sep. 30, 2022
NJR | Unsecured Senior Notes 6.14%, Maturing In 2032
Debt Instrument [Line Items]
Long-term debt			$ 50,000	$ 0
Stated interest rate			6.14%
NJNG
Debt Instrument [Line Items]
NJBPU dividend restriction, equity to capitalization ratio	54.40%
NJNG | Minimum
Debt Instrument [Line Items]
NJBPU dividend restriction, equity to capitalization ratio	30%
NJNG | First Mortgage Bonds
Debt Instrument [Line Items]
Maximum amount that can be issued	$ 1,400,000
NJNG | Senior Notes
Debt Instrument [Line Items]
Face amount		$ 100,000
NJNG | Senior Notes | Unsecured Senior Notes 5.47%
Debt Instrument [Line Items]
Stated interest rate			5.47%
Face amount			$ 125,000
NJNG | Senior Notes | Unsecured Senior Notes 5.56%
Debt Instrument [Line Items]
Stated interest rate		5.56%
Face amount		$ 50,000
NJNG | Senior Notes | Unsecured Senior Notes 5.58%
Debt Instrument [Line Items]
Stated interest rate		5.85%
Face amount		$ 50,000

DEBT - SALE-LEASEBACKS (Details

DEBT - SALE-LEASEBACKS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Debt Instrument [Line Items]
Proceeds from sale leaseback transaction	$ 8,441	$ 17,300	$ 0
Minimum | Meter License
Debt Instrument [Line Items]
Term of contract	7 years
Maximum | Meter License
Debt Instrument [Line Items]
Term of contract	10 years
NJNG
Debt Instrument [Line Items]
Proceeds from sale leaseback transaction	$ 8,400	17,300
Payments for sale leaseback transaction	$ 0	$ 1,100

DEBT - CONTRACTUAL COMMITMENTS

DEBT - CONTRACTUAL COMMITMENTS (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Finance Leases
2024	$ 9,362
2025	7,479
2026	6,407
2027	4,083
2028	4,715
Thereafter	1,676
Total future payments	33,722
Less: Interest component	(2,370)
Total liability	31,352	$ 30,300
NJNG
Finance Leases
2024	9,362
2025	7,479
2026	6,407
2027	4,083
2028	4,715
Thereafter	1,676
Total future payments	33,722
Less: Interest component	(2,370)
Total liability	31,352
CEV
Sale Leaseback Transaction, Net Book Value
2023	54,033
2024	50,663
2025	13,875
2026	16,385
2027	26,392
Thereafter	87,881
Subtotal	249,229
Less: Interest component	(42,942)
Total	$ 206,287

DEBT - CLEAN ENERGY VENTURES (D

DEBT - CLEAN ENERGY VENTURES (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Debt Instrument [Line Items]
Proceeds from sale leaseback transactions - solar	$ 167,790	$ 24,071	$ 17,673
CEV
Debt Instrument [Line Items]
Proceeds from sale leaseback transactions - solar	$ 167,800	$ 24,100
CEV | Minimum
Debt Instrument [Line Items]
Sale leaseback transaction lease term	5 years
CEV | Maximum
Debt Instrument [Line Items]
Sale leaseback transaction lease term	15 years

DEBT - CREDIT FACILITIES AND SH

DEBT - CREDIT FACILITIES AND SHORT-TERM DEBT, ADDITIONAL INFORMATION (Details) - Term Loan - Committed Credit Facilities Due February 2023 - NJR - USD ($)	Feb. 07, 2023	Sep. 30, 2022	Feb. 14, 2022	Feb. 09, 2022
Debt Conversion [Line Items]
Line of credit facility, maximum borrowing capacity	$ 150,000,000	$ 150,000,000
Amount borrowed			$ 100,000,000	$ 50,000,000

DEBT - CREDIT FACILITIES AND _2

DEBT - CREDIT FACILITIES AND SHORT-TERM DEBT (Details) - USD ($)	12 Months Ended
	Sep. 30, 2023	Feb. 07, 2023	Sep. 30, 2022	Aug. 30, 2022
NJR | Letters of Credit on Behalf of NJRES
Short-term Debt [Line Items]
Letters of credit outstanding, amount	$ 5,700,000		$ 9,700,000
NJR | Revolving Credit Facility
Short-term Debt [Line Items]
Commitment fee percentage	0.10%
NJNG | Letter of Credit
Short-term Debt [Line Items]
Letters of credit outstanding, amount	$ 700,000		700,000
NJNG | Revolving Credit Facility
Short-term Debt [Line Items]
Commitment fee percentage	0.075%
Revolving Credit Facility | NJR | Committed Credit Facilities Due September 2027
Short-term Debt [Line Items]
Total borrowing capacity	$ 650,000,000		650,000,000	$ 650,000,000
Loans outstanding	$ 217,300,000		$ 200,150,000
Weighted average interest rate	6.53%		3.97%
Remaining borrowing capacity	$ 426,967,000		$ 440,177,000
Revolving Credit Facility | NJNG | Committed Credit Facilities Due September 2027
Short-term Debt [Line Items]
Total borrowing capacity	250,000,000		250,000,000	$ 250,000,000
Loans outstanding	$ 34,800,000		$ 73,800,000
Weighted average interest rate	5.48%		3.34%
Remaining borrowing capacity	$ 214,469,000		$ 175,469,000
Term Loan | NJR | Committed Credit Facilities Due February 2023
Short-term Debt [Line Items]
Total borrowing capacity		$ 150,000,000	150,000,000
Loans outstanding			$ 150,000,000
Weighted average interest rate			3.81%
Remaining borrowing capacity			$ 0

DEBT - NJR SHORT-TERM DEBT (Det

DEBT - NJR SHORT-TERM DEBT (Details) - NJR	Aug. 30, 2022 USD ($)	Sep. 30, 2023 USD ($) debtInstrument	Sep. 30, 2022 USD ($)
Letters of Credit on Behalf of NJRES
Short-term Debt [Line Items]
Number of debt instruments (in debt instruments) | debtInstrument		7
Letters of credit outstanding, amount		$ 5,700,000	$ 9,700,000
Revolving Credit Facility
Short-term Debt [Line Items]
Number of mutual options, extension period	1 year
Line of credit facility, maximum borrowing capacity, incremental increase	$ 50,000,000
Line of credit facility, maximum borrowing capacity, maximum increase	750,000,000
Line of Credit
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	75,000,000
Committed Credit Facilities Due September 2027 | Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 650,000,000	$ 650,000,000	$ 650,000,000

