10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended September 30, 2018

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to             

Commission file number 001‑08359
NEW JERSEY RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
New Jersey	22‑2376465
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)
1415 Wyckoff Road, Wall, New Jersey 07719	732‑938‑1000
(Address of principal executive offices)	(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12 (b) of the Act:
Common Stock ‑ $2.50 Par Value	New York Stock Exchange
(Title of each class)	(Name of each exchange on which registered)
Securities registered pursuant to Section 12 (g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

x Yes        o No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

o Yes        x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    x Yes        o No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    

x Yes        o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K(§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b‑2 of the Exchange Act.

Large accelerated filer: x	Accelerated filer: o
Non-accelerated filer: o	Smaller reporting company: o
	Emerging growth company: o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     o Yes        x No

The aggregate market value of the registrant’s common stock held by non-affiliates was $3,451,945,383 based on the closing price of $40.10 per share on March 31, 2018, as reported on the New York Stock Exchange.

The number of shares outstanding of $2.50 par value common stock as of November 16, 2018 was 88,505,199.

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 23, 2019, are incorporated by reference into Part I and Part III of this report.

New Jersey Resources Corporation

TABLE OF CONTENTS

			Page
Glossary of Terms			1
Information Concerning Forward-Looking Statements			3
PART I
	ITEM 1.	Business	4
		Organizational Structure	4
		Reporting Segments	5
		Natural Gas Distribution	7
		Clean Energy Ventures	10
		Energy Services	11
		Midstream	12
		Other Business Operations	13
		Home Services and Other	13
		Environment	13
		Employee Relations	13
	ITEM 1A.	Risk Factors	14
	ITEM 1B.	Unresolved Staff Comments	23
	ITEM 2.	Properties	23
	ITEM 3.	Legal Proceedings	24
	ITEM 4.	Mine Safety Disclosures	25
	ITEM 4A.	Executive Officers of the Company	25
PART II
	ITEM 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
	ITEM 6.	Selected Financial Data	27
	ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
	ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	65
	ITEM 8.	Financial Statements and Supplementary Data	69
		Management’s Report on Internal Control over Financial Reporting	69
		Report of Independent Registered Public Accounting Firm	70
		Consolidated Financial Statements	72
		Notes to Consolidated Financial Statements	77
		Note 1. Nature of the Business	77
		Note 2. Summary of Significant Accounting Policies	77
		Note 3. Regulation	93
		Note 4. Derivative Instruments	95
		Note 5. Fair Value	101
		Note 6. Investments in Equity Investees	104
		Note 7. Earnings Per Share	104
		Note 8. Debt	104
		Note 9. Stock-Based Compensation	109
		Note 10. Employee Benefit Plans	112
		Note 11. Asset Retirement Obligations	117
		Note 12. Income Taxes	118
		Note 13. Commitments and Contingent Liabilities	121
		Note 14. Reporting Segment and Other Operations Data	123
		Note 15. Related Party Transactions	126
		Note 16. Acquisition	126
		Note 17. Dispositions	126
		Note 18. Selected Quarterly Financial Data (Unaudited)	127
	ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	127
	ITEM 9A.	Controls and Procedures	127
	ITEM 9B.	Other Information	127
PART III*
	ITEM 10.	Directors, Executive Officers and Corporate Governance	128
	ITEM 11.	Executive Compensation	128
	ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	128
	ITEM 13.	Certain Relationships and Related Transactions and Director Independence	128
	ITEM 14.	Principal Accountant Fees and Services	128
PART IV
	ITEM 15.	Exhibits and Financial Statement Schedules	129
		Index to Financial Statement Schedules	130
		Exhibit Index	132
		Signatures	136
* Portions of Item 10 and Items 11-14 are Incorporated by Reference from the Proxy Statement.

i

New Jersey Resources Corporation

GLOSSARY OF KEY TERMS                                                                                                                                                        

Adelphia	Adelphia Gateway, LLC
AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligations
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Bcf	Billion Cubic Feet
BGSS	Basic Gas Supply Service
BPU	New Jersey Board of Public Utilities
CIP	Conservation Incentive Program
CME	Chicago Mercantile Exchange
CR&R	Commercial Realty & Resources Corp.
Degree-day	The measure of the variation in the weather based on the extent to which the average daily temperature falls below 65 degrees Fahrenheit
DM	Dominion Energy Midstream Partners, L.P., a master limited partnership
DM Common Units	Common units representing limited partnership interests in DM
DRP	NJR Direct Stock Purchase and Dividend Reinvestment Plan
Dths	Dekatherms
EDA	New Jersey Economic Development Authority
EDA Bonds	Collectively, Series 2011A, Series 2011B and Series 2011C Bonds issued to NJNG by the EDA
EDECA	Electric Discount and Energy Competition Act
EE	Energy Efficiency
FASB	Financial Accounting Standards Board
FCM	Futures Commission Merchant
FERC	Federal Energy Regulatory Commission
Financial Margin	A non-GAAP financial measure, which represents revenues earned from the sale of natural gas less costs of natural gas sold including any transportation and storage costs, and excludes any accounting impact from the change in the fair value of certain derivative instruments
FMB	First Mortgage Bonds
GAAP	Generally Accepted Accounting Principles of the United States
HCCTR	Health Care Cost Trend Rate
Home Services and Other	Home Services and Other Operations (formerly Retail and Other Operations)
ICE	Intercontinental Exchange
IEC	Interstate Energy Company, LLC
Iroquois	Iroquois Gas Transmission L.P.
IRS	Internal Revenue Service
ISDA	The International Swaps and Derivatives Association
ITC	Investment Tax Credit
LIBOR	London Inter-Bank Offered Rate
LNG	Liquefied Natural Gas
Loan Agreement	Loan Agreement between the EDA and NJNG
MGP	Manufactured Gas Plant
MLP	Master Limited Partnership
MMBtu	Million British Thermal Units
Moody’s	Moody’s Investors Service, Inc.
Mortgage Indenture	The Amended and Restated Indenture of Mortgage, Deed of Trust and Security Agreement between NJNG and U.S. Bank National Association dated as of September 1, 2014
MW	Megawatts
MWh	Megawatt Hour
NAESB	The North American Energy Standards Board
NFE	Net Financial Earnings
NJ RISE	New Jersey Reinvestment in System Enhancement
NJCEP	New Jersey’s Clean Energy Program
NJDEP	New Jersey Department of Environmental Protection
NJNG	New Jersey Natural Gas Company or Natural Gas Distribution segment
NJNG Credit Facility	The $250 million unsecured committed credit facility expiring in May 2019
NJR Credit Facility	The $425 million unsecured committed credit facility expiring in September 2020
NJR or The Company	New Jersey Resources Corporation

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New Jersey Resources Corporation

GLOSSARY OF KEY TERMS (cont.)
NJRCEV	NJR Clean Energy Ventures Corporation
NJRES	NJR Energy Services Company
NJRHS	NJR Home Services Company
NJRRS	NJR Retail Services Company
Non-GAAP	Not in accordance with Generally Accepted Accounting Principles of the United States
NPNS	Normal Purchase/Normal Sale
NYMEX	New York Mercantile Exchange
O&M	Operation and Maintenance
OPEB	Other Postemployment Benefit Plans
PBO	Projected Benefit Obligation
PennEast	PennEast Pipeline Company, LLC
PEP	Pension Equalization Plan
PIM	Pipeline Integrity Management
PPA	Power Purchase Agreement
Prudential Facility	NJR’s unsecured, uncommitted private placement shelf note agreement with Prudential Investment Management, Inc.
PTC	Production Tax Credit
RAC	Remediation Adjustment Clause
REC	Renewable Energy Certificate
S&P	Standard & Poor’s Financial Services, LLC
SAFE I	Safety Acceleration and Facility Enhancement Program, Phase I
SAFE II	Safety Acceleration and Facility Enhancement Program, Phase II
Sarbanes-Oxley	Sarbanes-Oxley Act of 2002
SAVEGREEN	The SAVEGREEN Project®
Savings Plan	Employees’ Retirement Savings Plan
SBC	Societal Benefits Charge
SEC	Securities and Exchange Commission
SREC	Solar Renewable Energy Certificate
SRL	Southern Reliability Link
Steckman Ridge	Collectively, Steckman Ridge GP, LLC and Steckman Ridge, LP
Superstorm Sandy	Post-Tropical Cyclone Sandy
Talen	Talen Energy Marketing, LLC or Talen Generation, LLC
Tetco	Texas Eastern Transmission
The Exchange Act	The Securities Exchange Act of 1934, as amended
The Tax Act	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
Trustee	U.S. Bank National Association
TSR	Total Shareholder Return
U.S.	The United States of America
Union	International Brotherhood of Electrical Workers Local 1820
USF	Universal Service Fund

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New Jersey Resources Corporation

TABLE OF CONTENTS

INFORMATION CONCERNING FORWARD-LOOKING STATEMENTS                                                                           

Certain statements contained in this report, including, without limitation, statements as to management expectations, assumptions and beliefs presented in Part I, Item 1. Business and Item 3. Legal Proceedings, and in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and in the notes to the financial statements are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. Forward-looking statements can also be identified by the use of forward-looking terminology such as “anticipate,” “estimate,” “may,” “could,” “might,” “intend,” “expect,” “believe,” “will” “plan” or “should” or comparable terminology and are made based upon management’s current expectations, assumptions and beliefs as of this date concerning future developments and their potential effect on us. There can be no assurance that future developments will be in accordance with management’s expectations, assumptions or beliefs, or that the effect of future developments on us will be those anticipated by management.

We caution readers that the expectations, assumptions and beliefs that form the basis for forward-looking statements regarding customer growth, customer usage, qualifications for ITCs and SRECs, future rate case proceedings, financial condition, results of operations, cash flows, capital requirements, future capital expenditures, market risk, effective tax rate and other matters for fiscal 2019 and thereafter include many factors that are beyond our ability to control or estimate precisely, such as estimates of future market conditions, the behavior of other market participants and changes in the debt and equity capital markets. The factors that could cause actual results to differ materially from our expectations, assumptions and beliefs include, but are not limited to, those discussed in Part I, Item 1A. Risk Factors, as well as the following:

• risks associated with our investments in clean energy projects, including the availability of regulatory incentives and federal tax credits, the availability of viable projects, our eligibility for ITCs, the future market for SRECs and electricity prices, and operational risks related to projects in service;

• our ability to obtain governmental and regulatory approvals, land-use rights, electric grid connection (in the case of clean energy projects) and/or financing for the construction, development and operation of our unregulated energy investments, pipeline transportation systems and NJNG and Midstream infrastructure projects, including NJ RISE, SRL, PennEast and Adelphia, in a timely manner;

• risks associated with acquisitions and the related integration of acquired assets with our current operations, including our planned Adelphia acquisition;

• volatility of natural gas and other commodity prices and their impact on NJNG customer usage, NJNG’s BGSS incentive programs, our Energy Services segment operations and our risk management efforts;

• our ability to comply with current and future regulatory requirements;

• the level and rate at which NJNG’s costs and expenses are incurred and the extent to which they are approved for recovery from customers through the regulatory process, including through future base rate case filings;

• the impact of a disallowance of recovery of environmental-related expenditures and other regulatory changes;

• the performance of our subsidiaries;

• operating risks incidental to handling, storing, transporting and providing customers with natural gas;

• access to adequate supplies of natural gas and dependence on third-party storage and transportation facilities for natural gas supply;

• the regulatory and pricing policies of federal and state regulatory agencies;

• timing of qualifying for ITCs due to delays or failures to complete planned solar projects and the resulting effect on our effective tax rate and earnings;

• the results of legal or administrative proceedings with respect to claims, rates, environmental issues, gas cost prudence reviews and other matters;

• changes in rating agency requirements and/or credit ratings and their effect on availability and cost of capital to our Company;

• risks related to cyberattacks or failure of information technology systems;

• the impact of volatility in the equity and credit markets on our access to capital;

• the impact to the asset values and resulting higher costs and funding obligations of our pension and postemployment benefit plans as a result of potential downturns in the financial markets, lower discount rates, revised actuarial assumptions or impacts associated with the Patient Protection;

• commercial and wholesale credit risks, including the availability of creditworthy customers and counterparties, and liquidity in the wholesale energy trading market;

• accounting effects and other risks associated with hedging activities and use of derivatives contracts;

• our ability to optimize our physical assets;

• weather and economic conditions;

• changes to tax laws and regulations;

• any potential need to record a valuation allowance for our deferred tax assets;

• our ability to comply with debt covenants;

• demographic changes in ourservice territory and their effect on our customer growth;

• the impact of natural disasters, terrorist activities and other extreme events on our operations and customers;

• the costs of compliance with present and future environmental laws, including potential climate change-related legislation;

• environmental-related and other uncertainties related to litigation or administrative proceedings;

• risks related to our employee workforce; and

• risks associated with the management of our joint ventures and partnerships, and investment in a master limited partnership.

While we periodically reassess material trends and uncertainties affecting our results of operations and financial condition in connection with the preparation of management’s discussion and analysis of results of operations and financial condition contained in our Quarterly and Annual Reports on Form 10-Q and Form 10-K, respectively, we do not, by including this statement, assume any obligation to review or revise any particular forward-looking statement referenced herein in light of future events.

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New Jersey Resources Corporation

Part I

ITEM 1. BUSINESS                                                                                                                                                                         

ORGANIZATIONAL STRUCTURE

New Jersey Resources Corporation is a New Jersey corporation formed in 1981 pursuant to a corporate reorganization. We are an energy services holding company whose principal business is the distribution of natural gas through a regulated utility, providing other retail and wholesale energy services to customers and investing in clean energy projects and midstream assets. We are an exempt holding company under section 1263 of the Energy Policy Act of 2005.

Our primary subsidiaries include:

New Jersey Natural Gas Company provides regulated retail natural gas service to approximately 538,700 residential and commercial customers in central and northern New Jersey and participates in the off-system sales and capacity release markets. NJNG, a local natural gas distribution company, is regulated by the BPU and comprises the Company’s Natural Gas Distribution segment and is referred to herein as NJNG or Natural Gas Distribution.

NJR Clean Energy Ventures Corporation includes the results of operations and assets related to the Company’s unregulated capital investments in clean energy projects, including commercial and residential solar projects and onshore wind investments. NJRCEV comprises the Company’s Clean Energy Ventures segment and is referred to herein as Clean Energy Ventures.

NJR Energy Services Company maintains and transacts around a portfolio of physical assets consisting of natural gas storage and transportation contracts in the U.S. and Canada. NJRES also provides unregulated wholesale energy management services to other energy companies and natural gas producers. NJRES comprises our Energy Services segment and is referred to herein as Energy Services. NJR Retail Services Company provided unregulated retail natural gas supply and transportation services to commercial and industrial customers in Delaware, Maryland, Pennsylvania and New Jersey from July 2017 through February 2018. NJRRS was sold to an unrelated third party on February 28, 2018, and was included as part of our Energy Services segment for fiscal 2018 and 2017.

NJR Midstream Holdings Corporation,which comprises the Midstream segment, invests in energy-related ventures through its subsidiaries. Investments include NJR Steckman Ridge Storage Company, which holds our 50 percent combined ownership interest in Steckman Ridge, located in Pennsylvania; NJNR Pipeline, which holds our DM Common Units; and NJR Pipeline Company, which includes Adelphia Gateway, LLC and our 20 percent ownership interest in PennEast. See Note 6. Investments in Equity Investeesfor more information.

NJR Home Services Company provides heating, ventilation and cooling service, sales and installation of appliances to approximately 110,000 service contract customers, as well as solar installation projects, and is the primary contributor to Home Services and Other operations.

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New Jersey Resources Corporation

Part I

ITEM 1. BUSINESS (Continued)

REPORTING SEGMENTS

We operate within four reporting segments: Natural Gas Distribution, Clean Energy Ventures, Energy Services and Midstream.

The Natural Gas Distribution segment consists of regulated natural gas services, off-system sales, capacity and storage management operations. The Energy Services segment consists of unregulated wholesale and retail energy operations. The Clean Energy Ventures segment consists of capital investments in clean energy projects. The Midstream segment consists of investments in the midstream natural gas market, such as natural gas transportation and storage facilities.

Net income by reporting segment and other business operations for the years ended September 30, are as follows:

* Energy Services’ net income for fiscal 2017 was $476,000 and does not show clearly in the above graph.

Assets composition by reporting segment and other business operations at September 30, are as follows:

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New Jersey Resources Corporation

Part I

ITEM 1. BUSINESS (Continued)

Management uses NFE, a non-GAAP financial measure, when evaluating our operating results. NFE is a measure of the earnings based on eliminating timing differences surrounding the recognition of certain gains or losses to effectively match the earnings effects of the economic hedges with the physical sale of gas and, therefore, eliminates the impact of volatility to GAAP earnings associated with the derivative instruments. Energy Services economically hedges its natural gas inventory with financial derivative instruments and calculates the related tax effect based on the statutory rate.

Non-GAAP financial measures are not in accordance with, or an alternative to GAAP, and should be considered in addition to, and not as a substitute for, the comparable GAAP measure. The following is a reconciliation of consolidated net income, the most directly comparable GAAP measure, to NFE:

(Thousands)	2018			2017			2016
Net income	$	233,436		$	132,065		$	131,672
Add:
Unrealized loss (gain) on derivative instruments and related transactions	26,770			(11,241		)	46,883
Tax effect	(4,512		)	4,062			(17,018		)
Effects of economic hedging related to natural gas inventory	(22,570		)	38,470			(36,816		)
Tax effect	7,362			(13,964		)	13,364
NFE (1)	$	240,486		$	149,392		$	138,085
Basic earnings per share	$	2.66		$	1.53		$	1.53
Add:
Unrealized loss (gain) on derivative instruments and related transactions	0.31			(0.13		)	0.55
Tax effect	(0.05		)	0.05			(0.20		)
Effects of economic hedging related to natural gas inventory	(0.26		)	0.45			(0.43		)
Tax effect	0.08			(0.17		)	0.16
Basic NFE per share	$	2.74		$	1.73		$	1.61

NFE during fiscal 2018 was $59.6 million, or $0.68 per share, higher due to the revaluation of deferred taxes resulting from the reduction in the federal corporate tax rate related to the Tax Act.

NFE by reporting segment and other business operations for the years ended September 30, are as follows:

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New Jersey Resources Corporation

Part I

ITEM 1. BUSINESS (Continued)

Natural Gas Distribution

General

Our Natural Gas Distribution segment consists of regulated utility operations that provide natural gas service to approximately 538,700 customers. NJNG’s service territory includes New Jersey’s Monmouth and Ocean counties and parts of Burlington, Morris and Middlesex counties. It encompasses 1,516 square miles, covering 105 municipalities with an estimated population of 1.5 million people. It is primarily suburban, highlighted by approximately 100 miles of New Jersey coastline. It is in close proximity to New York City, Philadelphia and the metropolitan areas of northern New Jersey and is accessible through a network of major roadways and mass transportation.

NJNG’s business is subject to various risks, such as those associated with adverse economic conditions, which can negatively impact customer growth, operating and financing costs, fluctuations in commodity prices, which can impact customer usage, customer conservation efforts, certain regulatory actions and environmental remediation. It is often difficult to predict the impact of trends associated with these risks. NJNG employs strategies to manage the challenges it faces, including pursuing customer conversions from other fuel sources and monitoring new construction markets through contact with developers, utilizing incentive programs through BPU-approved mechanisms to reduce gas costs, pursuing rate and other regulatory strategies designed to stabilize and decouple gross margin, and working actively with consultants and the NJDEP to manage expectations related to its obligations associated with its former MGP sites.

Operating Revenues/Throughput

For the fiscal years ended September 30, operating revenues and throughput by customer class are as follows:

	2018			2017			2016
($ in thousands)	Operating Revenue		Bcf	Operating Revenue		Bcf	Operating Revenue		Bcf
Residential	$	441,486	45.5	$	395,315	40.7	$	345,597	36.9
Commercial and other	95,351		8.9	98,777		8.7	80,994		7.3
Firm transportation	65,256		15.5	73,206		14.4	69,696		14.1
Total residential and commercial	602,093		69.9	567,298		63.8	496,287		58.3
Interruptible	7,522		46.2	7,970		55.0	8,867		61.5
Total system	609,615		116.1	575,268		118.8	505,154		119.8
BGSS incentive programs (1)	122,250		42.8	120,369		49.5	89,192		56.6
Total	$	731,865	158.9	$	695,637	168.3	$	594,346	176.4

(1) Does not include 107.4, 128.9 and 160.1 Bcf for the capacity release program and related amounts of $5.7 million, $6.5 million and $8.1 million, which are recorded as a reduction of gas purchases on the Consolidated Statements of Operations for the fiscal years ended September 30, 2018, 2017 and 2016, respectively.

NJNG added 9,596 and 9,126 new customers and added natural gas heat and other services to another 613 and 662 existing customers in fiscal 2018 and 2017, respectively. NJNG expects its new customer annual growth rate to continue to be approximately 1.8 percent with projected additions in the range of approximately 28,000 to 30,000 new customers over the next three years. This anticipated customer growth represents approximately $5.5 million in new annual utility gross margin, a non-GAAP financial measure, as calculated under NJNG’s current CIP tariff. For a definition of utility gross margin see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Natural Gas Distribution Segment.

In fiscal 2018, no single customer represented more than 10 percent of consolidated operating revenues.

Seasonality of Gas Revenues

Therm sales are significantly affected by weather conditions, with customer demand being greatest during the winter months when natural gas is used for heating purposes. The relative measurement of the impact of weather is in degree-days. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65 degrees Fahrenheit. Each degree of temperature below 65 degrees Fahrenheit is counted as one heating degree-day. Normal heating degree-days are based on a 20-year average, calculated based on three reference areas representative of NJNG’s service territory.

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New Jersey Resources Corporation

Part I

ITEM 1. BUSINESS (Continued)

The CIP, a mechanism authorized by the BPU, stabilizes NJNG’s utility gross margin, regardless of variations in weather. In addition, the CIP decouples the link between utility gross margin and customer usage, allowing NJNG to promote energy conservation measures. Recovery of utility gross margin is subject to additional conditions, including an earnings test, a revenue test and an evaluation of BGSS-related savings achieved over a 12-month period. In May 2014, the BPU approved the continuation of the CIP program.

Concurrent with its annual BGSS filing, NJNG files for an annual review of its CIP, during which time it can request rate changes, as appropriate. For additional information regarding the CIP, including rate actions and impact to margin, see Note 3. Regulation in the accompanying Consolidated Financial Statements and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Natural Gas Distribution Segment.

Gas Supply

Firm Natural Gas Supplies

In fiscal 2018, NJNG purchased natural gas from approximately 79 suppliers under contracts ranging from one day to one year and purchased over 10 percent of its natural gas from one supplier. NJNG believes the loss of this supplier would not have a material adverse impact on its results of operations, financial position or cash flows, as an adequate number of alternative suppliers exist. NJNG believes that its supply strategy should adequately meet its expected firm load for the upcoming winter season.

Firm Transportation and Storage Capacity

NJNG maintains agreements for firm transportation and storage capacity with several interstate pipeline companies to take delivery of firm natural gas supplies, which ensures the ability to reliably service its customers. NJNG receives natural gas at 10 citygate stations located in Middlesex, Morris and Passaic counties in New Jersey.

The pipeline companies that provide firm transportation service to NJNG’s citygate stations, the maximum daily deliverability of that capacity and the contract expiration dates are as follows:

Pipeline	Dths(1)	Expiration
Texas Eastern Transmission, L.P.	300,738	Various dates between 2019 and 2023
Transcontinental Gas Pipe Line Corp.	202,531	Various dates between 2019 and 2032
Columbia Gas Transmission Corp.	50,000	Various dates between 2024 and 2030
Tennessee Gas Pipeline Co.	25,166	Various dates between 2023 and 2024
Algonquin Gas Transmission	12,000	2020
Total	590,435

(1) Numbers are shown net of any capacity release contracted amounts.

Dominion Energy Transmission, Inc. provides NJNG firm contract transportation service and supplies the pipelines included in the table above.

In addition, NJNG has storage contracts that provide an additional 102,941 Dths of maximum daily deliverability to NJNG’s citygate stations from storage fields in its Northeast market area. The storage suppliers, the maximum daily deliverability of that storage capacity and the contract expiration dates are as follows:

Pipeline	Dths	Expiration
Texas Eastern Transmission, L.P.	94,557	2020
Transcontinental Gas Pipe Line Corp.	8,384	2028
Total	102,941

NJNG also has upstream storage contracts. The maximum daily deliverability and contract expiration dates are as follows:

Company	Dths	Expiration
Dominion Transmission Corporation	208,214	Various dates between 2021 and 2024
Steckman Ridge, L.P.	38,000	2020
Stagecoach Pipeline & Storage Company LLC	25,337	2023
Total	271,551

NJNG utilizes its transportation contracts to transport gas to NJNG’s citygates from the Dominion Transmission Corporation, Steckman Ridge and Stagecoach Pipeline & Storage Company LLC storage fields. NJNG has sufficient firm transportation, storage and supply capacity to fully meet its firm sales contract obligations.

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New Jersey Resources Corporation

Part I

ITEM 1. BUSINESS (Continued)

Citygate Supplies from Energy Services

NJNG has several citygate supply agreements with Energy Services. NJNG and Energy Services have an agreement where NJNG releases 10,000 Dths/day of Tetco capacity, 2,200 Dths/day of Dominion Energy Transmission, Inc. capacity, 10,728 Dths/day of Tennessee Gas Pipeline capacity and 1.6 million Dths of Stagecoach Pipeline & Storage Company LLC storage capacity to Energy Services for the period of April 1, 2018 to March 31, 2019. NJNG can call upon a supply of up to 20,000 Dths/day delivered to NJNG’s Texas Eastern citygate. Energy Services manages the storage inventory and NJNG can call on that storage supply as needed at NJNG’s Tennessee citygate or storage point.

NJNG also has agreements where it releases 160,000 Dths/day of its Tetco capacity to Energy Services for the period of April 1, 2016 to October 31, 2021. Under these agreements, NJNG can call upon a supply of up to 160,000 Dths/day delivered to its Texas Eastern citygate as needed. See Note 15. Related Party Transactions in the accompanying Consolidated Financial Statements for additional information regarding these transactions.

Peaking Supply

To manage its winter peak day demand, NJNG maintains two LNG facilities with a combined deliverability of approximately 170,000 Dths/day, which represents approximately 18 percent of its estimated peak day sendout. NJNG’s liquefaction facility allows NJNG to convert natural gas into LNG to fill NJNG’s existing LNG storage tanks. See Item 2. Properties-Natural Gas Distribution for additional information regarding the LNG storage facilities.

Basic Gas Supply Service

BGSS is a BPU-approved clause designed to allow for the recovery of natural gas commodity costs on an annual basis. The clause requires all New Jersey natural gas utilities to make an annual filing by each June 1 for review of BGSS rates and to request a potential rate change effective the following October 1. The BGSS also allows each natural gas utility to provisionally increase residential and small commercial customer BGSS rates on December 1 and February 1 for up to a five percent increase to the average residential heat customer’s bill on a self-implementing basis with proper notice. Such increases are subject to subsequent BPU review and final approval.

In addition to making periodic rate adjustments to reflect changes in commodity prices, NJNG is also permitted to refund or credit back a portion of the commodity costs to customers when the natural gas commodity costs decrease in comparison to amounts projected or to amounts previously collected from customers. Decreases in the BGSS rate and BGSS refunds can be implemented with five days’ notice to the BPU. Rate changes, as well as other regulatory actions related to BGSS, are discussed further in Note 3. Regulation in the accompanying Consolidated Financial Statements.

Wholesale natural gas prices are, by their nature, volatile. NJNG mitigates the impact of volatile price changes on customers through the use of financial derivative instruments, which are part of its storage incentive program and its BGSS clause.

Future Natural Gas Supplies

NJNG expects to meet the natural gas requirements for existing and projected firm customers. If NJNG’s long-term natural gas requirements change, NJNG expects to renegotiate and restructure its contract portfolio to better match the changing needs of its customers and changing natural gas supply landscape.

Regulation and Rates

State

NJNG is subject to the jurisdiction of the BPU with respect to a wide range of matters such as base rates and regulatory rider rates, the issuance of securities, the safety and adequacy of service, the manner of keeping its accounts and records, the sufficiency of natural gas supply, pipeline safety, environmental issues, compliance with affiliate standards and the sale or encumbrance of its properties. In September 2016, the BPU approved NJNG’s filing for an increase to base rates in the amount of $45 million, effective October 2016. See Note 3. Regulation in the accompanying Consolidated Financial Statements for additional information regarding NJNG’s rate proceedings.

Federal

FERC regulates rates charged by interstate pipeline companies for the transportation and storage of natural gas. This affects NJNG’s agreements with several interstate pipeline companies for the purchase of such services. Costs associated with these services are currently recoverable through the BGSS.

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Competition

Although its franchises are nonexclusive, NJNG is not currently subject to competition from other natural gas distribution utilities with regard to the transportation of natural gas in its service territory. Due to significant distances between NJNG’s current large industrial customers and the nearest interstate natural gas pipelines, as well as the availability of its transportation tariff, NJNG currently does not believe it has significant exposure to the risk that its distribution system will be bypassed. Competition does exist from suppliers of oil, coal, electricity and propane. At the present time, however, natural gas is used in over 95 percent of new construction due to its efficiency, reliability and price advantage. Natural gas prices are a function of market supply and demand. Although NJNG believes natural gas will remain competitive with alternate fuels, no assurance can be given in this regard.

The BPU, within the framework of the EDECA, fully opened NJNG’s residential markets to competition, including third-party suppliers, and restructured rates to segregate its BGSS and delivery (i.e., transportation) prices. New Jersey’s natural gas utilities must provide BGSS in the absence of a third-party supplier. On September 30, 2018, NJNG had 26,490 residential and 9,636 commercial and industrial customers utilizing the transportation service.

Clean Energy Ventures

Our Clean Energy Ventures segment invests in, owns and operates clean energy projects, including commercial and residential solar installations located in New Jersey, and wind farms located in Iowa, Kansas, Wyoming and Pennsylvania.

As of September 30, 2018, Clean Energy Ventures has constructed a total of 231.3 MW of solar capacity in New Jersey that has qualified for ITCs, including a combination of residential and commercial net-metered and grid-connected solar systems. As part of its solar investment program, Clean Energy Ventures operates a residential lease program, The Sunlight Advantage®, which provides qualifying homeowners with the opportunity to have a solar system installed at their home with no installation or maintenance expenses. Clean Energy Ventures owns, operates and maintains the system over the life of the lease in exchange for monthly lease payments. The program is operated by Clean Energy Ventures using qualified contracting partners in addition to strategic suppliers for material standardization and sourcing. The residential solar lease and PPA market is highly competitive, with various companies operating in New Jersey. Clean Energy Ventures competes on price, quality and brand reputation, leveraging its partner network and customer referrals.

Clean Energy Ventures’ commercial solar projects are sourced through various channels and include both net-metered and grid-connected systems. Net-metered projects involve the sale of energy to a host and grid-connected systems into the wholesale energy markets. Project construction is competitively sourced through third parties. New Jersey has the sixth largest solar market in the U.S., according to the Solar Energy Industries Association®, with a large number of firms competing in all facets of the market including development, financing and construction.

Our solar systems are registered and certified with the BPU’s Office of Clean Energy and qualified to produce SRECs. One SREC is created for every MWh of electricity produced by a solar generator. Clean Energy Ventures sells the SRECs it generates to a variety of counterparties, including electric load-serving entities that serve electric customers in New Jersey and are required to comply with the solar carve-out of the Renewable Portfolio Standard, a regulation that requires the increased production of energy from renewable energy sources. Solar projects are also currently eligible for federal ITCs in the year that they are placed into service.

As of September 30, 2018, Clean Energy Ventures has a total of 116.9 MW of wind capacity. The wind projects are eligible for PTCs for a 10-year period following commencement of operations and have PPAs of various terms in place, which typically govern the sale of energy, capacity and/or renewable energy credits.

In March 2018, Clean Energy Ventures committed to a plan to sell its remaining wind assets and it is probable that the sale will be completed within the next 12 months. Accordingly, wind assets and related liabilities are classified as held for sale on the Consolidated Balance Sheets.

On June 1, 2018, Clean Energy Ventures completed the sale of its membership interest in its 9.7 MW wind farm in Two Dot, Montana to NorthWestern Energy for a total purchase price of $18.5 million. The transaction generated a pre-tax gain of approximately $951,000, which is recognized as a reduction to O&M on the Consolidated Statements of Operations.

Clean Energy Ventures is subject to various risks including those associated with adverse federal and state legislation and regulatory policies, construction delays that can impact the timing or eligibility of tax incentives, technological changes and the future market of SRECs. See Item 1A. Risk Factors for additional information regarding these risks.

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Energy Services

Our Energy Services segment consists of unregulated wholesale and retail natural gas operations and provides producer and asset management services to a diverse customer base across North America. Energy Services has acquired contractual rights to natural gas storage and transportation assets it utilizes to implement its strategic and opportunistic market strategies. The rights to these assets were acquired in anticipation of delivering natural gas, performing asset management services for customers or identifying strategic opportunities that exist in or between the market areas that it serves. These opportunities are driven by price differentials between market locations and/or time periods. Energy Services’ activities are conducted in the market areas in which it has strong expertise, including the U.S. and Canada. Energy Services differentiates itself in the marketplace based on price, reliability and quality of service. Its competitors include wholesale marketing and trading companies, utilities, natural gas producers and financial institutions. Energy Services’ portfolio of customers includes regulated natural gas distribution companies, industrial companies, electric generators, natural gas/liquids processors, retail aggregators, wholesale marketers and natural gas producers.

While focusing on maintaining a low-risk operating and counterparty credit profile, Energy Services’ activities specifically consist of the following elements:

• Providing natural gas portfolio management services to nonaffiliated and our affiliated natural gas utility, electric generation facilities and natural gas producers;

• Managing strategies for new and existing natural gas storage and transportation assets to capture value from changes in price due to location or timing differences as a means to generate financial margin (as defined below);

• Managing transactional logistics to minimize the cost of natural gas delivery to customers while maintaining security of supply. Transactions utilize the most optimal and advantageous natural gas supply transportation routing available within its contractual asset portfolio and various market areas; and

• Managing economic hedging programs that are designed to mitigate the impact of changes in market prices on financial margin generated on its natural gas storage and transportation commitments.

From July 2017 through February 2018, NJRRS provided retail natural gas supply and transportation services to commercial and industrial customers in Delaware, Maryland, Pennsylvania and New Jersey. NJRRS was sold to an unrelated third party on February 28, 2018. See Note 17. Dispositions for more details.

In fiscal 2018, Energy Services purchased over 10 percent of its natural gas from one supplier. Energy Services believes the loss of this supplier would not have a material adverse impact on its results of operations, financial position or cash flows, as an adequate number of alternative suppliers exist.

Transportation and Storage Transactions

Energy Services focuses on creating value from the use of its physical assets, which are typically amassed through contractual rights to natural gas storage and transportation capacity. These assets become more valuable when favorable price changes occur that impact the value between or within market areas and across time periods. On a forward basis, Energy Services may hedge these price differentials through the use of financial instruments. In addition, Energy Services may seek to optimize these assets on a daily basis, as market conditions warrant, by evaluating natural gas supply and transportation availability within its portfolio. This enables Energy Services to capture geographic pricing differences across various regions, as delivered natural gas prices may change favorably as a result of market conditions. Energy Services may, for example, initiate positions when intrinsic financial margin is present, and then enhance that financial margin as prices change across regions or time periods.

Energy Services also engages in park-and-loan transactions with storage and pipeline operators, where Energy Services will either borrow (receive a loan of) natural gas with an obligation to repay the storage or pipeline operator at a later date or “park” natural gas with an obligation to withdraw at a later date. In these cases, Energy Services evaluates the economics of the transaction to determine if it can capture pricing differentials in the marketplace and generate financial margin. Energy Services evaluates deal attributes such as fixed fees, calendar spread value from deal inception until volumes are scheduled to be returned and/or repaid, as well as the time value of money. If this evaluation demonstrates that financial margin exists, Energy Services may enter into the transaction and hedge with natural gas futures contracts, thereby locking in financial margin.

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Energy Services maintains inventory balances to satisfy existing or anticipated sales of natural gas to its counterparties and/or to create additional value, as described above. During fiscal 2018 and 2017, Energy Services managed and sold 662.4 Bcf and 521.6 Bcf of natural gas, respectively. In addition, as of September 30, 2018 and 2017, Energy Services had 34.1 Bcf or $90.2 million of gas in storage and 53.9 Bcf or $122.9 million of gas in storage, respectively.

Weather/Seasonality

Energy Services activities are typically seasonal in nature as a result of changes in the supply and demand for natural gas. Demand for natural gas is generally higher during the winter months when there may also be supply constraints; however, during periods of milder temperatures, demand can decrease. In addition, demand for natural gas can also be high during periods of extreme heat in the summer months, resulting from the need for additional natural gas supply for gas-fired electric generation facilities. Accordingly, Energy Services can be subject to variations in earnings and working capital throughout the year as a result of changes in weather.

Volatility

Energy Services’ activities are also subject to price volatility or supply/demand dynamics within its wholesale markets, including in the Northeastern, Appalachian, West Coast and Mid-Continent regions. Changes in natural gas supply can affect capacity values and Energy Services’ financial margin, described below, that is generated from the optimization of transportation and storage assets. With its focus on risk management, Energy Services continues to diversify its revenue stream by identifying new growth opportunities in producer and asset management services. Energy Services has added new counterparties and strategic storage and transportation assets to its portfolio, which currently includes an average of approximately 49.1 Bcf of firm storage and 1.5 Bcf/day of firm transportation capacity. Energy Services continues to expand its geographic footprint.

Financial Margin

To economically hedge the commodity price risk associated with its existing and anticipated commitments for the purchase and sale of natural gas, Energy Services enters into a variety of derivative instruments including, but not limited to, futures contracts, physical forward contracts, financial swaps and options. These derivative instruments are accounted for at fair value with changes in fair value recognized in earnings as they occur. Energy Services views “financial margin” as a key internal financial metric. Energy Services’ financial margin, which is a non-GAAP financial measure, represents revenues earned from the sale of natural gas less costs of natural gas sold including any storage and transportation costs, and excluding any accounting impact from changes in the fair value of certain derivative instruments. For additional information regarding financial margin, see Item 7. Management’s Discussion and Analysisof Financial Condition and Results of Operations - Energy Services Segment.

Risk Management

In conducting its business, Energy Services mitigates risk by following formal risk management guidelines, including transaction limits, segregation of duties and formal contract and credit review approval processes. Energy Services continuously monitors and seeks to reduce the risk associated with its counterparty credit exposures. Our Risk Management Committee oversees compliance with these established guidelines.

Midstream

Our Midstream segment includes investments in FERC-regulated interstate natural gas transportation and storage assets and is comprised of the following subsidiaries:

• NJR Steckman Ridge Storage Company, which holds our 50 percent equity investment in Steckman Ridge. Steckman Ridge is a Delaware limited partnership, jointly owned and controlled by our subsidiaries and subsidiaries of Enbridge Inc., that built, owns and operates a natural gas storage facility with up to 12 Bcf of working gas capacity in Bedford County, Pennsylvania. The facility has direct access to the Texas Eastern and Dominion Transmission pipelines and has access to the Northeast and Mid-Atlantic markets;

• NJR Pipeline Company, which includes our 20 percent equity investment in PennEast. PennEast is expected to construct a 120-mile, FERC-regulated interstate natural gas pipeline system that will extend from northern Pennsylvania to western New Jersey. Adelphia, our wholly owned subsidiary of NJR Pipeline Company, was established in anticipation of acquiring the membership interests in IEC. Upon closing, Adelphia will include an existing 84-mile pipeline in southeastern Pennsylvania and related assets and rights of way; and

• NJR Midstream Holdings Corporation, which, through its subsidiary NJNR Pipeline Company, holds approximately 1.84 million DM Common Units.

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OTHER BUSINESS OPERATIONS

Home Services and Other

Home Services and Other operations consist primarily of the following unregulated affiliates:

• NJRHS, which provides heating, ventilation and cooling service, sales and installation of appliances to approximately 110,000 service contract customers, as well as installation of solar equipment;

• NJR Plumbing Services, Inc., which provides plumbing repair and installation services;

• CR&R, which holds commercial real estate; and

• NJR Service Corporation, which provides shared administrative and financial services to the Company and all of its subsidiaries.

ENVIRONMENT

We along with our subsidiaries are subject to legislation and regulation by federal, state and local authorities with respect to environmental matters. We believe that we are, in all material respects, in compliance with all applicable environmental laws and regulations.

NJNG is responsible for the environmental remediation of five MGP sites, which contain contaminated residues from former gas manufacturing operations that ceased at these sites by the mid-1950s and, in some cases, had been discontinued many years earlier. NJNG periodically, and at least annually, performs an environmental review of the MGP sites, including a review of potential estimated liabilities related to the investigation and remedial action on these sites. Based on this review, NJNG has estimated that the total future expenditures to remediate and monitor the MGP sites for which it is responsible will range from approximately $117.7 million to $204.1 million.

NJNG’s estimate of these liabilities is based upon known and measurable facts, existing technology and enacted laws and regulations in place when the review was completed in fiscal 2018. 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. As of September 30, 2018, NJNG recorded an MGP remediation liability and a corresponding regulatory asset of $130.8 million on the Consolidated Balance Sheets, which represents its most likely possible liability and recoverable regulatory asset; however, actual costs may differ from these estimates.

EMPLOYEE RELATIONS

As of September 30, 2018, the Company and our subsidiaries employed 1,068 employees compared with 1,052 employees as of September 30, 2017. Of the total number of employees, NJNG had 446 and 444 and NJRHS had 97 and 104 Union or Represented employees as of September 30, 2018 and 2017, respectively. NJNG and NJRHS have collective bargaining agreements with the Union, which is affiliated with the American Federation of Labor and Congress of Industrial Organizations, that expire in December 2018 and April 2019, respectively. The labor agreements cover wage increases and other benefits, including the defined benefit pension (which was closed to all employees hired on or after January 1, 2012, with the exception of certain rehires who are eligible to resume active participation), the postemployment benefit plan (which was closed to all employees hired on or after January 1, 2012) and the enhanced 401(k) retirement savings plan. Collective bargaining negotiations with the Union for represented NJNG employees commenced in October 2018 and are expected to commence in February 2019 for represented NJRHS employees. We consider our relationship with employees, including those covered by collective bargaining agreements, to be in good standing.

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AVAILABLE INFORMATION AND CORPORATE GOVERNANCE DOCUMENTS

The following reports and any amendments to those reports are available free of charge on our website at http://investor.njresources.com/corporate-governance/sec-filings as soon as reasonably possible after filing or furnishing them with the SEC:

• Annual reports on Form 10-K;

• Quarterly reports on Form 10-Q; and

• Current reports on Form 8-K.

The following documents are available free of charge on our website (http://investor.njresources.com/corporate-governance):

• Bylaws;

• Corporate Governance Guidelines;

• Wholesale Trading Code of Conduct;

• NJR Code of Conduct;

• Charters of the following Board of Directors Committees: Audit, Leadership Development and Compensation and Nominating/Corporate Governance;

• Audit Complaint Procedure;

• Communicating with Non-Management Directors Procedure; and

• Statement of Policy with Respect to Related Person Transactions.

In Part III of this Form 10-K, we incorporate certain information by reference from our Proxy Statement for our 2019 Annual Meeting of Shareowners. We expect to file that Proxy Statement with the SEC on or about December 13, 2018. We will make it available on our website as soon as reasonably possible following that filing date. Please refer to the Proxy Statement when it is available.

A printed copy of each document is available free of charge to any shareholder who requests it by contacting the Corporate Secretary at New Jersey Resources Corporation, 1415 Wyckoff Road, Wall, New Jersey 07719.

ITEM 1A. RISK FACTORS

When considering any investment in our securities, investors should consider the following risk factors, as well as the information contained under the caption “Information Concerning Forward-Looking Statements,” in analyzing our present and future business performance. While this list is not exhaustive, management also places no priority or likelihood based on their descriptions or order of presentation. Unless indicated otherwise or the content requires otherwise, references below to “we,” “us,” and “our” should be read to refer to the Company and its subsidiaries.

Our investments in solar energy projects are subject to substantial risks and uncertainties.

Our investments in commercial and residential solar energy projects are dependent, in part, upon current regulatory incentives and federal tax credits in order for the projects to be economically viable. Our return on investment for these solar projects is based substantially on our eligibility for ITCs and the future market value of SRECs that are traded in a competitive marketplace in the State of New Jersey. As a result, these projects face the risk that the current regulatory programs and tax laws may expire or be adversely modified. Furthermore, a sustained decrease in the value of SRECs could negatively impact the return on our investment and could result in our portfolio of solar assets becoming impaired. The market for such projects is also limited, which creates increased competition and higher investment costs that may result in fewer investment opportunities that meet our return requirements.

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In addition, there are risks associated with our ability to develop and manage such projects profitably, including logistical risks and potential delays related to construction, permitting, regulatory approvals (including any approvals by the BPU required pursuant to recently enacted solar energy legislation in the State of New Jersey) and electric grid interconnection, as well as the operational risk that the projects in service will not perform according to expectations due to equipment failure, suboptimal weather conditions or other economic factors beyond our control. All of the aforementioned risks could reduce the availability of viable solar energy projects for development. Furthermore, at the development or acquisition stage, our ability to predict actual performance results may be hindered or inaccurate and the projects may not perform as predicted.

We may be unable to obtain governmental approvals, property rights and/or financing for the construction, development and operation of our proposed energy investments and projects in a timely manner or at all.

Construction, development and operation of energy investments, such as natural gas storage facilities, NJNG infrastructure improvements, such as SRL and NJ RISE, pipeline transportation systems, such as PennEast, planned Adelphia acquisition and solar energy projects are subject to federal and state regulatory oversight and require certain property rights, such as easements and rights-of-way from public and private property owners, as well as regulatory approvals, including environmental and other permits and licenses for such facilities and systems. We or our joint venture partnerships may be unable to obtain, in a cost-efficient or timely manner, all such needed property rights, permits and licenses to successfully construct and develop our energy facilities and systems. Successful financing of our energy investments requires participation by willing financial institutions and lenders, as well as acquisition of capital at favorable interest rates. If we do not obtain the necessary regulatory approvals, property rights and financing, our equity investments could be impaired. Such impairment could have a materially adverse effect on our financial condition, results of operations and cash flows.

Uncertainties associated with our planned Adelphia acquisition could adversely affect our business, results of operations, financial condition and cash flows.

In October 2017, we announced our planned Adelphia acquisition, involving the future operation and maintenance of a natural gas transmission pipeline extending approximately 90 miles into eastern Pennsylvania. As part of the acquisition we expect to convert the remaining sections of the southern mainline of the pipeline utilized to transport oil to transport natural gas. The completion of the acquisition is subject to various closing conditions, including, but not limited to, receipt of necessary permits and regulatory actions, such as those from the FERC and the Pennsylvania Public Utility Commission, and other pending regulatory determinations, such as compliance with anti-trust laws. There can be no assurance that we will receive the necessary approvals for the transaction or receive them within the expected timeframe. The announcement and pendency of our planned Adelphia acquisition, as well as any delays in the expected timeframe, could cause disruption and create uncertainties, which could have an adverse effect on our business, results of operations and financial condition, regardless of whether the acquisition is completed.

Any acquisitions that we may undertake involve risks and uncertainties. We may not realize the anticipated synergies, cost savings and growth opportunities as a results of these transactions.

The integration of acquisitions requires significant time and resources. Investments of resources are required to support any acquisition, which could result in significant ongoing operating expenses and may experience challenges when combining separate business cultures, information technology systems and employees, and those challenges may divert senior management’s time and attention. If we fail to successfully integrate assets and liabilities through the entities which we acquire, we may not fully realize all of the growth opportunities, benefits expected from the transaction, cost savings and other synergies and, as a result, the fair value of assets acquired could be impaired. We assess long-lived assets, including intangible assets associated with acquisitions for impairment whenever events or circumstances indicate that an asset’s carrying amount may not be recoverable. To the extent the value of long-lived assets become impaired, the impairment charges could have a material impact on our financial condition and results of operations.

The benefits that we expect to achieve from acquisitions will depend, in part, on our ability to realize anticipated growth opportunities and other synergies with our existing businesses. The success of these transactions will depend on our ability to integrate these transactions within our existing businesses timely and seamlessly. We may experience challenges when combining separate business cultures, information technology systems and employees. Even if we are able to complete the integration successfully, we may not fully realize all of the growth opportunities, cost savings and other synergies that we expect.

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Major changes in the supply and price of natural gas may affect financial results.

While NJNG expects to meet its customers’ demand for natural gas for the foreseeable future, factors impacting suppliers and other third parties, including the inability to develop additional interstate pipeline infrastructure, lack of supply sources, increased competition, further deregulation, transportation costs, possible climate change legislation, transportation availability and drilling for new natural gas resources, may impact the supply and price of natural gas. In addition, any significant disruption in the availability of supplies of natural gas could result in increased supply costs, higher prices for customers and potential supply disruptions to customers.

NJNG actively hedges against the fluctuation in the price of natural gas by entering into forward and financial contracts with third parties. Should these third parties fail to perform and regulators not allow the pass-through of expended funds to customers, it may result in a loss that could have a material impact on our financial condition, results of operations and cash flows.

We are subject to governmental regulation. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits and certificates may result in substantial costs to us.

We are subject to substantial regulation from federal, state and local authorities. We are required to comply with numerous laws and regulations and to obtain numerous authorizations, permits, approvals and certificates from governmental agencies. These agencies regulate various aspects of our business, including customer rates, services, construction and natural gas pipeline operations.

The FERC has regulatory authority over some of our operations, including sales of natural gas in the wholesale and retail markets and the purchase and sale of interstate pipeline and storage capacity. FERC will also have regulatory authority over Adelphia’s operations. Any Congressional legislation or agency regulation that would alter these or other similar statutory and regulatory structures in a way to significantly raise costs that could not be recovered in rates from customers, that would reduce the availability of supply or capacity or that would reduce our competitiveness could negatively impact our earnings. In addition, changes in and compliance with laws such as the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 could increase federal regulatory oversight and administrative costs that may not be recovered in rates from customers, which could have an adverse impact on our earnings.

We cannot predict the impact of any future revisions or changes in interpretations of existing regulations or the adoption of new laws and applicable regulations. Changes in regulations or the imposition of additional regulations could influence our operating environment and may result in substantial costs to us.

Significant regulatory assets recorded by NJNG could be disallowed for recovery from customers in the future.

NJNG records regulatory assets on its financial statements to reflect the ratemaking and regulatory decision-making authority of the BPU as allowed by GAAP. The creation of a regulatory asset allows for the deferral of costs, which, absent a mechanism to recover such costs from customers in rates approved by the BPU, would be charged to expense on its income statement in the period incurred. Primary regulatory assets that are subject to BPU approval include the recovery of BGSS and USF costs, remediation costs associated with NJNG’s MGP sites, CIP, NJCEP, economic stimulus plans, certain deferred income tax and pension and other postemployment benefit plans. If there were to be a change in regulatory positions surrounding the collection of these deferred costs there could be a material impact on NJNG’s existing tariff or a future base rate case, as well as our financial condition, results of operations and cash flows.

NJR is a holding company and depends on its operating subsidiaries to meet its financial obligations.

NJR is a holding company with no significant assets other than possible cash investments and the stock of its operating subsidiaries. We rely exclusively on dividends from our subsidiaries, on intercompany loans from our unregulated subsidiaries, and on the repayments of principal and interest from intercompany loans and reimbursement of expenses from our subsidiaries for our cash flows. Our ability to pay dividends on our common stock and to pay principal and interest on our outstanding debt depends on the payment of dividends to us by our subsidiaries or the repayment of loans to us by our subsidiaries. The extent to which our subsidiaries are unable to pay dividends or repay funds to us may adversely affect our ability to pay dividends to holders of our common stock and principal and interest to holders of our debt.

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Our regulated operations are subject to certain operating risks incidental to handling, storing, transporting and providing customers with natural gas.

Our regulated operations are subject to all operating hazards and risks incidental to handling, storing, transporting and providing customers with natural gas, including our natural gas vehicle refueling stations and LNG facilities. These risks include catastrophic failure of the interstate pipeline system, explosions, pollution, release of toxic substances, fires, storms, safety issues and other adverse weather conditions and hazards, each of which could result in damage to or destruction of facilities or damage to persons and property. We could suffer substantial losses should any of these events occur. Moreover, as a result, NJNG has been, and likely will be, a defendant in legal proceedings and litigation arising in the ordinary course of business. Although NJNG maintains insurance coverage, insurance may not be sufficient to cover all material expenses related to these risks.

NJNG and Energy Services rely on storage, transportation assets and suppliers, which they do not own or control, to deliver natural gas.

NJNG and Energy Services depend on natural gas pipelines and other storage and transportation facilities owned and operated by third parties to deliver natural gas to wholesale and retail markets and to provide retail energy services to customers. Their ability to provide natural gas for their present and projected sales will depend upon their suppliers’ ability to obtain and deliver additional supplies of natural gas, as well as NJNG’s ability to acquire supplies directly from new sources. Factors beyond the control of NJNG, its suppliers and the independent suppliers that have obligations to provide natural gas to certain NJNG customers may affect NJNG’s ability to deliver such supplies. These factors include other parties’ control over the drilling of new wells and the facilities to transport natural gas to NJNG’s citygate stations, development of additional interstate pipeline infrastructure, availability of supply sources, competition for the acquisition of natural gas, priority allocations, impact of severe weather disruptions to natural gas supplies and the regulatory and pricing policies of federal and state regulatory agencies, as well as the availability of Canadian reserves for export to the United States. Energy deregulation legislation may increase competition among natural gas utilities and impact the quantities of natural gas requirements needed for sales service. Energy Services also relies on a firm supply source to meet its energy management obligations to its customers. If supply, transportation or storage is disrupted, including for reasons of force majeure, the ability of NJNG and Energy Services to sell and deliver their products and services may be hindered. As a result, they may be responsible for damages incurred by their customers, such as the additional cost of acquiring alternative supply at then-current market rates. Particularly for Energy Services, these conditions could have a material impact on our financial condition, results of operations and cash flows.

Risks related to the regulation of NJNG could affect the rates it is able to charge, its costs and its profitability.

NJNG is subject to regulation by federal, state and local authorities. These authorities regulate many aspects of NJNG’s distribution and transmission operations, including construction and maintenance of facilities, operations, safety, tariff rates that NJNG can charge customers, rates of return, the authorized cost of capital, recovery of pipeline replacement, environmental remediation costs and relationships with its affiliates. NJNG’s ability to obtain rate increases, including base rate increases, extend its BGSS incentive and CIP programs and maintain its currently authorized rates of return may be impacted by events, including regulatory or legislative actions. There can be no assurance that NJNG will be able to obtain rate increases and continue its BGSS incentive, CIP, RAC and SAVEGREEN programs or continue to earn its currently authorized rates of return.

A change in our effective tax rate as a result of a failure to qualify for ITCs or being delayed in qualifying for ITCs due to delays or failures to complete planned solar energy projects within the safe harbor period may have a material impact on our earnings.

GAAP requires that we apply an effective tax rate to interim periods that is consistent with our estimated annual effective tax rate. As a result, we project quarterly the annual effective tax rate and then adjust the tax expense recorded in that quarter to reflect the projected annual effective tax rate. The amount of the quarterly adjustment is based on information and assumptions, which are subject to change and may have a material impact on our quarterly and annual NFE. Factors we consider in estimating the probability of projects being completed during the fiscal year include, but are not limited to, Board of Directors approval, construction logistics, permitting, interconnection completion and execution of various contracts, including PPAs. If we fail to qualify for ITCs or are delayed in qualifying for some ITCs during the fiscal year due to delays or failures to complete planned solar energy projects as scheduled, our quarterly and annual net income and NFE may be materially impacted. This could have a material adverse impact on our financial condition, results of operations and cash flows.

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We are involved in legal or administrative proceedings before various courts and governmental bodies that could adversely affect our results of operations, cash flows and financial condition.

In the ordinary conduct of business, we are involved in legal or administrative proceedings before various courts and governmental bodies with respect to general claims, rates, permitting, taxes, environmental issues, gas cost prudence reviews and other matters. Adverse decisions regarding these matters, to the extent they require us to make payments in excess of amounts provided for in our financial statements or are not covered by insurance or indemnity rights, could adversely affect our results of operations, cash flows and financial condition.

Credit rating downgrades could increase financing costs, limit access to the financial markets and negatively affect NJR and its subsidiaries.

Rating agencies Moody’s and S&P currently rate NJNG’s debt as investment grade. If such ratings are downgraded below investment grade, borrowing costs could increase, as will the costs of maintaining certain contractual relationships and obtaining future financing. Even if ratings are downgraded without falling below investment grade, NJR and NJNG could face increased borrowing costs under their current and future credit facilities. Our ability to borrow and costs of borrowing have a direct impact on our subsidiaries’ ability to execute their operating strategies, particularly in the case of NJNG, which relies heavily upon capital expenditures financed by its credit facility.

If we suffer a reduction in our credit and borrowing capacity or in our ability to issue parental guarantees, the business prospects of Energy Services, Clean Energy Ventures and Midstream, which rely on our creditworthiness, would be adversely affected. Energy Services could possibly be required to comply with various margin or other credit enhancement obligations under its trading and marketing contracts, and it may be unable to continue to trade or be able to do so only on less favorable terms with certain counterparties. Clean Energy Ventures could be required to seek alternative financing for its projects, and may be unable to obtain such financing or able to do so only on less favorable terms. In addition, NJNR Pipeline Company may not be able to finance its capital obligations to PennEast.

Additionally, lower credit ratings could adversely affect relationships with NJNG’s state regulators, who may be unwilling to allow NJNG to pass along increased costs to its natural gas customers.

Cyberattacks or failure of information technology systems could adversely affect our business operations, financial condition and results of operations.

We continue to place ever-greater reliance on technological tools that support our business operations and corporate functions, including tools that help us manage our natural gas distribution and energy trading operations and infrastructure. The failure of, or security breaches related to, these technologies could materially adversely affect our business operations, our financial position, results of operations and cash flows.

We rely on information technology to manage our natural gas distribution, energy trading and other corporate operations, maintain customer, employee, Company and vendor data, prepare our financial statements and perform other critical business processes. This technology may fail due to cyberattack, physical disruption, design and implementation defects or human error. Disruption or failure of business operations and information technology systems could harm our facilities or otherwise adversely impact our ability to safely deliver natural gas to our customers, serve our customers effectively or manage our assets. Additionally, an attack on, or failure of, information technology systems could result in the unauthorized release of customer, employee or other confidential or sensitive data. Any of the foregoing events could adversely affect our business reputation, diminish customer confidence, disrupt operations, subject us to financial liability or increased regulation, increase our costs and expose us to material legal claims and liability.

There is no guarantee that redundancies built into our networks and technology, or the procedures we have implemented to protect against cyberattack and other unauthorized access to secured data, are adequate to safeguard against all failures of technology or security breaches.

Adverse economic conditions, including inflation, increased natural gas costs, foreclosures and business failures, could adversely impact NJNG’s customer collections and increase our level of indebtedness.

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New Jersey Resources Corporation

Part I

ITEM 1A. RISK FACTORS (Continued)

Inflation may cause increases in certain operating and capital costs. We continually review the adequacy of NJNG’s base tariff rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those rates. The ability to control operating expenses is an important factor that will influence future results.

Rapid increases in the price of purchased gas may cause NJNG to experience a significant increase in short-term debt because it must pay suppliers for gas when it is purchased, which can be significantly in advance of when these costs may be recovered through the collection of monthly bills for gas delivered to customers. Increases in purchased gas costs also slow collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher-than-normal accounts receivable.

If we are unable to access the financial markets or there are adverse conditions in the equity or credit markets, it could affect management’s ability to execute our business plans.

We rely on access to both short-term and long-term credit markets as significant sources of liquidity for capital requirements not satisfied by our cash flow from operations. Any deterioration in our financial condition could hamper our ability to access the equity or credit markets or otherwise obtain debt financing on terms favorable to us or at all. In addition, because certain state regulatory approvals may be necessary for NJNG to incur debt, NJNG may be unable to access credit markets on a timely basis. External events could also increase the cost of borrowing or adversely affect our ability to access the financial markets. Such external events could include the following:

• economic weakness and/or political instability in the United States or in the regions where we operate;

• political conditions, such as a shutdown of the U.S. federal government;

• financial difficulties of unrelated energy companies;

• capital market conditions generally;

• volatility in the equity markets;

• market prices for natural gas;

• the overall health of the natural gas utility industry; and

• fluctuations in interest rates, particularly with respect to NJNG’s variable rate debt instruments.

Our ability to secure short-term financing is subject to conditions in the credit markets. A prolonged constriction of credit availability could affect management’s ability to execute our business plan. An inability to access capital may limit our ability to pursue improvements or acquisitions that we may otherwise rely on for both current operations and future growth.

Energy Services and NJNG execute derivative transactions with financial institutions as a part of their economic hedging strategy and could incur losses associated with the inability of a financial counterparty to meet or perform under its obligations as a result of adverse conditions in the credit markets or their ability to access capital or post collateral.

The cost of providing pension and postemployment health care benefits to eligible former employees is subject to changes in pension fund values, interest rates and changing demographics and may have a material adverse effect on our financial results.

We have two defined benefit pension plans and two OPEB plans for the benefit of eligible full-time employees and qualified retirees, which were closed to all employees hired on or after January 1, 2012. The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of the pension and OPEB fund assets, changing discount rates and changing actuarial assumptions based upon demographics, including longer life expectancy of beneficiaries, an expected increase in the number of eligible former employees over the next five years, impacts from healthcare legislation and increases in health care costs.

Significant declines in equity markets and/or reductions in bond yields can have a material adverse effect on the funded status of our pension and OPEB plans. In these circumstances, we may be required to recognize increased pension and OPEB expenses and/or be required to make additional cash contributions into the plans.

The funded status of these plans, and the related cost reflected in our financial statements, are affected by various factors that are subject to an inherent degree of uncertainty. Under the Pension Protection Act of 2006, losses of asset values may necessitate increased funding of the plans in the future to meet minimum federal government requirements. A significant decrease in the asset values of these plans can result in funding obligations earlier than we had originally planned, which would have a negative impact on cash flows from operations, decrease our borrowing capacity and increase our interest expense.

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New Jersey Resources Corporation

Part I

ITEM 1A. RISK FACTORS (Continued)

We are exposed to market risk and may incur losses in our wholesale business.

Our storage and transportation portfolios consist of contracts to transport and store natural gas. The value of our storage and transportation portfolio could be negatively impacted if the value of these contracts change in a direction or manner that we do not anticipate. In addition, upon expiration of these storage and transportation contracts, to the extent that they are renewed or replaced at less favorable terms, our results of operations and cash flows could be negatively impacted.

Our economic hedging activities that are designed to protect against commodity and financial market risks, including the use of derivative contracts in the normal course of our business, may cause fluctuations in reported financial results and financial losses that negatively impact results of operations and our stock price.

We use derivatives, including futures, forwards, options, swaps and foreign exchange contracts to manage commodity, financial market and foreign currency risks. The timing of the recognition of gains or losses associated with our economic hedges in accordance with GAAP does not always coincide with the gains or losses on the items being hedged. The difference in accounting can result in volatility in reported results, even though the expected profit margin is essentially unchanged from the dates the transactions were consummated.

In addition, we could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could adversely affect the value of the reported fair value of these contracts.

Energy Services’ earnings and cash flows are dependent upon optimization of its physical assets.

Energy Services’ earnings and cash flows are based, in part, on its ability to optimize its portfolio of contractually-based natural gas storage and pipeline assets. The optimization strategy involves utilizing its physical assets to take advantage of differences in natural gas prices between geographic locations and/or time periods. Any change among various pricing points could affect these differentials. In addition, significant increases in the supply of natural gas in Energy Services’ market areas, including as a result of increased production along the Marcellus Shale, can reduce Energy Services’ ability to take advantage of pricing fluctuations in the future. Changes in pricing dynamics and supply could have an adverse impact on Energy Services’ optimization activities, earnings and cash flows. Energy Services incurs fixed demand fees to acquire its contractual rights to storage and transportation assets. Should commodity prices at various locations or time periods change in such a way that Energy Services is not able to recoup these costs from its customers, the cash flows and earnings at Energy Services, and ultimately the Company, could be adversely impacted.

Changes in weather conditions may affect earnings and cash flows.

Weather conditions and other natural phenomena can have an adverse impact on our earnings and cash flows. Severe weather conditions can impact suppliers and the pipelines that deliver gas to NJNG’s distribution system. Extended mild weather, during either the winter period or summer period, can have a significant impact on demand for and the cost of natural gas. While we believe the CIP mitigates the impact of weather variations on NJNG’s margin, severe weather conditions may have an impact on the ability of suppliers and pipelines to deliver the natural gas to NJNG, which can negatively affect our earnings. The CIP does not mitigate the impact of severe weather conditions on our cash flows.

Future results at Energy Services are subject to volatility in the natural gas market due to weather. Variations in weather may affect earnings and working capital needs throughout the year. During periods of milder temperatures, demand and volatility in the natural gas market may decrease, which can negatively impact Energy Services’ earnings and cash flows.

Changes in tax laws or regulations may negatively affect our results of operations, net income, financial condition and cash flows.

We are subject to taxation by various taxing authorities at the federal, state and local levels. On December 22, 2017, the President signed into law the Tax Act. The newly enacted legislation included a broad range of tax reform initiatives, including a reduction to the federal statutory corporate tax rate from 35 percent to 21 percent, modification of bonus depreciation and changes to the deductibility of certain business-related expenses. Any future change in tax laws, including the Tax Act, or interpretation of such laws, could adversely affect our results of operations, net income, financial condition and cash flows. In addition, we cannot predict how our federal and state regulators will apply such tax change in our future rates.

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New Jersey Resources Corporation

Part I

ITEM 1A. RISK FACTORS (Continued)

A valuation allowance may be required for our deferred tax assets.

As a result of the Tax Act’s decrease to the federal statutory corporate tax rate, we revalued our deferred tax assets and liabilities at the enactment date to reflect the rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. Since these adjustments are based on assumptions we made with respect to our book versus tax differences and the timing of when those differences will reverse, the revaluation of our net deferred tax liabilities is subject to change as information and assumptions are updated. Our deferred tax assets are comprised primarily of investment tax credits and state net operating losses. Any further revaluation of our deferred tax assets that may be required in the future could have a material adverse impact on our financial condition and results of operations.

Failure by NJR and/or NJNG to comply with debt covenants may impact our financial condition.

Our long-term debt obligations contain financial covenants related to debt-to-capital ratios and, in the case of NJNG, an interest coverage ratio. These debt obligations also contain provisions that put limitations on our ability to finance future operations or capital needs or to expand or pursue certain business activities. For example, certain of these agreements contain provisions that, among other things, put limitations on our ability to make loans or investments, make material changes to the nature of our businesses, merge, consolidate or engage in asset sales, grant liens or make negative pledges. Furthermore, the debt obligations and our sale-leaseback agreements contain covenants and other provisions requiring us to provide timely delivery of accurate financial statements prepared in accordance with GAAP. The failure to comply with any of these covenants could result in an event of default, which, if not cured or waived, could result in the acceleration of outstanding debt obligations and/or the inability to borrow under existing revolving credit facilities. We have relied, and continue to rely, upon short-term bank borrowings or commercial paper supported by our revolving credit facilities to finance the execution of a portion of our operating strategies. NJNG is dependent on these capital sources to purchase its natural gas supply and maintain its properties. The acceleration of our outstanding debt obligations and our inability to borrow under the existing revolving credit facilities would cause a material adverse change in NJR’s and NJNG’s financial condition.

Changes in customer growth may affect earnings and cash flows.

NJNG’s ability to increase its utility firm gross margin is dependent upon the new construction housing market, as well as the conversion of customers to natural gas from other fuel sources. During periods of extended economic downturns, prolonged weakness in housing markets or slowdowns in the conversion market, there could be an adverse impact on NJNG’s utility firm gross margin, earnings and cash flows. Furthermore, while our estimates regarding customer growth are based in part upon information from third parties, the estimates have not been verified by an independent source and are subject to the aforementioned risks and uncertainties, which could cause actual results to materially deviate from the estimates.

We may be adversely impacted by natural disasters, pandemic illness, terrorist activities and other extreme events to which we may be unable to promptly respond.

Local or national natural disasters, pandemic illness, terrorist activities, catastrophic failure of the interstate pipeline system and other extreme events are a threat to our assets and operations. Companies in our industry that are located in our service territory may face a heightened risk due to exposure to acts of terrorism that could target or impact our natural gas distribution, transmission and storage facilities and disrupt our operations and ability to meet customer requirements. In addition, the threat of terrorist activities could lead to increased economic instability and volatility in the price of natural gas that could affect our operations. Natural disasters or actual or threatened terrorist activities may also disrupt capital markets and our ability to raise capital, or may impact our suppliers or our customers directly. A local disaster or pandemic illness could result in part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business. In addition, these risks could result in loss of human life, significant damage to property, environmental damage, impairment of our operations and substantial loss to the Company. Our regulators may not allow us to recover from our customers part or all of the increased cost related to the foregoing events, which could negatively affect our financial condition, results of operations and cash flows.

A slow or inadequate response to events that could cause business interruption may have an adverse impact on operations and earnings. We may be unable to obtain sufficient insurance to cover all risks associated with local and national disasters, pandemic illness, terrorist activities, catastrophic failure of the interstate pipeline system and other events, which could increase the risk that an event adversely affects our financial condition, results of operations and cash flows.

Our costs of compliance with present and future environmental laws are significant and could adversely affect our cash flows and profitability.

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and site remediation. Compliance with these laws and regulations

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New Jersey Resources Corporation

Part I

ITEM 1A. RISK FACTORS (Continued)

may require us to expend significant financial resources to, among other things, conduct site remediation and perform environmental monitoring. If we fail to comply with applicable environmental laws and regulations, even if we are unable to do so due to factors beyond our control, we may be subject to civil liabilities or criminal penalties and may be required to incur significant expenditures to come into compliance. Additionally, any alleged violations of environmental laws and regulations may require us to expend significant resources in our defense against alleged violations.

Furthermore, the U.S. Congress has for some time been considering various forms of climate change legislation. There is a possibility that, when and if enacted, the final form of such legislation could impact our costs and put upward pressure on natural gas prices. Higher cost levels could impact the competitive position of natural gas and negatively affect our growth opportunities, cash flows and earnings.

Failure to attract and retain an appropriately qualified employee workforce could adversely affect operations.

Our ability to implement our business strategy and serve our customers is dependent upon our continuing ability to attract and retain talented professionals and a technically skilled workforce, and being able to transfer the knowledge and expertise of our workforce to new employees as our aging employees retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor could adversely affect the ability to manage and operate our business. Furthermore, NJNG and NJRHS have collective bargaining agreements with the Union that expire in December 2018 and April 2019, respectively. Union negotiations for represented NJNG employees commenced in October 2018 and are expected to commence in February 2019 for represented NJRHS employees. Disputes with the Union over terms and conditions of the agreement could result in instability in our labor relationship and work stoppages that could impact the timely delivery of gas and other services from our utility, which could strain relationships with customers and state regulators and cause a loss of revenues that could adversely affect our results of operations. Our collective bargaining agreement may also increase the cost of employing our natural gas distribution segment workforce, affect our ability to continue offering market-based salaries and employee benefits, limit our flexibility in dealing with our workforce and limit our ability to change work rules and practices and implement other efficiency-related improvements to successfully compete in today’s challenging marketplace.

Investing through partnerships, joint ventures or in an MLP decreases our ability to manage risk.

We have utilized joint ventures through partnerships for certain midstream investments, including Steckman Ridge and PennEast, and we own a minority interest in DM, an MLP, through our investment in DM Common Units. Although we currently have no specific plans to do so, we may acquire interests in other joint ventures or partnerships in the future. In these joint ventures or partnerships, we may not have the right or power to direct the management and policies of the joint ventures or partnerships, and other participants or investors may take action contrary to our instructions or requests and against our policies and objectives. In addition, the other participants may become bankrupt or have economic or other business interests or goals that are inconsistent with those of NJR and our subsidiaries. Our financial condition, results of operations or cash flows could be harmed if a joint venture participant acts contrary to our interests.

Additionally, our investment in DM has risks that are unique to investments in MLPs. Holders of MLP common units have limited control and voting rights on matters affecting the MLP, and investments in MLPs may have limited liquidity. Additionally, if DM is treated as a corporation for federal income tax purposes as a result of a change in current law or a change in DM’s business, such treatment would result in a reduction in the after-tax return to us and may cause a reduction in the value of our investment in DM Common Units.

Our certificate of incorporation and bylaws may delay or prevent a transaction that stockholders would view as favorable.

Our certificate of incorporation and bylaws, as well as New Jersey law, contain provisions that could delay, defer or prevent an unsolicited change in control of NJR, which may negatively affect the market price of our common stock or the ability of stockholders to participate in a transaction in which they might otherwise receive a premium for their shares over the then-current market price. These provisions may also prevent changes in management. In addition, our Board of Directors is authorized to issue preferred stock without stockholder approval on such terms as our Board of Directors may determine. Our common stockholders will be subject to, and may be negatively affected by, the rights of any preferred stock that may be issued in the future. In addition, we are subject to the New Jersey Shareholders’ Protection Act, which could delay or prevent a change of control of NJR.

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New Jersey Resources Corporation

Part I

ITEM 1B. UNRESOLVED STAFF COMMENTS                                                                                                                        

None

ITEM 2. PROPERTIES

Natural Gas Distribution Segment

NJNG owns approximately 7,252 miles of distribution main, 7,525 miles of service main, 227 miles of transmission main and 557,000 meters. Mains are primarily located under public roads. Where mains are located under private property, NJNG has obtained easements from the owners of record.

Additionally, NJNG owns and operates two LNG storage plants in Stafford Township, Ocean County; and Howell Township, Monmouth County. The two LNG plants have an aggregate estimated maximum capacity of approximately 170,000 Dths per day and 1 Bcf of total capacity. These facilities are used for peaking natural gas supply and for emergencies. NJNG’s Liquefaction facility is also located on the Howell Township property and allows NJNG to convert natural gas into LNG to fill NJNG’s existing LNG storage tanks.

NJNG owns four service centers located in Rockaway Township, Morris County; Atlantic Highlands and Wall Township, Monmouth County; and Lakewood, Ocean County. These service centers house storerooms, garages, gas distribution and administrative offices. NJNG leases its headquarters and customer service facilities in Wall Township, Monmouth County; a customer service office in Asbury Park, Monmouth County; and a service center in Manahawkin, Ocean County. These customer service offices support customer contact, marketing, economic development and other functions.

Substantially all of NJNG’s properties, not expressly excepted or duly released, are subject to the lien of the Mortgage Indenture as security for NJNG’s mortgage bonds, which totaled $672 million as of September 30, 2018. In addition, under the terms of the Mortgage Indenture, NJNG could have issued up to $1 billion of additional first mortgage bonds as of September 30, 2018.

Clean Energy Ventures Segment

Clean Energy Ventures has various solar contracts, including lease agreements and easements, allowing the installation, operation and maintenance of solar equipment and access to the various properties, including commercial and residential rooftops. In addition to the lease agreements and easements, Clean Energy Ventures owns solar panels with a total of 231.3 MW of capacity throughout New Jersey and owns 79.5 acres of land in Vineland, New Jersey.

Clean Energy Ventures is also party to various land lease agreements and easements, which allow for the installation, operation and maintenance of wind turbines, associated electric collection facilities, substations, operation and maintenance buildings and access to the various properties. Clean Energy Ventures has a total of 116.9 MW of wind capacity and owns wind projects in Carroll County, Iowa, Rush County, Kansas, Carbon County, Wyoming and Somerset County, Pennsylvania. In addition to the lease agreements and easements, Clean Energy Ventures owns 1.8 acres and 7.1 acres of land for its Carroll County and Rush County wind projects, respectively. Clean Energy Ventures also owns a building on .16 acres in Rush County, Kansas that is used for operation and maintenance purposes.

Clean Energy Ventures leases office space in Wall Township, New Jersey.

Energy Services Segment

As of September 30, 2018, Energy Services leases office space in Wall Township, New Jersey, Houston, Texas, Charlotte, North Carolina and Allentown, Pennsylvania.

Midstream Segment

As of September 30, 2018, Steckman Ridge owned and/or leased storage rights on approximately 6,300 acres of land in Bedford County, Pennsylvania, with a FERC-regulated natural gas storage facility with up to 12 Bcf of working gas capacity. Equipment on the property includes a compressor station, gathering pipelines and pipeline interconnections. As of September 30, 2018, PennEast owned 74 acres of land in Carbon County, Pennsylvania and 58.7 acres of land in Mercer County, New Jersey.

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New Jersey Resources Corporation

Part I

ITEM 2. PROPERTIES (Continued)                                                                                                                                            

All Other Business Operations

As of September 30, 2018, CR&R’s real estate portfolio consisted of 35 acres of undeveloped land in Atlantic County, New Jersey with a net book value of $1.4 million.

NJRHS leases service centers in Dover, New Jersey and Wall Township, New Jersey.

Capital Expenditure Program

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of anticipated fiscal 2019 and 2020 capital expenditures, as applicable to our reporting segments and business operations.

ITEM 3. LEGAL PROCEEDINGS

Manufactured Gas Plant Remediation

NJNG is responsible for the remedial cleanup of five MGP sites, dating back to gas operations in the late 1800s and early 1900s, which contain contaminated residues from former gas manufacturing operations. NJNG is currently involved in administrative proceedings with the NJDEP, and 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 Administrative Consent Orders or a Memoranda of Agreement with the NJDEP.

NJNG may recover its remediation expenditures, including carrying costs, over rolling seven-year periods pursuant to a RAC approved by the BPU. NJNG recovered approximately $9.4 million annually through its SBC RAC. On July 25, 2018, the BPU approved NJNG’s annual SBC application requesting a reduction in the RAC, which decreased the annual recovery to $7 million, effective September 1, 2018. On September 21, 2018, NJNG filed its annual SBC application requesting to recover remediation expenses incurred through June 30, 2018, and an increase in the RAC, which will result in an annual increase of approximately $1.4 million, effective April 1, 2019. As of September 30, 2018, $33 million of previously incurred remediation costs, net of recoveries from customers and insurance proceeds, are included in regulatory assets on the Consolidated Balance Sheets.

NJNG periodically, and at least annually, performs an environmental review of MGP sites located in Atlantic Highlands, Berkeley, Long Branch, Manchester and Toms River, including a review of potential liability for investigation and remedial action. NJNG estimated at the time of the most recent review that total future expenditures to remediate and monitor the MGP sites for which it is responsible, including potential liabilities for natural resource damages that might be brought by the NJDEP for alleged injury to groundwater or other natural resources concerning these sites, will range from approximately $117.7 million to $204.1 million. NJNG’s estimate of these liabilities is based upon known facts, existing technology and enacted laws and regulations in place when the review was completed. Where it is probable that costs will be incurred, and the information is sufficient to establish a range of possible liability, NJNG accrues the most likely amount in the range. If no point within the range is more likely than the other, it is NJNG’s policy to accrue the lower end of the range. Accordingly, as of September 30, 2018, NJNG recorded an MGP remediation liability and a corresponding regulatory asset of $130.8 million on the Consolidated Balance Sheets, based on the most likely amount. This was reduced from $149 million in fiscal 2017, due to the completion of remediation work at certain sites and a reduction to the remediation scope at another site. The actual costs to be incurred by NJNG are dependent upon several factors, including final determination of remedial action, changing technologies and governmental regulations, the ultimate ability of other responsible parties to pay and insurance recoveries, if any.

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

We are involved, and from time to time in the future may be involved, in a number of pending and threatened judicial, regulatory and arbitration proceedings relating to matters that arise in connection with the conduct of business, certain of which litigation matters are described in Note 13. Commitments and Contingent Liabilities in the accompanying Consolidated Financial Statements. 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, we 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.

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New Jersey Resources Corporation

Part I

ITEM 3. LEGAL PROCEEDINGS (Continued)                                                                                                                          

In accordance with applicable accounting guidance, we establish reserves for litigation for those matters that present loss contingencies as to which it is both probable that a loss will be incurred and the amount of such loss can be reasonably estimated. Based upon currently available information, we believe that the results of litigation that is currently pending, taken together, will not have a materially adverse effect on our financial condition, results of operations or cash flows. The actual results of resolving the pending litigation matters may be substantially higher than the amounts reserved.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable

ITEM 4A. EXECUTIVE OFFICERS OF THE COMPANY

The Company’s Executive Officers and their age, position and business experience during the past five years are set forth below.

Name	Age	Officer since	Office held during last five years
Laurence M. Downes	61	1986	Chairman of the Board (September 1996 - present) Chief Executive Officer (July 1995 - present) President (July 1995 - September 2018)
Patrick J. Migliaccio	44	2013	Senior Vice President and Chief Financial Officer (January 2016 - present) Vice President, Finance and Accounting (November 2014 - December 2015) Treasurer (August 2013 - May 2015)
Stephen D. Westhoven	50	2004	President and Chief Operating Officer (October 2018 - present) Executive Vice President and Chief Operating Officer (November 2017 - September 2018) Senior Vice President and Chief Operating Officer, NJRES and NJRCEV (October 2016 - October 2017) Senior Vice President, NJRES (May 2010 - September 2016)
Glenn C. Lockwood	57	1990	Executive Vice President (January 2011 - present) Chief Financial Officer (September 1995 - December 2015)
Amanda E. Mullan	52	2015	Senior Vice President and Chief Human Resources Officer (January 2017 - present) Vice President and Chief Human Resources Officer (April 2015 - December 2016) Senior Vice President of HR, N. America, Willis Group Holdings, a risk management and insurance intermediary (April 2012 - April 2015)
Jacqueline K. Shea	54	2016	Vice President and Chief Information Officer (June 2016 - present) Chief Information Officer, Godiva Chocolatier, a manufacturer of premium fine chocolates and related products (March 2011 - May 2016)
Nancy A. Washington	54	2017	Senior Vice President and General Counsel (March 2017 - present) Senior Vice President and Chief Litigation Counsel, CIT Group Inc., a Livingston, NJ-based financial services firm (September 2010 - March 2017)

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New Jersey Resources Corporation

Part II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES

NJR’s Common Stock is traded on the New York Stock Exchange under the ticker symbol NJR. As of September 30, 2018, NJR had 52,673 holders of record of its common stock.