DEBT - NJNG SHORT-TERM DEBT (De

DEBT - NJNG SHORT-TERM DEBT (Details) - NJNG	Aug. 30, 2022 USD ($)	Sep. 30, 2023 USD ($) debtInstrument	Sep. 30, 2022 USD ($)
Letter of Credit
Line of Credit Facility [Line Items]
Number of debt instruments (in debt instruments) | debtInstrument		2
Letters of credit outstanding, amount		$ 700,000	$ 700,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Number of mutual options, extension period	1 year
Line of credit facility, maximum borrowing capacity, incremental increase	$ 50,000,000
Line of credit facility, maximum borrowing capacity, maximum increase	100,000,000
Line of Credit
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	30,000,000
Committed Credit Facilities Due September 2027 | Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 250,000,000	$ 250,000,000	$ 250,000,000

STOCK-BASED COMPENSATION - NARR

STOCK-BASED COMPENSATION - NARRATIVE (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for future issuance (in shares)	2,774,527
Performance Shares, Market Condition Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)	39,614	44,965	46,813
Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)	73,047	73,561	70,138
Deferred compensation related to unvested performance shares, period	1 year 8 months 12 days
Performance Shares, Subject to Performance Conditions | Vesting September 30, 2025
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)	42,449
Performance Shares, Subject to Performance Conditions | Vesting Annually Over Three Year Period Beginning September 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)	30,598
Award vesting period	3 years
Performance Shares, Subject to Performance Conditions | Vesting September 30, 2024
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)		44,596
Performance Shares, Subject to Performance Conditions | Vesting Annually Over Three Year Period Beginning September 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)		28,965
Award vesting period		3 years
Performance Shares, Subject to Performance Conditions | Vesting September 30, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)			44,156
Performance Shares, Subject to Performance Conditions | Vesting Annually Over Three Year Period Beginning September 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)			25,982
Award vesting period			3 years
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)	190,255	192,121	166,091	155,731
Deferred compensation related to unvested restricted and performance shares	$ 5.2
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)	108,876	97,824	101,621	73,486
Deferred compensation related to unvested restricted and performance shares	$ 1.4
Deferred compensation related to unvested performance shares, period	1 year 9 months 18 days
Restricted Stock | Vesting Annually Over Three Year Period Beginning October 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)	64,080
Award vesting period	3 years
Restricted Stock | Vesting Annually Over Three Year Period Beginning October 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)		54,826
Award vesting period		3 years
Restricted Stock | Vesting Annually Over Three Year Period Beginning October 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)			67,726
Award vesting period			3 years

STOCK-BASED COMPENSATION - STOC

STOCK-BASED COMPENSATION - STOCK-BASED COMPENSATION EXPENSE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense	$ 14,716	$ 14,827	$ 7,149
Income tax benefit	(3,563)	(3,624)	(1,613)
Total, net of tax	11,153	11,203	5,536
Taxes related to stock-based compensation	(588)	(144)	(159)
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense	4,882	4,131	3,856
Restricted and non-restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense	3,647	3,189	3,193
Deferred retention stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense	$ 6,187	$ 7,507	$ 100

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, 2023	Sep. 30, 2022	Sep. 30, 2021	Nov. 15, 2023	Nov. 09, 2022	Nov. 10, 2021
Performance share awards
Shares
Outstanding at beginning of period (in shares)	192,121	166,091	155,731
Granted (in shares)	112,661	118,526	116,951
Vested (in shares)	(105,197)	(76,708)	(54,918)
Cancelled/forfeited (in shares)	(9,330)	(15,788)	(51,673)
Outstanding at end of period (in shares)	190,255	192,121	166,091
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)	$ 36.29	$ 36.08	$ 44.22
Granted (in dollars per share)	46	38.84	33.34
Vested (in dollars per share)	35.07	39.57	44.64
Cancelled/forfeited (in dollars per share)	38.64	37.33	45.32
Outstanding at end of period (in dollars per share)	$ 42.60	$ 36.29	$ 36.08
Total Fair Value of Vested Shares
Total Fair Value of Vested Shares	$ 4,126	$ 2,765	$ 1,673
Percent of awards to common stock					105%	93%
Number of common shares issued (in shares)					26,282	31,116
Percent of awards to common stock, target					100%	100%
Performance share awards | Subsequent Event
Total Fair Value of Vested Shares
Percent of awards to common stock				150%
Number of common shares issued (in shares)				55,832
Percent of awards to common stock, target				100%
Performance share awards | Minimum
Total Fair Value of Vested Shares
Percent of awards to common stock	0%
Performance share awards | Maximum
Total Fair Value of Vested Shares
Percent of awards to common stock	150%
Performance Shares, Subject to Performance Conditions
Shares
Outstanding at beginning of period (in shares)	73,561	70,138
Outstanding at end of period (in shares)	73,047	73,561	70,138
Total Fair Value of Vested Shares
Number of common shares issued (in shares)						0
Performance-based Restricted Stock
Total Fair Value of Vested Shares
Percent of awards to common stock					100%	100%
Number of common shares issued (in shares)					28,965	25,982
Performance-based Restricted Stock | Subsequent Event
Total Fair Value of Vested Shares
Percent of awards to common stock				100%
Number of common shares issued (in shares)				30,598
Performance Shares, TSR
Total Fair Value of Vested Shares
Percent of awards to common stock					112%
Number of common shares issued (in shares)					30,472
Performance Shares, TSR | Subsequent Event
Total Fair Value of Vested Shares
Percent of awards to common stock				150%
Number of common shares issued (in shares)				59,192
Restricted Stock
Shares
Outstanding at beginning of period (in shares)	97,824	101,621	73,486
Granted (in shares)	64,080	54,826	67,726
Vested (in shares)	(48,312)	(47,867)	(34,000)
Cancelled/forfeited (in shares)	(4,716)	(10,756)	(5,591)
Outstanding at end of period (in shares)	108,876	97,824	101,621
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)	$ 36.90	$ 36.87	$ 43.52
Granted (in dollars per share)	46	38.84	33.34
Vested (in dollars per share)	40.30	39.01	44.30
Cancelled/forfeited (in dollars per share)	38.77	37.06	36.34
Outstanding at end of period (in dollars per share)	$ 41.55	$ 36.90	$ 36.87
Total Fair Value of Vested Shares
Total Fair Value of Vested Shares	$ 1,910	$ 1,824	$ 996