In 1996, the Board of Directors authorized the Company to implement a share repurchase program, which has been expanded seven times since the inception of the program. The share repurchase plan allows us to purchase our outstanding shares on the open market or in negotiated transactions, based on market and other conditions. We are not required to purchase any specific number of shares and may discontinue or suspend the program at any time. The share repurchase plan will expire when we have repurchased all shares authorized for repurchase thereunder, unless it is earlier terminated by action of our Board of Directors or additional shares are authorized for repurchase.

The following table sets forth NJR’s repurchase activity for the quarter ended September 30, 2018:

Period	Total Number of Shares (or Units) Purchased	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) That May Yet Be Purchased Under the Plans or Programs
7/01/18 - 7/31/18	—	$	—	—	2,431,053
8/01/18 - 8/31/18	—	$	—	—	2,431,053
9/01/18 - 9/30/18	—	$	—	—	2,431,053
Total	—	$	—	—	2,431,053

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New Jersey Resources Corporation

Part II

ITEM 6. SELECTED FINANCIAL DATA                                                                                                                                   

CONSOLIDATED FINANCIAL STATISTICS

(Thousands, except per share data)
Fiscal Years Ended September 30,	2018			2017			2016			2015			2014
SELECTED FINANCIAL DATA
Operating revenues	$	2,915,109		$	2,268,617		$	1,880,905		$	2,733,987		$	3,738,145
Gas purchases	$	2,275,342		$	1,703,767		$	1,352,686		$	2,085,645		$	3,139,525
Net income	$	233,436		$	132,065		$	131,672		$	180,960		$	141,970
Total assets	$	4,143,664		$	3,928,507		$	3,718,570		$	3,284,357		$	3,125,388
Common stock equity	$	1,418,978		$	1,236,643		$	1,166,591		$	1,106,956		$	966,166
Long-term debt (1) (2)	$	1,180,619		$	997,080		$	1,055,038		$	843,595		$	598,209
COMMON STOCK DATA
Earnings per share-basic	$2.66			$1.53			$1.53			$2.12			$1.69
Earnings per share-diluted	$2.64			$1.52			$1.52			$2.10			$1.67
Dividends declared per share	$1.11			$1.038			$0.975			$0.915			$0.855
NON-GAAP RECONCILIATION
Net income	$	233,436		$	132,065		$	131,672		$	180,960		$	141,970
Add:
Unrealized loss (gain) on derivative instruments and related transactions	26,770			(11,241		)	46,883			(38,681		)	28,534
Tax effect	(4,512		)	4,062			(17,018		)	14,391			(10,492		)
Effects of economic hedging related to natural gas inventory	(22,570		)	38,470			(36,816		)	(8,225		)	26,639
Tax effect	7,362			(13,964		)	13,364			3,058			(9,794		)
Net financial earnings (3)	$	240,486		$	149,392		$	138,085		$	151,503		$	176,857
Basic earnings per share	$2.66			$1.53			$1.53			$2.12			$1.69
Add:
Unrealized loss (gain) on derivative instruments and related transactions	0.31			(0.13		)	0.55			(0.45		)	0.34
Tax effect	(0.05		)	0.05			(0.20		)	0.17			(0.13		)
Effects of economic hedging related to natural gas inventory	(0.26		)	0.45			(0.43		)	(0.10		)	0.32
Tax effect	0.08			(0.17		)	0.16			0.04			(0.12		)
Net financial earnings per share-basic (3)	$2.74			$1.73			$1.61			$1.78			$2.10
Diluted earnings per share	$2.64			$1.52			$1.52			$2.10			$1.67
Add:
Unrealized loss (gain) on derivative instruments and related transactions	0.30			(0.13		)	0.54			(0.45		)	0.34
Tax effect	(0.05		)	0.05			(0.20		)	0.17			(0.12		)
Effects of economic hedging related to natural gas inventory	(0.25		)	0.44			(0.42		)	(0.10		)	0.31
Tax effect	0.08			(0.17		)	0.15			0.04			(0.12		)
Net financial earnings per share-diluted (3)	$2.72			$1.71			$1.59			$1.76			$2.08

(1) Includes long-term capital leases of $26.4 million, $28.9 million, $30.7 million, $35.7 million and $40.4 million, respectively.

(2) Includes long-term solar asset financing obligation of $89.8 millionand $28.2 million in fiscal 2018 and 2017, respectively.

(3) NFE is a non-GAAP financial measure that eliminates the timing differences surrounding the recognition of certain derivative gains or losses, to effectively match the earnings effects of economic hedges associated with the physical sale or purchase of gas and, therefore, eliminate the impact of volatility to GAAP earnings associated with the related derivative instruments. For further discussion of this financial measure, see the Energy Services segment in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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New Jersey Resources Corporation

Part II

ITEM 6. SELECTED FINANCIAL DATA (Continued)                                                                                                              

NJNG OPERATING STATISTICS

Fiscal Years Ended September 30,	2018			2017			2016			2015			2014
Operating revenues ($ in thousands)
Residential	$	441,486		$	395,315		$	345,597		$	466,464		$	469,831
Commercial, industrial and other	95,351			98,777			80,994			106,505			110,740
Firm transportation	65,256			73,206			69,696			77,974			86,131
Total residential and commercial	602,093			567,298			496,287			650,943			666,702
Interruptible	7,522			7,970			8,867			10,049			9,384
Total system	609,615			575,268			505,154			660,992			676,086
BGSS incentive programs	122,250			120,369			89,192			120,978			143,329
Total operating revenues	$	731,865		$	695,637		$	594,346		$	781,970		$	819,415
Throughput (Bcf)
Residential	45.5			40.7			36.9			45.9			43.1
Commercial, industrial and other	8.9			8.7			7.3			9.6			8.2
Firm transportation	15.5			14.4			14.1			16.0			17.7
Total residential and commercial	69.9			63.8			58.3			71.5			69.0
Interruptible	46.2			55			61.5			47.1			10.5
Total system	116.1			118.8			119.8			118.6			79.5
BGSS incentive programs	150.2			178.4			216.7			222.4			180.8
Total throughput	266.3			297.2			336.5			341.0			260.3
Customers at year-end
Residential	474,495			460,013			448,273			437,979			422,742
Commercial, industrial and other	28,037			26,947			26,218			25,541			24,684
Firm transportation	36,126			42,790			46,608			48,673			56,777
Total residential and commercial	538,658			529,750			521,099			512,193			504,203
Interruptible	31			33			34			35			37
BGSS incentive programs	28			27			30			24			34
Total customers at year-end	538,717			529,810			521,163			512,252			504,274
Interest coverage ratio(1)	6.35			7.96			8.97			9.57			10.24
Average therm use per customer
Residential	959			885			824			1,049			1,020
Commercial, industrial and other	10,992			11,183			11,378			9,799			4,466
Degree days	4,537			4,129			3,867			5,015			5,080
Weather as a percent of normal(2)	99.5		%	90.0		%	82.5		%	108.3		%	109.6		%
Number of employees	686			680			670			649			626

(1) NJNG’s income from operations divided by interest expense.

(2) Normal heating degree days are based on a 20-year average, calculated based upon three reference areas representative of NJNG’s service territory.

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Part II

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS                                                                                                                                                                                   

Critical Accounting Policies

We prepare our financial statements in accordance with GAAP. Application of these accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingencies during the reporting period. We regularly evaluate our estimates, including those related to the calculation of the fair value of derivative instruments, regulatory assets, income taxes, pension and postemployment benefits other than pensions and contingencies related to environmental matters and litigation. We base our estimates 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. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from estimates.

Regulatory Accounting

NJNG maintains its accounts in accordance with the FERC Uniform System of Accounts as prescribed by the BPU and recognizes the impact of regulatory decisions on its financial statements. As a result of the ratemaking process, NJNG is required to apply the accounting principles in ASC 980, Regulated Operations, which differ in certain respects from those applied by unregulated businesses. Specifically, NJNG records regulatory assets when it is probable that certain operating costs will be recoverable from customers in future periods and records regulatory liabilities associated with probable future obligations to customers.

NJNG’s BGSS requires it to project its annual natural gas costs and provides the ability, subject to BPU approval, to recover or refund the difference, if any, of such actual costs compared with the projected costs included in prices through a BGSS charge to customers. Any underrecovery or overrecovery is recorded as a regulatory asset or liability on the Consolidated Balance Sheets and reflected in the BGSS charge to customers in subsequent years.

As recovery of regulatory assets is subject to BPU approval, if there are any changes in future regulatory positions, which indicate that recovery of all or a portion of a regulatory asset is not probable, the related cost would be charged to income in the period of such determination.

Impairment of Long-lived assets

Property, plant and equipment and intangible assets are reviewed periodically when changes in facts and circumstances indicate that the carrying amount of an asset may not be fully recoverable in accordance with the appropriate accounting guidance. When an impairment indicator is present, the Company determines if the carrying value of the asset is recoverable by comparing it to the expected undiscounted future cash flows. If carrying value of the asset is greater than the expected undiscounted future cash flows an impairment charge is recorded in an amount equal to the excess of the carrying value of the asset over its fair value.

Equity method investments are reviewed periodically when changes in facts and circumstances indicate that the current fair value may be less than the asset’s carrying amount and record an impairment charge in an amount equal to the excess of the carrying value of the asset over its fair value if the decline is other than temporary.

Derivative Instruments

We record our derivative instruments held as assets and liabilities at fair value on the Consolidated Balance Sheets. In addition, since we choose not to designate any of our physical and financial natural gas commodity derivatives as accounting hedges, changes in the fair value of Energy Services’ commodity derivatives are recognized in earnings, as they occur, as a component of operating revenues or gas purchases on the Consolidated Statements of Operations. Changes in the fair value of foreign exchange contracts are recognized in gas purchases on the Consolidated Statements of Operations.

The fair value of derivative instruments is determined by reference to quoted market prices of listed exchange-traded contracts, published price quotations, pipeline tariff information and/or a combination of those items. Energy Services’ portfolio is valued using the most current and reasonable market information. If the price underlying a physical commodity transaction does not represent a visible and liquid market, Energy Services may utilize additional published pipeline tariff information and/or other services to determine an equivalent market price. As of September 30, 2018, fair value of its derivative assets and liabilities reported on the Consolidated Balance Sheets that is based on such pricing is considered immaterial.

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New Jersey Resources Corporation

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Should there be a significant change in the underlying market prices or pricing assumptions, Energy Services may experience a significant impact on its financial position, results of operations and cash flows. Refer to Item 7A. Quantitative and Qualitative Disclosures About Market Risks for a sensitivity analysis related to the impact to derivative fair values resulting from changes in commodity prices. The valuation methods we use to determine fair values remained consistent for fiscal 2018, 2017 and 2016. We apply a discount to our derivative assets to factor in an adjustment associated with the credit risk of its physical natural gas counterparties and to our derivative liabilities to factor in an adjustment associated with its own credit risk. We determine this amount by using historical default probabilities corresponding to the appropriate S&P issuer ratings. Since the majority of our counterparties are rated investment grade, this results in an immaterial credit risk adjustment.

Gains and losses associated with derivatives utilized by NJNG to manage the price risk inherent in its natural gas purchasing activities are recoverable through its BGSS, subject to BPU approval. Accordingly, the offset to the change in fair value of these derivatives is recorded as either a regulatory asset or liability on the Consolidated Balance Sheets.

Clean Energy Ventures hedges certain of its expected production of SRECs through forward and futures contracts. Clean Energy Ventures intends to physically deliver all SRECs it sells and recognizes SREC revenue as operating revenue on the Consolidated Statements of Operations upon delivery of the underlying SREC.

We have not designated any derivatives as fair value or cash flow hedges as of September 30, 2018 and 2017.

Income Taxes and Credits

The determination of our provision for income taxes requires the use of estimates and the interpretation and application of tax laws. Judgment is required in assessing the deductibility and recoverability of certain taxable items. We use the asset and liability method to determine and record deferred tax assets, representing future tax benefits, and deferred tax liabilities, representing future taxes payable, resulting from the differences between the financial reporting amount and the corresponding tax basis of the assets and liabilities using the enacted rates expected to be in effect at the time the differences are settled. An offsetting valuation allowance is recorded when it is more likely than not that some or all of the deferred income tax assets won’t be realized. Any significant changes to the estimates and judgments with respect to the interpretations, timing or deductibility could result in a material change to earnings and cash flows. For a more detailed description of Income Taxes see Note 12. Income Taxes in the accompanying Consolidated Financial Statements.

For state income tax and other taxes, estimates and judgments are required with respect to the apportionment among the various jurisdictions. In addition, we operate within multiple tax jurisdictions and are subject to audits in these jurisdictions. These audits can involve complex issues, which may require an extended period of time to resolve. We maintain a liability for the estimate of potential income tax exposure and, in our opinion, adequate provisions for income taxes have been made for all years reported. Any significant changes to the estimates and judgments with respect to the apportionment factor could result in a material change to earnings and cash flows.

Occasionally, the federal and state taxing authorities determine that it is necessary to make certain changes to the income tax laws. These changes may include but are not limited to changes in the tax rates and/or the treatment of certain items of income or expense. Accounting guidance requires that the Company reflect the effect of tax laws or tax rates at the date of enactment. Additionally, the Company is required to re-measure its deferred tax assets and liabilities as of the date of enactment. For non-regulated entities, the effect of changes in tax rates and/or tax laws are required to be included in income from continuing operations for the period that includes the enactment date. For regulated entities, if as the result of an action by a regulator it is probable that the future increase or decrease in taxes payable for items such as changes in tax law or rates will be recovered from or returned to customers through future rates, an asset or liability shall be recognized for that probable increase or decrease in future revenue. Additionally, accounting guidance also requires that regulatory liabilities/assets be considered a temporary difference for which a deferred tax asset/liability shall be recognized. As a result, NJNG grossed up its regulatory liability to reflect the required accounting for the tax effects of the revaluation.

Concurrent with the enactment of the current tax reform legislation, the SEC issued Staff Accounting Bulletin No. 118, which lays out an approach that a registrant may follow to comply with the enactment period accounting requirements. Accordingly, registrants can have up to 12 months from the enactment date to complete the accounting for some or all of the income tax effects triggered by the enactment of the new law. Registrants need to determine and use “reasonable estimates” for some or all of the expected effects beginning with the one-year measurement period. The accounting must be finalized no later than 12 months from the enactment date. If reasonable estimates cannot be determined, the accounting should continue to be based on the old law until reasonable estimates can be determined in a subsequent period. As of September 30, 2018, our accounting for the income tax effects of the Tax Act is considered complete.

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New Jersey Resources Corporation

Part II

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Accounting guidance requires that we establish reserves for uncertain tax positions when it is more likely than not that the positions will not be sustained when challenged by taxing authorities. We have no reason to believe that we have any future obligations associated with unrecognized tax benefits; therefore, as of September 30, 2018 and 2017, we have not recorded any liabilities related to uncertain tax positions. Any significant changes to the estimates and judgments with respect to the interpretations, timing or deductibility could result in a material change to earnings and cash flows.

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. For our unregulated subsidiaries, we recognize ITCs as a reduction to income tax expense when the property is placed in service.

Changes to the federal statutes related to ITCs, which have the effect of reducing or eliminating the credits, could have a negative impact on earnings and cash flows.

Environmental Costs

At the end of each fiscal year, NJNG, with the assistance of an independent consulting firm, updates the environmental review of its MGP sites, including its potential liability for investigation and remedial action. From this review, NJNG estimates expenditures necessary to remediate and monitor these MGP sites. NJNG’s estimate of these liabilities is developed from then-currently available facts, existing technology and current laws and regulations.

In accordance with accounting standards for contingencies, NJNG’s policy is to record a liability when it is probable that the cost will be incurred and can be reasonably estimated. NJNG will determine a range of liabilities and will record the most likely amount. If no point within the range is more likely than any other, NJNG will accrue the lower end of the range. Since we believe that recovery of these expenditures, as well as related litigation costs, is possible through the regulatory process, we have recorded a regulatory asset corresponding to the related accrued liability. Accordingly, NJNG recorded an MGP remediation liability and a corresponding regulatory asset on the Consolidated Balance Sheets, which is 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 and the ultimate ability of other responsible parties to pay, as well as the potential impact of any litigation and any insurance recoveries. Previously incurred remediation costs, net of recoveries from customers and insurance proceeds received are included in regulatory assets on the Consolidated Balance Sheets.

If there are changes in the regulatory position surrounding these costs, or should actual expenditures vary significantly from estimates in that these costs are disallowed for recovery by the BPU, such costs would be charged to income in the period of such determination. See the Legal Proceedings section in Note 13. Commitments and Contingent Liabilities for more details.

Postemployment Employee Benefits

Our costs of providing postemployment employee benefits are dependent upon numerous factors, including actual plan experience and assumptions of future experience. Postemployment employee benefit costs are impacted by actual employee demographics including age, compensation levels and employment periods, the level of contributions made to the plans, changes in long-term interest rates and the return on plan assets. Changes made to the provisions of the plans or healthcare legislation may also impact current and future postemployment employee benefit costs. Postemployment employee benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, changes in mortality tables, health care cost trends and discount rates used in determining the PBO. In determining the PBO and cost amounts, assumptions can change from period to period and could result in material changes to net postemployment employee benefit periodic costs and the related liability recognized by us.

Our postemployment employee benefit plan assets consist primarily of U.S. equity securities, international equity securities and fixed-income investments, with a targeted allocation of 34 percent, 17 percent and 41 percent, respectively. Fluctuations in actual market returns, as well as changes in interest rates, may result in increased or decreased postemployment employee benefit costs in future periods. Postemployment employee benefit expenses are included in O&M expense on the Consolidated Statements of Operations.

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New Jersey Resources Corporation

Part II

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

The following is a summary of a sensitivity analysis for each actuarial assumption:

Pension Plans
Actuarial Assumptions	Increase/ (Decrease)			Estimated Increase/(Decrease) on PBO (Thousands)				Estimated Increase/(Decrease) to Expense (Thousands)
Discount rate	1.00		%		$	(37,153	)		$	(4,095	)
Discount rate	(1.00	)	%		$	46,432			$	4,756
Rate of return on plan assets	1.00		%		n/a				$	(2,619	)
Rate of return on plan assets	(1.00	)	%		n/a				$	2,619

Other Postemployment Benefits
Actuarial Assumptions	Increase/ (Decrease)			Estimated Increase/(Decrease) on PBO (Thousands)				Estimated Increase/(Decrease) to Expense (Thousands)
Discount rate	1.00		%		$	(28,595	)		$	(2,728	)
Discount rate	(1.00	)	%		$	36,736			$	3,406
Rate of return on plan assets	1.00		%		n/a				$	(713	)
Rate of return on plan assets	(1.00	)	%		n/a				$	714
Actuarial Assumptions	Increase/ (Decrease)			Estimated Increase/(Decrease) on PBO (Thousands)				Estimated Increase/(Decrease) to Expense (Thousands)
Health care cost trend rate	1.00		%		$	36,260			$	3,838
Health care cost trend rate	(1.00	)	%		$	(28,743	)		$	(2,991	)

On October 1, 2016, we changed our approach used to measure the service and interest cost components of our net periodic benefit costs. Previously, we estimated service cost and interest cost based on a single weighted-average discount rate from the yield curve used to measure our projected benefit obligation. We determine our service and interest cost based upon duration-specific spot rates that are aligned to each year’s future benefit payments. Under the new approach, net periodic benefit costs will be lower during periods of low interest rates and upward-sloping yield curves. Conversely, in a downward-sloping yield curve environment, costs could increase. Refer to Note 10. Employee Benefit Plans in the accompanying Consolidated Financial Statements for further discussion of our change in method.

Recently Issued Accounting Standards

Refer to Note 2. Summary of Significant Accounting Policies in the accompanying Consolidated Financial Statements for discussion of recently issued accounting standards.

Management’s Overview

Consolidated

NJR is an energy services holding company providing retail natural gas service in New Jersey and wholesale natural gas and related energy services to customers in the United States and Canada. In addition, we invest in clean energy projects and midstream assets and provide various repair, sales and installations services. A more detailed description of our organizational structure can be found in Item 1. Business.

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New Jersey Resources Corporation

Part II

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Reporting Segments

We have four primary reporting segments as presented in the chart below:

In addition to our four reporting segments, we have non-utility operations that either provide corporate support services or do not meet the criteria to be treated as a separate reporting segment. These operations, which comprise Home Services and Other, include: appliance repair services, sales and installations at NJRHS and commercial real estate holdings at CR&R.

The Tax Act

On December 22, 2017, the Tax Act was signed into law, which resulted in a reduction in the federal corporate tax rate. Since our fiscal year end is September 30, it is required by the Internal Revenue Code to calculate a statutory rate based upon the federal tax rates in effect before and after the effective date of the change in the taxable year that includes the effective date. Accordingly, we applied a federal statutory tax rate of 24.5 percent during fiscal 2018 and the enacted rate of 21 percent beginning in fiscal 2019.

As a result of the Tax Act, we revalued our deferred tax assets and liabilities at the enactment date to reflect the rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. As of September 30, 2018, NJNG had a regulatory liability that included excess deferred income taxes of $205.4 million, which requires amortization over the remaining life of the utility plant consistent with IRS normalization principles. During fiscal 2018, we recognized an income tax benefit of approximately $17 million for NJNG and approximately $59.6 million for the remaining entities on the Consolidated Statements of Operations. See Note 12. Income Taxes for a more detailed discussion on the Tax Act.

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New Jersey Resources Corporation

Part II

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

A summary of our consolidated results in net income and assets by reporting segment and operations for the fiscal years ended September 30, is as follows:

(Thousands)	2018						2017					2016
	Net Income			Assets			Net Income		Assets			Net Income		Assets
Natural Gas Distribution	$	84,048		$	2,663,054		$	86,930	$	2,519,578		$	76,104	$	2,517,401
Clean Energy Ventures	75,849			865,018			24,873		771,340			28,393		665,696
Energy Services	53,139			396,852			476		398,277			14,265		327,626
Midstream	24,367			242,069			12,857		232,806			9,406		186,259
Home Services and Other	(3,555		)	114,732			6,811		114,801			2,882		109,487
Intercompany(1)	(412		)	(138,061		)	118		(108,295		)	622		(87,899		)
Total	$	233,436		$	4,143,664		$	132,065	$	3,928,507		$	131,672	$	3,718,570

(1) Consists of transactions between subsidiaries that are eliminated in consolidation.

Net Income

The primary drivers of the changes noted above, which are described in more detail in the individual segment discussions, are discussed below.

The increase in net income of $101.4 million during fiscal 2018, compared with fiscal 2017, was primarily driven by increased operating income at Energy Services related to colder weather, resulting in increased storage withdrawals due to higher demand coupled with higher volatility resulting in an increase in natural gas price spreads. Net income also increased due to impacts from the Tax Act, including a net income tax benefit of $59.6 million and a decrease in tax expense due to the lower tax rate, which was partially offset by increased O&M expense.

The increase in net income of $393,000 during fiscal 2017, compared with fiscal 2016, was primarily driven by increased margin at our Natural Gas Distribution segment due primarily to increased base rates which were effective October 1, 2016, increased other income at Home Services and Other due to the sale of available for sale securities, increased equity in earnings of affiliates at Midstream and increased revenues and PTCs at Clean Energy Ventures. These increases were partially offset by decreased operating income at Energy Services due primarily to a decrease of $16.4 million related to changes in the value of financial hedges and a decrease at Clean Energy Ventures due primarily to increased depreciation, operating and interest expenses.

Assets

The increase in assets during fiscal 2018, compared with fiscal 2017, was due primarily to additional utility plant at our Natural Gas Distribution segment and an advance payment of $10 million for the IEC acquisition, partially offset by a decrease in regulatory assets at our Natural Gas Distribution segment, as well as a decrease in the market value of the DM Common Units at Midstream.

The increase in assets during fiscal 2017, compared with fiscal 2016, was due primarily to additional solar expenditures at Clean Energy Ventures, the acquisition of Talen's wholesale and retail energy contract assets at Energy Services, increased PennEast capital contributions and an increase in the market value of our DM Common Units at Midstream, along with additional utility plant expenditures at our Natural Gas Distribution segment.

Non-GAAP Financial Measures

Our management uses NFE, a non-GAAP financial measure, when evaluating our operating results. Energy Services economically hedges its natural gas inventory with financial derivative instruments and calculates the related tax effect based on the statutory rate. NFE is a measure of the earnings based on eliminating timing differences surrounding the recognition of certain gains or losses, to effectively match the earnings effects of the economic hedges with the physical sale of gas and, therefore, eliminates the impact of volatility to GAAP earnings associated with the derivative instruments. To the extent we utilize forwards or futures to hedge forecasted SREC production, unrealized gains and losses are also eliminated for NFE purposes.

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Part II

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for or a replacement of, the comparable GAAP measure and should be read in conjunction with those GAAP results. The following is a reconciliation of consolidated net income, the most directly comparable GAAP measure, to NFE for the fiscal years ended September 30:

(Thousands, except per share data)	2018			2017			2016
Net income	$	233,436		$	132,065		$	131,672
Add:
Unrealized loss (gain) on derivative instruments and related transactions	26,770			(11,241		)	46,883
Tax effect	(4,512		)	4,062			(17,018		)
Effects of economic hedging related to natural gas inventory (1)	(22,570		)	38,470			(36,816		)
Tax effect	7,362			(13,964		)	13,364
Net financial earnings	$	240,486		$	149,392		$	138,085
Basic earnings per share	$	2.66		$	1.53		$	1.53
Add:
Unrealized loss (gain) on derivative instruments and related transactions	0.31			(0.13		)	0.55
Tax effect	(0.05		)	0.05			(0.20		)
Effects of economic hedging related to natural gas inventory (1)	(0.26		)	0.45			(0.43		)
Tax effect	0.08			(0.17		)	0.16
Basic net financial earnings per share	$	2.74		$	1.73		$	1.61

(1) Effects of hedging natural gas inventory transactions where the economic impact is realized in a future period.

NFE by reporting segment and other operations for the fiscal years ended September 30, discussed in more detail within the operating results sections of each segment, is summarized as follows:

(Thousands)	2018					2017					2016
Natural Gas Distribution	$	84,048		35	%	$	86,930		58	%	$	76,104		55	%
Clean Energy Ventures	75,849			32		24,873			17		28,393			20
Energy Services	60,378			25		18,554			12		21,934			16
Midstream	24,367			10		12,857			9		9,406			7
Home Services and Other	(3,829		)	(2	)	6,811			4		2,882			2
Eliminations (1)	(327		)	—		(633		)	—		(634		)	—
Total	$	240,486		100	%	$	149,392		100	%	$	138,085		100	%

(1) Consists of transactions between subsidiaries that are eliminated in consolidation.

The increase in NFE during fiscal 2018, compared with fiscal 2017, was driven primarily by higher financial margin generated at Energy Services due primarily to colder weather, resulting in increased storage withdrawals due to higher demand coupled with higher volatility, allowing Energy Services to capture additional margin from natural gas price spreads. The increase in NFE also included a net income tax benefit of $59.6 million associated with the Tax Act, as previously discussed.

The increase in NFE during fiscal 2017, compared with fiscal 2016, was driven primarily by increases at our Natural Gas Distribution segment, Midstream and Home Services and Other, as previously discussed, partially offset by lower financial margin at Energy Services due primarily to lower sales volumes and fewer market opportunities and the decrease at Clean Energy Ventures, as previously discussed.

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OPERATIONS (Continued)

Natural Gas Distribution Segment

Overview

Our Natural Gas Distribution segment is comprised of NJNG, a natural gas utility that provides regulated retail natural gas service in central and northern New Jersey to approximately 538,700 residential and commercial customers in its service territory and also participates in the off-system sales and capacity release markets. The business is subject to various risks, which can negatively impact customer growth, operating and financing costs, fluctuations in commodity prices and customer conservation efforts. These risks include, but are not limited to, adverse economic conditions, customer usage, certain regulatory actions, environmental remediation and severe weather conditions. It is often difficult to predict the impact of events or trends associated with these risks.

In addition, NJNG’s business is seasonal by nature, as weather conditions directly influence the volume of natural gas delivered to customers on an annual basis. Specifically, customer demand substantially increases during the winter months when natural gas is used for heating purposes. As a result, NJNG receives most of its natural gas distribution revenues during the first and second fiscal quarters and is subject to variations in earnings and working capital during the year.

As a regulated company, NJNG is required to recognize the impact of regulatory decisions on its financial statements. See Note 3. Regulation in the accompanying Consolidated Financial Statements for a more detailed discussion on regulatory actions, including filings related to programs and associated expenditures, as well as rate requests related to recovery of capital investments and operating costs.

NJNG’s operations are managed with the goal of providing safe and reliable service, growing its customer base, diversifying its margin, promoting clean energy programs and mitigating the risks discussed above through several key initiatives, including:

• earning a reasonable rate of return on the investments in its natural gas distribution and transmission businesses, as well as timely recovery of all prudently incurred costs to provide safe and reliable service throughout NJNG’s territory;

• continuing to invest in the safety and integrity of its infrastructure;

• managing its customer growth rate, which NJNG expects will be approximately 1.8 percent annually through fiscal 2021;

• maintaining a collaborative relationship with the BPU on regulatory initiatives, including:

-    planning and authorization of infrastructure investments;

-    pursuing rate and regulatory strategies to stabilize and decouple margin, including CIP;

-    utilizing BGSS incentive programs through BPU-approved mechanisms to reduce gas costs and generate margin; and

-    administering and promoting NJNG’s BPU-approved SAVEGREEN Project;

• managing the volatility of wholesale natural gas prices through a hedging program designed to keep customers’ BGSS rates as stable as possible; and

• working with the NJDEP and BPU to manage its financial obligations related to remediation activities associated with its former MGP sites.

Base Rate Case

In September 2016, the BPU approved NJNG's base rate case, effective October 2016, which included an increase in base rates in the amount of $45 million. The base rate increase includes a return on common equity of 9.75 percent, a common equity ratio of 52.5 percent and a depreciation rate of 2.4 percent. The approval also included the rate mechanism and five-year extension of SAFE II, rate recovery of NJ RISE capital investment costs through June 30, 2016, recovery of NJNG’s SAFE I, Natural Gas Vehicle Refueling Stations and LNG capital investments and recovery of other costs previously deferred in regulatory assets.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Infrastructure projects

NJNG has significant annual capital expenditures associated with the management of its natural gas distribution and transmission system, including new utility plant associated with customer growth and its associated PIM and infrastructure programs.

Below is a summary of NJNG’s capital expenditures, including accruals and estimates for expected investments over the next two fiscal years:

Estimated capital expenditures are reviewed on a regular basis and may vary based on the ongoing effects of regulatory oversight, environmental regulations, unforeseen events and the ability to access capital.

SAFE and NJ RISE

NJNG continues to implement BPU-approved infrastructure projects that are designed to enhance the reliability and integrity of NJNG’s gas distribution system.

The BPU approved recovery of SAFE I capital investments through September 30, 2016, and approved the rate mechanism and extension of SAFE II for an additional five years to replace the remaining unprotected steel mains and services from NJNG’s natural gas distribution system at an estimated cost of approximately $200 million, excluding AFUDC. The accelerated cost recovery methodology for the $157.5 million associated with the extension of SAFE II was approved in NJNG’s new base rates. The remaining $42.5 million in capital expenditures will be requested for recovery in future base rate cases.

The BPU approved NJNG’s NJ RISE capital infrastructure program, which consists of six capital investment projects estimated to cost $102.5 million, excluding AFUDC, for gas distribution storm hardening and mitigation projects, along with associated depreciation expense. These system enhancements are intended to minimize service impacts during extreme weather events to customers in the most storm-prone areas of NJNG’s service territory. Recovery of NJ RISE investments is included in NJNG’s base rates.

In July 2017, the BPU approved NJNG’s annual petition requesting a $4.1 million increase in recoveries of NJ RISE and SAFE II capital investment costs, with a weighted cost of capital of 6.9 percent including a return on equity of 9.75 percent, related to the period ending June 30, 2017, effective October 2017.

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OPERATIONS (Continued)

On September 17, 2018, the BPU approved NJNG’s annual petition requesting a base rate increase of $6.8 million for the recovery of SAFE II and NJ RISE capital investment costs, with a weighted cost of capital of 6.9 percent including a return on equity of 9.75 percent, related to the 12-months ended June 30, 2018, effective October 1, 2018.

Natural Gas Vehicle Refueling Stations

NJNG has three natural gas vehicle refueling stations open to the public. Costs for these stations were approximately $10 million and are being recovered through NJNG’s base rates, effective October 2016.

Liquefaction/LNG

NJNG’s Liquefaction facility allows NJNG to convert natural gas into LNG to fill its existing LNG storage tanks. Costs for this facility along with other plant upgrades were approximately $36.5 million and are being recovered through NJNG’s base rates effective October 2016.

Southern Reliability Link

The SRL is an approximately 30-mile, 30-inch transmission main designed to support improved system reliability and integrity in the southern portion of NJNG’s service territory, estimated to cost between $180 million and $215 million. In January 2016, the BPU issued an order approving NJNG’s modified, proposed SRL pipeline installation, operation and route selection. In March 2016, the BPU issued an order designating the SRL route and exempting the SRL from municipal land use ordinances, regulations, permits and license requirements. In February 2017, the New Jersey Department of Environmental Protection issued a permit authorizing construction of the SRL within the jurisdiction of the Coastal Area Facility Review Act, as well as a Freshwater Wetlands permit. In September 2017, the NJ Pinelands Commission approved construction of the SRL as being compliant with the Commission’s Comprehensive Management Plan. All approvals issued by state agencies are under appeal and certain road-opening permits and easements are in the process of being secured. Construction is expected to begin in fiscal 2019, with an estimated in-service date in 2019.

Customer growth

In conducting NJNG’s business, management focuses on factors it believes may have significant influence on its future financial results. NJNG’s policy is to work with all stakeholders, including customers, regulators and policymakers, to achieve favorable results. These factors include the rate of NJNG’s customer growth in its service territory, which can be influenced by political and regulatory policies, the delivered cost of natural gas compared with competing fuels, interest rates and general economic and business conditions.

NJNG’s total customers as of September 30, include the following:

	2018	2017	2016
Firm customers
Residential	474,495	460,013	448,273
Commercial, industrial & other	28,037	26,947	26,218
Residential transport	26,490	32,653	36,292
Commercial transport	9,636	10,137	10,316
Total firm customers	538,658	529,750	521,099
Other	59	60	64
Total customers	538,717	529,810	521,163

During fiscal 2018, NJNG added 9,596 new customers, which represents a new customer growth rate of approximately 1.8 percent. During that same time period, NJNG converted 613 existing customers to natural gas heat and other services. This customer growth, as well as commercial customers who switched from interruptible to firm natural gas service, will contribute approximately $5.5 million, on an annualized basis, to utility gross margin. NJNG also added 9,126 and 8,170 new customers and converted 662 and 644 existing customers to natural gas heat and other services during the fiscal years ended September 30, 2017 and 2016, respectively.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

In addition, NJNG currently expects to add approximately 28,000 to 30,000 new customers during the three-year period of fiscal 2019 to 2021. NJNG’s estimates are based on information from municipalities and developers, as well as external industry analysts and management’s experience. NJNG estimates that approximately 68 percent of the growth will come from new construction markets and 32 percent from customer conversions to natural gas from other fuel sources. This new customer and conversion growth would increase utility gross margin under NJNG’s base rates by approximately $5.5 million annually, as calculated under NJNG’s CIP tariff. See the Natural Gas Distribution Segment Operating Results section that follows for a definition and further discussion of utility gross margin.

Energy Efficiency Programs

SAVEGREEN conducts home energy audits and provides various grants, incentives and financing alternatives, which are designed to encourage the installation of high-efficiency heating and cooling equipment and other energy efficiency upgrades. Depending on the specific incentive or approval, NJNG recovers costs associated with the programs over a two- to 10-year period through a tariff rider mechanism. In June 2016, the BPU approved NJNG’s extension of SAVEGREEN through December 31, 2018. On September 17, 2018, the BPU approved the continuation of existing SAVEGREEN programs and the addition of new programs with investments of $135 million through December 2021.

On October 20, 2017, the BPU approved NJNG’s filing to decrease its EE recovery rate, which resulted in an annual decrease of $3.9 million, effective November 1, 2017. On May 25, 2018, NJNG filed a petition with the BPU to decrease its EE recovery rate. On October 16, 2018, NJNG updated this information through September 30, 2018, which will result in an annual decrease of $8.8 million, anticipated to be effective January 1, 2019.

Since inception, $162 million in grants, rebates and loans have been provided to customers, with a total annual recovery of approximately $16.1 million. The recovery includes a weighted average cost of capital that ranges from 6.69 percent to 7.76 percent, with a return on equity of 9.75 percent to 10.3 percent.

Conservation Incentive Program

The CIP facilitates normalizing NJNG’s utility gross margin for variances not only due to weather but also for other factors affecting customer usage, such as conservation and energy efficiency. Recovery of utility gross margin for the non-weather variance through the CIP is limited to the amount of certain gas supply cost savings achieved and is subject to a variable margin review test. Additionally, recovery of the CIP utility gross margin is subject to an annual earnings test. An annual review of the CIP must be filed by June 1, coincident with NJNG’s annual BGSS filing, during which NJNG can request rate changes to the CIP. In May 2014, the BPU approved the continuation of the CIP program with no expiration date. Refer to Note 3. Regulation - BGSS and CIP in the accompanying Consolidated Financial Statements, for a discussion of CIP rate actions.

NJNG’s total utility firm gross margin includes the following adjustments related to the CIP mechanism:

(Thousands)	2018			2017			2016
Weather (1)	$	205		$	19,261		$	27,547
Usage	(1,629		)	(2,309		)	10,420
Total	$	(1,424	)	$	16,952		$	37,967

(1) Compared with the CIP 20-year average, weather was 0.5 percent, 10 percent and 17.5 percentwarmer-than-normal during fiscal 2018, 2017 and 2016, respectively.

Commodity prices

Our Natural Gas Distribution segment is affected by the price of natural gas, which can have a significant impact on our cash flows, short-term financing costs, the price of natural gas charged to our customers through the BGSS clause, our ability to collect accounts receivable, which impacts our bad debt expense, and our ability to maintain a competitive advantage over other fuel sources.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Natural gas commodity prices may experience high volatility as shown in the graph below, which illustrates the daily natural gas prices⁽¹⁾ in the Northeast market region, also known as Tetco M-3.

(1) Midpoint daily gas price sourced from Platts, a division of McGraw Hill Financial.

The maximum price per MMBtu was $94.93, $8.71 and $4.74 and the minimum price was $0.53, $0.36 and $0.67 for the fiscal years ended September 30, 2018, 2017 and 2016, respectively. A more detailed discussion of the impacts of the price of natural gas on operating revenues, gas purchases and cash flows can be found in the Results of Operations and Cash Flow sections of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

BGSS

Recovery of natural gas costs

NJNG’s cost of natural gas is passed through to our customers, without markup, by applying NJNG’s authorized BGSS rate to actual therms delivered. There is no utility gross margin associated with BGSS costs; therefore, changes in such costs do not impact NJNG’s earnings. NJNG monitors its actual gas costs in comparison to its BGSS rates to manage its cash flows associated with its allowed recovery of natural gas costs, which is facilitated through BPU-approved deferred accounting and the BGSS pricing mechanism. Accordingly, NJNG occasionally adjusts its periodic BGSS rates or can issue credits or refunds, as appropriate, for its residential and small commercial customers when the commodity cost varies from the existing BGSS rate. BGSS rates for its large commercial customers are adjusted monthly based on NYMEX prices.

On March 26, 2018, the BPU approved maintaining NJNG's BGSS rate for residential and small commercial customers and an increase to its balancing charge rate, which resulted in a $3.7 million increase to the annual revenues credited to BGSS, effective October 2017. The balancing charge rate includes the cost of balancing natural gas deliveries with customer usage for sales and transportation customers and balancing charge revenues are credited to BGSS. During fiscal 2017, NJNG issued bill credits of $42 million as a result of a decline in the wholesale price of natural gas. There were no bill credits issued during fiscal 2018, related to BGSS prices.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

On September 17, 2018, the BPU provisionally approved NJNG’s annual petition to maintain its BGSS rate for residential and small commercial customers and increase its balancing charge rate, resulting in a $10.3 million increase to the annual revenues credited to BGSS, as well changes to the CIP rates, which will result in a $30.9 million annual recovery decrease, effective October 1, 2018. Refer to Note 3. Regulation - BGSS and CIP in the accompanying Consolidated Financial Statements for a further discussion of NJNG’s periodic BGSS rate adjustments and bill credits.

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. These programs are designed to encourage better utilization and hedging of NJNG’s natural gas supply, transportation and storage assets. Depending on the program, NJNG shares 80 or 85 percent of utility gross margin generated by these programs with firm customers. Should performance of the existing incentives or market conditions warrant, NJNG is permitted to propose a process to re-evaluate and discuss alternative incentive programs annually. Utility gross margin from incentive programs was $12.5 million, $13.7 million and $15 million during the fiscal years ended September 30, 2018, 2017 and 2016, respectively. A more detailed discussion of the impacts to utility gross margin can be found in the Natural Gas Distribution Segment Operating Results section that follows.

Hedging

In order to provide relative price stability to its natural gas supply portfolio, NJNG employs a hedging strategy with the goal of having at least 75 percent of its projected winter periodic BGSS gas sales volumes hedged by each November 1 and at least 25 percent of the projected BGSS gas sales hedged for the following April-through-March period. This is accomplished with the use of various financial instruments including futures, swaps and options used in conjunction with commodity and/or weather-related hedging activity.

Due to the capital-intensive nature of NJNG’s operations and the seasonal nature of its working capital requirements, significant changes in interest rates can impact NJNG’s results. In June 2015, NJNG entered into a transaction to fix a benchmark treasury rate of 3.26 percent associated with a $125 million debt issuance that was finalized in May 2018. The debt issuance coincided with the maturity of NJNG's $125 million, 5.6 percent notes that came due on May 15, 2018. This treasury lock was settled on March 13, 2018, which coincided with the pricing of the new debt being issued. Settlement of the interest rate contract resulted in a $2.6 million loss, which is recorded as a component of regulatory assets on the Consolidated Balance Sheets and will be amortized to earnings over the 30-year term of the $125 million note issued on May 11, 2018.

A more detailed discussion of NJNG’s debt can be found in the Liquidity and Capital Resources and Cash Flow sections of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Societal Benefits Charge

USF

NJNG’s qualifying customers are eligible for the USF program, which is administered by the New Jersey Department of Community Affairs, to help make energy bills more affordable. On September 17, 2018, the BPU approved NJNG’s annual USF compliance filing to increase the statewide USF rate, which will result in a $1 million annual increase, effective October 1, 2018. Refer to Note 3. Regulation - Societal Benefits Clause in the accompanying Consolidated Financial Statements for a further discussion of NJNG’s USF rates.

Environmental Remediation

NJNG is responsible for the environmental remediation of five MGP sites, which contain contaminated residues from former gas manufacturing operations that ceased operating at these sites by the mid-1950s and, in some cases, had been discontinued many years earlier. Actual MGP remediation costs may vary from management’s estimates due to the developing nature of remediation requirements, regulatory decisions by the NJDEP and related litigation. NJNG reviews these costs at the end of each fiscal year and adjusts its liability and corresponding regulatory asset as necessary to reflect its expected future remediation obligation. Accordingly, NJNG recognized a regulatory asset and an obligation of $130.8 million as of September 30, 2018, a decrease of $18.2 million, compared with the prior fiscal period.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Other

In May 2016, NJNG included a proposal in its base rate case to recover certain capital costs and incremental operation and maintenance costs related to a March 2016 BPU Order regarding new cybersecurity requirements. This proposal was updated in July 2016, and the associated costs were approved for recovery through NJNG’s new base rates, effective October 2016.

Interest Rate Risk

Due to the capital-intensive nature of NJNG’s operations and the seasonal nature of its working capital requirements, significant changes in interest rates can impact NJNG’s results. A more detailed discussion can be found in the Liquidity and Capital Resources and Cash Flow sections of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Other regulatory filings and a more detailed discussion of the filings in this section can be found in Note 3. Regulation in the accompanying Consolidated Financial Statements.

Commodity Service to Customers

The EDECA, which was enacted in 1999, provides the framework for New Jersey’s retail energy markets, which are open to competition from other electric and natural gas suppliers. NJNG’s residential and commercial markets are currently open to competition, and its rates are segregated between BGSS (i.e., natural gas commodity) and delivery (i.e., transportation) components. 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 and, therefore, is not negatively affected by customers who use its transportation service and purchase natural gas from another supplier. Under an existing order from the BPU, BGSS can be provided by suppliers other than the state’s natural gas utilities; however, customers who purchase natural gas from another supplier continue to use NJNG for transportation service.

Operating Results

NJNG’s operating results for the fiscal years ended September 30, are as follows:

(Thousands)	2018			2017		2016
Operating revenues	$	731,865		$	695,637	$	594,346
Operating expenses
Gas purchases (1) (2)	333,208			269,480		215,849
Operation and maintenance	161,723			142,509		130,575
Regulatory rider expense (3)	38,969			40,243		39,300
Depreciation and amortization	53,208			49,347		47,828
Energy and other taxes (4)	44,184			42,417		34,561
Total operating expenses	631,292			543,996		468,113
Operating income	100,573			151,641		126,233
Other income, net	6,864			4,592		4,752
Interest expense, net of capitalized interest	25,299			25,818		19,930
Income tax (benefit) provision	(1,910		)	43,485		34,951
Net income	$	84,048		$	86,930	$	76,104

(1) Includes the purchased cost of the natural gas, fees paid to pipelines and storage facilities, adjustments as a result of BGSS incentive programs and hedging transactions. These expenses are passed through to customers and are offset by corresponding revenues.

(2) Includes related party transactions of approximately $57.2 million, $10.8 million and $10.8 million during fiscal 2018, 2017 and 2016, respectively, a portion of which are eliminated in consolidation.

(3) Consists of expenses associated with state-mandated programs, the RAC and energy efficiency programs, and are calculated on a per-therm basis. These expenses are passed through to customers and offset by corresponding revenues.

(4) Consists primarily of sales tax, which is passed through to customers and offset by corresponding revenues.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Operating Revenues and Gas Purchases

Operating revenues increased5.2 percent during fiscal 2018 and increased17 percent during fiscal 2017. Gas purchases increased23.6 percent during fiscal 2018 and increased24.8 percent during fiscal 2017. The factors contributing to the increases (decreases) in operating revenues and gas purchases during fiscal 2018 and 2017, are as follows:

	2018 v. 2017					2017 v. 2016
(Thousands)	Operating revenue			Gas purchases		Operating revenue			Gas purchases
Firm sales	$	49,414		$	19,779	$	44,397		$	21,634
Bill credits (1)	41,971			39,260		19,588			18,265
Average BGSS rates (2)	1,147			1,413		(17,874		)	(16,544		)
Off-system sales	677			221		29,156			29,117
Tax Act impact	(35,910		)	—		—			—
CIP adjustments	(18,375		)	—		(21,015		)	—
Rate impact (3)	—			—		37,436			—
Other (4)	(2,696		)	3,055		9,603			1,159
Total increase	$	36,228		$	63,728	$	101,291		$	53,631

(1) Operating revenues include changes in sales tax of $2.7 million and $1.3 million during fiscal 2018 and 2017, respectively.

(2) Operating revenues include changes in sales tax of $266,000 and $1.4 million during fiscal 2018 and 2017, respectively.

(3) Includes rate adjustments for the base rate case, CIP and demand charges.

(4) Other includes changes for NJ RISE/SAFE II and rider rates, including those related to EE, NJCEP and other programs.

Fiscal 2018 compared with fiscal 2017

The changes in operating revenues and gas purchases during fiscal 2018 were due primarily to:

• increased firm sales due primarily to customer growth and higher usage related to weather being 9.9 percentcolder than fiscal 2017;

• bill credits issued to residential and small commercial customers during fiscal 2017 that did not occur in fiscal 2018; partially offset by

• the Tax Act impact, which is comprised of customer credits related to the initial revaluation of excess deferred income taxes and the overcollection of taxes from customers during the second quarter of fiscal 2018, including related interest and sales tax, as well as the effects from the reduction in base rates related to the Tax Act implemented during the third quarter;

• a decrease in CIP due primarily to normal weather during fiscal 2018, compared with warmer-than-normal weather during fiscal 2017; and

• higher off-system sales due primarily to an increase of 19.7 percent in the average price of natural gas sold, partially offset by a reduction in volumes of 15.9 percent.

Fiscal 2017 compared with fiscal 2016

The changes in operating revenues and gas purchases during fiscal 2017 were due primarily to:

• increased firm sales due primarily to customer growth and higher usage, related to weather being 6.8 percent colder;

• increased base rates resulting from the settlement of the base rate case;

• higher off-system sales due primarily to a 49.8 percent increase in the average price of natural gas sold, partially offset by a 12.2 percent reduction in volumes;

• a decrease in bill credits issued to residential and small commercial customers during the months of November 2016 through February 2017 compared with the same period in the prior year; partially offset by

• a decrease in CIP due primarily to weather, partially offset by changes in the CIP as a result of the settlement of the base rate case.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Non-GAAP Financial Measures

Management uses utility gross margin, a non-GAAP financial measure, when evaluating the operating results of NJNG. NJNG’s utility gross margin is defined as natural gas revenues less natural gas purchases, sales tax and regulatory rider expenses, and may not be comparable to the definition of gross margin used by others in the natural gas distribution business and other industries. Management believes that utility gross margin provides a meaningful basis for evaluating utility operations since natural gas costs, sales tax and regulatory rider expenses are included in operating revenue and passed through to customers and, therefore, have no effect on utility gross margin. Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measure.

Utility Gross Margin

A reconciliation of operating revenues, the closest GAAP financial measure to NJNG’s utility gross margin, is as follows for the fiscal years ended September 30:

(Thousands)	2018		2017		2016
Operating revenues	$	731,865	$	695,637	$	594,346
Less:
Gas purchases	333,208		269,480		215,849
Energy taxes	39,426		37,917		29,832
Regulatory rider expense	38,969		40,243		39,300
Utility gross margin	$	320,262	$	347,997	$	309,365

Utility gross margin consists of three components:

• utility firm gross margin generated from only the delivery component of either a sales tariff or a transportation tariff from residential and commercial customers who receive natural gas service from NJNG;

• BGSS incentive programs, where revenues generated or savings achieved from BPU-approved off-system sales, capacity release or storage incentive programs are shared between customers and NJNG; and

• utility gross margin generated from off-tariff customers, as well as interruptible customers.

The following provides more information on the components of utility gross margin and associated throughput (Bcf) of natural gas delivered to customers:

	2018			2017			2016
($ in thousands)	Margin		Bcf	Margin		Bcf	Margin		Bcf
Utility gross margin/throughput
Residential	$	203,195	45.5	$	218,093	40.7	$	187,762	36.9
Commercial, industrial and other	46,636		8.9	51,510		8.7	46,878		7.3
Firm transportation	51,880		15.5	58,172		14.4	54,841		14.1
Total utility firm gross margin/throughput	301,711		69.9	327,775		63.8	289,481		58.3
BGSS incentive programs	12,482		150.2	13,724		178.4	14,978		216.7
Interruptible/off-tariff agreements	6,069		46.2	6,498		55	4,906		61.5
Total utility gross margin/throughput	$	320,262	266.3	$	347,997	297.2	$	309,365	336.5

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Utility Firm Gross Margin

A description of the factors contributing to the (decreases) increases in utility firm gross margin during fiscal 2018 and 2017, are as follows:

(Thousands)	2018 v. 2017				2017 v. 2016
Tax Act impact		$	(33,657	)		$	—
SAVEGREEN		(977		)		(345		)
NJ RISE/SAFE II		4,334				—
Customer growth		4,236				3,619
Rate impact		—				35,019
Total (decrease) increase		$	(26,064	)		$	38,293

BGSS Incentive Programs

A description of the factors contributing to the (decreases) increases in utility gross margin generated by NJNG’s BGSS incentive programs during fiscal 2018 and 2017, are as follows:

(Thousands)	2018 v. 2017				2017 v. 2016
Storage		$	(954	)		$	378
Capacity release		(745		)		(1,672		)
Off-system sales		457				39
Total decrease		$	(1,242	)		$	(1,255	)

Fiscal 2018 compared with fiscal 2017

The decrease in utility gross margin was due primarily to the Tax Act impact, as previously discussed, a decrease in value in the storage incentive program and a decrease in capacity release due to less volume and lower values, partially offset by increased margins for off-system sales.

Fiscal 2017 compared with fiscal 2016

The increase in utility gross margin was due primarily to the base rate increase and customer growth, along with an increase in interruptible/off-tariff agreements, partially offset by decreased margins related to capacity release due to lower volumes and lower value of capacity.

Operation and Maintenance Expense

A summary and description of the factors contributing to the increases (decreases) in O&M expense during fiscal 2018 and 2017, are as follows:

(Thousands)	2018 v. 2017			2017 v. 2016
Shared corporate costs		$	5,991		$	3,061
Compensation and benefits		5,767			5,412
Consulting		5,184			512
Other		2,272			2,949
Total increase		$	19,214		$	11,934

Fiscal 2018 compared with fiscal 2017

The increase in O&M expense during fiscal 2018 was due primarily to:

• increased shared corporate costs due primarily to increased headcount and incentives, along with additional expenses related to a voluntary early retirement program;

• increased compensation and benefits as a result of voluntary early retirement program costs; and

• increased consulting expenses due primarily to technology improvements.

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OPERATIONS (Continued)

Fiscal 2017 compared with fiscal 2016

The increase in O&M expense during fiscal 2017 was due primarily to:

• increased compensation costs due primarily to increases in headcount, incentives, healthcare premiums, lower capitalized labor and increased pension/OPEB benefit costs related to changes in actuarial assumptions, partially offset by implementation of the spot rate method to measure interest and service cost components;

• additional amortization of regulatory assets in other that are being recovered as a result of the settlement of the base rate case; and

• increased shared corporate costs resulting primarily from increased software maintenance, incentives, postemployment costs and healthcare premiums.

Depreciation Expense

Depreciation expense increased$3.9 million in fiscal 2018, compared with fiscal 2017, as a result of additional utility plant being placed into service. Depreciation expense increased$1.5 million in fiscal 2017, compared with fiscal 2016, as a result of additional utility plant being placed into service, as well as an increase in the overall depreciation rate from 2.34 percent to 2.4 percent resulting from the settlement of the base rate case.

Operating Income

Operating income decreased$51.1 million, or 33.7 percent, in fiscal 2018, compared with fiscal 2017, due primarily to the decrease in total utility gross margin of $27.7 million, as well as the increase in O&M and depreciation, as previously discussed. Operating income increased$25.4 million, or 20.1 percent, in fiscal 2017, compared with fiscal 2016, due primarily to theincrease in total utility gross margin of $38.6 million, partially offset by the increase in O&M, as previously discussed.

Income Tax Provision

Income tax provision decreased$45.4 million during fiscal 2018, compared with fiscal 2017, due primarily to the impacts of the change in the federal corporate tax rate resulting from the Tax Act. Income tax provision increased$8.5 million during fiscal 2017, compared with fiscal 2016, due primarily to an increase in pre-tax income, partially offset by increased costs associated with the removal of distribution main that was placed in service before 1981, for which the tax benefit is passed on to customers in base rates.

Net Income

Net income decreased$2.9 million to $84 million in fiscal 2018, compared with fiscal 2017, due primarily to decreased utility gross margin and increased O&M and depreciation, partially offset by the decrease in the income tax provision as previously discussed.

Net income increased$10.8 million to $86.9 million in fiscal 2017, compared with fiscal 2016, due primarily to an increase in operating income as discussed above, partially offset by an increase in the income tax provision as discussed above and interest expense associated with debt issued in June 2016.

Clean Energy Ventures Segment

Overview

Our Clean Energy Ventures segment actively pursues opportunities in the renewable energy markets. Clean Energy Ventures has entered into various agreements to install solar net-metered systems for residential and commercial customers, as well as large commercial grid-connected projects. In addition, Clean Energy Ventures has entered into various long-term agreements, including PPAs, to supply energy from wind and solar projects.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Solar

Solar projects placed in service and related expenditures for the fiscal years ended September 30, are as follows:

($ in Thousands)	2018				2017				2016
Placed in service	Projects	MW	Costs		Projects	MW	Costs		Projects	MW	Costs
Grid-connected (1)	3	33.7	$	70,216	2	20.0	$	62,700	5	21.8	$	51,240
Net-metered:
Commercial (1)	—	—	74		3	7.1	19,714		—	—	3
Residential	910	8.5	27,342		1,300	12.4	37,901		1,123	10.4	34,318
Total placed in service	913	42.2	$	97,632	1,305	39.5	$	120,315	1,128	32.2	$	85,561

(1) Includes projects subject to sale-leaseback arrangements.

Since its inception, Clean Energy Ventures has constructed a total of 231.3 MW of solar capacity and has an additional 19.6 MW under construction. Projects that are placed in service through December 31, 2019, qualify for a 30 percent federal ITC. The credit will decline to 26 percent for property under construction during 2020 and to 22 percent for property under construction during 2021. The ITC will be reduced to 10 percent for any property that is under construction before 2022, but not placed in service before 2024.

Clean Energy Ventures may enter into transactions to sell certain of its commercial solar assets concurrent with agreements to lease the assets back over a period of six to 15 years. The Company will continue to operate the solar assets and are responsible for related expenses and entitled to retain the revenue generated from SRECs and energy sales. The ITCs and other tax benefits associated with these solar projects have been transferred to the buyer; however, the lease payments are structured so that Clean Energy Ventures is compensated for the transfer of the related tax incentives. Accordingly, Clean Energy Ventures recognizes the equivalent value of the ITC 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. As of September 30, 2018, Clean Energy Ventures has entered into five sale-leaseback transactions, three during fiscal 2018 with costs of $70.2 million and two during fiscal 2017 with costs of $31.1 million. Clean Energy Ventures did not enter into sale-leasebacks during fiscal 2016.

Excluding the project costs related to the commercial solar projects that were included in the sale-leaseback transactions, the Company had $27.4 million, $89.2 million and $85.6 million of solar-related capital expenditures were ITC-eligible during fiscal 2018, 2017 and 2016, respectively, which were recognized in income tax (benefit) provision on the Consolidated Statements of Operations when the assets were placed in service.

As part of its solar investment portfolio, Clean Energy Ventures operates a residential solar program, The Sunlight Advantage®, which provides qualifying homeowners the opportunity to have a solar system installed at their home with no installation or maintenance expenses. Clean Energy Ventures owns, operates and maintains the system over the life of the contract in exchange for monthly lease payments.

Once a solar installation has received the proper certifications and commences operations, each MWh of electricity produced creates an SREC that represents the renewable energy attribute of the solar-electricity generated that can be sold to third parties, predominantly load-serving entities that are required to comply with the solar requirements under New Jersey’s renewable portfolio standard.

SREC activity for the fiscal years ended September 30, is as follows:

	2018		2017		2016
Inventory balance as of October 1,	48,357		24,135		33,203
SRECs generated	245,147		197,521		160,009
SRECs delivered	(188,312	)	(173,299	)	(169,077	)
Inventory balance as of September 30,	105,192		48,357		24,135

SRECs generated increased24.1 percent and 23.4 percent for the fiscal years ended September 30, 2018 and 2017, respectively, compared with the previous fiscal years. The average SREC sales price was $217 in fiscal 2018, $233 in fiscal 2017 and $214 in fiscal 2016.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Clean Energy Ventures hedges a portion of its expected SREC production through the use of forward sales contracts. The following table reflects the hedged percentage of SREC inventory and projected SREC production related to its in-service commercial and residential assets as of September 30, 2018:

Energy Year (1)	Percent of SRECs Hedged
2019	91%
2020	86%
2021	58%

(1) Energy years are compliance periods for New Jersey’s renewable portfolio standard that run from June 1 to May 31.

There are no direct costs associated with the production of SRECs by our solar assets. All related costs are included as a component of O&M expenses on the Consolidated Statements of Operations, including such expenses as facility maintenance and various fees.

Onshore Wind

Clean Energy Ventures has invested in small to mid-size onshore wind projects that fit its investment profile and has a total of 116.9 MW of wind capacity as of September 30, 2018. The wind projects are eligible for PTCs for a 10-year period following commencement of operations and have PPAs of various terms in place, which typically govern the sale of energy, capacity and/or renewable energy credits. Once a wind installation has commenced operations, each MWh of electricity produced creates an REC that represents the renewable energy attribute of the wind-electricity generated that can be sold to third parties. There are no direct costs associated with the production of RECs by our wind assets and all related costs are included as a component of O&M expenses on the Consolidated Statements of Operations.

On June 1, 2018, Clean Energy Ventures completed the sale of its membership interest in its 9.7 MW wind farm in Two Dot, Montana to NorthWestern Energy for a total purchase price of $18.5 million. The transaction generated a pre-tax gain of approximately $951,000, which is recognized as a reduction to O&M on the Consolidated Statements of Operations.

In March 2018, Clean Energy Ventures committed to a plan to sell its remaining wind assets, and it is probable that these sales will be completed within the next 12 months. Accordingly, we classified our wind assets and related liabilities as held for sale, as of March 31, 2018, on Consolidated Balance Sheets.

Operating Results

Clean Energy Ventures’ financial results for the fiscal years ended September 30, are summarized as follows:

(Thousands)	2018			2017			2016
Operating revenues	$	71,375		$	64,394		$	53,540
Operating expenses
Operation and maintenance	26,298			23,448			18,897
Depreciation and amortization	31,877			31,834			23,971
Other taxes	1,137			1,209			900
Total operating expenses	59,312			56,491			43,768
Operating income	12,063			7,903			9,772
Other income, net	2,174			2,072			2,333
Interest expense, net	18,320			16,263			10,304
Income tax benefit	(79,932		)	(31,161		)	(26,592		)
Net income	$	75,849		$	24,873		$	28,393

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Operating Revenues

Operating revenues increased $7 million in fiscal 2018, compared with fiscal 2017, due primarily to increased electricity sales from solar assets. Operating revenues increased$10.9 million in fiscal 2017, compared with fiscal 2016, due primarily to higher SREC sales and increased electricity sales from wind assets.

Operation and Maintenance Expense

O&M expense increased$2.9 million in fiscal 2018, compared with fiscal 2017, due primarily to increased consulting expenses and additional maintenance costs related to additional solar assets, partially offset by a pre-tax gain of $951,000 associated with the sale of the Two Dot wind farm. O&M expense increased$4.6 million in fiscal 2017, compared with fiscal 2016, due primarily to additional maintenance, leasing and administrative costs associated with wind and solar projects placed in service, as well as increased shared corporate costs.

Depreciation Expense

Depreciation expense remained relatively flat in fiscal 2018, compared with fiscal 2017, due primarily to increases in solar capital additions that were offset by depreciation expense on wind assets no longer being recorded resulting from their reclassification as held for sale in March 2018. Depreciation expense increased$7.9 million in fiscal 2017, compared with fiscal 2016, as a result of increases in wind and solar projects placed in service.

Income Tax Benefit

Income tax benefit increased$48.8 million during fiscal 2018, compared with fiscal 2017, due primarily to an income tax benefit of $61.4 millionassociated with the Tax Act, which was caused by a revaluation of the deferred tax liability related to the book versus tax differences in depreciation calculated on property-related items, partially offset by the decrease in ITCs recognized as a result of solar sale-leaseback financing activity.

Income tax benefit during fiscal 2018, 2017 and 2016 includes $10.5 million, $24.6 million and $25.7 million, respectively, of ITCs associated with solar projects, that were completed and placed into service during the corresponding fiscal year. Income tax benefit during fiscal 2018, 2017 and 2016 includes $10.8 million, $9.9 million and $6.7 million, respectively, of PTCs associated with wind projects. Clean Energy Ventures recognized $19 million, $29.2 million and $27 million related to tax credits, net of deferred taxes, during fiscal 2018, 2017 and 2016, respectively.

Net Income

Net income in fiscal 2018increased$51 million, compared with fiscal 2017, due primarily to the increased income tax benefit resulting from the impact of the Tax Act partially offset by a decreased income tax benefit related to ITCs, as previously discussed. Net income during fiscal 2017decreased$3.5 million, compared with fiscal 2016, due primarily to increased costs related to depreciation and O&M, as previously discussed, as well as an increase in interest expense related to higher debt associated with capital expenditures, partially offset by increases in operating revenues and tax benefits recognized due primarily to an increase in PTCs, as previously discussed.

Energy Services Segment

Overview

Energy Services markets and sells natural gas to wholesale and retail customers and manages natural gas storage and transportation assets throughout major market areas across North America. Energy Services maintains a strategic portfolio of natural gas storage and transportation contracts that it utilizes in conjunction with its market expertise to provide service and value to its customers. Availability of these storage and transportation contracts allows Energy Services to generate market opportunities by capturing price differentials over specific time horizons and between geographic market locations.

Energy Services also provides management of storage and transportation assets for natural gas producers and regulated utilities. These management transactions typically involve the release of producer/utility-owned storage and/or transportation capacity in combination with an obligation to purchase and/or deliver physical natural gas. In addition to the contractual purchase and/or sale of physical natural gas, Energy Services generates or pays fee-based margin in exchange for its active management and may provide the producer and/or utility with additional margin based on actual results.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

In conjunction with the active management of these contracts, Energy Services generates financial margin by identifying market opportunities and simultaneously entering into natural gas purchase/sale, storage or transportation contracts and financial derivative contracts. In cases where storage is utilized to fulfill these contracts, these forecast sales and/or purchases are economically hedged through the use of financial derivative contracts. The financial derivative contracts consist primarily of exchange-traded futures, options and swap contracts, and are frequently used to lock in anticipated transactional cash flows and to help manage volatility in natural gas market prices. Generally, when its storage and transportation contracts are exposed to periods of increased market volatility, Energy Services is able to implement strategies that allow it to capture margin by improving the respective time or geographic spreads on a forward basis.

In July 2017, Energy Services acquired certain retail and wholesale natural gas energy contract assets from Talen. The acquisition included sales agreements with large commercial and industrial retail customers in Delaware, Maryland, New Jersey and Pennsylvania, pipeline and storage capacity agreements on various pipelines and various wholesale transportation contracts.

On February 28, 2018, NJR sold all of the issued and outstanding shares of capital stock of NJRRS, which was a component of our Energy Services segment. We received $9.5 million in cash and a natural gas swap contract with a gain at inception of $14.6 million. The sale generated a pre-tax gain of $3.7 million, which was recognized as a reduction to O&M on the Consolidated Statements of Operations.

Energy Services accounts for its physical commodity contracts and its financial derivative instruments at fair value on the Consolidated Balance Sheets. Changes in the fair value of physical commodity contracts and financial derivative instruments are included in earnings as a component of operating revenue or gas purchases on the Consolidated Statements of Operations. Volatility in reported net income at Energy Services can occur over periods of time due to changes in the fair value of derivatives, as well as timing differences related to certain transactions. Unrealized gains and losses can fluctuate as a result of changes in the price of natural gas, SRECs and foreign currency from the original transaction price. Volatility in earnings can also occur as a result of timing differences between the settlement of financial derivatives and the sale of the underlying physical commodity. For example, when a financial instrument settles and the physical natural gas is injected into inventory, the realized gains and losses associated with the financial instrument are recognized in earnings. However, the gains and losses associated with the physical natural gas are not recognized in earnings until the natural gas inventory is withdrawn from storage and sold, at which time Energy Services realizes the entire margin on the transaction.

Operating Results

Energy Services’ financial results for the fiscal years ended September 30, are summarized as follows:

(Thousands)	2018		2017			2016
Operating revenues (1)	$	2,112,804	$	1,462,681		$	1,197,253
Operating expenses
Gas purchases (including demand charges (2)(3))	1,995,335		1,441,310			1,153,911
Operation and maintenance	32,821		20,313			20,025
Depreciation and amortization	76		63			88
Other taxes	2,732		1,788			937
Total operating expenses	2,030,964		1,463,474			1,174,961
Operating income (loss)	81,840		(793		)	22,292
Other income	240		1			98
Interest expense, net	3,945		2,747			1,095
Income tax provision (benefit)	24,996		(4,015		)	7,030
Net income	$	53,139	$	476		$	14,265

(1) Includes related party transactions of approximately $48.3 million, $316,000 and $9.5 million during fiscal 2018, 2017 and 2016, respectively, which is eliminated in consolidation.

(2) Costs associated with pipeline and storage capacity that are expensed over the term of the related contracts, which generally varies from less than one year to 10 years.

(3) Includes related party transactions of approximately $4.5 million, $4.6 million and $14.6 million during fiscal 2018, 2017 and 2016, respectively, a portion of which are eliminated in consolidation.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

As of September 30, Energy Services’ portfolio of financial derivative instruments are composed of:

(in Bcf)	2018	2017	2016
Net short futures contracts	24.3	16.4	79.1
Net long options	—	—	1.2

Operating Revenues and Gas Purchases

During fiscal 2018, operating revenues increased$650.1 million and gas purchases increased$554 million, due primarily to increased volume and price spreads resulting from market volatility caused by changes in weather and related demand. Gas purchases also include an increase due to the changes in the economic hedging of natural gas inventory of $61 million, partially offset by a decrease of $25.7 million in unrealized gains on derivative instruments.

During fiscal 2017, operating revenues increased$265.4 million and gas purchases increased$287.4 million due primarily to an approximate 36.8 percent increase in the average price of natural gas and the acquisition of Talen’s sales, pipeline and storage capacity agreements, as well as various wholesale transactions, partially offset by a 5.4 percentincrease in wholesale volumes. Gas purchases also include a decrease due to the changes in the economic hedging of natural gas inventory of $75.3 million, partially offset by an increase of $63.4 million in unrealized gains on derivative instruments.

Future results at Energy Services are contingent upon natural gas market price volatility driven by variations in both the supply and demand balances caused by weather and other factors. As a result, variations in weather patterns in the key market areas served may affect earnings during the fiscal year. Changes in market fundamentals, such as an increase in supply and decrease in demand due to milder temperatures, and reduced volatility, can negatively impact Energy Services’ earnings. See Item 7. Management’s Discussion and Analysisof Financial Condition and Results of Operations - Natural Gas Distribution Segment forTetco M-3 Daily Prices, which illustrates the daily natural gas prices in the Northeast market region.

Operation and Maintenance Expense

O&M expense increased$12.5 million or 61.6 percent during fiscal 2018, compared with fiscal 2017, due primarily to increased incentive compensation and shared corporate costs, partially offset by the pre-tax gain of $3.7 million, associated with the sale of NJRRS. O&M expense remained relatively unchanged during fiscal 2017, compared with fiscal 2016.

Income Tax Provision

Income tax benefit increased$29 million during fiscal 2018, compared with fiscal 2017, due primarily to increased operating income and income tax expenseof $6.1 million related to the revaluation of deferred tax assets due to the Tax Act, partially offset by the lower effective tax rate as a result of the new tax legislation. Income taxes decreased $11 million during fiscal 2017, compared with fiscal 2016, due primarily to decreased operating income.

Net Income

Net income increased$52.7 million during fiscal 2018, compared with fiscal 2017, due primarily to the increase in operating income, partially offset by an increase in O&M and income tax expense, as previously discussed. Net income decreased$13.8 million during fiscal 2017, compared with fiscal 2016, due primarily to lower operating income, partially offset by the related decrease in income tax expense.

Non-GAAP Financial Measures

Management uses financial margin and NFE, non-GAAP financial measures, when evaluating the operating results of Energy Services. Energy Services economically hedges its natural gas inventory with financial derivative instruments and calculates the related tax effect based on the statutory rate. Financial margin and NFE are based on removing timing differences associated with certain derivative instruments, as discussed above. Management views these measures as representative of the overall expected economic result and uses these measures to compare Energy Services’ results against established benchmarks and earnings targets, as these measures eliminate the impact of volatility on GAAP earnings as a result of timing differences associated with the settlement of derivative instruments. To the extent that there are unanticipated impacts from changes in the market value related to the effectiveness of economic hedges, Energy Services’ actual non-GAAP results can differ from the results anticipated at the outset of the transaction. Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measure.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

When Energy Services reconciles the most directly comparable GAAP measure to both financial margin and NFE, the current-period unrealized gains and losses on derivatives are excluded as a reconciling item. Financial margin and NFE also exclude the effects of economic hedging of the value of our natural gas in storage and, therefore, only include realized gains and losses related to natural gas withdrawn from storage, effectively matching the full earnings effects of the derivatives with realized margins on the related physical gas flows.

Financial Margin

The following table is a computation of Energy Services’ financial margin for the fiscal years ended September 30.

(Thousands)	2018			2017			2016
Operating revenues	$	2,112,804		$	1,462,681		$	1,197,253
Less: Gas purchases	1,995,335			1,441,310			1,153,911
Add:
Unrealized (gain) loss on derivative instruments and related transactions (1)	26,728			(10,063		)	48,855
Effects of economic hedging related to natural gas inventory (2)	(22,570		)	38,470			(36,816		)
Financial margin	$	121,627		$	49,778		$	55,381

(1) Includes unrealized (gains) losses related to an intercompany transaction between NJNG and Energy Services that have been eliminated in consolidation of approximately $85,000, $(751,000) and $(1.3) million for the fiscal years ended September 30, 2018, 2017 and 2016, respectively.

(2) Effects of hedging natural gas inventory transactions where the economic impact is realized in a future period.

A reconciliation of operating income, the closest GAAP financial measure to Energy Services’ financial margin, is as follows for the fiscal years ended September 30:

(Thousands)	2018			2017			2016
Operating income (loss)	$	81,840		$	(793	)	$	22,292
Add:
Operation and maintenance	32,821			20,313			20,025
Depreciation and amortization	76			63			88
Other taxes	2,732			1,788			937
Subtotal	117,469			21,371			43,342
Add:
Unrealized loss (gain) on derivative instruments and related transactions	26,728			(10,063		)	48,855
Effects of economic hedging related to natural gas inventory	(22,570		)	38,470			(36,816		)
Financial margin	$	121,627		$	49,778		$	55,381

Financial margin increased$71.8 million during fiscal 2018, compared with fiscal 2017, due primarily to increased volume and price spreads resulting from market volatility caused by changes in weather and related demand. Financial margin decreased$5.6 million during fiscal 2017, compared with fiscal 2016, due primarily to fewer market opportunities related to transportation assets and timing of certain transactions related to storage withdrawals along with a warmer winter and a milder spring.

Net Financial Earnings

A reconciliation of Energy Services’ net income (loss), the most directly comparable GAAP financial measure to NFE, is as follows for the fiscal years ended September 30:

(Thousands)	2018			2017			2016
Net income	$	53,139		$	476		$	14,265
Add:
Unrealized loss (gain) on derivative instruments and related transactions	26,728			(10,063		)	48,855
Tax effect (1)	(4,281		)	3,635			(17,734		)
Effects of economic hedging related to natural gas inventory	(22,570		)	38,470			(36,816		)
Tax effect	7,362			(13,964		)	13,364
Net financial earnings	$	60,378		$	18,554		$	21,934

(1) Includes taxes related to an intercompany transaction between NJNG and Energy Services that have been eliminated in consolidation of approximately $(337,000), $427,000 and $716,000 for the fiscal years ended September 30, 2018, 2017 and 2016, respectively.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

NFE increased$41.8 million during fiscal 2018, compared with fiscal 2017, due primarily to higher financial margin, partially offset by increased O&M expense, as previously discussed, and an income tax expense of $6.1 millionassociated with the Tax Act, as previously discussed. NFE decreased$3.4 million during fiscal 2017, compared with fiscal 2016, due primarily to a decrease in financial margin and higher interest expense related to increased borrowing, partially offset by a reduction in income tax expense related to the decrease in NFE.

Future results are subject to Energy Services’ ability to expand its wholesale sales and service activities and are contingent upon many other factors, including an adequate number of appropriate and credit-qualified counterparties in an active and liquid natural marketplace; volatility in the natural gas market due to weather or other fundamental market factors impacting supply and/or demand; transportation, storage and/or other market arbitrage opportunities; sufficient liquidity in the overall energy trading market; and continued access to liquidity in the capital markets.

Midstream Segment

Overview

Our Midstream segment invests in natural gas assets, such as natural gas transportation and storage facilities. We believe that acquiring, owning and developing these midstream assets, which operate under a tariff structure that has either regulated or market-based rates, can provide us a growth opportunity. To that end, we have a 50 percent ownership interest in Steckman Ridge, a storage facility that operates under market-based rates, and a 20 percent ownership interest in PennEast, a natural gas pipeline. PennEast received a Certificate of Public Convenience and Necessity for the project from FERC on January 19, 2018. PennEast has advised that it currently expects the pipeline to be completed and operational in 2019. However, the project could be delayed beyond 2019, due to factors beyond PennEast’s ability to control or estimate precisely, including potential delays in obtaining (or the inability to obtain) governmental and regulatory approvals and land-use rights and unforeseen construction delays. As of September 30, 2018, our net investments in Steckman Ridge and PennEast were $117 million and $73.9 million, respectively.

In September 2015, Midstream exchanged its 5.53 percent ownership interest in Iroquois with Dominion Midstream Partners, L.P. for 1.84 million DM Common Units. As of September 30, 2018, the market value of the DM Common Units was $32.9 million. See Note 2. Summary of Significant Accounting Policies - Available for Sale Securities in the accompanying Consolidated Financial Statements for a more detailed discussion.

Operating Results

The financial results of our Midstream segment for the fiscal years ended September 30, are summarized as follows:

(Thousands)	2018			2017		2016
Equity in earnings of affiliates	$	16,165		$	17,797	$	13,936
Operation and maintenance	$	4,441		$	2,302	$	1,197
Other income	$	5,775		$	4,162	$	3,130
Interest expense, net	$	1,667		$	960	$	287
Income tax provision	$	(8,548	)	$	5,820	$	6,130
Net income	$	24,367		$	12,857	$	9,406

Equity in earnings of affiliates are driven primarily by storage revenues generated by Steckman Ridge and AFUDC earned at PennEast.

Equity in earnings of affiliates is as follows for the fiscal years ended September 30:

(Thousands)	2018		2017		2016
Steckman Ridge	$	11,283	$	13,351	$	14,050
PennEast	4,882		4,446		(114		)
Total equity in earnings of affiliates	$	16,165	$	17,797	$	13,936

Equity in earnings of affiliates decreased$1.6 million during fiscal 2018, compared with fiscal 2017, due primarily to decreases in revenue and increases in debt service costs at Steckman Ridge. Equity in earnings of affiliates increased$3.9 million during fiscal 2017, compared with fiscal 2016, due primarily to increased AFUDC earned at PennEast resulting from the cumulative effect adjustment recorded in fiscal 2017.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

O&M expense increased$2.1 million during fiscal 2018, compared with fiscal 2017, due primarily to increased shared corporate costs. O&M expense increased$1.1 million during fiscal 2017, compared with fiscal 2016, due primarily to increased consulting expenses, charitable donations and shared services costs.

Other income increased $1.6 million during fiscal 2018, compared with fiscal 2017, and increased $1 million during fiscal 2017, compared with fiscal 2016, due primarily to increased interest income from Steckman Ridge and dividend income from our investment in DM Common Units.

Interest expense, net increased$707,000 during fiscal 2018, compared with fiscal 2017, and $673,000 during fiscal 2017, compared with fiscal 2016, due primarily to increased intercompany borrowing related to our PennEast investment.

Income taxes decreased$14.4 million during fiscal 2018, compared with fiscal 2017, due primarily to an income tax benefit of $13.9 million associated with the Tax Act. The income tax provision remained relatively unchanged during fiscal 2017, compared with fiscal 2016. Equity in earnings increased; however, the tax benefits associated with AFUDC reduced the overall tax expense.

Net income in fiscal 2018increased$11.5 million, compared with fiscal 2017, due primarily to the income tax benefit and the decrease in effective tax rate related to the Tax Act, as previously discussed, partially offset by lower equity in earnings of affiliates, as previously discussed. Net income increased$3.5 million in fiscal 2017, compared with fiscal 2016, due primarily to the increase in equity in earnings of affiliates, as discussed above.

Home Services and Other Operations

Overview

The financial results of Home Services and Other consist primarily of the operating results of NJRHS. NJRHS provides service, sales and installation of appliances to approximately 110,000 service contract customers and has been focused on growing its installation business and expanding its service contract customer base. Home Services and Other also includes organizational expenses incurred at NJR and rental income at CR&R.

Operating Results

The consolidated financial results of Home Services and Other for the fiscal years ended September 30, are summarized as follows:

(Thousands)	2018			2017		2016
Operating revenues	$	50,057		$	49,591	$	48,497
Operation and maintenance	$	43,731		$	40,245	$	40,106
Energy and other taxes	$	4,042		$	3,938	$	3,777
Other income, net	$	6,892		$	6,467	$	869
Income tax provision	$	11,944		$	3,857	$	1,387
Net (loss) income	$	(3,555	)	$	6,811	$	2,882

Operating revenue remained relatively flat during fiscal 2018, compared with fiscal 2017. Operating revenue increased$1.1 million during fiscal 2017, compared with fiscal 2016, due primarily to increased furnace/air conditioner combination installations at NJRHS related to increased marketing promotions, along with increased contract revenue, partially offset by decreased operating revenue at CR&R due to the sale of a 56,400 square foot office building.

O&M expense increased$3.5 million during fiscal 2018, compared with fiscal 2017, due primarily to a pre-tax gain of $1.9 million, associated with the sale of a 56,400 square foot office building that was recorded during fiscal 2017, as well as an increase in consulting expense due primarily to additional technology improvements. O&M expense remained relatively flat during fiscal 2017 compared with fiscal 2016.

Other income, net remained relatively unchanged during fiscal 2018, compared with fiscal 2017, due primarily to pre-tax gains associated with the sale of available for sale securities of $5.3 million and $5.4 million during fiscal 2018 and 2017, respectively. Other income, net increased $5.6 million during fiscal 2017, compared with fiscal 2016, due primarily to the sale of available for sale securities, which resulted in a pre-tax gain during fiscal 2017 of $5.4 million.

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Income taxes increased$8.1 million during fiscal 2018, compared with fiscal 2017, due primarily to tax expense of $9.7 millionassociated with the Tax Act. Income taxes increased$2.5 million during fiscal 2017, compared with fiscal 2016, due primarily to the increase in other income, as previously discussed.

Net income decreased$10.4 million during fiscal 2018, compared with fiscal 2017, due primarily to increased income tax provision, as previously discussed. Net income during fiscal 2017increased$3.9 million, compared with fiscal 2016, due primarily to the increases in other income and operating revenue, partially offset by the increase in the income tax provision.

Non-GAAP Financial Measures

NFE is based on removing timing differences associated with NJR's variable-for-fixed interest rate swap. Non-GAAP financial measures are not in accordance with, or an alternative to GAAP, and should be considered in addition to, and not as a substitute for the comparable GAAP measure. A reconciliation of Home Services and Other's net income for the fiscal years ended September 30, to the GAAP financial measure most directly comparable to NFE, is as follows:

(Thousands)	2018			2017		2016
Net income (loss)	$	(3,555	)	$	6,811	$	2,882
Add:
Unrealized (gain) loss on derivative instruments and related transactions	(381		)	—		—
Tax effect	107			—		—
Net financial earnings (loss)	$	(3,829	)	$	6,811	$	2,882

Liquidity and Capital Resources

Our objective is to maintain an efficient consolidated capital structure that reflects the different characteristics of each reporting segment and business operations and provides adequate financial flexibility for accessing capital markets as required.

Our consolidated capital structure as of September 30, was as follows:

	2018		2017
Common stock equity	49	%	46	%
Long-term debt	41		38
Short-term debt	10		16
Total	100	%	100	%

Common Stock Equity

We satisfy our external common equity requirements, if any, through issuances of our common stock, including the proceeds from stock issuances under our DRP. The DRP allows us, at our option, to use treasury shares or newly issued shares to raise capital. On September 28, 2018, we registered approximately 3.2 million shares of additional common stock for issuance under the DRP. NJR raised approximately $41.7 million of equity by issuing approximately 1,014,000 new shares through the waiver discount feature of the DRP during fiscal 2018. NJR did not issue new shares through the waiver discount feature of the DRP during fiscal 2017.

NJR also raised approximately $17.1 million and $17.5 million of equity through the DRP by issuing approximately 413,000 and 472,000 shares of treasury stock during fiscal 2018 and 2017, respectively.

In 1996, the Board of Directors authorized us to implement a share repurchase program, which was expanded seven times since the inception of the program, authorizing a total of 19.5 million shares of common stock for repurchase. As of September 30, 2018, we have repurchased a total of approximately 17.1 million shares and may repurchase an additional 2.4 million shares under the approved program. There were 105,000 shares of common stock shares repurchased during fiscal 2017.

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Debt

NJR and its unregulated subsidiaries generally rely on cash flows generated from operating activities and the utilization of committed credit facilities to provide liquidity to meet working capital and short-term debt financing requirements. NJNG also relies on the issuance of commercial paper for short-term funding. NJR and NJNG periodically access the capital markets to fund long-lived assets through the issuance of long-term debt securities.

We believe that our existing borrowing availability, equity proceeds and cash flows from operations will be sufficient to satisfy our working capital, capital expenditures and dividend requirements for the next 12 months. NJR, NJNG, Clean Energy Ventures, Midstream and Energy Services currently anticipate that each of their financing requirements for the next 12 months will be met primarily through the issuance of short and long-term debt, meter and solar sale-leasebacks and proceeds from our DRP, including utilizing the waiver discount feature.

We believe that as of September 30, 2018, NJR and NJNG were, and currently are, in compliance with all existing debt covenants, both financial and non-financial.

Short-Term Debt

We use our short-term borrowings primarily to finance Energy Services’ short-term liquidity needs, Midstream segment’s PennEast contributions, share repurchases and, on an initial basis, Clean Energy Ventures’ investments. Energy Services’ use of high volume storage facilities and anticipated pipeline park-and-loan arrangements, combined with related economic hedging activities in the volatile wholesale natural gas market, create significant short-term cash requirements.

NJNG satisfies its debt needs by issuing short- and long-term debt based on its financial profile. The seasonal nature of NJNG’s operations creates large short-term cash requirements, primarily to finance natural gas purchases and customer accounts receivable. NJNG obtains working capital for these requirements and for the temporary financing of construction and MGP remediation expenditures and energy tax payments, based on its financial profile, through the issuance of commercial paper supported by the NJNG Credit Facility or through short-term bank loans under the NJNG Credit Facility.

As of September 30, 2018, NJR and NJNG, respectively, had revolving credit facilities totaling $425 million and $250 million, and letters of credit outstanding totaling $14.9 million and $731,000, which reduced the amounts available under the facilities along with short-term borrowings to $322 million and $185 million. Short-term borrowings were as follows:

	Three Months Ended			Twelve Months Ended
($ in thousands)	September 30, 2018
NJR
Notes Payable to banks:
Balance at end of period	$	87,950		$	87,950
Weighted average interest rate at end of period	3.07		%	3.07		%
Average balance for the period	$	63,089		$	197,154
Weighted average interest rate for average balance	3.02		%	2.64		%
Month end maximum for the period	$	87,950		$	330,900
NJNG
Commercial Paper and Notes Payable to banks:
Balance at end of period	$	64,000		$	64,000
Weighted average interest rate at end of period	2.18		%	2.18		%
Average balance for the period	$	63,698		$	31,924
Weighted average interest rate for average balance	2.07		%	1.37		%
Month end maximum for the period	$	82,000		$	82,000

Due to the seasonal nature of natural gas prices and demand, and because inventory levels are built up during its natural gas injection season (April through October), NJR and NJNG’s short-term borrowings tend to peak in November and December.

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NJR

On September 28, 2015, NJR entered into a $425 million Amended and Restated Credit Agreement, which refinanced an earlier $425 million revolving credit facility. The NJR Credit Facility is scheduled to terminate on September 28, 2020, subject to two mutual options for a one-year extension beyond that date. Certain of NJR’s unregulated subsidiaries have guaranteed all of NJR’s obligations under the NJR Credit Facility.

The NJR Credit Facility permits the borrowing of revolving loans and swingline loans, as well as the issuance of letters of credit. The NJR Credit Facility also includes an accordion feature, which would allow NJR, in the absence of a default or event of default, to increase from time to time, with the existing or new lenders, the revolving credit commitments under the NJR Credit Facility in minimum $5 million increments up to a maximum of $100 million. As of September 30, 2018, the consolidated total indebtedness to total capitalization ratio, as defined in the NJR Credit Facility, was 51 percent.

On June 25, 2018, the $425 million NJR Credit Facility was amended to permit liens and the disposition of assets relating to sale-leaseback or other similar tax equity financing arrangements of meter assets or of solar or wind facilities. These transactions are permissible so long as NJR is in compliance with certain covenants both before and after such incurrence, and if no event of default may be caused by such sale-leaseback or similar arrangement.

As of September 30, 2018, NJR had $88 million outstanding under the NJR Credit Facility. Neither NJNG nor its assets are obligated or pledged to support the NJR Credit Facility.

During fiscal 2018, NJR’s average interest rate under the NJR Credit Facility was 2.64 percent, resulting in interest expense of $4.9 million. Based on average borrowings under the facilities of $197.2 million during the period, a 100 basis point change in the underlying average interest rate would have caused a change in interest expense of approximately $2.1 million during fiscal 2018.

As of September 30, 2018, NJR has six letters of credit outstanding totaling $14.9 million. Three letters of credit totaling $11.9 million are on behalf of Energy Services and three letters of credit totaling $3 million are on behalf of Clean Energy Ventures. These letters of credit reduce the amount available under NJR’s committed credit facility by the same amount. NJR does not anticipate that these letters of credit will be drawn upon by the counterparties and they will be renewed as necessary.

Energy Services’ letters of credit are used for margin requirements for natural gas transactions and expire on dates ranging from December 2018 to September 2019. Clean Energy Ventures’ letters of credit are used to secure construction of ground-mounted solar projects and to secure obligations pursuant to an interconnection services agreement. They expire on dates ranging from May 2019 to August 2019.

NJNG

NJNG’s commercial paper is sold through several commercial banks under an issuing and paying agency agreement and is supported by the $250 million NJNG Credit Facility. The NJNG Credit Facility permits the borrowing of revolving loans and swing loans, as well as the issuance of letters of credit. It also permits an increase to the facility, from time to time, with the existing or new lenders, in a minimum of $15 million increments up to a maximum of $50 million at the lending banks’ discretion. As of September 30, 2018, NJNG’s consolidated total indebtedness to total capitalization ratio was 43 percent. As of September 30, 2018, the unused amount available under the NJNG Credit Facility, including amounts allocated to the backstop under the commercial paper program and the issuance of letters of credit, was $185 million. During fiscal 2018, NJNG’s weighted average interest rate on outstanding commercial paper was 1.37 percent, resulting in interest expense of $557,300. Based on average borrowings under the facility of $31.9 million during the period, a 100 basis point change in the underlying average interest rate would have caused a change in interest expense of approximately $325,400 during fiscal 2018.

As of September 30, 2018, NJNG has two letters of credit outstanding for $731,000. These letters of credit reduce the amount available under NJNG’s committed credit facility by the same amount. NJNG does not anticipate that these letters of credit will be drawn upon by the counterparties. These letters of credit are used as collateral for soil remediation systems and expire in August 2019.

Short-Term Debt Covenants

Borrowings under the NJR Credit Facility and NJNG Credit Facility are conditioned upon compliance with a maximum leverage ratio (consolidated total indebtedness to consolidated total capitalization as defined in the applicable agreements), of

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not more than .65 to 1.00 at any time. These revolving credit facilities contain customary representations and warranties for transactions of this type. They also contain customary events of default and certain covenants that will limit NJR’s or NJNG’s ability, beyond agreed upon thresholds, to, among other things:

•incur additional debt;

•incur liens and encumbrances;

•make dispositions of assets;

•enter into transactions with affiliates; and

•merge, consolidate, transfer, sell or lease all or substantially all of the borrowers’ or guarantors’ assets.

These covenants are subject to a number of exceptions and qualifications set forth in the applicable agreements.

Default Provisions

The agreements governing our long-term and short-term debt obligations include provisions that, if not complied with, could require early payment or similar actions. Default events include, but are not limited to, the following:

•defaults for non-payment;

•defaults for breach of representations and warranties;

•defaults for insolvency;

•defaults for non-performance of covenants;

•cross-defaults to other debt obligations of the borrower; and

•guarantor defaults.

The occurrence of an event of default under these agreements could result in all loans and other obligations of the borrower becoming immediately due and payable and the termination of the credit facilities or term loan.

Long-Term Debt

NJR

NJR has $50 million of 3.25 percent senior notes due September 2022, issued under a private placement debt shelf facility.

In November 2014, NJR issued $100 million in 3.48 percent senior notes due November 7, 2024, under the Prudential Facility, which fully utilized the remaining capacity under the facility. The notes issued under the Prudential Facility are guaranteed by certain unregulated subsidiaries of NJR.

In March 2016, NJR entered into a note purchase agreement under which we issued, on August 18, 2016, $50 million of 3.2 percent senior notes due August 18, 2023, and $100 million of 3.54 percent senior notes due August 18, 2026. The notes are guaranteed by certain of our unregulated subsidiaries. The notes are unsecured. The proceeds of the notes were used for general corporate purposes, including working capital and capital expenditures.

In August 2017, NJR entered into a $100 million credit agreement due August 16, 2019. The term loan accrues interest at a variable rate determined monthly, which is LIBOR plus 70 basis points. On January 26, 2018, NJR entered into a variable-for-fixed interest rate swap for its variable rate term loan, which fixed the variable rate at 2.84 percent. As of September 30, 2018, the $100 million term loan, net of deferred financing costs, was classified as a current maturity of long-term debt.

On June 8, 2018, NJR entered into a note purchase agreement, under which we issued $100 million of 3.96 percent senior notes due June 8, 2028. The notes are not secured by assets, but are instead guaranteed by certain unregulated subsidiaries of NJR. The proceeds of the notes will be used for general corporate purposes, including, but not limited to, funding capital expenditures.

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On July 17, 2018, the $100 million variable rate term loan was amended to permit the disposition of assets relating to sale-leaseback or other similar tax equity financing arrangements of meter assets or of solar or wind facilities. These transactions are permissible so long as NJR is in compliance with certain covenants both before and after such incurrence, and if no event of default may be caused by such sale-leaseback or similar arrangement.

Neither NJNG nor its assets are obligated or pledged to support NJR’s long-term debt.

NJNG

NJNG and the Trustee are parties to the Mortgage Indenture, which secures all of NJNG’s outstanding FMB. The Mortgage Indenture provides a direct first mortgage lien upon substantially all of the operating properties and franchises of NJNG (other than excepted property, such as cash on hand, choses-in-action, securities, rent, natural gas meters and certain materials, supplies, appliances and vehicles), subject only to certain permitted encumbrances. The Mortgage Indenture contains provisions subjecting after-acquired property (other than excepted property and subject to pre-existing liens, if any, at the time of acquisition) to the lien thereof.

As of September 30, 2018, NJNG’s long-term debt consisted of $575 million in fixed-rate debt issuances, with maturities ranging from 2024 to 2048, and $97 million in secured variable rate debt, with maturities ranging from 2027 to 2041, which are both secured by the Mortgage Indenture, and $26.4 million in capital leases with various maturities ranging from 2019 to 2025.

On May 31, 2017, the BPU approved a petition filed by NJNG requesting authorization over a three-year period to issue up to $400 million of medium-term notes with a maturity of not more than 40 years, for up to five years with an option for two additional one-year extensions; enter into interest rate risk management transactions related to debt securities and redeem and refinance or defease any of NJNG’s outstanding long-term debt securities.

On April 15, 2015, NJNG issued $50 million of 2.82 percent senior notes due April 15, 2025, and $100 million of 3.66 percent senior notes due April 15, 2045, in the private placement market pursuant to a note purchase agreement entered into on February 12, 2015. The notes are secured by an equal principal amount of NJNG’s FMB (Series SS and TT, respectively) issued under NJNG’s Mortgage Indenture. The proceeds of the notes were used for general corporate purposes, to refinance or retire debt and to fund capital expenditure requirements. The notes are subject to required prepayments upon the occurrence of certain events. NJNG may at any time prepay all or a portion of the notes at a make-whole prepayment price.

On June 21, 2016, NJNG entered into a Note Purchase Agreement, under which NJNG issued $125 million of its 3.63 percent senior notes due June 21, 2046. The notes are secured by an equal principal amount of NJNG’s FMB (series UU) issued under NJNG’s Mortgage Indenture. The proceeds of the notes will be used for general corporate purposes, including, but not limited to, refinancing or retiring short-term debt and funding capital expenditures. The notes are subject to required prepayments upon the occurrence of certain events. NJNG may prepay all or any part of the notes in amounts not less than $1 million in aggregate principal amount of the notes then outstanding at 100 percent of the aggregate principal amount, plus accrued interest and a make-whole amount, if applicable.

On January 17, 2017, we completed the purchase of three FMBs in lieu of redemption with an aggregate principal amount totaling $35.8 million. The FMBs bore interest at rates ranging from 4.5 percent to 4.9 percent. The bonds purchased in lieu of redemption are being held by us to provide an opportunity to evaluate remarketing alternatives.

On May 11, 2018, NJNG entered into a note purchase agreement, under which NJNG issued $125 million of 4.01 percent senior notes due May 11, 2048. The interest rate includes the quoted March 9, 2018 30-year treasury rate, plus a market-based credit spread. The notes are secured by an equal principal amount of NJNG's FMB (series VV) issued under NJNG's Mortgage Indenture. The proceeds of the notes will be used for general corporate purposes, including, but not limited to, refinancing or retiring short-term debt and funding capital expenditures.

In June 2015, NJNG entered into a treasury lock transaction to fix a benchmark treasury rate of 3.26 percent associated with a $125 million debt issuance that was finalized in May 2018. This debt issuance coincided with the maturity of NJNG's $125 million, 5.6 percent notes that came due on May 15, 2018. This treasury lock was settled on March 13, 2018, which coincided with the pricing of the new debt being issued. Settlement of the treasury lock resulted in a $2.6 million loss, which is recorded as a component of regulatory assets on the Consolidated Balance Sheets and will be amortized to earnings over the 30-year term of the $125 million, 4.01 percent notes that were issued on May 11, 2018.

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In August 2011, NJNG completed a refunding of its outstanding Auction-Rate Securities whereby the EDA issued a total of $97 million of Natural Gas Facilities Refunding Revenue Bonds (New Jersey Natural Gas Company Project) composed of three series of bonds. EDA Bonds are special, limited obligations of the EDA payable solely from payments made by NJNG pursuant to a Loan Agreement and are secured by the pledge of $97 million principal amount of the FMB issued by the Company.

EDA Bonds accrue interest at a variable rate determined monthly, which was initially calculated as a rate of .55 percent, plus 70 percent of one month LIBOR, subject to earlier redemption or conversion to another interest rate mode. The maximum interest rate on the EDA Bonds is 12 percent per annum. NJNG’s obligations under the Loan Agreement, and its corresponding obligations under the FMB, match the respective principal amounts, interest rates and maturity dates of the EDA Bonds. The weighted average interest rate on the EDA Bonds as of September 30, 2018, was 2.03 percent. The interest rates on variable rate debt may vary based upon market conditions. Sudden increases in the interest rate could cause a change in interest expense and cash flow for the Company in the future.

NJR is not obligated directly or contingently with respect to the NJNG notes or the FMB.

Long-Term Debt Covenants and Default Provisions

The NJR and NJNG long-term debt instruments contain customary representations and warranties for transactions of their type. They also contain customary events of default and certain covenants that will limit NJR or NJNG’s ability beyond agreed upon thresholds to, among other things:

•incur additional debt (including a covenant that limits the amount of consolidated total debt of the borrower at the end of a fiscal quarter to 65 percent of the consolidated total capitalization of the borrower, as those terms are defined in the applicable agreements, and a covenant limiting priority debt to 20 percent of the borrower’s consolidated total capitalization, as those terms are defined in the applicable agreements);

•incur liens and encumbrances;

•make loans and investments;

•make dispositions of assets;

•make dividends or restricted payments;

•enter into transactions with affiliates; and

•merge, consolidate, transfer, sell or lease substantially all of the borrower’s assets.

The aforementioned covenants are subject to a number of exceptions and qualifications set forth in the applicable note purchase agreements.

In addition, the FMB issued by NJNG under the Mortgage Indenture are subject to certain default provisions. Events of Default, as defined in the Mortgage Indenture, consist mainly of:

•failure for 30 days to pay interest when due;

•failure to pay principal or premium when due and payable;

•failure to make sinking fund payments when due;

•failure to comply with any other covenants of the Mortgage Indenture after 30 days’ written notice from the Trustee;

•failure to pay or provide for judgments in excess of $30 million in aggregate amount within 60 days of the entry thereof; or

•certain events that are or could be the basis of a bankruptcy, reorganization, insolvency or receivership proceeding.

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Upon the occurrence and continuance of such an Event of Default, the Mortgage Indenture, subject to any provisions of law applicable thereto, provides that the Trustee may take possession and conduct the business of NJNG, may sell the trust estate or proceed to foreclose the lien of the Mortgage Indenture. The interest rate on defaulted principal and interest, to the extent permitted by law, on the FMB issued under the Mortgage Indenture is the rate stated in the applicable supplement or, if no such rate is stated, six percent per annum.

Sale-Leaseback

NJNG

NJNG received $7.8 million, $9.6 million and $7.1 million in fiscal 2018, 2017 and 2016, respectively, in connection with the sale-leaseback of its natural gas meters. During fiscal 2018, 2017 and 2016, NJNG exercised early purchase options with respect to meter leases by making final principal payments of $2.2 million, $2.4 million and $1.9 million, respectively. NJNG continues to evaluate this sale-leaseback program based on current market conditions. As noted, natural gas meters are accepted as property under the Mortgage Indenture.

Clean Energy Ventures

Clean Energy Ventures received proceeds of $71.5 million and $32.9 million in fiscal 2018 and 2017, respectively, in connection with the sale-leaseback of commercial solar assets. Clean Energy Ventures has entered into transactions to sell certain of its commercial solar assets concurrent with agreements to lease the assets back over six to 15-year terms. These sale-leasebacks are financing obligations secured by the solar assets and related future cash flows from SREC and energy sales. ITCs and other tax benefits associated with these solar projects were transferred to the buyer. Clean Energy Ventures will continue to operate the solar projects and retain ownership of SRECs generated, and has the option to renew the lease or repurchase the assets at the end of the lease term per the terms of the arrangement.

Contractual Obligations

The following table is a summary of NJR, NJNG, Energy Services and Clean Energy Ventures contractual cash obligations and financial commitments and their applicable payment due dates as of September 30, 2018:

			Up to		1-3		3-5		After
(Thousands)	Total		1 Year		Years		Years		5 Years
Long-term debt(1)	$	1,783,345	$	139,772	$	74,338	$	172,472	$	1,396,763
Capital lease obligations(1)	39,570		10,932		17,225		6,168		5,245
Solar asset financing obligations (1)	79,410		9,794		15,633		15,680		38,303
Operating leases(1)	67,740		3,217		7,445		7,028		50,050
Short-term debt	151,950		151,950		—		—		—
New Jersey Clean Energy Program(1)	14,052		14,052		—		—		—
Construction obligations	23,903		23,903		—		—		—
Remediation expenditures(2)	130,800		19,800		28,800		28,800		53,400
Natural gas supply purchase obligations-NJNG	240,731		65,737		71,465		67,767		35,762
Demand fee commitments-NJNG	1,128,331		111,993		223,991		200,015		592,332
Natural gas supply purchase obligations-Energy Services	467,369		428,015		39,354		—		—
Demand fee commitments-Energy Services	257,666		83,864		111,403		56,257		6,142
Total contractual cash obligations	$	4,384,867	$	1,063,029	$	589,654	$	554,187	$	2,177,997

(1) These obligations include an interest component, as defined under the related governing agreements or in accordance with the applicable tax statute.

(2) Expenditures are estimated. See Note 13. Commitments and Contingent Liabilities in the accompanying Consolidated Financial Statements.

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We made a discretionary contribution of $30 million during the first quarter of fiscal 2016, to improve the funded status of the pension plans based on then-current actuarial assumptions, which included the adoption of the most recent mortality table. We do not expect to be required to make additional contributions to fund the pension plans over the following two fiscal years based on current actuarial assumptions; however, funding requirements are uncertain and can depend significantly on changes in actuarial assumptions, returns on plan assets and changes in the demographics of eligible employees and covered dependents. In addition, as in the past, we may elect to make discretionary contributions to the plans in excess of the minimum required amount. We made no discretionary contributions to the pension plans in fiscal 2018 and 2017. There are no federal requirements to pre-fund OPEB benefits. However, we are required to fund certain amounts due to regulatory agreements with the BPU. We anticipate that the annual funding level of the OPEB plans will range from $5 million to $8 million annually over each of the next five years. Additional contributions may vary based on market conditions and various assumptions.

As of September 30, 2018, there were NJR guarantees covering approximately $418.1 million of natural gas purchases and Energy Services demand fee commitments not yet reflected in accounts payable on the Consolidated Balance Sheets.

NJNG incurs significant capital expenditures consisting primarily of its construction program to support customer growth, maintenance of its distribution and transmission system and replacement needed under pipeline safety regulations. During fiscal 2018, committed and spent capital expenditures totaled $241.3 million. In fiscal 2019 and 2020, NJNG’s total capital expenditures are projected to be $475.2 million and $343.2 million, respectively.

In November 2012, NJNG filed a petition with the BPU requesting deferral accounting for incurred uninsured incremental O&M costs associated with Superstorm Sandy. As of September 30, 2018, NJNG deferred $10.9 million in regulatory assets that was approved for recovery through NJNG’s new base rates, effective October 2016.

NJNG expects to fund its obligations with a combination of cash flow from operations, cash on hand, issuance of commercial paper, available capacity under its revolving credit facility and the issuance of long-term debt.

As of September 30, 2018, NJNG’s future MGP expenditures are estimated to be $130.8 million. For a more detailed description of MGP see Note 13. Commitments and Contingent Liabilities in the accompanying Consolidated Financial Statements.

Estimated capital expenditures are reviewed on a regular basis and may vary based on the ongoing effects of regulatory constraints, environmental regulations, unforeseen events and the ability to access capital.

Clean Energy Ventures’ expenditures include clean energy projects that support our goal to promote renewable energy. Accordingly, Clean Energy Ventures enters into agreements to install solar equipment involving both residential and commercial projects. During fiscal 2018, capital expenditures related to the purchase and installation of the solar equipment were $120.1 million. In fiscal 2019, Clean Energy Ventures plans to spend an estimated $134.4 million on commercial and residential solar projects. We estimate the value of solar-related projects placed in service in fiscal 2019 to be between $156 million and $166 million.

Capital expenditures related to clean energy projects are subject to change due to a variety of factors that may affect our ability to commence operations at these projects on a timely basis or at all, including logistics associated with the start-up of residential and commercial solar projects, such as timing of construction schedules, the permitting and regulatory process, any delays related to electric grid interconnection, economic trends, unforeseen events and the ability to access capital or allocation of capital to other investments or business opportunities.

During fiscal 2018, Midstream had a total of $16.2 million of expenditures related to our investment in the PennEast pipeline project. Expenditures in the PennEast pipeline are expected to total between $13 million and $15 million. Capital expenditures related to our Midstream investment in the Adelphia project were $16.7 million, which includes the initial payment of $10 million towards the purchase price. Including the purchase price of $166 million and assuming the transaction closes, we estimate expenditures related to the Adelphia project to be between $306 million and $310 million.

Energy Services does not currently anticipate any significant capital expenditures in fiscal 2019 and 2020.

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Off-Balance-Sheet Arrangements

Our off-balance-sheet arrangements consist of guarantees covering approximately $418.1 million of natural gas purchases, SREC sales and demand fee commitments, and eight outstanding letters of credit totaling $15.6 million, as previously mentioned. See Note 13. Commitments and Contingent Liabilities and Note 8. Debt for more information.

Cash Flows

Operating Activities

Cash flows from operating activities during fiscal 2018 totaled $398.3 million compared with $248 million during fiscal 2017. Operating cash flows are primarily affected by variations in working capital, which can be impacted by several factors, including:

•seasonality of our business;

•fluctuations in wholesale natural gas prices and other energy prices, including changes in derivative asset and liability values;

•timing of storage injections and withdrawals;

•the deferral and recovery of gas costs;

•changes in contractual assets used to optimize margins related to natural gas transactions;

•broker margin requirements;

•impact of unusual weather patterns on our wholesale business;

•timing of the collections of receivables and payments of current liabilities;

•volumes of natural gas purchased and sold; and

•timing of SREC deliveries.

The increase of $150.2 million in operating cash flows during fiscal 2018, compared with fiscal 2017, was due primarily to increased earnings at Energy Services and decreased working capital requirements as mentioned above.

The increase of $105.4 million in operating cash flows during fiscal 2017, compared with fiscal 2016, was due primarily to increased base rates, increased working capital due primarily to lower broker margin requirements, a decrease in bill credits issued and a discretionary contribution of $30 million to our pension plan during fiscal 2016 that did not recur in fiscal 2017.

Investing Activities

Cash flows used in investing activities totaled $373.1 million during fiscal 2018, compared with $390.7 million during fiscal 2017. The decrease of $17.6 million is due primarily to our fiscal 2017 acquisition of Talen’s retail and wholesale energy contract assets totaling $55.7 million that did not recur in fiscal 2018, cash proceeds of $27.9 million from the sale of Two Dot wind farm and NJRRS and a decrease in solar capital expenditures and PennEast investment of $26 million and $10.9 million, respectively, partially offset by an increase in expenditures of $78.3 million for our utility plant at NJNG, an advance payment of $10 million for the IEC acquisition and cash proceeds in fiscal 2017 of $9.4 million from a sale of a building that did not recur in fiscal 2018.

Cash flows used in investing activities totaled $390.7 million during fiscal 2017, compared with $363.2 million during fiscal 2016. The increase of $27.5 million was due primarily to our acquisition of Talen’s retail and wholesale energy contract assets totaling $55.7 million and increased investments in solar projects and PennEast of $39.4 million and $15.9 million, respectively, partially offset by a decrease in capital expenditures in wind investments of $39.1 million and utility plant of $32 million, along with net proceeds of $9.4 million from the sale of an office building and $6.6 million from the sale of available for sale securities.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

NJNG’s capital expenditures result primarily from the need for services, mains and meters to support its continued customer growth, mandated pipeline safety rulemaking, general system improvements and approved infrastructure programs. NJNG’s capital expenditures, including cost of removal, totaled $254.5 million and $176.2 million in fiscal 2018 and fiscal 2017, respectively.

The Company enters into various agreements to install, own and operate solar equipment, including both residential and commercial projects and onshore wind projects. During fiscal 2018 and fiscal 2017, capital expenditures on these projects totaled $123.4 million and $149.4 million, respectively.

Financing Activities

Financing cash flows generally are seasonal in nature and are impacted by the volatility in pricing in the natural gas and other energy markets. NJNG’s inventory levels are built up during its natural gas injection season (April through October) and reduced during withdrawal season (November through March) in response to the supply requirements of its customers. Changes in financing cash flows can also be impacted by gas management and marketing activities at Energy Services and clean energy investments at Clean Energy Ventures.

Cash flows used in financing activities during fiscal 2018 totaled $26 million, compared with cash flows from financing activities of $107.3 million during fiscal 2017. The increase of $133.3 million is due primarily to increased payments of short-term borrowings at NJR and long-term borrowings at NJNG, partially offset by an additional $125 million in long-term borrowings at NJNG, proceeds from the issuance of stock through our waiver discount plan and increased proceeds from solar sale-leasebacks.

Cash flows from financing activities during fiscal 2017 totaled $107.3 million, compared with $253.2 million during fiscal 2016. The increase of $145.9 million was due primarily to the issuance of $100 million of long-term debt compared with $275 million in the previous year, the purchase of three FMBs in lieu of redemption totaling $35.8 million at NJNG and $50 million redemption of long-term debt at NJR, partially offset by an increase in short-term borrowings at NJR and proceeds of $32.9 million from the solar sale-leasebacks at Clean Energy Ventures.

NJNG received $7.8 million, $9.6 million and $7.1 million for fiscal 2018, 2017 and 2016, respectively, in connection with the sale-leaseback of its natural gas meters. During fiscal 2018, 2017 and 2016, NJNG exercised early purchase options with respect to meter leases by making final principal payments of $2.2 million, $2.4 million and $1.9 million, respectively. NJNG continues to evaluate the natural gas meter sale-leaseback program based on current market conditions.

Credit Ratings

The table below summarizes NJNG’s current credit ratings issued by two rating entities, S&P and Moody’s, as of September 30, 2018:

	S&P	Moody’s
Corporate Rating	BBB+	N/A
Commercial Paper	A-2	P-1
Senior Secured	A	Aa2
Ratings Outlook	Negative	Negative

On January 19, 2018, Moody’s revised NJNG's rating outlook from stable to negative along with 23 other utility companies. This change reflects Moody’s view that tax reform is credit-negative for regulated utilities due to reduced cash collected from customers, while the loss of bonus depreciation reduces tax deferrals. The negative outlook also considers the uncertainty over timing of any regulatory actions or changes to corporate finance polices made to offset the financial impact. This action does not currently affect any of NJNG’s long-term borrowing rates. These ratings were reaffirmed by Moody’s on February 2, 2018.

On August 13, 2018, S&P lowered NJNG’s credit rating to BBB+ from A, senior secured debt rating to A from A+ and short-term and Commercial Paper rating to A-2 from A-1, and also reaffirmed NJNG's rating outlook that was changed on May 23, 2018, from stable to negative. S&P's negative outlook reflects NJNG's rising capital spending program, impacts of corporate tax reform and modestly higher use of debt leverage to fund NJR's growing midstream business. This action does not currently affect any of NJNG’s long-term borrowing rates or financial covenants. The impact on NJNG’s short-term borrowing rates was immaterial.

NJNG’s S&P and Moody’s ratings are investment-grade ratings. NJR is not a rated entity.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS (Continued)

Although NJNG is not party to any lending agreements that would accelerate the maturity date of any obligation caused by a failure to maintain any specific credit rating, if such ratings are downgraded below investment grade, borrowing costs could increase, as would the costs of maintaining certain contractual relationships and future financing, and our access to capital markets would be reduced. Even if ratings are downgraded without falling below investment grade, NJR and NJNG could face increased borrowing costs under their credit facilities. A rating set forth above is not a recommendation to buy, sell or hold NJR’s or NJNG’s securities and may be subject to revision or withdrawal at any time. Each rating set forth above should be evaluated independently of any other rating.

The timing and mix of any external financings will target a common equity ratio that is consistent with maintaining NJNG’s current short-term and long-term credit ratings.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                                              

Financial Risk Management

Commodity Market Risks

Natural gas is a nationally traded commodity. Its prices are determined effectively by the NYMEX, CME, ICE and over-the-counter markets. The prices on the NYMEX, CME, ICE and over-the-counter markets generally reflect the national balance of natural gas supply and demand, but are also significantly influenced from time to time by other events.

Our regulated and deregulated businesses are subject to market risk due to fluctuations in the price of natural gas. To economically hedge against such fluctuations, we have entered into forwards, futures, options and swap agreements. To manage these derivative instruments, we have well-defined risk management policies and procedures that include daily monitoring of volumetric limits and monetary guidelines. Our natural gas businesses are conducted through three of our reporting segments. NJNG is a regulated utility that uses futures, options and swaps to economically hedge against price fluctuations, and its recovery of natural gas costs is governed by the BPU. Energy Services uses futures, options, swaps and physical contracts to economically hedge purchases and sales of natural gas. Financial derivatives have historically been transacted on an exchange and cleared through an FCM, thus requiring daily cash margining for a majority of Energy Services’ and NJNG’s positions.

The following table reflects the changes in the fair market value of financial derivatives related to natural gas purchases and sales from September 30, 2017 to September 30, 2018:

	Balance				Increase				Less				Balance
(Thousands)	September 30, 2017				(Decrease) in Fair Market Value				Amounts Settled				September 30, 2018
Natural Gas Distribution		$	(1,149	)		$	(25	)		$	(1,268	)		$	94
Energy Services		(5,552		)		(22,571		)	(1)	(14,198		)		(13,925		)
Total		$	(6,701	)		$	(22,596	)		$	(15,466	)		$	(13,831	)

(1) Includes the addition of $9.5 million related to the fair value of the derivative instrument acquired through the disposition of NJRRS.

There were no changes in methods of valuations during the year ended September 30, 2018.

The following is a summary of fair market value of financial derivatives as of September 30, 2018, excluding foreign exchange contracts discussed below, by method of valuation and by maturity for each fiscal year period:

(Thousands)	2019			2020			2021 - 2023				After 2023			Total Fair Value
Price based on NYMEX/CME	$	4,425		$	1,880			$	721			$	—		$	7,026
Price based on ICE	(13,371		)	(7,263		)		(223		)		—			(20,857		)
Total	$	(8,946	)	$	(5,383	)		$	498			$	—		$	(13,831	)

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (Continued)                      

The following is a summary of financial derivatives by type at September 30, 2018:

		Volume Bcf		Price per MMBtu (1)	Amounts included in Derivatives (Thousands)
Natural Gas Distribution	Futures	27.9		2.28 - 3.05		$	94
Energy Services	Futures	(7.0	)	$1.48 - $5.93		(20,949		)
	Swaps	(17.3	)	2.72 - 3.46		7,024
Total						$	(13,831	)

(1) Million British thermal unit

The following table reflects the changes in the fair market value of physical commodity contracts from September 30, 2017 to September 30, 2018:

	Balance				Increase		Less		Balance
(Thousands)	September 30, 2017				(Decrease) in Fair Market Value		Amounts Settled		September 30, 2018
Natural Gas Distribution - Prices based on other external data		$	79			4,587		4,773		$	(107	)
Energy Services - Prices based on other external data		(3,584		)		277		14,570		(17,877		)
Total		$	(3,505	)		4,864		19,343		$	(17,984	)

The following table reflects the changes in the fair market value of interest rate contracts from September 30, 2017 to September 30, 2018:

	Balance				Increase		Less			Balance
(Thousands)	September 30, 2017				(Decrease) in Fair Market Value		Amounts Settled			September 30, 2018
Natural Gas Distribution - Prices based on other external data		$	(8,467	)		5,892		(2,575	)		$	—
Home Services and Other - Prices based on other external data		—				335		(46	)		381
Total		$	(8,467	)		6,227		(2,621	)		$	381

Foreign Currency Market Risks

The following table reflects the changes in the fair market value of financial derivatives related to foreign currency hedges from September 30, 2017 to September 30, 2018:

	Balance			Increase			Less			Balance
(Thousands)	September 30, 2017			(Decrease) in Fair Market Value			Amounts Settled			September 30, 2018
Energy Services		$	44		(379	)		(91	)		$	(244	)

There were no changes in methods of valuations during the fiscal year ended September 30, 2018.

The following is a summary of fair market value of financial derivatives related to foreign currency hedges as of September 30, 2018, by method of valuation and by maturity for each fiscal year period:

(Thousands)	2019			2020		2021 - 2023			After 2023		Total Fair Value
Prices based on other external data	$	(126	)	(84	)		(34	)		—		$	(244	)

Our market price risk is predominately related to changes in the price of natural gas at the Henry Hub, which is the delivery point for the NYMEX natural gas futures contracts. As the fair value of futures and fixed price swaps is linked to this location, the price sensitivity analysis has been prepared for all open Henry Hub natural gas futures and fixed swap positions. Based on this, an illustrative 10 percent movement in the natural gas futures contract price, for example, increases (decreases) the reported

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (Continued)                      

derivative fair value of all open, unadjusted Henry Hub natural gas futures and fixed swap positions by approximately $10.8 million. This analysis does not include potential changes to reported credit adjustments embedded in the $5.1 million reported fair value.

Derivative Fair Value Sensitivity Analysis
(Thousands)	Henry Hub Futures and Fixed Price Swaps
Percent increase in NYMEX natural gas futures prices	0%		5%			10%			15%			20%
Estimated change in derivative fair value	$	—	$	(5,414	)	$	(10,829	)	$	(16,243	)	$	(21,657	)
Ending derivative fair value	$	5,081	$	(333	)	$	(5,748	)	$	(11,162	)	$	(16,576	)
Percent decrease in NYMEX natural gas futures prices	0%		(5)%			(10)%			(15)%			(20)%
Estimated change in derivative fair value	$	—	$	5,414		$	10,829		$	16,243		$	21,657
Ending derivative fair value	$	5,081	$	10,495		$	15,910		$	21,324		$	26,738

Wholesale Credit Risk

Natural Gas Distribution and Energy Services engage in wholesale marketing activities and Clean Energy Ventures engages in SREC sales. We monitor and manage the credit risk of our operations through credit policies and procedures that management believes reduce overall credit risk. These policies include a review and evaluation of prospective counterparties’ financial statements and/or credit ratings, daily monitoring of counterparties’ credit limits, daily communication with traders regarding credit status and the use of credit mitigation measures, such as minimum margin requirements, collateral requirements and netting agreements. Examples of collateral include letters of credit and cash received for either prepayment or margin deposit.

Our Risk Management Committee continuously monitors our credit risk management policies and procedures and is composed of individuals from NJR-affiliated companies. The Risk Management Committee meets at least once a month and, among other things, evaluates the effectiveness of existing credit policies and procedures, reviews material transactions and discusses emerging issues.

The following is a summary of gross and net credit exposures, grouped by investment and non-investment grade counterparties, as of September 30, 2018. Gross credit exposure is defined as the unrealized fair value of derivative and energy trading contracts, plus any outstanding wholesale receivable for the value of natural gas or power delivered and/or financial derivative commodity contract that has settled for which payment has not yet been received. Net credit exposure is defined as gross credit exposure reduced by collateral received from counterparties and/or payables, where netting agreements exist. The amounts presented below exclude accounts receivable for NJNG retail natural gas sales and services.

Energy Services’ and Clean Energy Ventures’ counterparty credit exposure as of September 30, 2018, is as follows:

(Thousands)	Gross Credit Exposure			Net Credit Exposure
Investment grade		$	175,064		$	143,438
Noninvestment grade		43,419			10,648
Internally-rated investment grade		30,693			26,189
Internally-rated noninvestment grade		15,566			3,789
Total		$	264,742		$	184,064

NJNG’s counterparty credit exposure as of September 30, 2018, is as follows:

(Thousands)	Gross Credit Exposure			Net Credit Exposure
Investment grade		$	4,918		$	4,121
Noninvestment grade		67			—
Internally-rated investment grade		93			43
Internally-rated noninvestment grade		10,184			—
Total		$	15,262		$	4,164

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (Continued)                      

Due to the inherent volatility in the market price for natural gas, electricity 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 failed to perform the obligations under its contract (for example, failed to make payment for natural gas received), we could sustain a loss. This loss would comprise the loss on natural gas delivered but not paid for and/or the cost of replacing natural gas not delivered or received at a price that exceeds the original contract price. Any such loss could have a material impact on our financial condition, results of operations or cash flows.

Effects of Interest Rate and Foreign Currency Rate Fluctuations

We are also exposed to changes in interest rates on our debt hedges, variable rate debt and changes in foreign currency rates for our business conducted in Canada using Canadian dollars. We do not believe an immediate 10 percent increase or decrease in interest rates or foreign currency rates would have a material effect on our operating results or cash flows.

As of September 30, 2018, NJNG is obligated to make principal and interest payments under a loan agreement securing $97 million of variable rate debt issued by the EDA. The bonds are in a LIBOR-based monthly interest rate mode and will accrue interest for five years at a variable rate determined monthly, which was initially calculated at .55 percent plus 70 percent of one-month LIBOR. As of September 30, 2018, the EDA Bonds had a weighted average interest rate of 1.78 percent. The EDA Bonds are subject to changes in market conditions for tax-exempt bonds and there can be no assurance that the interest rate will remain stable and not increase significantly due to market conditions, which could adversely affect NJNG’s borrowing costs. A 100 basis point change in the EDA Bonds’ average interest rate would have caused a change in interest expense for these variable rate bonds by approximately $922,000 during fiscal 2018.

As of September 30, 2018, NJR is obligated to make principal and interest payments under a loan agreement securing $100 million of variable rate debt dated August 18, 2017. The term loan accrues interest at a variable rate determined monthly, which is LIBOR plus 70 basis points. On January 26, 2018, NJR entered into a variable-for-fixed interest rate swap on the variable rate term loan, which fixed the variable rate at 2.84 percent.

For more information regarding the interest rate risk related to our short-term debt, please see the Liquidity and Capital Resources - Debt section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Effects of Inflation

Although inflation rates have been relatively low to moderate in recent years, including the three most recent fiscal years, any change in price levels has an effect on operating results due to the capital-intensive and regulated nature of our utility subsidiary. We attempt to minimize the effects of inflation through cost control, productivity improvements and regulatory actions, when appropriate.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                                                                 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of New Jersey Resources Corporation is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) of the Securities and Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance to the Company’s Management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

Under the supervision and with the participation of the Company’s management, including its principal executive officer and principal financial officer, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018. In making this assessment, management used the criteria for effective internal control over financial reporting described in the Internal Control-Integrated Framework(2013) set forth by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management concluded that, as of September 30, 2018, the Company’s internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the Unites States of America.

The conclusion of the Company’s principal executive officer and principal financial officer is based on the recognition that there are inherent limitations in all systems of internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements, errors or fraud. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued its report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018, which appears herein.

November 20, 2018

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of New Jersey Resources Corporation:

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of New Jersey Resources Corporation and subsidiaries (the “Company”) as of September 30, 2018 and 2017, and the related consolidated statements of operations, comprehensive income, common stock equity, and cash flows, for each of the three years in the period ended September 30, 2018, and the related notes and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2018, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of September 30, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 20, 2018, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

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

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

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

November 20, 2018

We have served as the Company's auditor since 1951.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of New Jersey Resources Corporation:

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of New Jersey Resources Corporation and subsidiaries (the “Company”) as of September 30, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB),the consolidated financial statements and financial statement schedule as of and for the year ended September 30, 2018, of the Company and our report dated November 20, 2018, expressed an unqualified opinion on those financial statements and financial statement schedule.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

November 20, 2018

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                             

CONSOLIDATED STATEMENTS OF OPERATIONS

(Thousands, except per share data)
Fiscal years ended September 30,	2018			2017		2016
OPERATING REVENUES
Utility	$	731,865		$	695,637	$	594,346
Nonutility	2,183,244			1,572,980		1,286,559
Total operating revenues	2,915,109			2,268,617		1,880,905
OPERATING EXPENSES
Gas purchases:
Utility	276,005			258,687		205,034
Nonutility	1,990,832			1,436,740		1,139,301
Related parties	8,505			8,340		8,351
Operation and maintenance	266,919			226,356		208,421
Regulatory rider expenses	38,969			40,243		39,300
Depreciation and amortization	85,701			81,841		72,748
Energy and other taxes	52,102			49,366		40,215
Total operating expenses	2,719,033			2,101,573		1,713,370
OPERATING INCOME	196,076			167,044		167,535
Other income, net	16,853			14,437		9,196
Interest expense, net of capitalized interest	46,286			44,886		31,044
INCOME BEFORE INCOME TAXES AND EQUITY IN EARNINGS OF AFFILIATES	166,643			136,595		145,687
Income tax (benefit) provision	(53,785		)	18,343		23,530
Equity in earnings of affiliates	13,008			13,813		9,515
NET INCOME	$	233,436		$	132,065	$	131,672
EARNINGS PER COMMON SHARE
Basic	$2.66			$1.53		$1.53
Diluted	$2.64			$1.52		$1.52
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic	87,689			86,321		85,884
Diluted	88,315			87,144		86,731

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands)
Fiscal years ended September 30,	2018			2017		2016
Net income	$	233,436		$	132,065	$	131,672
Other comprehensive income, net of tax:
Unrealized (loss) gain on available for sale securities, net of tax of 6,973, $(4,401) and $1,499, respectively	(19,245		)	6,846		(2,187		)
Reclassifications of losses to net income on available for sale securities, net of tax of $(858), $0 and $0, respectively	11,647			—		—
Adjustment to postemployment benefit obligation, net of tax of $(573), $(3,487) and $2,466, respectively	1,520			5,053		(3,574		)
Other comprehensive (loss) income	(6,078		)	11,899		(5,761		)
Comprehensive income	$	227,358		$	143,964	$	125,911

(1) Available for sale securities are included in other noncurrent assets on the Consolidated Balance Sheets.

See Notes to Consolidated Financial Statements

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                             

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands)
Fiscal years ended September 30,	2018			2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	233,436		$	132,065		$	131,672
Adjustments to reconcile net income to cash flows from operating activities
Unrealized loss (gain) on derivative instruments	26,770			(11,241		)	46,883
Gain on sale of available for sale securities	(5,332		)	(7,287		)	—
Gain on sale of businesses	(4,663		)	—			—
Depreciation and amortization	85,701			81,841			72,748
Amortization of acquired wholesale energy contracts	18,222			762			—
Allowance for equity used during construction	(5,531		)	(3,867		)	(4,375		)
Allowance for doubtful accounts	2,579			2,023			1,616
Deferred income taxes	15,590			41,442			27,721
Deferred income tax benefit due to tax legislation	(75,736		)	—			—
Manufactured gas plant remediation costs	(16,171		)	(10,934		)	(8,106		)
Equity in earnings, net of distributions received from equity investees	(1,725		)	(462		)	4,534
Cost of removal - asset retirement obligations	(298		)	(484		)	(403		)
Contributions to postemployment benefit plans	(6,359		)	(6,077		)	(33,359		)
Tax benefit of delivered shares from stock based compensation	2,950			1,285			1,755
Changes in:
Components of working capital	97,004			17,081			(123,325		)
Other noncurrent assets	17,860			13,978			3,933
Other noncurrent liabilities	13,989			(2,079		)	21,336
Cash flows from operating activities	398,286			248,046			142,630
CASH FLOWS USED IN INVESTING ACTIVITIES
Expenditures for:
Utility plant	(206,880		)	(144,106		)	(176,067		)
Solar and wind equipment	(123,421		)	(149,400		)	(149,063		)
Midstream and other	(6,644		)	(2,434		)	(1,896		)
Cost of removal	(47,643		)	(32,143		)	(29,066		)
Acquisition of retail and wholesale energy contracts	—			(55,661		)	—
Investments in equity investees	(16,151		)	(27,070		)	(11,176		)
Distributions from equity investees in excess of equity in earnings	3,117			2,749			2,351
Cash paid related to acquisition	(10,000		)	—			—
(Deposits to) withdrawal from restricted cash construction fund	(9		)	1,322			979
Proceeds from sale of property, net of closing costs	—			9,443			748
Proceeds from sale of businesses, net of closing costs	27,916			—			—
Proceeds from sale of available for sale securities, net	6,616			6,639			—
Cash flows used in investing activities	(373,099		)	(390,661		)	(363,190		)
CASH FLOWS (USED IN) FROM FINANCING ACTIVITIES
Proceeds from long-term debt	225,000			100,000			275,000
Payments of long-term debt	(165,486		)	(97,854		)	(13,289		)
(Payments of) proceeds from short-term debt, net	(114,050		)	144,300			55,350
Proceeds from sale-leaseback transaction - solar	71,538			32,901			—
Proceeds from sale-leaseback transaction - gas meters	7,820			9,587			7,107
Payments of common stock dividends	(95,835		)	(87,988		)	(82,445		)
Proceeds from waiver discount issuance of common stock	41,677			—			—
Proceeds from issuance of common stock	17,136			17,492			16,010
Purchases of treasury stock	—			(6,355		)	(1,008		)
Tax withholding payments related to net settled stock compensation	(13,755		)	(4,788		)	(3,547		)
Cash flows (used in) from financing activities	(25,955		)	107,295			253,178
Change in cash and cash equivalents	(768		)	(35,320		)	32,618
Cash and cash equivalents at beginning of period	2,226			37,546			4,928
Cash and cash equivalents at end of period	$	1,458		$	2,226		$	37,546
CHANGES IN COMPONENTS OF WORKING CAPITAL
Receivables	$	(7,524	)	$	(56,974	)	$	11,303
Inventories	15,464			3,022			(45,986		)
Recovery of gas costs	30,439			(90		)	(39,642		)
Gas purchases payable	51,187			20,663			(11,963		)
Gas purchases payable - related parties	(1		)	2			(411		)
Prepaid and accrued taxes	1,254			10,366			2,385
Accounts payable and other	40,422			13,086			(15,656		)
Restricted broker margin accounts	(30,974		)	22,570			(38,752		)
Customers’ credit balances and deposits	368			(5,877		)	12,044
Other current assets	(3,631		)	10,313			3,353
Total	$	97,004		$	17,081		$	(123,325	)
SUPPLEMENTAL DISCLOSURES
Cash paid (received) for:
Interest (net of amounts capitalized)	$	44,821		$	44,362		$	31,996
Income taxes	$	5,577		$	(6,877	)	$	(3,516	)
Accrued capital expenditures	$	30,559		$	21,769		$	48,881
Inception gain on natural gas swap contract recognized as non-cash proceeds from sale of business	$	14,579		$	—		$	—
See Notes to Consolidated Financial Statements

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New Jersey Resources Corporation

Part II

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                             

CONSOLIDATED BALANCE SHEETS

ASSETS

(Thousands)
September 30,	2018			2017
PROPERTY, PLANT AND EQUIPMENT
Utility plant, at cost	$	2,368,914		$	2,241,324
Construction work in progress	192,481			119,318
Nonutility plant and equipment, at cost	697,406			843,142
Construction work in progress	45,690			7,286
Total property, plant and equipment	3,304,491			3,211,070
Accumulated depreciation and amortization, utility plant	(530,753		)	(489,122		)
Accumulated depreciation and amortization, nonutility plant and equipment	(122,689		)	(112,207		)
Property, plant and equipment, net	2,651,049			2,609,741
CURRENT ASSETS
Cash and cash equivalents	1,458			2,226
Customer accounts receivable:
Billed	205,490			196,467
Unbilled revenues	7,199			7,202
Allowance for doubtful accounts	(5,704		)	(5,181		)
Regulatory assets	18,297			50,791
Gas in storage, at average cost	184,633			202,063
Materials and supplies, at average cost	13,910			11,944
Prepaid and accrued taxes	23,047			24,764
Derivatives, at fair value	27,396			30,081
Restricted broker margin accounts	53,719			25,827
Asset held for sale	206,905			—
Other current assets	33,730			33,260
Total current assets	770,080			579,444
NONCURRENT ASSETS
Investments in equity investees	190,866			172,585
Regulatory assets	368,592			375,919
Derivatives, at fair value	10,560			9,164
Available for sale securities	32,917			65,752
Intangible assets	23,375			41,084
Other noncurrent assets	96,225			74,818
Total noncurrent assets	722,535			739,322
Total assets	$	4,143,664		$	3,928,507

See Notes to Consolidated Financial Statements

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New Jersey Resources Corporation

Part II

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                             

CAPITALIZATION AND LIABILITIES

(Thousands, except share data)
September 30,	2018			2017
CAPITALIZATION
Common stock, $2.50 par value; authorized 150,000,000 shares; Outstanding September 30, 2018 — 88,292,956; September 30, 2017 — 86,555,507	$	226,196		$	222,258
Premium on common stock	274,748			219,696
Accumulated other comprehensive loss, net of tax	(12,610		)	(3,256		)
Treasury stock, at cost and other; Shares September 30, 2018 — 2,185,013; September 30, 2017 — 2,347,380	(76,473		)	(70,039		)
Retained earnings	1,007,117			867,984
Common stock equity	1,418,978			1,236,643
Long-term debt	1,180,619			997,080
Total capitalization	2,599,597			2,233,723
CURRENT LIABILITIES
Current maturities of long-term debt	123,545			165,375
Short-term debt	151,950			266,000
Gas purchases payable	211,303			160,115
Gas purchases payable to related parties	1,150			1,152
Accounts payable and other	135,240			96,878
Dividends payable	25,824			23,586
Accrued taxes	1,568			2,031
Regulatory liabilities	8,185			78
New Jersey Clean Energy Program	14,052			14,202
Derivatives, at fair value	46,652			46,544
Liabilities held for sale	4,182			—
Customers’ credit balances and deposits	27,325			26,957
Total current liabilities	750,976			802,918
NONCURRENT LIABILITIES
Deferred income taxes	242,436			514,708
Deferred investment tax credits	3,976			4,297
Deferred gain	9,104			27,728
Derivatives, at fair value	22,982			11,330
Manufactured gas plant remediation	130,800			149,000
Postemployment employee benefit liability	137,007			128,888
Regulatory liabilities	209,139			14,507
Asset retirement obligation	28,688			31,420
Other noncurrent liabilities	8,959			9,988
Total noncurrent liabilities	793,091			891,866
Commitments and contingent liabilities (Note 13)
Total capitalization and liabilities	$	4,143,664		$	3,928,507

See Notes to Consolidated Financial Statements

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New Jersey Resources Corporation

Part II

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                             

CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY

(Thousands)	Number of Shares		Common Stock		Premium on Common Stock			Accumulated Other Comprehensive (Loss) Income				Treasury Stock And Other			Retained Earnings			Total
Balance at September 30, 2015	85,531		$	220,838	$	209,931			$	(9,394	)	$	(92,164	)	$	777,745		$	1,106,956
Net income															131,672			131,672
Other comprehensive loss									(5,761		)							(5,761		)
Common stock issued:
Incentive compensation plan	325		816		8,583													9,399
Dividend reinvestment plan (1)	471				(2,879		)					18,942						16,063
Cash dividend declared ($.975 per share)															(83,861		)	(83,861		)
Treasury stock and other	(241	)			(55		)					(7,822		)				(7,877		)
Balance at September 30, 2016	86,086		221,654		215,580				(15,155		)	(81,044		)	825,556			1,166,591
Net income															132,065			132,065
Other comprehensive income									11,899									11,899
Common stock issued:
Incentive compensation plan	241		604		5,090													5,694
Dividend reinvestment plan (1)	472				(946		)					18,568						17,622
Cash dividend declared ($1.0375 per share)															(89,637		)	(89,637		)
Treasury stock and other	(243	)			(28		)					(7,563		)				(7,591		)
Balance at September 30, 2017	86,556		222,258		219,696				(3,256		)	(70,039		)	867,984			1,236,643
Net income															233,436			233,436
Other comprehensive loss									(6,078		)							(6,078		)
Common stock issued:
Incentive compensation plan	561		1,403		15,169													16,572
Dividend reinvestment plan (1)	413				755							16,339						17,094
Waiver discount	1,014		2,535		39,142													41,677
Cash dividend declared ($1.11 per share)															(97,579		)	(97,579		)
Treasury stock and other	(251	)			(14		)					(22,773		)				(22,787		)
Reclassifications of certain income tax effects to retained earnings (2)									(3,276		)				3,276			—
Balance at September 30, 2018	88,293		$	226,196	$	274,748			$	(12,610	)	$	(76,473	)	$	1,007,117		$	1,418,978

(1) Shares sold through the DRP are issued from treasury stock at average cost, which may differ from the actual market price paid.

(2) Due to the adoption of ASU No. 2018-02, an amendment to ASC 740, Income Taxes. See Note 2. Summary of Significant Accounting Policies - Recently Adopted Updates to the Accounting Standards Codification section for more details.

See Notes to Consolidated Financial Statements

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New Jersey Resources Corporation

Part II

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

1. NATURE OF THE BUSINESS

New Jersey Resources Corporation provides regulated gas distribution services and operates certain unregulated businesses primarily through the following:

New Jersey Natural Gas Company provides natural gas utility service to approximately 538,700 retail customers in central and northern New Jersey and is subject to rate regulation by the BPU. NJNG comprises the Natural Gas Distribution segment.

NJR Clean Energy Ventures Corporation, the Company's clean energy subsidiary, comprises the Clean Energy Ventures segment and consists of the Company's capital investments in commercial and residential solar projects located throughout New Jersey and onshore wind investments in Iowa, Kansas, Wyoming and Pennsylvania. On June 1, 2018, Clean Energy Ventures completed the sale of its membership interest in a 9.7 MW wind farm in Two Dot, Montana. See Note 17. Dispositions for more details regarding the sale.

NJR Energy Services Company comprises the Energy Services segment. Energy Services maintains and transacts around a portfolio of natural gas storage and transportation capacity contracts and provides physical wholesale energy and energy management services in the U.S. and Canada. From July 2017 through February 2018, NJR Retail Services Company provided retail natural gas supply and transportation services to commercial and industrial customers in Delaware, Maryland, Pennsylvania and New Jersey as part of the Energy Services segment. NJRRS was sold to an unrelated third party on February 28, 2018. See Note 17. Dispositions for more details regarding the sale.

NJR Midstream Holdings Corporation, which comprises the Midstream segment, invests in energy-related ventures through its subsidiaries, NJR Steckman Ridge Storage Company, which holds the Company's 50 percent combined ownership interest in Steckman Ridge, located in Pennsylvania; NJNR Pipeline, which holds our DM Common Units; and NJR Pipeline Company, which includes Adelphia Gateway, LLC and the Company's 20 percent ownership interest in PennEast. See Note 6. Investments in Equity Investeesfor more information.

NJR Retail Holdings Corporation has two principal subsidiaries: NJR Home Services Company, which provides heating, central air conditioning, standby generators, solar and other indoor and outdoor comfort products to residential homes throughout New Jersey; and Commercial Realty & Resources Corporation, which owns commercial real estate. NJR Home Services Company and Commercial Realty & Resources Corporation are included in Home Services and Other operations.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Consolidated Financial Statements include the accounts of the Company and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated.

Other financial investments or contractual interests that lack the characteristics of a voting interest entity, which are commonly referred to as variable interest entities, are evaluated by the Company to determine if 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, 2018, 2017 and 2016.

Investments in entities over which the Company does not have a controlling financial interest are either accounted for under the equity method or cost method of accounting.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires the Company to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a 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, investments, 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. AROs are evaluated as often as needed. The Company’s estimates are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources.

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New Jersey Resources Corporation

Part II

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

The Company has legal, regulatory and environmental proceedings during the normal course of business that can result in loss contingencies. When evaluating the potential for a loss, the Company will establish a reserve if a loss is probable and can be reasonably estimated, in which case it is the Company’s policy to accrue the full amount of such estimates. Where the information is sufficient only to establish a range of probable liability, and no point within the range is more likely than any other, it is the Company’s policy to accrue the lower end of the range. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from estimates.

Business Combinations

The Company accounts for business combinations by applying the acquisition method of accounting. Identifiable assets acquired and liabilities assumed are measured separately at their fair value as of the acquisition date and associated transactions costs are expensed as incurred.

The determination and allocation of fair values to the identifiable assets acquired and liabilities assumed are based on various assumptions and valuation methodologies requiring considerable management judgment. The most significant variables in these valuations are discount rates and the number of years on which to base the cash flow projections, as well as other assumptions and estimates used to determine the cash inflows and outflows. Management determines discount rates based on the risk inherent in the acquired assets and related cash flows. Our valuation of an acquired business is based on available information at the acquisition date and assumptions that we believe are reasonable. However, a change in facts and circumstances as of the acquisition date can result in subsequent adjustments during the measurement period, but no later than one year from the acquisition date.

Revenues

Revenues from the sale of natural gas to NJNG customers are recognized in the period that gas is delivered and consumed by customers, including an estimate for unbilled revenue.

NJNG records unbilled revenue for natural gas services. Natural gas sales to individual customers are based on meter readings, which are performed on a systematic basis throughout the month. At the end of each month, the amount of natural gas delivered to each customer after the last meter reading through the end of the respective accounting period is estimated, and recognizes unbilled revenues related to these amounts. The unbilled revenue estimates are based on estimated customer usage by customer type, weather effects, unaccounted-for gas and the most current tariff rates.

Clean Energy Ventures recognizes revenue when SRECs are transferred to counterparties. SRECs are physically delivered through the transfer of certificates as per contractual settlement schedules.

Revenues for Energy Services are recognized when the natural gas is physically delivered to the customer. In addition, changes in the fair value of derivatives that economically hedge the forecasted sales of the natural gas are recognized in operating revenues as they occur, as noted above. Energy Services also recognizes changes in the fair value of SREC derivative contracts as a component of operating revenues.

Revenues from all other activities are recorded in the period during which products or services are delivered and accepted by customers, or over the related contractual term.

Gas Purchases

NJNG’s tariff includes a component for BGSS, which is designed to allow it to recover the cost of natural gas through rates charged to its customers and is typically revised on an annual basis. As part of computing its BGSS rate, NJNG projects its cost of natural gas, net of supplier refunds, the impact of hedging activities and cost savings created by BGSS incentive programs. NJNG subsequently recovers or credits the difference, if any, of actual costs compared with those included in current rates. Any underrecoveries or overrecoveries are either credited to customers or deferred and, subject to BPU approval, reflected in the BGSS rates in subsequent years.

Gas purchases at Energy Services are composed of gas costs to be paid upon completion of a variety of transactions, as well as realized gains and losses from settled derivative instruments and unrealized gains and losses on the change in fair value of derivative instruments that have not yet settled. Changes in the fair value of derivatives that economically hedge the forecasted purchases of natural gas are recognized in gas purchases as they occur.

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New Jersey Resources Corporation

Part II

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Demand Fees

For the purpose of securing storage and pipeline capacity in support of their respective businesses, the Energy Services and Natural Gas Distribution segments enter into storage and pipeline capacity contracts, which require the payment of associated demand fees and charges that allow them access to a high priority of service in order to maintain the ability to access storage or pipeline capacity during a fixed time period, which generally ranges from one to 10 years. Many of these demand fees and charges are based on established tariff rates as established and regulated by FERC. These charges represent commitments to pay storage providers and pipeline companies for the priority right to transport and/or store natural gas utilizing their respective assets.

The following table summarizes the demand charges, which are net of capacity releases, and are included as a component of gas purchases on the Consolidated Statements of Operations for the fiscal years ended September 30:

(Millions)	2018		2017		2016
Energy Services	$	153.0	$	126.4	$	141.0
Natural Gas Distribution	92.5		80.2		77.8
Total	$	245.5	$	206.6	$	218.8

Energy Services expenses demand charges over the term of the service being provided.

The Natural Gas Distribution segment’s costs associated with demand charges are included in its weighted average cost of gas. The demand charges are expensed based on NJNG’s BGSS sales and recovered as part of its gas commodity component of its BGSS tariff.

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, 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 NJR Board of Directors members. 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 9. Stock-Based Compensation for further information.

Sales Tax Accounting

Sales tax that is collected from customers is presented in both operating revenues and operating expenses on the Consolidated Statements of Operations. During fiscal 2018, 2017 and 2016, sales tax collected was $41.7 million, $39.4 million and $31 million, respectively. Effective January 1, 2017, the New Jersey sales tax rate decreased from 7 percent to 6.875 percent. Effective January 1, 2018, the New Jersey sales tax rate decreased again to 6.625 percent.

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.

The Company invests in property that qualifies for federal ITCs and utilizes the ITCs, as allowed, based on the cost and life of the assets. ITCs at NJNG are deferred and amortized as a reduction to the tax provision over the average lives of the related equipment in accordance with regulatory treatment. ITCs at the unregulated subsidiaries of NJR are recognized as a reduction to income tax expense when the property is placed in service. The Company invests in property that qualifies for PTCs. PTCs are recognized as reductions to current federal income tax expense as PTCs are generated through the production activities of the assets. Changes to the federal statutes related to ITCs and PTCs, which have the effect of reducing or eliminating the credits, could have a negative impact on earnings and cash flows.

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New Jersey Resources Corporation

Part II

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Investments in Equity Investees

The Company accounts for its investments in Steckman Ridge and PennEast, using the equity method of accounting where its respective ownership interests are 50 percent or less and/or it has significant influence over operating and management decisions, but is not the primary beneficiary, as defined under ASC 810, Consolidation. The Company’s share of earnings is recognized as equity in earnings of affiliates on the Consolidated Statements of Operations. See Note 6. Investments in Equity Investeesfor more information.

Property Plant and Equipment

Regulated property, plant and equipment is stated at original cost. Costs include direct labor, materials and third-party construction contractor costs, AFUDC and certain indirect costs related to equipment and employees engaged in construction. Nonregulated property, plant and equipment is stated at original cost. Costs include direct labor, materials and third-party construction contractor costs and certain indirect costs related to equipment and employees engaged in construction. 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 unregulated entities, and using rates based on the estimated average lives of the various classes of depreciable property for NJNG. The composite rate of depreciation used for NJNG was 2.29 percent of average depreciable property in fiscal 2018, 2.25 percent in fiscal 2017 and 2.32 percent in fiscal 2016. The Company recorded $85.7 million, $81.8 million and $72.7 million in depreciation expense during fiscal 2018, 2017 and 2016, respectively. Effective October 1, 2016, the overall depreciation rate is 2.4 percent, as settled in the base rate case.

Property, plant and equipment was comprised of the following as of September 30:

(Thousands)
Property Classifications	Estimated Useful Lives	2018			2017
Distribution facilities	38 to 74 years	$	2,151,249		$	1,952,697
Transmission facilities	35 to 56 years	295,692			294,586
Storage facilities	34 to 47 years	79,470			78,245
Solar property	20 to 25 years	720,562			587,345
Wind property(1)	17 to 25 years	—			244,764
Midstream property(2)	30 years	6,747			—
All other property	5 to 35 years	50,771			53,433
Total property, plant and equipment		3,304,491			3,211,070
Accumulated depreciation and amortization		(653,442		)	(601,329		)
Property, plant and equipment, net		$	2,651,049		$	2,609,741

(1) Reclassified to assets held for sale. See Note 2. Summary of Significant Accounting Policies, for more information.

(2) Includes activity related to the acquisition of IEC by Adelphia. For fiscal 2017, Midstream property was originally included in All other property.

In March 2017, CR&R sold a 56,400-square-foot office building on five acres of land located in Monmouth County for $9.4 million, net of closing costs, generating a pre-tax gain of $1.9 million, which was recognized as a reduction to O&M on the Consolidated Statements of Operations.

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 3. 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.

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New Jersey Resources Corporation

Part II

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Capitalized and deferred interest include the following for the fiscal years ended September 30:

($ in thousands)	2018			2017			2016
AFUDC:
Debt	$	1,979		$	1,311		$	5,009
Equity	5,531			3,867			4,375
Total	$	7,510		$	5,178		$	9,384
Weighted average interest rate	5.94		%	6.90		%	5.06		%

Pursuant to a BPU order, NJNG is permitted to recover carrying costs on uncollected balances related to SBC program costs, which include NJCEP, RAC and USF expenditures. See Note 3. Regulation. The SBC interest rate changes each September based on the August 31 seven-year constant maturity treasury rate plus 60 basis points. The rate was 3.41 percent, 2.55 percent and 2.05 percent for the fiscal years ended September 30, 2018, 2017 and 2016, respectively. Accordingly, other income included $411,000, $78,000 and $54,000 in the fiscal years ended September 30, 2018, 2017 and 2016, respectively.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash on deposit and temporary investments with maturities of three months or less, and excludes restricted cash of $252,000 and $243,000 as of September 30, 2018 and 2017, respectively, related to escrow balances for utility plant projects, which is recorded in other current and noncurrent assets on the Consolidated Balance Sheets.

Customer Accounts Receivable and Allowance for Doubtful Accounts

Receivables consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers, as well as equipment sales, installations, solar leases and PPAs to commercial and residential customers. The Company evaluates its accounts receivables and, to the extent customer account balances are outstanding for more than 60 days, establishes an allowance for doubtful accounts. The allowance is based on a combination of factors including historical collection experience and trends, aging of receivables, general economic conditions in the Company’s distribution or sales territories and customer-specific information. The Company writes-off customer accounts once it is determined they are uncollectible.

The following table summarizes customer accounts receivable by company as of September 30:

(Thousands)	2018				2017
Energy Services	$	157,936	77	%	$	150,322	77	%
Natural Gas Distribution (1)	39,151		19		37,432		19
Clean Energy Ventures	3,330		2		2,655		1
Home Services and Other Operations	5,073		2		6,058		3
Total	$	205,490	100	%	$	196,467	100	%

(1) Does not include unbilled revenues of $7.2 million as of September 30, 2018 and 2017.

Loans Receivable

NJNG currently provides loans, with terms ranging from three to 10 years, to customers that elect to purchase and install certain energy-efficient equipment in accordance with its BPU-approved SAVEGREEN program. The loans are recognized at net present value on the Consolidated Balance Sheets. The Company has recorded $10.4 million and $8.9 million in other current assets and $39.5 million and $40.4 million in other noncurrent assets as of September 30, 2018 and 2017, respectively, on the Consolidated Balance Sheets, related to the loans. If NJNG determines a loan is impaired, the basis of the loan would be subject to regulatory review for recovery. As of September 30, 2018 and 2017, the Company has not recorded an allowance for doubtful accounts for SAVEGREEN loans.

Regulatory Assets & Liabilities

Under cost-based regulation, regulated utility enterprises generally are permitted to recover their operating expenses and earn a reasonable rate of return on their utility investment.

Our Natural Gas Distribution segment maintains its accounts in accordance with the FERC Uniform System of Accounts as prescribed by the BPU and in accordance with the ASC 980, Regulated Operations. As a result of the impact of the ratemaking process and regulatory actions of the BPU, NJNG is required to recognize the economic effects of rate regulation. Accordingly, NJNG capitalizes or defers certain costs that are expected to be recovered from its customers as regulatory assets and recognizes certain obligations representing probable future expenditures as regulatory liabilities on the Consolidated Balance Sheets. See Note 3. Regulation for a more detailed description of NJNG’s regulatory assets and liabilities.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Gas in Storage

Gas in storage is reflected at average cost on the Consolidated Balance Sheets and represents natural gas and LNG that will be utilized in the ordinary course of business.

The following table summarizes gas in storage, at average cost by company, as of September 30:

	2018				2017
($ in thousands)	Gas in Storage			Bcf	Gas in Storage			Bcf
Energy Services		$	90,166	34.1		$	122,884	53.9
Natural Gas Distribution		94,467		24.9		79,179		21.8
Total		$	184,633	59.0		$	202,063	75.7

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 Energy Services, as derivatives, and therefore recognizes them at fair value on the Consolidated Balance Sheets. The Company’s unregulated subsidiaries record changes in the fair value of their financial commodity derivatives in gas purchases and changes in the fair value of their physical forward contracts in gas purchases or operating revenues, as appropriate, on the Consolidated Statements of Operations. Ineffective portions of the cash flow hedges are recognized immediately in earnings.

The ASC 815, Derivatives and Hedging also provides for a NPNS scope exception for qualifying physical commodity contracts that are intended for purchases and sales during the normal course of business and for which physical delivery is probable. Effective January 1, 2016, the Company prospectively applies this normal scope exception on a case-by-case basis to physical commodity contracts at NJNG and forward SREC contracts at Clean Energy Ventures. When applied, it does not record changes in the fair value of these contracts until the contract settles and the related underlying natural gas or SREC is delivered. Gains and/or losses on NJNG’s derivatives used to economically hedge its regulated natural gas supply obligations, as well as its exposure to interest rate variability, are recoverable through its BGSS, a component of its tariff. Accordingly, the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability on the Consolidated Balance Sheets.

See Note 4. 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 Energy Services 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.

Assets Held for Sale

The Company classifies an asset as held for sale if there is a commitment to sell the asset, the asset is available for immediate sale, the sale is probable and the sale will be completed within one year. In March 2018, Clean Energy Ventures committed to a plan to sell its wind assets and expects that the sale will be completed within the next 12 months. Accordingly, the Company classified its wind assets and related liabilities as held for sale on the Consolidated Balance Sheets, which resulted in depreciation expense on wind assets no longer being recorded.

The wind assets classified as held for sale are measured at the lower of their carrying value or fair value less cost to sell. At September 30, 2018, the Company performed a fair value assessment of its wind assets held for sale. The Company equally weighted the valuation derived from an income approach and a market approach to determine fair value. The Company believes that the estimates and assumptions used in calculating the fair value of our assets and liabilities held for sale are reasonable and appropriate based on the information that was known when the estimates were made. The Company concluded that the fair value of the wind assets was greater than the carrying value and thus no impairment was recorded.

On June 1, 2018, Clean Energy Ventures completed the sale of its membership interest in a 9.7 MW wind farm in Two Dot, Montana. See Note 17. Dispositions for more details.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

The major classes of assets and liabilities included within the disposal group as held for sale are as follows:

(Thousands)	September 30, 2017		Assets reclassified as held for sale			Assets Sold			September 30, 2018
Assets held for sale:
Property, plant and equipment - wind equipment, at cost	$	—	$	245,044		$	(20,688	)	$	224,356
Property, plant and equipment - accumulated depreciation, wind equipment	—		(21,561		)	3,060			(18,501		)
Prepaid and accrued taxes	—		866			(77		)	789
Other noncurrent assets	—		261			—			261
	$	—	$	224,610		$	(17,705	)	$	206,905
Liabilities held for sale:
Accounts payable and other (1)	$	—	$	—		$	186		$	186
Asset retirement obligation	—		4,262			(266		)	3,996
	$	—	$	4,262		$	(80	)	$	4,182

(1) Transaction fee owed to broker for the sale of Two Dot wind farm.

Available for Sale Securities

Available for sale securities are carried at fair value on the Consolidated Balance Sheets. For fiscal years ended September 30, 2018 and prior, total unrealized gains and losses associated are included as a part of accumulated other comprehensive income, a component of common stock equity. Reclassifications of realized gains or losses out of other comprehensive income into earnings are recorded in other income, net on the Consolidated Statements of Operations based on average cost.

Management evaluates its equity securities for other-than-temporary impairment on a quarterly basis, and more frequently when economic, market or other concerns warrant such evaluation. Consideration is given to the length of time and the extent to which the fair value has been less than cost; the financial condition and near term prospects of the issuer; whether the market decline was affected by macroeconomic conditions, changes in tax laws, regulations or other governmental policies; and whether the Company has the intent to sell the security or more likely than not will be required to sell the security before the recovery of its amortized cost basis. If the decline in value of our equity securities is determined to be other-than-temporary, an impairment is recognized through earnings within other income, net on the Consolidated Statements of Operations.

During fiscal 2018, NJR sold shares of its available for sale securities and received proceeds of approximately $6.6 million and realized a pre-tax gain of approximately $5.3 million, which is included in other income, net on the Consolidated Statements of Operations, or $3.2 million, net of tax. During fiscal 2017, NJR received proceeds of approximately $6.6 million and realized a pre-tax gain of $5.4 million, or $3.2 million, net of tax. Reclassifications of realized gains out of other comprehensive income into income are determined based on average cost.

DM Units

In September 2015, the Company exchanged its ownership interest in Iroquois for approximately 1.84 million DM Common Units. The investment in DM is included as part of the Company's equity investments in the Midstream segment. The exchange of ownership interests in Iroquois for DM was considered a contribution of real estate into another real estate venture. As a result, the Company recorded a deferred gain of $24.6 million on the Consolidated Balance Sheets, based on the difference between the carrying amount of its investment in Iroquois and the fair value of the DM Common Units on the closing date of the transaction. The deferred gain will be recognized in other income, net on the Consolidated Statements of Operations upon completion of the earnings process, typically through the sale of the related securities, or other earnings event.

On March 15, 2018, the FERC issued a policy revision indicating that it no longer will allow interstate natural gas and oil pipelines held by a MLP to recover an income tax allowance in cost-of-service rates. The policy revision had a material negative impact on the value of NJR's investment in DM Common Units. As a result, the Company evaluated the decrease in fair value of its available for sale securities and determined that the decline was other-than-temporary. Accordingly, the Company recognized an other-than-temporary impairment of $17.8 million, or $14.8 million, net of tax, as of March 31, 2018.

Since the deferred gain was established based upon the difference in the fair value of the DM Common Units acquired and the carrying value of the ownership of Iroquois, concurrent with the impairment charge to earnings, the Company reduced the amount of the deferred gain for the DM Common Units. This reduction of the deferred gain of $17.8 million was also recorded in other income, net on the Consolidated Statements of Operations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

On July 18, 2018, the FERC finalized its March 15, 2018 policy regarding the tax treatment of MLP pipelines. Natural gas pipelines within an MLP structure, where the parent is a taxable entity and consolidates the financial results of the MLP on its federal income tax return, will be allowed to include an income tax allowance in its cost-of-service rates.

As of September 30, 2018, the Company's available for sale securities had a fair value of $32.9 million and total unrealized gains were $4.7 million, or $3.4 million, net of deferred income tax benefit. The remaining deferred gain associated with the Company’s investment in DM Common Units totaled $6.8 million. As of September 30, 2017, the Company's available for sale securities had a fair value of $65.8 million and total unrealized gains were $12.8 million, or $7.7 million, net of deferred income tax expense.

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, 2018, intangible assets consist of internal-use software costs of $513,000 and $22.9 million, net of amortization, related to its acquisition of Talen’s wholesale natural gas energy contracts. These contracts are being amortized based upon expected cash flows over the respective terms of the agreements. The estimated future amortization expense for the next five years as of September 30, is as follows:

(Thousands)
2019	$	8,424
2020	$	4,925
2021	$	4,604
2022	$	2,561
2023	$	2,271
Thereafter	$	77

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. During the year, the Company evaluated whether there were such events or circumstances that occurred, including evaluation of the new clean energy legislation signed in May 2018, and concluded that there were no events or circumstances in the current year that indicated that the carrying value of long-lived assets or finite-lived intangibles is 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 8. 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 at the end of the term or repurchase the asset. Proceeds from sale-leaseback transactions are accounted for as financings and are included in long-term debt on the Consolidated Balance Sheets. During fiscal 2018 and 2017, NJNG received $7.8 million and $9.6 million, respectively, in connection with the sale-leaseback of its natural gas meters with terms ranging from seven to 11 years.

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 terms of the arrangement create a continuing involvement in the asset and the asset is

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

considered integral equipment, the Company uses the financing method to account for the transaction. Under the financing method, the Company recognizes the proceeds received from the lessor that constitute a payment to acquire the solar energy asset as a financing arrangement, which is recorded as a component of debt on the Consolidated Balance Sheets.