STOCK-BASED COMPENSATION - DEFE

STOCK-BASED COMPENSATION - DEFERRED RETENTION STOCK/NON-EMPLOYEE DIRECTOR STOCK (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Scheduled to Vest Immediately | Director
Shares
Granted (in shares)	24,044	30,908	34,994
Weighted Average Grant Date Fair Value
Granted (in dollars per share)	$ 49.58	$ 39.09	$ 35.72
Total Fair Value of Vested Shares
Compensation costs not yet recognized	$ 300
Deferred retention stock
Shares
Outstanding at beginning of period (in shares)	231,267	208,856	228,246
Granted/Vested (in shares)	134,941	192,728	2,999
Delivered (in shares)	(38,115)	(163,499)	(22,389)
Forfeited (in shares)		(6,818)
Outstanding at end of period (in shares)	328,093	231,267	208,856
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)	$ 39.16	$ 46.28	$ 46.32
Granted (in dollars per share)	45.85	38.95	33.34
Vested (in dollars per share)	45.85	38.95	33.34
Delivered (in dollars per share)	40.67	47.95	45
Forfeited (in dollars per share)		40.33
Outstanding at end of period (in dollars per share)	$ 41.74	$ 39.16	$ 46.28
Total Fair Value of Vested Shares
Delivered	$ 1,517	$ 6,167	$ 641

EMPLOYEE BENEFIT PLANS - PENSIO

EMPLOYEE BENEFIT PLANS - PENSION AND OTHER POSTEMPLOYMENT BENEFIT PLANS, NARRATIVE (Details)	12 Months Ended
	Sep. 30, 2023 USD ($) plan	Sep. 30, 2022 USD ($)
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
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer discretionary contributions	$ 0	$ 0
Employer contributions	579,000	628,000
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	4,192,000	$ 6,082,000
OPEB | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated future employer contributions over the next five years	5,000,000
OPEB | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated future employer contributions over the next five years	$ 10,000,000

EMPLOYEE BENEFIT PLANS - SUMMAR

EMPLOYEE BENEFIT PLANS - SUMMARY OF CHANGE IN FUNDED STATUS AND LIABILITIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Postemployment employee benefit asset
Postemployment employee benefit assets	$ 18,684	$ 4,388
Postemployment employee benefit liability
Noncurrent	(102,528)	(82,867)
Pension
Change in Benefit Obligation
Benefit obligation at beginning of year	290,823	395,547
Service cost	5,402	8,291	$ 8,730
Interest cost	15,174	9,632	9,112
Plan participants’ contributions	32	59
Actuarial (gain) loss	(7,057)	(109,320)
Benefits paid, net of retiree subsidies received	(14,053)	(13,386)
Benefit obligation at end of year	290,321	290,823	395,547
Change in plan assets
Fair value of plan assets at beginning of year	284,347	355,284
Actual return (loss) on plan assets	27,456	(58,239)
Employer contributions	579	628
Benefits paid, net of plan participants’ contributions	(14,021)	(13,326)
Fair value of plan assets at end of year	298,361	284,347	355,284
Funded status	8,040	(6,476)
Postemployment employee benefit asset
Postemployment employee benefit assets	18,684	4,388
Postemployment employee benefit liability
Current	(538)	(578)
Noncurrent	(10,106)	(10,286)
Total	8,040	(6,476)
OPEB
Change in Benefit Obligation
Benefit obligation at beginning of year	173,217	244,674
Service cost	2,471	4,305	4,844
Interest cost	9,146	6,355	6,071
Plan participants’ contributions	552	423
Actuarial (gain) loss	25,363	(77,775)
Benefits paid, net of retiree subsidies received	(7,343)	(4,765)
Benefit obligation at end of year	203,406	173,217	244,674
Change in plan assets
Fair value of plan assets at beginning of year	99,736	114,183
Actual return (loss) on plan assets	9,826	(15,996)
Employer contributions	4,192	6,082
Benefits paid, net of plan participants’ contributions	(6,971)	(4,533)
Fair value of plan assets at end of year	106,783	99,736	$ 114,183
Funded status	(96,623)	(73,481)
Postemployment employee benefit asset
Postemployment employee benefit assets	0	0
Postemployment employee benefit liability
Current	(4,201)	(900)
Noncurrent	(92,422)	(72,581)
Total	$ (96,623)	$ (73,481)

EMPLOYEE BENEFIT PLANS - REGULA

EMPLOYEE BENEFIT PLANS - REGULATORY ASSETS AND AOCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Pension
Amounts amortized to net periodic costs:
Net actuarial (loss)	$ (300)	$ (8,745)	$ (11,446)
Prior service (cost) credit	(103)	(101)	(102)
OPEB
Amounts amortized to net periodic costs:
Net actuarial (loss)	0	(5,684)	(7,909)
Prior service (cost) credit	0	144	179
Regulatory Assets | Pension
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Regulatory Assets, Balance at beginning of period	35,321	56,187
Amounts arising during the period, Net actuarial (gain) loss	(10,493)	(14,922)
Amounts amortized to net periodic costs:
Net actuarial (loss)	(87)	(5,843)
Prior service (cost) credit	(103)	(101)
Regulatory Assets, Balance at end of period	24,638	35,321	56,187
Regulatory Assets | OPEB
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Regulatory Assets, Balance at beginning of period	20,110	60,335
Amounts arising during the period, Net actuarial (gain) loss	9,936	(35,781)
Amounts amortized to net periodic costs:
Net actuarial (loss)	0	(4,577)
Prior service (cost) credit	0	133
Regulatory Assets, Balance at end of period	30,046	20,110	60,335
Accumulated Other Comprehensive Income (Loss) | Pension
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss), Balance at beginning of period	5,003	22,790
Amounts arising during the period, Net actuarial (gain) loss	(4,048)	(14,885)
Amounts amortized to net periodic costs:
Net actuarial (loss)	(213)	(2,902)
Prior service (cost) credit	0	0
Accumulated Other Comprehensive Income (Loss), Balance at end of period	742	5,003	22,790
Accumulated Other Comprehensive Income (Loss) | OPEB
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss), Balance at beginning of period	(6,822)	12,696
Amounts arising during the period, Net actuarial (gain) loss	12,320	(18,422)
Amounts amortized to net periodic costs:
Net actuarial (loss)	0	(1,107)
Prior service (cost) credit	0	11
Accumulated Other Comprehensive Income (Loss), Balance at end of period	$ 5,498	$ (6,822)	$ 12,696