Clean Energy Ventures received $71.5 million and $32.9 million in proceeds related to the sale of commercial solar assets during fiscal 2018 and 2017, respectively. Clean Energy Ventures simultaneously entered into agreements to lease the assets back over six to 15-year terms. The Company will continue to operate the solar assets and is responsible for related expenses and entitled to retain the revenue generated from SRECs and energy sales. The ITCs and other tax benefits associated with these solar projects have been transferred to the buyer; however, the lease payments are structured so that Clean Energy Ventures is compensated for the transfer of the related tax incentives. Accordingly, Clean Energy Ventures recognizes the equivalent value of the ITC 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. Clean Energy Ventures did not enter into sale-leaseback during fiscal 2016 and therefore recognized the full ITC in income tax (benefit) provision on the Consolidated Statements of Operations when the assets were placed in service.

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 the 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 13. 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 Income Security Act, as amended, and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments. The Company made a discretionary contribution of $30 million during the first quarter of fiscal 2016 to improve the funded status of the pension plans based on the current actuarial assumptions, which included the adoption of the most recent mortality table. The Company made no discretionary contributions to the pension plans in fiscal 2018 and 2017.

The Company also provides two primarily noncontributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. The Company contributed $6.2 million, $6 million and $3.2 million in aggregate to these plans in fiscal 2018, 2017 and 2016, respectively, which is recorded in postemployment employee benefit liability on the Consolidated Balance Sheets.

See Note 10. Employee Benefit Plans, for a more detailed description of the Company’s pension and postemployment plans.

Asset Retirement Obligations

The Company recognizes AROs related to the costs associated with cutting and capping NJNG’s main and service gas distribution mains, which is required by New Jersey law when taking such gas distribution mains out of service. The Company also recognizes AROs associated with Clean Energy Ventures’ solar and wind assets when there are decommissioning provisions in lease agreements that require removal of the asset at the end of the lease term.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

AROs 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 Clean Energy Ventures’ 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 AROs 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 assign probabilities based on management’s reasonable judgment and knowledge of industry practice. Accordingly, AROs are subject to change.

Accumulated Other Comprehensive Income

The following table presents the changes in the components of accumulated other comprehensive income, net of related tax effects, as of September 30:

(Thousands)	Unrealized gain (loss) on available for sale securities			Adjustment to postemployment benefit obligation				Total
Balance as of September 30, 2016	$	4,198		$	(19,353	)		$	(15,155	)
Other comprehensive income, net of tax
Other comprehensive income, before reclassifications, net of tax of $(6,593), $(2,619), $(9,212)	10,019			3,783				13,802
Amounts reclassified from accumulated other comprehensive (loss) income, net of tax of $2,192, $(868), $1,324	(3,173		)	1,270			(1)	(1,903		)
Net current-period other comprehensive income, net of tax of $(4,401), $(3,487), $(7,888)	6,846			5,053				11,899
Balance at September 30, 2017	$	11,044		$	(14,300	)		$	(3,256	)
Other comprehensive income, net of tax
Other comprehensive (loss) income, before reclassifications, net of tax of $6,973, $(125), $6,848	(19,245		)	464				(18,781		)
Amounts reclassified from accumulated other comprehensive income, net of tax of $(858), $(448), $(1,306)	11,647			1,056			(1)	12,703
Net current-period other comprehensive (loss) income, net of tax of $6,115, $(573), $5,542	(7,598		)	1,520				(6,078		)
Reclassifications of certain income tax effects to retained earnings (2)	—			(3,276		)		(3,276		)
Balance at September 30, 2018	$	3,446		$	(16,056	)		$	(12,610	)

(1) Included in the computation of net periodic pension cost, a component of O&M expense on the Consolidated Statements of Operations. For more details, see Note 10. Employee Benefit Plans.

(2) Due to the adoption of ASU No. 2018-02, an amendment to ASC 740, Income Taxes. See Note 2. Summary of Significant Accounting Policies- Recently Adopted Updates to the Accounting Standards Codification section for more details.

Foreign Currency Transactions

The market area of Energy Services includes Canadian delivery points and as a result, Energy Services incurs certain natural gas commodity costs and demand fees denominated in Canadian dollars. Gains or losses that occur as a result of these foreign currency transactions are reported as a component of gas purchases on the Consolidated Statements of Operations. Gains and losses recognized for the fiscal years ended September 30, 2018, 2017 and 2016, are considered immaterial.

Reclassification

Certain prior period amounts related to the amortization of acquired wholesale energy contracts on the Consolidated Statements of Cash Flows and in the deferred tax table in Note 12. Income Taxes for the fiscal year ended September 30, 2017, were reclassified to conform to the current period presentation.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Recently Adopted Updates to the Accounting Standards Codification

Inventory

In July 2015, the FASB issued ASU No. 2015-11, an amendment to ASC 330, Inventory, which requires entities to measure most inventory “at the lower of cost or net realizable value,” thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. The Company adopted the new guidance in the first quarter of fiscal 2018 and applied the new provisions on a prospective basis, which did not impact its financial position, results of operations or cash flows upon adoption.

Reporting Comprehensive Income

In February 2018, the FASB issued ASU No. 2018-02, an amendment to ASC 220, Income Statement - Reporting Comprehensive Income, which allows for the reclassification from accumulated other comprehensive income to retained earnings for the disproportionate tax effects of the Tax Act. The Company early adopted this guidance in the fourth quarter of fiscal 2018 and reclassified on a prospective basis only, $3.3 million from accumulated other comprehensive income to retained earnings. This did not materially impact the Company’s financial position, results of operations or cash flows.

Tax

In March 2018, the FASB issued ASU No. 2018-05, an amendment to ASC 740, Income Taxes, which provides relief to entities in their calculation of the effects of the Tax Act by allowing them to record provisional amounts for certain income tax effects to address circumstances in which an entity does not have the necessary information available, prepared or analyzed to complete the accounting. These provisional amounts are subject to change as information and assumptions are updated throughout the measurement period, which may not extend beyond one year from the enactment date. The new guidance was effective immediately upon issuance, and the Company adopted the new guidance in the second quarter of fiscal 2018 and applied the new provision on a prospective basis.

Other Recent Updates to the Accounting Standards Codification

Revenue

In May 2014, the FASB issued ASU No. 2014-09, and added ASC 606, Revenue from Contracts with Customers, to the ASC. ASC 606 supersedes ASC 605, Revenue Recognition, as well as most industry-specific guidance, and prescribes a single, comprehensive revenue recognition model designed to improve financial reporting comparability across entities, industries, jurisdictions and capital markets. The Company adopted the new guidance on October 1, 2018, and will apply the new provisions on a modified retrospective basis.

Management established an implementation team to evaluate the impact on the Company’s financial position, results of operations and cash flows upon adoption of ASC 606. This implementation team reviewed the revenue streams of all of its subsidiaries and formed conclusions to determine if any system, process, controls and organizational changes are necessary upon adoption. The assessment of the impact of this guidance included reviewing the Company’s accounting policies under ASC 605 and identifying potential differences after the adoption of ASC 606. The Company concluded that its tariff-based sales of natural gas will be within the scope of the new guidance and it does not anticipate any modification to the pattern of revenue recognition from such sales. Revenues from derivative instruments such as those related to the Company’s SREC sales and natural gas purchases and sales will continue to be accounted for under ASC 815 and thus are outside the scope of ASC 606. Additionally, NJNG revenues generated by the CIP have been determined to be alternative revenue programs under ASC 980 and are also outside the scope of ASC 606 as they are deemed to be a contract with the regulator. The Company also evaluated its renewable asset PPA arrangements and does not anticipate any modification to the pattern of revenue recognition of the related electricity, capacity and REC sales. Revenues from RECs sold as part of a bundled arrangement will be recognized in the same period as the related generation, consistent with current practice.

The Company has completed its evaluation of its revenue streams, and based on the assessment performed, has concluded that the new guidance will not have a material impact on its financial position, results of operations or cash flows upon adoption. Additionally, the Company did not implement significant changes to its business processes, systems or internal controls over financial reporting upon adoption. ASC 606 requires expanded disclosures, including the disclosure of performance obligations, disaggregated revenues and contract balances, which the Company will include in its financial statements beginning in the first quarter of fiscal 2019.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Financial Instruments

In January 2016, the FASB issued ASU No. 2016-01, an amendment to ASC 825, Financial Instruments, to address certain aspects of the recognition, measurement, presentation and disclosure of financial instruments. The standard affects investments in equity securities that do not result in consolidation and are not accounted for under the equity method and the presentation of certain fair value changes for financial liabilities measured at fair value. It also simplifies the impairment assessment of equity investments without a readily determinable fair value by requiring a qualitative assessment. The guidance is effective for the Company beginning October 1, 2018. The amendment will be applied on a modified retrospective basis. The Company evaluated the amendment and noted that, upon adoption, subsequent changes to the fair value of the Company’s available for sale securities will be recorded in the Consolidated Statement of Operations as opposed to other comprehensive income. The Company will reclassify $3.4 million in accumulated other comprehensive income related to available for sale securities to the opening balance of retained earnings as of October 1, 2018. There will be no material impact to the Company’s financial position, results of operations or cash flows upon adoption.

In June 2016, the FASB issued ASU No. 2016-13, an amendment to ASC 326, Financial Instruments - Credit Losses, which changes the impairment model for certain financial assets that have a contractual right to receive cash, including trade and loan receivables. The new model requires recognition based upon an estimation of expected credit losses rather than recognition of losses when it is probable that they have been incurred. An entity will apply the amendment through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. The Company is currently evaluating the amendment to understand the impact on its financial position, results of operations and cash flows upon adoption and will apply the new guidance to its trade and loan receivables on a modified retrospective basis.

Leases

In February 2016, the FASB issued ASU No. 2016-02, an amendment to ASC 842, Leases, which provides for a comprehensive overhaul of the lease accounting model and changes the definition of a lease within the accounting literature. Under the new standard, all leases with a term greater than one year will be recorded on the balance sheet. Amortization of the related asset will be accounted for using one of two approaches prescribed by the guidance. Additional disclosures will be required to allow the user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach is required for leases existing at the time of adoption.

In January 2018, the FASB issued ASU No. 2018-01, a further amendment to ASC 842, Leases, which was introduced by ASU No. 2016-02, as discussed above. This update provides an optional practical expedient that allows companies to not evaluate existing or expired land easements that were not previously accounted for under Topic 840 as leases. The Company expects to elect this practical expedient upon adoption. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted.

In July 2018, the FASB issued ASU No. 2018-11, which provides an optional transition method to ASC 842 that allows the Company to recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. At this time, the Company does not plan to early adopt the new guidance and expects to transition on a modified retrospective basis. While the Company is currently evaluating the full impact of the standard and its related updates, it expects to recognize additional assets and liabilities arising from current operating leases to its financial position upon adoption. Current operating leases primarily consist of office and land leases related to the Company’s solar and wind assets.

Statement of Cash Flows

In August 2016, the FASB issued ASU No. 2016-15, an amendment to ASC 230, Statement of Cash Flows, which addresses eight specific cash flow issues for which there has been diversity in practice. The guidance is effective for the Company beginning October 1, 2018. The amendment will be applied on a retrospective basis and the Company does not expect any material impacts to its statement of cash flows.

In November 2016, the FASB issued ASU No. 2016-18, an amendment to ASC 230, Statement of Cash Flows, which requires that any amounts that are deemed to be restricted cash or restricted cash-equivalents be included in cash and cash-equivalent balances on the cash flow statement and, therefore, transfers between cash and restricted cash accounts will no longer be recognized within the statement of cash flows. The guidance is effective for the Company beginning October 1, 2018, and will be applied on a retrospective basis. Based on the Company's historical restricted cash balances, it does not expect any material impacts to its statement of cash flows.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Intangibles

In August 2018, the FASB issued ASU No. 2018-15, an amendment to ASC 350, Intangibles - Goodwill and Other, which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. Upon adoption, the amendment will be applied on a prospective or retrospective basis.

Business Combinations

In January 2017, the FASB issued ASU No. 2017-01, an amendment to ASC 805, Business Combinations, clarifying the definition of a business in the ASC, which is intended to reduce the complexity surrounding the assessment of a transaction as an asset acquisition or business combination. The amendment provides an initial fair value screen to reduce the number of transactions that would fit the definition of a business, and when the screen threshold is not met, provides an updated model that further clarifies the characteristics of a business. The guidance is effective for the Company beginning October 1, 2018, and will be applied on a prospective basis. The amendment could potentially have material impacts on future transactions that the Company may enter into by altering the Company’s conclusion on the accounting framework that is applied to acquisitions.

Gains and Losses from the Derecognition of Nonfinancial Assets

In February 2017, the FASB issued ASU No. 2017-05, an amendment to ASC 610-20, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets, which clarifies the scope and accounting related to the derecognition of nonfinancial assets, including partial sales and contributions of nonfinancial assets to a joint venture or other non-controlled investee. The guidance is effective concurrently with ASC 606, which is effective for the Company as of October 1, 2018 and will be applied retrospectively with a cumulative effect adjustment at the date of adoption. The Company had a deferred gain of $6.8 million related to nonfinancial assets on the balance sheet, which will be recognized under the new accounting guidance as a cumulative effect adjustment to the opening balance of retained earnings as of October 1, 2018.

Compensation - Retirement Benefits

In March 2017, the FASB issued ASU No. 2017-07, an amendment to ASC 715, Compensation - Retirement Benefits, which changes the presentation of net periodic benefit cost on the income statement by requiring companies to present all components of net periodic benefit cost, other than service cost, outside a subtotal of income from operations. The amendment also states that only the service cost component of net periodic benefits costs is eligible for capitalization, when applicable. The amendment establishes a practical expedient that permits entities to use their previously disclosed service and other costs in their pension and other postretirement benefit plan footnotes in the prior comparative periods as the estimation basis when applying the retrospective presentation of these costs in the income statement. The guidance is effective for the Company beginning October 1, 2018, and will be applied on a retrospective basis for income statement presentation, and on a prospective basis for changes to capitalization of costs. The changes related to the costs that will be eligible for capitalization and based on the components of net periodic benefit costs during fiscal year 2018, will not have a material impact on the Company's financial position, results of operations or cash flows upon adoption

In August 2018, the FASB issued ASU No. 2018-14, an amendment to ASC 715, Compensation - Retirement Benefits, which removes disclosures that no longer are considered cost-beneficial, clarifies the specific requirements of certain disclosures, and adds new disclosure requirements identified as relevant. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. Upon adoption, the amendments will be applied on a retrospective basis. The Company is continuing to evaluate the amendment to fully understand the impact on the Company's disclosures upon adoption.

Stock Compensation

In May 2017, the FASB issued ASU No. 2017-09, an amendment to ASC 718, Compensation - Stock Compensation, which clarifies the accounting for changes to the terms or conditions of share-based payments. The guidance is effective for the Company beginning October 1, 2018, and will be applied prospectively to awards modified on or after the adoption date. There was no material impact to the Company's financial position, results of operations or cash flows upon adoption.

In June 2018, the FASB issued ASU No. 2018-07, an amendment to ASC 718, Compensation - Stock Compensation, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. The guidance is effective for the Company beginning October 1, 2019, with early adoption permitted. The Company is currently evaluating the impact of the amendment on the Company’s financial position, results of operations and cash flows upon adoption.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Derivatives and Hedging

In August 2017, the FASB issued ASU No. 2017-12, an amendment to ASC 815, Derivatives and Hedging, which is intended to make targeted improvements to the accounting for hedging activities by better aligning an entity’s risk management activities and financial reporting for hedging relationships. These amendments modify the accounting for both nonfinancial and financial risk components and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. Additionally, the amendments are intended to simplify the application of the hedge accounting guidance and provide relief to companies by easing certain hedge documentation requirements. The guidance is effective for the Company beginning October 1, 2019, with early adoption permitted. Upon adoption, the transition requirements and elections will be applied to hedging relationships existing on the date of adoption. The Company does not currently apply hedge accounting to any of its risk management activities and thus does not expect the amendments to have any impact on its financial position, results of operations and cash flows upon adoption.

Fair Value

In August 2018, the FASB issued ASU No. 2018-13, an amendment to ASC 820, Fair Value Measurement, which removes, modifies and adds to certain disclosure requirements of fair value measurements. Disclosure requirements removed include the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the valuation processes for Level 3 fair value measurements. Modifications include considerations around the requirement to disclose the timing of liquidation of an investee’s assets and the date when restrictions from redemption might lapse. The additions include the requirement to disclose changes in unrealized gains and losses for the period in other comprehensive income for recurring Level 3 fair value measurements held and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. Upon adoption, the amendments will be applied on a prospective or retrospective basis depending on the specific amendments’ transition requirements. The Company is currently evaluating the amendments to understand the impact on its financial position, results of operations, cash flows and disclosures upon adoption and will apply the new guidance.

3. REGULATION

The EDECA is the legal framework for New Jersey’s public utility and wholesale energy landscape. NJNG is required, pursuant to a written order by the BPU under EDECA, to open its residential markets to competition from third-party natural gas suppliers. Customers can choose the supplier of their natural gas commodity in NJNG’s service territory.

As required by EDECA, NJNG’s rates are segregated into two primary components: the commodity portion, which represents the wholesale cost of natural gas, including the cost for interstate pipeline capacity to transport the gas to NJNG’s service territory; and the delivery portion, which represents the transportation of the commodity portion through NJNG’s gas distribution system to the end-use customer. NJNG does not earn utility gross margin on the commodity portion of its natural gas sales. NJNG earns utility gross margin through the delivery of natural gas to its customers, regardless of whether it or a third-party supplier provides the wholesale natural gas commodity.

Under EDECA, the BPU is required to audit the state’s energy utilities every two years. The primary purpose of the audit is to ensure that utilities and their affiliates offering unregulated retail services do not have an unfair competitive advantage over nonaffiliated providers of similar retail services. A combined competitive services and management audit of NJNG commenced in August 2013. A draft management audit report was accepted by the BPU on July 23, 2014, for public comment. To date, NJNG has implemented all audit recommendations with the approval of BPU staff and is waiting for final BPU approval.

NJNG is subject to cost-based regulation; therefore, it is permitted to recover authorized operating expenses and earn a reasonable return on its utility capital investments based on the BPU’s approval. The impact of the ratemaking process and decisions authorized by the BPU allows NJNG to capitalize or defer certain costs that are expected to be recovered from its customers as regulatory assets, and to recognize certain obligations representing amounts that are probable future expenditures as regulatory liabilities in accordance with accounting guidance applicable to regulated operations.

NJNG’s recovery of costs is facilitated through its base rates, BGSS and other regulatory tariff riders. NJNG is required to make an annual filing to the BPU by June 1 of each year for review of its BGSS, CIP and other programs and related rates. Annual rate changes are requested to be effective at the beginning of the following fiscal year. The current base rate includes a weighted average cost of capital of 6.9 percent and a return on common equity of 9.75 percent. In addition, NJNG is permitted to request approval of certain rate or program changes on an interim basis. All rate and program changes are subject to proper notification and BPU review and approval.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Regulatory assets and liabilities included on the Consolidated Balance Sheets as of September 30, are composed of the following:

(Thousands)	2018		2017
Regulatory assets-current
New Jersey Clean Energy Program	$	14,052	$	14,202
Underrecovered gas costs	4,137		9,910
Derivatives at fair value, net	108		9,010
Conservation Incentive Program	—		17,669
Total current regulatory assets	$	18,297	$	50,791
Regulatory assets-noncurrent
Environmental remediation costs:
Expended, net of recoveries	$	33,017	$	28,547
Liability for future expenditures	130,800		149,000
Deferred income taxes	17,225		21,795
SAVEGREEN	8,636		16,302
Postemployment and other benefit costs	136,716		141,433
Deferred storm damage costs	10,858		13,030
Cost of removal	22,339		—
Other noncurrent regulatory assets	9,001		5,812
Total noncurrent regulatory assets	$	368,592	$	375,919
Regulatory liability-current
Conservation Incentive Program	$	6,994	$	—
Derivatives at fair value, net	1,191		78
Total current regulatory liabilities	$	8,185	$	78
Regulatory liabilities-noncurrent
Tax Act impact (1)	$	205,410	$	—
Cost of removal	—		7,902
New Jersey Clean Energy Program	1,902		5,795
Other noncurrent regulatory liabilities	1,827		810
Total noncurrent regulatory liabilities	$	209,139	$	14,507

(1) Includes an adjustment related to the re-measurement of NJNG's net deferred tax liabilities to reflect the change in federal tax rates enacted in the Tax Act, which is net of sales tax collected from customers. For a more detailed discussion, see Note 12. Income Taxes.

Recovery of regulatory assets is subject to BPU approval, and therefore, if there are any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to income in the period of such determination.

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 2019. NJNG recovers the costs associated with its portion of the NJCEP obligation through its NJCEP rider, with interest.

Over and Underrecovered Gas Costs

NJNG recovers its cost of gas through the BGSS rate component of its customers’ bills. NJNG’s cost of gas includes the purchased cost of the natural gas commodity, fees paid to pipelines and storage facilities, adjustments as a result of BGSS incentive programs and hedging transactions. Overrecovered gas costs represent a regulatory liability that generally occurs when NJNG’s BGSS rates are higher than actual costs and requests approval to be returned to customers including interest, when applicable, in accordance with NJNG’s approved BGSS tariff. Conversely, underrecovered gas costs generally occur during periods when NJNG’s BGSS rates are lower than actual costs, in which case NJNG records a regulatory asset and requests amounts to be recovered from customers in the future.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

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 4. Derivative Instruments.

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.

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 13. 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, without interest, as approved by the BPU, over a two- to 10-year period depending upon the specific program incentive.

Postemployment and Other Benefit Costs

Postemployment and Other Benefit Costs represents NJNG’s underfunded postemployment benefit obligations, 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 10. Employee Benefit Plans.

Deferred Storm Damage Costs

Portions of NJNG’s distribution system incurred significant damage as a result of Superstorm 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 in docket number GR15111304 dated September 23, 2016. 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. NJNG’s prior regulatory liability represented customer collections in excess of actual expenditures, which the Company returned to customers as a reduction to depreciation expense.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

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. As of September 30, 2018, NJNG recorded $3.2 million of PIM in other regulatory assets, which is being recovered through base rates over a seven-year amortization period effective October 2016.

The Tax Act

On December 22, 2017, the Tax Act was signed into law, which resulted in a reduction in the federal corporate tax rate. As a result, NJNG recorded a regulatory liability, which included the revaluation of its deferred income taxes and the accounting of the income tax effects on the revaluation. The revaluation was based on certain assumptions and estimations NJNG made with respect to its deferred taxes, as well as the effects from the Tax Act, and as such is subject to change if and when assumptions are updated. See Note 12. Income Taxes for a more detailed discussion on the Tax Act.

On January 31, 2018, the BPU issued an Order which directed New Jersey utilities to submit filings to the BPU by March 2, 2018, to propose the prospective change in base rates as a result of the Tax Act to be effective April 1, 2018, the method to return to customers the overcollection of taxes in base rates from January 1, 2018, through March 31, 2018 and an outline of the method by which the excess deferred taxes would be returned to customers. The excess deferred taxes are primarily related to timing differences associated with utility plant depreciation and are subject to IRS normalization rules, which require amortization over the remaining life of the utility plant.

On March 1, 2018, NJNG submitted its required filing to the BPU proposing a $19.7 million base rate reduction and customer refunds of approximately $31 million, which is inclusive of state sales tax and interest at the Company’s short-term debt rate as specified in the Company’s last base rate case. On March 26, 2018, the BPU approved, on an interim basis, the $19.7 million rate reduction, effective April 1, 2018. On May 22, 2018, the BPU approved final rates and also customer refunds of the $31 million. These credits were returned to customer accounts in June 2018.

The following is a description of certain regulatory proceedings during fiscal 2017 and 2018:

BGSS and CIP

BGSS rates are normally revised on an annual basis. In addition, to manage the fluctuations in wholesale natural gas costs, NJNG has the ability to make two interim filings during each fiscal year to increase residential and small commercial customer BGSS rates on a self-implementing and provisional basis. NJNG is also permitted to refund or credit back a portion of the commodity costs to customers at any time given five days’ notice when the natural gas commodity costs decrease in comparison to amounts projected or to amounts previously collected from customers. Concurrent with the annual BGSS filing, NJNG files for an annual review of its CIP. NJNG’s annual BGSS and CIP filings are summarized as follows:

• June 2016 BGSS/CIP filing — In September 2016, the BPU approved NJNG’s filing to increase its CIP rates resulting in a $43.9 million annual recovery increase and to decrease its annual BGSS rate for residential and small commercial customers resulting in a $22.6 million annual recovery decrease effective October 2016. This petition also included bill credits to residential and small commercial customers during the months of November 2016 through February 2017, as a result of a decline in the wholesale price of natural gas. A total of $42 million in bill credits were issued during fiscal 2017.

• June 2017 BGSS/CIP filing — In March 2018, the BPU approved NJNG’s petition on a final basis to maintain its BGSS rate for residential and small commercial customers, increase its balancing charge rate, which resulted in a $3.7 million increase to the annual revenues credited to BGSS, and decrease its CIP rates, which resulted in a $16.2 million annual recovery decrease that was effective October 2017.

• May 2018 BGSS/CIP filing — On September 17, 2018, the BPU provisionally approved NJNG’s annual petition to maintain its BGSS rate for residential and small commercial customers and increase its balancing charge rate, resulting in a $10.3 million increase to the annual revenues credited to BGSS, as well as changes to the CIP rates, which will result in a $30.9 million annual recovery decrease effective October 2018.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

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 energy efficiency upgrades to promote energy efficiency incentives to its residential and commercial customers while stimulating state and local economies through the creation of jobs. Depending on the specific initiative or approval, NJNG recovers costs associated with the programs over a three- to 10-year period through a tariff rider mechanism.

As of September 30, 2018, the BPU has approved total SAVEGREEN investments of approximately $354.3 million, including $135 million that was approved on September 17, 2018, for a continuation of existing EE programs and the implementation of new programs through December 2021.

SAVEGREEN investments and costs are filed with the BPU on an annual basis. Since inception, $162 million in grants, rebates and loans have been provided to customers, with a total annual recovery of approximately $16.1 million. The recovery includes a weighted average cost of capital that ranges from 6.69 percent to 7.76 percent, with a return on equity of 9.75 percent to 10.3 percent, respectively. On October 16, 2018, NJNG requested a decrease in its EE recovery rate reflecting costs incurred through September 30, 2018, which will result in an annual decrease of $8.8 million, anticipated to be effective January 1, 2019.

Societal Benefits Clause

The SBC is comprised of three primary riders that allow NJNG to recover costs associated with USF, which is a permanent statewide program for all natural gas and electric utilities for the benefit of income-eligible customers, MGP remediation and the NJCEP. NJNG has submitted the following filings to the BPU, which include a report of program expenditures incurred each program year:

• 2017 SBC filing — In September 2017, the BPU approved NJNG’s annual USF compliance filing to decrease the statewide USF rate, which will result in a $2.6 million annual decrease, effective October 1, 2017. On July 25, 2018, the BPU approved NJNG's annual SBC filing requesting to recover remediation expenses incurred through June 30, 2017, a reduction in the RAC, which resulted in an annual decrease of $2.4 million, and to increase the NJCEP factor, which will result in an annual increase of $1.8 million, effective September 1, 2018.

• 2018 SBC filing — On September 17, 2018, the BPU approved NJNG’s annual USF compliance filing to increase the statewide USF rate, which will result in a $1 million annual increase, effective October 1, 2018. On September 21, 2018, NJNG filed its annual SBC application requesting to recover remediation expenses incurred through June 30, 2018, an increase in the RAC, which will result in an annual increase of $1.4 million, and an increase to the NJCEP factor, which will result in an annual increase of approximately $1.9 million, effective April 1, 2019.

Infrastructure Programs

NJNG has significant annual capital expenditures associated with the management of its natural gas distribution and transmission system, including new utility plant for customer growth and its associated PIM and infrastructure programs. NJNG continues to implement BPU-approved infrastructure projects that are designed to enhance the reliability of NJNG’s gas distribution system, including SAFE and NJ RISE.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

SAFE/NJ RISE

The SAFE program replaces portions of NJNG’s gas distribution unprotected steel, cast iron infrastructure and associated services to improve the safety and reliability of the gas distribution system. SAFE I was approved to invest up to $130 million, exclusive of AFUDC, over a four-year period. The recovery of SAFE I capital investments and the corresponding rate mechanism were approved through NJNG’s base rate case effective October 2016. SAFE II was approved to invest up to $200 million, excluding AFUDC, over a five-year period. NJNG will recover approximately $157.5 million through annual rate filings, with the remainder recovered through subsequent rate cases. As a condition of approval of the program, NJNG is required to file a base rate case no later than November 2019.

NJ RISE consists of six capital investment projects estimated to cost $102.5 million over a five-year period, excluding AFUDC, for gas distribution storm-hardening and mitigation projects, along with incremental depreciation expense. NJ RISE includes a weighted average cost of capital that ranges from 6.74 percent to 6.9 percent and a return on equity of 9.75 percent. NJ RISE investments through June 30, 2016, were approved for recovery through NJNG’s new base rates effective October 2016. Requests for recovery of future NJ RISE capital costs will occur in conjunction with SAFE II.

In September 2017, the BPU approved NJNG’s annual petition requesting a base rate increase for the recovery of NJ RISE and SAFE II capital investment costs with an annual increase of $4.1 million effective October 1, 2017. On September 17, 2018, the BPU approved NJNG’s petition requesting a base rate increase of $6.8 million annually for the recovery of SAFE II and NJ RISE capital investment costs related to the 12 months ending June 30, 2018 effective October 1, 2018.

SRL

The SRL is an approximately 30-mile, 30-inch transmission main designed to support improved system integrity and reliability in the southern portion of NJNG’s service territory, estimated to cost between $180 million and $215 million. In March 2016, the BPU issued an order designating the SRL route and exempting the SRL from municipal land use ordinances, regulations, permits and license requirements. In February 2017, the New Jersey Department of Environmental Protection issued a permit authorizing construction of the SRL within the jurisdiction of the Coastal Area Facility Review Act as well as a Freshwater Wetlands permit. In September 2017, the NJ Pinelands Commission approved construction of NJNG’s SRL. All approvals and permits have been appealed by third parties.

Other Regulatory Initiatives

In May 2016, NJNG included a proposal in its base rate case to recover certain capital costs and incremental operation and maintenance costs related to a March 2016 BPU Order regarding new cyber security requirements. Costs associated with this initiative were approved for recovery through NJNG’s base rates effective October 2016.

In June 2016, NJNG’s liquefaction project became operational, allowing NJNG to convert natural gas into LNG and to fill NJNG’s existing LNG storage tanks. Costs for this project along with other plant upgrades were approximately $36.5 million. Costs associated with this initiative were approved for recovery through NJNG’s base rates effective October 2016.

4. DERIVATIVE INSTRUMENTS

The Company is subject to commodity price risk due to fluctuations in the market price of natural gas, SRECs and electricity. To manage this risk, the Company enters into a variety of derivative instruments including, but not limited to, futures contracts, physical forward contracts, financial options and swaps to economically hedge the commodity price risk associated with its existing and anticipated commitments to purchase and sell natural gas, SRECs and electricity. In addition, the Company may utilize foreign currency derivatives to hedge Canadian dollar denominated gas purchases and/or sales. Therefore, the Company’s primary underlying risks include commodity prices, interest rates and foreign currency. These contracts, with a few exceptions as described below, are accounted for as derivatives. Accordingly, all of the financial and certain of the Company’s physical derivative instruments are recorded at fair value on the Consolidated Balance Sheets. For a more detailed discussion of the Company’s fair value measurement policies and level disclosures associated with the Company’s derivative instruments, see Note 5. Fair Value.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Energy Services

Energy Services 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 gas purchases or operating revenues, as appropriate for Energy Services, on the Consolidated Statements of Operations as unrealized gains or losses. For Energy Services at settlement, realized gains and losses on all financial derivative instruments are recognized as a component of gas purchases and realized gains and losses on all physical derivatives follow the presentation of the related unrealized gains and losses as a component of either gas purchases or operating revenues.

Energy Services also enters into natural gas transactions in Canada and, consequently, is exposed to fluctuations in the value of Canadian currency relative to the U.S. dollar. Energy Services may utilize foreign currency derivatives to lock in the exchange rate associated with natural gas transactions denominated in Canadian currency. The derivatives may include currency forwards, futures or swaps and are accounted for as derivatives. These derivatives are typically used to hedge demand fee payments on pipeline capacity, storage and gas purchase agreements.

As a result of Energy Services entering into transactions to borrow natural gas, commonly referred to as “park and loans,” an embedded derivative is recognized relating to differences between the fair value of the amount borrowed and the fair value of the amount that will ultimately be repaid, based on changes in the forward price for natural gas prices at the borrowed location over the contract term. This embedded derivative is accounted for as a forward sale in the month in which the repayment of the borrowed gas is expected to occur, and is considered a derivative transaction that is recorded at fair value on the Consolidated Balance Sheets, with changes in value recognized in current-period earnings.

Expected production of SRECs is hedged through the use of forward and futures contracts. All contracts require the Company to physically deliver SRECs through the transfer of certificates as per contractual settlement schedules. For transactions occurring on or before December 31, 2015, the Company elected NPNS accounting treatment on SREC forward and futures contracts. Effective January 1, 2016, on a prospective basis, Energy Services no longer elects NPNS accounting treatment on SREC contracts entered into from January 1, 2016, and recognizes changes in the fair value of these derivatives as a component of operating revenues. Upon settlement of the contract, the related revenue is recognized when the SREC is transferred to the counterparty. NPNS is a contract-by-contract election and, where it makes sense to do so, we can and may elect certain contracts to be normal.

Natural Gas Distribution

Changes in fair value of NJNG’s financial commodity derivatives are recorded as a component of regulatory assets or liabilities on the Consolidated Balance Sheets. The Company elects NPNS accounting treatment on all physical commodity contracts that NJNG entered into on or before December 31, 2015, and accounts for these contracts on an accrual basis. Accordingly, physical natural gas purchases are recognized in regulatory assets or liabilities on the Consolidated Balance Sheets when the contract settles and the natural gas is delivered. The average cost of natural gas is amortized in current-period earnings based on the current BPU BGSS factor and therm sales. Effective January 1, 2016, on a prospective basis, NJNG no longer elects NPNS accounting treatment on all of its physical commodity contracts entered into from January 1, 2016. However, since NPNS is a contract-by-contract election, where it makes sense to do so, NJNG can and may elect certain contracts to be normal. Because NJNG recovers these amounts through future BGSS rates as increases or decreases to the cost of natural gas in NJNG’s tariff for gas service, the changes in fair value of these contracts are deferred as a component of regulatory assets or liabilities on the Consolidated Balance Sheets.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Home Services and Other

On January 26, 2018, NJR entered into a variable-for-fixed interest rate swap on its existing $100 million variable rate term loan, which fixed the variable rate at 2.84 percent. The swap will terminate on August 16, 2019, which coincides with the maturity of the debt. The change in the fair value of the interest rate swap is recorded as interest expense on the Consolidated Statements of Operations.

Fair Value of Derivatives

The following table reflects the fair value of the Company’s derivative assets and liabilities recognized on the Consolidated Balance Sheets as of September 30:

			Fair Value
			2018						2017
(Thousands)	Balance Sheet Location	Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments:
Natural Gas Distribution:
Physical commodity contracts	Derivatives - current		$	85		$	192		$	151		$	72
Financial commodity contracts	Derivatives - current		94			—			—			1,149
Interest rate contracts (1)	Derivatives - current		—			—			—			8,467
Energy Services:
Physical commodity contracts	Derivatives - current		7,667			18,158			14,588			16,589
	Derivatives - noncurrent		3,930			11,316			7,127			8,710
Financial commodity contracts	Derivatives - current		19,169			28,176			15,302			20,267
	Derivatives - noncurrent		6,630			11,548			2,033			2,620
Foreign currency contracts	Derivatives - current		—			126			40			—
	Derivatives - noncurrent		—			118			4			—
Home Services and Other:
Interest rate contracts	Derivatives - current		381			—			—			—
Total fair value of derivatives			$	37,956		$	69,634		$	39,245		$	57,874

(1) Includes treasury lock which was settled in March 2018. See Note 8. Debt for more information.

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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

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.

(Thousands)	Amounts Presented in Balance Sheets (1)			Offsetting Derivative Instruments (2)				Financial Collateral Received/Pledged (3)				Net Amounts (4)
As of September 30, 2018:
Derivative assets:
Energy Services
Physical commodity contracts		$	11,597		$	(3,944	)		$	(200	)		$	7,453
Financial commodity contracts		25,799			(18,775		)		—				7,024
Total Energy Services		$	37,396		$	(22,719	)		$	(200	)		$	14,477
Natural Gas Distribution
Physical commodity contracts		$	85		$	(3	)		$	—			$	82
Financial commodity contracts		94			—				(94		)		—
Total Natural Gas Distribution		$	179		$	(3	)		$	(94	)		$	82
Home Services and Other
Interest rate contracts		$	381		$	—			$	—			$	381
Total Home Services and Other		$	381		$	—			$	—			$	381
Derivative liabilities:
Energy Services
Physical commodity contracts		$	29,474		$	(3,944	)		$	—			$	25,530
Financial commodity contracts		39,724			(18,775		)		(20,949		)		—
Foreign currency contracts		244			—				—				244
Total Energy Services		$	69,442		$	(22,719	)		$	(20,949	)		$	25,774
Natural Gas Distribution
Physical commodity contracts		$	192		$	(3	)		$	—			$	189
Total Natural Gas Distribution		$	192		$	(3	)		$	—			$	189
As of September 30, 2017:
Derivative assets:
Energy Services
Physical commodity contracts		$	21,715		$	(2,173	)		$	(200	)		$	19,342
Financial commodity contracts		17,335			(14,121		)		—				3,214
Foreign currency contracts		44			—				—				44
Total Energy Services		$	39,094		$	(16,294	)		$	(200	)		$	22,600
Natural Gas Distribution
Physical commodity contracts		$	151		$	(20	)		$	—			$	131
Total Natural Gas Distribution		$	151		$	(20	)		$	—			$	131
Derivative liabilities:
Energy Services
Physical commodity contracts		$	25,299		$	(2,173	)		$	—			$	23,126
Financial commodity contracts		22,887			(14,121		)		(8,766		)		—
Total Energy Services		$	48,186		$	(16,294	)		$	(8,766	)		$	23,126
Natural Gas Distribution
Physical commodity contracts		$	72		$	(20	)		$	—			$	52
Financial commodity contracts		1,149			—				(1,149		)		—
Interest rate contracts		8,467			—				—				8,467
Total Natural Gas Distribution		$	9,688		$	(20	)		$	(1,149	)		$	8,519

(1) Derivative assets and liabilities are presented on a gross basis in the balance sheet as the Company does not elect balance sheet offsetting under ASC 210-20.

(2) Offsetting derivative instruments include transactions with NAESB netting election, transactions held by FCMs with net margining and transactions with ISDA netting.

(3) Financial collateral includes cash balances at FCMs, as well as cash received from or pledged to other counterparties.

(4) Net amounts represent presentation of derivative assets and liabilities if the Company were to elect balance sheet offsetting under ASC 210-20.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Energy Services utilizes financial derivatives to economically hedge the gross margin associated with the purchase of physical gas to be used for storage injection and its subsequent sale at a later date. The gains or (losses) on the financial transactions that are economic hedges of the cost of the purchased gas are recognized prior to the gains or (losses) on the physical transaction, which are recognized in earnings when the natural gas is delivered. Therefore, mismatches between the timing of the recognition of realized gains or (losses) on the financial derivative instruments and gains or (losses) associated with the actual sale of the natural gas that is being economically hedged, along with fair value changes in derivative instruments, create volatility in the results of Energy Services, although the Company’s intended economic results relating to the entire transaction are unaffected.

The following table reflects the effect of derivative instruments on the Consolidated Statements of Operations as of September 30:

(Thousands)	Location of gain (loss) recognized in income on derivatives	Amount of gain (loss) recognized in income on derivatives
Derivatives not designated as hedging instruments:		2018			2017			2016
Energy Services:
Physical commodity contracts	Operating revenues	$	(9,311	)	$	8,912		$	33,034
Physical commodity contracts	Gas purchases	(197		)	(27,461		)	(45,637		)
Financial commodity contracts	Gas purchases	(24,622		)	26,563			45,579
Foreign currency contracts	Gas purchases	(379		)	41			(34		)
Home Services and Other:
Interest rate contracts	Interest expense	334			—			—
Total unrealized and realized gains (losses)		$	(34,175	)	$	8,055		$	32,942

NJNG’s derivative contracts are part of the Company’s risk management activities that relate to its natural gas purchases, BGSS incentive programs and debt financing. These transactions are entered into pursuant to regulatory approval and, at settlement, the resulting gains and/or losses are payable to or recoverable from utility customers. Any changes in the value of NJNG’s financial derivatives are deferred in regulatory assets or liabilities resulting in no impact to earnings.

The following table reflects the (losses) gains associated with NJNG’s derivative instruments as of September 30:

(Thousands)	2018		2017			2016
Natural Gas Distribution:
Physical commodity contracts	$	1,232	$	(12,303	)	$	(15,756	)
Financial commodity contracts	1,844		5,595			(7,984		)
Interest rate contracts	8,467		14,606			(18,845		)
Total unrealized and realized (losses) gains	$	11,543	$	7,898		$	(42,585	)

NJNG and Energy Services had the following outstanding long (short) derivatives as of September 30:

		Volume (Bcf)
		2018		2017
Natural Gas Distribution	Futures	27.9		18.2
	Physical	23.1		32.1
Energy Services	Futures	(7.0	)	(16.4	)
	Physical	51.2		(13.1	)

Not included in the previous table are Energy Services’ gross notional amount of foreign currency transactions of approximately $8.5 million, interest rate contracts, as previously discussed, and 698,700 SRECs at Energy Services that are open as of September 30, 2018.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Broker Margin

Futures exchanges have contract-specific performance bond requirements, also known as margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin, which is posted upon the initiation of a position, maintenance margin, which is usually expressed as a percent of initial margin, and variation margin, which fluctuates based on the daily marked-to-market relative to maintenance margin requirements. The Company maintains separate broker margin accounts for the Natural Gas Distribution and Energy Services segments. The balances as of September 30, by segment, are as follows:

(Thousands)	Balance Sheet Location	2018		2017
Natural Gas Distribution	Broker margin - Current assets	$	2,038	$	2,661
Energy Services	Broker margin - Current assets	$	51,681	$	23,166

Due to CME rulebook changes that took effect in January 2017, variation margin is being treated as a settlement payment, rather than collateral. As a result, the Company is now required to present variation margin net with the related derivative assets and/or liabilities on the Consolidated Balance Sheets for any derivatives the Company clears through the CME.

Wholesale Credit Risk

NJNG, Energy Services and Clean Energy Ventures are exposed to credit risk as a result of their sales/wholesale and retail marketing activities. As a result of the inherent volatility in the prices of natural gas commodities, derivatives, SRECs, electricity and RECs, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If a counterparty fails to perform the obligations under its contract (e.g., fails to deliver or pay for natural gas, SRECs, electricity or RECs), the Company could sustain a loss.

The Company monitors and manages the credit risk of its wholesale operations through credit policies and procedures that management believes reduce overall credit risk. These policies include a review and evaluation of current and prospective counterparties’ financial statements and/or credit ratings, daily monitoring of counterparties’ credit limits and exposure, daily communication with traders regarding credit status and the use of credit mitigation measures, such as collateral requirements and netting agreements. Examples of collateral include letters of credit and cash received for either prepayment or margin deposit. Collateral may be requested due to the Company’s election not to extend credit or because exposure exceeds defined thresholds. Most of the Company’s wholesale marketing contracts contain standard netting provisions. These contracts include those governed by ISDA and the NAESB. The netting provisions refer to payment netting, whereby receivables and payables with the same counterparty are offset and the resulting net amount is paid to the party to which it is due.

Internally-rated exposure applies to counterparties that are not rated by S&P or Moody’s. In these cases, the counterparty’s or guarantor’s financial statements are reviewed, and similar methodologies and ratios used by S&P and/or Moody’s are applied to arrive at a substitute rating. Gross credit exposure is defined as the unrealized fair value of physical and financial derivative commodity contracts, plus any outstanding wholesale receivable for the value of natural gas delivered and/or financial derivative commodity contract that has settled for which payment has not yet been received.

The following is a summary of gross credit exposures grouped by investment and noninvestment grade counterparties, as of September 30, 2018.The amounts presented below have not been reduced by any collateral received or netting and exclude accounts receivable for NJNG retail natural gas sales and services and Clean Energy Ventures residential solar installations.

(Thousands)	Gross Credit Exposure
Investment grade		$	179,982
Noninvestment grade		43,486
Internally-rated investment grade		30,786
Internally-rated noninvestment grade		25,750
Total		$	280,004

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Conversely, certain of NJNG’s and Energy Services’ derivative instruments are linked to agreements containing provisions that would require cash collateral payments from the Company if certain events occur. These provisions vary based upon the terms in individual counterparty agreements and can result in cash payments if NJNG’s credit rating were to fall below its current level. NJNG’s credit rating, with respect to S&P, reflects the overall corporate credit profile of the Company. Specifically, most, but not all, of these additional payments will be triggered if NJNG’s debt is downgraded by the major credit agencies, regardless of investment grade status. In addition, some of these agreements include threshold amounts that would result in additional collateral payments if the values of derivative liabilities were to exceed the maximum values provided for in relevant counterparty agreements. Other provisions include payment features that are not specifically linked to ratings, but are based on certain financial metrics.

Collateral amounts associated with any of these conditions are determined based on a sliding scale and are contingent upon the degree to which the Company’s credit rating and/or financial metrics deteriorate, and the extent to which liability amounts exceed applicable threshold limits. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on September 30, 2018 and 2017, is approximately $124,000 and $8.7 million, respectively, for which the Company had not posted collateral. If all thresholds related to the credit-risk-related contingent features underlying these agreements had been invoked on September 30, 2018 and 2017, the Company would have been required to post an additional $33,000 and $8.6 million, respectively, to its counterparties. These amounts differ from the respective net derivative liabilities reflected on the Consolidated Balance Sheets because the agreements also include clauses, commonly known as “Rights of Offset,” that would permit the Company to offset its derivative assets against its derivative liabilities for determining additional collateral to be posted, as previously discussed.

5. FAIR VALUE

Fair Value of Assets and Liabilities

The fair value of cash and cash equivalents, accounts receivable, current loan receivables, accounts payable, commercial paper and borrowings under revolving credit facilities are estimated to equal their carrying amounts due to the short maturity of those instruments. Non-current loan receivables are recorded based on what the Company expects to receive, which approximates fair value. The Company regularly evaluates the credit quality and collection profile of its customers to approximate fair value.

As of September 30, the estimated fair value of long-term debt at NJNG and NJR, including current maturities, excluding capital leases, debt issuance costs and solar asset financing obligations, is as follows ⁽¹⁾:

(Thousands)	2018		2017
NJNG
Carrying value	$	672,045	$	672,045
Fair market value	$	669,162	$	673,051
NJR
Carrying value	$	500,000	$	425,000
Fair market value	$	488,889	$	434,625

(1) SeeNote 8. Debt for a reconciliation to long-term and short-term debt.

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, 2018 and 2017, the Company disclosed its debt within Level 2 of the fair value hierarchy.

Fair Value Hierarchy

The Company applies fair value measurement guidance to its financial assets and liabilities, as appropriate, which include financial derivatives and physical commodity contracts qualifying as derivatives, available for sale securities and other financial assets and liabilities. In addition, authoritative accounting literature prescribes the use of a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value based on the source of the data used to develop the price inputs.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to inputs that are based on unobservable market data and includes the following:

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Level 1 Unadjusted quoted prices for identical assets or liabilities in active markets. The Company’s Level 1 assets and liabilities include exchange traded natural gas futures and options contracts, listed equities and money market funds. Exchange traded futures and options contracts include all energy contracts traded on the NYMEX, CME and ICE that the Company refers internally to as basis swaps, fixed swaps, futures and financial options that are cleared through a FCM.

Level 2 Other significant observable inputs, such as interest rates or price data, including both commodity and basis pricing that is observed either directly or indirectly from publications or pricing services. The Company’s Level 2 assets and liabilities include over-the-counter physical forward commodity contracts and swap contracts, SREC forward sales or derivatives that are initially valued using observable quotes and are subsequently adjusted to include time value, credit risk or estimated transport pricing components for which no basis price is available. Level 2 financial derivatives consist of transactions with non-FCM counterparties (basis swaps, fixed swaps and/or options). Inputs are verifiable and do not require significant management judgment. For some physical commodity contracts, the Company utilizes transportation tariff rates that are publicly available and that it considers to be observable inputs that are equivalent to market data received from an independent source. There are no significant judgments or adjustments applied to the transportation tariff inputs and no market perspective is required. Even if the transportation tariff input were considered to be a “model,” it would still be considered to be a Level 2 input as the data is:

• widely accepted and public;

• non-proprietary and sourced from an independent third party; and

• observable and published.

These additional adjustments are generally not considered to be significant to the ultimate recognized values.

Level 3 Inputs derived from a significant amount of unobservable market data. These include the Company’s best estimate of fair value and are derived primarily through the use of internal valuation methodologies.

Financial derivative portfolios of NJNG and Energy Services consist mainly of futures, options and swaps. The Company primarily uses the market approach and its policy is to use actively quoted market prices when available. The principal market for its derivative transactions is the natural gas wholesale market; therefore, the primary sources for its price inputs are CME, NYMEX and ICE. Energy Services uses Platts and Natural Gas Exchange for Canadian delivery points. However, Energy Services also engages in transactions that result in transporting natural gas to delivery points for which there is no actively quoted market price. In most instances, the transportation cost to the final delivery location is not significant to the overall valuation. If required, Energy Services’ policy is to use the best information available to determine fair value based on internal pricing models, which would include estimates extrapolated from broker quotes or other pricing services.

The Company also has available for sale securities and other financial assets that include listed equities, mutual funds and money market funds for which there are active exchange quotes available.

When the Company determines fair values, measurements are adjusted, as needed, for credit risk associated with its counterparties, as well as its own credit risk. The Company determines these adjustments by using historical default probabilities that correspond to the applicable S&P issuer ratings, while also taking into consideration collateral and netting arrangements that serve to mitigate risk.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Assets and liabilities measured at fair value on a recurring basis are summarized as follows:

	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
(Thousands)	(Level 1)			(Level 2)			(Level 3)			Total
As of September 30, 2018:
Assets
Physical commodity contracts		$	—		$	11,682		$	—	$	11,682
Financial commodity contracts		18,868			7,025			—		25,893
Financial commodity contracts - foreign exchange		—			—			—		—
Interest rate contract		—			381			—		381
Available for sale equity securities		32,917			—			—		32,917
Other (1)		1,217			—			—		1,217
Total assets at fair value		$	53,002		$	19,088		$	—	$	72,090
Liabilities
Physical commodity contracts		$	—		$	29,666		$	—	$	29,666
Financial commodity contracts		39,724			—			—		39,724
Financial commodity contracts - foreign exchange		—			244			—		244
Total liabilities at fair value		$	39,724		$	29,910		$	—	$	69,634
As of September 30, 2017:
Assets
Physical commodity contracts		$	—		$	21,866		$	—	$	21,866
Financial commodity contracts		17,335								17,335
Financial commodity contracts - foreign exchange		—			44			—		44
Available for sale equity securities		65,752			—			—		65,752
Other (1)		1,202			—			—		1,202
Total assets at fair value		$	84,289		$	21,910		$	—	$	106,199
Liabilities
Physical commodity contracts		$	—		$	25,371		$	—	$	25,371
Financial commodity contracts		24,036			—			—		24,036
Interest rate contract		—			8,467			—		8,467
Total liabilities at fair value		$	24,036		$	33,838		$	—	$	57,874

(1) Includes money market funds.

During the second quarter of fiscal 2018, the Company evaluated the decrease in fair value of its available for sale securities on a nonrecurring basis and determined that the decline was other-than-temporary. Accordingly, the Company recognized an other-than-temporary impairment of $17.8 million, which was determined using quoted market prices for identical publicly traded equity securities on an active exchange. As of March 31, 2018, the Company’s available for sale securities had a fair value of $28.2 million.See the Company’s discussion of available for sale securities in Note 2. Summary of Significant Accounting Policies for more information regarding the impairment.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

6. INVESTMENTS IN EQUITY INVESTEES

As of September 30, the Company’s investments in equity method investees includes the following:

(Thousands)	2018		2017
Steckman Ridge (1)	$	117,001	$	120,262
PennEast	73,865		52,323
Total	$	190,866	$	172,585

(1)Includes loans with a total outstanding principal balance of $70.4 million for both fiscal 2018 and 2017, which accrue interest at a variable rate that resets quarterly and are due October 1, 2023.

The Company, through its subsidiary NJR Pipeline Company, is an investor in PennEast, which is expected to construct and operate a 120-mile pipeline that will extend from northeast Pennsylvania to western New Jersey. PennEast has advised that it currently expects the pipeline to be completed and operational in 2019; however, the project could be delayed beyond 2019 due to factors that are beyond PennEast’s ability to control or estimate precisely, including potential delays in obtaining (or the inability to obtain) governmental and regulatory approvals and land-use rights, and unforeseen construction delays.

NJNG and Energy Services have entered into storage and park and loan agreements with Steckman Ridge. In addition, NJNG has entered into a precedent capacity agreement with PennEast. See Note 15. Related Party Transactions for more information on these intercompany transactions.

7. 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)	2018		2017		2016
Net income, as reported	$	233,436	$	132,065	$	131,672
Basic earnings per share
Weighted average shares of common stock outstanding-basic	87,689		86,321		85,884
Basic earnings per common share	$2.66		$1.53		$1.53
Diluted earnings per share
Weighted average shares of common stock outstanding-basic	87,689		86,321		85,884
Incremental shares (1)	626		823		847
Weighted average shares of common stock outstanding-diluted	88,315		87,144		86,731
Diluted earnings per common share (2)	$2.64		$1.52		$1.52

(1) Incremental shares consist primarily of unvested stock awards and performance units.

(2) There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2018, 2017 and 2016.

8. DEBT

NJNG and NJR finance working capital requirements and capital expenditures through the issuance of various long-term debt and other financing arrangements, including unsecured credit and private placement debt shelf facilities. Amounts available under credit facilities are reduced by bank or commercial paper borrowings, as applicable, and any outstanding letters of credit.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Long-term Debt

The following table presents the long-term debt of the Company as of September 30:

(Thousands)			2018			2017
NJNG
First mortgage bonds:		Maturity date:
5.60%	Series LL	May 15, 2018	$	—		$	125,000
Variable	Series MM	September 1, 2027	9,545			9,545
Variable	Series NN	August 1, 2035	41,000			41,000
Variable	Series OO	August 1, 2041	46,500			46,500
3.15%	Series PP	April 15, 2028	50,000			50,000
3.58%	Series QQ	March 13, 2024	70,000			70,000
4.61%	Series RR	March 13, 2044	55,000			55,000
2.82%	Series SS	April 15, 2025	50,000			50,000
3.66%	Series TT	April 15, 2045	100,000			100,000
3.63%	Series UU	June 21, 2046	125,000			125,000
4.01%	Series VV	May 11, 2048	125,000			—
Capital lease obligation-buildings		June 1, 2021	8,749			11,617
Capital lease obligation-meters		Various dates	27,188			28,042
Less: Debt issuance costs			(6,515		)	(6,262		)
Less: Current maturities of long-term debt			(9,502		)	(135,800		)
Total NJNG long-term debt			691,965			569,642
NJR
2.51%	Unsecured senior notes	September 15, 2018	—			25,000
3.25%	Unsecured senior notes	September 17, 2022	50,000			50,000
3.48%	Unsecured senior notes	November 7, 2024	100,000			100,000
3.20%	Unsecured senior notes	August 18, 2023	50,000			50,000
3.54%	Unsecured senior notes	August 18, 2026	100,000			100,000
3.96%	Unsecured senior notes	June 8, 2028	100,000			—
Variable	Term loan	August 16, 2019	100,000			100,000
Less: Debt issuance costs			(1,136		)	(770		)
Less: Current maturities of long-term debt			(100,000		)	(25,000		)
Total NJR long-term debt			398,864			399,230
Clean Energy Ventures
Solar asset financing obligation		Various dates	103,923			32,790
Less: Current maturities of long-term debt			(14,133		)	(4,582		)
Total Clean Energy Ventures long-term debt			89,790			28,208
Total long-term debt			$	1,180,619		$	997,080

Annual long-term debt redemption requirements, excluding capital leases, debt issuance costs and solar asset financing obligations, as of September 30, are as follows:

(Thousands)	NJNG		NJR
2019	$	—	$	100,000
2020	$	—	$	—
2021	$	—	$	—
2022	$	—	$	50,000
2023	$	—	$	50,000
Thereafter	$	672,045	$	300,000

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

NJNG

First Mortgage Bonds

NJNG and Trustee entered into the Mortgage Indenture, dated September 1, 2014, which secures all of the outstanding First Mortgage Bonds issued by NJNG. The Mortgage Indenture provides a direct first mortgage lien upon substantially all of the operating properties and franchises of NJNG (other than excepted property, such as cash on hand, choses-in-action, securities, rent, natural gas meters and certain materials, supplies, appliances and vehicles), subject only to certain permitted encumbrances. The Mortgage Indenture contains provisions subjecting after-acquired property (other than excepted property and subject to pre-existing liens, if any, at the time of acquisition) to the lien thereof.

NJNG’s Mortgage Indenture no longer contains a restriction on NJNG’s ability to pay dividends. New Jersey Administrative Code 14:4-4.7 states that a public utility cannot issue dividends, without regulatory approval, if its equity to total capitalization ratio falls below 30 percent. As of September 30, 2018, NJNG’s equity to total capitalization ratio is 56.7 percent and has the ability to issue up to $1 billion of FMB under the terms of the Mortgage Indenture.

NJNG has variable rate EDA Bonds with a total principal amount of $97 million and maturity dates ranging from September 2027 to August 2041. The EDA Bonds are not subject to optional tender while they bear interest at a LIBOR index rate. As of September 30, 2018, the interest rate on the EDA Bonds was 2.03 percent.

In June 2016, NJNG entered into a Note Purchase Agreement, under which NJNG issued $125 million of its 3.63 percent senior notes due June 2046. The notes are secured by an equal principal amount of NJNG’s FMB (series UU) issued under NJNG’s Mortgage Indenture. The proceeds of the notes will be used for general corporate purposes, including, but not limited to, refinancing or retiring short-term debt and funding capital expenditures.

On January 17, 2017, the Company completed the purchase of three FMBs in lieu of redemption with an aggregate principal amount totaling $35.8 million. The FMBs bore interest at rates ranging from 4.5 percent to 4.9 percent. The bonds purchased in lieu of redemption are being held by the Company to provide an opportunity to evaluate remarketing alternatives.

On May 11, 2018, NJNG entered into a Note Purchase Agreement, under which NJNG issued $125 million, 4.01 percent senior notes due May 11, 2048. The interest rate includes the quoted March 9, 2018, 30-year treasury rate, plus a market based credit spread. The notes are secured by an equal principal amount of NJNG's FMB (series VV) issued under NJNG's Mortgage Indenture.

In June 2015, NJNG entered into a treasury lock transaction to fix a benchmark treasury rate of 3.26 percent associated with a $125 million debt issuance that was finalized in May 2018. This debt issuance coincided with the maturity of the $125 million, 5.6 percent notes that came due May 15, 2018. This treasury lock was settled on March 13, 2018, which coincided with the pricing of the new debt being issued. Settlement of the treasury lock resulted in a $2.6 million loss, which is recorded as a component of regulatory assets on the Consolidated Balance Sheets and will be amortized in earnings over the term of the May 11, 2018 debt issuance, discussed above.

Sale-Leasebacks

NJNG has entered into a sale-leaseback for its headquarters building, which has a 25.5-year term that expires in June 2021, subject to an option by NJNG to renew the lease for additional five-year terms a maximum of four times. The present value of the agreement’s minimum lease payments is reflected as both a capital lease asset and a capital lease obligation, which are included in utility plant and long-term debt, respectively, on the Consolidated Balance Sheets.

NJNG received $7.8 million, $9.6 million and $7.1 million for fiscal 2018, 2017 and 2016, respectively, in connection with the sale-leaseback of its natural gas meters. NJNG records a capital lease obligation that is paid over the term of the lease and has the option to purchase the meters back at fair value upon expiration of the lease. During fiscal 2018, 2017 and 2016, NJNG exercised early purchase options with respect to meter leases by making final principal payments of $2.2 million, $2.4 million and $1.9 million, respectively. NJNG continues to evaluate this sale-leaseback program based on current market conditions.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Contractual commitments for capital lease payments, as of the fiscal years ended September 30, are as follows:

(Thousands)	Lease Payments
2019		$	10,932
2020		7,989
2021		9,236
2022		3,775
2023		2,393
Thereafter		5,245
Subtotal		39,570
Less: Interest component		(3,633		)
Total		$	35,937

NJR

In March 2016, NJR entered into a Note Purchase Agreement, under which the Company issued, in August 2016, $50 million of the Company’s 3.2 percent senior notes due August 2023, and $100 million of the Company’s 3.54 percent senior notes due August 2026. The notes are not secured by assets, but are instead guaranteed by certain unregulated subsidiaries of the Company. The proceeds of the notes will be used for general corporate purposes, including working capital and capital expenditures.

On January 26, 2018, NJR entered into a variable-for-fixed interest rate swap on its existing $100 million variable rate term loan due August 16, 2019, which fixed the variable rate at 2.84 percent. On July 17, 2018, the $100 million variable rate term loan was amended to permit the disposition of assets relating to sale leaseback or other similar tax equity financing arrangements of meter assets or of solar or wind facilities. These transactions are permissible so long as NJR is in compliance with certain covenants both before and after such incurrence, and if no event of default may be caused by such sale leaseback or similar arrangement. As of September 30, 2018, NJR’s variable rate term loan was classified within current maturities of long-term debt.

On June 8, 2018, NJR entered into a Note Purchase Agreement, under which the Company issued $100 million, 3.96 percent senior notes due June 8, 2028. The notes are not secured by assets, but are instead guaranteed by certain unregulated subsidiaries of NJR.

Clean Energy Ventures

Clean Energy Ventures received proceeds of $71.5 million and $32.9 million in connection with the sale-leasebacks of commercial solar projects for fiscal 2018 and 2017, respectively. Clean Energy Ventures enters into transactions to sell the commercial solar assets concurrent with agreements to lease the assets back over a period of six to 15 years. These sale-leasebacks are treated as financing obligations, which are typically secured by the renewable energy facility asset and its future cash flows from SREC and energy sales. ITCs and other tax benefits associated with these solar projects are transferred to the buyer. Clean Energy Ventures continues to operate the solar assets, including related expenses, and retain the revenue generated from SRECs and energy sales, and has the option to renew the lease or repurchase the assets sold at the end of the lease term.

Contractual commitments for solar sale-leaseback lease payments, as of the fiscal years ended September 30, are as follows:

(Thousands)	Lease Payments
2019		$	9,794
2020		7,830
2021		7,803
2022		7,802
2023		7,878
Thereafter		38,303
Subtotal		79,410
Less: Interest component		(26,728		)
Total		$	52,682

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Short-term Debt

A summary of NJR’s and NJNG’s short-term bank facilities as of September 30, are as follows:

(Thousands)	2018			2017
NJR
Bank revolving credit facilities:(1)	$	425,000		$	425,000
Notes outstanding at end of period	$	87,950		$	255,000
Weighted average interest rate at end of period	3.07		%	2.14		%
Amount available at end of period (2)	$	322,144		$	156,601
NJNG
Bank revolving credit facilities: (3)	$	250,000		$	250,000
Commercial paper outstanding at end of period	$	64,000		$	11,000
Weighted average interest rate at end of period	2.18		%	1.13		%
Amount available at end of period (4)	$	185,269		$	238,269

(1) Committed credit facilities, which require commitment fees of .075 percent on the unused amounts.

(2) Letters of credit outstanding total $14.9 million and $13.4 million as of September 30, 2018 and 2017, respectively, which reduces amount available by the same amount.

(3) Committed credit facilities, which require commitment fees of .075 percent on the unused amounts.

(4) Letters of credit outstanding total $731,000 as of September 30, 2018 and 2017, which reduces amount available by the same amount.

NJR

NJR entered into a $425 million unsecured, committed credit facility scheduled to expire on September 28, 2020, subject to two mutual options for a one-year extension beyond that date. The NJR Credit Facility includes an accordion feature, which would allow NJR, in the absence of a default or event of default, to increase from time to time, with the existing or new lenders, the revolving credit commitments under the NJR Credit Facility in minimum $5 million increments up to a maximum of $100 million. The credit facility is used primarily to finance its share repurchases, to satisfy Energy Services’ short-term liquidity needs and to finance, on an initial basis, unregulated investments.

On June 25, 2018, the $425 million NJR Credit Facility was amended to permit liens and the disposition of assets relating to sale-leaseback or other similar tax equity financing arrangements of meter assets or of solar or wind facilities. These transactions are permissible so long as NJR is in compliance with certain covenants both before and after such incurrence, and if no event of default may be caused by such sale-leaseback or similar arrangement.

On December 14, 2017, NJR entered into a four-month, $75 million revolving line of credit facility.On January 19, 2018, NJR amended the agreement to increase the available amount to $100 million. This facility expired on April 14, 2018. No amounts were outstanding on the facility at the time of expiration.

As of September 30, 2018, NJR had six letters of credit outstanding totaling $14.9 million. Three letters of credit totaling $11.9 million are issued on behalf of Energy Services and three letters of credit, which total $3 million, are issued on behalf of Clean Energy Ventures. These letters of credit reduce the amount available under NJR’s committed credit facility by the same amount. NJR does not anticipate that these letters of credit will be drawn upon by the counterparties, and they will be renewed as necessary.

Energy Services’ letters of credit are used for margin requirements for natural gas transactions, collateral and security deposit for retail gas sales and expire on dates ranging from December 2018 to September 2019. Clean Energy Ventures’ letters of credit are used to secure construction of ground-mounted solar projects and to secure obligations pursuant to an Interconnection Services Agreement. They expire on dates ranging from May 2019 to August 2019.

Neither NJNG nor the results of its operations are obligated or pledged to support the NJR credit or debt shelf facilities.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

NJNG

NJNG has a $250 million, five-year, revolving, unsecured credit facility, which expires in May 2019. The NJNG Credit Facility permits the borrowing of revolving loans and swing loans, as well as the issuance of letters of credit. It also permits an increase to the facility, from time to time, with the existing or new lenders, in a minimum of $15 million increments up to a maximum of $50 million at the lending banks’ discretion.

As of September 30, 2018, NJNG has two letters of credit outstanding for $731,000. NJNG’s letters of credit are used as collateral for remediation projects and expire in August 2019. These letters of credit reduce the amount available under NJNG’s committed credit facility by the same amount. NJNG does not anticipate that these letters of credit will be drawn upon by the counterparty and will be renewed as necessary.

9. STOCK-BASED COMPENSATION

Effective January 25, 2017, the shareholders of the Company approved the NJR 2017 Stock Award and Incentive Plan, which replaced the NJR 2007 Stock Award and Incentive Plan. The 2007 plan had 914,169 shares granted but not issued as of September 30, 2017, which were transferred into the 2017 plan. The 2017 plan added an additional 3,135,000 shares available for issuance. Shares have been issued in the form of performance shares, restricted stock, deferred retention stock and unrestricted common stock to non-employee directors. As of September 30, 2018, 3,473,062 shares remain available for future issuance.

The following table summarizes all stock-based compensation expense recognized during the following fiscal years:

(Thousands)	2018			2017			2016
Stock-based compensation expense:
Performance share awards	$	3,526		$	2,614		$	3,188
Restricted and non-restricted stock	2,191			1,732			2,161
Deferred retention stock	7,128			1,461			1,885
Compensation expense included in operation and maintenance expense	12,845			5,807			7,234
Income tax benefit (1)	(3,734		)	(2,372		)	(2,955		)
Total, net of tax	$	9,111		$	3,435		$	4,279

(1) Excludes additional tax benefit related to delivered shares of $3 million, $1.3 million and $1.8 million as of September 30, 2018, 2017 and 2016, respectively.

Performance Shares

In fiscal 2018, the Company granted to various officers 31,836 performance shares, which are market condition awards that vest on September 30, 2020, subject to the Company meeting certain performance conditions. In fiscal 2018, the Company also granted to various officers 59,341 performance shares, of which 29,608 vest on September 30, 2020 and 29,733 vest annually over a three-year period beginning on September 30, 2018, both of which are subject to the Company meeting certain performance conditions.

In fiscal 2017, the Company granted to various officers 44,576 performance shares, which are market condition awards that vest on September 30, 2019, subject to the Company meeting certain performance conditions. In fiscal 2017, the Company also granted to various officers 51,931 performance shares, of which 25,806 vest on September 30, 2019 and 26,125 vest annually over a three-year period beginning in September 30, 2017, both of which are subject to the Company meeting certain performance conditions.

In fiscal 2016, the Company granted to various officers 46,175 performance shares, which are market condition awards that vested on September 30, 2018, subject to the Company meeting certain performance conditions. In fiscal 2016, the Company also granted to various officers 69,305 performance shares, of which 38,789 vested in September 30, 2018 and 30,516 vest annually over a three-year period beginning in September 2016, 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 $3.8 million of deferred compensation related to unvested performance shares that is expected to be recognized over the weighted average period of 1.7 years.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

The following table summarizes the performance share activity under the stock award and incentive plans for the past three fiscal years:

	Shares (1)		Weighted Average Grant Date Fair Value		Total Fair Value of Vested Shares (in Thousands)
Non-vested and outstanding at September 30, 2015	214,464			$23.40		—
Granted	115,480			$27.37		—
Vested (2)	(137,053	)		$21.40		$	5,657
Cancelled/forfeited (3)	(12,975	)		$23.40		—
Non-vested and outstanding at September 30, 2016	179,916			$27.47		—
Granted	96,507			$33.57		—
Vested (4)	(95,407	)		$28.88		$	4,179
Cancelled/forfeited	(24,429	)		$29.14		—
Non-vested and outstanding at September 30, 2017	156,587			$30.12		—
Granted	91,177			$44.67		—
Vested (5)	(100,146	)		$29.49		$	4,714
Cancelled/forfeited	(2,442	)		$31.45		—
Non-vested and outstanding at September 30, 2018	145,176			$39.67		—

(1) The number of common shares issued related to certain performance shares may range from zero to 150 percent of the number of shares shown in the table above based on the Company’s achievement of performance goals.

(2) As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, the number of common shares related to performance shares earned was 85 percent, or 55,702 shares, the number of common shares earned related to NFE performance was 150 percent or 71,808 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 23,649 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

(3) As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, 9,366 shares were canceled due to not achieving a certain performance target. The remainder were forfeitures due to individuals departing the Company.

(4) As certified by the Company’s Leadership and Compensation Committee on November 14, 2017, the number of common shares earned related to TSR performance was 108.44 percent or 39,595 shares, the number of common shares earned related to NFE performance was 119 percent or 36,498 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 28,223 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

(5) As certified by the Company’s Leadership and Compensation Committee on November 13, 2018, the number of common shares earned related to TSR performance was 99 percent or 38,660 shares, the number of common shares earned related to NFE performance was 121 percent or 39,694 shares and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 36,998 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

The Company measures compensation expense related to performance shares based on the fair value of these awards at their date of grant. In accordance with ASC 718, Compensation - Stock Compensation, compensation expense for market condition grants are recognized for awards granted, and are not adjusted based on actual achievement of the performance goals. The Company estimated the fair value of these grants on the date of grant using a lattice model. Performance condition grants are initially fair valued at the Company’s stock price on grant date, and are subsequently adjusted for actual achievement of the performance goals.

Restricted Stock

In fiscal 2018, the Company granted 27,949 shares of restricted stock that vest annually over a three-year period beginning October 15, 2018. In fiscal 2017, the Company granted 22,591 shares of restricted stock that vest annually over a three-year period beginning in October 2017. In fiscal 2017, the Company also granted 6,143 shares of restricted stock that vest annually over a three-year period beginning May 8, 2018. In fiscal 2016, the Company granted 41,909 shares of restricted stock that vest annually over a three-year period beginning in October 2016. There is approximately $612,964 of deferred compensation related to unvested restricted stock shares that is expected to be recognized over the weighted average period of two years.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

The following table summarizes the restricted stock activity under the stock award and incentive plans for the past three fiscal years:

	Shares		Weighted Average Grant Date Fair Value		Total Fair Value of Vested Shares (in Thousands)
Non-vested and outstanding at September 30, 2015	81,492			$27.17		—
Granted	41,909			$30.03		—
Vested	(48,089	)		$26.66		$	1,469
Cancelled/forfeited	(2,241	)		$29.21		—
Non-vested and outstanding at September 30, 2016	73,071			$29.09		—
Granted	28,734			$35.79		—
Vested	(38,752	)		$28.92		$	1,344
Cancelled/forfeited	(11,899	)		$31.56		—
Non-vested and outstanding at September 30, 2017	51,154			$32.40		—
Granted	27,949			$45.00
Vested	(33,815	)		$31.23		$	1,438
Cancelled/forfeited	(1,120	)		$33.54
Non-vested and outstanding at September 30, 2018	44,168			$41.24		—

Deferred Retention Stock

Deferred retention stock awards vest immediately when granted, with shares delivered at a future date in accordance with the terms of the underlying agreements. The expense for these awards is recognized in the fiscal year in which services are rendered. The related shares are granted upon approval by the Board of Directors, which generally occurs subsequent to the fiscal year end.

The following table summarizes the deferred retention stock award under the stock award and incentive plans for the past three fiscal years:

	Shares		Weighted Average Grant Date Fair Value		Total Fair Value of Vested Shares (in Thousands)
Outstanding at September 30, 2015	632,730			$27.03		—
Granted/Vested	159,831			$30.37		—
Delivered	(121,764	)		$20.31		$	3,751
Forfeited	(8,318	)		$28.14		—
Outstanding at September 30, 2016	662,479			$29.06		—
Granted/Vested	63,977			$35.64		—
Delivered	(53,878	)		$23.11		$	1,774
Outstanding at September 30, 2017	672,578			$29.54		—
Granted/Vested	24,167			$45.00
Delivered	(452,694	)		$29.42		$	19,581
Forfeited	(1,969	)		$35.56
Outstanding at September 30, 2018	242,082			$32.99		—

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Non-Employee Director Stock

Non-employee director compensation includes an annual January retainer that is awarded in stock. The shares vest immediately and are subsequently amortized to expense over a 12-month period. The following summarizes non-employee director share awards for the past three fiscal years:

	2018		2017	2016
Shares granted	26,524	(1)	27,972	27,481
Weighted average grant date fair value	$39.85		$35.59	$32.75

(1) $264,000 of expense remains as of September 30, 2018, to be recognized through December 31, 2018.

10. EMPLOYEE BENEFIT PLANS

Pension and Other Postemployment Benefit Plans

The Company has two trusteed, noncontributory defined benefit retirement plans covering eligible regular represented and nonrepresented employees with more than one year of service. Defined benefit plan benefits are based on years of service and average compensation during the highest 60 consecutive months of employment. The Company also provides postemployment medical and life insurance benefits to employees who meet certain eligibility requirements.

All represented employees of NJRHS hired on or after October 1, 2000, non-represented employees hired on or after October 1, 2009 and NJNG represented employees hired on or after January 1, 2012, are covered by an enhanced defined contribution plan instead of the defined benefit plan. Participation in the postemployment medical and life insurance plan was also frozen to new employees as of the same dates, with the exception of new NJRHS represented employees, for which benefits were frozen beginning April 3, 2012.

The Company maintains an unfunded nonqualified PEP that was established to provide employees with the full level of benefits as stated in the qualified plan without reductions due to various limitations imposed by the provisions of federal income tax laws and regulations. There were no plan assets in the nonqualified plan due to the nature of the plan.

In April 2018, the Company implemented a voluntary early retirement program open to certain eligible employees. As of September 30, 2018, pension and postemployment benefit costs related to the special termination benefits were $4.2 million and other severance benefits were $2.2 million. For the amounts incurred, NJNG recognized an expense of approximately $5.1 million and Home Services and other recognized an expense of approximately $1.3 million, as a component of O&M in the Consolidated Statements of Operations.

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 2018 and 2017, the Company had no minimum funding requirements. The Company made no discretionary contributions to the pension plans in fiscal 2018 or 2017. The Company does not expect to be required to make additional contributions to fund the pension plans over the following two fiscal years based on current actuarial assumptions; however, funding requirements are uncertain and can depend significantly on changes in actuarial assumptions, returns on plan assets and changes in the demographics of eligible employees and covered dependents.

There are no federal requirements to pre-fund OPEB benefits. However, the Company is required to fund certain amounts due to regulatory agreements with the BPU. The Company contributed $6.2 million and $6 million, in fiscal 2018 and 2017, respectively, and estimates that it will contribute between $5 million to $8 million over each of the next five years. Additional contributions may be required based on market conditions and changes to assumptions.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

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)	2018			2017			2018			2017
Change in Benefit Obligation
Benefit obligation at beginning of year	$	297,835		$	293,654		$	175,090		$	160,393
Service cost	8,139			8,347			4,607			4,380
Interest cost	10,493			9,771			6,365			5,545
Plan participants’ contributions (2)	45			45			161			120
Special termination benefits (3)	3,730			—			490			—
Actuarial (gain) loss	(12,846		)	(5,995		)	15,145			8,985
Benefits paid, net of retiree subsidies received	(8,821		)	(7,987		)	(5,073		)	(4,333		)
Benefit obligation at end of year	$	298,575		$	297,835		$	196,785		$	175,090
Change in plan assets
Fair value of plan assets at beginning of year	$	271,743		$	249,875		$	71,534		$	62,035
Actual return on plan assets	16,306			29,736			5,284			7,953
Employer contributions	137			74			6,222			6,049
Benefits paid, net of plan participants’ contributions (2)	(8,776		)	(7,942		)	(5,060		)	(4,503		)
Fair value of plan assets at end of year	$	279,410		$	271,743		$	77,980		$	71,534
Funded status	$	(19,165	)	$	(26,092	)	$	(118,805	)	$	(103,556	)
Amounts recognized on Consolidated Balance Sheets
Postemployment employee (liability)
Current	$	(294	)	$	(158	)	$	(669	)	$	(602	)
Noncurrent	(18,871		)	(25,934		)	(118,136		)	(102,954		)
Total	$	(19,165	)	$	(26,092	)	$	(118,805	)	$	(103,556	)

(1) Includes the Company’s PEP.

(2) Prior to July 1, 1998, employees were eligible to elect an additional participant contribution to enhance their benefits and contributions made during the periods were insignificant.

(3) Related to the voluntary early retirement program offered during fiscal 2018, as previously discussed.

The actuarial gain on the Company’s pension plans is primarily due to an increase in the discount rate used to measure the obligation. The actuarial loss related to the OPEB plans is primarily due to an increase in expected retiree healthcare claims, partially offset by an increase in the discount rate. 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 other comprehensive income for the portion of the liability related to its unregulated operations.

The following table summarizes the amounts recognized in regulatory assets and accumulated other comprehensive income as of September 30:

	Regulatory Assets						Accumulated Other Comprehensive Income (Loss)
	Pension			OPEB			Pension			OPEB
Balance at September 30, 2016	$	94,941		$	59,147		$	28,436		$	4,486
Amounts arising during the period:
Net actuarial (gain) loss	(9,429		)	5,211			(6,990		)	587
Amounts amortized to net periodic costs:
Net actuarial (loss)	(6,799		)	(4,209		)	(2,028		)	(160		)
Prior service (cost) credit	(108		)	311			(3		)	54
Balance at September 30, 2017	$	78,605		$	60,460		$	19,415		$	4,967
Amounts arising during the period:
Net actuarial (gain) loss	(6,090		)	12,378			(3,422		)	2,834
Amounts amortized to net periodic costs:
Net actuarial (loss)	(6,177		)	(4,464		)	(1,359		)	(196		)
Prior service (cost) credit	(105		)	311			(1		)	54
Balance at September 30, 2018	$	66,233		$	68,685		$	14,633		$	7,659

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

The amounts in regulatory assets and accumulated other comprehensive income not yet recognized as components of net periodic benefit cost as of September 30 are:

	Regulatory Assets										Accumulated Other Comprehensive Income (Loss)
	Pension				OPEB						Pension				OPEB
(Thousands)	2018		2017		2018			2017			2018		2017		2018			2017
Net actuarial loss	$	65,664	$	77,930	$	69,477		$	61,563		$	14,633	$	19,414	$	7,750		$	5,113
Prior service cost (credit)	569		675		(792		)	(1,103		)	—		1		(91		)	(146		)
Total	$	66,233	$	78,605	$	68,685		$	60,460		$	14,633	$	19,415	$	7,659		$	4,967

To the extent the unrecognized amounts in accumulated other comprehensive income or regulatory assets exceed 10 percent of the greater of the benefit obligation or the fair value of plan assets, an amortized amount over the average expected future working lifetime of the active plan participants is recognized. Amounts included in regulatory assets and accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost in fiscal 2019 are as follows:

	Regulatory Assets					Accumulated Other Comprehensive Income (Loss)
(Thousands)	Pension		OPEB			Pension		OPEB
Net actuarial loss	$	4,662	$	5,527		$	1,103	$	643
Prior service cost (credit)	102		(312		)	—		(53		)
Total	$	4,764	$	5,215		$	1,103	$	590

The accumulated benefit obligation for the pension plans, including the PEP, exceeded the fair value of plan assets. The projected benefit and accumulated benefit obligations and the fair value of plan assets as of September 30, are as follows:

	Pension
(Thousands)	2018		2017
Projected benefit obligation	$	298,575	$	297,835
Accumulated benefit obligation	$	263,279	$	258,514
Fair value of plan assets	$	279,410	$	271,743

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)	2018			2017			2016			2018			2017			2016
Service cost	$	8,139		$	8,347		$	7,591		$	4,607		$	4,380		$	4,521
Interest cost	10,493			9,771			11,342			6,365			5,545			6,256
Expected return on plan assets	(19,639		)	(19,313		)	(20,118		)	(5,352		)	(4,767		)	(4,845		)
Recognized actuarial loss	7,537			8,827			7,281			4,660			4,370			3,274
Prior service cost (credit) amortization	106			111			111			(365		)	(365		)	(365		)
Net periodic benefit cost	$	6,636		$	7,743		$	6,207		$	9,915		$	9,163		$	8,841
Special termination benefit	3,730			—			—			490			—			—
Net periodic benefit cost recognized as expense	$	10,366		$	7,743		$	6,207		$	10,405		$	9,163		$	8,841

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

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
	2018			2017			2016			2018			2017			2016
Benefit costs:
Discount rate	4.04/4.03%			3.96/3.94%			4.50	%		4.12/4.08%		(1)	4.08/4.01%		(1)	4.60/4.55%
Expected asset return	7.50	%		7.75	%		8.75	%		7.50	%		7.75	%		8.75	%
Compensation increase	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%			3.25/3.50%		(1)	3.25/3.50%			3.50	%
Obligations:
Discount rate	4.36/4.35%			4.03	%	(1)	3.96/3.94%			4.38/4.37%		(1)	4.12/4.08%		(1)	4.08/4.01%		(1)
Compensation increase	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%			3.50	%

(1) Percentages for represented and nonrepresented plans, respectively.

When measuring its projected benefit obligations, the Company uses an aggregate discount rate at which its obligation could be effectively settled. The Company determines a single weighted average discount rate based on a yield curve comprised of rates of return on a population of high quality debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of its expected future benefit payments. Prior to October 1, 2016, the Company used the same assumed rate to measure the service and interest cost components of its net periodic benefit costs. Effective October 1, 2016, the Company changed its method of measuring its service and interest costs from the aggregate approach to a disaggregated, or spot rate, approach. Under the new approach, the Company applies the duration-specific spot rates from the full yield curve, as of the measurement date, to each year’s future benefit payments. The Company believes that this provides for a more precise measurement of its service and interest costs by aligning the timing of the plans’ separate future cash flows to the corresponding spot rates on the yield curve.

Information relating to the assumed HCCTR used to determine expected OPEB benefits as of September 30, and the effect of a 1 percent change in the rate, are as follows:

($ in thousands)	2018			2017			2016
HCCTR	7.9		%	8.3		%	8.5		%
Ultimate HCCTR	4.5		%	4.5		%	4.5		%
Year ultimate HCCTR reached	2024			2025			2025
Effect of a 1 percentage point increase in the HCCTR on:
Year-end benefit obligation	$	36,260		$	32,019		$	28,803
Total service and interest cost	$	2,482		$	2,468		$	2,331
Effect of a 1 percentage point decrease in the HCCTR on:
Year-end benefit obligation	$	(28,743	)	$	(25,466	)	$	(22,862	)
Total service and interest costs	$	(1,937	)	$	(1,909	)	$	(1,801	)

The Company’s investment objective is a long-term real rate of return on assets before permissible expenses that is approximately 5 percent greater than the assumed rate of inflation, as measured by the consumer price index. The expected long-term rate of return is based on the asset categories in which the Company invests and the current expectations and historical performance for these categories.

The mix and targeted allocation of the pension and OPEB plans’ assets are as follows:

	2019		Assets at
	Target		September 30,
Asset Allocation	Allocation		2018		2017
U.S. equity securities	34	%	41	%	39	%
International equity securities	17		19		21
Fixed income	41		37		40
Other assets	8		3		—
Total	100	%	100	%	100	%

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

The Company adopted the revised mortality assumptions published by the Society of Actuaries for its pension and other postemployment benefit obligations, which reflected increased life expectancies in the United States. The adoption of the new mortality projection scale, MP-2017, 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)	Pension		OPEB
2019	$	10,320	$	5,450
2020	$	11,769	$	6,512
2021	$	12,399	$	7,096
2022	$	13,239	$	7,810
2023	$	14,217	$	8,413
2024 - 2028	$	85,426	$	50,869

The Company’s OPEB plans provide prescription drug benefits that are actuarially equivalent to those provided by Medicare Part D. Therefore, under the Medicare Prescription Drug, Improvement and Modernization Act of 2003, the Company qualifies for federal subsidies.

The following estimated subsidy payments are expected to be paid during the following fiscal years:

	Estimated Subsidy
(Thousands)	Payment
2019		$	280
2020		$	316
2021		$	347
2022		$	375
2023		$	417
2024 - 2028		$	2,787

Pension and OPEB assets held in the master trust, measured at fair value, as of September 30, are summarized as follows:

	Quoted Prices in Active Markets for Identical Assets (Level 1)
(Thousands)	Pension				OPEB
Assets	2018		2017		2018		2017
Money market funds	$	8,207	$	—	$	2,273	$	11
Registered Investment Companies:
Equity Funds:
Large Cap Index	97,016		88,321		27,340		23,986
Extended Market Index	17,741		16,329		5,014		4,409
International Stock	53,516		56,446		14,874		15,000
Fixed Income Funds:
Emerging Markets	11,754		13,516		3,264		3,551
Core Fixed Income	—		—		7,970		8,082
Opportunistic Income	—		—		4,798		4,744
Ultra Short Duration	—		—		4,830		4,673
High Yield Bond Fund	25,720		26,540		7,236		7,078
Long Duration Fund	64,039		70,591		—		—
Total assets	$	277,993	$	271,743	$	77,599	$	71,534

The Plan had no Level 2 or Level 3 fair value measurements during fiscal 2018 and 2017, and there have been no changes in valuation methodologies as of September 30, 2018. The Plan held $1.8 million of other assets as of September 30, 2018, that are valued using net asset value as a practical expedient, which are excluded from the fair value hierarchy.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

The following is a description of the valuation methodologies used for assets measured at fair value:

Money Market funds — Represents bank balances and money market funds that are valued based on the net asset value of shares held at year end.

Registered Investment Companies — Equity and fixed income funds valued at the net asset value of shares held by the plan at year end as reported on the active market on which the individual securities are traded.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Plan believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

Defined Contribution Plan

The Company offers a Savings Plan to eligible employees. As of January 1, 2015, the Company matches 65 percent of participants’ contributions up to 6 percent of base compensation. Represented NJRHS employees, non-represented employees hired on or after October 1, 2009, and NJNG represented employees hired on or after January 1, 2012, are eligible for an employer special contribution of between 3 and 4 percent of base compensation, depending on years of service, into the Savings Plan on their behalf. The amount expensed and contributed for the matching provision of the Savings Plan was $3.9 million in fiscal 2018, $2.9 million in fiscal 2017 and $2.8 million in fiscal 2016. The amount contributed for the employer special contribution of the Savings Plan was $959,000 in fiscal 2018, $781,000 in fiscal 2017 and $571,000 in fiscal 2016.

11. ASSET RETIREMENT OBLIGATIONS

The Company recognizes AROs when the legal obligation to retire an asset has been incurred and a reasonable estimate of fair value can be made. Accordingly, the Company recognizes AROs related to the costs associated with cutting and capping its main and service gas distribution pipelines of NJNG, which is required by New Jersey law when taking such gas distribution pipeline out of service. The Company also recognizes AROs related to Clean Energy Ventures’ solar and wind assets when there are decommissioning provisions in Clean Energy Ventures’ lease agreements that require removal of the asset.

Accretion amounts associated with NJNG’s ARO are recognized as part of its depreciation expense and the corresponding regulatory asset and liability will be shown gross on the Consolidated Balance Sheets. Accretion amounts associated with Clean Energy Ventures’ ARO are recognized as a component of operations and maintenance expense on the Consolidated Statements of Operations.

The following is an analysis of the change in the Company’s AROs for the fiscal years ended September 30:

(Thousands)	2018						2017
	NJNG			NJRCEV			NJNG			NJRCEV
Balance at October 1	$	24,825		$	6,595		$	23,521		$	4,858
Accretion	1,366			198			1,304			245
Additions	1,880			517			729			1,492
Revisions in estimated cash flows	(2,133		)	—			(245		)	—
Retirements	(298		)	—			(484		)	—
Reclassification to held for sale or sold	—			(4,262		)	—			—
Balance at period end	$	25,640		$	3,048		$	24,825		$	6,595

Accretion for the next five years, for the fiscal years ended September 30, is estimated to be as follows:

	Estimated
(Thousands)	Accretion
2019	$	1,557
2020	1,627
2021	1,702
2022	1,778
2023	1,863
Total	$	8,527

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

12. INCOME TAXES

The income tax (benefit) provision from operations for the fiscal years ended September 30, consists of the following:

(Thousands)	2018			2017			2016
Current:
Federal	$	(2,848	)	$	(16,023	)	$	(23,597	)
State	4,563			2,470			(2,209		)
Deferred:
Federal	(40,785		)	54,965			70,386
State	6,731			11,457			11,441
Investment/production tax credits	(21,446		)	(34,526		)	(32,491		)
Income tax (benefit) provision	$	(53,785	)	$	18,343		$	23,530

As of September 30, the temporary differences, which give rise to deferred tax assets and (liabilities), consist of the following:

(Thousands)	2018			2017
Deferred tax assets
Investment tax credits (1)	$	123,258		$	111,642
Deferred service contract revenue	—			3,877
Incentive compensation	4,646			6,260
Fair value of derivatives	8,411			11,519
Federal net operating losses (2)	24,500			28,487
State net operating losses	34,754			23,597
Amortization of intangibles	3,737			2,747
Conservation incentive plan	1,955			—
Other	8,213			11,098
Total deferred tax assets	$	209,474		$	199,227
Deferred tax liabilities
Property related items	$	(392,886	)	$	(620,850	)
Remediation costs	(9,229		)	(11,625		)
Equity investments	(31,956		)	(38,370		)
Postemployment benefits	(353		)	(6,855		)
Conservation incentive plan	—			(7,195		)
Underrecovered gas costs	(1,156		)	(4,035		)
Other	(7,826		)	(16,643		)
Total deferred tax liabilities	$	(443,406	)	$	(705,573	)
Total net deferred tax liabilities	$	(233,932	)	$	(506,346	)

(1) Includes $2.2 million and $2.3 million for NJNG for fiscal 2018 and 2017, respectively, which is being amortized over the life of the related assets, and$121.1 million and $109.3 million for Clean Energy Ventures for fiscal 2018 and 2017, respectively, which is ITC carryforward.

(2) See discussion of federal net operating loss utilization in the Other Tax Items section of this note.

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)	2018			2017			2016
Statutory income tax expense	$	44,014		$	52,643		$	54,321
Change resulting from:
Tax Act - nonutility excess deferred income taxes (1)	(59,627		)	—			—
Tax Act - utility excess deferred income taxes refunded to customers (1)	(14,323		)	—			—
Tax Act - utility excess deferred income taxes amortized (1)	(1,786		)	—			—
State income taxes, net of federal benefit	7,092			8,222			6,044
Cost of removal of assets placed in service prior to1981	(5,829		)	(6,886		)	(5,738		)
Investment/production tax credits	(21,446		)	(34,526		)	(32,491		)
Basis adjustment of solar assets due to ITC	1,080			4,256			4,453
AFUDC equity	(2,117		)	(2,624		)	(1,531		)
Other	(843		)	(2,742		)	(1,528		)
Income tax (benefit) provision	$	(53,785	)	$	18,343		$	23,530
Effective income tax rate (2) (3)	(29.9		)%	12.2		%	15.2		%

(1) For a more detailed description, see The Tax Act section of this note.

(2) The U.S. federal statutory rate was 24.5 percent for fiscal 2018 and 35 percent for fiscal 2017 and 2016.

(3) The effective tax rate without the impact of the Tax Act would have been 12.4 percent for fiscal 2018.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

The Company and one or more of its subsidiaries files or expects to file income and/or franchise tax returns in the U.S. Federal jurisdiction and in the states of Colorado, Connecticut, Delaware, Iowa, Kansas, Louisiana, Maryland, Montana, New Jersey, New York, North Carolina, Pennsylvania, South Carolina, Texas, Utah, Virginia and the City of New York. The Company neither files in, nor believes it has a filing requirement in, any foreign jurisdictions other than Canada. Due to certain available tax treaty benefits, the Company incurs no tax liability in Canada.

The Company’s federal income tax returns through fiscal 2014 have either been reviewed by the IRS, or the related statute of limitations has expired and all matters have been settled. Federal income tax returns for periods subsequent to fiscal 2014 are not currently under examination by the IRS. For all periods subsequent to those ended September 30, 2014, 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, 2013 are statutorily open to examination.

The State of New Jersey is currently conducting a sales and use tax examination for the period from July 1, 2011 through September 30, 2018.

On March 7, 2018, the State of New Jersey notified the Company that it will conduct a general tax examination for fiscal years 2014 through 2017 related to NJRHS. The audit is currently in the information gathering stage. All periods subsequent to those ended September 30, 2013, are statutorily open to examination.

The Company evaluates its tax positions to determine the appropriate accounting and recognition of potential future obligations associated with unrecognized tax benefits. As of September 30, 2018 and 2017, based on its analysis, the Company determined there was no need to recognize any liabilities associated with uncertain tax positions.

The Tax Act

On December 22, 2017, the President signed into law the Tax Act. The law made several changes to the Internal Revenue Code of 1986, as amended, the most impactful to the Company of which was a reduction in the federal corporate income tax rate from 35 percent to 21 percent that became effective January 1, 2018. Since the Company's fiscal year end is September 30, it is required by the Internal Revenue Code to calculate a statutory rate based upon the federal tax rates in effect before and after the effective date of the change in the taxable year that includes the effective date. Accordingly, the Company will use a federal statutory tax rate of 24.5 percent during fiscal 2018 and will use the enacted rate of 21 percent beginning in fiscal 2019.

The SEC issued guidance in Staff Accounting Bulletin 118 to address the changes in estimates associated with impacts resulting from the Tax Act, which allows companies to record provisional amounts during a one-year measurement period. The Company calculated an original estimate for the measurement and accounting for certain effects of the Tax Act, including the remeasurement of deferred tax assets and liabilities to reflect the rates that will be in effect when the deferred tax assets and liabilities are expected to be realized or settled. The adjustments to deferred income taxes were based on assumptions the Company made with respect to its book versus tax differences and the timing of when those differences will reverse, including estimations associated with depreciation and the settlement of derivative unrealized amounts. Therefore, the revaluation of net deferred tax liabilities was subject to change as information and assumptions were updated each quarter for actual results.

As a result of the changes associated with the Tax Act, NJNG recorded a decrease in its net deferred tax liability of $228.4 million, which included $164.3 million for the revaluation of its deferred income taxes and $64.1 million for the accounting of the income tax effects on the revaluation of those deferred income taxes. These amounts were recorded as a regulatory liability on the Consolidated Balance Sheets. On May 22, 2018, the BPU approved a refund of $31 million, which included approximately $20.1 million of the initial revaluation of excess deferred income taxes, $9 million for the overcollection of taxes from customers from January 1, 2018 through March 31, 2018, and interest on the overcollected taxes at the Company's short-term debt rate. These credits were returned to customer accounts in June 2018.

During fiscal 2018, NJNG credited approximately $17 million to income tax (benefit) provision on the Consolidated Statements of Operations, which includes $14.3 million attributable to the remeasurement of deferred income taxes, $1.8 million for the amortization of excess deferred income taxes primarily related to timing differences associated with utility plant depreciation and $880,000 related to the revaluation of deferred income taxes not included in base rates. As of September 30, 2018, the regulatory liability included excess deferred income taxes of $205.4 million, which requires amortization over the remaining life of the utility plant consistent with IRS normalization principles.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

The (decrease) increase of the net deferred tax liability due to the impact of the Tax Act that was recognized on the Consolidated Statements of Operations for the remaining entities, was as follows:

(Thousands)	2018
Income tax (benefit) provision
Clean Energy Ventures	$	(61,423	)
Energy Services	6,062
Midstream	(13,946		)
Home Services and Other	9,680
Total	$	(59,627	)

There was a $2.1 million change in the original estimate resulting from the use of actual results instead of estimated results through the Company’s fourth fiscal quarter.

As of September 30, 2018, our accounting for the income tax effects of the Tax Act is considered complete. The Company does not expect to make any further adjustments to the amounts recorded as a result of the Tax Act.

Other Tax Items

As of September 30, 2018 and 2017, the Company has federal income tax net operating losses of approximately $136.8 million and $125.3 million, respectively. Federal net operating losses can generally can be carried back two years and forward 20 years and will begin to expire in fiscal 2036, with the remainder expiring by 2038. The Company expects to exercise its ability to carryback federal net operating losses to offset taxable income in prior periods.

For the net operating losses it expects to carryback, the Company estimated the portion considered refundable and recorded receivables of approximately $23 million and $15.4 million as of September 30, 2018 and 2017, respectively, as a component of other noncurrent assets on the Consolidated Balance Sheets. Upon filing amended federal income tax returns to carryback its remaining federal net operating losses totaling $24.5 million, the Company will reduce its taxable income in those periods and recapture federal investment tax credits of the same amount that were previously utilized to offset taxable income.

In addition, as of September 30, 2018 and 2017, the Company has an ITC/PTC carryforward of approximately $121.1 million and $109.3 million, respectively, which each have a life of 20 years. When the Company carries back the federal net operating losses noted above, it expects to recapture investment tax credits totaling $24.5 million. These recaptured tax credits are in addition to the $121.1 million and will be carried forward to offset future taxable income. The Company expects to utilize this entire carryforward, which would begin to expire in fiscal 2033.

As of September 30, 2018 and 2017, the Company has state income tax net operating losses of approximately $578.8 million and $471.7 million, respectively. These state net operating losses have varying carry forward periods dictated by the state in which they were incurred; these state carry forward periods range from seven to 20 years and would begin to expire in fiscal 2021, with the majority expiring after 2035.

In March 2018, Clean Energy Ventures committed to a plan to sell its wind assets and expects that the sale will be completed within the next 12 months. As a result of the planned sale, it is more likely than not that certain state net operating loss carryforwards will not be realizable prior to their expiration. As of September 30, 2018, the Company had a valuation allowance of $4 million related to state net operating loss carryforwards in Montana, Iowa, Kansas and Wyoming. As of September 30, 2017, the Company had a valuation allowance of $1 million related to state net operating loss carryforwards in Montana. This is included as a component of Other within the composition of deferred tax assets.

The Consolidated Appropriations Act extended the 30 percent ITC for solar property that is under construction on or before December 31, 2019. The credit will decline to 26 percent for property under construction during 2020, and to 22 percent for property under construction during 2021. For any property that is under construction before 2022, but not placed in service before 2024, the ITC will be reduced to 10 percent. In addition, the Consolidated Appropriations Act retroactively extended the PTC for five years through December 31, 2019, with a gradual three-year phase-out for any project for which construction of the facility begins after December 31, 2016.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

13. COMMITMENTS AND CONTINGENT LIABILITIES

Cash Commitments

NJNG has entered into long-term contracts, expiring at various dates through September 2024, for the supply, storage and transportation of natural gas. These contracts include annual fixed charges of approximately $112 million at current contract rates and volumes, which are recoverable through BGSS.

For the purpose of securing storage and pipeline capacity, our Energy Services segment enters into storage and pipeline capacity contracts, which require the payment of certain demand charges by Energy Services to maintain the ability to access such natural gas storage or pipeline capacity, during a fixed time period, which generally ranges from one to 10 years. Demand charges are established by interstate storage and pipeline operators and are regulated by FERC. These demand charges represent commitments to pay storage providers or pipeline companies for the right to store and/or transport natural gas utilizing their respective assets.

Commitments as of September 30, 2018, for natural gas purchases and future demand fees for the next five fiscal year periods, are as follows:

(Thousands)	2019		2020		2021		2022		2023		Thereafter
Energy Services:
Natural gas purchases	$	428,015	$	28,389	$	10,965	$	—	$	—	$	—
Storage demand fees	31,716		19,926		13,478		8,904		4,212		991
Pipeline demand fees	52,148		49,790		28,209		24,153		18,988		5,151
Sub-total Energy Services	$	511,879	$	98,105	$	52,652	$	33,057	$	23,200	$	6,142
NJNG:
Natural gas purchases	$	65,737	$	37,727	$	33,738	$	33,546	$	34,221	$	35,762
Storage demand fees	31,384		24,263		14,251		12,930		7,899		6,066
Pipeline demand fees	80,609		96,241		89,236		91,946		87,240		586,266
Sub-total NJNG	$	177,730	$	158,231	$	137,225	$	138,422	$	129,360	$	628,094
Total	$	689,609	$	256,336	$	189,877	$	171,479	$	152,560	$	634,236

As of September 30, 2018, the Company’s future minimum lease payments under various operating leases will not be more than $3.7 million annually for the next five years and $50 million in the aggregate for all years thereafter.

Guarantees

As of September 30, 2018, there were NJR guarantees covering approximately $418.1 million of Energy Services’ natural gas purchases and demand fee commitments not yet reflected in accounts payable on the Consolidated Balance Sheets.

Legal Proceedings

Manufactured Gas Plant Remediation

NJNG is responsible for the remedial cleanup of five MGP sites, dating back to gas operations in the late 1800s and early 1900s, which contain contaminated residues from former gas manufacturing operations. NJNG is currently involved in administrative proceedings with the NJDEP, and participating in various studies and investigations by outside consultants, to determine the nature and extent of any such contaminated residues and to develop appropriate programs of remedial action, where warranted, under Administrative Consent Orders or Memoranda of Agreement with the NJDEP.

NJNG recovers its remediation expenditures, including carrying costs, over rolling seven-year periods pursuant to a RAC approved by the BPU. NJNG recovered approximately $9.4 million annually through its SBC RAC. In July 2018, the BPU approved NJNG's annual SBC filing requesting a reduction in the RAC, which decreased the annual recovery to $7 million, effective September 1, 2018. On September 21, 2018, NJNG filed its annual SBC application requesting to recover remediation expenses incurred through June 30, 2018, which will result in an annual increase of $1.4 million, effective April 1, 2019. As of September 30, 2018, $33 million of previously incurred remediation costs, net of recoveries from customers and insurance proceeds, are included in regulatory assets on the Consolidated Balance Sheets.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

In the first quarter of fiscal 2018, the NJDEP contacted NJNG regarding its association with a parcel of land, located within NJNG's service territory, which may have been a MGP site for a period of time. NJNG is investigating to determine the nature and extent of its relationship to the parcel, its previous owners and the operations conducted on the site and has accrued for costs associated with the preliminary investigation of the existence of potential contaminants. NJNG will continue to gather information to determine whether a potential obligation exists to undertake remedial action, if any, and whether there are other potentially responsible parties.

NJNG periodically, and at least annually, performs an environmental review of MGP sites located in Atlantic Highlands, Berkeley, Long Branch, Manchester and Toms River, including a review of potential liability for investigation and remedial action. NJNG estimated at the time of the most recent review that total future expenditures to remediate and monitor the five MGP sites for which it is responsible, including potential liabilities for natural resource damages that might be brought by the NJDEP for alleged injury to groundwater or other natural resources concerning these sites, will range from approximately $117.7 million to $204.1 million. NJNG’s estimate of these liabilities is based upon known facts, existing technology and enacted laws and regulations in place when the review was completed. Where it is probable that costs will be incurred, and the information is sufficient to establish a range of possible liability, NJNG accrues the most likely amount in the range. If no point within the range is more likely than the other, it is NJNG’s policy to accrue the lower end of the range. Accordingly, as of September 30, 2018, NJNG recorded an MGP remediation liability and a corresponding regulatory asset of $130.8 million on the Consolidated Balance Sheets, based on the most likely amount. This was reduced from $149 million in fiscal 2017, due to the completion of remediation work at certain sites and a reduction to the remediation scope at another site. The actual costs to be incurred by NJNG are dependent upon several factors, including final determination of remedial action, changing technologies and governmental regulations, the ultimate ability of other responsible parties to pay and insurance recoveries, if any.

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, NJR establishes reserves for litigation for those matters that present loss contingencies as to which it is both probable that a loss will be incurred and the amount of such loss can be reasonably estimated. NJR also discloses contingent matters for which there is a reasonable possibility of a loss. Based upon currently available information, NJR believes that the results of litigation that is currently pending, taken together, will not have a materially adverse effect on the Company’s financial condition, results of operations or cash flows. The actual results of resolving the pending litigation matters may be substantially higher than the amounts reserved.

The foregoing statements about NJR’s litigation are based upon the Company’s judgments, assumptions and estimates and are necessarily subjective and uncertain. The Company has a number of threatened and pending litigation matters at various stages. Certain of the Company’s significant litigation is described below.

Stafford Township

In February 2015, a natural gas fire and explosion occurred in Stafford Township, New Jersey as a result of a natural gas leak emanating from an underground pipe. There were no fatalities, although several employees of NJNG were injured and several homes were damaged. NJNG notified its insurance carrier and believes that any costs associated with the incident, including attorneys’ fees, property damage and other losses, will be substantially covered by insurance. The Company believes the resolution of the remaining claims associated with the incident will not have a material effect on its financial condition, results of operations or cash flows. Subrogated property damage claims asserted against the Company and co-defendants and cross-claims have been amicably resolved in August 2018.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

14. REPORTING SEGMENT AND OTHER OPERATIONS DATA

The Company organizes its businesses based on a combination of factors, including its products and its regulatory environment. As a result, the Company manages its businesses through the following reporting segments and other operations: the Natural Gas Distribution segment consists of regulated energy and off-system, capacity and storage management operations; the Clean Energy Ventures segment consists of capital investments in clean energy projects; the Energy Services segment consists of unregulated wholesale and retail energy operations; the Midstream segment consists of the Company’s investments in natural gas transportation and storage facilities; the Home Services and Other operations consist of heating, cooling and water appliance sales, installations and services, other investments and general corporate activities.

Information related to the Company’s various reporting segments and other operations is detailed below:

(Thousands)
Fiscal Years Ended September 30,	2018			2017			2016
Operating revenues
Natural Gas Distribution
External customers	$	731,865		$	695,637		$	594,346
Clean Energy Ventures
External customers	71,375			64,394			53,540
Energy Services
External customers(1)	2,064,477			1,462,365			1,187,754
Intercompany	48,327			316			9,499
Subtotal	2,916,044			2,222,712			1,845,139
Home Services and Other
External customers	47,392			46,221			45,265
Intercompany	2,665			3,370			3,232
Eliminations	(50,992		)	(3,686		)	(12,731		)
Total	$	2,915,109		$	2,268,617		$	1,880,905
Depreciation and amortization
Natural Gas Distribution	$	53,208		$	49,347		$	47,828
Clean Energy Ventures	31,877			31,834			23,971
Energy Services (2)	76			63			88
Midstream	6			6			6
Subtotal	85,167			81,250			71,893
Home Services and Other	780			798			981
Eliminations	(246		)	(207		)	(126		)
Total	$	85,701		$	81,841		$	72,748
Interest income (3)
Natural Gas Distribution	$	614		$	555		$	115
Energy Services	240			6			98
Midstream	3,374			2,195			1,524
Subtotal	4,228			2,756			1,737
Home Services and Other	1,476			590			397
Eliminations	(5,090		)	(1,312		)	(2,006		)
Total	$	614		$	2,034		$	128

(1) Includes sales to Canada, which are immaterial.

(2) The amortization of acquired wholesale energy contracts is excluded above and is included in gas purchases - nonutility on the Unaudited Condensed Consolidated Statements of Operations.

(3) Included in other income, net on the Consolidated Statements of Operations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

(Thousands)
Fiscal Years Ended September 30,	2018			2017			2016
Interest expense, net of capitalized interest
Natural Gas Distribution	$	25,299		$	25,818		$	19,930
Clean Energy Ventures	18,320			16,263			10,304
Energy Services	3,945			2,747			1,095
Midstream	1,667			960			287
Subtotal	49,231			45,788			31,616
Home Services and Other	7			410			252
Eliminations	(2,952		)	(1,312		)	(824		)
Total	$	46,286		$	44,886		$	31,044
Income tax (benefit) provision
Natural Gas Distribution	$	(1,910	)	$	43,485		$	34,951
Clean Energy Ventures	(79,932		)	(31,161		)	(26,592		)
Energy Services	24,996			(4,015		)	7,030
Midstream	(8,548		)	5,820			6,130
Subtotal	(65,394		)	14,129			21,519
Home Services and Other	11,944			3,857			1,387
Eliminations	(335		)	357			624
Total	$	(53,785	)	$	18,343		$	23,530
Equity in earnings of affiliates
Midstream	$	16,165		$	17,797		$	13,936
Eliminations	(3,157		)	(3,984		)	(4,421		)
Total	$	13,008		$	13,813		$	9,515
Net financial earnings (loss)
Natural Gas Distribution	$	84,048		$	86,930		$	76,104
Clean Energy Ventures	75,849			24,873			28,393
Energy Services	60,378			18,554			21,934
Midstream	24,367			12,857			9,406
Subtotal	244,642			143,214			135,837
Home Services and Other	(3,829		)	6,811			2,882
Eliminations	(327		)	(633		)	(634		)
Total	$	240,486		$	149,392		$	138,085
Capital expenditures
Natural Gas Distribution	$	254,523		$	176,249		$	205,133
Clean Energy Ventures	123,421			149,400			149,063
Midstream	5,431			—			—
Subtotal	383,375			325,649			354,196
Home Services and Other	1,213			2,434			1,896
Total	$	384,588		$	328,083		$	356,092
Investments in equity investees
Midstream	16,151			27,070			11,176
Total	$	16,151		$	27,070		$	11,176

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

The Chief Executive Officer, who uses NFE as a measure of profit or loss in measuring the results of the Company’s reporting segments and operations, is the chief operating decision maker of the Company. A reconciliation of consolidated NFE to consolidated net income is as follows:

(Thousands)	2018			2017			2016
Consolidated net financial earnings	$	240,486		$	149,392		$	138,085
Less:
Unrealized loss (gain) on derivative instruments and related transactions	26,770			(11,241		)	46,883
Tax effect	(4,512		)	4,062			(17,018		)
Effects of economic hedging related to natural gas inventory	(22,570		)	38,470			(36,816		)
Tax effect	7,362			(13,964		)	13,364
Consolidated net income	$	233,436		$	132,065		$	131,672

The Company uses derivative instruments as economic hedges of purchases and sales of physical gas inventory. For GAAP purposes, these derivatives are recorded at fair value and related changes in fair value are included in reported earnings. Revenues and cost of gas related to physical gas flow are recognized when the gas is delivered to customers. Consequently, there is a mismatch in the timing of earnings recognition between the economic hedges and physical gas flows. Timing differences occur in two ways:

• Unrealized gains and losses on derivatives are recognized in reported earnings in periods prior to physical gas inventory flows; and

• Unrealized gains and losses of prior periods are reclassified as realized gains and losses when derivatives are settled in the same period as physical gas inventory movements occur.

NFE is a measure of the earnings based on eliminating these timing differences, to effectively match the earnings effects of the economic hedges with the physical sale of gas, SRECs and foreign currency contracts. Consequently, to reconcile between net income and NFE, current-period unrealized gains and losses on the derivatives are excluded from NFE as a reconciling item. Additionally, realized derivative gains and losses are also included in current-period net income. However, NFE includes only realized gains and losses related to natural gas sold out of inventory, effectively matching the full earnings effects of the derivatives with realized margins on physical gas flows. Included in the tax effects are current and deferred income tax expense corresponding with the non-GAAP measure. Also included in the tax effects during fiscal 2018, are the impacts of the Tax Act and resulting revaluation of the deferred income taxes that arose from derivative and hedging activity as measured under NFE. The revaluation caused the effective tax rate on reconciling items to differ from the statutory rate in effect for the year. The Company also calculates a quarterly tax adjustment based on an estimated annual effective tax rate for NFE purposes.

The Company’s assets for the various reporting segments and business operations are detailed below:

(Thousands)	2018			2017			2016
Assets at end of period:
Natural Gas Distribution	$	2,663,054		$	2,519,578		$	2,517,401
Clean Energy Ventures (1)	865,018			771,340			665,696
Energy Services	396,852			398,277			327,626
Midstream	242,069			232,806			186,259
Subtotal	4,166,993			3,922,001			3,696,982
Home Services and Other	114,732			114,801			109,487
Intercompany assets (2)	(138,061		)	(108,295		)	(87,899		)
Total	$	4,143,664		$	3,928,507		$	3,718,570

(1) Includes assets held for sale of $206.9 million for September 30, 2018.

(2) Consists of transactions between subsidiaries that are eliminated and reclassified in consolidation.

15. RELATED PARTY TRANSACTIONS

Effective April 1, 2010, NJNG entered into a 10-year agreement for 3 Bcf of firm storage capacity with Steckman Ridge. Under the terms of the agreement, NJNG incurs demand fees, at market rates, of approximately $9.3 million annually, a portion of which is eliminated in consolidation. These fees are recoverable through NJNG’s BGSS mechanism and are included in regulatory assets.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

Energy Services may periodically enter into storage or park and loan agreements with its affiliated FERC-jurisdictional natural gas storage facility, Steckman Ridge. As of September 30, 2018, Energy Services has entered into transactions with Steckman Ridge for varying terms, all of which expire by October 31, 2020.

Demand fees, net of eliminations, associated with Steckman Ridge during the fiscal years ended September 30, are as follows:

(Thousands)	2018		2017		2016
Natural Gas Distribution	$	5,730	$	5,590	$	5,562
Energy Services	2,775		2,750		2,789
Total	$	8,505	$	8,340	$	8,351

The following table summarizes demand fees payable to Steckman Ridge as of September 30:

(Thousands)	2018		2017
Natural Gas Distribution	$	775	$	775
Energy Services	375		377
Total	$	1,150	$	1,152

NJNG and Energy Services have entered into various asset management agreements, the effects of which are eliminated in consolidation. Under the terms of these agreements, NJNG releases certain transportation and storage contracts to Energy Services. NJNG retains the right to purchase market-priced gas or fixed-price storage gas from Energy Services. As of September 30, 2018, NJNG and Energy Services had four asset management agreements with expiration dates ranging from March 31, 2019 through October 31, 2021.

NJNG has entered into a 15-year transportation precedent agreement for committed capacity of 180,000 Dths per day with PennEast, to commence when in service.

16. ACQUISITION

On October 27, 2017, Adelphia, an indirect wholly owned subsidiary of NJR, entered into a Purchase and Sale Agreement with Talen pursuant to which Adelphia will acquire all of Talen’s membership interests in IEC for a base purchase price of $166 million. As additional consideration, Adelphia will pay Talen specified amounts of up to $23 million contingent upon the achievement of certain regulatory approvals and binding natural gas capacity commitments, which have not been received as of September 30, 2018. On November 7, 2017, the Company made an initial payment of $10 million towards the base purchase price, which is included in other noncurrent assets on the Consolidated Balance Sheets.

IEC owns an existing 84-mile pipeline in southeastern Pennsylvania. The transaction is expected to close following receipt of necessary permits and regulatory actions including those from the FERC and the Pennsylvania Public Utility Commission. Upon the closing, Adelphia will acquire IEC and, with it, IEC’s existing pipeline, related assets and rights of way. Adelphia has also agreed to provide firm natural gas transportation service for ten years following the closing to two power generators owned by affiliates of Talen that are currently served by IEC.

17. DISPOSITIONS

Energy Services

On February 28, 2018, NJR sold all of the issued and outstanding shares of capital stock of NJRRS, which was a component of the Energy Services segment. The Company received $9.5 million in cash and a natural gas swap contract with a fair value of $14.6 million, which was recorded in Derivatives, at fair value on the Consolidated Balance Sheets. The sale generated a pre-tax gain of $3.7 million, which was recognized as a reduction to O&M on the Consolidated Statements of Operations.

Clean Energy Ventures

On June 1, 2018, Clean Energy Ventures completed the sale of its membership interest in its 9.7 MW wind farm in Two Dot, Montana to NorthWestern Energy for a total purchase price of $18.5 million. The transaction generated a pre-tax gain of approximately $951,000, which is recognized as a reduction to O&M on the Consolidated Statements of Operations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)                                                            

18. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of financial data for each quarter of fiscal 2018 and 2017 follows. Due to the seasonal nature of the Company’s businesses, quarterly amounts vary significantly during the fiscal year. In the opinion of management, the information furnished reflects all adjustments necessary for a fair presentation of the results of the interim periods.

	First		Second		Third			Fourth
(Thousands, except per share data)	Quarter		Quarter		Quarter			Quarter
2018
Operating revenues	$	705,305	$	1,019,043	$	543,435		$	647,326
Operating income (loss)	$	75,245	$	177,792	$	(37,666	)	$	(19,295	)
Net income (loss)	$	123,699	$	140,266	$	(14,274	)	$	(16,255	)
Earnings (loss) per share (1)
Basic	$1.42		$1.60		$(0.16)			$(0.18)
Diluted	$1.42		$1.59		$(0.16)			$(0.18)
2017
Operating revenues	$	541,028	$	733,546	$	457,523		$	536,520
Operating income (loss)	$	41,475	$	139,653	$	17,967		$	(32,051	)
Net income (loss)	$	34,929	$	114,702	$	18,957		$	(36,523	)
Earnings (loss) per share (1)
Basic	$0.41		$1.33		$0.22			$(0.42)
Diluted	$0.40		$1.32		$0.22			$(0.42)

(1) The sum of quarterly amounts may not equal the annual amounts due to rounding.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL

DISCLOSURE                                                                                                                                                                                   

None

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, the Company’s principal executive officer and principal financial officer concluded that, as of end of the period covered by this report, the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control over Financial Reporting

The report of management required under this Item 9A is contained in Item 8 of this Form 10-K under the caption Management’s Report on Internal Control over Financial Reporting.

Attestation Report of Registered Public Accounting Firm

The attestation report required under this Item 9A is contained in Item 8 of this 10-K under the caption Report of Independent Registered Public Accounting Firm.

Changes in Internal Control over Financial Reporting

There has been no change in internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended September 30, 2018, that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None

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ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE                                         

Information required by this item, including information concerning the Board of Directors of the Company, the members of the Company’s Audit Committee, the Company’s Audit Committee Financial Expert, compliance with Section 16(a) of the Exchange Act and shareowner proposals, is incorporated by reference to the Company’s Proxy Statement for the 2019 Annual Meeting of Shareowners, which will be filed with the SEC pursuant to Regulation 14A within 120 days after September 30, 2018. The information regarding executive officers is included in this report as Item 4A under the caption Executive Officers of the Company and incorporated herein by reference.

The Board of Directors has adopted the Code of Conduct, a code for all directors, officers and employees, as required by the New York Stock Exchange rules, and governing the chief executive officer and senior financial officers, in compliance with Sarbanes-Oxley and SEC regulations. Copies of the Code of Conduct are available free of charge on the Company’s website at http://investor.njresources.com under the caption Corporate Governance. A printed copy of the Code of Conduct is available free of charge to any shareowner who requests it by contacting the Corporate Secretary at 1415 Wyckoff Road, Wall, New Jersey 07719. The Company will disclose any amendments to, or waivers from, a provision of the Code of Conduct that applies to the principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions that relate to any element of the Code of Conduct as defined in Item 406 of Regulation S-K by posting such information on the Company’s website.

ITEM 11. EXECUTIVE COMPENSATION                                                                                                                               

Information required by this Item is incorporated by reference from the Registrant’s Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND

RELATED STOCKHOLDER MATTERS                                                                                                                                    

Information required by this Item is incorporated by reference from the Registrant’s Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE      

Information required by this Item is incorporated by reference from the Registrant’s Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES                                                                                             

Information required by this Item is incorporated by reference from the Registrant’s Proxy Statement.

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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES                                                                                  

(a) 1. Financial Statements.
All Financial Statements of the Registrant are filed as part of this report and included in Item 8 of Part II of this Form 10-K.
(a) 2. Financial Statement Schedules-See Index to Financial Statement Schedulesin Item 8.
(a) 3. Exhibits-See Exhibit Index on page	132.

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INDEX TO FINANCIAL STATEMENT SCHEDULES

	Page
Schedule II - Valuation and qualifying accounts and reserves for each of the three years in the period ended September 30, 2018	131

Schedules other than those listed above are omitted because they are either not required or are not applicable, or the required information is shown in the financial statements or notes thereto.

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SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED SEPTEMBER 30, 2018, 2017 and 2016

(Thousands)			ADDITIONS
CLASSIFICATION	BEGINNING BALANCE		CHARGED TO EXPENSE	OTHER (1)		ENDING BALANCE
2018
Allowance for doubtful accounts	$	5,181	2,579	(2,056	)	$	5,704
2017
Allowance for doubtful accounts	$	4,865	2,023	(1,707	)	$	5,181
2016
Allowance for doubtful accounts	$	5,189	1,616	(1,940	)	$	4,865

(1) Uncollectible accounts written off, less recoveries and adjustments.

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EXHIBIT INDEX

Exhibit Number	Exhibit Description
2.1*	Purchase and Sale Agreement, dated as of October 27, 2017, by and between Talen Generation, LLC, and Adelphia Gateway, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, as filed on November 2, 2017)
3.1	Restated Certificate of Incorporation of New Jersey Resources Corporation, as amended through March 3, 2015 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, as filed on January 23, 2014, and Exhibit 3.1 to the Current Report on Form 8-K, as filed on March 3, 2015)
3.2	Bylaws of New Jersey Resources Corporation, as amended through July 10, 2018 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, as filed on July 16, 2018)
4.1	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Annual Report on Form 10-K for the year ended September 30, 2013, as filed on November 25, 2013)
4.2	Amended and Restated Indenture of Mortgage, Deed of Trust and Security Agreement, dated as of September 1, 2014, between NJNG and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K, as filed on September 30, 2014)
4.2(a)	36th Supplemental Indenture dated as of September 1, 2014, between NJNG and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K, as filed on September 30, 2014)
4.2(b)	Second Supplemental Indenture dated as of June 1, 2016, between New Jersey Natural Gas Company and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K as filed on June 22, 2016)
4.3	$250,000,000 Credit Agreement dated as of May 15, 2014, by and among New Jersey Natural Gas Company, the Lenders party thereto, PNC Bank, National Association, as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, U.S. Bank National Association, TD Bank, N.A., and Santander Bank, N.A., as Documentation Agents, and PNC Capital Markets LLC and Wells Fargo Securities, LLC, as Joint Lead Arrangers (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, as filed on August 4, 2014)
4.4	$425,000,000 Amended and Restated Credit Agreement dated as of September 28, 2015, by and among the Company, the guarantors thereto, the lenders party thereto, PNC Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, Bank of America, N.A., TD Bank, N.A. and U.S. Bank National Association, as Documentation Agents, and PNC Capital Markets LLC, J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as Joint Lead Arrangers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K as filed on October 2, 2015)
4.5	$75,000,000 Shelf Note Purchase Agreement, dated as of June 30, 2011, between New Jersey Resources Corporation and Prudential Investment Management, Inc. (“Prudential Facility”) (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K as filed on July 6, 2011)
4.5(a)	First Amendment to the Prudential Facility, dated as of July 25, 2014, between the Company and Prudential Investment Management, Inc. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K as filed on November 12, 2014)
4.5(b)	Second Amendment to the Prudential Facility, dated as of September 28, 2015, between the Company and Prudential Investment Management, Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K as filed on October 2, 2015)
4.6	$50,000,000 Note Purchase Agreement, dated as of September 24, 2007, by and among the Company, New York Life Insurance Company and New York Life Insurance and Annuity Company (incorporated by reference to Exhibit 4.8 to the Annual Report on Form 10-K as filed on December 10, 2007)
4.6(a)	First Amendment to Note Purchase Agreement, dated as of September 28, 2015, by and among the Company, New York Life Insurance Company and New York Life Insurance and Annuity Company (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K, as filed on October 2, 2015)
4.7	$125,000,000 Note Purchase Agreement, dated as of February 7, 2014, by and among New Jersey Natural Gas Company and the Purchasers party thereto (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q, as filed on May 7, 2014)

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Exhibit Number	Exhibit Description
4.8	Loan Agreement between New Jersey Economic Development Authority and New Jersey Natural Gas Company, dated as of August 1, 2011 (incorporated by reference to Exhibit 4.10 to the Annual Report on Form 10-K for the year ended September 30, 2011, as filed on November 23, 2011)
4.9	Continuing Covenant Agreement between NJNG and Wells Fargo Municipal Strategies, LLC, dated September 24, 2014 (incorporated by reference to Exhibit 99.4 to the Current Report on Form 8-K, as filed on September 30, 2014)
4.10	$50,000,000 Note Purchase Agreement, dated as of February 8, 2013, by and among New Jersey Natural Gas Company and the Purchasers party thereto (incorporated by reference to Exhibit 4.12 to the Quarterly Report on Form 10-Q, as filed on May 3, 2013)
4.11	$150,000,000 Note Purchase Agreement, dated as of February 12, 2015, by and among New Jersey Natural Gas Company and the Purchasers party thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, as filed on February 17, 2015)
4.12	Note Purchase Agreement, dated as of March 22, 2016, among New Jersey Resources Corporation and each of the Purchasers listed in Schedule A thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, as filed on March 25, 2016)
4.13	$125,000,000 Note Purchase Agreement, dated as of June 21, 2016, by and among New Jersey Natural Gas Company and the Purchasers party thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, as filed on June 22, 2016)
4.15	$125,000,000 Note Purchase Agreement, dated as of May 11, 2018, by and among New Jersey Natural Gas Company and the Purchasers party thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, as filed on May 11, 2018)
4.16	Third Supplemental Indenture, dated as of May 1, 2018, by and between New Jersey Natural Gas Company and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, as filed on May 11, 2018)
4.17	$100,000,000 Note Purchase Agreement, dated as of June 8, 2018, by and among New Jersey Resources Corporation and the Purchasers party thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, as filed on June 8, 2018)
10.1*	Amended and Restated Supplemental Executive Retirement Plan Agreement between the Company and Laurence M. Downes dated November 28, 2008 (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q, as filed on February 6, 2009)
10.2(a)*	Schedule of Supplemental Executive Retirement Plan Agreements for named executive officers (incorporated by reference to Exhibit 10.2(a) to the Annual Report on Form 10-K for the year ended September 30, 2010, as filed on November 24, 2010)
10.2(b)*	Form of Amendment to Supplemental Executive Retirement Plan Agreement between the Company and Named Executive Officer (for future use) (incorporated by reference to Exhibit 10.4(b) to the Quarterly Report on Form 10-Q, as filed on February 6, 2009)
10.3	Service Agreement for Rate Schedule SS-1 by and between NJNG and Texas Eastern Transmission Company, dated as of June 21, 1995 (incorporated by reference to Exhibit 10-5B to the Annual Report on Form 10-K for the year ended September 30, 1996, as filed on December 30, 1996)
10.4	Amended and Restated Lease Agreement between NJNG, as Lessee, and State Street Bank and Trust Company of Connecticut, National Association, as Lessor, for NJNG’s Headquarters Building dated December 21, 1995 (incorporated by reference to Exhibit 10-7 to the Annual Report on Form 10-K for the year ended September 30, 1996, as filed on December 30, 1996)
10.5*	Summary of Company’s Non-Employee Director Compensation (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K as filed on November 19, 2018)
10.6*	The Company’s 2007 Stock Award and Incentive Plan (as amended and restated January 1, 2009) (incorporated by reference to Exhibit 10.17 to the Quarterly Report on Form 10-Q, as filed on February 6, 2009)

Page 133

New Jersey Resources Corporation

Part IV

Exhibit Number	Exhibit Description
10.7*	2007 Stock Award and Incentive Plan Form of Performance Share Units Agreement (TSR) (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q, as filed on February 8, 2017)
10.8*	New Jersey Resources Corporation 2017 Stock Award and Incentive Plan Performance Share Units Agreement - Total Shareholder Return (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q, as filed on February 8, 2018)
10.9*	2007 Stock Award and Incentive Plan Form of Performance Share Units Agreement (NFE) (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q, as filed on February 8, 2017)
10.10*	New Jersey Resources Corporation 2017 Stock Award and Incentive Plan Performance Share Units Agreement - NFE (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q, as filed on February 8, 2018)
10.11*	2007 Stock Award and Incentive Plan Form of Performance-Based Restricted Stock Units Agreement (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q, as filed on February 8, 2017)
10.12*	New Jersey Resources Corporation 2017 Stock Award and Incentive Plan Performance Based Restricted Stock Units Agreement (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q, as filed on February 8, 2018)
10.13*	Form of Amendment of Deferred Stock Retention Award Agreement (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q, as filed on August 3, 2016)
10.14*	2007 Stock Award and Incentive Plan Form of Deferred Stock Retention Award Agreement (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q, as filed on February 8, 2017)
10.15*	New Jersey Resources Corporation Deferred Stock Retention Award Agreement (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q, as filed on February 8, 2018)
10.16*	2007 Stock Award and Incentive Plan Form of Restricted Stock Units Agreement (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q, as filed on February 8, 2017)
10.17*	New Jersey Resources Corporation 2017 Stock Award and Incentive Plan Restricted Stock Units Agreement (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q, as filed on February 8, 2018)
10.18*	The Company’s 2017 Stock Award and Incentive Plan (incorporated by reference to Appendix A to the Proxy Statement for the 2017 Annual Meeting as filed on December 15, 2016)
10.19*	New Jersey Resources Corporation Savings Equalization Plan (as amended and restated as of January 1, 2017) (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K as filed on November 21, 2017)
10.20*	New Jersey Resources Corporation Pension Equalization Plan (incorporated by reference to Exhibit 10.28 to the Quarterly Report on Form 10-Q, as filed on February 6, 2009)
10.21*	New Jersey Resources Corporation Directors’ Deferred Compensation Plan (incorporated by reference to Exhibit 10.25 to the Quarterly Report on Form 10-Q, as filed on February 6, 2009)
10.22*	New Jersey Resources Corporation Officers’ Deferred Compensation Plan (incorporated by reference to Exhibit 10.26 to the Quarterly Report on Form 10-Q, as filed on February 6, 2009)
10.23*	Form of Amended and Restated Employment Continuation Agreement between the Company and NJR Energy Services Company named executive officer (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, as filed on December 16, 2015)
10.24*	Form of Amended and Restated Employment Continuation Agreement between the Company and named executive officer (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, as filed on December 16, 2015)
10.24(a)*+	Schedule of Employee Continuation Agreements
10.25	Limited Liability Company Agreement of Steckman Ridge GP, LLC, dated as of March 2, 2007 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q, as filed on May 3, 2007)

Page 134

New Jersey Resources Corporation

Part IV

Exhibit Number	Exhibit Description
10.26	Limited Partnership Agreement of Steckman Ridge, LP dated as of March 2, 2007 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q, as filed on May 3, 2007)
10.27	First Amendment to Amended and Restated Credit Agreement, dated as of June 25, 2018, by and among New Jersey Resources Corporation and the Guarantors party thereto, the Lenders party thereto and PNC Bank, National Association, in its capacity as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, as filed on June 26, 2018)
10.28	First Amendment to Amended and Restated Credit Agreement, dated as of July 17, 2018, by and among New Jersey Resources Corporation and the guarantors party thereto, the lenders party thereto and U.S. Bank National Association, in its capacity as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, as filed on July 19, 2018)
21.1+	Subsidiaries of the Registrant
23.1+	Consent of Independent Registered Public Accounting Firm
31.1+	Certification of the Chief Executive Officer pursuant to section 302 of the Sarbanes-Oxley Act
31.2+	Certification of the Chief Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act
32.1+ †	Certification of the Chief Executive Officer pursuant to section 906 of the Sarbanes-Oxley Act
32.2+ †	Certification of the Chief Financial Officer pursuant to section 906 of the Sarbanes-Oxley Act
99.1	Form of Letter to Shareowners Regarding Transfer Agent Change August 17, 2018 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K, as filed on August 17, 2018)
101+	Interactive Data File {Annual Report on Form 10-K, for the fiscal year ended September 30, 2018, furnished in XBRL (eXtensible Business Reporting Language)}

________________________________

+ Filed herewith.

* Denotes compensatory plans or arrangements or management contracts.

† This certificate accompanies this report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by NJR for purposes of Section 18 or any other provision of the Securities Exchange Act of 1934, as amended.

Page 135

New Jersey Resources Corporation

Part IV

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		NEW JERSEY RESOURCES CORPORATION
		(Registrant)
Date:	November 20, 2018	By:/s/ Patrick Migliaccio
		Patrick Migliaccio
		Senior Vice President and
		Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated:

November 20, 2018	/s/ Laurence M. Downes	November 20, 2018	/s/ Patrick J. Migliaccio
	Laurence M. Downes Chairman and Chief Executive Officer Director (Principal Executive Officer)		Patrick J. Migliaccio Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
November 20, 2018	/s/ Maureen A. Borkowski	November 20, 2018	/s/ J. Terry Strange
	Maureen A. Borkowski Director		J. Terry Strange Director
November 20, 2018	/s/ Donald L. Correll	November 20, 2018	/s/ Sharon C. Taylor
	Donald L. Correll Director		Sharon C. Taylor Director
November 20, 2018	/s/ Robert B. Evans	November 20, 2018	/s/ David A. Trice
	Robert B. Evans Director		David A. Trice Director
November 20, 2018	/s/ M. William Howard, Jr.	November 20, 2018	/s/ Stephen D. Westhoven
	M. William Howard, Jr. Director		Stephen D. Westhoven President and Chief Operating Officer Director
November 20, 2018	/s/ Jane M. Kenny	November 20, 2018	/s/ George R. Zoffinger
	Jane M. Kenny Director		George R. Zoffinger Director
November 20, 2018	/s/ Thomas C. O’Connor
	Thomas C. O’Connor Director

Page 136

EX-10.24(A)

Exhibit 10.24(a)

Schedule of Employment Continuation Agreements of Named Executive Officers dated September 30, 2018.

Name	Termination Benefit
Laurence M. Downes, President and Chief Executive Officer	Three times the sum, of (x) his then annual base salary and (y) the average of his annual bonuses paid or payable with respect to the last three calendar years ended prior to the Change of Control.
Stephen D. Westhoven, President and Chief Operating Officer	Two times the sum, of (x) his then annual base salary and (y) the average of his annual bonuses paid or payable with respect to the last three calendar years ended prior to the Change of Control (“2x”).
Patrick J. Migliaccio, Senior Vice President and Chief Financial Officer	2x
Amanda Mullan, Senior Vice President and Chief Human Resources Officer	2x
Nancy A. Washington, Senior Vice President and General Counsel	2x

EX-21.1

NEW JERSEY RESOURCES CORPORATION

EXHIBIT 21.1

SUBSIDIARIES OF THE REGISTRANT

SUBSIDIARY				STATE OF INCORPORATION
New Jersey Natural Gas Company					New Jersey
NJR Service Corporation					New Jersey
NJR Energy Services Company					New Jersey
NJR Clean Energy Ventures Corporation					New Jersey
	Subsidiary:
	NJR Clean Energy Ventures II Corporation				New Jersey
		Subsidiaries:
		Carroll Area Wind Farm, LLC (Limited Liability Company)			Iowa
		Alexander Wind Farm, LLC (Limited Liability Company)			Delaware
		Ringer Hill Wind, LLC (Limited Liability Company)			Delaware
		Bernards Solar, LLC (Limited Liability Company)			New Jersey
		Medicine Bow Wind, LLC (Limited Liability Company)			Delaware
		NJR Clean Energy Ventures III Corporation			New Jersey
NJR Energy Investments Corporation					New Jersey
	Subsidiaries:
	NJR Midstream Holdings Corporation				New Jersey
		Subsidiaries:
		NJNR Pipeline Company			New Jersey
		NJR Pipeline Company			New Jersey
			Subsidiary:
			Adelphia Gateway, LLC (Limited Liability Company)		Delaware
		NJR Storage Holdings Company			Delaware
			Subsidiary:
			NJR Steckman Ridge Storage Company		Delaware
NJR Retail Holdings Corporation					New Jersey
	Subsidiaries:
	Commercial Realty and Resources Corporation				New Jersey
	Phoenix Fuel Management Company				New Jersey
	NJR Home Services Company				New Jersey
		Subsidiary:
		NJR Plumbing Services, Inc			New Jersey

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements No. 333-164572 and No. 333-215728 on Form S-8 and Registration Statement No. 333-227603 on Form S-3 of our reports dated November 20, 2018, relating to the consolidated financial statements and financial statement schedule of New Jersey Resources Corporation and subsidiaries (the “Company”), and the effectiveness of the Company's internal control over financial reporting, appearing in this Annual Report on Form 10-K of New Jersey Resources Corporation for the year ended September 30, 2018.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

November 20, 2018

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

 I, Laurence M. Downes, certify that:

1) I have reviewed this report on Form 10-K of New Jersey Resources Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5) The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 20, 2018	By:	/s/ Laurence M. Downes
			Laurence M. Downes
			Chairman & Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF THE PRINCIPAL FINANCIAL OFFICER

PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

 I, Patrick Migliaccio, certify that:

1) I have reviewed this report on Form 10-K of New Jersey Resources Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5) The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 20, 2018	By:	/s/ Patrick Migliaccio
			Patrick Migliaccio
			Senior Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned, Laurence M. Downes hereby certifies as follows:

(a) I am the Chief Executive Officer of New Jersey Resources Corporation (the "Company");

(b) To the best of my knowledge, this annual report on Form 10-K for the fiscal year ended September 30, 2018, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(c) To the best of my knowledge, based upon a review of this report, the information contained in this periodic report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 20, 2018	By:	/s/ Laurence M. Downes
			Laurence M. Downes
			Chairman and Chief Executive Officer

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned, Patrick Migliaccio hereby certifies as follows:

(a) I am the Chief Financial Officer of New Jersey Resources Corporation (the "Company");

(b) To the best of my knowledge, this annual report on Form 10-K for the fiscal year ended September 30, 2018, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(c) To the best of my knowledge, based upon a review of this report, the information contained in this periodic report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 20, 2018	By:	/s/ Patrick Migliaccio
			Patrick Migliaccio
			Senior Vice President and Chief Financial Officer

XML

Document and Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2018	Nov. 16, 2018	Mar. 31, 2018
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Entity Registrant Name	NEW JERSEY RESOURCES CORP
Entity Central Index Key	0000356309
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	Yes
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 3,451,945,383
Entity Common Stock, Shares Outstanding		88,505,199

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
OPERATING REVENUES
Utility		$ 731,865	$ 695,637	$ 594,346
Nonutility		2,183,244	1,572,980	1,286,559
Total operating revenues		2,915,109	2,268,617	1,880,905
Gas purchases:
Utility		276,005	258,687	205,034
Nonutility		1,990,832	1,436,740	1,139,301
Related parties		8,505	8,340	8,351
Operation and maintenance		266,919	226,356	208,421
Regulatory rider expenses		38,969	40,243	39,300
Depreciation and amortization		85,701	81,841	72,748
Energy and other taxes		52,102	49,366	40,215
Total operating expenses		2,719,033	2,101,573	1,713,370
OPERATING INCOME		196,076	167,044	167,535
Other income, net		16,853	14,437	9,196
Interest expense, net of capitalized interest		46,286	44,886	31,044
INCOME BEFORE INCOME TAXES AND EQUITY IN EARNINGS OF AFFILIATES		166,643	136,595	145,687
Income tax (benefit) provision		(53,785)	18,343	23,530
Equity in earnings of affiliates		13,008	13,813	9,515
NET INCOME		$ 233,436	$ 132,065	$ 131,672
EARNINGS PER COMMON SHARE
Basic (in dollars per share)		$ 2.66	$ 1.53	$ 1.53
Diluted (in dollars per share)	[1]	$ 2.64	$ 1.52	$ 1.52
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic (in shares)		87,689	86,321	85,884
Diluted (in shares)		88,315	87,144	86,731

[1] There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2018, 2017 and 2016.

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 233,436	$ 132,065	$ 131,672
Other comprehensive income, net of tax:
Unrealized (loss) gain on available for sale securities, net of tax of 6,973, $(4,401) and $1,499, respectively	(19,245)	6,846	(2,187)
Reclassifications of losses to net income on available for sale securities, net of tax of $(858), $0 and $0, respectively	11,647	0	0
Adjustment to postemployment benefit obligation, net of tax of $(573), $(3,487) and $2,466, respectively	1,520	5,053	(3,574)
Other comprehensive (loss) income	(6,078)	11,899	(5,761)
Comprehensive income	$ 227,358	$ 143,964	$ 125,911

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Tax on unrealized gain (loss) on available for sale securities	$ 6,973	$ (4,401)	$ 1,499
Tax on reclassifications of available for sale securities	(858)	0	0
Tax on adjustment to postemployment benefit obligation	$ (573)	$ (3,487)	$ 2,466

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 233,436	$ 132,065	$ 131,672
Adjustments to reconcile net income to cash flows from operating activities
Unrealized loss (gain) on derivative instruments	26,770	(11,241)	46,883
Gain on sale of available for sale securities	(5,332)	(7,287)	0
Gain on sale of businesses	(4,663)	0	0
Depreciation and amortization	85,701	81,841	72,748
Amortization of acquired wholesale energy contracts	18,222	762	0
Allowance for equity used during construction	(5,531)	(3,867)	(4,375)
Allowance for doubtful accounts	2,579	2,023	1,616
Deferred income taxes	15,590	41,442	27,721
Deferred income tax benefit due to tax legislation	(75,736)	0	0
Manufactured gas plant remediation costs	(16,171)	(10,934)	(8,106)
Equity in earnings, net of distributions received from equity investees	(1,725)	(462)	4,534
Cost of removal - asset retirement obligations	(298)	(484)	(403)
Contributions to postemployment benefit plans	(6,359)	(6,077)	(33,359)
Tax benefit of delivered shares from stock based compensation	2,950	1,285	1,755
Changes in:
Components of working capital	97,004	17,081	(123,325)
Other noncurrent assets	17,860	13,978	3,933
Other noncurrent liabilities	13,989	(2,079)	21,336
Cash flows from operating activities	398,286	248,046	142,630
Expenditures for:
Utility plant	(206,880)	(144,106)	(176,067)
Solar and wind equipment	(123,421)	(149,400)	(149,063)
Midstream and other	(6,644)	(2,434)	(1,896)
Cost of removal	(47,643)	(32,143)	(29,066)
Acquisition of retail and wholesale energy contracts	0	(55,661)	0
Investments in equity investees	(16,151)	(27,070)	(11,176)
Distributions from equity investees in excess of equity in earnings	3,117	2,749	2,351
Acquisition of retail and wholesale energy contracts	(10,000)	0	0
(Deposits to) withdrawal from restricted cash construction fund	(9)	1,322	979
Proceeds from sale of property, net of closing costs	0	9,443	748
Proceeds from sale of businesses, net of closing costs	27,916	0	0
Proceeds from sale of available for sale securities, net	6,616	6,639	0
Cash flows used in investing activities	(373,099)	(390,661)	(363,190)
CASH FLOWS (USED IN) FROM FINANCING ACTIVITIES
Proceeds from long-term debt	225,000	100,000	275,000
Payments of long-term debt	(165,486)	(97,854)	(13,289)
(Payments of) proceeds from short-term debt, net	(114,050)	144,300	55,350
Proceeds from sale-leaseback transaction - solar	71,538	32,901	0
Proceeds from sale-leaseback transaction - gas meters	7,820	9,587	7,107
Payments of common stock dividends	(95,835)	(87,988)	(82,445)
Proceeds from waiver discount issuance of common stock	41,677	0	0
Proceeds from issuance of common stock	17,136	17,492	16,010
Purchases of treasury stock	0	(6,355)	(1,008)
Tax withholding payments related to net settled stock compensation	(13,755)	(4,788)	(3,547)
Cash flows (used in) from financing activities	(25,955)	107,295	253,178
Change in cash and cash equivalents	(768)	(35,320)	32,618
Cash and cash equivalents at beginning of period	2,226	37,546	4,928
Cash and cash equivalents at end of period	1,458	2,226	37,546
CHANGES IN COMPONENTS OF WORKING CAPITAL
Receivables	(7,524)	(56,974)	11,303
Inventories	15,464	3,022	(45,986)
Recovery of gas costs	30,439	(90)	(39,642)
Gas purchases payable	51,187	20,663	(11,963)
Gas purchases payable - related parties	(1)	2	(411)
Prepaid and accrued taxes	1,254	10,366	2,385
Accounts payable and other	40,422	13,086	(15,656)
Restricted broker margin accounts	(30,974)	22,570	(38,752)
Customers’ credit balances and deposits	368	(5,877)	12,044
Other current assets	(3,631)	10,313	3,353
Components of working capital	97,004	17,081	(123,325)
Cash paid (received) for:
Interest (net of amounts capitalized)	44,821	44,362	31,996
Income taxes	5,577	(6,877)	(3,516)
Accrued capital expenditures	30,559	21,769	48,881
Inception gain on natural gas swap contract recognized as non-cash proceeds from sale of business	$ 14,579	$ 0	$ 0

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017
PROPERTY, PLANT AND EQUIPMENT
Utility plant, at cost	$ 2,368,914	$ 2,241,324
Construction work in progress	192,481	119,318
Nonutility plant and equipment, at cost	697,406	843,142
Construction work in progress	45,690	7,286
Total property, plant and equipment	3,304,491	3,211,070
Accumulated depreciation and amortization, utility plant	(530,753)	(489,122)
Accumulated depreciation and amortization, nonutility plant and equipment	(122,689)	(112,207)
Property, plant and equipment, net	2,651,049	2,609,741
CURRENT ASSETS
Cash and cash equivalents	1,458	2,226
Customer accounts receivable:
Billed	205,490	196,467
Unbilled revenues	7,199	7,202
Allowance for doubtful accounts	(5,704)	(5,181)
Regulatory assets	18,297	50,791
Gas in storage, at average cost	184,633	202,063
Materials and supplies, at average cost	13,910	11,944
Prepaid and accrued taxes	23,047	24,764
Derivatives, at fair value	27,396	30,081
Restricted broker margin accounts	53,719	25,827
Asset held for sale	206,905	0
Other current assets	33,730	33,260
Total current assets	770,080	579,444
NONCURRENT ASSETS
Investments in equity investees	190,866	172,585
Regulatory assets	368,592	375,919
Derivatives, at fair value	10,560	9,164
Available for sale securities	32,917	65,752
Intangible assets	23,375	41,084
Other noncurrent assets	96,225	74,818
Total noncurrent assets	722,535	739,322
Total assets	4,143,664	3,928,507
CAPITALIZATION
Common stock, $2.50 par value; authorized 150,000,000 shares; Outstanding September 30, 2018 — 88,292,956; September 30, 2017 — 86,555,507	226,196	222,258
Premium on common stock	274,748	219,696
Accumulated other comprehensive loss, net of tax	(12,610)	(3,256)
Treasury stock, at cost and other; Shares September 30, 2018 — 2,185,013; September 30, 2017 — 2,347,380	(76,473)	(70,039)
Retained earnings	1,007,117	867,984
Common stock equity	1,418,978	1,236,643
Long-term debt	1,180,619	997,080
Total capitalization	2,599,597	2,233,723
CURRENT LIABILITIES
Current maturities of long-term debt	123,545	165,375
Short-term debt	151,950	266,000
Gas purchases payable	211,303	160,115
Gas purchases payable to related parties	1,150	1,152
Accounts payable and other	135,240	96,878
Dividends payable	25,824	23,586
Accrued taxes	1,568	2,031
Regulatory liabilities	8,185	78
New Jersey Clean Energy Program	14,052	14,202
Derivatives, at fair value	46,652	46,544
Liabilities held for sale	4,182	0
Customers’ credit balances and deposits	27,325	26,957
Total current liabilities	750,976	802,918
NONCURRENT LIABILITIES
Deferred income taxes	242,436	514,708
Deferred investment tax credits	3,976	4,297
Deferred gain	9,104	27,728
Derivatives, at fair value	22,982	11,330
Manufactured gas plant remediation	130,800	149,000
Postemployment employee benefit liability	137,007	128,888
Regulatory liabilities	209,139	14,507
Asset retirement obligation	28,688	31,420
Other noncurrent liabilities	8,959	9,988
Total noncurrent liabilities	793,091	891,866
Commitments and contingent liabilities
Total capitalization and liabilities	$ 4,143,664	$ 3,928,507

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2018	Sep. 30, 2017
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 2.5	$ 2.5
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	88,292,956	86,555,507
Treasury stock at cost and other (in shares)	2,185,013	2,347,380

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CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY - USD ($) $ in Thousands		Total	Common Stock	Premium on Common Stock	Accumulated Other Comprehensive (Loss) Income	Treasury Stock And Other	Retained Earnings
Beginning Balance (in shares) at Sep. 30, 2015			85,531,000
Beginning Balance at Sep. 30, 2015		$ 1,106,956	$ 220,838	$ 209,931	$ (9,394)	$ (92,164)	$ 777,745
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		131,672					131,672
Other comprehensive loss		(5,761)			(5,761)
Common stock issued:
Incentive compensation plan (in shares)			325,000
Incentive compensation plan		9,399	$ 816	8,583
Divident reinvestment plan (in shares)	[1]		471,000
Dividend reinvestment plan	[1]	16,063		(2,879)		18,942
Cash dividend declared ($1.11 per share in 2018, $1.0375 per share in 2017, and $.975 per share in 2016)		(83,861)					(83,861)
Treasury stock and other (in shares)			(241,000)
Treasury stock and other		(7,877)		(55)		(7,822)
Ending Balance (in shares) at Sep. 30, 2016			86,086,000
Ending Balance at Sep. 30, 2016		1,166,591	$ 221,654	215,580	(15,155)	(81,044)	825,556
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		132,065					132,065
Other comprehensive loss		11,899			11,899
Common stock issued:
Incentive compensation plan (in shares)			241,000
Incentive compensation plan		5,694	$ 604	5,090
Divident reinvestment plan (in shares)	[1]		472,000
Dividend reinvestment plan	[1]	17,622		(946)		18,568
Cash dividend declared ($1.11 per share in 2018, $1.0375 per share in 2017, and $.975 per share in 2016)		(89,637)					(89,637)
Treasury stock and other (in shares)			(243,000)
Treasury stock and other		$ (7,591)		(28)		(7,563)
Ending Balance (in shares) at Sep. 30, 2017		86,555,507	86,556,000
Ending Balance at Sep. 30, 2017		$ 1,236,643	$ 222,258	219,696	(3,256)	(70,039)	867,984
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		233,436					233,436
Other comprehensive loss		(6,078)			(6,078)
Common stock issued:
Incentive compensation plan (in shares)			561,000
Incentive compensation plan		16,572	$ 1,403	15,169
Divident reinvestment plan (in shares)	[1]		413,000
Dividend reinvestment plan	[1]	17,094		755		16,339
Waiver discount (in shares)			1,014,000
Waiver discount		41,677	$ 2,535	39,142
Cash dividend declared ($1.11 per share in 2018, $1.0375 per share in 2017, and $.975 per share in 2016)		(97,579)					(97,579)
Treasury stock and other (in shares)			(251,000)
Treasury stock and other		$ (22,787)		(14)		(22,773)
Ending Balance (in shares) at Sep. 30, 2018		88,292,956	88,293,000
Ending Balance at Sep. 30, 2018		$ 1,418,978	$ 226,196	$ 274,748	(12,610)	$ (76,473)	1,007,117
Common stock issued:
Reclassifications of certain income tax effects to retained earnings (2)	[2]				$ (3,276)		$ 3,276

[1] Shares sold through the DRP are issued from treasury stock at average cost, which may differ from the actual market price paid.

[2] Due to the adoption of ASU No. 2018-02, an amendment to ASC 740, Income Taxes. See Note 2. Summary of Significant Accounting Policies - Recently Adopted Updates to the Accounting Standards Codification section for more details.

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CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Statement of Stockholders' Equity [Abstract]
Cash dividends declared per share (in usd per share)	$ 1.11	$ 1.0375	$ 0.975

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NATURE OF THE BUSINESS

12 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

NATURE OF THE BUSINESS

1. NATURE OF THE BUSINESS

New Jersey Resources Corporation provides regulated gas distribution services and operates certain unregulated businesses primarily through the following:

New Jersey Natural Gas Company provides natural gas utility service to approximately 538,700 retail customers in central and northern New Jersey and is subject to rate regulation by the BPU. NJNG comprises the Natural Gas Distribution segment.

NJR Clean Energy Ventures Corporation, the Company's clean energy subsidiary, comprises the Clean Energy Ventures segment and consists of the Company's capital investments in commercial and residential solar projects located throughout New Jersey and onshore wind investments in Iowa, Kansas, Wyoming and Pennsylvania. On June 1, 2018, Clean Energy Ventures completed the sale of its membership interest in a 9.7 MW wind farm in Two Dot, Montana. See Note 17. Dispositions for more details regarding the sale.

NJR Energy Services Company comprises the Energy Services segment. Energy Services maintains and transacts around a portfolio of natural gas storage and transportation capacity contracts and provides physical wholesale energy and energy management services in the U.S. and Canada. From July 2017 through February 2018, NJR Retail Services Company provided retail natural gas supply and transportation services to commercial and industrial customers in Delaware, Maryland, Pennsylvania and New Jersey as part of the Energy Services segment. NJRRS was sold to an unrelated third party on February 28, 2018. See Note 17. Dispositions for more details regarding the sale.

NJR Midstream Holdings Corporation, which comprises the Midstream segment, invests in energy-related ventures through its subsidiaries, NJR Steckman Ridge Storage Company, which holds the Company's 50 percent combined ownership interest in Steckman Ridge, located in Pennsylvania; NJNR Pipeline, which holds our DM Common Units; and NJR Pipeline Company, which includes Adelphia Gateway, LLC and the Company's 20 percent ownership interest in PennEast. See Note 6. Investments in Equity Investeesfor more information.

NJR Retail Holdings Corporation has two principal subsidiaries: NJR Home Services Company, which provides heating, central air conditioning, standby generators, solar and other indoor and outdoor comfort products to residential homes throughout New Jersey; and Commercial Realty & Resources Corporation, which owns commercial real estate. NJR Home Services Company and Commercial Realty & Resources Corporation are included in Home Services and Other operations.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Consolidated Financial Statements include the accounts of the Company and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated.

Other financial investments or contractual interests that lack the characteristics of a voting interest entity, which are commonly referred to as variable interest entities, are evaluated by the Company to determine if 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, 2018, 2017 and 2016.

Investments in entities over which the Company does not have a controlling financial interest are either accounted for under the equity method or cost method of accounting.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires the Company to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a 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, investments, 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. AROs are evaluated as often as needed. The Company’s estimates are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources.

The Company has legal, regulatory and environmental proceedings during the normal course of business that can result in loss contingencies. When evaluating the potential for a loss, the Company will establish a reserve if a loss is probable and can be reasonably estimated, in which case it is the Company’s policy to accrue the full amount of such estimates. Where the information is sufficient only to establish a range of probable liability, and no point within the range is more likely than any other, it is the Company’s policy to accrue the lower end of the range. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from estimates.

Business Combinations

The Company accounts for business combinations by applying the acquisition method of accounting. Identifiable assets acquired and liabilities assumed are measured separately at their fair value as of the acquisition date and associated transactions costs are expensed as incurred.

The determination and allocation of fair values to the identifiable assets acquired and liabilities assumed are based on various assumptions and valuation methodologies requiring considerable management judgment. The most significant variables in these valuations are discount rates and the number of years on which to base the cash flow projections, as well as other assumptions and estimates used to determine the cash inflows and outflows. Management determines discount rates based on the risk inherent in the acquired assets and related cash flows. Our valuation of an acquired business is based on available information at the acquisition date and assumptions that we believe are reasonable. However, a change in facts and circumstances as of the acquisition date can result in subsequent adjustments during the measurement period, but no later than one year from the acquisition date.

Revenues

Revenues from the sale of natural gas to NJNG customers are recognized in the period that gas is delivered and consumed by customers, including an estimate for unbilled revenue.

NJNG records unbilled revenue for natural gas services. Natural gas sales to individual customers are based on meter readings, which are performed on a systematic basis throughout the month. At the end of each month, the amount of natural gas delivered to each customer after the last meter reading through the end of the respective accounting period is estimated, and recognizes unbilled revenues related to these amounts. The unbilled revenue estimates are based on estimated customer usage by customer type, weather effects, unaccounted-for gas and the most current tariff rates.

Clean Energy Ventures recognizes revenue when SRECs are transferred to counterparties. SRECs are physically delivered through the transfer of certificates as per contractual settlement schedules.

Revenues for Energy Services are recognized when the natural gas is physically delivered to the customer. In addition, changes in the fair value of derivatives that economically hedge the forecasted sales of the natural gas are recognized in operating revenues as they occur, as noted above. Energy Services also recognizes changes in the fair value of SREC derivative contracts as a component of operating revenues.

Revenues from all other activities are recorded in the period during which products or services are delivered and accepted by customers, or over the related contractual term.

Gas Purchases

NJNG’s tariff includes a component for BGSS, which is designed to allow it to recover the cost of natural gas through rates charged to its customers and is typically revised on an annual basis. As part of computing its BGSS rate, NJNG projects its cost of natural gas, net of supplier refunds, the impact of hedging activities and cost savings created by BGSS incentive programs. NJNG subsequently recovers or credits the difference, if any, of actual costs compared with those included in current rates. Any underrecoveries or overrecoveries are either credited to customers or deferred and, subject to BPU approval, reflected in the BGSS rates in subsequent years.

Gas purchases at Energy Services are composed of gas costs to be paid upon completion of a variety of transactions, as well as realized gains and losses from settled derivative instruments and unrealized gains and losses on the change in fair value of derivative instruments that have not yet settled. Changes in the fair value of derivatives that economically hedge the forecasted purchases of natural gas are recognized in gas purchases as they occur.

Demand Fees

For the purpose of securing storage and pipeline capacity in support of their respective businesses, the Energy Services and Natural Gas Distribution segments enter into storage and pipeline capacity contracts, which require the payment of associated demand fees and charges that allow them access to a high priority of service in order to maintain the ability to access storage or pipeline capacity during a fixed time period, which generally ranges from one to 10 years. Many of these demand fees and charges are based on established tariff rates as established and regulated by FERC. These charges represent commitments to pay storage providers and pipeline companies for the priority right to transport and/or store natural gas utilizing their respective assets.

The following table summarizes the demand charges, which are net of capacity releases, and are included as a component of gas purchases on the Consolidated Statements of Operations for the fiscal years ended September 30:

(Millions)	2018		2017		2016
Energy Services	$	153.0	$	126.4	$	141.0
Natural Gas Distribution	92.5		80.2		77.8
Total	$	245.5	$	206.6	$	218.8

Energy Services expenses demand charges over the term of the service being provided.

The Natural Gas Distribution segment’s costs associated with demand charges are included in its weighted average cost of gas. The demand charges are expensed based on NJNG’s BGSS sales and recovered as part of its gas commodity component of its BGSS tariff.

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, 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 NJR Board of Directors members. 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 9. Stock-Based Compensation for further information.

Sales Tax Accounting

Sales tax that is collected from customers is presented in both operating revenues and operating expenses on the Consolidated Statements of Operations. During fiscal 2018, 2017 and 2016, sales tax collected was $41.7 million, $39.4 million and $31 million, respectively. Effective January 1, 2017, the New Jersey sales tax rate decreased from 7 percent to 6.875 percent. Effective January 1, 2018, the New Jersey sales tax rate decreased again to 6.625 percent.

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.

The Company invests in property that qualifies for federal ITCs and utilizes the ITCs, as allowed, based on the cost and life of the assets. ITCs at NJNG are deferred and amortized as a reduction to the tax provision over the average lives of the related equipment in accordance with regulatory treatment. ITCs at the unregulated subsidiaries of NJR are recognized as a reduction to income tax expense when the property is placed in service. The Company invests in property that qualifies for PTCs. PTCs are recognized as reductions to current federal income tax expense as PTCs are generated through the production activities of the assets. Changes to the federal statutes related to ITCs and PTCs, which have the effect of reducing or eliminating the credits, could have a negative impact on earnings and cash flows.

Investments in Equity Investees

The Company accounts for its investments in Steckman Ridge and PennEast, using the equity method of accounting where its respective ownership interests are 50 percent or less and/or it has significant influence over operating and management decisions, but is not the primary beneficiary, as defined under ASC 810, Consolidation. The Company’s share of earnings is recognized as equity in earnings of affiliates on the Consolidated Statements of Operations. See Note 6. Investments in Equity Investeesfor more information.

Property Plant and Equipment

Regulated property, plant and equipment is stated at original cost. Costs include direct labor, materials and third-party construction contractor costs, AFUDC and certain indirect costs related to equipment and employees engaged in construction. Nonregulated property, plant and equipment is stated at original cost. Costs include direct labor, materials and third-party construction contractor costs and certain indirect costs related to equipment and employees engaged in construction. 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 unregulated entities, and using rates based on the estimated average lives of the various classes of depreciable property for NJNG. The composite rate of depreciation used for NJNG was 2.29 percent of average depreciable property in fiscal 2018, 2.25 percent in fiscal 2017 and 2.32 percent in fiscal 2016. The Company recorded $85.7 million, $81.8 million and $72.7 million in depreciation expense during fiscal 2018, 2017 and 2016, respectively. Effective October 1, 2016, the overall depreciation rate is 2.4 percent, as settled in the base rate case.

Property, plant and equipment was comprised of the following as of September 30:

(Thousands)
Property Classifications	Estimated Useful Lives	2018			2017
Distribution facilities	38 to 74 years	$	2,151,249		$	1,952,697
Transmission facilities	35 to 56 years	295,692			294,586
Storage facilities	34 to 47 years	79,470			78,245
Solar property	20 to 25 years	720,562			587,345
Wind property(1)	17 to 25 years	—			244,764
Midstream property(2)	30 years	6,747			—
All other property	5 to 35 years	50,771			53,433
Total property, plant and equipment		3,304,491			3,211,070
Accumulated depreciation and amortization		(653,442		)	(601,329		)
Property, plant and equipment, net		$	2,651,049		$	2,609,741

(1) Reclassified to assets held for sale. See Note 2. Summary of Significant Accounting Policies, for more information.