EMPLOYEE BENEFIT PLANS - AMOUNT

EMPLOYEE BENEFIT PLANS - AMOUNTS NOT YET RECOGNIZED AS NET PERIODIC COST (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Regulatory Assets | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss (gain)	$ 24,577	$ 35,157
Prior service cost	61	164
Regulatory Assets, Total	24,638	35,321	$ 56,187
Regulatory Assets | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss (gain)	30,046	20,110
Prior service cost	0	0
Regulatory Assets, Total	30,046	20,110	60,335
Accumulated Other Comprehensive Income (Loss) | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss (gain)	742	5,003
Prior service cost	0	0
Accumulated Other Comprehensive Income (Loss), Total	742	5,003	22,790
Accumulated Other Comprehensive Income (Loss) | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss (gain)	5,498	(6,822)
Prior service cost	0	0
Accumulated Other Comprehensive Income (Loss), Total	$ 5,498	$ (6,822)	$ 12,696

EMPLOYEE BENEFIT PLANS - AMOU_2

EMPLOYEE BENEFIT PLANS - AMOUNTS EXPECTED TO BE RECOGNIZED IN NET PERIODIC BENEFIT COST (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2023 USD ($)
Pension
Regulatory Assets
Net actuarial loss (gain)	$ 815
Prior service cost	62
Total	877
Accumulated Other Comprehensive Income (Loss)
Net actuarial loss (gain)	(12)
Prior service cost	0
Total	(12)
OPEB
Regulatory Assets
Net actuarial loss (gain)	667
Prior service cost	0
Total	667
Accumulated Other Comprehensive Income (Loss)
Net actuarial loss (gain)	661
Prior service cost	0
Total	$ 661

EMPLOYEE BENEFIT PLANS - ACCUMU

EMPLOYEE BENEFIT PLANS - ACCUMULATED BENEFIT OBLIGATION (Details) - Pension - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 290,321	$ 290,823
Accumulated benefit obligation	267,794	265,933
Fair value of plan assets	$ 298,361	$ 284,347

EMPLOYEE BENEFIT PLANS - COMPON

EMPLOYEE BENEFIT PLANS - COMPONENTS OF NET PERIODIC COST (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]	Other income, net
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 5,402	$ 8,291	$ 8,730
Interest cost	15,174	9,632	9,112
Expected return on plan assets	(19,972)	(21,275)	(20,150)
Recognized actuarial loss	300	8,745	11,446
Prior service cost (credit) amortization	103	101	102
Net periodic benefit cost recognized as expense	1,007	5,494	9,240
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	2,471	4,305	4,844
Interest cost	9,146	6,355	6,071
Expected return on plan assets	(6,721)	(7,575)	(6,497)
Recognized actuarial loss	0	5,684	7,909
Prior service cost (credit) amortization	0	(144)	(179)
Net periodic benefit cost recognized as expense	$ 4,896	$ 8,625	$ 12,148

EMPLOYEE BENEFIT PLANS - WEIGHT

EMPLOYEE BENEFIT PLANS - WEIGHTED AVERAGE ASSUMPTIONS (Details)	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Pension
Benefit costs:
Expected asset return	7%	6.75%	6.75%
Pension | Represented
Benefit costs:
Discount rate	5.50%	3.10%	2.95%
Compensation increase	3%	3%	3%
Obligations:
Discount rate	5.89%	5.50%	3.10%
Compensation increase	3%	3%	3%
Pension | Nonrepresented
Benefit costs:
Discount rate	5.50%	3.07%	2.92%
Compensation increase	3.50%	3.50%	3.50%
Obligations:
Discount rate	5.87%	5.50%	3.07%
Compensation increase	3.50%	3.50%	3.50%
OPEB
Benefit costs:
Expected asset return	7%	6.75%	6.75%
OPEB | Represented
Benefit costs:
Discount rate	5.51%	3.24%	3.08%
Compensation increase	3%	3%	3%
Obligations:
Discount rate	5.97%	5.51%	3.24%
Compensation increase	3%	3%	3%
OPEB | Nonrepresented
Benefit costs:
Discount rate	5.51%	3.17%	3.03%
Compensation increase	3.50%	3.50%	3.50%
Obligations:
Discount rate	5.94%	5.51%	3.17%
Compensation increase	3.50%	3.50%	3.50%

EMPLOYEE BENEFIT PLANS - ASSUME

EMPLOYEE BENEFIT PLANS - ASSUMED HCCTR (Details) - OPEB - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
HCCTR	7.40%	6.60%	6.90%
Ultimate HCCTR	4.50%	4.50%	4.50%
Effect of a 1 percentage point increase in the HCCTR on:
Year-end benefit obligation	$ 30,818	$ 26,710	$ 43,217
Total service and interest cost	2,117	2,544	2,959
Effect of a 1 percentage point decrease in the HCCTR on:
Year-end benefit obligation	(25,283)	(21,853)	(34,669)
Total service and interest costs	$ (1,700)	$ (1,966)	$ (2,253)

EMPLOYEE BENEFIT PLANS - MIX AN

EMPLOYEE BENEFIT PLANS - MIX AND TARGETED ALLOCATION (Details)	Sep. 30, 2023	Sep. 30, 2022
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	100%
Assets	100%	100%
U.S. equity securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	34%
Assets	34%	32%
International equity securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	17%
Assets	16%	16%
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	33%
Assets	31%	32%
Collective investment trusts at NAV
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	16%
Assets	19%	20%

EMPLOYEE BENEFIT PLANS - EXPECT

EMPLOYEE BENEFIT PLANS - EXPECTED BENEFIT PAYMENTS (Details) $ in Thousands	Sep. 30, 2023 USD ($)
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2024	$ 15,227
2025	16,233
2026	17,255
2027	18,246
2028	19,219
2029 - 2033	110,341
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2024	6,925
2025	7,602
2026	8,481
2027	9,337
2028	10,211
2029 - 2033	$ 63,780