(2) Includes activity related to the acquisition of IEC by Adelphia. For fiscal 2017, Midstream property was originally included in All other property.

In March 2017, CR&R sold a 56,400-square-foot office building on five acres of land located in Monmouth County for $9.4 million, net of closing costs, generating a pre-tax gain of $1.9 million, which was recognized as a reduction to O&M on the Consolidated Statements of Operations.

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 3. 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.

Capitalized and deferred interest include the following for the fiscal years ended September 30:

($ in thousands)	2018			2017			2016
AFUDC:
Debt	$	1,979		$	1,311		$	5,009
Equity	5,531			3,867			4,375
Total	$	7,510		$	5,178		$	9,384
Weighted average interest rate	5.94		%	6.90		%	5.06		%

Pursuant to a BPU order, NJNG is permitted to recover carrying costs on uncollected balances related to SBC program costs, which include NJCEP, RAC and USF expenditures. See Note 3. Regulation. The SBC interest rate changes each September based on the August 31 seven-year constant maturity treasury rate plus 60 basis points. The rate was 3.41 percent, 2.55 percent and 2.05 percent for the fiscal years ended September 30, 2018, 2017 and 2016, respectively. Accordingly, other income included $411,000, $78,000 and $54,000 in the fiscal years ended September 30, 2018, 2017 and 2016, respectively.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash on deposit and temporary investments with maturities of three months or less, and excludes restricted cash of $252,000 and $243,000 as of September 30, 2018 and 2017, respectively, related to escrow balances for utility plant projects, which is recorded in other current and noncurrent assets on the Consolidated Balance Sheets.

Customer Accounts Receivable and Allowance for Doubtful Accounts

Receivables consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers, as well as equipment sales, installations, solar leases and PPAs to commercial and residential customers. The Company evaluates its accounts receivables and, to the extent customer account balances are outstanding for more than 60 days, establishes an allowance for doubtful accounts. The allowance is based on a combination of factors including historical collection experience and trends, aging of receivables, general economic conditions in the Company’s distribution or sales territories and customer-specific information. The Company writes-off customer accounts once it is determined they are uncollectible.

The following table summarizes customer accounts receivable by company as of September 30:

(Thousands)	2018				2017
Energy Services	$	157,936	77	%	$	150,322	77	%
Natural Gas Distribution (1)	39,151		19		37,432		19
Clean Energy Ventures	3,330		2		2,655		1
Home Services and Other Operations	5,073		2		6,058		3
Total	$	205,490	100	%	$	196,467	100	%

(1) Does not include unbilled revenues of $7.2 million as of September 30, 2018 and 2017.

Loans Receivable

NJNG currently provides loans, with terms ranging from three to 10 years, to customers that elect to purchase and install certain energy-efficient equipment in accordance with its BPU-approved SAVEGREEN program. The loans are recognized at net present value on the Consolidated Balance Sheets. The Company has recorded $10.4 million and $8.9 million in other current assets and $39.5 million and $40.4 million in other noncurrent assets as of September 30, 2018 and 2017, respectively, on the Consolidated Balance Sheets, related to the loans. If NJNG determines a loan is impaired, the basis of the loan would be subject to regulatory review for recovery. As of September 30, 2018 and 2017, the Company has not recorded an allowance for doubtful accounts for SAVEGREEN loans.

Regulatory Assets & Liabilities

Under cost-based regulation, regulated utility enterprises generally are permitted to recover their operating expenses and earn a reasonable rate of return on their utility investment.

Our Natural Gas Distribution segment maintains its accounts in accordance with the FERC Uniform System of Accounts as prescribed by the BPU and in accordance with the ASC 980, Regulated Operations. As a result of the impact of the ratemaking process and regulatory actions of the BPU, NJNG is required to recognize the economic effects of rate regulation. Accordingly, NJNG capitalizes or defers certain costs that are expected to be recovered from its customers as regulatory assets and recognizes certain obligations representing probable future expenditures as regulatory liabilities on the Consolidated Balance Sheets. See Note 3. Regulation for a more detailed description of NJNG’s regulatory assets and liabilities.

Gas in Storage

Gas in storage is reflected at average cost on the Consolidated Balance Sheets and represents natural gas and LNG that will be utilized in the ordinary course of business.

The following table summarizes gas in storage, at average cost by company, as of September 30:

	2018				2017
($ in thousands)	Gas in Storage			Bcf	Gas in Storage			Bcf
Energy Services		$	90,166	34.1		$	122,884	53.9
Natural Gas Distribution		94,467		24.9		79,179		21.8
Total		$	184,633	59.0		$	202,063	75.7

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 Energy Services, as derivatives, and therefore recognizes them at fair value on the Consolidated Balance Sheets. The Company’s unregulated subsidiaries record changes in the fair value of their financial commodity derivatives in gas purchases and changes in the fair value of their physical forward contracts in gas purchases or operating revenues, as appropriate, on the Consolidated Statements of Operations. Ineffective portions of the cash flow hedges are recognized immediately in earnings.

The ASC 815, Derivatives and Hedging also provides for a NPNS scope exception for qualifying physical commodity contracts that are intended for purchases and sales during the normal course of business and for which physical delivery is probable. Effective January 1, 2016, the Company prospectively applies this normal scope exception on a case-by-case basis to physical commodity contracts at NJNG and forward SREC contracts at Clean Energy Ventures. When applied, it does not record changes in the fair value of these contracts until the contract settles and the related underlying natural gas or SREC is delivered. Gains and/or losses on NJNG’s derivatives used to economically hedge its regulated natural gas supply obligations, as well as its exposure to interest rate variability, are recoverable through its BGSS, a component of its tariff. Accordingly, the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability on the Consolidated Balance Sheets.

See Note 4. 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 Energy Services 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.

Assets Held for Sale

The Company classifies an asset as held for sale if there is a commitment to sell the asset, the asset is available for immediate sale, the sale is probable and the sale will be completed within one year. In March 2018, Clean Energy Ventures committed to a plan to sell its wind assets and expects that the sale will be completed within the next 12 months. Accordingly, the Company classified its wind assets and related liabilities as held for sale on the Consolidated Balance Sheets, which resulted in depreciation expense on wind assets no longer being recorded.

The wind assets classified as held for sale are measured at the lower of their carrying value or fair value less cost to sell. At September 30, 2018, the Company performed a fair value assessment of its wind assets held for sale. The Company equally weighted the valuation derived from an income approach and a market approach to determine fair value. The Company believes that the estimates and assumptions used in calculating the fair value of our assets and liabilities held for sale are reasonable and appropriate based on the information that was known when the estimates were made. The Company concluded that the fair value of the wind assets was greater than the carrying value and thus no impairment was recorded.

On June 1, 2018, Clean Energy Ventures completed the sale of its membership interest in a 9.7 MW wind farm in Two Dot, Montana. See Note 17. Dispositions for more details.

The major classes of assets and liabilities included within the disposal group as held for sale are as follows:

(Thousands)	September 30, 2017		Assets reclassified as held for sale			Assets Sold			September 30, 2018
Assets held for sale:
Property, plant and equipment - wind equipment, at cost	$	—	$	245,044		$	(20,688	)	$	224,356
Property, plant and equipment - accumulated depreciation, wind equipment	—		(21,561		)	3,060			(18,501		)
Prepaid and accrued taxes	—		866			(77		)	789
Other noncurrent assets	—		261			—			261
	$	—	$	224,610		$	(17,705	)	$	206,905
Liabilities held for sale:
Accounts payable and other (1)	$	—	$	—		$	186		$	186
Asset retirement obligation	—		4,262			(266		)	3,996
	$	—	$	4,262		$	(80	)	$	4,182

(1) Transaction fee owed to broker for the sale of Two Dot wind farm.

Available for Sale Securities

Available for sale securities are carried at fair value on the Consolidated Balance Sheets. For fiscal years ended September 30, 2018 and prior, total unrealized gains and losses associated are included as a part of accumulated other comprehensive income, a component of common stock equity. Reclassifications of realized gains or losses out of other comprehensive income into earnings are recorded in other income, net on the Consolidated Statements of Operations based on average cost.

Management evaluates its equity securities for other-than-temporary impairment on a quarterly basis, and more frequently when economic, market or other concerns warrant such evaluation. Consideration is given to the length of time and the extent to which the fair value has been less than cost; the financial condition and near term prospects of the issuer; whether the market decline was affected by macroeconomic conditions, changes in tax laws, regulations or other governmental policies; and whether the Company has the intent to sell the security or more likely than not will be required to sell the security before the recovery of its amortized cost basis. If the decline in value of our equity securities is determined to be other-than-temporary, an impairment is recognized through earnings within other income, net on the Consolidated Statements of Operations.

During fiscal 2018, NJR sold shares of its available for sale securities and received proceeds of approximately $6.6 million and realized a pre-tax gain of approximately $5.3 million, which is included in other income, net on the Consolidated Statements of Operations, or $3.2 million, net of tax. During fiscal 2017, NJR received proceeds of approximately $6.6 million and realized a pre-tax gain of $5.4 million, or $3.2 million, net of tax. Reclassifications of realized gains out of other comprehensive income into income are determined based on average cost.

DM Units

In September 2015, the Company exchanged its ownership interest in Iroquois for approximately 1.84 million DM Common Units. The investment in DM is included as part of the Company's equity investments in the Midstream segment. The exchange of ownership interests in Iroquois for DM was considered a contribution of real estate into another real estate venture. As a result, the Company recorded a deferred gain of $24.6 million on the Consolidated Balance Sheets, based on the difference between the carrying amount of its investment in Iroquois and the fair value of the DM Common Units on the closing date of the transaction. The deferred gain will be recognized in other income, net on the Consolidated Statements of Operations upon completion of the earnings process, typically through the sale of the related securities, or other earnings event.

On March 15, 2018, the FERC issued a policy revision indicating that it no longer will allow interstate natural gas and oil pipelines held by a MLP to recover an income tax allowance in cost-of-service rates. The policy revision had a material negative impact on the value of NJR's investment in DM Common Units. As a result, the Company evaluated the decrease in fair value of its available for sale securities and determined that the decline was other-than-temporary. Accordingly, the Company recognized an other-than-temporary impairment of $17.8 million, or $14.8 million, net of tax, as of March 31, 2018.

Since the deferred gain was established based upon the difference in the fair value of the DM Common Units acquired and the carrying value of the ownership of Iroquois, concurrent with the impairment charge to earnings, the Company reduced the amount of the deferred gain for the DM Common Units. This reduction of the deferred gain of $17.8 million was also recorded in other income, net on the Consolidated Statements of Operations.

On July 18, 2018, the FERC finalized its March 15, 2018 policy regarding the tax treatment of MLP pipelines. Natural gas pipelines within an MLP structure, where the parent is a taxable entity and consolidates the financial results of the MLP on its federal income tax return, will be allowed to include an income tax allowance in its cost-of-service rates.

As of September 30, 2018, the Company's available for sale securities had a fair value of $32.9 million and total unrealized gains were $4.7 million, or $3.4 million, net of deferred income tax benefit. The remaining deferred gain associated with the Company’s investment in DM Common Units totaled $6.8 million. As of September 30, 2017, the Company's available for sale securities had a fair value of $65.8 million and total unrealized gains were $12.8 million, or $7.7 million, net of deferred income tax expense.

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, 2018, intangible assets consist of internal-use software costs of $513,000 and $22.9 million, net of amortization, related to its acquisition of Talen’s wholesale natural gas energy contracts. These contracts are being amortized based upon expected cash flows over the respective terms of the agreements. The estimated future amortization expense for the next five years as of September 30, is as follows:

(Thousands)
2019	$	8,424
2020	$	4,925
2021	$	4,604
2022	$	2,561
2023	$	2,271
Thereafter	$	77

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. During the year, the Company evaluated whether there were such events or circumstances that occurred, including evaluation of the new clean energy legislation signed in May 2018, and concluded that there were no events or circumstances in the current year that indicated that the carrying value of long-lived assets or finite-lived intangibles is 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 8. 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 at the end of the term or repurchase the asset. Proceeds from sale-leaseback transactions are accounted for as financings and are included in long-term debt on the Consolidated Balance Sheets. During fiscal 2018 and 2017, NJNG received $7.8 million and $9.6 million, respectively, in connection with the sale-leaseback of its natural gas meters with terms ranging from seven to 11 years.

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 terms of the arrangement create a continuing involvement in the asset and the asset is considered integral equipment, the Company uses the financing method to account for the transaction. Under the financing method, the Company recognizes the proceeds received from the lessor that constitute a payment to acquire the solar energy asset as a financing arrangement, which is recorded as a component of debt on the Consolidated Balance Sheets.

Clean Energy Ventures received $71.5 million and $32.9 million in proceeds related to the sale of commercial solar assets during fiscal 2018 and 2017, respectively. Clean Energy Ventures simultaneously entered into agreements to lease the assets back over six to 15-year terms. The Company will continue to operate the solar assets and is responsible for related expenses and entitled to retain the revenue generated from SRECs and energy sales. The ITCs and other tax benefits associated with these solar projects have been transferred to the buyer; however, the lease payments are structured so that Clean Energy Ventures is compensated for the transfer of the related tax incentives. Accordingly, Clean Energy Ventures recognizes the equivalent value of the ITC 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. Clean Energy Ventures did not enter into sale-leaseback during fiscal 2016 and therefore recognized the full ITC in income tax (benefit) provision on the Consolidated Statements of Operations when the assets were placed in service.

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 the 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 13. 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 Income Security Act, as amended, and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments. The Company made a discretionary contribution of $30 million during the first quarter of fiscal 2016 to improve the funded status of the pension plans based on the current actuarial assumptions, which included the adoption of the most recent mortality table. The Company made no discretionary contributions to the pension plans in fiscal 2018 and 2017.

The Company also provides two primarily noncontributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. The Company contributed $6.2 million, $6 million and $3.2 million in aggregate to these plans in fiscal 2018, 2017 and 2016, respectively, which is recorded in postemployment employee benefit liability on the Consolidated Balance Sheets.

See Note 10. Employee Benefit Plans, for a more detailed description of the Company’s pension and postemployment plans.

Asset Retirement Obligations

The Company recognizes AROs related to the costs associated with cutting and capping NJNG’s main and service gas distribution mains, which is required by New Jersey law when taking such gas distribution mains out of service. The Company also recognizes AROs associated with Clean Energy Ventures’ solar and wind assets when there are decommissioning provisions in lease agreements that require removal of the asset at the end of the lease term.

AROs 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 Clean Energy Ventures’ 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 AROs 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 assign probabilities based on management’s reasonable judgment and knowledge of industry practice. Accordingly, AROs are subject to change.

Accumulated Other Comprehensive Income

The following table presents the changes in the components of accumulated other comprehensive income, net of related tax effects, as of September 30:

(Thousands)	Unrealized gain (loss) on available for sale securities			Adjustment to postemployment benefit obligation				Total
Balance as of September 30, 2016	$	4,198		$	(19,353	)		$	(15,155	)
Other comprehensive income, net of tax
Other comprehensive income, before reclassifications, net of tax of $(6,593), $(2,619), $(9,212)	10,019			3,783				13,802
Amounts reclassified from accumulated other comprehensive (loss) income, net of tax of $2,192, $(868), $1,324	(3,173		)	1,270			(1)	(1,903		)
Net current-period other comprehensive income, net of tax of $(4,401), $(3,487), $(7,888)	6,846			5,053				11,899
Balance at September 30, 2017	$	11,044		$	(14,300	)		$	(3,256	)
Other comprehensive income, net of tax
Other comprehensive (loss) income, before reclassifications, net of tax of $6,973, $(125), $6,848	(19,245		)	464				(18,781		)
Amounts reclassified from accumulated other comprehensive income, net of tax of $(858), $(448), $(1,306)	11,647			1,056			(1)	12,703
Net current-period other comprehensive (loss) income, net of tax of $6,115, $(573), $5,542	(7,598		)	1,520				(6,078		)
Reclassifications of certain income tax effects to retained earnings (2)	—			(3,276		)		(3,276		)
Balance at September 30, 2018	$	3,446		$	(16,056	)		$	(12,610	)

(1) Included in the computation of net periodic pension cost, a component of O&M expense on the Consolidated Statements of Operations. For more details, see Note 10. Employee Benefit Plans.

(2) Due to the adoption of ASU No. 2018-02, an amendment to ASC 740, Income Taxes. See Note 2. Summary of Significant Accounting Policies- Recently Adopted Updates to the Accounting Standards Codification section for more details.

Foreign Currency Transactions

The market area of Energy Services includes Canadian delivery points and as a result, Energy Services incurs certain natural gas commodity costs and demand fees denominated in Canadian dollars. Gains or losses that occur as a result of these foreign currency transactions are reported as a component of gas purchases on the Consolidated Statements of Operations. Gains and losses recognized for the fiscal years ended September 30, 2018, 2017 and 2016, are considered immaterial.

Reclassification

Certain prior period amounts related to the amortization of acquired wholesale energy contracts on the Consolidated Statements of Cash Flows and in the deferred tax table in Note 12. Income Taxes for the fiscal year ended September 30, 2017, were reclassified to conform to the current period presentation.

Recently Adopted Updates to the Accounting Standards Codification

Inventory

In July 2015, the FASB issued ASU No. 2015-11, an amendment to ASC 330, Inventory, which requires entities to measure most inventory “at the lower of cost or net realizable value,” thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. The Company adopted the new guidance in the first quarter of fiscal 2018 and applied the new provisions on a prospective basis, which did not impact its financial position, results of operations or cash flows upon adoption.

Reporting Comprehensive Income

In February 2018, the FASB issued ASU No. 2018-02, an amendment to ASC 220, Income Statement - Reporting Comprehensive Income, which allows for the reclassification from accumulated other comprehensive income to retained earnings for the disproportionate tax effects of the Tax Act. The Company early adopted this guidance in the fourth quarter of fiscal 2018 and reclassified on a prospective basis only, $3.3 million from accumulated other comprehensive income to retained earnings. This did not materially impact the Company’s financial position, results of operations or cash flows.

Tax

In March 2018, the FASB issued ASU No. 2018-05, an amendment to ASC 740, Income Taxes, which provides relief to entities in their calculation of the effects of the Tax Act by allowing them to record provisional amounts for certain income tax effects to address circumstances in which an entity does not have the necessary information available, prepared or analyzed to complete the accounting. These provisional amounts are subject to change as information and assumptions are updated throughout the measurement period, which may not extend beyond one year from the enactment date. The new guidance was effective immediately upon issuance, and the Company adopted the new guidance in the second quarter of fiscal 2018 and applied the new provision on a prospective basis.

Other Recent Updates to the Accounting Standards Codification

Revenue

In May 2014, the FASB issued ASU No. 2014-09, and added ASC 606, Revenue from Contracts with Customers, to the ASC. ASC 606 supersedes ASC 605, Revenue Recognition, as well as most industry-specific guidance, and prescribes a single, comprehensive revenue recognition model designed to improve financial reporting comparability across entities, industries, jurisdictions and capital markets. The Company adopted the new guidance on October 1, 2018, and will apply the new provisions on a modified retrospective basis.

Management established an implementation team to evaluate the impact on the Company’s financial position, results of operations and cash flows upon adoption of ASC 606. This implementation team reviewed the revenue streams of all of its subsidiaries and formed conclusions to determine if any system, process, controls and organizational changes are necessary upon adoption. The assessment of the impact of this guidance included reviewing the Company’s accounting policies under ASC 605 and identifying potential differences after the adoption of ASC 606. The Company concluded that its tariff-based sales of natural gas will be within the scope of the new guidance and it does not anticipate any modification to the pattern of revenue recognition from such sales. Revenues from derivative instruments such as those related to the Company’s SREC sales and natural gas purchases and sales will continue to be accounted for under ASC 815 and thus are outside the scope of ASC 606. Additionally, NJNG revenues generated by the CIP have been determined to be alternative revenue programs under ASC 980 and are also outside the scope of ASC 606 as they are deemed to be a contract with the regulator. The Company also evaluated its renewable asset PPA arrangements and does not anticipate any modification to the pattern of revenue recognition of the related electricity, capacity and REC sales. Revenues from RECs sold as part of a bundled arrangement will be recognized in the same period as the related generation, consistent with current practice.

The Company has completed its evaluation of its revenue streams, and based on the assessment performed, has concluded that the new guidance will not have a material impact on its financial position, results of operations or cash flows upon adoption. Additionally, the Company did not implement significant changes to its business processes, systems or internal controls over financial reporting upon adoption. ASC 606 requires expanded disclosures, including the disclosure of performance obligations, disaggregated revenues and contract balances, which the Company will include in its financial statements beginning in the first quarter of fiscal 2019.

Financial Instruments

In January 2016, the FASB issued ASU No. 2016-01, an amendment to ASC 825, Financial Instruments, to address certain aspects of the recognition, measurement, presentation and disclosure of financial instruments. The standard affects investments in equity securities that do not result in consolidation and are not accounted for under the equity method and the presentation of certain fair value changes for financial liabilities measured at fair value. It also simplifies the impairment assessment of equity investments without a readily determinable fair value by requiring a qualitative assessment. The guidance is effective for the Company beginning October 1, 2018. The amendment will be applied on a modified retrospective basis. The Company evaluated the amendment and noted that, upon adoption, subsequent changes to the fair value of the Company’s available for sale securities will be recorded in the Consolidated Statement of Operations as opposed to other comprehensive income. The Company will reclassify $3.4 million in accumulated other comprehensive income related to available for sale securities to the opening balance of retained earnings as of October 1, 2018. There will be no material impact to the Company’s financial position, results of operations or cash flows upon adoption.

In June 2016, the FASB issued ASU No. 2016-13, an amendment to ASC 326, Financial Instruments - Credit Losses, which changes the impairment model for certain financial assets that have a contractual right to receive cash, including trade and loan receivables. The new model requires recognition based upon an estimation of expected credit losses rather than recognition of losses when it is probable that they have been incurred. An entity will apply the amendment through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. The Company is currently evaluating the amendment to understand the impact on its financial position, results of operations and cash flows upon adoption and will apply the new guidance to its trade and loan receivables on a modified retrospective basis.

Leases

In February 2016, the FASB issued ASU No. 2016-02, an amendment to ASC 842, Leases, which provides for a comprehensive overhaul of the lease accounting model and changes the definition of a lease within the accounting literature. Under the new standard, all leases with a term greater than one year will be recorded on the balance sheet. Amortization of the related asset will be accounted for using one of two approaches prescribed by the guidance. Additional disclosures will be required to allow the user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach is required for leases existing at the time of adoption.

In January 2018, the FASB issued ASU No. 2018-01, a further amendment to ASC 842, Leases, which was introduced by ASU No. 2016-02, as discussed above. This update provides an optional practical expedient that allows companies to not evaluate existing or expired land easements that were not previously accounted for under Topic 840 as leases. The Company expects to elect this practical expedient upon adoption. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted.

In July 2018, the FASB issued ASU No. 2018-11, which provides an optional transition method to ASC 842 that allows the Company to recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. At this time, the Company does not plan to early adopt the new guidance and expects to transition on a modified retrospective basis. While the Company is currently evaluating the full impact of the standard and its related updates, it expects to recognize additional assets and liabilities arising from current operating leases to its financial position upon adoption. Current operating leases primarily consist of office and land leases related to the Company’s solar and wind assets.

Statement of Cash Flows

In August 2016, the FASB issued ASU No. 2016-15, an amendment to ASC 230, Statement of Cash Flows, which addresses eight specific cash flow issues for which there has been diversity in practice. The guidance is effective for the Company beginning October 1, 2018. The amendment will be applied on a retrospective basis and the Company does not expect any material impacts to its statement of cash flows.

In November 2016, the FASB issued ASU No. 2016-18, an amendment to ASC 230, Statement of Cash Flows, which requires that any amounts that are deemed to be restricted cash or restricted cash-equivalents be included in cash and cash-equivalent balances on the cash flow statement and, therefore, transfers between cash and restricted cash accounts will no longer be recognized within the statement of cash flows. The guidance is effective for the Company beginning October 1, 2018, and will be applied on a retrospective basis. Based on the Company's historical restricted cash balances, it does not expect any material impacts to its statement of cash flows.

Intangibles

In August 2018, the FASB issued ASU No. 2018-15, an amendment to ASC 350, Intangibles - Goodwill and Other, which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. Upon adoption, the amendment will be applied on a prospective or retrospective basis.

Business Combinations

In January 2017, the FASB issued ASU No. 2017-01, an amendment to ASC 805, Business Combinations, clarifying the definition of a business in the ASC, which is intended to reduce the complexity surrounding the assessment of a transaction as an asset acquisition or business combination. The amendment provides an initial fair value screen to reduce the number of transactions that would fit the definition of a business, and when the screen threshold is not met, provides an updated model that further clarifies the characteristics of a business. The guidance is effective for the Company beginning October 1, 2018, and will be applied on a prospective basis. The amendment could potentially have material impacts on future transactions that the Company may enter into by altering the Company’s conclusion on the accounting framework that is applied to acquisitions.

Gains and Losses from the Derecognition of Nonfinancial Assets

In February 2017, the FASB issued ASU No. 2017-05, an amendment to ASC 610-20, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets, which clarifies the scope and accounting related to the derecognition of nonfinancial assets, including partial sales and contributions of nonfinancial assets to a joint venture or other non-controlled investee. The guidance is effective concurrently with ASC 606, which is effective for the Company as of October 1, 2018 and will be applied retrospectively with a cumulative effect adjustment at the date of adoption. The Company had a deferred gain of $6.8 million related to nonfinancial assets on the balance sheet, which will be recognized under the new accounting guidance as a cumulative effect adjustment to the opening balance of retained earnings as of October 1, 2018.

Compensation - Retirement Benefits

In March 2017, the FASB issued ASU No. 2017-07, an amendment to ASC 715, Compensation - Retirement Benefits, which changes the presentation of net periodic benefit cost on the income statement by requiring companies to present all components of net periodic benefit cost, other than service cost, outside a subtotal of income from operations. The amendment also states that only the service cost component of net periodic benefits costs is eligible for capitalization, when applicable. The amendment establishes a practical expedient that permits entities to use their previously disclosed service and other costs in their pension and other postretirement benefit plan footnotes in the prior comparative periods as the estimation basis when applying the retrospective presentation of these costs in the income statement. The guidance is effective for the Company beginning October 1, 2018, and will be applied on a retrospective basis for income statement presentation, and on a prospective basis for changes to capitalization of costs. The changes related to the costs that will be eligible for capitalization and based on the components of net periodic benefit costs during fiscal year 2018, will not have a material impact on the Company's financial position, results of operations or cash flows upon adoption

In August 2018, the FASB issued ASU No. 2018-14, an amendment to ASC 715, Compensation - Retirement Benefits, which removes disclosures that no longer are considered cost-beneficial, clarifies the specific requirements of certain disclosures, and adds new disclosure requirements identified as relevant. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. Upon adoption, the amendments will be applied on a retrospective basis. The Company is continuing to evaluate the amendment to fully understand the impact on the Company's disclosures upon adoption.

Stock Compensation

In May 2017, the FASB issued ASU No. 2017-09, an amendment to ASC 718, Compensation - Stock Compensation, which clarifies the accounting for changes to the terms or conditions of share-based payments. The guidance is effective for the Company beginning October 1, 2018, and will be applied prospectively to awards modified on or after the adoption date. There was no material impact to the Company's financial position, results of operations or cash flows upon adoption.

In June 2018, the FASB issued ASU No. 2018-07, an amendment to ASC 718, Compensation - Stock Compensation, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. The guidance is effective for the Company beginning October 1, 2019, with early adoption permitted. The Company is currently evaluating the impact of the amendment on the Company’s financial position, results of operations and cash flows upon adoption.

Derivatives and Hedging

In August 2017, the FASB issued ASU No. 2017-12, an amendment to ASC 815, Derivatives and Hedging, which is intended to make targeted improvements to the accounting for hedging activities by better aligning an entity’s risk management activities and financial reporting for hedging relationships. These amendments modify the accounting for both nonfinancial and financial risk components and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. Additionally, the amendments are intended to simplify the application of the hedge accounting guidance and provide relief to companies by easing certain hedge documentation requirements. The guidance is effective for the Company beginning October 1, 2019, with early adoption permitted. Upon adoption, the transition requirements and elections will be applied to hedging relationships existing on the date of adoption. The Company does not currently apply hedge accounting to any of its risk management activities and thus does not expect the amendments to have any impact on its financial position, results of operations and cash flows upon adoption.

Fair Value

In August 2018, the FASB issued ASU No. 2018-13, an amendment to ASC 820, Fair Value Measurement, which removes, modifies and adds to certain disclosure requirements of fair value measurements. Disclosure requirements removed include the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the valuation processes for Level 3 fair value measurements. Modifications include considerations around the requirement to disclose the timing of liquidation of an investee’s assets and the date when restrictions from redemption might lapse. The additions include the requirement to disclose changes in unrealized gains and losses for the period in other comprehensive income for recurring Level 3 fair value measurements held and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. Upon adoption, the amendments will be applied on a prospective or retrospective basis depending on the specific amendments’ transition requirements. The Company is currently evaluating the amendments to understand the impact on its financial position, results of operations, cash flows and disclosures upon adoption and will apply the new guidance.

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REGULATION

12 Months Ended

Sep. 30, 2018

Regulated Operations [Abstract]

REGULATION

3. REGULATION

The EDECA is the legal framework for New Jersey’s public utility and wholesale energy landscape. NJNG is required, pursuant to a written order by the BPU under EDECA, to open its residential markets to competition from third-party natural gas suppliers. Customers can choose the supplier of their natural gas commodity in NJNG’s service territory.

As required by EDECA, NJNG’s rates are segregated into two primary components: the commodity portion, which represents the wholesale cost of natural gas, including the cost for interstate pipeline capacity to transport the gas to NJNG’s service territory; and the delivery portion, which represents the transportation of the commodity portion through NJNG’s gas distribution system to the end-use customer. NJNG does not earn utility gross margin on the commodity portion of its natural gas sales. NJNG earns utility gross margin through the delivery of natural gas to its customers, regardless of whether it or a third-party supplier provides the wholesale natural gas commodity.

Under EDECA, the BPU is required to audit the state’s energy utilities every two years. The primary purpose of the audit is to ensure that utilities and their affiliates offering unregulated retail services do not have an unfair competitive advantage over nonaffiliated providers of similar retail services. A combined competitive services and management audit of NJNG commenced in August 2013. A draft management audit report was accepted by the BPU on July 23, 2014, for public comment. To date, NJNG has implemented all audit recommendations with the approval of BPU staff and is waiting for final BPU approval.

NJNG is subject to cost-based regulation; therefore, it is permitted to recover authorized operating expenses and earn a reasonable return on its utility capital investments based on the BPU’s approval. The impact of the ratemaking process and decisions authorized by the BPU allows NJNG to capitalize or defer certain costs that are expected to be recovered from its customers as regulatory assets, and to recognize certain obligations representing amounts that are probable future expenditures as regulatory liabilities in accordance with accounting guidance applicable to regulated operations.

NJNG’s recovery of costs is facilitated through its base rates, BGSS and other regulatory tariff riders. NJNG is required to make an annual filing to the BPU by June 1 of each year for review of its BGSS, CIP and other programs and related rates. Annual rate changes are requested to be effective at the beginning of the following fiscal year. The current base rate includes a weighted average cost of capital of 6.9 percent and a return on common equity of 9.75 percent. In addition, NJNG is permitted to request approval of certain rate or program changes on an interim basis. All rate and program changes are subject to proper notification and BPU review and approval.

Regulatory assets and liabilities included on the Consolidated Balance Sheets as of September 30, are composed of the following:

(Thousands)	2018		2017
Regulatory assets-current
New Jersey Clean Energy Program	$	14,052	$	14,202
Underrecovered gas costs	4,137		9,910
Derivatives at fair value, net	108		9,010
Conservation Incentive Program	—		17,669
Total current regulatory assets	$	18,297	$	50,791
Regulatory assets-noncurrent
Environmental remediation costs:
Expended, net of recoveries	$	33,017	$	28,547
Liability for future expenditures	130,800		149,000
Deferred income taxes	17,225		21,795
SAVEGREEN	8,636		16,302
Postemployment and other benefit costs	136,716		141,433
Deferred storm damage costs	10,858		13,030
Cost of removal	22,339		—
Other noncurrent regulatory assets	9,001		5,812
Total noncurrent regulatory assets	$	368,592	$	375,919
Regulatory liability-current
Conservation Incentive Program	$	6,994	$	—
Derivatives at fair value, net	1,191		78
Total current regulatory liabilities	$	8,185	$	78
Regulatory liabilities-noncurrent
Tax Act impact (1)	$	205,410	$	—
Cost of removal	—		7,902
New Jersey Clean Energy Program	1,902		5,795
Other noncurrent regulatory liabilities	1,827		810
Total noncurrent regulatory liabilities	$	209,139	$	14,507

(1) Includes an adjustment related to the re-measurement of NJNG's net deferred tax liabilities to reflect the change in federal tax rates enacted in the Tax Act, which is net of sales tax collected from customers. For a more detailed discussion, see Note 12. Income Taxes.

Recovery of regulatory assets is subject to BPU approval, and therefore, if there are any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to income in the period of such determination.

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 2019. NJNG recovers the costs associated with its portion of the NJCEP obligation through its NJCEP rider, with interest.

Over and Underrecovered Gas Costs

NJNG recovers its cost of gas through the BGSS rate component of its customers’ bills. NJNG’s cost of gas includes the purchased cost of the natural gas commodity, fees paid to pipelines and storage facilities, adjustments as a result of BGSS incentive programs and hedging transactions. Overrecovered gas costs represent a regulatory liability that generally occurs when NJNG’s BGSS rates are higher than actual costs and requests approval to be returned to customers including interest, when applicable, in accordance with NJNG’s approved BGSS tariff. Conversely, underrecovered gas costs generally occur during periods when NJNG’s BGSS rates are lower than actual costs, in which case NJNG records a regulatory asset and requests amounts to be recovered from customers in the future.

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 4. Derivative Instruments.

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.

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 13. 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, without interest, as approved by the BPU, over a two- to 10-year period depending upon the specific program incentive.

Postemployment and Other Benefit Costs

Postemployment and Other Benefit Costs represents NJNG’s underfunded postemployment benefit obligations, 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 10. Employee Benefit Plans.

Deferred Storm Damage Costs

Portions of NJNG’s distribution system incurred significant damage as a result of Superstorm 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 in docket number GR15111304 dated September 23, 2016. 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. NJNG’s prior regulatory liability represented customer collections in excess of actual expenditures, which the Company returned to customers as a reduction to depreciation expense.

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. As of September 30, 2018, NJNG recorded $3.2 million of PIM in other regulatory assets, which is being recovered through base rates over a seven-year amortization period effective October 2016.

The Tax Act

On December 22, 2017, the Tax Act was signed into law, which resulted in a reduction in the federal corporate tax rate. As a result, NJNG recorded a regulatory liability, which included the revaluation of its deferred income taxes and the accounting of the income tax effects on the revaluation. The revaluation was based on certain assumptions and estimations NJNG made with respect to its deferred taxes, as well as the effects from the Tax Act, and as such is subject to change if and when assumptions are updated. See Note 12. Income Taxes for a more detailed discussion on the Tax Act.

On January 31, 2018, the BPU issued an Order which directed New Jersey utilities to submit filings to the BPU by March 2, 2018, to propose the prospective change in base rates as a result of the Tax Act to be effective April 1, 2018, the method to return to customers the overcollection of taxes in base rates from January 1, 2018, through March 31, 2018 and an outline of the method by which the excess deferred taxes would be returned to customers. The excess deferred taxes are primarily related to timing differences associated with utility plant depreciation and are subject to IRS normalization rules, which require amortization over the remaining life of the utility plant.

On March 1, 2018, NJNG submitted its required filing to the BPU proposing a $19.7 million base rate reduction and customer refunds of approximately $31 million, which is inclusive of state sales tax and interest at the Company’s short-term debt rate as specified in the Company’s last base rate case. On March 26, 2018, the BPU approved, on an interim basis, the $19.7 million rate reduction, effective April 1, 2018. On May 22, 2018, the BPU approved final rates and also customer refunds of the $31 million. These credits were returned to customer accounts in June 2018.

The following is a description of certain regulatory proceedings during fiscal 2017 and 2018:

BGSS and CIP

BGSS rates are normally revised on an annual basis. In addition, to manage the fluctuations in wholesale natural gas costs, NJNG has the ability to make two interim filings during each fiscal year to increase residential and small commercial customer BGSS rates on a self-implementing and provisional basis. NJNG is also permitted to refund or credit back a portion of the commodity costs to customers at any time given five days’ notice when the natural gas commodity costs decrease in comparison to amounts projected or to amounts previously collected from customers. Concurrent with the annual BGSS filing, NJNG files for an annual review of its CIP. NJNG’s annual BGSS and CIP filings are summarized as follows:

• June 2016 BGSS/CIP filing — In September 2016, the BPU approved NJNG’s filing to increase its CIP rates resulting in a $43.9 million annual recovery increase and to decrease its annual BGSS rate for residential and small commercial customers resulting in a $22.6 million annual recovery decrease effective October 2016. This petition also included bill credits to residential and small commercial customers during the months of November 2016 through February 2017, as a result of a decline in the wholesale price of natural gas. A total of $42 million in bill credits were issued during fiscal 2017.

• June 2017 BGSS/CIP filing — In March 2018, the BPU approved NJNG’s petition on a final basis to maintain its BGSS rate for residential and small commercial customers, increase its balancing charge rate, which resulted in a $3.7 million increase to the annual revenues credited to BGSS, and decrease its CIP rates, which resulted in a $16.2 million annual recovery decrease that was effective October 2017.

• May 2018 BGSS/CIP filing — On September 17, 2018, the BPU provisionally approved NJNG’s annual petition to maintain its BGSS rate for residential and small commercial customers and increase its balancing charge rate, resulting in a $10.3 million increase to the annual revenues credited to BGSS, as well as changes to the CIP rates, which will result in a $30.9 million annual recovery decrease effective October 2018.

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 energy efficiency upgrades to promote energy efficiency incentives to its residential and commercial customers while stimulating state and local economies through the creation of jobs. Depending on the specific initiative or approval, NJNG recovers costs associated with the programs over a three- to 10-year period through a tariff rider mechanism.

As of September 30, 2018, the BPU has approved total SAVEGREEN investments of approximately $354.3 million, including $135 million that was approved on September 17, 2018, for a continuation of existing EE programs and the implementation of new programs through December 2021.

SAVEGREEN investments and costs are filed with the BPU on an annual basis. Since inception, $162 million in grants, rebates and loans have been provided to customers, with a total annual recovery of approximately $16.1 million. The recovery includes a weighted average cost of capital that ranges from 6.69 percent to 7.76 percent, with a return on equity of 9.75 percent to 10.3 percent, respectively. On October 16, 2018, NJNG requested a decrease in its EE recovery rate reflecting costs incurred through September 30, 2018, which will result in an annual decrease of $8.8 million, anticipated to be effective January 1, 2019.

Societal Benefits Clause

The SBC is comprised of three primary riders that allow NJNG to recover costs associated with USF, which is a permanent statewide program for all natural gas and electric utilities for the benefit of income-eligible customers, MGP remediation and the NJCEP. NJNG has submitted the following filings to the BPU, which include a report of program expenditures incurred each program year:

• 2017 SBC filing — In September 2017, the BPU approved NJNG’s annual USF compliance filing to decrease the statewide USF rate, which will result in a $2.6 million annual decrease, effective October 1, 2017. On July 25, 2018, the BPU approved NJNG's annual SBC filing requesting to recover remediation expenses incurred through June 30, 2017, a reduction in the RAC, which resulted in an annual decrease of $2.4 million, and to increase the NJCEP factor, which will result in an annual increase of $1.8 million, effective September 1, 2018.

• 2018 SBC filing — On September 17, 2018, the BPU approved NJNG’s annual USF compliance filing to increase the statewide USF rate, which will result in a $1 million annual increase, effective October 1, 2018. On September 21, 2018, NJNG filed its annual SBC application requesting to recover remediation expenses incurred through June 30, 2018, an increase in the RAC, which will result in an annual increase of $1.4 million, and an increase to the NJCEP factor, which will result in an annual increase of approximately $1.9 million, effective April 1, 2019.

Infrastructure Programs

NJNG has significant annual capital expenditures associated with the management of its natural gas distribution and transmission system, including new utility plant for customer growth and its associated PIM and infrastructure programs. NJNG continues to implement BPU-approved infrastructure projects that are designed to enhance the reliability of NJNG’s gas distribution system, including SAFE and NJ RISE.

SAFE/NJ RISE

The SAFE program replaces portions of NJNG’s gas distribution unprotected steel, cast iron infrastructure and associated services to improve the safety and reliability of the gas distribution system. SAFE I was approved to invest up to $130 million, exclusive of AFUDC, over a four-year period. The recovery of SAFE I capital investments and the corresponding rate mechanism were approved through NJNG’s base rate case effective October 2016. SAFE II was approved to invest up to $200 million, excluding AFUDC, over a five-year period. NJNG will recover approximately $157.5 million through annual rate filings, with the remainder recovered through subsequent rate cases. As a condition of approval of the program, NJNG is required to file a base rate case no later than November 2019.

NJ RISE consists of six capital investment projects estimated to cost $102.5 million over a five-year period, excluding AFUDC, for gas distribution storm-hardening and mitigation projects, along with incremental depreciation expense. NJ RISE includes a weighted average cost of capital that ranges from 6.74 percent to 6.9 percent and a return on equity of 9.75 percent. NJ RISE investments through June 30, 2016, were approved for recovery through NJNG’s new base rates effective October 2016. Requests for recovery of future NJ RISE capital costs will occur in conjunction with SAFE II.

In September 2017, the BPU approved NJNG’s annual petition requesting a base rate increase for the recovery of NJ RISE and SAFE II capital investment costs with an annual increase of $4.1 million effective October 1, 2017. On September 17, 2018, the BPU approved NJNG’s petition requesting a base rate increase of $6.8 million annually for the recovery of SAFE II and NJ RISE capital investment costs related to the 12 months ending June 30, 2018 effective October 1, 2018.

SRL

The SRL is an approximately 30-mile, 30-inch transmission main designed to support improved system integrity and reliability in the southern portion of NJNG’s service territory, estimated to cost between $180 million and $215 million. In March 2016, the BPU issued an order designating the SRL route and exempting the SRL from municipal land use ordinances, regulations, permits and license requirements. In February 2017, the New Jersey Department of Environmental Protection issued a permit authorizing construction of the SRL within the jurisdiction of the Coastal Area Facility Review Act as well as a Freshwater Wetlands permit. In September 2017, the NJ Pinelands Commission approved construction of NJNG’s SRL. All approvals and permits have been appealed by third parties.

Other Regulatory Initiatives

In May 2016, NJNG included a proposal in its base rate case to recover certain capital costs and incremental operation and maintenance costs related to a March 2016 BPU Order regarding new cyber security requirements. Costs associated with this initiative were approved for recovery through NJNG’s base rates effective October 2016.

In June 2016, NJNG’s liquefaction project became operational, allowing NJNG to convert natural gas into LNG and to fill NJNG’s existing LNG storage tanks. Costs for this project along with other plant upgrades were approximately $36.5 million. Costs associated with this initiative were approved for recovery through NJNG’s base rates effective October 2016.

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DERIVATIVE INSTRUMENTS

12 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

4. DERIVATIVE INSTRUMENTS

The Company is subject to commodity price risk due to fluctuations in the market price of natural gas, SRECs and electricity. To manage this risk, the Company enters into a variety of derivative instruments including, but not limited to, futures contracts, physical forward contracts, financial options and swaps to economically hedge the commodity price risk associated with its existing and anticipated commitments to purchase and sell natural gas, SRECs and electricity. In addition, the Company may utilize foreign currency derivatives to hedge Canadian dollar denominated gas purchases and/or sales. Therefore, the Company’s primary underlying risks include commodity prices, interest rates and foreign currency. These contracts, with a few exceptions as described below, are accounted for as derivatives. Accordingly, all of the financial and certain of the Company’s physical derivative instruments are recorded at fair value on the Consolidated Balance Sheets. For a more detailed discussion of the Company’s fair value measurement policies and level disclosures associated with the Company’s derivative instruments, see Note 5. Fair Value.

Energy Services

Energy Services chooses not to designate its financial commodity and physical forward commodity derivatives as accounting hedges or to elect NPNS. The changes in the fair value of these derivatives are recorded as a component of gas purchases or operating revenues, as appropriate for Energy Services, on the Consolidated Statements of Operations as unrealized gains or losses. For Energy Services at settlement, realized gains and losses on all financial derivative instruments are recognized as a component of gas purchases and realized gains and losses on all physical derivatives follow the presentation of the related unrealized gains and losses as a component of either gas purchases or operating revenues.

Energy Services also enters into natural gas transactions in Canada and, consequently, is exposed to fluctuations in the value of Canadian currency relative to the U.S. dollar. Energy Services may utilize foreign currency derivatives to lock in the exchange rate associated with natural gas transactions denominated in Canadian currency. The derivatives may include currency forwards, futures or swaps and are accounted for as derivatives. These derivatives are typically used to hedge demand fee payments on pipeline capacity, storage and gas purchase agreements.

As a result of Energy Services entering into transactions to borrow natural gas, commonly referred to as “park and loans,” an embedded derivative is recognized relating to differences between the fair value of the amount borrowed and the fair value of the amount that will ultimately be repaid, based on changes in the forward price for natural gas prices at the borrowed location over the contract term. This embedded derivative is accounted for as a forward sale in the month in which the repayment of the borrowed gas is expected to occur, and is considered a derivative transaction that is recorded at fair value on the Consolidated Balance Sheets, with changes in value recognized in current-period earnings.

Expected production of SRECs is hedged through the use of forward and futures contracts. All contracts require the Company to physically deliver SRECs through the transfer of certificates as per contractual settlement schedules. For transactions occurring on or before December 31, 2015, the Company elected NPNS accounting treatment on SREC forward and futures contracts. Effective January 1, 2016, on a prospective basis, Energy Services no longer elects NPNS accounting treatment on SREC contracts entered into from January 1, 2016, and recognizes changes in the fair value of these derivatives as a component of operating revenues. Upon settlement of the contract, the related revenue is recognized when the SREC is transferred to the counterparty. NPNS is a contract-by-contract election and, where it makes sense to do so, we can and may elect certain contracts to be normal.

Natural Gas Distribution

Changes in fair value of NJNG’s financial commodity derivatives are recorded as a component of regulatory assets or liabilities on the Consolidated Balance Sheets. The Company elects NPNS accounting treatment on all physical commodity contracts that NJNG entered into on or before December 31, 2015, and accounts for these contracts on an accrual basis. Accordingly, physical natural gas purchases are recognized in regulatory assets or liabilities on the Consolidated Balance Sheets when the contract settles and the natural gas is delivered. The average cost of natural gas is amortized in current-period earnings based on the current BPU BGSS factor and therm sales. Effective January 1, 2016, on a prospective basis, NJNG no longer elects NPNS accounting treatment on all of its physical commodity contracts entered into from January 1, 2016. However, since NPNS is a contract-by-contract election, where it makes sense to do so, NJNG can and may elect certain contracts to be normal. Because NJNG recovers these amounts through future BGSS rates as increases or decreases to the cost of natural gas in NJNG’s tariff for gas service, the changes in fair value of these contracts are deferred as a component of regulatory assets or liabilities on the Consolidated Balance Sheets.

Home Services and Other

On January 26, 2018, NJR entered into a variable-for-fixed interest rate swap on its existing $100 million variable rate term loan, which fixed the variable rate at 2.84 percent. The swap will terminate on August 16, 2019, which coincides with the maturity of the debt. The change in the fair value of the interest rate swap is recorded as interest expense on the Consolidated Statements of Operations.

Fair Value of Derivatives

The following table reflects the fair value of the Company’s derivative assets and liabilities recognized on the Consolidated Balance Sheets as of September 30:

			Fair Value
			2018						2017
(Thousands)	Balance Sheet Location	Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments:
Natural Gas Distribution:
Physical commodity contracts	Derivatives - current		$	85		$	192		$	151		$	72
Financial commodity contracts	Derivatives - current		94			—			—			1,149
Interest rate contracts (1)	Derivatives - current		—			—			—			8,467
Energy Services:
Physical commodity contracts	Derivatives - current		7,667			18,158			14,588			16,589
	Derivatives - noncurrent		3,930			11,316			7,127			8,710
Financial commodity contracts	Derivatives - current		19,169			28,176			15,302			20,267
	Derivatives - noncurrent		6,630			11,548			2,033			2,620
Foreign currency contracts	Derivatives - current		—			126			40			—
	Derivatives - noncurrent		—			118			4			—
Home Services and Other:
Interest rate contracts	Derivatives - current		381			—			—			—
Total fair value of derivatives			$	37,956		$	69,634		$	39,245		$	57,874

(1) Includes treasury lock which was settled in March 2018. See Note 8. Debt for more information.

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.

(Thousands)	Amounts Presented in Balance Sheets (1)			Offsetting Derivative Instruments (2)				Financial Collateral Received/Pledged (3)				Net Amounts (4)
As of September 30, 2018:
Derivative assets:
Energy Services
Physical commodity contracts		$	11,597		$	(3,944	)		$	(200	)		$	7,453
Financial commodity contracts		25,799			(18,775		)		—				7,024
Total Energy Services		$	37,396		$	(22,719	)		$	(200	)		$	14,477
Natural Gas Distribution
Physical commodity contracts		$	85		$	(3	)		$	—			$	82
Financial commodity contracts		94			—				(94		)		—
Total Natural Gas Distribution		$	179		$	(3	)		$	(94	)		$	82
Home Services and Other
Interest rate contracts		$	381		$	—			$	—			$	381
Total Home Services and Other		$	381		$	—			$	—			$	381
Derivative liabilities:
Energy Services
Physical commodity contracts		$	29,474		$	(3,944	)		$	—			$	25,530
Financial commodity contracts		39,724			(18,775		)		(20,949		)		—
Foreign currency contracts		244			—				—				244
Total Energy Services		$	69,442		$	(22,719	)		$	(20,949	)		$	25,774
Natural Gas Distribution
Physical commodity contracts		$	192		$	(3	)		$	—			$	189
Total Natural Gas Distribution		$	192		$	(3	)		$	—			$	189
As of September 30, 2017:
Derivative assets:
Energy Services
Physical commodity contracts		$	21,715		$	(2,173	)		$	(200	)		$	19,342
Financial commodity contracts		17,335			(14,121		)		—				3,214
Foreign currency contracts		44			—				—				44
Total Energy Services		$	39,094		$	(16,294	)		$	(200	)		$	22,600
Natural Gas Distribution
Physical commodity contracts		$	151		$	(20	)		$	—			$	131
Total Natural Gas Distribution		$	151		$	(20	)		$	—			$	131
Derivative liabilities:
Energy Services
Physical commodity contracts		$	25,299		$	(2,173	)		$	—			$	23,126
Financial commodity contracts		22,887			(14,121		)		(8,766		)		—
Total Energy Services		$	48,186		$	(16,294	)		$	(8,766	)		$	23,126
Natural Gas Distribution
Physical commodity contracts		$	72		$	(20	)		$	—			$	52
Financial commodity contracts		1,149			—				(1,149		)		—
Interest rate contracts		8,467			—				—				8,467
Total Natural Gas Distribution		$	9,688		$	(20	)		$	(1,149	)		$	8,519

(1) Derivative assets and liabilities are presented on a gross basis in the balance sheet as the Company does not elect balance sheet offsetting under ASC 210-20.

(2) Offsetting derivative instruments include transactions with NAESB netting election, transactions held by FCMs with net margining and transactions with ISDA netting.

(3) Financial collateral includes cash balances at FCMs, as well as cash received from or pledged to other counterparties.

(4) Net amounts represent presentation of derivative assets and liabilities if the Company were to elect balance sheet offsetting under ASC 210-20.

Energy Services utilizes financial derivatives to economically hedge the gross margin associated with the purchase of physical gas to be used for storage injection and its subsequent sale at a later date. The gains or (losses) on the financial transactions that are economic hedges of the cost of the purchased gas are recognized prior to the gains or (losses) on the physical transaction, which are recognized in earnings when the natural gas is delivered. Therefore, mismatches between the timing of the recognition of realized gains or (losses) on the financial derivative instruments and gains or (losses) associated with the actual sale of the natural gas that is being economically hedged, along with fair value changes in derivative instruments, create volatility in the results of Energy Services, although the Company’s intended economic results relating to the entire transaction are unaffected.

The following table reflects the effect of derivative instruments on the Consolidated Statements of Operations as of September 30:

(Thousands)	Location of gain (loss) recognized in income on derivatives	Amount of gain (loss) recognized in income on derivatives
Derivatives not designated as hedging instruments:		2018			2017			2016
Energy Services:
Physical commodity contracts	Operating revenues	$	(9,311	)	$	8,912		$	33,034
Physical commodity contracts	Gas purchases	(197		)	(27,461		)	(45,637		)
Financial commodity contracts	Gas purchases	(24,622		)	26,563			45,579
Foreign currency contracts	Gas purchases	(379		)	41			(34		)
Home Services and Other:
Interest rate contracts	Interest expense	334			—			—
Total unrealized and realized gains (losses)		$	(34,175	)	$	8,055		$	32,942

NJNG’s derivative contracts are part of the Company’s risk management activities that relate to its natural gas purchases, BGSS incentive programs and debt financing. These transactions are entered into pursuant to regulatory approval and, at settlement, the resulting gains and/or losses are payable to or recoverable from utility customers. Any changes in the value of NJNG’s financial derivatives are deferred in regulatory assets or liabilities resulting in no impact to earnings.

The following table reflects the (losses) gains associated with NJNG’s derivative instruments as of September 30:

(Thousands)	2018		2017			2016
Natural Gas Distribution:
Physical commodity contracts	$	1,232	$	(12,303	)	$	(15,756	)
Financial commodity contracts	1,844		5,595			(7,984		)
Interest rate contracts	8,467		14,606			(18,845		)
Total unrealized and realized (losses) gains	$	11,543	$	7,898		$	(42,585	)

NJNG and Energy Services had the following outstanding long (short) derivatives as of September 30:

		Volume (Bcf)
		2018		2017
Natural Gas Distribution	Futures	27.9		18.2
	Physical	23.1		32.1
Energy Services	Futures	(7.0	)	(16.4	)
	Physical	51.2		(13.1	)

Not included in the previous table are Energy Services’ gross notional amount of foreign currency transactions of approximately $8.5 million, interest rate contracts, as previously discussed, and 698,700 SRECs at Energy Services that are open as of September 30, 2018.

Broker Margin

Futures exchanges have contract-specific performance bond requirements, also known as margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin, which is posted upon the initiation of a position, maintenance margin, which is usually expressed as a percent of initial margin, and variation margin, which fluctuates based on the daily marked-to-market relative to maintenance margin requirements. The Company maintains separate broker margin accounts for the Natural Gas Distribution and Energy Services segments. The balances as of September 30, by segment, are as follows:

(Thousands)	Balance Sheet Location	2018		2017
Natural Gas Distribution	Broker margin - Current assets	$	2,038	$	2,661
Energy Services	Broker margin - Current assets	$	51,681	$	23,166

Due to CME rulebook changes that took effect in January 2017, variation margin is being treated as a settlement payment, rather than collateral. As a result, the Company is now required to present variation margin net with the related derivative assets and/or liabilities on the Consolidated Balance Sheets for any derivatives the Company clears through the CME.

Wholesale Credit Risk

NJNG, Energy Services and Clean Energy Ventures are exposed to credit risk as a result of their sales/wholesale and retail marketing activities. As a result of the inherent volatility in the prices of natural gas commodities, derivatives, SRECs, electricity and RECs, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If a counterparty fails to perform the obligations under its contract (e.g., fails to deliver or pay for natural gas, SRECs, electricity or RECs), the Company could sustain a loss.

The Company monitors and manages the credit risk of its wholesale operations through credit policies and procedures that management believes reduce overall credit risk. These policies include a review and evaluation of current and prospective counterparties’ financial statements and/or credit ratings, daily monitoring of counterparties’ credit limits and exposure, daily communication with traders regarding credit status and the use of credit mitigation measures, such as collateral requirements and netting agreements. Examples of collateral include letters of credit and cash received for either prepayment or margin deposit. Collateral may be requested due to the Company’s election not to extend credit or because exposure exceeds defined thresholds. Most of the Company’s wholesale marketing contracts contain standard netting provisions. These contracts include those governed by ISDA and the NAESB. The netting provisions refer to payment netting, whereby receivables and payables with the same counterparty are offset and the resulting net amount is paid to the party to which it is due.

Internally-rated exposure applies to counterparties that are not rated by S&P or Moody’s. In these cases, the counterparty’s or guarantor’s financial statements are reviewed, and similar methodologies and ratios used by S&P and/or Moody’s are applied to arrive at a substitute rating. Gross credit exposure is defined as the unrealized fair value of physical and financial derivative commodity contracts, plus any outstanding wholesale receivable for the value of natural gas delivered and/or financial derivative commodity contract that has settled for which payment has not yet been received.

The following is a summary of gross credit exposures grouped by investment and noninvestment grade counterparties, as of September 30, 2018.The amounts presented below have not been reduced by any collateral received or netting and exclude accounts receivable for NJNG retail natural gas sales and services and Clean Energy Ventures residential solar installations.

(Thousands)	Gross Credit Exposure
Investment grade		$	179,982
Noninvestment grade		43,486
Internally-rated investment grade		30,786
Internally-rated noninvestment grade		25,750
Total		$	280,004

Conversely, certain of NJNG’s and Energy Services’ derivative instruments are linked to agreements containing provisions that would require cash collateral payments from the Company if certain events occur. These provisions vary based upon the terms in individual counterparty agreements and can result in cash payments if NJNG’s credit rating were to fall below its current level. NJNG’s credit rating, with respect to S&P, reflects the overall corporate credit profile of the Company. Specifically, most, but not all, of these additional payments will be triggered if NJNG’s debt is downgraded by the major credit agencies, regardless of investment grade status. In addition, some of these agreements include threshold amounts that would result in additional collateral payments if the values of derivative liabilities were to exceed the maximum values provided for in relevant counterparty agreements. Other provisions include payment features that are not specifically linked to ratings, but are based on certain financial metrics.

Collateral amounts associated with any of these conditions are determined based on a sliding scale and are contingent upon the degree to which the Company’s credit rating and/or financial metrics deteriorate, and the extent to which liability amounts exceed applicable threshold limits. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on September 30, 2018 and 2017, is approximately $124,000 and $8.7 million, respectively, for which the Company had not posted collateral. If all thresholds related to the credit-risk-related contingent features underlying these agreements had been invoked on September 30, 2018 and 2017, the Company would have been required to post an additional $33,000 and $8.6 million, respectively, to its counterparties. These amounts differ from the respective net derivative liabilities reflected on the Consolidated Balance Sheets because the agreements also include clauses, commonly known as “Rights of Offset,” that would permit the Company to offset its derivative assets against its derivative liabilities for determining additional collateral to be posted, as previously discussed.

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FAIR VALUE

12 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

FAIR VALUE

5. FAIR VALUE

Fair Value of Assets and Liabilities

The fair value of cash and cash equivalents, accounts receivable, current loan receivables, accounts payable, commercial paper and borrowings under revolving credit facilities are estimated to equal their carrying amounts due to the short maturity of those instruments. Non-current loan receivables are recorded based on what the Company expects to receive, which approximates fair value. The Company regularly evaluates the credit quality and collection profile of its customers to approximate fair value.

As of September 30, the estimated fair value of long-term debt at NJNG and NJR, including current maturities, excluding capital leases, debt issuance costs and solar asset financing obligations, is as follows ⁽¹⁾:

(Thousands)	2018		2017
NJNG
Carrying value	$	672,045	$	672,045
Fair market value	$	669,162	$	673,051
NJR
Carrying value	$	500,000	$	425,000
Fair market value	$	488,889	$	434,625

(1) SeeNote 8. Debt for a reconciliation to long-term and short-term debt.

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, 2018 and 2017, the Company disclosed its debt within Level 2 of the fair value hierarchy.

Fair Value Hierarchy

The Company applies fair value measurement guidance to its financial assets and liabilities, as appropriate, which include financial derivatives and physical commodity contracts qualifying as derivatives, available for sale securities and other financial assets and liabilities. In addition, authoritative accounting literature prescribes the use of a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value based on the source of the data used to develop the price inputs.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to inputs that are based on unobservable market data and includes the following:

Level 1 Unadjusted quoted prices for identical assets or liabilities in active markets. The Company’s Level 1 assets and liabilities include exchange traded natural gas futures and options contracts, listed equities and money market funds. Exchange traded futures and options contracts include all energy contracts traded on the NYMEX, CME and ICE that the Company refers internally to as basis swaps, fixed swaps, futures and financial options that are cleared through a FCM.

Level 2 Other significant observable inputs, such as interest rates or price data, including both commodity and basis pricing that is observed either directly or indirectly from publications or pricing services. The Company’s Level 2 assets and liabilities include over-the-counter physical forward commodity contracts and swap contracts, SREC forward sales or derivatives that are initially valued using observable quotes and are subsequently adjusted to include time value, credit risk or estimated transport pricing components for which no basis price is available. Level 2 financial derivatives consist of transactions with non-FCM counterparties (basis swaps, fixed swaps and/or options). Inputs are verifiable and do not require significant management judgment. For some physical commodity contracts, the Company utilizes transportation tariff rates that are publicly available and that it considers to be observable inputs that are equivalent to market data received from an independent source. There are no significant judgments or adjustments applied to the transportation tariff inputs and no market perspective is required. Even if the transportation tariff input were considered to be a “model,” it would still be considered to be a Level 2 input as the data is:

• widely accepted and public;

• non-proprietary and sourced from an independent third party; and

• observable and published.

These additional adjustments are generally not considered to be significant to the ultimate recognized values.

Level 3 Inputs derived from a significant amount of unobservable market data. These include the Company’s best estimate of fair value and are derived primarily through the use of internal valuation methodologies.

Financial derivative portfolios of NJNG and Energy Services consist mainly of futures, options and swaps. The Company primarily uses the market approach and its policy is to use actively quoted market prices when available. The principal market for its derivative transactions is the natural gas wholesale market; therefore, the primary sources for its price inputs are CME, NYMEX and ICE. Energy Services uses Platts and Natural Gas Exchange for Canadian delivery points. However, Energy Services also engages in transactions that result in transporting natural gas to delivery points for which there is no actively quoted market price. In most instances, the transportation cost to the final delivery location is not significant to the overall valuation. If required, Energy Services’ policy is to use the best information available to determine fair value based on internal pricing models, which would include estimates extrapolated from broker quotes or other pricing services.

The Company also has available for sale securities and other financial assets that include listed equities, mutual funds and money market funds for which there are active exchange quotes available.

When the Company determines fair values, measurements are adjusted, as needed, for credit risk associated with its counterparties, as well as its own credit risk. The Company determines these adjustments by using historical default probabilities that correspond to the applicable S&P issuer ratings, while also taking into consideration collateral and netting arrangements that serve to mitigate risk.

Assets and liabilities measured at fair value on a recurring basis are summarized as follows:

	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
(Thousands)	(Level 1)			(Level 2)			(Level 3)			Total
As of September 30, 2018:
Assets
Physical commodity contracts		$	—		$	11,682		$	—	$	11,682
Financial commodity contracts		18,868			7,025			—		25,893
Financial commodity contracts - foreign exchange		—			—			—		—
Interest rate contract		—			381			—		381
Available for sale equity securities		32,917			—			—		32,917
Other (1)		1,217			—			—		1,217
Total assets at fair value		$	53,002		$	19,088		$	—	$	72,090
Liabilities
Physical commodity contracts		$	—		$	29,666		$	—	$	29,666
Financial commodity contracts		39,724			—			—		39,724
Financial commodity contracts - foreign exchange		—			244			—		244
Total liabilities at fair value		$	39,724		$	29,910		$	—	$	69,634
As of September 30, 2017:
Assets
Physical commodity contracts		$	—		$	21,866		$	—	$	21,866
Financial commodity contracts		17,335								17,335
Financial commodity contracts - foreign exchange		—			44			—		44
Available for sale equity securities		65,752			—			—		65,752
Other (1)		1,202			—			—		1,202
Total assets at fair value		$	84,289		$	21,910		$	—	$	106,199
Liabilities
Physical commodity contracts		$	—		$	25,371		$	—	$	25,371
Financial commodity contracts		24,036			—			—		24,036
Interest rate contract		—			8,467			—		8,467
Total liabilities at fair value		$	24,036		$	33,838		$	—	$	57,874

(1) Includes money market funds.

During the second quarter of fiscal 2018, the Company evaluated the decrease in fair value of its available for sale securities on a nonrecurring basis and determined that the decline was other-than-temporary. Accordingly, the Company recognized an other-than-temporary impairment of $17.8 million, which was determined using quoted market prices for identical publicly traded equity securities on an active exchange. As of March 31, 2018, the Company’s available for sale securities had a fair value of $28.2 million.See the Company’s discussion of available for sale securities in Note 2. Summary of Significant Accounting Policies for more information regarding the impairment.

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INVESTMENTS IN EQUITY INVESTEES

12 Months Ended

Sep. 30, 2018

Equity Method Investments and Joint Ventures [Abstract]

INVESTMENTS IN EQUITY INVESTEES

6. INVESTMENTS IN EQUITY INVESTEES

As of September 30, the Company’s investments in equity method investees includes the following:

(Thousands)	2018		2017
Steckman Ridge (1)	$	117,001	$	120,262
PennEast	73,865		52,323
Total	$	190,866	$	172,585

(1)Includes loans with a total outstanding principal balance of $70.4 million for both fiscal 2018 and 2017, which accrue interest at a variable rate that resets quarterly and are due October 1, 2023.

The Company, through its subsidiary NJR Pipeline Company, is an investor in PennEast, which is expected to construct and operate a 120-mile pipeline that will extend from northeast Pennsylvania to western New Jersey. PennEast has advised that it currently expects the pipeline to be completed and operational in 2019; however, the project could be delayed beyond 2019 due to factors that are beyond PennEast’s ability to control or estimate precisely, including potential delays in obtaining (or the inability to obtain) governmental and regulatory approvals and land-use rights, and unforeseen construction delays.

NJNG and Energy Services have entered into storage and park and loan agreements with Steckman Ridge. In addition, NJNG has entered into a precedent capacity agreement with PennEast. See Note 15. Related Party Transactions for more information on these intercompany transactions.

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EARNINGS PER SHARE

12 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

EARNINGS PER SHARE

7. 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)	2018		2017		2016
Net income, as reported	$	233,436	$	132,065	$	131,672
Basic earnings per share
Weighted average shares of common stock outstanding-basic	87,689		86,321		85,884
Basic earnings per common share	$2.66		$1.53		$1.53
Diluted earnings per share
Weighted average shares of common stock outstanding-basic	87,689		86,321		85,884
Incremental shares (1)	626		823		847
Weighted average shares of common stock outstanding-diluted	88,315		87,144		86,731
Diluted earnings per common share (2)	$2.64		$1.52		$1.52

(1) Incremental shares consist primarily of unvested stock awards and performance units.

(2) There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2018, 2017 and 2016.

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DEBT

12 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

DEBT

8. DEBT

NJNG and NJR finance working capital requirements and capital expenditures through the issuance of various long-term debt and other financing arrangements, including unsecured credit and private placement debt shelf facilities. Amounts available under credit facilities are reduced by bank or commercial paper borrowings, as applicable, and any outstanding letters of credit.

Long-term Debt

The following table presents the long-term debt of the Company as of September 30:

(Thousands)			2018			2017
NJNG
First mortgage bonds:		Maturity date:
5.60%	Series LL	May 15, 2018	$	—		$	125,000
Variable	Series MM	September 1, 2027	9,545			9,545
Variable	Series NN	August 1, 2035	41,000			41,000
Variable	Series OO	August 1, 2041	46,500			46,500
3.15%	Series PP	April 15, 2028	50,000			50,000
3.58%	Series QQ	March 13, 2024	70,000			70,000
4.61%	Series RR	March 13, 2044	55,000			55,000
2.82%	Series SS	April 15, 2025	50,000			50,000
3.66%	Series TT	April 15, 2045	100,000			100,000
3.63%	Series UU	June 21, 2046	125,000			125,000
4.01%	Series VV	May 11, 2048	125,000			—
Capital lease obligation-buildings		June 1, 2021	8,749			11,617
Capital lease obligation-meters		Various dates	27,188			28,042
Less: Debt issuance costs			(6,515		)	(6,262		)
Less: Current maturities of long-term debt			(9,502		)	(135,800		)
Total NJNG long-term debt			691,965			569,642
NJR
2.51%	Unsecured senior notes	September 15, 2018	—			25,000
3.25%	Unsecured senior notes	September 17, 2022	50,000			50,000
3.48%	Unsecured senior notes	November 7, 2024	100,000			100,000
3.20%	Unsecured senior notes	August 18, 2023	50,000			50,000
3.54%	Unsecured senior notes	August 18, 2026	100,000			100,000
3.96%	Unsecured senior notes	June 8, 2028	100,000			—
Variable	Term loan	August 16, 2019	100,000			100,000
Less: Debt issuance costs			(1,136		)	(770		)
Less: Current maturities of long-term debt			(100,000		)	(25,000		)
Total NJR long-term debt			398,864			399,230
Clean Energy Ventures
Solar asset financing obligation		Various dates	103,923			32,790
Less: Current maturities of long-term debt			(14,133		)	(4,582		)
Total Clean Energy Ventures long-term debt			89,790			28,208
Total long-term debt			$	1,180,619		$	997,080

Annual long-term debt redemption requirements, excluding capital leases, debt issuance costs and solar asset financing obligations, as of September 30, are as follows:

(Thousands)	NJNG		NJR
2019	$	—	$	100,000
2020	$	—	$	—
2021	$	—	$	—
2022	$	—	$	50,000
2023	$	—	$	50,000
Thereafter	$	672,045	$	300,000

NJNG

First Mortgage Bonds

NJNG and Trustee entered into the Mortgage Indenture, dated September 1, 2014, which secures all of the outstanding First Mortgage Bonds issued by NJNG. The Mortgage Indenture provides a direct first mortgage lien upon substantially all of the operating properties and franchises of NJNG (other than excepted property, such as cash on hand, choses-in-action, securities, rent, natural gas meters and certain materials, supplies, appliances and vehicles), subject only to certain permitted encumbrances. The Mortgage Indenture contains provisions subjecting after-acquired property (other than excepted property and subject to pre-existing liens, if any, at the time of acquisition) to the lien thereof.

NJNG’s Mortgage Indenture no longer contains a restriction on NJNG’s ability to pay dividends. New Jersey Administrative Code 14:4-4.7 states that a public utility cannot issue dividends, without regulatory approval, if its equity to total capitalization ratio falls below 30 percent. As of September 30, 2018, NJNG’s equity to total capitalization ratio is 56.7 percent and has the ability to issue up to $1 billion of FMB under the terms of the Mortgage Indenture.

NJNG has variable rate EDA Bonds with a total principal amount of $97 million and maturity dates ranging from September 2027 to August 2041. The EDA Bonds are not subject to optional tender while they bear interest at a LIBOR index rate. As of September 30, 2018, the interest rate on the EDA Bonds was 2.03 percent.

In June 2016, NJNG entered into a Note Purchase Agreement, under which NJNG issued $125 million of its 3.63 percent senior notes due June 2046. The notes are secured by an equal principal amount of NJNG’s FMB (series UU) issued under NJNG’s Mortgage Indenture. The proceeds of the notes will be used for general corporate purposes, including, but not limited to, refinancing or retiring short-term debt and funding capital expenditures.

On January 17, 2017, the Company completed the purchase of three FMBs in lieu of redemption with an aggregate principal amount totaling $35.8 million. The FMBs bore interest at rates ranging from 4.5 percent to 4.9 percent. The bonds purchased in lieu of redemption are being held by the Company to provide an opportunity to evaluate remarketing alternatives.

On May 11, 2018, NJNG entered into a Note Purchase Agreement, under which NJNG issued $125 million, 4.01 percent senior notes due May 11, 2048. The interest rate includes the quoted March 9, 2018, 30-year treasury rate, plus a market based credit spread. The notes are secured by an equal principal amount of NJNG's FMB (series VV) issued under NJNG's Mortgage Indenture.

In June 2015, NJNG entered into a treasury lock transaction to fix a benchmark treasury rate of 3.26 percent associated with a $125 million debt issuance that was finalized in May 2018. This debt issuance coincided with the maturity of the $125 million, 5.6 percent notes that came due May 15, 2018. This treasury lock was settled on March 13, 2018, which coincided with the pricing of the new debt being issued. Settlement of the treasury lock resulted in a $2.6 million loss, which is recorded as a component of regulatory assets on the Consolidated Balance Sheets and will be amortized in earnings over the term of the May 11, 2018 debt issuance, discussed above.

Sale-Leasebacks

NJNG has entered into a sale-leaseback for its headquarters building, which has a 25.5-year term that expires in June 2021, subject to an option by NJNG to renew the lease for additional five-year terms a maximum of four times. The present value of the agreement’s minimum lease payments is reflected as both a capital lease asset and a capital lease obligation, which are included in utility plant and long-term debt, respectively, on the Consolidated Balance Sheets.

NJNG received $7.8 million, $9.6 million and $7.1 million for fiscal 2018, 2017 and 2016, respectively, in connection with the sale-leaseback of its natural gas meters. NJNG records a capital lease obligation that is paid over the term of the lease and has the option to purchase the meters back at fair value upon expiration of the lease. During fiscal 2018, 2017 and 2016, NJNG exercised early purchase options with respect to meter leases by making final principal payments of $2.2 million, $2.4 million and $1.9 million, respectively. NJNG continues to evaluate this sale-leaseback program based on current market conditions.

Contractual commitments for capital lease payments, as of the fiscal years ended September 30, are as follows:

(Thousands)	Lease Payments
2019		$	10,932
2020		7,989
2021		9,236
2022		3,775
2023		2,393
Thereafter		5,245
Subtotal		39,570
Less: Interest component		(3,633		)
Total		$	35,937

NJR

In March 2016, NJR entered into a Note Purchase Agreement, under which the Company issued, in August 2016, $50 million of the Company’s 3.2 percent senior notes due August 2023, and $100 million of the Company’s 3.54 percent senior notes due August 2026. The notes are not secured by assets, but are instead guaranteed by certain unregulated subsidiaries of the Company. The proceeds of the notes will be used for general corporate purposes, including working capital and capital expenditures.

On January 26, 2018, NJR entered into a variable-for-fixed interest rate swap on its existing $100 million variable rate term loan due August 16, 2019, which fixed the variable rate at 2.84 percent. On July 17, 2018, the $100 million variable rate term loan was amended to permit the disposition of assets relating to sale leaseback or other similar tax equity financing arrangements of meter assets or of solar or wind facilities. These transactions are permissible so long as NJR is in compliance with certain covenants both before and after such incurrence, and if no event of default may be caused by such sale leaseback or similar arrangement. As of September 30, 2018, NJR’s variable rate term loan was classified within current maturities of long-term debt.

On June 8, 2018, NJR entered into a Note Purchase Agreement, under which the Company issued $100 million, 3.96 percent senior notes due June 8, 2028. The notes are not secured by assets, but are instead guaranteed by certain unregulated subsidiaries of NJR.

Clean Energy Ventures

Clean Energy Ventures received proceeds of $71.5 million and $32.9 million in connection with the sale-leasebacks of commercial solar projects for fiscal 2018 and 2017, respectively. Clean Energy Ventures enters into transactions to sell the commercial solar assets concurrent with agreements to lease the assets back over a period of six to 15 years. These sale-leasebacks are treated as financing obligations, which are typically secured by the renewable energy facility asset and its future cash flows from SREC and energy sales. ITCs and other tax benefits associated with these solar projects are transferred to the buyer. Clean Energy Ventures continues to operate the solar assets, including related expenses, and retain the revenue generated from SRECs and energy sales, and has the option to renew the lease or repurchase the assets sold at the end of the lease term.

Contractual commitments for solar sale-leaseback lease payments, as of the fiscal years ended September 30, are as follows:

(Thousands)	Lease Payments
2019		$	9,794
2020		7,830
2021		7,803
2022		7,802
2023		7,878
Thereafter		38,303
Subtotal		79,410
Less: Interest component		(26,728		)
Total		$	52,682

Short-term Debt

A summary of NJR’s and NJNG’s short-term bank facilities as of September 30, are as follows:

(Thousands)	2018			2017
NJR
Bank revolving credit facilities:(1)	$	425,000		$	425,000
Notes outstanding at end of period	$	87,950		$	255,000
Weighted average interest rate at end of period	3.07		%	2.14		%
Amount available at end of period (2)	$	322,144		$	156,601
NJNG
Bank revolving credit facilities: (3)	$	250,000		$	250,000
Commercial paper outstanding at end of period	$	64,000		$	11,000
Weighted average interest rate at end of period	2.18		%	1.13		%
Amount available at end of period (4)	$	185,269		$	238,269

(1) Committed credit facilities, which require commitment fees of .075 percent on the unused amounts.

(2) Letters of credit outstanding total $14.9 million and $13.4 million as of September 30, 2018 and 2017, respectively, which reduces amount available by the same amount.

(3) Committed credit facilities, which require commitment fees of .075 percent on the unused amounts.

(4) Letters of credit outstanding total $731,000 as of September 30, 2018 and 2017, which reduces amount available by the same amount.

NJR

NJR entered into a $425 million unsecured, committed credit facility scheduled to expire on September 28, 2020, subject to two mutual options for a one-year extension beyond that date. The NJR Credit Facility includes an accordion feature, which would allow NJR, in the absence of a default or event of default, to increase from time to time, with the existing or new lenders, the revolving credit commitments under the NJR Credit Facility in minimum $5 million increments up to a maximum of $100 million. The credit facility is used primarily to finance its share repurchases, to satisfy Energy Services’ short-term liquidity needs and to finance, on an initial basis, unregulated investments.

On June 25, 2018, the $425 million NJR Credit Facility was amended to permit liens and the disposition of assets relating to sale-leaseback or other similar tax equity financing arrangements of meter assets or of solar or wind facilities. These transactions are permissible so long as NJR is in compliance with certain covenants both before and after such incurrence, and if no event of default may be caused by such sale-leaseback or similar arrangement.

On December 14, 2017, NJR entered into a four-month, $75 million revolving line of credit facility.On January 19, 2018, NJR amended the agreement to increase the available amount to $100 million. This facility expired on April 14, 2018. No amounts were outstanding on the facility at the time of expiration.

As of September 30, 2018, NJR had six letters of credit outstanding totaling $14.9 million. Three letters of credit totaling $11.9 million are issued on behalf of Energy Services and three letters of credit, which total $3 million, are issued on behalf of Clean Energy Ventures. These letters of credit reduce the amount available under NJR’s committed credit facility by the same amount. NJR does not anticipate that these letters of credit will be drawn upon by the counterparties, and they will be renewed as necessary.

Energy Services’ letters of credit are used for margin requirements for natural gas transactions, collateral and security deposit for retail gas sales and expire on dates ranging from December 2018 to September 2019. Clean Energy Ventures’ letters of credit are used to secure construction of ground-mounted solar projects and to secure obligations pursuant to an Interconnection Services Agreement. They expire on dates ranging from May 2019 to August 2019.

Neither NJNG nor the results of its operations are obligated or pledged to support the NJR credit or debt shelf facilities.

NJNG

NJNG has a $250 million, five-year, revolving, unsecured credit facility, which expires in May 2019. The NJNG Credit Facility permits the borrowing of revolving loans and swing loans, as well as the issuance of letters of credit. It also permits an increase to the facility, from time to time, with the existing or new lenders, in a minimum of $15 million increments up to a maximum of $50 million at the lending banks’ discretion.

As of September 30, 2018, NJNG has two letters of credit outstanding for $731,000. NJNG’s letters of credit are used as collateral for remediation projects and expire in August 2019. These letters of credit reduce the amount available under NJNG’s committed credit facility by the same amount. NJNG does not anticipate that these letters of credit will be drawn upon by the counterparty and will be renewed as necessary.

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STOCK-BASED COMPENSATION

12 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

STOCK-BASED COMPENSATION

9. STOCK-BASED COMPENSATION

Effective January 25, 2017, the shareholders of the Company approved the NJR 2017 Stock Award and Incentive Plan, which replaced the NJR 2007 Stock Award and Incentive Plan. The 2007 plan had 914,169 shares granted but not issued as of September 30, 2017, which were transferred into the 2017 plan. The 2017 plan added an additional 3,135,000 shares available for issuance. Shares have been issued in the form of performance shares, restricted stock, deferred retention stock and unrestricted common stock to non-employee directors. As of September 30, 2018, 3,473,062 shares remain available for future issuance.

The following table summarizes all stock-based compensation expense recognized during the following fiscal years:

(Thousands)	2018			2017			2016
Stock-based compensation expense:
Performance share awards	$	3,526		$	2,614		$	3,188
Restricted and non-restricted stock	2,191			1,732			2,161
Deferred retention stock	7,128			1,461			1,885
Compensation expense included in operation and maintenance expense	12,845			5,807			7,234
Income tax benefit (1)	(3,734		)	(2,372		)	(2,955		)
Total, net of tax	$	9,111		$	3,435		$	4,279

(1) Excludes additional tax benefit related to delivered shares of $3 million, $1.3 million and $1.8 million as of September 30, 2018, 2017 and 2016, respectively.