EMPLOYEE BENEFIT PLANS - FAIR V

EMPLOYEE BENEFIT PLANS - FAIR VALUE (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Pension
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	$ 298,361	$ 284,347	$ 355,284
OPEB
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	106,783	99,736	$ 114,183
Fair Value, Inputs, Level 1, 2 and 3 | Pension
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	237,624	225,997
Fair Value, Inputs, Level 1, 2 and 3 | Pension | Large Cap Index
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	81,171	75,394
Fair Value, Inputs, Level 1, 2 and 3 | Pension | Extended Market Index
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	17,256	15,783
Fair Value, Inputs, Level 1, 2 and 3 | Pension | International Stock
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	48,557	44,846
Fair Value, Inputs, Level 1, 2 and 3 | Pension | Emerging Markets
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	11,471	11,074
Fair Value, Inputs, Level 1, 2 and 3 | Pension | Core Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	0	0
Fair Value, Inputs, Level 1, 2 and 3 | Pension | High Yield Bond Fund
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	20,685	19,816
Fair Value, Inputs, Level 1, 2 and 3 | Pension | Long Duration Fund
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	58,484	59,084
Fair Value, Inputs, Level 1, 2 and 3 | Pension | Money market funds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		0
Fair Value, Inputs, Level 1, 2 and 3 | Pension | Opportunistic Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		0
Fair Value, Inputs, Level 1, 2 and 3 | Pension | Ultra Short Duration
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		0
Fair Value, Inputs, Level 1, 2 and 3 | OPEB
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	89,492	83,170
Fair Value, Inputs, Level 1, 2 and 3 | OPEB | Large Cap Index
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	30,884	26,939
Fair Value, Inputs, Level 1, 2 and 3 | OPEB | Extended Market Index
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	6,444	5,578
Fair Value, Inputs, Level 1, 2 and 3 | OPEB | International Stock
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	17,966	16,106
Fair Value, Inputs, Level 1, 2 and 3 | OPEB | Emerging Markets
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	4,306	4,026
Fair Value, Inputs, Level 1, 2 and 3 | OPEB | Core Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	22,241	16,594
Fair Value, Inputs, Level 1, 2 and 3 | OPEB | High Yield Bond Fund
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	7,651	7,320
Fair Value, Inputs, Level 1, 2 and 3 | OPEB | Long Duration Fund
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	0	0
Fair Value, Inputs, Level 1, 2 and 3 | OPEB | Money market funds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		28
Fair Value, Inputs, Level 1, 2 and 3 | OPEB | Opportunistic Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		3,283
Fair Value, Inputs, Level 1, 2 and 3 | OPEB | Ultra Short Duration
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		3,296
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	237,624	225,997
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	81,171	75,394
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	17,256	15,783
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	48,557	44,846
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	11,471	11,074
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 | High Yield Bond Fund
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	20,685	19,816
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	58,484	59,084
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
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
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
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	89,492	83,170
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	30,884	26,939
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	6,444	5,578
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	17,966	16,106
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	4,306	4,026
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	22,241	16,594
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	7,651	7,320
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
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		28
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		3,283
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		3,296
Investments measured at net asset value | Pension | Collective investment trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	60,737	58,350
Investments measured at net asset value | OPEB | Collective investment trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	$ 17,291	$ 16,566

EMPLOYEE BENEFIT PLANS - DEFINE

EMPLOYEE BENEFIT PLANS - DEFINED CONTRIBUTION (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Defined Benefit Plan Disclosure [Line Items]
Defined contribution, company match of employee contribution	85%
Defined contribution plan, maximum employer contribution by percentage of employee salary	6%
Defined contribution plan, cost recognized	$ 5.9	$ 5.5	$ 5.1
Deferred compensation arrangement with individual, employer contribution	$ 2.1	$ 2.4	$ 2.1
NJRHS | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan, employer contribution for employees not qualifying for the defined benefit plan	3.50%
NJRHS | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan, employer contribution for employees not qualifying for the defined benefit plan	4.50%

INCOME TAXES - COMPONENTS OF IN

INCOME TAXES - COMPONENTS OF INCOME TAX PROVISION (BENEFIT) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Current:
Federal	$ 13,393	$ 4,238	$ 651
State	7,716	2,104	1,703
Deferred:
Federal	36,825	55,968	25,030
State	(8,381)	14,185	6,224
Investment/production tax credits	(278)	(300)	(322)
Income tax provision	$ 49,275	$ 76,195	$ 33,286

INCOME TAXES - DEFERRED TAX ASS

INCOME TAXES - DEFERRED TAX ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Deferred tax assets
Investment tax credits	$ 191,948	$ 212,506
State net operating losses	39,612	36,950
Deferred revenue	8,205	0
Fair value of derivatives	5,386	6,506
Impairment of equity method investment	14,004	14,124
Postemployment benefits	6,502	2,751
Incentive compensation	8,949	7,297
Amortization of intangibles	6,308	6,474
Overrecovered natural gas costs	8,564	4,977
Allowance for doubtful accounts	4,485	5,761
Other	7,636	5,748
Total deferred tax assets	301,599	303,094
Less: Valuation allowance	(5,747)	(22,241)
Total deferred tax assets net of valuation allowance	295,852	280,853
Deferred tax liabilities
Property-related items	(487,294)	(468,115)
Remediation costs	(18,532)	(18,490)
Investments in equity investees	(28,325)	(19,176)
Conservation incentive program	(14,075)	(6,457)
Other	(4,670)	(4,615)
Total deferred tax liabilities	(552,896)	(516,853)
Total net deferred tax liabilities	(257,044)	(236,000)
Tax credit carryforward	191,200	211,800
NJNG
Deferred tax liabilities
Tax credit carryforward	$ 700	$ 700

INCOME TAXES - INCOME TAX RECON

INCOME TAXES - INCOME TAX RECONCILIATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory income tax expense	$ 65,940	$ 73,735	$ 31,747
Change resulting from:
Investment/production tax credits	(278)	(300)	(322)
Cost of removal of assets placed in service prior to 1981	(4,758)	(3,533)	(5,366)
AFUDC equity	(1,499)	(2,361)	(786)
State income taxes, net of federal benefit	13,293	13,072	6,124
Valuation allowance	(16,494)	(1,372)	5,974
Tax Act - utility excess deferred income taxes amortized	(3,573)	(3,573)	(3,573)
Other	(3,356)	527	(512)
Income tax provision	$ 49,275	$ 76,195	$ 33,286
Effective income tax rate	15.70%	21.70%	22%