Performance Shares

In fiscal 2018, the Company granted to various officers 31,836 performance shares, which are market condition awards that vest on September 30, 2020, subject to the Company meeting certain performance conditions. In fiscal 2018, the Company also granted to various officers 59,341 performance shares, of which 29,608 vest on September 30, 2020 and 29,733 vest annually over a three-year period beginning on September 30, 2018, both of which are subject to the Company meeting certain performance conditions.

In fiscal 2017, the Company granted to various officers 44,576 performance shares, which are market condition awards that vest on September 30, 2019, subject to the Company meeting certain performance conditions. In fiscal 2017, the Company also granted to various officers 51,931 performance shares, of which 25,806 vest on September 30, 2019 and 26,125 vest annually over a three-year period beginning in September 30, 2017, both of which are subject to the Company meeting certain performance conditions.

In fiscal 2016, the Company granted to various officers 46,175 performance shares, which are market condition awards that vested on September 30, 2018, subject to the Company meeting certain performance conditions. In fiscal 2016, the Company also granted to various officers 69,305 performance shares, of which 38,789 vested in September 30, 2018 and 30,516 vest annually over a three-year period beginning in September 2016, 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 $3.8 million of deferred compensation related to unvested performance shares that is expected to be recognized over the weighted average period of 1.7 years.

The following table summarizes the performance share activity under the stock award and incentive plans for the past three fiscal years:

	Shares (1)		Weighted Average Grant Date Fair Value		Total Fair Value of Vested Shares (in Thousands)
Non-vested and outstanding at September 30, 2015	214,464			$23.40		—
Granted	115,480			$27.37		—
Vested (2)	(137,053	)		$21.40		$	5,657
Cancelled/forfeited (3)	(12,975	)		$23.40		—
Non-vested and outstanding at September 30, 2016	179,916			$27.47		—
Granted	96,507			$33.57		—
Vested (4)	(95,407	)		$28.88		$	4,179
Cancelled/forfeited	(24,429	)		$29.14		—
Non-vested and outstanding at September 30, 2017	156,587			$30.12		—
Granted	91,177			$44.67		—
Vested (5)	(100,146	)		$29.49		$	4,714
Cancelled/forfeited	(2,442	)		$31.45		—
Non-vested and outstanding at September 30, 2018	145,176			$39.67		—

(1) The number of common shares issued related to certain performance shares may range from zero to 150 percent of the number of shares shown in the table above based on the Company’s achievement of performance goals.

(2) As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, the number of common shares related to performance shares earned was 85 percent, or 55,702 shares, the number of common shares earned related to NFE performance was 150 percent or 71,808 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 23,649 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

(3) As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, 9,366 shares were canceled due to not achieving a certain performance target. The remainder were forfeitures due to individuals departing the Company.

(4) As certified by the Company’s Leadership and Compensation Committee on November 14, 2017, the number of common shares earned related to TSR performance was 108.44 percent or 39,595 shares, the number of common shares earned related to NFE performance was 119 percent or 36,498 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 28,223 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

(5) As certified by the Company’s Leadership and Compensation Committee on November 13, 2018, the number of common shares earned related to TSR performance was 99 percent or 38,660 shares, the number of common shares earned related to NFE performance was 121 percent or 39,694 shares and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 36,998 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

The Company measures compensation expense related to performance shares based on the fair value of these awards at their date of grant. In accordance with ASC 718, Compensation - Stock Compensation, compensation expense for market condition grants are recognized for awards granted, and are not adjusted based on actual achievement of the performance goals. The Company estimated the fair value of these grants on the date of grant using a lattice model. Performance condition grants are initially fair valued at the Company’s stock price on grant date, and are subsequently adjusted for actual achievement of the performance goals.

Restricted Stock

In fiscal 2018, the Company granted 27,949 shares of restricted stock that vest annually over a three-year period beginning October 15, 2018. In fiscal 2017, the Company granted 22,591 shares of restricted stock that vest annually over a three-year period beginning in October 2017. In fiscal 2017, the Company also granted 6,143 shares of restricted stock that vest annually over a three-year period beginning May 8, 2018. In fiscal 2016, the Company granted 41,909 shares of restricted stock that vest annually over a three-year period beginning in October 2016. There is approximately $612,964 of deferred compensation related to unvested restricted stock shares that is expected to be recognized over the weighted average period of two years.

The following table summarizes the restricted stock activity under the stock award and incentive plans for the past three fiscal years:

	Shares		Weighted Average Grant Date Fair Value		Total Fair Value of Vested Shares (in Thousands)
Non-vested and outstanding at September 30, 2015	81,492			$27.17		—
Granted	41,909			$30.03		—
Vested	(48,089	)		$26.66		$	1,469
Cancelled/forfeited	(2,241	)		$29.21		—
Non-vested and outstanding at September 30, 2016	73,071			$29.09		—
Granted	28,734			$35.79		—
Vested	(38,752	)		$28.92		$	1,344
Cancelled/forfeited	(11,899	)		$31.56		—
Non-vested and outstanding at September 30, 2017	51,154			$32.40		—
Granted	27,949			$45.00
Vested	(33,815	)		$31.23		$	1,438
Cancelled/forfeited	(1,120	)		$33.54
Non-vested and outstanding at September 30, 2018	44,168			$41.24		—

Deferred Retention Stock

Deferred retention stock awards vest immediately when granted, with shares delivered at a future date in accordance with the terms of the underlying agreements. The expense for these awards is recognized in the fiscal year in which services are rendered. The related shares are granted upon approval by the Board of Directors, which generally occurs subsequent to the fiscal year end.

The following table summarizes the deferred retention stock award under the stock award and incentive plans for the past three fiscal years:

	Shares		Weighted Average Grant Date Fair Value		Total Fair Value of Vested Shares (in Thousands)
Outstanding at September 30, 2015	632,730			$27.03		—
Granted/Vested	159,831			$30.37		—
Delivered	(121,764	)		$20.31		$	3,751
Forfeited	(8,318	)		$28.14		—
Outstanding at September 30, 2016	662,479			$29.06		—
Granted/Vested	63,977			$35.64		—
Delivered	(53,878	)		$23.11		$	1,774
Outstanding at September 30, 2017	672,578			$29.54		—
Granted/Vested	24,167			$45.00
Delivered	(452,694	)		$29.42		$	19,581
Forfeited	(1,969	)		$35.56
Outstanding at September 30, 2018	242,082			$32.99		—

Non-Employee Director Stock

Non-employee director compensation includes an annual January retainer that is awarded in stock. The shares vest immediately and are subsequently amortized to expense over a 12-month period. The following summarizes non-employee director share awards for the past three fiscal years:

	2018		2017	2016
Shares granted	26,524	(1)	27,972	27,481
Weighted average grant date fair value	$39.85		$35.59	$32.75

(1) $264,000 of expense remains as of September 30, 2018, to be recognized through December 31, 2018.

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EMPLOYEE BENEFIT PLANS

12 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

EMPLOYEE BENEFIT PLANS

10. EMPLOYEE BENEFIT PLANS

Pension and Other Postemployment Benefit Plans

The Company has two trusteed, noncontributory defined benefit retirement plans covering eligible regular represented and nonrepresented employees with more than one year of service. Defined benefit plan benefits are based on years of service and average compensation during the highest 60 consecutive months of employment. The Company also provides postemployment medical and life insurance benefits to employees who meet certain eligibility requirements.

All represented employees of NJRHS hired on or after October 1, 2000, non-represented employees hired on or after October 1, 2009 and NJNG represented employees hired on or after January 1, 2012, are covered by an enhanced defined contribution plan instead of the defined benefit plan. Participation in the postemployment medical and life insurance plan was also frozen to new employees as of the same dates, with the exception of new NJRHS represented employees, for which benefits were frozen beginning April 3, 2012.

The Company maintains an unfunded nonqualified PEP that was established to provide employees with the full level of benefits as stated in the qualified plan without reductions due to various limitations imposed by the provisions of federal income tax laws and regulations. There were no plan assets in the nonqualified plan due to the nature of the plan.

In April 2018, the Company implemented a voluntary early retirement program open to certain eligible employees. As of September 30, 2018, pension and postemployment benefit costs related to the special termination benefits were $4.2 million and other severance benefits were $2.2 million. For the amounts incurred, NJNG recognized an expense of approximately $5.1 million and Home Services and other recognized an expense of approximately $1.3 million, as a component of O&M in the Consolidated Statements of Operations.

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 2018 and 2017, the Company had no minimum funding requirements. The Company made no discretionary contributions to the pension plans in fiscal 2018 or 2017. The Company does not expect to be required to make additional contributions to fund the pension plans over the following two fiscal years based on current actuarial assumptions; however, funding requirements are uncertain and can depend significantly on changes in actuarial assumptions, returns on plan assets and changes in the demographics of eligible employees and covered dependents.

There are no federal requirements to pre-fund OPEB benefits. However, the Company is required to fund certain amounts due to regulatory agreements with the BPU. The Company contributed $6.2 million and $6 million, in fiscal 2018 and 2017, respectively, and estimates that it will contribute between $5 million to $8 million over each of the next five years. Additional contributions may be required based on market conditions and changes to assumptions.

The following summarizes the changes in the funded status of the plans and the related liabilities recognized on the Consolidated Balance Sheets as of September 30:

	Pension (1)						OPEB
(Thousands)	2018			2017			2018			2017
Change in Benefit Obligation
Benefit obligation at beginning of year	$	297,835		$	293,654		$	175,090		$	160,393
Service cost	8,139			8,347			4,607			4,380
Interest cost	10,493			9,771			6,365			5,545
Plan participants’ contributions (2)	45			45			161			120
Special termination benefits (3)	3,730			—			490			—
Actuarial (gain) loss	(12,846		)	(5,995		)	15,145			8,985
Benefits paid, net of retiree subsidies received	(8,821		)	(7,987		)	(5,073		)	(4,333		)
Benefit obligation at end of year	$	298,575		$	297,835		$	196,785		$	175,090
Change in plan assets
Fair value of plan assets at beginning of year	$	271,743		$	249,875		$	71,534		$	62,035
Actual return on plan assets	16,306			29,736			5,284			7,953
Employer contributions	137			74			6,222			6,049
Benefits paid, net of plan participants’ contributions (2)	(8,776		)	(7,942		)	(5,060		)	(4,503		)
Fair value of plan assets at end of year	$	279,410		$	271,743		$	77,980		$	71,534
Funded status	$	(19,165	)	$	(26,092	)	$	(118,805	)	$	(103,556	)
Amounts recognized on Consolidated Balance Sheets
Postemployment employee (liability)
Current	$	(294	)	$	(158	)	$	(669	)	$	(602	)
Noncurrent	(18,871		)	(25,934		)	(118,136		)	(102,954		)
Total	$	(19,165	)	$	(26,092	)	$	(118,805	)	$	(103,556	)

(1) Includes the Company’s PEP.

(2) Prior to July 1, 1998, employees were eligible to elect an additional participant contribution to enhance their benefits and contributions made during the periods were insignificant.

(3) Related to the voluntary early retirement program offered during fiscal 2018, as previously discussed.

The actuarial gain on the Company’s pension plans is primarily due to an increase in the discount rate used to measure the obligation. The actuarial loss related to the OPEB plans is primarily due to an increase in expected retiree healthcare claims, partially offset by an increase in the discount rate. 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 other comprehensive income for the portion of the liability related to its unregulated operations.

The following table summarizes the amounts recognized in regulatory assets and accumulated other comprehensive income as of September 30:

	Regulatory Assets						Accumulated Other Comprehensive Income (Loss)
	Pension			OPEB			Pension			OPEB
Balance at September 30, 2016	$	94,941		$	59,147		$	28,436		$	4,486
Amounts arising during the period:
Net actuarial (gain) loss	(9,429		)	5,211			(6,990		)	587
Amounts amortized to net periodic costs:
Net actuarial (loss)	(6,799		)	(4,209		)	(2,028		)	(160		)
Prior service (cost) credit	(108		)	311			(3		)	54
Balance at September 30, 2017	$	78,605		$	60,460		$	19,415		$	4,967
Amounts arising during the period:
Net actuarial (gain) loss	(6,090		)	12,378			(3,422		)	2,834
Amounts amortized to net periodic costs:
Net actuarial (loss)	(6,177		)	(4,464		)	(1,359		)	(196		)
Prior service (cost) credit	(105		)	311			(1		)	54
Balance at September 30, 2018	$	66,233		$	68,685		$	14,633		$	7,659

The amounts in regulatory assets and accumulated other comprehensive income not yet recognized as components of net periodic benefit cost as of September 30 are:

	Regulatory Assets										Accumulated Other Comprehensive Income (Loss)
	Pension				OPEB						Pension				OPEB
(Thousands)	2018		2017		2018			2017			2018		2017		2018			2017
Net actuarial loss	$	65,664	$	77,930	$	69,477		$	61,563		$	14,633	$	19,414	$	7,750		$	5,113
Prior service cost (credit)	569		675		(792		)	(1,103		)	—		1		(91		)	(146		)
Total	$	66,233	$	78,605	$	68,685		$	60,460		$	14,633	$	19,415	$	7,659		$	4,967

To the extent the unrecognized amounts in accumulated other comprehensive income or regulatory assets exceed 10 percent of the greater of the benefit obligation or the fair value of plan assets, an amortized amount over the average expected future working lifetime of the active plan participants is recognized. Amounts included in regulatory assets and accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost in fiscal 2019 are as follows:

	Regulatory Assets					Accumulated Other Comprehensive Income (Loss)
(Thousands)	Pension		OPEB			Pension		OPEB
Net actuarial loss	$	4,662	$	5,527		$	1,103	$	643
Prior service cost (credit)	102		(312		)	—		(53		)
Total	$	4,764	$	5,215		$	1,103	$	590

The accumulated benefit obligation for the pension plans, including the PEP, exceeded the fair value of plan assets. The projected benefit and accumulated benefit obligations and the fair value of plan assets as of September 30, are as follows:

	Pension
(Thousands)	2018		2017
Projected benefit obligation	$	298,575	$	297,835
Accumulated benefit obligation	$	263,279	$	258,514
Fair value of plan assets	$	279,410	$	271,743

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)	2018			2017			2016			2018			2017			2016
Service cost	$	8,139		$	8,347		$	7,591		$	4,607		$	4,380		$	4,521
Interest cost	10,493			9,771			11,342			6,365			5,545			6,256
Expected return on plan assets	(19,639		)	(19,313		)	(20,118		)	(5,352		)	(4,767		)	(4,845		)
Recognized actuarial loss	7,537			8,827			7,281			4,660			4,370			3,274
Prior service cost (credit) amortization	106			111			111			(365		)	(365		)	(365		)
Net periodic benefit cost	$	6,636		$	7,743		$	6,207		$	9,915		$	9,163		$	8,841
Special termination benefit	3,730			—			—			490			—			—
Net periodic benefit cost recognized as expense	$	10,366		$	7,743		$	6,207		$	10,405		$	9,163		$	8,841

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
	2018			2017			2016			2018			2017			2016
Benefit costs:
Discount rate	4.04/4.03%			3.96/3.94%			4.50	%		4.12/4.08%		(1)	4.08/4.01%		(1)	4.60/4.55%
Expected asset return	7.50	%		7.75	%		8.75	%		7.50	%		7.75	%		8.75	%
Compensation increase	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%			3.25/3.50%		(1)	3.25/3.50%			3.50	%
Obligations:
Discount rate	4.36/4.35%			4.03	%	(1)	3.96/3.94%			4.38/4.37%		(1)	4.12/4.08%		(1)	4.08/4.01%		(1)
Compensation increase	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%			3.50	%

(1) Percentages for represented and nonrepresented plans, respectively.

When measuring its projected benefit obligations, the Company uses an aggregate discount rate at which its obligation could be effectively settled. The Company determines a single weighted average discount rate based on a yield curve comprised of rates of return on a population of high quality debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of its expected future benefit payments. Prior to October 1, 2016, the Company used the same assumed rate to measure the service and interest cost components of its net periodic benefit costs. Effective October 1, 2016, the Company changed its method of measuring its service and interest costs from the aggregate approach to a disaggregated, or spot rate, approach. Under the new approach, the Company applies the duration-specific spot rates from the full yield curve, as of the measurement date, to each year’s future benefit payments. The Company believes that this provides for a more precise measurement of its service and interest costs by aligning the timing of the plans’ separate future cash flows to the corresponding spot rates on the yield curve.

Information relating to the assumed HCCTR used to determine expected OPEB benefits as of September 30, and the effect of a 1 percent change in the rate, are as follows:

($ in thousands)	2018			2017			2016
HCCTR	7.9		%	8.3		%	8.5		%
Ultimate HCCTR	4.5		%	4.5		%	4.5		%
Year ultimate HCCTR reached	2024			2025			2025
Effect of a 1 percentage point increase in the HCCTR on:
Year-end benefit obligation	$	36,260		$	32,019		$	28,803
Total service and interest cost	$	2,482		$	2,468		$	2,331
Effect of a 1 percentage point decrease in the HCCTR on:
Year-end benefit obligation	$	(28,743	)	$	(25,466	)	$	(22,862	)
Total service and interest costs	$	(1,937	)	$	(1,909	)	$	(1,801	)

The Company’s investment objective is a long-term real rate of return on assets before permissible expenses that is approximately 5 percent greater than the assumed rate of inflation, as measured by the consumer price index. The expected long-term rate of return is based on the asset categories in which the Company invests and the current expectations and historical performance for these categories.

The mix and targeted allocation of the pension and OPEB plans’ assets are as follows:

	2019		Assets at
	Target		September 30,
Asset Allocation	Allocation		2018		2017
U.S. equity securities	34	%	41	%	39	%
International equity securities	17		19		21
Fixed income	41		37		40
Other assets	8		3		—
Total	100	%	100	%	100	%

The Company adopted the revised mortality assumptions published by the Society of Actuaries for its pension and other postemployment benefit obligations, which reflected increased life expectancies in the United States. The adoption of the new mortality projection scale, MP-2017, 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)	Pension		OPEB
2019	$	10,320	$	5,450
2020	$	11,769	$	6,512
2021	$	12,399	$	7,096
2022	$	13,239	$	7,810
2023	$	14,217	$	8,413
2024 - 2028	$	85,426	$	50,869

The Company’s OPEB plans provide prescription drug benefits that are actuarially equivalent to those provided by Medicare Part D. Therefore, under the Medicare Prescription Drug, Improvement and Modernization Act of 2003, the Company qualifies for federal subsidies.

The following estimated subsidy payments are expected to be paid during the following fiscal years:

	Estimated Subsidy
(Thousands)	Payment
2019		$	280
2020		$	316
2021		$	347
2022		$	375
2023		$	417
2024 - 2028		$	2,787

Pension and OPEB assets held in the master trust, measured at fair value, as of September 30, are summarized as follows:

	Quoted Prices in Active Markets for Identical Assets (Level 1)
(Thousands)	Pension				OPEB
Assets	2018		2017		2018		2017
Money market funds	$	8,207	$	—	$	2,273	$	11
Registered Investment Companies:
Equity Funds:
Large Cap Index	97,016		88,321		27,340		23,986
Extended Market Index	17,741		16,329		5,014		4,409
International Stock	53,516		56,446		14,874		15,000
Fixed Income Funds:
Emerging Markets	11,754		13,516		3,264		3,551
Core Fixed Income	—		—		7,970		8,082
Opportunistic Income	—		—		4,798		4,744
Ultra Short Duration	—		—		4,830		4,673
High Yield Bond Fund	25,720		26,540		7,236		7,078
Long Duration Fund	64,039		70,591		—		—
Total assets	$	277,993	$	271,743	$	77,599	$	71,534

The Plan had no Level 2 or Level 3 fair value measurements during fiscal 2018 and 2017, and there have been no changes in valuation methodologies as of September 30, 2018. The Plan held $1.8 million of other assets as of September 30, 2018, that are valued using net asset value 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:

Money Market funds — Represents bank balances and money market funds that are valued based on the net asset value of shares held at year end.

Registered Investment Companies — Equity and fixed income funds valued at the net asset value of shares held by the plan at year end as reported on the active market on which the individual securities are traded.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Plan believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

Defined Contribution Plan

The Company offers a Savings Plan to eligible employees. As of January 1, 2015, the Company matches 65 percent of participants’ contributions up to 6 percent of base compensation. Represented NJRHS employees, non-represented employees hired on or after October 1, 2009, and NJNG represented employees hired on or after January 1, 2012, are eligible for an employer special contribution of between 3 and 4 percent of base compensation, depending on years of service, into the Savings Plan on their behalf. The amount expensed and contributed for the matching provision of the Savings Plan was $3.9 million in fiscal 2018, $2.9 million in fiscal 2017 and $2.8 million in fiscal 2016. The amount contributed for the employer special contribution of the Savings Plan was $959,000 in fiscal 2018, $781,000 in fiscal 2017 and $571,000 in fiscal 2016.

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Sep. 30, 2018

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

11. ASSET RETIREMENT OBLIGATIONS

The Company recognizes AROs when the legal obligation to retire an asset has been incurred and a reasonable estimate of fair value can be made. Accordingly, the Company recognizes AROs related to the costs associated with cutting and capping its main and service gas distribution pipelines of NJNG, which is required by New Jersey law when taking such gas distribution pipeline out of service. The Company also recognizes AROs related to Clean Energy Ventures’ solar and wind assets when there are decommissioning provisions in Clean Energy Ventures’ lease agreements that require removal of the asset.

Accretion amounts associated with NJNG’s ARO are recognized as part of its depreciation expense and the corresponding regulatory asset and liability will be shown gross on the Consolidated Balance Sheets. Accretion amounts associated with Clean Energy Ventures’ ARO are recognized as a component of operations and maintenance expense on the Consolidated Statements of Operations.

The following is an analysis of the change in the Company’s AROs for the fiscal years ended September 30:

(Thousands)	2018						2017
	NJNG			NJRCEV			NJNG			NJRCEV
Balance at October 1	$	24,825		$	6,595		$	23,521		$	4,858
Accretion	1,366			198			1,304			245
Additions	1,880			517			729			1,492
Revisions in estimated cash flows	(2,133		)	—			(245		)	—
Retirements	(298		)	—			(484		)	—
Reclassification to held for sale or sold	—			(4,262		)	—			—
Balance at period end	$	25,640		$	3,048		$	24,825		$	6,595

Accretion for the next five years, for the fiscal years ended September 30, is estimated to be as follows:

	Estimated
(Thousands)	Accretion
2019	$	1,557
2020	1,627
2021	1,702
2022	1,778
2023	1,863
Total	$	8,527

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INCOME TAXES

12 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

INCOME TAXES

12. INCOME TAXES

The income tax (benefit) provision from operations for the fiscal years ended September 30, consists of the following:

(Thousands)	2018			2017			2016
Current:
Federal	$	(2,848	)	$	(16,023	)	$	(23,597	)
State	4,563			2,470			(2,209		)
Deferred:
Federal	(40,785		)	54,965			70,386
State	6,731			11,457			11,441
Investment/production tax credits	(21,446		)	(34,526		)	(32,491		)
Income tax (benefit) provision	$	(53,785	)	$	18,343		$	23,530

As of September 30, the temporary differences, which give rise to deferred tax assets and (liabilities), consist of the following:

(Thousands)	2018			2017
Deferred tax assets
Investment tax credits (1)	$	123,258		$	111,642
Deferred service contract revenue	—			3,877
Incentive compensation	4,646			6,260
Fair value of derivatives	8,411			11,519
Federal net operating losses (2)	24,500			28,487
State net operating losses	34,754			23,597
Amortization of intangibles	3,737			2,747
Conservation incentive plan	1,955			—
Other	8,213			11,098
Total deferred tax assets	$	209,474		$	199,227
Deferred tax liabilities
Property related items	$	(392,886	)	$	(620,850	)
Remediation costs	(9,229		)	(11,625		)
Equity investments	(31,956		)	(38,370		)
Postemployment benefits	(353		)	(6,855		)
Conservation incentive plan	—			(7,195		)
Underrecovered gas costs	(1,156		)	(4,035		)
Other	(7,826		)	(16,643		)
Total deferred tax liabilities	$	(443,406	)	$	(705,573	)
Total net deferred tax liabilities	$	(233,932	)	$	(506,346	)

(1) Includes $2.2 million and $2.3 million for NJNG for fiscal 2018 and 2017, respectively, which is being amortized over the life of the related assets, and$121.1 million and $109.3 million for Clean Energy Ventures for fiscal 2018 and 2017, respectively, which is ITC carryforward.

(2) See discussion of federal net operating loss utilization in the Other Tax Items section of this note.

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)	2018			2017			2016
Statutory income tax expense	$	44,014		$	52,643		$	54,321
Change resulting from:
Tax Act - nonutility excess deferred income taxes (1)	(59,627		)	—			—
Tax Act - utility excess deferred income taxes refunded to customers (1)	(14,323		)	—			—
Tax Act - utility excess deferred income taxes amortized (1)	(1,786		)	—			—
State income taxes, net of federal benefit	7,092			8,222			6,044
Cost of removal of assets placed in service prior to1981	(5,829		)	(6,886		)	(5,738		)
Investment/production tax credits	(21,446		)	(34,526		)	(32,491		)
Basis adjustment of solar assets due to ITC	1,080			4,256			4,453
AFUDC equity	(2,117		)	(2,624		)	(1,531		)
Other	(843		)	(2,742		)	(1,528		)
Income tax (benefit) provision	$	(53,785	)	$	18,343		$	23,530
Effective income tax rate (2) (3)	(29.9		)%	12.2		%	15.2		%

(1) For a more detailed description, see The Tax Act section of this note.

(2) The U.S. federal statutory rate was 24.5 percent for fiscal 2018 and 35 percent for fiscal 2017 and 2016.

(3) The effective tax rate without the impact of the Tax Act would have been 12.4 percent for fiscal 2018.

The Company and one or more of its subsidiaries files or expects to file income and/or franchise tax returns in the U.S. Federal jurisdiction and in the states of Colorado, Connecticut, Delaware, Iowa, Kansas, Louisiana, Maryland, Montana, New Jersey, New York, North Carolina, Pennsylvania, South Carolina, Texas, Utah, Virginia and the City of New York. The Company neither files in, nor believes it has a filing requirement in, any foreign jurisdictions other than Canada. Due to certain available tax treaty benefits, the Company incurs no tax liability in Canada.

The Company’s federal income tax returns through fiscal 2014 have either been reviewed by the IRS, or the related statute of limitations has expired and all matters have been settled. Federal income tax returns for periods subsequent to fiscal 2014 are not currently under examination by the IRS. For all periods subsequent to those ended September 30, 2014, 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, 2013 are statutorily open to examination.

The State of New Jersey is currently conducting a sales and use tax examination for the period from July 1, 2011 through September 30, 2018.

On March 7, 2018, the State of New Jersey notified the Company that it will conduct a general tax examination for fiscal years 2014 through 2017 related to NJRHS. The audit is currently in the information gathering stage. All periods subsequent to those ended September 30, 2013, are statutorily open to examination.

The Company evaluates its tax positions to determine the appropriate accounting and recognition of potential future obligations associated with unrecognized tax benefits. As of September 30, 2018 and 2017, based on its analysis, the Company determined there was no need to recognize any liabilities associated with uncertain tax positions.

The Tax Act

On December 22, 2017, the President signed into law the Tax Act. The law made several changes to the Internal Revenue Code of 1986, as amended, the most impactful to the Company of which was a reduction in the federal corporate income tax rate from 35 percent to 21 percent that became effective January 1, 2018. Since the Company's fiscal year end is September 30, it is required by the Internal Revenue Code to calculate a statutory rate based upon the federal tax rates in effect before and after the effective date of the change in the taxable year that includes the effective date. Accordingly, the Company will use a federal statutory tax rate of 24.5 percent during fiscal 2018 and will use the enacted rate of 21 percent beginning in fiscal 2019.

The SEC issued guidance in Staff Accounting Bulletin 118 to address the changes in estimates associated with impacts resulting from the Tax Act, which allows companies to record provisional amounts during a one-year measurement period. The Company calculated an original estimate for the measurement and accounting for certain effects of the Tax Act, including the remeasurement of deferred tax assets and liabilities to reflect the rates that will be in effect when the deferred tax assets and liabilities are expected to be realized or settled. The adjustments to deferred income taxes were based on assumptions the Company made with respect to its book versus tax differences and the timing of when those differences will reverse, including estimations associated with depreciation and the settlement of derivative unrealized amounts. Therefore, the revaluation of net deferred tax liabilities was subject to change as information and assumptions were updated each quarter for actual results.

As a result of the changes associated with the Tax Act, NJNG recorded a decrease in its net deferred tax liability of $228.4 million, which included $164.3 million for the revaluation of its deferred income taxes and $64.1 million for the accounting of the income tax effects on the revaluation of those deferred income taxes. These amounts were recorded as a regulatory liability on the Consolidated Balance Sheets. On May 22, 2018, the BPU approved a refund of $31 million, which included approximately $20.1 million of the initial revaluation of excess deferred income taxes, $9 million for the overcollection of taxes from customers from January 1, 2018 through March 31, 2018, and interest on the overcollected taxes at the Company's short-term debt rate. These credits were returned to customer accounts in June 2018.

During fiscal 2018, NJNG credited approximately $17 million to income tax (benefit) provision on the Consolidated Statements of Operations, which includes $14.3 million attributable to the remeasurement of deferred income taxes, $1.8 million for the amortization of excess deferred income taxes primarily related to timing differences associated with utility plant depreciation and $880,000 related to the revaluation of deferred income taxes not included in base rates. As of September 30, 2018, the regulatory liability included excess deferred income taxes of $205.4 million, which requires amortization over the remaining life of the utility plant consistent with IRS normalization principles.

The (decrease) increase of the net deferred tax liability due to the impact of the Tax Act that was recognized on the Consolidated Statements of Operations for the remaining entities, was as follows:

(Thousands)	2018
Income tax (benefit) provision
Clean Energy Ventures	$	(61,423	)
Energy Services	6,062
Midstream	(13,946		)
Home Services and Other	9,680
Total	$	(59,627	)

There was a $2.1 million change in the original estimate resulting from the use of actual results instead of estimated results through the Company’s fourth fiscal quarter.

As of September 30, 2018, our accounting for the income tax effects of the Tax Act is considered complete. The Company does not expect to make any further adjustments to the amounts recorded as a result of the Tax Act.

Other Tax Items

As of September 30, 2018 and 2017, the Company has federal income tax net operating losses of approximately $136.8 million and $125.3 million, respectively. Federal net operating losses can generally can be carried back two years and forward 20 years and will begin to expire in fiscal 2036, with the remainder expiring by 2038. The Company expects to exercise its ability to carryback federal net operating losses to offset taxable income in prior periods.

For the net operating losses it expects to carryback, the Company estimated the portion considered refundable and recorded receivables of approximately $23 million and $15.4 million as of September 30, 2018 and 2017, respectively, as a component of other noncurrent assets on the Consolidated Balance Sheets. Upon filing amended federal income tax returns to carryback its remaining federal net operating losses totaling $24.5 million, the Company will reduce its taxable income in those periods and recapture federal investment tax credits of the same amount that were previously utilized to offset taxable income.

In addition, as of September 30, 2018 and 2017, the Company has an ITC/PTC carryforward of approximately $121.1 million and $109.3 million, respectively, which each have a life of 20 years. When the Company carries back the federal net operating losses noted above, it expects to recapture investment tax credits totaling $24.5 million. These recaptured tax credits are in addition to the $121.1 million and will be carried forward to offset future taxable income. The Company expects to utilize this entire carryforward, which would begin to expire in fiscal 2033.

As of September 30, 2018 and 2017, the Company has state income tax net operating losses of approximately $578.8 million and $471.7 million, respectively. These state net operating losses have varying carry forward periods dictated by the state in which they were incurred; these state carry forward periods range from seven to 20 years and would begin to expire in fiscal 2021, with the majority expiring after 2035.

In March 2018, Clean Energy Ventures committed to a plan to sell its wind assets and expects that the sale will be completed within the next 12 months. As a result of the planned sale, it is more likely than not that certain state net operating loss carryforwards will not be realizable prior to their expiration. As of September 30, 2018, the Company had a valuation allowance of $4 million related to state net operating loss carryforwards in Montana, Iowa, Kansas and Wyoming. As of September 30, 2017, the Company had a valuation allowance of $1 million related to state net operating loss carryforwards in Montana. This is included as a component of Other within the composition of deferred tax assets.

The Consolidated Appropriations Act extended the 30 percent ITC for solar property that is under construction on or before December 31, 2019. The credit will decline to 26 percent for property under construction during 2020, and to 22 percent for property under construction during 2021. For any property that is under construction before 2022, but not placed in service before 2024, the ITC will be reduced to 10 percent. In addition, the Consolidated Appropriations Act retroactively extended the PTC for five years through December 31, 2019, with a gradual three-year phase-out for any project for which construction of the facility begins after December 31, 2016.

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COMMITMENTS AND CONTINGENT LIABILITIES

12 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENT LIABILITIES

13. COMMITMENTS AND CONTINGENT LIABILITIES

Cash Commitments

NJNG has entered into long-term contracts, expiring at various dates through September 2024, for the supply, storage and transportation of natural gas. These contracts include annual fixed charges of approximately $112 million at current contract rates and volumes, which are recoverable through BGSS.

For the purpose of securing storage and pipeline capacity, our Energy Services segment enters into storage and pipeline capacity contracts, which require the payment of certain demand charges by Energy Services to maintain the ability to access such natural gas storage or pipeline capacity, during a fixed time period, which generally ranges from one to 10 years. Demand charges are established by interstate storage and pipeline operators and are regulated by FERC. These demand charges represent commitments to pay storage providers or pipeline companies for the right to store and/or transport natural gas utilizing their respective assets.

Commitments as of September 30, 2018, for natural gas purchases and future demand fees for the next five fiscal year periods, are as follows:

(Thousands)	2019		2020		2021		2022		2023		Thereafter
Energy Services:
Natural gas purchases	$	428,015	$	28,389	$	10,965	$	—	$	—	$	—
Storage demand fees	31,716		19,926		13,478		8,904		4,212		991
Pipeline demand fees	52,148		49,790		28,209		24,153		18,988		5,151
Sub-total Energy Services	$	511,879	$	98,105	$	52,652	$	33,057	$	23,200	$	6,142
NJNG:
Natural gas purchases	$	65,737	$	37,727	$	33,738	$	33,546	$	34,221	$	35,762
Storage demand fees	31,384		24,263		14,251		12,930		7,899		6,066
Pipeline demand fees	80,609		96,241		89,236		91,946		87,240		586,266
Sub-total NJNG	$	177,730	$	158,231	$	137,225	$	138,422	$	129,360	$	628,094
Total	$	689,609	$	256,336	$	189,877	$	171,479	$	152,560	$	634,236

As of September 30, 2018, the Company’s future minimum lease payments under various operating leases will not be more than $3.7 million annually for the next five years and $50 million in the aggregate for all years thereafter.

Guarantees

As of September 30, 2018, there were NJR guarantees covering approximately $418.1 million of Energy Services’ natural gas purchases and demand fee commitments not yet reflected in accounts payable on the Consolidated Balance Sheets.

Legal Proceedings

Manufactured Gas Plant Remediation

NJNG is responsible for the remedial cleanup of five MGP sites, dating back to gas operations in the late 1800s and early 1900s, which contain contaminated residues from former gas manufacturing operations. NJNG is currently involved in administrative proceedings with the NJDEP, and participating in various studies and investigations by outside consultants, to determine the nature and extent of any such contaminated residues and to develop appropriate programs of remedial action, where warranted, under Administrative Consent Orders or Memoranda of Agreement with the NJDEP.

NJNG recovers its remediation expenditures, including carrying costs, over rolling seven-year periods pursuant to a RAC approved by the BPU. NJNG recovered approximately $9.4 million annually through its SBC RAC. In July 2018, the BPU approved NJNG's annual SBC filing requesting a reduction in the RAC, which decreased the annual recovery to $7 million, effective September 1, 2018. On September 21, 2018, NJNG filed its annual SBC application requesting to recover remediation expenses incurred through June 30, 2018, which will result in an annual increase of $1.4 million, effective April 1, 2019. As of September 30, 2018, $33 million of previously incurred remediation costs, net of recoveries from customers and insurance proceeds, are included in regulatory assets on the Consolidated Balance Sheets.

In the first quarter of fiscal 2018, the NJDEP contacted NJNG regarding its association with a parcel of land, located within NJNG's service territory, which may have been a MGP site for a period of time. NJNG is investigating to determine the nature and extent of its relationship to the parcel, its previous owners and the operations conducted on the site and has accrued for costs associated with the preliminary investigation of the existence of potential contaminants. NJNG will continue to gather information to determine whether a potential obligation exists to undertake remedial action, if any, and whether there are other potentially responsible parties.

NJNG periodically, and at least annually, performs an environmental review of MGP sites located in Atlantic Highlands, Berkeley, Long Branch, Manchester and Toms River, including a review of potential liability for investigation and remedial action. NJNG estimated at the time of the most recent review that total future expenditures to remediate and monitor the five MGP sites for which it is responsible, including potential liabilities for natural resource damages that might be brought by the NJDEP for alleged injury to groundwater or other natural resources concerning these sites, will range from approximately $117.7 million to $204.1 million. NJNG’s estimate of these liabilities is based upon known facts, existing technology and enacted laws and regulations in place when the review was completed. Where it is probable that costs will be incurred, and the information is sufficient to establish a range of possible liability, NJNG accrues the most likely amount in the range. If no point within the range is more likely than the other, it is NJNG’s policy to accrue the lower end of the range. Accordingly, as of September 30, 2018, NJNG recorded an MGP remediation liability and a corresponding regulatory asset of $130.8 million on the Consolidated Balance Sheets, based on the most likely amount. This was reduced from $149 million in fiscal 2017, due to the completion of remediation work at certain sites and a reduction to the remediation scope at another site. The actual costs to be incurred by NJNG are dependent upon several factors, including final determination of remedial action, changing technologies and governmental regulations, the ultimate ability of other responsible parties to pay and insurance recoveries, if any.

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, NJR establishes reserves for litigation for those matters that present loss contingencies as to which it is both probable that a loss will be incurred and the amount of such loss can be reasonably estimated. NJR also discloses contingent matters for which there is a reasonable possibility of a loss. Based upon currently available information, NJR believes that the results of litigation that is currently pending, taken together, will not have a materially adverse effect on the Company’s financial condition, results of operations or cash flows. The actual results of resolving the pending litigation matters may be substantially higher than the amounts reserved.

The foregoing statements about NJR’s litigation are based upon the Company’s judgments, assumptions and estimates and are necessarily subjective and uncertain. The Company has a number of threatened and pending litigation matters at various stages. Certain of the Company’s significant litigation is described below.

Stafford Township

In February 2015, a natural gas fire and explosion occurred in Stafford Township, New Jersey as a result of a natural gas leak emanating from an underground pipe. There were no fatalities, although several employees of NJNG were injured and several homes were damaged. NJNG notified its insurance carrier and believes that any costs associated with the incident, including attorneys’ fees, property damage and other losses, will be substantially covered by insurance. The Company believes the resolution of the remaining claims associated with the incident will not have a material effect on its financial condition, results of operations or cash flows. Subrogated property damage claims asserted against the Company and co-defendants and cross-claims have been amicably resolved in August 2018.

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BUSINESS SEGMENT AND OTHER OPERATIONS DATA

12 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

BUSINESS SEGMENT AND OTHER OPERATIONS DATA

14. REPORTING SEGMENT AND OTHER OPERATIONS DATA

The Company organizes its businesses based on a combination of factors, including its products and its regulatory environment. As a result, the Company manages its businesses through the following reporting segments and other operations: the Natural Gas Distribution segment consists of regulated energy and off-system, capacity and storage management operations; the Clean Energy Ventures segment consists of capital investments in clean energy projects; the Energy Services segment consists of unregulated wholesale and retail energy operations; the Midstream segment consists of the Company’s investments in natural gas transportation and storage facilities; the Home Services and Other operations consist of heating, cooling and water appliance sales, installations and services, other investments and general corporate activities.

Information related to the Company’s various reporting segments and other operations is detailed below:

(Thousands)
Fiscal Years Ended September 30,	2018			2017			2016
Operating revenues
Natural Gas Distribution
External customers	$	731,865		$	695,637		$	594,346
Clean Energy Ventures
External customers	71,375			64,394			53,540
Energy Services
External customers(1)	2,064,477			1,462,365			1,187,754
Intercompany	48,327			316			9,499
Subtotal	2,916,044			2,222,712			1,845,139
Home Services and Other
External customers	47,392			46,221			45,265
Intercompany	2,665			3,370			3,232
Eliminations	(50,992		)	(3,686		)	(12,731		)
Total	$	2,915,109		$	2,268,617		$	1,880,905
Depreciation and amortization
Natural Gas Distribution	$	53,208		$	49,347		$	47,828
Clean Energy Ventures	31,877			31,834			23,971
Energy Services (2)	76			63			88
Midstream	6			6			6
Subtotal	85,167			81,250			71,893
Home Services and Other	780			798			981
Eliminations	(246		)	(207		)	(126		)
Total	$	85,701		$	81,841		$	72,748
Interest income (3)
Natural Gas Distribution	$	614		$	555		$	115
Energy Services	240			6			98
Midstream	3,374			2,195			1,524
Subtotal	4,228			2,756			1,737
Home Services and Other	1,476			590			397
Eliminations	(5,090		)	(1,312		)	(2,006		)
Total	$	614		$	2,034		$	128

(1) Includes sales to Canada, which are immaterial.

(2) The amortization of acquired wholesale energy contracts is excluded above and is included in gas purchases - nonutility on the Unaudited Condensed Consolidated Statements of Operations.

(3) Included in other income, net on the Consolidated Statements of Operations.

(Thousands)
Fiscal Years Ended September 30,	2018			2017			2016
Interest expense, net of capitalized interest
Natural Gas Distribution	$	25,299		$	25,818		$	19,930
Clean Energy Ventures	18,320			16,263			10,304
Energy Services	3,945			2,747			1,095
Midstream	1,667			960			287
Subtotal	49,231			45,788			31,616
Home Services and Other	7			410			252
Eliminations	(2,952		)	(1,312		)	(824		)
Total	$	46,286		$	44,886		$	31,044
Income tax (benefit) provision
Natural Gas Distribution	$	(1,910	)	$	43,485		$	34,951
Clean Energy Ventures	(79,932		)	(31,161		)	(26,592		)
Energy Services	24,996			(4,015		)	7,030
Midstream	(8,548		)	5,820			6,130
Subtotal	(65,394		)	14,129			21,519
Home Services and Other	11,944			3,857			1,387
Eliminations	(335		)	357			624
Total	$	(53,785	)	$	18,343		$	23,530
Equity in earnings of affiliates
Midstream	$	16,165		$	17,797		$	13,936
Eliminations	(3,157		)	(3,984		)	(4,421		)
Total	$	13,008		$	13,813		$	9,515
Net financial earnings (loss)
Natural Gas Distribution	$	84,048		$	86,930		$	76,104
Clean Energy Ventures	75,849			24,873			28,393
Energy Services	60,378			18,554			21,934
Midstream	24,367			12,857			9,406
Subtotal	244,642			143,214			135,837
Home Services and Other	(3,829		)	6,811			2,882
Eliminations	(327		)	(633		)	(634		)
Total	$	240,486		$	149,392		$	138,085
Capital expenditures
Natural Gas Distribution	$	254,523		$	176,249		$	205,133
Clean Energy Ventures	123,421			149,400			149,063
Midstream	5,431			—			—
Subtotal	383,375			325,649			354,196
Home Services and Other	1,213			2,434			1,896
Total	$	384,588		$	328,083		$	356,092
Investments in equity investees
Midstream	16,151			27,070			11,176
Total	$	16,151		$	27,070		$	11,176

The Chief Executive Officer, who uses NFE as a measure of profit or loss in measuring the results of the Company’s reporting segments and operations, is the chief operating decision maker of the Company. A reconciliation of consolidated NFE to consolidated net income is as follows:

(Thousands)	2018			2017			2016
Consolidated net financial earnings	$	240,486		$	149,392		$	138,085
Less:
Unrealized loss (gain) on derivative instruments and related transactions	26,770			(11,241		)	46,883
Tax effect	(4,512		)	4,062			(17,018		)
Effects of economic hedging related to natural gas inventory	(22,570		)	38,470			(36,816		)
Tax effect	7,362			(13,964		)	13,364
Consolidated net income	$	233,436		$	132,065		$	131,672

The Company uses derivative instruments as economic hedges of purchases and sales of physical gas inventory. For GAAP purposes, these derivatives are recorded at fair value and related changes in fair value are included in reported earnings. Revenues and cost of gas related to physical gas flow are recognized when the gas is delivered to customers. Consequently, there is a mismatch in the timing of earnings recognition between the economic hedges and physical gas flows. Timing differences occur in two ways:

• Unrealized gains and losses on derivatives are recognized in reported earnings in periods prior to physical gas inventory flows; and

• Unrealized gains and losses of prior periods are reclassified as realized gains and losses when derivatives are settled in the same period as physical gas inventory movements occur.

NFE is a measure of the earnings based on eliminating these timing differences, to effectively match the earnings effects of the economic hedges with the physical sale of gas, SRECs and foreign currency contracts. Consequently, to reconcile between net income and NFE, current-period unrealized gains and losses on the derivatives are excluded from NFE as a reconciling item. Additionally, realized derivative gains and losses are also included in current-period net income. However, NFE includes only realized gains and losses related to natural gas sold out of inventory, effectively matching the full earnings effects of the derivatives with realized margins on physical gas flows. Included in the tax effects are current and deferred income tax expense corresponding with the non-GAAP measure. Also included in the tax effects during fiscal 2018, are the impacts of the Tax Act and resulting revaluation of the deferred income taxes that arose from derivative and hedging activity as measured under NFE. The revaluation caused the effective tax rate on reconciling items to differ from the statutory rate in effect for the year. The Company also calculates a quarterly tax adjustment based on an estimated annual effective tax rate for NFE purposes.

The Company’s assets for the various reporting segments and business operations are detailed below:

(Thousands)	2018			2017			2016
Assets at end of period:
Natural Gas Distribution	$	2,663,054		$	2,519,578		$	2,517,401
Clean Energy Ventures (1)	865,018			771,340			665,696
Energy Services	396,852			398,277			327,626
Midstream	242,069			232,806			186,259
Subtotal	4,166,993			3,922,001			3,696,982
Home Services and Other	114,732			114,801			109,487
Intercompany assets (2)	(138,061		)	(108,295		)	(87,899		)
Total	$	4,143,664		$	3,928,507		$	3,718,570

(1) Includes assets held for sale of $206.9 million for September 30, 2018.

(2) Consists of transactions between subsidiaries that are eliminated and reclassified in consolidation.

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RELATED PARTY TRANSACTIONS

12 Months Ended

Sep. 30, 2018

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

15. RELATED PARTY TRANSACTIONS

Effective April 1, 2010, NJNG entered into a 10-year agreement for 3 Bcf of firm storage capacity with Steckman Ridge. Under the terms of the agreement, NJNG incurs demand fees, at market rates, of approximately $9.3 million annually, a portion of which is eliminated in consolidation. These fees are recoverable through NJNG’s BGSS mechanism and are included in regulatory assets.

Energy Services may periodically enter into storage or park and loan agreements with its affiliated FERC-jurisdictional natural gas storage facility, Steckman Ridge. As of September 30, 2018, Energy Services has entered into transactions with Steckman Ridge for varying terms, all of which expire by October 31, 2020.

Demand fees, net of eliminations, associated with Steckman Ridge during the fiscal years ended September 30, are as follows:

(Thousands)	2018		2017		2016
Natural Gas Distribution	$	5,730	$	5,590	$	5,562
Energy Services	2,775		2,750		2,789
Total	$	8,505	$	8,340	$	8,351

The following table summarizes demand fees payable to Steckman Ridge as of September 30:

(Thousands)	2018		2017
Natural Gas Distribution	$	775	$	775
Energy Services	375		377
Total	$	1,150	$	1,152

NJNG and Energy Services have entered into various asset management agreements, the effects of which are eliminated in consolidation. Under the terms of these agreements, NJNG releases certain transportation and storage contracts to Energy Services. NJNG retains the right to purchase market-priced gas or fixed-price storage gas from Energy Services. As of September 30, 2018, NJNG and Energy Services had four asset management agreements with expiration dates ranging from March 31, 2019 through October 31, 2021.

NJNG has entered into a 15-year transportation precedent agreement for committed capacity of 180,000 Dths per day with PennEast, to commence when in service.

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ACQUISITION

12 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

ACQUISITION

16. ACQUISITION

On October 27, 2017, Adelphia, an indirect wholly owned subsidiary of NJR, entered into a Purchase and Sale Agreement with Talen pursuant to which Adelphia will acquire all of Talen’s membership interests in IEC for a base purchase price of $166 million. As additional consideration, Adelphia will pay Talen specified amounts of up to $23 million contingent upon the achievement of certain regulatory approvals and binding natural gas capacity commitments, which have not been received as of September 30, 2018. On November 7, 2017, the Company made an initial payment of $10 million towards the base purchase price, which is included in other noncurrent assets on the Consolidated Balance Sheets.

IEC owns an existing 84-mile pipeline in southeastern Pennsylvania. The transaction is expected to close following receipt of necessary permits and regulatory actions including those from the FERC and the Pennsylvania Public Utility Commission. Upon the closing, Adelphia will acquire IEC and, with it, IEC’s existing pipeline, related assets and rights of way. Adelphia has also agreed to provide firm natural gas transportation service for ten years following the closing to two power generators owned by affiliates of Talen that are currently served by IEC.

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DISPOSITIONS

12 Months Ended

Sep. 30, 2018

Discontinued Operations and Disposal Groups [Abstract]

DISPOSITIONS

17. DISPOSITIONS

Energy Services

On February 28, 2018, NJR sold all of the issued and outstanding shares of capital stock of NJRRS, which was a component of the Energy Services segment. The Company received $9.5 million in cash and a natural gas swap contract with a fair value of $14.6 million, which was recorded in Derivatives, at fair value on the Consolidated Balance Sheets. The sale generated a pre-tax gain of $3.7 million, which was recognized as a reduction to O&M on the Consolidated Statements of Operations.

Clean Energy Ventures

On June 1, 2018, Clean Energy Ventures completed the sale of its membership interest in its 9.7 MW wind farm in Two Dot, Montana to NorthWestern Energy for a total purchase price of $18.5 million. The transaction generated a pre-tax gain of approximately $951,000, which is recognized as a reduction to O&M on the Consolidated Statements of Operations.

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SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

12 Months Ended

Sep. 30, 2018

Quarterly Financial Information Disclosure [Abstract]

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

18. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of financial data for each quarter of fiscal 2018 and 2017 follows. Due to the seasonal nature of the Company’s businesses, quarterly amounts vary significantly during the fiscal year. In the opinion of management, the information furnished reflects all adjustments necessary for a fair presentation of the results of the interim periods.

	First		Second		Third			Fourth
(Thousands, except per share data)	Quarter		Quarter		Quarter			Quarter
2018
Operating revenues	$	705,305	$	1,019,043	$	543,435		$	647,326
Operating income (loss)	$	75,245	$	177,792	$	(37,666	)	$	(19,295	)
Net income (loss)	$	123,699	$	140,266	$	(14,274	)	$	(16,255	)
Earnings (loss) per share (1)
Basic	$1.42		$1.60		$(0.16)			$(0.18)
Diluted	$1.42		$1.59		$(0.16)			$(0.18)
2017
Operating revenues	$	541,028	$	733,546	$	457,523		$	536,520
Operating income (loss)	$	41,475	$	139,653	$	17,967		$	(32,051	)
Net income (loss)	$	34,929	$	114,702	$	18,957		$	(36,523	)
Earnings (loss) per share (1)
Basic	$0.41		$1.33		$0.22			$(0.42)
Diluted	$0.40		$1.32		$0.22			$(0.42)

(1) The sum of quarterly amounts may not equal the annual amounts due to rounding.

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VALUATION AND QUALIFYING ACCOUNTS

12 Months Ended

Sep. 30, 2018

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

VALUATION AND QUALIFYING ACCOUNTS

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED SEPTEMBER 30, 2018, 2017 and 2016

(Thousands)			ADDITIONS
CLASSIFICATION	BEGINNING BALANCE		CHARGED TO EXPENSE	OTHER (1)		ENDING BALANCE
2018
Allowance for doubtful accounts	$	5,181	2,579	(2,056	)	$	5,704
2017
Allowance for doubtful accounts	$	4,865	2,023	(1,707	)	$	5,181
2016
Allowance for doubtful accounts	$	5,189	1,616	(1,940	)	$	4,865

(1) Uncollectible accounts written off, less recoveries and adjustments.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

The Consolidated Financial Statements include the accounts of the Company and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated.

Other financial investments or contractual interests that lack the characteristics of a voting interest entity, which are commonly referred to as variable interest entities, are evaluated by the Company to determine if 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, 2018, 2017 and 2016.

Investments in entities over which the Company does not have a controlling financial interest are either accounted for under the equity method or cost method of accounting.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP requires the Company to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a 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, investments, 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. AROs are evaluated as often as needed. The Company’s estimates are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources.

The Company has legal, regulatory and environmental proceedings during the normal course of business that can result in loss contingencies. When evaluating the potential for a loss, the Company will establish a reserve if a loss is probable and can be reasonably estimated, in which case it is the Company’s policy to accrue the full amount of such estimates. Where the information is sufficient only to establish a range of probable liability, and no point within the range is more likely than any other, it is the Company’s policy to accrue the lower end of the range. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from estimates.

Business Combinations

Business Combinations

The Company accounts for business combinations by applying the acquisition method of accounting. Identifiable assets acquired and liabilities assumed are measured separately at their fair value as of the acquisition date and associated transactions costs are expensed as incurred.

The determination and allocation of fair values to the identifiable assets acquired and liabilities assumed are based on various assumptions and valuation methodologies requiring considerable management judgment. The most significant variables in these valuations are discount rates and the number of years on which to base the cash flow projections, as well as other assumptions and estimates used to determine the cash inflows and outflows. Management determines discount rates based on the risk inherent in the acquired assets and related cash flows. Our valuation of an acquired business is based on available information at the acquisition date and assumptions that we believe are reasonable. However, a change in facts and circumstances as of the acquisition date can result in subsequent adjustments during the measurement period, but no later than one year from the acquisition date.

Revenues

Revenues

Revenues from the sale of natural gas to NJNG customers are recognized in the period that gas is delivered and consumed by customers, including an estimate for unbilled revenue.

NJNG records unbilled revenue for natural gas services. Natural gas sales to individual customers are based on meter readings, which are performed on a systematic basis throughout the month. At the end of each month, the amount of natural gas delivered to each customer after the last meter reading through the end of the respective accounting period is estimated, and recognizes unbilled revenues related to these amounts. The unbilled revenue estimates are based on estimated customer usage by customer type, weather effects, unaccounted-for gas and the most current tariff rates.

Clean Energy Ventures recognizes revenue when SRECs are transferred to counterparties. SRECs are physically delivered through the transfer of certificates as per contractual settlement schedules.

Revenues for Energy Services are recognized when the natural gas is physically delivered to the customer. In addition, changes in the fair value of derivatives that economically hedge the forecasted sales of the natural gas are recognized in operating revenues as they occur, as noted above. Energy Services also recognizes changes in the fair value of SREC derivative contracts as a component of operating revenues.

Revenues from all other activities are recorded in the period during which products or services are delivered and accepted by customers, or over the related contractual term.

Gas Purchases

Gas Purchases

NJNG’s tariff includes a component for BGSS, which is designed to allow it to recover the cost of natural gas through rates charged to its customers and is typically revised on an annual basis. As part of computing its BGSS rate, NJNG projects its cost of natural gas, net of supplier refunds, the impact of hedging activities and cost savings created by BGSS incentive programs. NJNG subsequently recovers or credits the difference, if any, of actual costs compared with those included in current rates. Any underrecoveries or overrecoveries are either credited to customers or deferred and, subject to BPU approval, reflected in the BGSS rates in subsequent years.

Gas purchases at Energy Services are composed of gas costs to be paid upon completion of a variety of transactions, as well as realized gains and losses from settled derivative instruments and unrealized gains and losses on the change in fair value of derivative instruments that have not yet settled. Changes in the fair value of derivatives that economically hedge the forecasted purchases of natural gas are recognized in gas purchases as they occur.

Demand Fees

Demand Fees

For the purpose of securing storage and pipeline capacity in support of their respective businesses, the Energy Services and Natural Gas Distribution segments enter into storage and pipeline capacity contracts, which require the payment of associated demand fees and charges that allow them access to a high priority of service in order to maintain the ability to access storage or pipeline capacity during a fixed time period, which generally ranges from one to 10 years. Many of these demand fees and charges are based on established tariff rates as established and regulated by FERC. These charges represent commitments to pay storage providers and pipeline companies for the priority right to transport and/or store natural gas utilizing their respective assets.

The following table summarizes the demand charges, which are net of capacity releases, and are included as a component of gas purchases on the Consolidated Statements of Operations for the fiscal years ended September 30:

(Millions)	2018		2017		2016
Energy Services	$	153.0	$	126.4	$	141.0
Natural Gas Distribution	92.5		80.2		77.8
Total	$	245.5	$	206.6	$	218.8

Energy Services expenses demand charges over the term of the service being provided.

The Natural Gas Distribution segment’s costs associated with demand charges are included in its weighted average cost of gas. The demand charges are expensed based on NJNG’s BGSS sales and recovered as part of its gas commodity component of its BGSS tariff.

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, 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 NJR Board of Directors members. 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 9. Stock-Based Compensation for further information.

Sales Tax Accounting

Sales Tax Accounting

Sales tax that is collected from customers is presented in both operating revenues and operating expenses on the Consolidated Statements of Operations. During fiscal 2018, 2017 and 2016, sales tax collected was $41.7 million, $39.4 million and $31 million, respectively. Effective January 1, 2017, the New Jersey sales tax rate decreased from 7 percent to 6.875 percent. Effective January 1, 2018, the New Jersey sales tax rate decreased again to 6.625 percent.

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.

The Company invests in property that qualifies for federal ITCs and utilizes the ITCs, as allowed, based on the cost and life of the assets. ITCs at NJNG are deferred and amortized as a reduction to the tax provision over the average lives of the related equipment in accordance with regulatory treatment. ITCs at the unregulated subsidiaries of NJR are recognized as a reduction to income tax expense when the property is placed in service. The Company invests in property that qualifies for PTCs. PTCs are recognized as reductions to current federal income tax expense as PTCs are generated through the production activities of the assets. Changes to the federal statutes related to ITCs and PTCs, which have the effect of reducing or eliminating the credits, could have a negative impact on earnings and cash flows.

Investments in Equity Investees

Investments in Equity Investees

The Company accounts for its investments in Steckman Ridge and PennEast, using the equity method of accounting where its respective ownership interests are 50 percent or less and/or it has significant influence over operating and management decisions, but is not the primary beneficiary, as defined under ASC 810, Consolidation. The Company’s share of earnings is recognized as equity in earnings of affiliates on the Consolidated Statements of Operations. See Note 6. Investments in Equity Investeesfor more information.

Property Plant and Equipment

Property Plant and Equipment

Regulated property, plant and equipment is stated at original cost. Costs include direct labor, materials and third-party construction contractor costs, AFUDC and certain indirect costs related to equipment and employees engaged in construction. Nonregulated property, plant and equipment is stated at original cost. Costs include direct labor, materials and third-party construction contractor costs and certain indirect costs related to equipment and employees engaged in construction. 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 unregulated entities, and using rates based on the estimated average lives of the various classes of depreciable property for NJNG.

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 3. 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.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents consist of cash on deposit and temporary investments with maturities of three months or less, and excludes restricted cash of $252,000 and $243,000 as of September 30, 2018 and 2017, respectively, related to escrow balances for utility plant projects, which is recorded in other current and noncurrent assets on the Consolidated Balance Sheets.

Customer Accounts Receivable and Allowance for Doubtful Accounts and Loan Receivable

Customer Accounts Receivable and Allowance for Doubtful Accounts

Receivables consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers, as well as equipment sales, installations, solar leases and PPAs to commercial and residential customers. The Company evaluates its accounts receivables and, to the extent customer account balances are outstanding for more than 60 days, establishes an allowance for doubtful accounts. The allowance is based on a combination of factors including historical collection experience and trends, aging of receivables, general economic conditions in the Company’s distribution or sales territories and customer-specific information. The Company writes-off customer accounts once it is determined they are uncollectible.

The following table summarizes customer accounts receivable by company as of September 30:

(Thousands)	2018				2017
Energy Services	$	157,936	77	%	$	150,322	77	%
Natural Gas Distribution (1)	39,151		19		37,432		19
Clean Energy Ventures	3,330		2		2,655		1
Home Services and Other Operations	5,073		2		6,058		3
Total	$	205,490	100	%	$	196,467	100	%

(1) Does not include unbilled revenues of $7.2 million as of September 30, 2018 and 2017.

Loans Receivable

NJNG currently provides loans, with terms ranging from three to 10 years, to customers that elect to purchase and install certain energy-efficient equipment in accordance with its BPU-approved SAVEGREEN program. The loans are recognized at net present value on the Consolidated Balance Sheets. The Company has recorded $10.4 million and $8.9 million in other current assets and $39.5 million and $40.4 million in other noncurrent assets as of September 30, 2018 and 2017, respectively, on the Consolidated Balance Sheets, related to the loans. If NJNG determines a loan is impaired, the basis of the loan would be subject to regulatory review for recovery. As of September 30, 2018 and 2017, the Company has not recorded an allowance for doubtful accounts for SAVEGREEN loans.

Regulatory Assets & Liabilities

Regulatory Assets & Liabilities

Under cost-based regulation, regulated utility enterprises generally are permitted to recover their operating expenses and earn a reasonable rate of return on their utility investment.

Our Natural Gas Distribution segment maintains its accounts in accordance with the FERC Uniform System of Accounts as prescribed by the BPU and in accordance with the ASC 980, Regulated Operations. As a result of the impact of the ratemaking process and regulatory actions of the BPU, NJNG is required to recognize the economic effects of rate regulation. Accordingly, NJNG capitalizes or defers certain costs that are expected to be recovered from its customers as regulatory assets and recognizes certain obligations representing probable future expenditures as regulatory liabilities on the Consolidated Balance Sheets. See Note 3. Regulation for a more detailed description of NJNG’s regulatory assets and liabilities.

Gas in Storage

Gas in Storage

Gas in storage is reflected at average cost on the Consolidated Balance Sheets and represents natural gas and LNG that will be utilized in the ordinary course of business.

The following table summarizes gas in storage, at average cost by company, as of September 30:

	2018				2017
($ in thousands)	Gas in Storage			Bcf	Gas in Storage			Bcf
Energy Services		$	90,166	34.1		$	122,884	53.9
Natural Gas Distribution		94,467		24.9		79,179		21.8
Total		$	184,633	59.0		$	202,063	75.7

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 Energy Services, as derivatives, and therefore recognizes them at fair value on the Consolidated Balance Sheets. The Company’s unregulated subsidiaries record changes in the fair value of their financial commodity derivatives in gas purchases and changes in the fair value of their physical forward contracts in gas purchases or operating revenues, as appropriate, on the Consolidated Statements of Operations. Ineffective portions of the cash flow hedges are recognized immediately in earnings.

The ASC 815, Derivatives and Hedging also provides for a NPNS scope exception for qualifying physical commodity contracts that are intended for purchases and sales during the normal course of business and for which physical delivery is probable. Effective January 1, 2016, the Company prospectively applies this normal scope exception on a case-by-case basis to physical commodity contracts at NJNG and forward SREC contracts at Clean Energy Ventures. When applied, it does not record changes in the fair value of these contracts until the contract settles and the related underlying natural gas or SREC is delivered. Gains and/or losses on NJNG’s derivatives used to economically hedge its regulated natural gas supply obligations, as well as its exposure to interest rate variability, are recoverable through its BGSS, a component of its tariff. Accordingly, the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability on the Consolidated Balance Sheets.

See Note 4. 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 Energy Services 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.

The Company is subject to commodity price risk due to fluctuations in the market price of natural gas, SRECs and electricity. To manage this risk, the Company enters into a variety of derivative instruments including, but not limited to, futures contracts, physical forward contracts, financial options and swaps to economically hedge the commodity price risk associated with its existing and anticipated commitments to purchase and sell natural gas, SRECs and electricity. In addition, the Company may utilize foreign currency derivatives to hedge Canadian dollar denominated gas purchases and/or sales. Therefore, the Company’s primary underlying risks include commodity prices, interest rates and foreign currency. These contracts, with a few exceptions as described below, are accounted for as derivatives. Accordingly, all of the financial and certain of the Company’s physical derivative instruments are recorded at fair value on the Consolidated Balance Sheets. For a more detailed discussion of the Company’s fair value measurement policies and level disclosures associated with the Company’s derivative instruments, see Note 5. Fair Value.

Energy Services

Energy Services chooses not to designate its financial commodity and physical forward commodity derivatives as accounting hedges or to elect NPNS. The changes in the fair value of these derivatives are recorded as a component of gas purchases or operating revenues, as appropriate for Energy Services, on the Consolidated Statements of Operations as unrealized gains or losses. For Energy Services at settlement, realized gains and losses on all financial derivative instruments are recognized as a component of gas purchases and realized gains and losses on all physical derivatives follow the presentation of the related unrealized gains and losses as a component of either gas purchases or operating revenues.

Energy Services also enters into natural gas transactions in Canada and, consequently, is exposed to fluctuations in the value of Canadian currency relative to the U.S. dollar. Energy Services may utilize foreign currency derivatives to lock in the exchange rate associated with natural gas transactions denominated in Canadian currency. The derivatives may include currency forwards, futures or swaps and are accounted for as derivatives. These derivatives are typically used to hedge demand fee payments on pipeline capacity, storage and gas purchase agreements.

As a result of Energy Services entering into transactions to borrow natural gas, commonly referred to as “park and loans,” an embedded derivative is recognized relating to differences between the fair value of the amount borrowed and the fair value of the amount that will ultimately be repaid, based on changes in the forward price for natural gas prices at the borrowed location over the contract term. This embedded derivative is accounted for as a forward sale in the month in which the repayment of the borrowed gas is expected to occur, and is considered a derivative transaction that is recorded at fair value on the Consolidated Balance Sheets, with changes in value recognized in current-period earnings.

Expected production of SRECs is hedged through the use of forward and futures contracts. All contracts require the Company to physically deliver SRECs through the transfer of certificates as per contractual settlement schedules. For transactions occurring on or before December 31, 2015, the Company elected NPNS accounting treatment on SREC forward and futures contracts. Effective January 1, 2016, on a prospective basis, Energy Services no longer elects NPNS accounting treatment on SREC contracts entered into from January 1, 2016, and recognizes changes in the fair value of these derivatives as a component of operating revenues. Upon settlement of the contract, the related revenue is recognized when the SREC is transferred to the counterparty. NPNS is a contract-by-contract election and, where it makes sense to do so, we can and may elect certain contracts to be normal.

Natural Gas Distribution

Changes in fair value of NJNG’s financial commodity derivatives are recorded as a component of regulatory assets or liabilities on the Consolidated Balance Sheets. The Company elects NPNS accounting treatment on all physical commodity contracts that NJNG entered into on or before December 31, 2015, and accounts for these contracts on an accrual basis. Accordingly, physical natural gas purchases are recognized in regulatory assets or liabilities on the Consolidated Balance Sheets when the contract settles and the natural gas is delivered. The average cost of natural gas is amortized in current-period earnings based on the current BPU BGSS factor and therm sales. Effective January 1, 2016, on a prospective basis, NJNG no longer elects NPNS accounting treatment on all of its physical commodity contracts entered into from January 1, 2016. However, since NPNS is a contract-by-contract election, where it makes sense to do so, NJNG can and may elect certain contracts to be normal. Because NJNG recovers these amounts through future BGSS rates as increases or decreases to the cost of natural gas in NJNG’s tariff for gas service, the changes in fair value of these contracts are deferred as a component of regulatory assets or liabilities on the Consolidated Balance Sheets.

Assets Held for Sale

Assets Held for Sale

The Company classifies an asset as held for sale if there is a commitment to sell the asset, the asset is available for immediate sale, the sale is probable and the sale will be completed within one year. In March 2018, Clean Energy Ventures committed to a plan to sell its wind assets and expects that the sale will be completed within the next 12 months. Accordingly, the Company classified its wind assets and related liabilities as held for sale on the Consolidated Balance Sheets, which resulted in depreciation expense on wind assets no longer being recorded.

The wind assets classified as held for sale are measured at the lower of their carrying value or fair value less cost to sell. At September 30, 2018, the Company performed a fair value assessment of its wind assets held for sale. The Company equally weighted the valuation derived from an income approach and a market approach to determine fair value. The Company believes that the estimates and assumptions used in calculating the fair value of our assets and liabilities held for sale are reasonable and appropriate based on the information that was known when the estimates were made. The Company concluded that the fair value of the wind assets was greater than the carrying value and thus no impairment was recorded.

Available for Sale Securities

Available for Sale Securities

Available for sale securities are carried at fair value on the Consolidated Balance Sheets. For fiscal years ended September 30, 2018 and prior, total unrealized gains and losses associated are included as a part of accumulated other comprehensive income, a component of common stock equity. Reclassifications of realized gains or losses out of other comprehensive income into earnings are recorded in other income, net on the Consolidated Statements of Operations based on average cost.

Management evaluates its equity securities for other-than-temporary impairment on a quarterly basis, and more frequently when economic, market or other concerns warrant such evaluation. Consideration is given to the length of time and the extent to which the fair value has been less than cost; the financial condition and near term prospects of the issuer; whether the market decline was affected by macroeconomic conditions, changes in tax laws, regulations or other governmental policies; and whether the Company has the intent to sell the security or more likely than not will be required to sell the security before the recovery of its amortized cost basis. If the decline in value of our equity securities is determined to be other-than-temporary, an impairment is recognized through earnings within other income, net on the Consolidated Statements of Operations.

During fiscal 2018, NJR sold shares of its available for sale securities and received proceeds of approximately $6.6 million and realized a pre-tax gain of approximately $5.3 million, which is included in other income, net on the Consolidated Statements of Operations, or $3.2 million, net of tax. During fiscal 2017, NJR received proceeds of approximately $6.6 million and realized a pre-tax gain of $5.4 million, or $3.2 million, net of tax. Reclassifications of realized gains out of other comprehensive income into income are determined based on average cost.

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, 2018, intangible assets consist of internal-use software costs of $513,000 and $22.9 million, net of amortization, related to its acquisition of Talen’s wholesale natural gas energy contracts. These contracts are being amortized based upon expected cash flows over the respective terms of the agreements. The estimated future amortization expense for the next five years as of September 30, is as follows:

(Thousands)
2019	$	8,424
2020	$	4,925
2021	$	4,604
2022	$	2,561
2023	$	2,271
Thereafter	$	77

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. During the year, the Company evaluated whether there were such events or circumstances that occurred, including evaluation of the new clean energy legislation signed in May 2018, and concluded that there were no events or circumstances in the current year that indicated that the carrying value of long-lived assets or finite-lived intangibles is 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 8. 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 at the end of the term or repurchase the asset. Proceeds from sale-leaseback transactions are accounted for as financings and are included in long-term debt on the Consolidated Balance Sheets. During fiscal 2018 and 2017, NJNG received $7.8 million and $9.6 million, respectively, in connection with the sale-leaseback of its natural gas meters with terms ranging from seven to 11 years.

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 terms of the arrangement create a continuing involvement in the asset and the asset is considered integral equipment, the Company uses the financing method to account for the transaction. Under the financing method, the Company recognizes the proceeds received from the lessor that constitute a payment to acquire the solar energy asset as a financing arrangement, which is recorded as a component of debt on the Consolidated Balance Sheets.

Clean Energy Ventures received $71.5 million and $32.9 million in proceeds related to the sale of commercial solar assets during fiscal 2018 and 2017, respectively. Clean Energy Ventures simultaneously entered into agreements to lease the assets back over six to 15-year terms. The Company will continue to operate the solar assets and is responsible for related expenses and entitled to retain the revenue generated from SRECs and energy sales. The ITCs and other tax benefits associated with these solar projects have been transferred to the buyer; however, the lease payments are structured so that Clean Energy Ventures is compensated for the transfer of the related tax incentives. Accordingly, Clean Energy Ventures recognizes the equivalent value of the ITC 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. Clean Energy Ventures did not enter into sale-leaseback during fiscal 2016 and therefore recognized the full ITC in income tax (benefit) provision on the Consolidated Statements of Operations when the assets were placed in service.

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 the 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 13. 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 made a discretionary contribution of $30 million during the first quarter of fiscal 2016 to improve the funded status of the pension plans based on the current actuarial assumptions, which included the adoption of the most recent mortality table. The Company made no discretionary contributions to the pension plans in fiscal 2018 and 2017.

The Company also provides two primarily noncontributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds.

Asset Retirement Obligations

Asset Retirement Obligations

The Company recognizes AROs related to the costs associated with cutting and capping NJNG’s main and service gas distribution mains, which is required by New Jersey law when taking such gas distribution mains out of service. The Company also recognizes AROs associated with Clean Energy Ventures’ solar and wind assets when there are decommissioning provisions in lease agreements that require removal of the asset at the end of the lease term.

AROs 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 Clean Energy Ventures’ 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 AROs 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 assign probabilities based on management’s reasonable judgment and knowledge of industry practice. Accordingly, AROs are subject to change.

Foreign Currency Transactions

Foreign Currency Transactions

The market area of Energy Services includes Canadian delivery points and as a result, Energy Services incurs certain natural gas commodity costs and demand fees denominated in Canadian dollars. Gains or losses that occur as a result of these foreign currency transactions are reported as a component of gas purchases on the Consolidated Statements of Operations. Gains and losses recognized for the fiscal years ended September 30, 2018, 2017 and 2016, are considered immaterial.

Recent Updates to the Accounting Standards Codification

Recently Adopted Updates to the Accounting Standards Codification

Inventory

In July 2015, the FASB issued ASU No. 2015-11, an amendment to ASC 330, Inventory, which requires entities to measure most inventory “at the lower of cost or net realizable value,” thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. The Company adopted the new guidance in the first quarter of fiscal 2018 and applied the new provisions on a prospective basis, which did not impact its financial position, results of operations or cash flows upon adoption.

Reporting Comprehensive Income

In February 2018, the FASB issued ASU No. 2018-02, an amendment to ASC 220, Income Statement - Reporting Comprehensive Income, which allows for the reclassification from accumulated other comprehensive income to retained earnings for the disproportionate tax effects of the Tax Act. The Company early adopted this guidance in the fourth quarter of fiscal 2018 and reclassified on a prospective basis only, $3.3 million from accumulated other comprehensive income to retained earnings. This did not materially impact the Company’s financial position, results of operations or cash flows.

Tax

In March 2018, the FASB issued ASU No. 2018-05, an amendment to ASC 740, Income Taxes, which provides relief to entities in their calculation of the effects of the Tax Act by allowing them to record provisional amounts for certain income tax effects to address circumstances in which an entity does not have the necessary information available, prepared or analyzed to complete the accounting. These provisional amounts are subject to change as information and assumptions are updated throughout the measurement period, which may not extend beyond one year from the enactment date. The new guidance was effective immediately upon issuance, and the Company adopted the new guidance in the second quarter of fiscal 2018 and applied the new provision on a prospective basis.

Other Recent Updates to the Accounting Standards Codification

Revenue

In May 2014, the FASB issued ASU No. 2014-09, and added ASC 606, Revenue from Contracts with Customers, to the ASC. ASC 606 supersedes ASC 605, Revenue Recognition, as well as most industry-specific guidance, and prescribes a single, comprehensive revenue recognition model designed to improve financial reporting comparability across entities, industries, jurisdictions and capital markets. The Company adopted the new guidance on October 1, 2018, and will apply the new provisions on a modified retrospective basis.

Management established an implementation team to evaluate the impact on the Company’s financial position, results of operations and cash flows upon adoption of ASC 606. This implementation team reviewed the revenue streams of all of its subsidiaries and formed conclusions to determine if any system, process, controls and organizational changes are necessary upon adoption. The assessment of the impact of this guidance included reviewing the Company’s accounting policies under ASC 605 and identifying potential differences after the adoption of ASC 606. The Company concluded that its tariff-based sales of natural gas will be within the scope of the new guidance and it does not anticipate any modification to the pattern of revenue recognition from such sales. Revenues from derivative instruments such as those related to the Company’s SREC sales and natural gas purchases and sales will continue to be accounted for under ASC 815 and thus are outside the scope of ASC 606. Additionally, NJNG revenues generated by the CIP have been determined to be alternative revenue programs under ASC 980 and are also outside the scope of ASC 606 as they are deemed to be a contract with the regulator. The Company also evaluated its renewable asset PPA arrangements and does not anticipate any modification to the pattern of revenue recognition of the related electricity, capacity and REC sales. Revenues from RECs sold as part of a bundled arrangement will be recognized in the same period as the related generation, consistent with current practice.

The Company has completed its evaluation of its revenue streams, and based on the assessment performed, has concluded that the new guidance will not have a material impact on its financial position, results of operations or cash flows upon adoption. Additionally, the Company did not implement significant changes to its business processes, systems or internal controls over financial reporting upon adoption. ASC 606 requires expanded disclosures, including the disclosure of performance obligations, disaggregated revenues and contract balances, which the Company will include in its financial statements beginning in the first quarter of fiscal 2019.

Financial Instruments

In January 2016, the FASB issued ASU No. 2016-01, an amendment to ASC 825, Financial Instruments, to address certain aspects of the recognition, measurement, presentation and disclosure of financial instruments. The standard affects investments in equity securities that do not result in consolidation and are not accounted for under the equity method and the presentation of certain fair value changes for financial liabilities measured at fair value. It also simplifies the impairment assessment of equity investments without a readily determinable fair value by requiring a qualitative assessment. The guidance is effective for the Company beginning October 1, 2018. The amendment will be applied on a modified retrospective basis. The Company evaluated the amendment and noted that, upon adoption, subsequent changes to the fair value of the Company’s available for sale securities will be recorded in the Consolidated Statement of Operations as opposed to other comprehensive income. The Company will reclassify $3.4 million in accumulated other comprehensive income related to available for sale securities to the opening balance of retained earnings as of October 1, 2018. There will be no material impact to the Company’s financial position, results of operations or cash flows upon adoption.

In June 2016, the FASB issued ASU No. 2016-13, an amendment to ASC 326, Financial Instruments - Credit Losses, which changes the impairment model for certain financial assets that have a contractual right to receive cash, including trade and loan receivables. The new model requires recognition based upon an estimation of expected credit losses rather than recognition of losses when it is probable that they have been incurred. An entity will apply the amendment through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. The Company is currently evaluating the amendment to understand the impact on its financial position, results of operations and cash flows upon adoption and will apply the new guidance to its trade and loan receivables on a modified retrospective basis.

Leases

In February 2016, the FASB issued ASU No. 2016-02, an amendment to ASC 842, Leases, which provides for a comprehensive overhaul of the lease accounting model and changes the definition of a lease within the accounting literature. Under the new standard, all leases with a term greater than one year will be recorded on the balance sheet. Amortization of the related asset will be accounted for using one of two approaches prescribed by the guidance. Additional disclosures will be required to allow the user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach is required for leases existing at the time of adoption.

In January 2018, the FASB issued ASU No. 2018-01, a further amendment to ASC 842, Leases, which was introduced by ASU No. 2016-02, as discussed above. This update provides an optional practical expedient that allows companies to not evaluate existing or expired land easements that were not previously accounted for under Topic 840 as leases. The Company expects to elect this practical expedient upon adoption. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted.

In July 2018, the FASB issued ASU No. 2018-11, which provides an optional transition method to ASC 842 that allows the Company to recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. At this time, the Company does not plan to early adopt the new guidance and expects to transition on a modified retrospective basis. While the Company is currently evaluating the full impact of the standard and its related updates, it expects to recognize additional assets and liabilities arising from current operating leases to its financial position upon adoption. Current operating leases primarily consist of office and land leases related to the Company’s solar and wind assets.

Statement of Cash Flows

In August 2016, the FASB issued ASU No. 2016-15, an amendment to ASC 230, Statement of Cash Flows, which addresses eight specific cash flow issues for which there has been diversity in practice. The guidance is effective for the Company beginning October 1, 2018. The amendment will be applied on a retrospective basis and the Company does not expect any material impacts to its statement of cash flows.

In November 2016, the FASB issued ASU No. 2016-18, an amendment to ASC 230, Statement of Cash Flows, which requires that any amounts that are deemed to be restricted cash or restricted cash-equivalents be included in cash and cash-equivalent balances on the cash flow statement and, therefore, transfers between cash and restricted cash accounts will no longer be recognized within the statement of cash flows. The guidance is effective for the Company beginning October 1, 2018, and will be applied on a retrospective basis. Based on the Company's historical restricted cash balances, it does not expect any material impacts to its statement of cash flows.

Intangibles

In August 2018, the FASB issued ASU No. 2018-15, an amendment to ASC 350, Intangibles - Goodwill and Other, which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. Upon adoption, the amendment will be applied on a prospective or retrospective basis.

Business Combinations

In January 2017, the FASB issued ASU No. 2017-01, an amendment to ASC 805, Business Combinations, clarifying the definition of a business in the ASC, which is intended to reduce the complexity surrounding the assessment of a transaction as an asset acquisition or business combination. The amendment provides an initial fair value screen to reduce the number of transactions that would fit the definition of a business, and when the screen threshold is not met, provides an updated model that further clarifies the characteristics of a business. The guidance is effective for the Company beginning October 1, 2018, and will be applied on a prospective basis. The amendment could potentially have material impacts on future transactions that the Company may enter into by altering the Company’s conclusion on the accounting framework that is applied to acquisitions.