INCOME TAXES - ADDITIONAL INFOR

INCOME TAXES - ADDITIONAL INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Dec. 31, 2022	Sep. 30, 2022	Dec. 31, 2021	Sep. 30, 2021	Dec. 31, 2020
Income Tax Contingency [Line Items]
Deferred employer portion of OASDI	$ 0		$ 2,700		$ 5,100
ITC carryforward	$ 191,200		211,800
Effective term	20 years
Potential net capital loss			56,600
Unrecognized tax benefits	$ 4,978		0		$ 0
Operating loss carryforward, valuation allowance	700		17,200
Reversal of a valuation allowance for certain deferred tax assets	15,800
Investment tax credit, solar property, percentage		26%		26%		26%
Capital Loss Carryforward
Income Tax Contingency [Line Items]
Tax credit carryforward, valuation allowance	5,000		5,100
State and Local Jurisdiction
Income Tax Contingency [Line Items]
Net operating loss carryforwards	$ 631,200		$ 544,400
State and Local Jurisdiction | Minimum
Income Tax Contingency [Line Items]
Effective term	7 years
State and Local Jurisdiction | Maximum
Income Tax Contingency [Line Items]
Effective term	20 years

INCOME TAXES - RESERVE FOR UNCE

INCOME TAXES - RESERVE FOR UNCERTAIN TAX BENEFITS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning balance	$ 0	$ 0
Additions based on tax positions related to the current fiscal period	4,978	0
Ending balance	$ 4,978	$ 0

LEASES - ADDITIONAL INFORMATION

LEASES - ADDITIONAL INFORMATION (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Jul. 31, 2021
Lessee, Lease, Description [Line Items]
ROU asset obtained in exchange for operating lease liability	$ 13.2	$ 0.9
ROU asset obtained in exchange for finance lease liability	$ 8.4	$ 17.3
Weighted average remaining lease term, operating lease	29 years 2 months 12 days	29 years 2 months 12 days
Operating lease, discount rate	3.50%	3.20%
Weighted average remaining lease term, finance lease	3 years 3 months 18 days	4 years
Finance lease, discount rate	2.70%	2.70%
Solar Property | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	20 years
Renewal term	5 years
Solar Property | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	50 years
Renewal term	20 years
Office Building
Lessee, Lease, Description [Line Items]
Term of contract			16 years
Office Building | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	2 years
Office Building | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	17 years
Meter License | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	7 years
Meter License | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	10 years
Equipment
Lessee, Lease, Description [Line Items]
Term of contract	8 years
Storage and Capacity
Lessee, Lease, Description [Line Items]
Term of contract	50 years

LEASES - LEASE COST (Details)

LEASES - LEASE COST (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Leases [Abstract]
Operating lease cost	$ 9,336	$ 9,702	$ 8,182
Amortization of right-of-use assets	2,105	1,769	3,442
Interest on lease liabilities	1,084	612	710
Total finance lease cost	3,189	2,381	4,152
Short-term lease cost	0	34	543
Variable lease cost	1,128	781	1,381
Total lease cost	$ 13,653	$ 12,898	$ 14,258

LEASES - SUPPLEMENTAL CASH FLOW

LEASES - SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Leases [Abstract]
Operating cash flows for operating leases	$ 8,942	$ 7,417	$ 6,675
Operating cash flows for finance leases	1,084	831	1,167
Financing cash flows for finance leases	$ 7,379	$ 7,145	$ 8,180

LEASES - RIGHT-OF-USE ASSETS AN

LEASES - RIGHT-OF-USE ASSETS AND LEASE LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Noncurrent
Operating lease assets	$ 175,740	$ 168,520
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Utility plant, at cost	Utility plant, at cost
Finance lease assets	$ 28,248	$ 21,913
Total lease assets	203,988	190,433
Current
Operating lease liabilities	$ 4,772	$ 4,562
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Current maturities of long-term debt	Current maturities of long-term debt
Finance lease liabilities	$ 8,477	$ 6,538
Noncurrent
Operating lease liabilities	$ 148,023	$ 138,382
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Long-term debt	Long-term debt
Finance lease liabilities	$ 22,875	$ 23,752
Total lease liabilities	$ 184,147	$ 173,234

LEASES - MATURITIES OF LEASE LI

LEASES - MATURITIES OF LEASE LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Operating
2024	$ 7,913
2025	7,875
2026	7,799
2027	7,743
2028	7,803
Thereafter	213,927
Total future payments	253,060
Less: interest	(100,265)
Total liability	152,795
Finance Leases
2024	9,362
2025	7,479
2026	6,407
2027	4,083
2028	4,715
Thereafter	1,676
Total future payments	33,722
Less: interest	(2,370)
Total liability	$ 31,352	$ 30,300

COMMITMENTS AND CONTINGENT LI_3

COMMITMENTS AND CONTINGENT LIABILITIES - SCHEDULE OF FUTURE COMMITTED EXPENSES (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2023 USD ($)
Long-term Purchase Commitment [Line Items]
Current charges recoverable through BGSS	$ 198,300
Purchase Obligation, Fiscal Year Maturity [Abstract]
2024	349,520
2025	240,100
2026	187,289
2027	167,926
2028	136,306
Thereafter	988,200
Operating leases, future minimum payments due, next five years (not more than)	7,900
Thereafter	213,927
ES
Purchase Obligation, Fiscal Year Maturity [Abstract]
2024	127,224
2025	53,868
2026	37,759
2027	29,112
2028	17,224
Thereafter	21,237
ES | Natural gas purchases
Purchase Obligation, Fiscal Year Maturity [Abstract]
2024	66,525
2025	2,498
2026	0
2027	0
2028	0
Thereafter	0
ES | Storage demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2024	16,944
2025	8,099
2026	6,010
2027	4,878
2028	3,505
Thereafter	6,780
ES | Pipeline demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2024	43,755
2025	43,271
2026	31,749
2027	24,234
2028	13,719
Thereafter	14,457
Annual pipeline obligation to be paid over 10 year period	4,000
NJNG
Purchase Obligation, Fiscal Year Maturity [Abstract]
2024	222,296
2025	186,232
2026	149,530
2027	138,814
2028	119,082
Thereafter	966,963
NJNG | Natural gas purchases
Purchase Obligation, Fiscal Year Maturity [Abstract]
2024	23,952
2025	0
2026	0
2027	0
2028	0
Thereafter	0
NJNG | Storage demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2024	42,469
2025	30,673
2026	14,975
2027	10,163
2028	5,084
Thereafter	0
NJNG | Pipeline demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2024	155,875
2025	155,559
2026	134,555
2027	128,651
2028	113,998
Thereafter	$ 966,963
Minimum
Long-term Purchase Commitment [Line Items]
Storage and pipeline capacity, contract term	1 year
Minimum | ES
Long-term Purchase Commitment [Line Items]
Storage and pipeline capacity, contract term	1 year
Maximum
Long-term Purchase Commitment [Line Items]
Storage and pipeline capacity, contract term	10 years
Maximum | ES
Long-term Purchase Commitment [Line Items]
Storage and pipeline capacity, contract term	10 years

COMMITMENTS AND CONTINGENT LI_4

COMMITMENTS AND CONTINGENT LIABILITIES - GUARANTEES (Details) $ in Millions	Sep. 30, 2023 USD ($)
Guarantee Obligations
Guarantor Obligations [Line Items]
Loss contingency, estimate of possible loss	$ 192.3

COMMITMENTS AND CONTINGENT LI_5

COMMITMENTS AND CONTINGENT LIABILITIES - LEGAL PROCEEDINGS (Details) - USD ($) $ in Thousands				1 Months Ended			12 Months Ended
	Sep. 11, 2023	Apr. 12, 2023	Apr. 07, 2021	Sep. 30, 2022	Mar. 31, 2022	Apr. 30, 2021	Sep. 30, 2023
Loss Contingencies [Line Items]
Manufactured gas plant remediation				$ 127,060			$ 169,390
Recovery from third party of environmental remediation cost, period							7 years
Regulatory assets				500,666			$ 584,830
Expended, net of recoveries
Loss Contingencies [Line Items]
Regulatory assets							66,300
RAC
Loss Contingencies [Line Items]
Approved rate, amount		$ 15,400	$ 11,100		$ 11,700
Approved rate increase (decrease), amount	$ 2,400	$ 3,700		$ 3,800	$ 600	$ 1,300
Minimum
Loss Contingencies [Line Items]
Product liability contingency, loss exposure in excess of accrual, best estimate							137,300
Maximum
Loss Contingencies [Line Items]
Product liability contingency, loss exposure in excess of accrual, best estimate							$ 201,500

REPORTING SEGMENT AND OTHER O_3

REPORTING SEGMENT AND OTHER OPERATIONS DATA - RECONCILIATION OF SEGMENT INCOME TO CONSOLIDATED (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Segment Reporting Information [Line Items]
Utility	$ 1,011,284	$ 1,127,417	$ 731,459
Nonutility	951,710	1,778,562	1,425,154
Operating revenues	1,962,994	2,905,979	2,156,613
Depreciation and amortization	152,941	129,249	111,387
Interest income	8,919	2,716	2,167
Interest expense, net of capitalized interest	123,014	85,830	78,559
Income tax provision (benefit)	49,275	76,195	33,286
Equity in earnings of affiliates	3,930	8,177	(83,212)
Net financial earnings	261,827	240,321	207,712
Capital expenditures	540,919	598,428	624,610
Return of capital from equity investees	0	(5,479)
Investments in equity investees			690
ES
Segment Reporting Information [Line Items]
Operating revenues	48,500	53,000
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1,905,561	2,850,161	2,105,169
Depreciation and amortization	152,052	128,425	110,683
Interest income	9,789	3,021	2,580
Interest expense, net of capitalized interest	122,367	85,184	74,505
Income tax provision (benefit)	53,169	75,157	32,430
Equity in earnings of affiliates	3,126	9,865	(81,072)
Net financial earnings	257,224	241,102	208,327
Capital expenditures	538,613	597,038	621,980
Return of capital from equity investees		(5,479)
Investments in equity investees			690
Operating Segments | NJNG
Segment Reporting Information [Line Items]
Utility	1,011,284	1,127,417	731,796
Operating revenues	1,011,284	1,127,417	731,796
Depreciation and amortization	102,326	94,579	80,045
Interest income	1,713	895	85
Interest expense, net of capitalized interest	56,595	46,394	36,405
Income tax provision (benefit)	33,065	40,141	19,054
Equity in earnings of affiliates	0	0	0
Net financial earnings	131,414	140,124	107,375
Capital expenditures	390,394	298,374	426,628
Return of capital from equity investees		0
Investments in equity investees			0
Operating Segments | CEV
Segment Reporting Information [Line Items]
Nonutility	124,131	128,280	95,275
Operating revenues	124,131	128,280	95,275
Depreciation and amortization	25,320	21,396	20,567
Interest income	0	0	241
Interest expense, net of capitalized interest	28,569	21,968	22,548
Income tax provision (benefit)	(7,683)	11,361	5,048
Equity in earnings of affiliates	0	0	0
Net financial earnings	44,458	39,403	16,789
Capital expenditures	107,303	146,676	87,852
Return of capital from equity investees		0
Investments in equity investees			0
Operating Segments | ES
Segment Reporting Information [Line Items]
Nonutility	681,446	1,529,178	1,228,846
Operating revenues	681,446	1,529,178	1,228,846
Depreciation and amortization	221	148	111
Interest income	1,119	16	11
Interest expense, net of capitalized interest	11,400	4,725	2,204
Income tax provision (benefit)	24,343	21,776	18,371
Equity in earnings of affiliates	0	0	0
Net financial earnings	68,517	39,121	71,117
Capital expenditures	0	0	0
Return of capital from equity investees		0
Investments in equity investees			0
Operating Segments | ES | CANADA
Segment Reporting Information [Line Items]
Nonutility	8,400	2,400	100
Operating Segments | S&T
Segment Reporting Information [Line Items]
Nonutility	88,700	65,286	49,252
Operating revenues	88,700	65,286	49,252
Depreciation and amortization	24,185	12,302	9,960
Interest income	6,957	2,110	2,243
Interest expense, net of capitalized interest	25,803	12,097	13,348
Income tax provision (benefit)	3,444	1,879	(10,043)
Equity in earnings of affiliates	3,126	9,865	(81,072)
Net financial earnings	12,835	22,454	13,046
Capital expenditures	40,916	151,988	107,500
Return of capital from equity investees		(5,479)
Investments in equity investees			690
Intersegment Eliminations
Segment Reporting Information [Line Items]
Nonutility	(205)	(364)	(785)
Operating revenues	(15,678)	(3,893)	(1,342)
Intersegment Eliminations | NJNG
Segment Reporting Information [Line Items]
Utility	(1,349)	(1,350)	0
Intersegment Eliminations | CEV
Segment Reporting Information [Line Items]
Nonutility	0	0	0
Intersegment Eliminations | ES
Segment Reporting Information [Line Items]
Nonutility	(10,170)	(94)	426
Intersegment Eliminations | S&T
Segment Reporting Information [Line Items]
Nonutility	(4,159)	(2,449)	(1,768)
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Nonutility	57,433	55,818	51,444
Operating revenues	57,433	55,818	51,444
Depreciation and amortization	889	824	980
Interest income	2,977	944	522
Interest expense, net of capitalized interest	647	646	4,054
Income tax provision (benefit)	(1,477)	1,059	(196)
Equity in earnings of affiliates	0	0	0
Net financial earnings	4,758	(781)	(826)
Capital expenditures	2,306	1,390	2,630
Return of capital from equity investees		0
Investments in equity investees			0
Consolidation, Eliminations
Segment Reporting Information [Line Items]
Nonutility	(15,883)	(4,257)	(2,127)
Depreciation and amortization	0	0	(276)
Interest income	(3,847)	(1,249)	(935)
Interest expense, net of capitalized interest	0	0	0
Income tax provision (benefit)	(2,417)	(21)	1,052
Equity in earnings of affiliates	804	(1,688)	(2,140)
Net financial earnings	(155)	0	211
Capital expenditures	$ 0	0	0
Return of capital from equity investees		$ 0
Investments in equity investees			$ 0

REPORTING SEGMENT AND OTHER O_4

REPORTING SEGMENT AND OTHER OPERATIONS DATA - RECONCILIATION OF SEGMENT ASSETS TO CONSOLIDATED (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 6,537,496	$ 6,261,416	$ 5,722,278
Operating Segments
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	6,679,140	6,378,335	5,850,079
Operating Segments | NJNG
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	4,414,829	4,030,686	3,707,461
Operating Segments | CEV
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	1,128,577	1,015,065	914,788
Operating Segments | ES
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	123,775	333,064	365,423
Operating Segments | S&T
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	1,011,959	999,520	862,407
Corporate, Non-Segment
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	171,275	159,068	162,134
Consolidation, Eliminations
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ (312,919)	$ (275,987)	$ (289,935)

REPORTING SEGMENT AND OTHER O_5

REPORTING SEGMENT AND OTHER OPERATIONS DATA - NET FINANCIAL EARNINGS LOSS RECONCILIATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Segment Reporting [Abstract]
Net financial earnings	$ 261,827	$ 240,321	$ 207,712
Less:
Unrealized (gain) loss on derivative instruments and related transactions	(38,081)	(59,906)	54,203
Tax effect	9,050	14,248	(12,887)
Effects of economic hedging related to natural gas inventory	34,699	19,939	(42,405)
Tax effect	(8,246)	(4,738)	10,078
(Gain on) impairment of equity method investment	(300)	(5,521)	92,000
Tax effect	(19)	1,377	(11,167)
NET INCOME	$ 264,724	$ 274,922	$ 117,890

RELATED PARTY TRANSACTIONS - AD

RELATED PARTY TRANSACTIONS - ADDITIONAL INFORMATION (Details) $ in Millions		1 Months Ended		12 Months Ended
	Apr. 01, 2020 USD ($) Bcf	Jun. 30, 2022	Mar. 31, 2021	Sep. 30, 2023 dth / d dekatherm lease Bcf	Jul. 31, 2021
Related Party Transaction [Line Items]
Number of asset management agreements | lease				1
NJNG to ES Affiliate
Related Party Transaction [Line Items]
Asset management agreement, period	5 years
NJNG to Steckman RIdge Affiliate
Related Party Transaction [Line Items]
Natural gas sold at cost under asset management agreement (in Bcf)	3
Approximate annual demand fees under agreement | $	$ 9.3
NJNG to Adelphia Affiliate
Related Party Transaction [Line Items]
Transportation capacity under precedent agreement with PennEast (in bcf per day) | dekatherm				130,000
NJNG to Adelphia Affiliate | Transportation Precedent Agreement One
Related Party Transaction [Line Items]
Transportation precedent agreement term				5 years
NJNG to Adelphia Affiliate | Transportation Precedent Agreement Two
Related Party Transaction [Line Items]
Transportation precedent agreement term				15 years
Transportation capacity under precedent agreement with PennEast (in bcf per day) | dth / d				130,000
Leaf River Energy Center LLC
Related Party Transaction [Line Items]
Natural gas sold at cost under asset management agreement (in Bcf)				3
Storage capacity agreement term				5 years
NJNG and CEV to PPA
Related Party Transaction [Line Items]
Sublease agreement term		20 years	15 years
NJNG to NJR Subsidiaries
Related Party Transaction [Line Items]
Term of contract					16 years

RELATED PARTY TRANSACTIONS - DE

RELATED PARTY TRANSACTIONS - DEMAND FEES (Details) - Related Party - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Related Party Transaction [Line Items]
Demand fees expense recognized pertaining to related party agreement	$ 7,206	$ 7,395	$ 7,013
Demand fees payable	859	851
NJNG to Steckman RIdge Affiliate
Related Party Transaction [Line Items]
Demand fees expense recognized pertaining to related party agreement	6,549	6,663	6,449
Demand fees payable	775	775
ES to Steckman Ridge Affiliate
Related Party Transaction [Line Items]
Demand fees expense recognized pertaining to related party agreement	657	732	$ 564
Demand fees payable	$ 84	$ 76

VALUATION AND QUALIFYING ACCO_2

VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Valuation allowance for deferred tax assets
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
BEGINNING BALANCE	$ 22,241	$ 23,613	$ 17,639
ADDITIONS CHARGED TO EXPENSE	(16,494)	(1,372)	6,355
OTHER	0	0	(381)
ENDING BALANCE	5,747	22,241	23,613
Allowance for doubtful accounts
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
BEGINNING BALANCE	19,379	24,652	7,242
ADDITIONS CHARGED TO EXPENSE	1,570	2,401	18,986
OTHER	(9,913)	(7,674)	(1,576)
ENDING BALANCE	$ 11,036	$ 19,379	$ 24,652