Gains and Losses from the Derecognition of Nonfinancial Assets

In February 2017, the FASB issued ASU No. 2017-05, an amendment to ASC 610-20, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets, which clarifies the scope and accounting related to the derecognition of nonfinancial assets, including partial sales and contributions of nonfinancial assets to a joint venture or other non-controlled investee. The guidance is effective concurrently with ASC 606, which is effective for the Company as of October 1, 2018 and will be applied retrospectively with a cumulative effect adjustment at the date of adoption. The Company had a deferred gain of $6.8 million related to nonfinancial assets on the balance sheet, which will be recognized under the new accounting guidance as a cumulative effect adjustment to the opening balance of retained earnings as of October 1, 2018.

Compensation - Retirement Benefits

In March 2017, the FASB issued ASU No. 2017-07, an amendment to ASC 715, Compensation - Retirement Benefits, which changes the presentation of net periodic benefit cost on the income statement by requiring companies to present all components of net periodic benefit cost, other than service cost, outside a subtotal of income from operations. The amendment also states that only the service cost component of net periodic benefits costs is eligible for capitalization, when applicable. The amendment establishes a practical expedient that permits entities to use their previously disclosed service and other costs in their pension and other postretirement benefit plan footnotes in the prior comparative periods as the estimation basis when applying the retrospective presentation of these costs in the income statement. The guidance is effective for the Company beginning October 1, 2018, and will be applied on a retrospective basis for income statement presentation, and on a prospective basis for changes to capitalization of costs. The changes related to the costs that will be eligible for capitalization and based on the components of net periodic benefit costs during fiscal year 2018, will not have a material impact on the Company's financial position, results of operations or cash flows upon adoption

In August 2018, the FASB issued ASU No. 2018-14, an amendment to ASC 715, Compensation - Retirement Benefits, which removes disclosures that no longer are considered cost-beneficial, clarifies the specific requirements of certain disclosures, and adds new disclosure requirements identified as relevant. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. Upon adoption, the amendments will be applied on a retrospective basis. The Company is continuing to evaluate the amendment to fully understand the impact on the Company's disclosures upon adoption.

Stock Compensation

In May 2017, the FASB issued ASU No. 2017-09, an amendment to ASC 718, Compensation - Stock Compensation, which clarifies the accounting for changes to the terms or conditions of share-based payments. The guidance is effective for the Company beginning October 1, 2018, and will be applied prospectively to awards modified on or after the adoption date. There was no material impact to the Company's financial position, results of operations or cash flows upon adoption.

In June 2018, the FASB issued ASU No. 2018-07, an amendment to ASC 718, Compensation - Stock Compensation, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. The guidance is effective for the Company beginning October 1, 2019, with early adoption permitted. The Company is currently evaluating the impact of the amendment on the Company’s financial position, results of operations and cash flows upon adoption.

Derivatives and Hedging

In August 2017, the FASB issued ASU No. 2017-12, an amendment to ASC 815, Derivatives and Hedging, which is intended to make targeted improvements to the accounting for hedging activities by better aligning an entity’s risk management activities and financial reporting for hedging relationships. These amendments modify the accounting for both nonfinancial and financial risk components and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. Additionally, the amendments are intended to simplify the application of the hedge accounting guidance and provide relief to companies by easing certain hedge documentation requirements. The guidance is effective for the Company beginning October 1, 2019, with early adoption permitted. Upon adoption, the transition requirements and elections will be applied to hedging relationships existing on the date of adoption. The Company does not currently apply hedge accounting to any of its risk management activities and thus does not expect the amendments to have any impact on its financial position, results of operations and cash flows upon adoption.

Fair Value

In August 2018, the FASB issued ASU No. 2018-13, an amendment to ASC 820, Fair Value Measurement, which removes, modifies and adds to certain disclosure requirements of fair value measurements. Disclosure requirements removed include the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the valuation processes for Level 3 fair value measurements. Modifications include considerations around the requirement to disclose the timing of liquidation of an investee’s assets and the date when restrictions from redemption might lapse. The additions include the requirement to disclose changes in unrealized gains and losses for the period in other comprehensive income for recurring Level 3 fair value measurements held and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The guidance is effective for the Company beginning October 1, 2020, with early adoption permitted. Upon adoption, the amendments will be applied on a prospective or retrospective basis depending on the specific amendments’ transition requirements. The Company is currently evaluating the amendments to understand the impact on its financial position, results of operations, cash flows and disclosures upon adoption and will apply the new guidance.

Fair Value Hierarchy

Fair Value Hierarchy

The Company applies fair value measurement guidance to its financial assets and liabilities, as appropriate, which include financial derivatives and physical commodity contracts qualifying as derivatives, available for sale securities and other financial assets and liabilities. In addition, authoritative accounting literature prescribes the use of a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value based on the source of the data used to develop the price inputs.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to inputs that are based on unobservable market data and includes the following:

Level 1 Unadjusted quoted prices for identical assets or liabilities in active markets. The Company’s Level 1 assets and liabilities include exchange traded natural gas futures and options contracts, listed equities and money market funds. Exchange traded futures and options contracts include all energy contracts traded on the NYMEX, CME and ICE that the Company refers internally to as basis swaps, fixed swaps, futures and financial options that are cleared through a FCM.

Level 2 Other significant observable inputs, such as interest rates or price data, including both commodity and basis pricing that is observed either directly or indirectly from publications or pricing services. The Company’s Level 2 assets and liabilities include over-the-counter physical forward commodity contracts and swap contracts, SREC forward sales or derivatives that are initially valued using observable quotes and are subsequently adjusted to include time value, credit risk or estimated transport pricing components for which no basis price is available. Level 2 financial derivatives consist of transactions with non-FCM counterparties (basis swaps, fixed swaps and/or options). Inputs are verifiable and do not require significant management judgment. For some physical commodity contracts, the Company utilizes transportation tariff rates that are publicly available and that it considers to be observable inputs that are equivalent to market data received from an independent source. There are no significant judgments or adjustments applied to the transportation tariff inputs and no market perspective is required. Even if the transportation tariff input were considered to be a “model,” it would still be considered to be a Level 2 input as the data is:

• widely accepted and public;

• non-proprietary and sourced from an independent third party; and

• observable and published.

These additional adjustments are generally not considered to be significant to the ultimate recognized values.

Level 3 Inputs derived from a significant amount of unobservable market data. These include the Company’s best estimate of fair value and are derived primarily through the use of internal valuation methodologies.

Financial derivative portfolios of NJNG and Energy Services consist mainly of futures, options and swaps. The Company primarily uses the market approach and its policy is to use actively quoted market prices when available. The principal market for its derivative transactions is the natural gas wholesale market; therefore, the primary sources for its price inputs are CME, NYMEX and ICE. Energy Services uses Platts and Natural Gas Exchange for Canadian delivery points. However, Energy Services also engages in transactions that result in transporting natural gas to delivery points for which there is no actively quoted market price. In most instances, the transportation cost to the final delivery location is not significant to the overall valuation. If required, Energy Services’ policy is to use the best information available to determine fair value based on internal pricing models, which would include estimates extrapolated from broker quotes or other pricing services.

The Company also has available for sale securities and other financial assets that include listed equities, mutual funds and money market funds for which there are active exchange quotes available.

When the Company determines fair values, measurements are adjusted, as needed, for credit risk associated with its counterparties, as well as its own credit risk. The Company determines these adjustments by using historical default probabilities that correspond to the applicable S&P issuer ratings, while also taking into consideration collateral and netting arrangements that serve to mitigate risk.

Reclassification

Reclassification

Certain prior period amounts related to the amortization of acquired wholesale energy contracts on the Consolidated Statements of Cash Flows and in the deferred tax table in Note 12. Income Taxes for the fiscal year ended September 30, 2017, were reclassified to conform to the current period presentation.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Sep. 30, 2018

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 gas purchases on the Consolidated Statements of Operations for the fiscal years ended September 30:

(Millions)	2018		2017		2016
Energy Services	$	153.0	$	126.4	$	141.0
Natural Gas Distribution	92.5		80.2		77.8
Total	$	245.5	$	206.6	$	218.8

Schedule of Property, Plant and Equipment

Property, plant and equipment was comprised of the following as of September 30:

(Thousands)
Property Classifications	Estimated Useful Lives	2018			2017
Distribution facilities	38 to 74 years	$	2,151,249		$	1,952,697
Transmission facilities	35 to 56 years	295,692			294,586
Storage facilities	34 to 47 years	79,470			78,245
Solar property	20 to 25 years	720,562			587,345
Wind property(1)	17 to 25 years	—			244,764
Midstream property(2)	30 years	6,747			—
All other property	5 to 35 years	50,771			53,433
Total property, plant and equipment		3,304,491			3,211,070
Accumulated depreciation and amortization		(653,442		)	(601,329		)
Property, plant and equipment, net		$	2,651,049		$	2,609,741

(1) Reclassified to assets held for sale. See Note 2. Summary of Significant Accounting Policies, for more information.

(2) Includes activity related to the acquisition of IEC by Adelphia. For fiscal 2017, Midstream property was originally included in All other property.

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)	2018			2017			2016
AFUDC:
Debt	$	1,979		$	1,311		$	5,009
Equity	5,531			3,867			4,375
Total	$	7,510		$	5,178		$	9,384
Weighted average interest rate	5.94		%	6.90		%	5.06		%

Summary of Customer Accounts Receivable by Company

The following table summarizes customer accounts receivable by company as of September 30:

(Thousands)	2018				2017
Energy Services	$	157,936	77	%	$	150,322	77	%
Natural Gas Distribution (1)	39,151		19		37,432		19
Clean Energy Ventures	3,330		2		2,655		1
Home Services and Other Operations	5,073		2		6,058		3
Total	$	205,490	100	%	$	196,467	100	%

(1) Does not include unbilled revenues of $7.2 million as of September 30, 2018 and 2017.

Summary of Gas in Storage

The following table summarizes gas in storage, at average cost by company, as of September 30:

	2018				2017
($ in thousands)	Gas in Storage			Bcf	Gas in Storage			Bcf
Energy Services		$	90,166	34.1		$	122,884	53.9
Natural Gas Distribution		94,467		24.9		79,179		21.8
Total		$	184,633	59.0		$	202,063	75.7

Schedule of Disposal Groups, Including Discontinued Operations

The major classes of assets and liabilities included within the disposal group as held for sale are as follows:

(Thousands)	September 30, 2017		Assets reclassified as held for sale			Assets Sold			September 30, 2018
Assets held for sale:
Property, plant and equipment - wind equipment, at cost	$	—	$	245,044		$	(20,688	)	$	224,356
Property, plant and equipment - accumulated depreciation, wind equipment	—		(21,561		)	3,060			(18,501		)
Prepaid and accrued taxes	—		866			(77		)	789
Other noncurrent assets	—		261			—			261
	$	—	$	224,610		$	(17,705	)	$	206,905
Liabilities held for sale:
Accounts payable and other (1)	$	—	$	—		$	186		$	186
Asset retirement obligation	—		4,262			(266		)	3,996
	$	—	$	4,262		$	(80	)	$	4,182

(1) Transaction fee owed to broker for the sale of Two Dot wind farm.

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

The estimated future amortization expense for the next five years as of September 30, is as follows:

(Thousands)
2019	$	8,424
2020	$	4,925
2021	$	4,604
2022	$	2,561
2023	$	2,271
Thereafter	$	77

Changes in Components of Accumulated Other Comprehensive Income, Net

The following table presents the changes in the components of accumulated other comprehensive income, net of related tax effects, as of September 30:

(Thousands)	Unrealized gain (loss) on available for sale securities			Adjustment to postemployment benefit obligation				Total
Balance as of September 30, 2016	$	4,198		$	(19,353	)		$	(15,155	)
Other comprehensive income, net of tax
Other comprehensive income, before reclassifications, net of tax of $(6,593), $(2,619), $(9,212)	10,019			3,783				13,802
Amounts reclassified from accumulated other comprehensive (loss) income, net of tax of $2,192, $(868), $1,324	(3,173		)	1,270			(1)	(1,903		)
Net current-period other comprehensive income, net of tax of $(4,401), $(3,487), $(7,888)	6,846			5,053				11,899
Balance at September 30, 2017	$	11,044		$	(14,300	)		$	(3,256	)
Other comprehensive income, net of tax
Other comprehensive (loss) income, before reclassifications, net of tax of $6,973, $(125), $6,848	(19,245		)	464				(18,781		)
Amounts reclassified from accumulated other comprehensive income, net of tax of $(858), $(448), $(1,306)	11,647			1,056			(1)	12,703
Net current-period other comprehensive (loss) income, net of tax of $6,115, $(573), $5,542	(7,598		)	1,520				(6,078		)
Reclassifications of certain income tax effects to retained earnings (2)	—			(3,276		)		(3,276		)
Balance at September 30, 2018	$	3,446		$	(16,056	)		$	(12,610	)

(1) Included in the computation of net periodic pension cost, a component of O&M expense on the Consolidated Statements of Operations. For more details, see Note 10. Employee Benefit Plans.

(2) Due to the adoption of ASU No. 2018-02, an amendment to ASC 740, Income Taxes. See Note 2. Summary of Significant Accounting Policies- Recently Adopted Updates to the Accounting Standards Codification section for more details.

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REGULATION (Tables)

12 Months Ended

Sep. 30, 2018

Regulated Operations [Abstract]

Schedule of Regulatory Assets

Regulatory assets and liabilities included on the Consolidated Balance Sheets as of September 30, are composed of the following:

(Thousands)	2018		2017
Regulatory assets-current
New Jersey Clean Energy Program	$	14,052	$	14,202
Underrecovered gas costs	4,137		9,910
Derivatives at fair value, net	108		9,010
Conservation Incentive Program	—		17,669
Total current regulatory assets	$	18,297	$	50,791
Regulatory assets-noncurrent
Environmental remediation costs:
Expended, net of recoveries	$	33,017	$	28,547
Liability for future expenditures	130,800		149,000
Deferred income taxes	17,225		21,795
SAVEGREEN	8,636		16,302
Postemployment and other benefit costs	136,716		141,433
Deferred storm damage costs	10,858		13,030
Cost of removal	22,339		—
Other noncurrent regulatory assets	9,001		5,812
Total noncurrent regulatory assets	$	368,592	$	375,919
Regulatory liability-current
Conservation Incentive Program	$	6,994	$	—
Derivatives at fair value, net	1,191		78
Total current regulatory liabilities	$	8,185	$	78
Regulatory liabilities-noncurrent
Tax Act impact (1)	$	205,410	$	—
Cost of removal	—		7,902
New Jersey Clean Energy Program	1,902		5,795
Other noncurrent regulatory liabilities	1,827		810
Total noncurrent regulatory liabilities	$	209,139	$	14,507

Schedule of Regulatory Liabilities

Regulatory assets and liabilities included on the Consolidated Balance Sheets as of September 30, are composed of the following:

(Thousands)	2018		2017
Regulatory assets-current
New Jersey Clean Energy Program	$	14,052	$	14,202
Underrecovered gas costs	4,137		9,910
Derivatives at fair value, net	108		9,010
Conservation Incentive Program	—		17,669
Total current regulatory assets	$	18,297	$	50,791
Regulatory assets-noncurrent
Environmental remediation costs:
Expended, net of recoveries	$	33,017	$	28,547
Liability for future expenditures	130,800		149,000
Deferred income taxes	17,225		21,795
SAVEGREEN	8,636		16,302
Postemployment and other benefit costs	136,716		141,433
Deferred storm damage costs	10,858		13,030
Cost of removal	22,339		—
Other noncurrent regulatory assets	9,001		5,812
Total noncurrent regulatory assets	$	368,592	$	375,919
Regulatory liability-current
Conservation Incentive Program	$	6,994	$	—
Derivatives at fair value, net	1,191		78
Total current regulatory liabilities	$	8,185	$	78
Regulatory liabilities-noncurrent
Tax Act impact (1)	$	205,410	$	—
Cost of removal	—		7,902
New Jersey Clean Energy Program	1,902		5,795
Other noncurrent regulatory liabilities	1,827		810
Total noncurrent regulatory liabilities	$	209,139	$	14,507

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DERIVATIVE INSTRUMENTS (Tables)

12 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value of Derivative Assets and Liabilities

The following table reflects the fair value of the Company’s derivative assets and liabilities recognized on the Consolidated Balance Sheets as of September 30:

			Fair Value
			2018						2017
(Thousands)	Balance Sheet Location	Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments:
Natural Gas Distribution:
Physical commodity contracts	Derivatives - current		$	85		$	192		$	151		$	72
Financial commodity contracts	Derivatives - current		94			—			—			1,149
Interest rate contracts (1)	Derivatives - current		—			—			—			8,467
Energy Services:
Physical commodity contracts	Derivatives - current		7,667			18,158			14,588			16,589
	Derivatives - noncurrent		3,930			11,316			7,127			8,710
Financial commodity contracts	Derivatives - current		19,169			28,176			15,302			20,267
	Derivatives - noncurrent		6,630			11,548			2,033			2,620
Foreign currency contracts	Derivatives - current		—			126			40			—
	Derivatives - noncurrent		—			118			4			—
Home Services and Other:
Interest rate contracts	Derivatives - current		381			—			—			—
Total fair value of derivatives			$	37,956		$	69,634		$	39,245		$	57,874

(1) Includes treasury lock which was settled in March 2018. See Note 8. Debt for more information.

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.

(Thousands)	Amounts Presented in Balance Sheets (1)			Offsetting Derivative Instruments (2)				Financial Collateral Received/Pledged (3)				Net Amounts (4)
As of September 30, 2018:
Derivative assets:
Energy Services
Physical commodity contracts		$	11,597		$	(3,944	)		$	(200	)		$	7,453
Financial commodity contracts		25,799			(18,775		)		—				7,024
Total Energy Services		$	37,396		$	(22,719	)		$	(200	)		$	14,477
Natural Gas Distribution
Physical commodity contracts		$	85		$	(3	)		$	—			$	82
Financial commodity contracts		94			—				(94		)		—
Total Natural Gas Distribution		$	179		$	(3	)		$	(94	)		$	82
Home Services and Other
Interest rate contracts		$	381		$	—			$	—			$	381
Total Home Services and Other		$	381		$	—			$	—			$	381
Derivative liabilities:
Energy Services
Physical commodity contracts		$	29,474		$	(3,944	)		$	—			$	25,530
Financial commodity contracts		39,724			(18,775		)		(20,949		)		—
Foreign currency contracts		244			—				—				244
Total Energy Services		$	69,442		$	(22,719	)		$	(20,949	)		$	25,774
Natural Gas Distribution
Physical commodity contracts		$	192		$	(3	)		$	—			$	189
Total Natural Gas Distribution		$	192		$	(3	)		$	—			$	189
As of September 30, 2017:
Derivative assets:
Energy Services
Physical commodity contracts		$	21,715		$	(2,173	)		$	(200	)		$	19,342
Financial commodity contracts		17,335			(14,121		)		—				3,214
Foreign currency contracts		44			—				—				44
Total Energy Services		$	39,094		$	(16,294	)		$	(200	)		$	22,600
Natural Gas Distribution
Physical commodity contracts		$	151		$	(20	)		$	—			$	131
Total Natural Gas Distribution		$	151		$	(20	)		$	—			$	131
Derivative liabilities:
Energy Services
Physical commodity contracts		$	25,299		$	(2,173	)		$	—			$	23,126
Financial commodity contracts		22,887			(14,121		)		(8,766		)		—
Total Energy Services		$	48,186		$	(16,294	)		$	(8,766	)		$	23,126
Natural Gas Distribution
Physical commodity contracts		$	72		$	(20	)		$	—			$	52
Financial commodity contracts		1,149			—				(1,149		)		—
Interest rate contracts		8,467			—				—				8,467
Total Natural Gas Distribution		$	9,688		$	(20	)		$	(1,149	)		$	8,519

(1) Derivative assets and liabilities are presented on a gross basis in the balance sheet as the Company does not elect balance sheet offsetting under ASC 210-20.

(2) Offsetting derivative instruments include transactions with NAESB netting election, transactions held by FCMs with net margining and transactions with ISDA netting.

(3) Financial collateral includes cash balances at FCMs, as well as cash received from or pledged to other counterparties.

(4) Net amounts represent presentation of derivative assets and liabilities if the Company were to elect balance sheet offsetting under ASC 210-20.

Offsetting Liabilities

The following table summarizes the reported gross amounts, the amounts that the Company has the right to offset but elects not to, financial collateral and the net amounts the Company could present on the Consolidated Balance Sheets but elects not to.

(Thousands)	Amounts Presented in Balance Sheets (1)			Offsetting Derivative Instruments (2)				Financial Collateral Received/Pledged (3)				Net Amounts (4)
As of September 30, 2018:
Derivative assets:
Energy Services
Physical commodity contracts		$	11,597		$	(3,944	)		$	(200	)		$	7,453
Financial commodity contracts		25,799			(18,775		)		—				7,024
Total Energy Services		$	37,396		$	(22,719	)		$	(200	)		$	14,477
Natural Gas Distribution
Physical commodity contracts		$	85		$	(3	)		$	—			$	82
Financial commodity contracts		94			—				(94		)		—
Total Natural Gas Distribution		$	179		$	(3	)		$	(94	)		$	82
Home Services and Other
Interest rate contracts		$	381		$	—			$	—			$	381
Total Home Services and Other		$	381		$	—			$	—			$	381
Derivative liabilities:
Energy Services
Physical commodity contracts		$	29,474		$	(3,944	)		$	—			$	25,530
Financial commodity contracts		39,724			(18,775		)		(20,949		)		—
Foreign currency contracts		244			—				—				244
Total Energy Services		$	69,442		$	(22,719	)		$	(20,949	)		$	25,774
Natural Gas Distribution
Physical commodity contracts		$	192		$	(3	)		$	—			$	189
Total Natural Gas Distribution		$	192		$	(3	)		$	—			$	189
As of September 30, 2017:
Derivative assets:
Energy Services
Physical commodity contracts		$	21,715		$	(2,173	)		$	(200	)		$	19,342
Financial commodity contracts		17,335			(14,121		)		—				3,214
Foreign currency contracts		44			—				—				44
Total Energy Services		$	39,094		$	(16,294	)		$	(200	)		$	22,600
Natural Gas Distribution
Physical commodity contracts		$	151		$	(20	)		$	—			$	131
Total Natural Gas Distribution		$	151		$	(20	)		$	—			$	131
Derivative liabilities:
Energy Services
Physical commodity contracts		$	25,299		$	(2,173	)		$	—			$	23,126
Financial commodity contracts		22,887			(14,121		)		(8,766		)		—
Total Energy Services		$	48,186		$	(16,294	)		$	(8,766	)		$	23,126
Natural Gas Distribution
Physical commodity contracts		$	72		$	(20	)		$	—			$	52
Financial commodity contracts		1,149			—				(1,149		)		—
Interest rate contracts		8,467			—				—				8,467
Total Natural Gas Distribution		$	9,688		$	(20	)		$	(1,149	)		$	8,519

(1) Derivative assets and liabilities are presented on a gross basis in the balance sheet as the Company does not elect balance sheet offsetting under ASC 210-20.

(2) Offsetting derivative instruments include transactions with NAESB netting election, transactions held by FCMs with net margining and transactions with ISDA netting.

(3) Financial collateral includes cash balances at FCMs, as well as cash received from or pledged to other counterparties.

(4) Net amounts represent presentation of derivative assets and liabilities if the Company were to elect balance sheet offsetting under ASC 210-20.

Effect of Derivative Instruments on the Consolidated Statements of Operations

The following table reflects the effect of derivative instruments on the Consolidated Statements of Operations as of September 30:

(Thousands)	Location of gain (loss) recognized in income on derivatives	Amount of gain (loss) recognized in income on derivatives
Derivatives not designated as hedging instruments:		2018			2017			2016
Energy Services:
Physical commodity contracts	Operating revenues	$	(9,311	)	$	8,912		$	33,034
Physical commodity contracts	Gas purchases	(197		)	(27,461		)	(45,637		)
Financial commodity contracts	Gas purchases	(24,622		)	26,563			45,579
Foreign currency contracts	Gas purchases	(379		)	41			(34		)
Home Services and Other:
Interest rate contracts	Interest expense	334			—			—
Total unrealized and realized gains (losses)		$	(34,175	)	$	8,055		$	32,942

The following table reflects the (losses) gains associated with NJNG’s derivative instruments as of September 30:

(Thousands)	2018		2017			2016
Natural Gas Distribution:
Physical commodity contracts	$	1,232	$	(12,303	)	$	(15,756	)
Financial commodity contracts	1,844		5,595			(7,984		)
Interest rate contracts	8,467		14,606			(18,845		)
Total unrealized and realized (losses) gains	$	11,543	$	7,898		$	(42,585	)

Schedule of Outstanding Long (Short) Derivatives

NJNG and Energy Services had the following outstanding long (short) derivatives as of September 30:

		Volume (Bcf)
		2018		2017
Natural Gas Distribution	Futures	27.9		18.2
	Physical	23.1		32.1
Energy Services	Futures	(7.0	)	(16.4	)
	Physical	51.2		(13.1	)

Schedule of Due to (from) Broker-Dealers and Clearing Organizations

The balances as of September 30, by segment, are as follows:

(Thousands)	Balance Sheet Location	2018		2017
Natural Gas Distribution	Broker margin - Current assets	$	2,038	$	2,661
Energy Services	Broker margin - Current assets	$	51,681	$	23,166

Schedules of Concentration of Risk, by Risk Factor

The following is a summary of gross credit exposures grouped by investment and noninvestment grade counterparties, as of September 30, 2018.The amounts presented below have not been reduced by any collateral received or netting and exclude accounts receivable for NJNG retail natural gas sales and services and Clean Energy Ventures residential solar installations.

(Thousands)	Gross Credit Exposure
Investment grade		$	179,982
Noninvestment grade		43,486
Internally-rated investment grade		30,786
Internally-rated noninvestment grade		25,750
Total		$	280,004

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FAIR VALUE (Tables)

12 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Estimated Fair Value of Long-term Debt

As of September 30, the estimated fair value of long-term debt at NJNG and NJR, including current maturities, excluding capital leases, debt issuance costs and solar asset financing obligations, is as follows ⁽¹⁾:

(Thousands)	2018		2017
NJNG
Carrying value	$	672,045	$	672,045
Fair market value	$	669,162	$	673,051
NJR
Carrying value	$	500,000	$	425,000
Fair market value	$	488,889	$	434,625

(1) SeeNote 8. Debt for a reconciliation to long-term and short-term debt.

Assets and Liabilities Measured at Fair Value on Recurring Basis

Assets and liabilities measured at fair value on a recurring basis are summarized as follows:

	Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
(Thousands)	(Level 1)			(Level 2)			(Level 3)			Total
As of September 30, 2018:
Assets
Physical commodity contracts		$	—		$	11,682		$	—	$	11,682
Financial commodity contracts		18,868			7,025			—		25,893
Financial commodity contracts - foreign exchange		—			—			—		—
Interest rate contract		—			381			—		381
Available for sale equity securities		32,917			—			—		32,917
Other (1)		1,217			—			—		1,217
Total assets at fair value		$	53,002		$	19,088		$	—	$	72,090
Liabilities
Physical commodity contracts		$	—		$	29,666		$	—	$	29,666
Financial commodity contracts		39,724			—			—		39,724
Financial commodity contracts - foreign exchange		—			244			—		244
Total liabilities at fair value		$	39,724		$	29,910		$	—	$	69,634
As of September 30, 2017:
Assets
Physical commodity contracts		$	—		$	21,866		$	—	$	21,866
Financial commodity contracts		17,335								17,335
Financial commodity contracts - foreign exchange		—			44			—		44
Available for sale equity securities		65,752			—			—		65,752
Other (1)		1,202			—			—		1,202
Total assets at fair value		$	84,289		$	21,910		$	—	$	106,199
Liabilities
Physical commodity contracts		$	—		$	25,371		$	—	$	25,371
Financial commodity contracts		24,036			—			—		24,036
Interest rate contract		—			8,467			—		8,467
Total liabilities at fair value		$	24,036		$	33,838		$	—	$	57,874

(1) Includes money market funds.

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INVESTMENTS IN EQUITY INVESTEES (Tables)

12 Months Ended

Sep. 30, 2018

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

As of September 30, the Company’s investments in equity method investees includes the following:

(Thousands)	2018		2017
Steckman Ridge (1)	$	117,001	$	120,262
PennEast	73,865		52,323
Total	$	190,866	$	172,585

(1)Includes loans with a total outstanding principal balance of $70.4 million for both fiscal 2018 and 2017, which accrue interest at a variable rate that resets quarterly and are due October 1, 2023.

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EARNINGS PER SHARE (Tables)

12 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Schedule of Basic and Diluted Earnings Per Share

The following table presents the calculation of the Company’s basic and diluted earnings per share for the fiscal years ended September 30:

(Thousands, except per share amounts)	2018		2017		2016
Net income, as reported	$	233,436	$	132,065	$	131,672
Basic earnings per share
Weighted average shares of common stock outstanding-basic	87,689		86,321		85,884
Basic earnings per common share	$2.66		$1.53		$1.53
Diluted earnings per share
Weighted average shares of common stock outstanding-basic	87,689		86,321		85,884
Incremental shares (1)	626		823		847
Weighted average shares of common stock outstanding-diluted	88,315		87,144		86,731
Diluted earnings per common share (2)	$2.64		$1.52		$1.52

(1) Incremental shares consist primarily of unvested stock awards and performance units.

(2) There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2018, 2017 and 2016.

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DEBT (Tables)

12 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Schedule of Long-term Debt

The following table presents the long-term debt of the Company as of September 30:

(Thousands)			2018			2017
NJNG
First mortgage bonds:		Maturity date:
5.60%	Series LL	May 15, 2018	$	—		$	125,000
Variable	Series MM	September 1, 2027	9,545			9,545
Variable	Series NN	August 1, 2035	41,000			41,000
Variable	Series OO	August 1, 2041	46,500			46,500
3.15%	Series PP	April 15, 2028	50,000			50,000
3.58%	Series QQ	March 13, 2024	70,000			70,000
4.61%	Series RR	March 13, 2044	55,000			55,000
2.82%	Series SS	April 15, 2025	50,000			50,000
3.66%	Series TT	April 15, 2045	100,000			100,000
3.63%	Series UU	June 21, 2046	125,000			125,000
4.01%	Series VV	May 11, 2048	125,000			—
Capital lease obligation-buildings		June 1, 2021	8,749			11,617
Capital lease obligation-meters		Various dates	27,188			28,042
Less: Debt issuance costs			(6,515		)	(6,262		)
Less: Current maturities of long-term debt			(9,502		)	(135,800		)
Total NJNG long-term debt			691,965			569,642
NJR
2.51%	Unsecured senior notes	September 15, 2018	—			25,000
3.25%	Unsecured senior notes	September 17, 2022	50,000			50,000
3.48%	Unsecured senior notes	November 7, 2024	100,000			100,000
3.20%	Unsecured senior notes	August 18, 2023	50,000			50,000
3.54%	Unsecured senior notes	August 18, 2026	100,000			100,000
3.96%	Unsecured senior notes	June 8, 2028	100,000			—
Variable	Term loan	August 16, 2019	100,000			100,000
Less: Debt issuance costs			(1,136		)	(770		)
Less: Current maturities of long-term debt			(100,000		)	(25,000		)
Total NJR long-term debt			398,864			399,230
Clean Energy Ventures
Solar asset financing obligation		Various dates	103,923			32,790
Less: Current maturities of long-term debt			(14,133		)	(4,582		)
Total Clean Energy Ventures long-term debt			89,790			28,208
Total long-term debt			$	1,180,619		$	997,080

Schedule of Long-term Debt Redemption Requirements

Annual long-term debt redemption requirements, excluding capital leases, debt issuance costs and solar asset financing obligations, as of September 30, are as follows:

(Thousands)	NJNG		NJR
2019	$	—	$	100,000
2020	$	—	$	—
2021	$	—	$	—
2022	$	—	$	50,000
2023	$	—	$	50,000
Thereafter	$	672,045	$	300,000

Schedule of Contractual Commitments for Capital Lease Payments

Contractual commitments for capital lease payments, as of the fiscal years ended September 30, are as follows:

(Thousands)	Lease Payments
2019		$	10,932
2020		7,989
2021		9,236
2022		3,775
2023		2,393
Thereafter		5,245
Subtotal		39,570
Less: Interest component		(3,633		)
Total		$	35,937

Contractual commitments for solar sale-leaseback lease payments, as of the fiscal years ended September 30, are as follows:

(Thousands)	Lease Payments
2019		$	9,794
2020		7,830
2021		7,803
2022		7,802
2023		7,878
Thereafter		38,303
Subtotal		79,410
Less: Interest component		(26,728		)
Total		$	52,682

Summary of Short-Term Bank Facilities

A summary of NJR’s and NJNG’s short-term bank facilities as of September 30, are as follows:

(Thousands)	2018			2017
NJR
Bank revolving credit facilities:(1)	$	425,000		$	425,000
Notes outstanding at end of period	$	87,950		$	255,000
Weighted average interest rate at end of period	3.07		%	2.14		%
Amount available at end of period (2)	$	322,144		$	156,601
NJNG
Bank revolving credit facilities: (3)	$	250,000		$	250,000
Commercial paper outstanding at end of period	$	64,000		$	11,000
Weighted average interest rate at end of period	2.18		%	1.13		%
Amount available at end of period (4)	$	185,269		$	238,269

(1) Committed credit facilities, which require commitment fees of .075 percent on the unused amounts.

(2) Letters of credit outstanding total $14.9 million and $13.4 million as of September 30, 2018 and 2017, respectively, which reduces amount available by the same amount.

(3) Committed credit facilities, which require commitment fees of .075 percent on the unused amounts.

(4) Letters of credit outstanding total $731,000 as of September 30, 2018 and 2017, which reduces amount available by the same amount.

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STOCK-BASED COMPENSATION (Tables)

12 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Stock-based Compensation Expense Recognized

The following table summarizes all stock-based compensation expense recognized during the following fiscal years:

(Thousands)	2018			2017			2016
Stock-based compensation expense:
Performance share awards	$	3,526		$	2,614		$	3,188
Restricted and non-restricted stock	2,191			1,732			2,161
Deferred retention stock	7,128			1,461			1,885
Compensation expense included in operation and maintenance expense	12,845			5,807			7,234
Income tax benefit (1)	(3,734		)	(2,372		)	(2,955		)
Total, net of tax	$	9,111		$	3,435		$	4,279

(1) Excludes additional tax benefit related to delivered shares of $3 million, $1.3 million and $1.8 million as of September 30, 2018, 2017 and 2016, respectively.

Summary of Performance Share Activity

The following table summarizes the performance share activity under the stock award and incentive plans for the past three fiscal years:

	Shares (1)		Weighted Average Grant Date Fair Value		Total Fair Value of Vested Shares (in Thousands)
Non-vested and outstanding at September 30, 2015	214,464			$23.40		—
Granted	115,480			$27.37		—
Vested (2)	(137,053	)		$21.40		$	5,657
Cancelled/forfeited (3)	(12,975	)		$23.40		—
Non-vested and outstanding at September 30, 2016	179,916			$27.47		—
Granted	96,507			$33.57		—
Vested (4)	(95,407	)		$28.88		$	4,179
Cancelled/forfeited	(24,429	)		$29.14		—
Non-vested and outstanding at September 30, 2017	156,587			$30.12		—
Granted	91,177			$44.67		—
Vested (5)	(100,146	)		$29.49		$	4,714
Cancelled/forfeited	(2,442	)		$31.45		—
Non-vested and outstanding at September 30, 2018	145,176			$39.67		—

(1) The number of common shares issued related to certain performance shares may range from zero to 150 percent of the number of shares shown in the table above based on the Company’s achievement of performance goals.

(2) As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, the number of common shares related to performance shares earned was 85 percent, or 55,702 shares, the number of common shares earned related to NFE performance was 150 percent or 71,808 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 23,649 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

(3) As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, 9,366 shares were canceled due to not achieving a certain performance target. The remainder were forfeitures due to individuals departing the Company.

(4) As certified by the Company’s Leadership and Compensation Committee on November 14, 2017, the number of common shares earned related to TSR performance was 108.44 percent or 39,595 shares, the number of common shares earned related to NFE performance was 119 percent or 36,498 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 28,223 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

(5) As certified by the Company’s Leadership and Compensation Committee on November 13, 2018, the number of common shares earned related to TSR performance was 99 percent or 38,660 shares, the number of common shares earned related to NFE performance was 121 percent or 39,694 shares and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 36,998 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

Summary of Restricted Stock Activity

The following table summarizes the restricted stock activity under the stock award and incentive plans for the past three fiscal years:

	Shares		Weighted Average Grant Date Fair Value		Total Fair Value of Vested Shares (in Thousands)
Non-vested and outstanding at September 30, 2015	81,492			$27.17		—
Granted	41,909			$30.03		—
Vested	(48,089	)		$26.66		$	1,469
Cancelled/forfeited	(2,241	)		$29.21		—
Non-vested and outstanding at September 30, 2016	73,071			$29.09		—
Granted	28,734			$35.79		—
Vested	(38,752	)		$28.92		$	1,344
Cancelled/forfeited	(11,899	)		$31.56		—
Non-vested and outstanding at September 30, 2017	51,154			$32.40		—
Granted	27,949			$45.00
Vested	(33,815	)		$31.23		$	1,438
Cancelled/forfeited	(1,120	)		$33.54
Non-vested and outstanding at September 30, 2018	44,168			$41.24		—

Summary of Deferred Retention Stock Award

The following table summarizes the deferred retention stock award under the stock award and incentive plans for the past three fiscal years:

	Shares		Weighted Average Grant Date Fair Value		Total Fair Value of Vested Shares (in Thousands)
Outstanding at September 30, 2015	632,730			$27.03		—
Granted/Vested	159,831			$30.37		—
Delivered	(121,764	)		$20.31		$	3,751
Forfeited	(8,318	)		$28.14		—
Outstanding at September 30, 2016	662,479			$29.06		—
Granted/Vested	63,977			$35.64		—
Delivered	(53,878	)		$23.11		$	1,774
Outstanding at September 30, 2017	672,578			$29.54		—
Granted/Vested	24,167			$45.00
Delivered	(452,694	)		$29.42		$	19,581
Forfeited	(1,969	)		$35.56
Outstanding at September 30, 2018	242,082			$32.99		—

Schedule of Nonemployee Director Stock Award Plan Activity

The following summarizes non-employee director share awards for the past three fiscal years:

	2018		2017	2016
Shares granted	26,524	(1)	27,972	27,481
Weighted average grant date fair value	$39.85		$35.59	$32.75

(1) $264,000 of expense remains as of September 30, 2018, to be recognized through December 31, 2018.

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EMPLOYEE BENEFIT PLANS (Tables)

12 Months Ended

Sep. 30, 2018

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)	2018			2017			2018			2017
Change in Benefit Obligation
Benefit obligation at beginning of year	$	297,835		$	293,654		$	175,090		$	160,393
Service cost	8,139			8,347			4,607			4,380
Interest cost	10,493			9,771			6,365			5,545
Plan participants’ contributions (2)	45			45			161			120
Special termination benefits (3)	3,730			—			490			—
Actuarial (gain) loss	(12,846		)	(5,995		)	15,145			8,985
Benefits paid, net of retiree subsidies received	(8,821		)	(7,987		)	(5,073		)	(4,333		)
Benefit obligation at end of year	$	298,575		$	297,835		$	196,785		$	175,090
Change in plan assets
Fair value of plan assets at beginning of year	$	271,743		$	249,875		$	71,534		$	62,035
Actual return on plan assets	16,306			29,736			5,284			7,953
Employer contributions	137			74			6,222			6,049
Benefits paid, net of plan participants’ contributions (2)	(8,776		)	(7,942		)	(5,060		)	(4,503		)
Fair value of plan assets at end of year	$	279,410		$	271,743		$	77,980		$	71,534
Funded status	$	(19,165	)	$	(26,092	)	$	(118,805	)	$	(103,556	)
Amounts recognized on Consolidated Balance Sheets
Postemployment employee (liability)
Current	$	(294	)	$	(158	)	$	(669	)	$	(602	)
Noncurrent	(18,871		)	(25,934		)	(118,136		)	(102,954		)
Total	$	(19,165	)	$	(26,092	)	$	(118,805	)	$	(103,556	)

(1) Includes the Company’s PEP.

(2) Prior to July 1, 1998, employees were eligible to elect an additional participant contribution to enhance their benefits and contributions made during the periods were insignificant.

(3) Related to the voluntary early retirement program offered during fiscal 2018, as previously discussed.

Summary of Regulatory Assets and Accumulated Other Comprehensive Income

The following table summarizes the amounts recognized in regulatory assets and accumulated other comprehensive income as of September 30:

	Regulatory Assets						Accumulated Other Comprehensive Income (Loss)
	Pension			OPEB			Pension			OPEB
Balance at September 30, 2016	$	94,941		$	59,147		$	28,436		$	4,486
Amounts arising during the period:
Net actuarial (gain) loss	(9,429		)	5,211			(6,990		)	587
Amounts amortized to net periodic costs:
Net actuarial (loss)	(6,799		)	(4,209		)	(2,028		)	(160		)
Prior service (cost) credit	(108		)	311			(3		)	54
Balance at September 30, 2017	$	78,605		$	60,460		$	19,415		$	4,967
Amounts arising during the period:
Net actuarial (gain) loss	(6,090		)	12,378			(3,422		)	2,834
Amounts amortized to net periodic costs:
Net actuarial (loss)	(6,177		)	(4,464		)	(1,359		)	(196		)
Prior service (cost) credit	(105		)	311			(1		)	54
Balance at September 30, 2018	$	66,233		$	68,685		$	14,633		$	7,659

The amounts in regulatory assets and accumulated other comprehensive income not yet recognized as components of net periodic benefit cost as of September 30 are:

	Regulatory Assets										Accumulated Other Comprehensive Income (Loss)
	Pension				OPEB						Pension				OPEB
(Thousands)	2018		2017		2018			2017			2018		2017		2018			2017
Net actuarial loss	$	65,664	$	77,930	$	69,477		$	61,563		$	14,633	$	19,414	$	7,750		$	5,113
Prior service cost (credit)	569		675		(792		)	(1,103		)	—		1		(91		)	(146		)
Total	$	66,233	$	78,605	$	68,685		$	60,460		$	14,633	$	19,415	$	7,659		$	4,967

Schedule of Amounts Expected to be Recognized as Components of Net Periodic Benefit Cost

Amounts included in regulatory assets and accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost in fiscal 2019 are as follows:

	Regulatory Assets					Accumulated Other Comprehensive Income (Loss)
(Thousands)	Pension		OPEB			Pension		OPEB
Net actuarial loss	$	4,662	$	5,527		$	1,103	$	643
Prior service cost (credit)	102		(312		)	—		(53		)
Total	$	4,764	$	5,215		$	1,103	$	590

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets

The accumulated benefit obligation for the pension plans, including the PEP, exceeded the fair value of plan assets. The projected benefit and accumulated benefit obligations and the fair value of plan assets as of September 30, are as follows:

	Pension
(Thousands)	2018		2017
Projected benefit obligation	$	298,575	$	297,835
Accumulated benefit obligation	$	263,279	$	258,514
Fair value of plan assets	$	279,410	$	271,743

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)	2018			2017			2016			2018			2017			2016
Service cost	$	8,139		$	8,347		$	7,591		$	4,607		$	4,380		$	4,521
Interest cost	10,493			9,771			11,342			6,365			5,545			6,256
Expected return on plan assets	(19,639		)	(19,313		)	(20,118		)	(5,352		)	(4,767		)	(4,845		)
Recognized actuarial loss	7,537			8,827			7,281			4,660			4,370			3,274
Prior service cost (credit) amortization	106			111			111			(365		)	(365		)	(365		)
Net periodic benefit cost	$	6,636		$	7,743		$	6,207		$	9,915		$	9,163		$	8,841
Special termination benefit	3,730			—			—			490			—			—
Net periodic benefit cost recognized as expense	$	10,366		$	7,743		$	6,207		$	10,405		$	9,163		$	8,841

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
	2018			2017			2016			2018			2017			2016
Benefit costs:
Discount rate	4.04/4.03%			3.96/3.94%			4.50	%		4.12/4.08%		(1)	4.08/4.01%		(1)	4.60/4.55%
Expected asset return	7.50	%		7.75	%		8.75	%		7.50	%		7.75	%		8.75	%
Compensation increase	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%			3.25/3.50%		(1)	3.25/3.50%			3.50	%
Obligations:
Discount rate	4.36/4.35%			4.03	%	(1)	3.96/3.94%			4.38/4.37%		(1)	4.12/4.08%		(1)	4.08/4.01%		(1)
Compensation increase	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%		(1)	3.25/3.50%			3.50	%

(1) Percentages for represented and nonrepresented plans, respectively.

Information on Assumed HCCTR Used to Determine Expected OPEB Benefits

Information relating to the assumed HCCTR used to determine expected OPEB benefits as of September 30, and the effect of a 1 percent change in the rate, are as follows:

($ in thousands)	2018			2017			2016
HCCTR	7.9		%	8.3		%	8.5		%
Ultimate HCCTR	4.5		%	4.5		%	4.5		%
Year ultimate HCCTR reached	2024			2025			2025
Effect of a 1 percentage point increase in the HCCTR on:
Year-end benefit obligation	$	36,260		$	32,019		$	28,803
Total service and interest cost	$	2,482		$	2,468		$	2,331
Effect of a 1 percentage point decrease in the HCCTR on:
Year-end benefit obligation	$	(28,743	)	$	(25,466	)	$	(22,862	)
Total service and interest costs	$	(1,937	)	$	(1,909	)	$	(1,801	)

Schedule of Mix and Targeted Allocation of Plan Assets

The mix and targeted allocation of the pension and OPEB plans’ assets are as follows:

	2019		Assets at
	Target		September 30,
Asset Allocation	Allocation		2018		2017
U.S. equity securities	34	%	41	%	39	%
International equity securities	17		19		21
Fixed income	41		37		40
Other assets	8		3		—
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)	Pension		OPEB
2019	$	10,320	$	5,450
2020	$	11,769	$	6,512
2021	$	12,399	$	7,096
2022	$	13,239	$	7,810
2023	$	14,217	$	8,413
2024 - 2028	$	85,426	$	50,869

Schedule of Estimated Subsidy Payments

The following estimated subsidy payments are expected to be paid during the following fiscal years:

	Estimated Subsidy
(Thousands)	Payment
2019		$	280
2020		$	316
2021		$	347
2022		$	375
2023		$	417
2024 - 2028		$	2,787

Summary of Pension and OPEB Assets Held in the Master Trust

Pension and OPEB assets held in the master trust, measured at fair value, as of September 30, are summarized as follows:

	Quoted Prices in Active Markets for Identical Assets (Level 1)
(Thousands)	Pension				OPEB
Assets	2018		2017		2018		2017
Money market funds	$	8,207	$	—	$	2,273	$	11
Registered Investment Companies:
Equity Funds:
Large Cap Index	97,016		88,321		27,340		23,986
Extended Market Index	17,741		16,329		5,014		4,409
International Stock	53,516		56,446		14,874		15,000
Fixed Income Funds:
Emerging Markets	11,754		13,516		3,264		3,551
Core Fixed Income	—		—		7,970		8,082
Opportunistic Income	—		—		4,798		4,744
Ultra Short Duration	—		—		4,830		4,673
High Yield Bond Fund	25,720		26,540		7,236		7,078
Long Duration Fund	64,039		70,591		—		—
Total assets	$	277,993	$	271,743	$	77,599	$	71,534

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ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Sep. 30, 2018

Asset Retirement Obligation Disclosure [Abstract]

Analysis of Change in ARO Liability

The following is an analysis of the change in the Company’s AROs for the fiscal years ended September 30:

(Thousands)	2018						2017
	NJNG			NJRCEV			NJNG			NJRCEV
Balance at October 1	$	24,825		$	6,595		$	23,521		$	4,858
Accretion	1,366			198			1,304			245
Additions	1,880			517			729			1,492
Revisions in estimated cash flows	(2,133		)	—			(245		)	—
Retirements	(298		)	—			(484		)	—
Reclassification to held for sale or sold	—			(4,262		)	—			—
Balance at period end	$	25,640		$	3,048		$	24,825		$	6,595

Schedule of Future Accretion

Accretion for the next five years, for the fiscal years ended September 30, is estimated to be as follows:

	Estimated
(Thousands)	Accretion
2019	$	1,557
2020	1,627
2021	1,702
2022	1,778
2023	1,863
Total	$	8,527

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INCOME TAXES (Tables)

12 Months Ended

Sep. 30, 2018

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Provision (Benefit)

The income tax (benefit) provision from operations for the fiscal years ended September 30, consists of the following:

(Thousands)	2018			2017			2016
Current:
Federal	$	(2,848	)	$	(16,023	)	$	(23,597	)
State	4,563			2,470			(2,209		)
Deferred:
Federal	(40,785		)	54,965			70,386
State	6,731			11,457			11,441
Investment/production tax credits	(21,446		)	(34,526		)	(32,491		)
Income tax (benefit) provision	$	(53,785	)	$	18,343		$	23,530

Schedule of Deferred Tax Assets and Liabilities

he temporary differences, which give rise to deferred tax assets and (liabilities), consist of the following:

(Thousands)	2018			2017
Deferred tax assets
Investment tax credits (1)	$	123,258		$	111,642
Deferred service contract revenue	—			3,877
Incentive compensation	4,646			6,260
Fair value of derivatives	8,411			11,519
Federal net operating losses (2)	24,500			28,487
State net operating losses	34,754			23,597
Amortization of intangibles	3,737			2,747
Conservation incentive plan	1,955			—
Other	8,213			11,098
Total deferred tax assets	$	209,474		$	199,227
Deferred tax liabilities
Property related items	$	(392,886	)	$	(620,850	)
Remediation costs	(9,229		)	(11,625		)
Equity investments	(31,956		)	(38,370		)
Postemployment benefits	(353		)	(6,855		)
Conservation incentive plan	—			(7,195		)
Underrecovered gas costs	(1,156		)	(4,035		)
Other	(7,826		)	(16,643		)
Total deferred tax liabilities	$	(443,406	)	$	(705,573	)
Total net deferred tax liabilities	$	(233,932	)	$	(506,346	)

(1) Includes $2.2 million and $2.3 million for NJNG for fiscal 2018 and 2017, respectively, which is being amortized over the life of the related assets, and$121.1 million and $109.3 million for Clean Energy Ventures for fiscal 2018 and 2017, respectively, which is ITC carryforward.

(2) See discussion of federal net operating loss utilization in the Other Tax Items section of this note.

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)	2018			2017			2016
Statutory income tax expense	$	44,014		$	52,643		$	54,321
Change resulting from:
Tax Act - nonutility excess deferred income taxes (1)	(59,627		)	—			—
Tax Act - utility excess deferred income taxes refunded to customers (1)	(14,323		)	—			—
Tax Act - utility excess deferred income taxes amortized (1)	(1,786		)	—			—
State income taxes, net of federal benefit	7,092			8,222			6,044
Cost of removal of assets placed in service prior to1981	(5,829		)	(6,886		)	(5,738		)
Investment/production tax credits	(21,446		)	(34,526		)	(32,491		)
Basis adjustment of solar assets due to ITC	1,080			4,256			4,453
AFUDC equity	(2,117		)	(2,624		)	(1,531		)
Other	(843		)	(2,742		)	(1,528		)
Income tax (benefit) provision	$	(53,785	)	$	18,343		$	23,530
Effective income tax rate (2) (3)	(29.9		)%	12.2		%	15.2		%

(1) For a more detailed description, see The Tax Act section of this note.

(2) The U.S. federal statutory rate was 24.5 percent for fiscal 2018 and 35 percent for fiscal 2017 and 2016.

(3) The effective tax rate without the impact of the Tax Act would have been 12.4 percent for fiscal 2018

Schedule of Deferred Tax Liability Due to Tax Act

The (decrease) increase of the net deferred tax liability due to the impact of the Tax Act that was recognized on the Consolidated Statements of Operations for the remaining entities, was as follows:

(Thousands)	2018
Income tax (benefit) provision
Clean Energy Ventures	$	(61,423	)
Energy Services	6,062
Midstream	(13,946		)
Home Services and Other	9,680
Total	$	(59,627	)

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COMMITMENTS AND CONTINGENT LIABILITIES (Tables)

12 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Schedule of Commitments for Natural Gas Purchases and Future Demans Fees for the Next Five Years

Commitments as of September 30, 2018, for natural gas purchases and future demand fees for the next five fiscal year periods, are as follows:

(Thousands)	2019		2020		2021		2022		2023		Thereafter
Energy Services:
Natural gas purchases	$	428,015	$	28,389	$	10,965	$	—	$	—	$	—
Storage demand fees	31,716		19,926		13,478		8,904		4,212		991
Pipeline demand fees	52,148		49,790		28,209		24,153		18,988		5,151
Sub-total Energy Services	$	511,879	$	98,105	$	52,652	$	33,057	$	23,200	$	6,142
NJNG:
Natural gas purchases	$	65,737	$	37,727	$	33,738	$	33,546	$	34,221	$	35,762
Storage demand fees	31,384		24,263		14,251		12,930		7,899		6,066
Pipeline demand fees	80,609		96,241		89,236		91,946		87,240		586,266
Sub-total NJNG	$	177,730	$	158,231	$	137,225	$	138,422	$	129,360	$	628,094
Total	$	689,609	$	256,336	$	189,877	$	171,479	$	152,560	$	634,236

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BUSINESS SEGMENT AND OTHER OPERATIONS DATA (Tables)

12 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Schedule of Business Segments and Other Operations

Information related to the Company’s various reporting segments and other operations is detailed below:

(Thousands)
Fiscal Years Ended September 30,	2018			2017			2016
Operating revenues
Natural Gas Distribution
External customers	$	731,865		$	695,637		$	594,346
Clean Energy Ventures
External customers	71,375			64,394			53,540
Energy Services
External customers(1)	2,064,477			1,462,365			1,187,754
Intercompany	48,327			316			9,499
Subtotal	2,916,044			2,222,712			1,845,139
Home Services and Other
External customers	47,392			46,221			45,265
Intercompany	2,665			3,370			3,232
Eliminations	(50,992		)	(3,686		)	(12,731		)
Total	$	2,915,109		$	2,268,617		$	1,880,905
Depreciation and amortization
Natural Gas Distribution	$	53,208		$	49,347		$	47,828
Clean Energy Ventures	31,877			31,834			23,971
Energy Services (2)	76			63			88
Midstream	6			6			6
Subtotal	85,167			81,250			71,893
Home Services and Other	780			798			981
Eliminations	(246		)	(207		)	(126		)
Total	$	85,701		$	81,841		$	72,748
Interest income (3)
Natural Gas Distribution	$	614		$	555		$	115
Energy Services	240			6			98
Midstream	3,374			2,195			1,524
Subtotal	4,228			2,756			1,737
Home Services and Other	1,476			590			397
Eliminations	(5,090		)	(1,312		)	(2,006		)
Total	$	614		$	2,034		$	128

(1) Includes sales to Canada, which are immaterial.

(2) The amortization of acquired wholesale energy contracts is excluded above and is included in gas purchases - nonutility on the Unaudited Condensed Consolidated Statements of Operations.

(3) Included in other income, net on the Consolidated Statements of Operations.

(Thousands)
Fiscal Years Ended September 30,	2018			2017			2016
Interest expense, net of capitalized interest
Natural Gas Distribution	$	25,299		$	25,818		$	19,930
Clean Energy Ventures	18,320			16,263			10,304
Energy Services	3,945			2,747			1,095
Midstream	1,667			960			287
Subtotal	49,231			45,788			31,616
Home Services and Other	7			410			252
Eliminations	(2,952		)	(1,312		)	(824		)
Total	$	46,286		$	44,886		$	31,044
Income tax (benefit) provision
Natural Gas Distribution	$	(1,910	)	$	43,485		$	34,951
Clean Energy Ventures	(79,932		)	(31,161		)	(26,592		)
Energy Services	24,996			(4,015		)	7,030
Midstream	(8,548		)	5,820			6,130
Subtotal	(65,394		)	14,129			21,519
Home Services and Other	11,944			3,857			1,387
Eliminations	(335		)	357			624
Total	$	(53,785	)	$	18,343		$	23,530
Equity in earnings of affiliates
Midstream	$	16,165		$	17,797		$	13,936
Eliminations	(3,157		)	(3,984		)	(4,421		)
Total	$	13,008		$	13,813		$	9,515
Net financial earnings (loss)
Natural Gas Distribution	$	84,048		$	86,930		$	76,104
Clean Energy Ventures	75,849			24,873			28,393
Energy Services	60,378			18,554			21,934
Midstream	24,367			12,857			9,406
Subtotal	244,642			143,214			135,837
Home Services and Other	(3,829		)	6,811			2,882
Eliminations	(327		)	(633		)	(634		)
Total	$	240,486		$	149,392		$	138,085
Capital expenditures
Natural Gas Distribution	$	254,523		$	176,249		$	205,133
Clean Energy Ventures	123,421			149,400			149,063
Midstream	5,431			—			—
Subtotal	383,375			325,649			354,196
Home Services and Other	1,213			2,434			1,896
Total	$	384,588		$	328,083		$	356,092
Investments in equity investees
Midstream	16,151			27,070			11,176
Total	$	16,151		$	27,070		$	11,176

Reconciliation of Consolidated NFE to Consolidated Net Income

A reconciliation of consolidated NFE to consolidated net income is as follows:

(Thousands)	2018			2017			2016
Consolidated net financial earnings	$	240,486		$	149,392		$	138,085
Less:
Unrealized loss (gain) on derivative instruments and related transactions	26,770			(11,241		)	46,883
Tax effect	(4,512		)	4,062			(17,018		)
Effects of economic hedging related to natural gas inventory	(22,570		)	38,470			(36,816		)
Tax effect	7,362			(13,964		)	13,364
Consolidated net income	$	233,436		$	132,065		$	131,672

Schedule of Assets for Business Segments and Business Operations

The Company’s assets for the various reporting segments and business operations are detailed below:

(Thousands)	2018			2017			2016
Assets at end of period:
Natural Gas Distribution	$	2,663,054		$	2,519,578		$	2,517,401
Clean Energy Ventures (1)	865,018			771,340			665,696
Energy Services	396,852			398,277			327,626
Midstream	242,069			232,806			186,259
Subtotal	4,166,993			3,922,001			3,696,982
Home Services and Other	114,732			114,801			109,487
Intercompany assets (2)	(138,061		)	(108,295		)	(87,899		)
Total	$	4,143,664		$	3,928,507		$	3,718,570

(1) Includes assets held for sale of $206.9 million for September 30, 2018.

(2) Consists of transactions between subsidiaries that are eliminated and reclassified in consolidation.

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RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Sep. 30, 2018

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Demand fees, net of eliminations, associated with Steckman Ridge during the fiscal years ended September 30, are as follows:

(Thousands)	2018		2017		2016
Natural Gas Distribution	$	5,730	$	5,590	$	5,562
Energy Services	2,775		2,750		2,789
Total	$	8,505	$	8,340	$	8,351

The following table summarizes demand fees payable to Steckman Ridge as of September 30:

(Thousands)	2018		2017
Natural Gas Distribution	$	775	$	775
Energy Services	375		377
Total	$	1,150	$	1,152

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SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)

12 Months Ended

Sep. 30, 2018

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Data

A summary of financial data for each quarter of fiscal 2018 and 2017 follows. Due to the seasonal nature of the Company’s businesses, quarterly amounts vary significantly during the fiscal year. In the opinion of management, the information furnished reflects all adjustments necessary for a fair presentation of the results of the interim periods.

	First		Second		Third			Fourth
(Thousands, except per share data)	Quarter		Quarter		Quarter			Quarter
2018
Operating revenues	$	705,305	$	1,019,043	$	543,435		$	647,326
Operating income (loss)	$	75,245	$	177,792	$	(37,666	)	$	(19,295	)
Net income (loss)	$	123,699	$	140,266	$	(14,274	)	$	(16,255	)
Earnings (loss) per share (1)
Basic	$1.42		$1.60		$(0.16)			$(0.18)
Diluted	$1.42		$1.59		$(0.16)			$(0.18)
2017
Operating revenues	$	541,028	$	733,546	$	457,523		$	536,520
Operating income (loss)	$	41,475	$	139,653	$	17,967		$	(32,051	)
Net income (loss)	$	34,929	$	114,702	$	18,957		$	(36,523	)
Earnings (loss) per share (1)
Basic	$0.41		$1.33		$0.22			$(0.42)
Diluted	$0.40		$1.32		$0.22			$(0.42)

(1) The sum of quarterly amounts may not equal the annual amounts due to rounding.

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NATURE OF THE BUSINESS (Details)		12 Months Ended
	Jun. 01, 2018 MW	Sep. 30, 2018 subsidiary customer
Natural Gas Distribution
Investment [Line Items]
Total retail customers (in customers) | customer		538,700
NJR Retail Holdings Corporation
Investment [Line Items]
Number of principal subsidiaries (in subsidiaries) | subsidiary		2
Steckman Ridge
Investment [Line Items]
Ownership interest, percent		50.00%
PennEast
Investment [Line Items]
Ownership interest, percent		20.00%
Clean Energy Ventures
Investment [Line Items]
Wind farm total capacity (in MW) | MW	9.7

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - DEMAND FEES (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Demand fees	$ 245.5	$ 206.6	$ 218.8
Energy Services
Demand fees	153.0	126.4	141.0
Natural Gas Distribution
Demand fees	$ 92.5	$ 80.2	$ 77.8
Minimum
Storage and pipeline capacity, contract term	1 year
Maximum
Storage and pipeline capacity, contract term	10 years

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - SALES TAX ACCOUNTING (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Accounting Policies [Abstract]
Sales tax	$ 41.7	$ 39.4	$ 31.0
Sales tax, percentage	6.625%	6.875%	7.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - PROPERTY PLANT AND EQUIPMENT (Details) - USD ($) $ in Thousands		1 Months Ended	12 Months Ended
		Sep. 30, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Composite rate of depreciation			2.29%	2.25%	2.32%
Depreciation and amortization			$ 85,701	$ 81,841	$ 72,748
Property Classifications
Property, plant and equipment - wind equipment, at cost			3,304,491	3,211,070
Accumulated depreciation and amortization			(653,442)	(601,329)
Property, plant and equipment, net			2,651,049	2,609,741
Regulated Operation | Distribution facilities
Property Classifications
Property, plant and equipment - wind equipment, at cost			$ 2,151,249	1,952,697
Regulated Operation | Distribution facilities | Minimum
Property Classifications
Estimated Useful Lives			38 years
Regulated Operation | Distribution facilities | Maximum
Property Classifications
Estimated Useful Lives			74 years
Regulated Operation | Transmission facilities
Property Classifications
Property, plant and equipment - wind equipment, at cost			$ 295,692	294,586
Regulated Operation | Transmission facilities | Minimum
Property Classifications
Estimated Useful Lives			35 years
Regulated Operation | Transmission facilities | Maximum
Property Classifications
Estimated Useful Lives			56 years
Regulated Operation | Storage facilities
Property Classifications
Property, plant and equipment - wind equipment, at cost			$ 79,470	78,245
Regulated Operation | Storage facilities | Minimum
Property Classifications
Estimated Useful Lives			34 years
Regulated Operation | Storage facilities | Maximum
Property Classifications
Estimated Useful Lives			47 years
Unregulated Operation | Solar property
Property Classifications
Property, plant and equipment - wind equipment, at cost			$ 720,562	587,345
Unregulated Operation | Solar property | Minimum
Property Classifications
Estimated Useful Lives			20 years
Unregulated Operation | Solar property | Maximum
Property Classifications
Estimated Useful Lives			25 years
Unregulated Operation | Wind property
Property Classifications
Property, plant and equipment - wind equipment, at cost	[1]		$ 0	244,764
Unregulated Operation | Wind property | Minimum
Property Classifications
Estimated Useful Lives	[1]		17 years
Unregulated Operation | Wind property | Maximum
Property Classifications
Estimated Useful Lives	[1]		25 years
Unregulated Operation | Midstream property
Property Classifications
Estimated Useful Lives	[2]		30 years
Property, plant and equipment - wind equipment, at cost	[2]		$ 6,747	0
Unregulated Operation | All other property
Property Classifications
Property, plant and equipment - wind equipment, at cost			$ 50,771	$ 53,433
Unregulated Operation | All other property | Minimum
Property Classifications
Estimated Useful Lives			5 years
Unregulated Operation | All other property | Maximum
Property Classifications
Estimated Useful Lives			35 years
September 2016 Base Rate Case
Public Utility, Property, Plant and Equipment [Line Items]
Composite rate of depreciation		2.40%

[1] Reclassified to assets held for sale. See Note 2. Summary of Significant Accounting Policies, for more information.

[2] Includes activity related to the acquisition of IEC by Adelphia. For fiscal 2017, Midstream property was originally included in All other property.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - SALE OF ASSET (Details) $ in Millions	1 Months Ended
	Mar. 31, 2018 USD ($)	Mar. 31, 2017 a	Mar. 31, 2017 ft²
Accounting Policies [Abstract]
Area of real estate property (in sqft or acres)		5	56,400
Proceeds from sale of real estate	$ 9.4
Gain (loss) on sale of properties	$ 1.9

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CAPITALIZED AND DEFERRED INTEREST (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
AFUDC:
SBC interest rate	3.41%	2.55%	2.05%
Deferred interest	$ 411	$ 78	$ 54
Seven-Year Treasury Rate
AFUDC:
Debt instrument, term	7 years
Basis spread on variable rate	60.00%
Natural Gas Distribution
AFUDC:
Debt	$ 1,979	1,311	5,009
Equity	5,531	3,867	4,375
Total	$ 7,510	$ 5,178	$ 9,384
Weighted average interest rate	5.94%	6.90%	5.06%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CASH AND CASH EQUIVALENTS (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017
Accounting Policies [Abstract]
Restricted cash	$ 252	$ 243

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - RECEIVABLE BY SUBSIDIARY (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Establishment of allowance for doubtful accounts, customer account balances, days outstanding (more than)		60 days
Billed		$ 205,490	$ 196,467
Receivable by subsidiary percentage		100.00%	100.00%
Unbilled revenues		$ 7,199	$ 7,202
Energy Services
Accounts, Notes, Loans and Financing Receivable [Line Items]
Billed		$ 157,936	$ 150,322
Receivable by subsidiary percentage		77.00%	77.00%
Natural Gas Distribution
Accounts, Notes, Loans and Financing Receivable [Line Items]
Billed	[1]	$ 39,151	$ 37,432
Receivable by subsidiary percentage	[1]	19.00%	19.00%
Clean Energy Ventures
Accounts, Notes, Loans and Financing Receivable [Line Items]
Billed		$ 3,330	$ 2,655
Receivable by subsidiary percentage		2.00%	1.00%
Home Services and Other Operations
Accounts, Notes, Loans and Financing Receivable [Line Items]
Billed		$ 5,073	$ 6,058
Receivable by subsidiary percentage		2.00%	3.00%

[1] Does not include unbilled revenues of $7.2 million as of September 30, 2018 and 2017.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - LOAN RECEIVABLE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loans receivable in other current assets	$ 10,400	$ 8,900
Loans receivable in other noncurrent assets	39,500	40,400
Allowance for doubtful accounts	$ 0	$ 0
Minimum
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loans receivable term	3 years
Maximum
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loans receivable term	10 years

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - GAS IN STORAGE (Details) $ in Thousands	Sep. 30, 2018 USD ($) Bcf	Sep. 30, 2017 USD ($) Bcf
Public Utilities, Inventory [Line Items]
Gas in Storage | $	$ 184,633	$ 202,063
Bcf | Bcf	59.0	75.7
Energy Services
Public Utilities, Inventory [Line Items]
Gas in Storage | $	$ 90,166	$ 122,884
Bcf | Bcf	34.1	53.9
Natural Gas Distribution
Public Utilities, Inventory [Line Items]
Gas in Storage | $	$ 94,467	$ 79,179
Bcf | Bcf	24.9	21.8

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ASSETS HELD FOR SALE (Details) $ in Thousands		Jun. 01, 2018 MW	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)
Assets and Liabilities Held for Sale [Roll Forward]
Liabilities held for sale			$ 4,182	$ 0
Clean Energy Ventures
Long Lived Assets Held-for-sale [Line Items]
Wind farm total capacity (in MW) | MW		9.7
Assets and Liabilities Held for Sale [Roll Forward]
Property, plant and equipment - wind equipment, at cost			224,356	0
Property, plant and equipment - accumulated depreciation, wind equipment			(18,501)	0
Prepaid and accrued taxes			789	0
Other noncurrent assets			261	0
Asset held for sale			206,905	0
Accounts payable and other	[1]		186	0
Asset retirement obligation			3,996	0
Liabilities held for sale			$ 4,182	0
Assets reclassified as held for sale | Clean Energy Ventures
Assets and Liabilities Held for Sale [Roll Forward]
Property, plant and equipment - wind equipment, at cost				245,044
Property, plant and equipment - accumulated depreciation, wind equipment				(21,561)
Prepaid and accrued taxes				866
Other noncurrent assets				261
Asset held for sale				224,610
Accounts payable and other	[1]			0
Asset retirement obligation				4,262
Liabilities held for sale				4,262
Assets Sold | Clean Energy Ventures
Assets and Liabilities Held for Sale [Roll Forward]
Property, plant and equipment - wind equipment, at cost				(20,688)
Property, plant and equipment - accumulated depreciation, wind equipment				3,060
Prepaid and accrued taxes				(77)
Other noncurrent assets				0
Asset held for sale				(17,705)
Accounts payable and other	[1]			186
Asset retirement obligation				(266)
Liabilities held for sale				$ (80)

[1] Transaction fee owed to broker for the sale of Two Dot wind farm.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - AVAILABLE FOR SALE SECURITIES (Details) - USD ($) shares in Thousands, $ in Thousands	1 Months Ended	6 Months Ended	12 Months Ended
	Sep. 30, 2015	Mar. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Debt Securities, Available-for-sale [Line Items]
Proceeds from sale of available for sale securities, net			$ 6,616	$ 6,639	$ 0
Gain on sale of available-for-sale securities, pre-tax			5,300	5,400
Gain on sale of available-for-sale securities, net of tax			3,200	3,200
Impairment of available for sale securities		$ 17,800
Other than temporary impairment, net of tax		$ 14,800
Available for sale securities			32,917	65,752
Unrealized gain			4,700	12,800
Unrealized gain, net of tax			3,400	$ 7,700
Deferred gain, unamortized balance			$ (6,800)
Common Units [Member]
Debt Securities, Available-for-sale [Line Items]
Ownership interest exchanged (in shares)	1,840
Deferred gain	$ 24,600

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - INTANGIBLE ASSETS (Details) $ in Thousands	Sep. 30, 2018 USD ($)
Business Acquisition [Line Items]
2019	$ 8,424
2020	4,925
2021	4,604
2022	2,561
2023	2,271
Thereafter	77
Talen's Wholesale Natural Gas Energy Contracts
Business Acquisition [Line Items]
Internal use software costs	513
Intangible assets, net of amortization	$ 22,900

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - SALE-LEASEBACKS (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Sale Leaseback Transaction [Line Items]
Proceeds from sale-leaseback transaction			$ 7,820	$ 9,587	$ 7,107
Proceeds from sale-leaseback transaction - solar			$ 71,538	32,901	0
Natural Gas Distribution
Sale Leaseback Transaction [Line Items]
Proceeds from sale-leaseback transaction	$ 7,800	$ 9,600			$ 7,100
Minimum | Natural Gas Distribution
Sale Leaseback Transaction [Line Items]
Term of lease			7 years
Maximum | Natural Gas Distribution
Sale Leaseback Transaction [Line Items]
Term of lease			11 years
Clean Energy Ventures
Sale Leaseback Transaction [Line Items]
Proceeds from sale-leaseback transaction - solar			$ 71,538	$ 32,901
Clean Energy Ventures | Minimum
Sale Leaseback Transaction [Line Items]
Term of lease			6 years
Clean Energy Ventures | Maximum
Sale Leaseback Transaction [Line Items]
Term of lease			15 years

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - PENSION AND POSTEMPLOYMENT PLANS (Details)		3 Months Ended	12 Months Ended
		Dec. 31, 2015 USD ($)	Sep. 30, 2018 USD ($) plan	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Number of noncontributory defined benefit retirement plans (in plans) | plan			2
Number of noncontributory medical and life insurance plans (in plans) | plan			2
Pension
Defined Benefit Plan Disclosure [Line Items]
Employer discretionary contributions		$ 30,000,000	$ 0.0	$ 0
Employer contributions	[1]		137,000	74,000
OPEB
Defined Benefit Plan Disclosure [Line Items]
Employer contributions			$ 6,222,000	$ 6,049,000	$ 3,200,000

[1] Includes the Company’s PEP.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance		$ 1,236,643	$ 1,166,591
Reclassifications of certain income tax effects to retained earnings	[1]	3,300
Ending Balance		1,418,978	1,236,643
Unrealized gain (loss) on available for sale securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance		11,044	4,198
Other comprehensive (loss), before reclassifications, net of tax		(19,245)	10,019
Amounts reclassified from accumulated other comprehensive income, net of tax		11,647	(3,173)
Net current-period other comprehensive (loss), net of tax		(7,598)	6,846
Reclassifications of certain income tax effects to retained earnings	[1]	0
Ending Balance		3,446	11,044
Tax on other comprehensive income before reclassifications		(6,973)	6,593
Tax on amounts reclassified from accumulated other comprehensive income		858	(2,192)
Tax on net current-period other comprehensive income (loss)		(6,115)	4,401
Adjustment to postemployment benefit obligation
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance		(14,300)	(19,353)
Other comprehensive (loss), before reclassifications, net of tax		464	3,783
Amounts reclassified from accumulated other comprehensive income, net of tax		1,056	1,270
Net current-period other comprehensive (loss), net of tax		1,520	5,053
Reclassifications of certain income tax effects to retained earnings	[1]	3,276
Ending Balance		(16,056)	(14,300)
Tax on other comprehensive income before reclassifications		125	2,619
Tax on amounts reclassified from accumulated other comprehensive income		448	868
Tax on net current-period other comprehensive income (loss)		573	3,487
Total
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance		(3,256)	(15,155)
Other comprehensive (loss), before reclassifications, net of tax		(18,781)	13,802
Amounts reclassified from accumulated other comprehensive income, net of tax	[2]	12,703	(1,903)
Net current-period other comprehensive (loss), net of tax		(6,078)	11,899
Reclassifications of certain income tax effects to retained earnings	[1]	3,276
Ending Balance		(12,610)	(3,256)
Tax on other comprehensive income before reclassifications		(6,848)	9,212
Tax on amounts reclassified from accumulated other comprehensive income		1,306	(1,324)
Tax on net current-period other comprehensive income (loss)		$ (5,542)	$ 7,888

[1] Due to the adoption of ASU No. 2018-02, an amendment to ASC 740, Income Taxes. See Note 2. Summary of Significant Accounting Policies - Recently Adopted Updates to the Accounting Standards Codification section for more details.

[2] Included in the computation of net periodic pension cost, a component of O&M expense on the Consolidated Statements of Operations. For more details, see Note 10. Employee Benefit Plans.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - RECENTLY ADOPTED ACCOUNTING STANDARDS (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Accounting Policies [Abstract]
Reclassifications of certain income tax effects to retained earnings	[1]	$ 3,300
Equity reclass		1,418,978	$ 1,236,643	$ 1,166,591	$ 1,106,956
Deferred gain, unamortized balance		$ (6,800)

[1] Due to the adoption of ASU No. 2018-02, an amendment to ASC 740, Income Taxes. See Note 2. Summary of Significant Accounting Policies - Recently Adopted Updates to the Accounting Standards Codification section for more details.

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REGULATION - REGULATORY ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands		Sep. 30, 2018	Sep. 30, 2017
Regulatory Assets [Line Items]
Regulatory assets-current		$ 18,297	$ 50,791
Regulatory assets-noncurrent		368,592	375,919
Regulatory Liabilities [Line Items]
Regulatory liability-current		8,185	78
Regulatory liabilities-noncurrent		209,139	14,507
Conservation Incentive Program
Regulatory Liabilities [Line Items]
Regulatory liability-current		6,994	0
Tax Act impact
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	[1]	205,410	0
Cost of removal
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent		0	7,902
New Jersey Clean Energy Program
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent		1,902	5,795
Other noncurrent regulatory liabilities
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent		1,827	810
Derivatives at fair value, net
Regulatory Liabilities [Line Items]
Regulatory liability-current		1,191	78
New Jersey Clean Energy Program
Regulatory Assets [Line Items]
Regulatory assets-current		14,052	14,202
Underrecovered gas costs
Regulatory Assets [Line Items]
Regulatory assets-current		4,137	9,910
Derivatives at fair value, net
Regulatory Assets [Line Items]
Regulatory assets-current		108	9,010
Conservation Incentive Program
Regulatory Assets [Line Items]
Regulatory assets-current		0	17,669
Environmental remediation costs, Expended, net of recoveries
Regulatory Assets [Line Items]
Regulatory assets-noncurrent		33,017	28,547
Environmental remediation costs, Liability for future expenditures
Regulatory Assets [Line Items]
Regulatory assets-noncurrent		130,800	149,000
Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets-noncurrent		17,225	21,795
SAVEGREEN
Regulatory Assets [Line Items]
Regulatory assets-noncurrent		8,636	16,302
Postemployment and other benefit costs
Regulatory Assets [Line Items]
Regulatory assets-noncurrent		136,716	141,433
Deferred Superstorm Sandy costs
Regulatory Assets [Line Items]
Regulatory assets-noncurrent		10,858	13,030
Cost of removal
Regulatory Assets [Line Items]
Regulatory assets-noncurrent		22,339	0
Other noncurrent regulatory assets
Regulatory Assets [Line Items]
Regulatory assets-noncurrent		$ 9,001	$ 5,812

[1] Includes an adjustment related to the re-measurement of NJNG's net deferred tax liabilities to reflect the change in federal tax rates enacted in the Tax Act, which is net of sales tax collected from customers. For a more detailed discussion, see Note 12. Income Taxes.

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REGULATION - REGULATORY FILINGS (Details) $ in Thousands							1 Months Ended				4 Months Ended	12 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 17, 2018 USD ($)	May 22, 2018 USD ($)	Mar. 01, 2018 USD ($)	Jul. 20, 2017 USD ($)	Oct. 01, 2016 USD ($)	Mar. 31, 2018 USD ($)	Sep. 30, 2017 USD ($)	Oct. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Feb. 28, 2017 USD ($)	Sep. 30, 2018 USD ($) project
Public Utilities, General Disclosures [Line Items]
Regulatory assets-noncurrent	$ 368,592							$ 375,919				$ 368,592
Public utilities, approved equity capital structure, percentage												6.90%
Return on equity										9.75%
Environmental Remediation Costs
Public Utilities, General Disclosures [Line Items]
Regulatory assets, amortization period												7 years
Postemployment and Other Benefit Costs
Public Utilities, General Disclosures [Line Items]
Regulatory assets, amortization period												7 years
Deferred Storm Damage Costs
Public Utilities, General Disclosures [Line Items]
Regulatory assets, amortization period												7 years
Other Regulatory Asset Noncurrent, PIM
Public Utilities, General Disclosures [Line Items]
Regulatory assets, amortization period												7 years
Regulatory assets-noncurrent	3,200											$ 3,200
SAVEGREEN
Public Utilities, General Disclosures [Line Items]
Capital investments approved by the BPU	354,300	$ 135,000
Grants, rebates and loans provided to customers												162,000
Increase in regulatory funding obligations												$ 16,100
SAVEGREEN | Minimum
Public Utilities, General Disclosures [Line Items]
Regulatory assets, amortization period												2 years
Program recovery term												3 years
Public utilities, approved equity capital structure, percentage												6.69%
Return on equity												9.75%
SAVEGREEN | Maximum
Public Utilities, General Disclosures [Line Items]
Regulatory assets, amortization period												10 years
Program recovery term												10 years
Public utilities, approved equity capital structure, percentage												7.76%
Return on equity												10.30%
Energy Efficiency EE
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease), amount	$ (8,800)
March 2018 BGSS/CIP Filing
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease), amount				$ 19,700
Requested customer refunds				$ 31,000
Approved customer refunds			$ 31,000
June 2016 BGSS/CIP Filing
Public Utilities, General Disclosures [Line Items]
Customer bill credits											$ 42,000
June 2016 BGSS/CIP Filing | Conservation Incentive Program
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease), amount										$ 43,900
June 2016 BGSS/CIP Filing | Basic Gas Supply Service
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease), amount										$ (22,600)
June 2017 BGSS/CIP Filing | Conservation Incentive Program
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease), amount							$ (16,200)
Increase in annual revenues							$ 3,700
May 2018 BGSS/CIP Filing | Conservation Incentive Program
Public Utilities, General Disclosures [Line Items]
Increase in annual revenues		10,300
Requested base rate increase, amount		(30,900)
USF
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease), amount		1,000						(2,600)
RAC
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease), amount		1,400						(2,400)
NJCEP
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease), amount		1,900						$ 1,800
SAFE Program
Public Utilities, General Disclosures [Line Items]
Capital investments approved by the BPU									$ 200,000			$ 130,000
Capital investments approved by the BPU, period												4 years
Capital investments to be recovered approved by the Board of Public Utilities									$ 157,500
NJ RISE Program
Public Utilities, General Disclosures [Line Items]
Program recovery term												5 years
Public utilities, approved equity capital structure, percentage												6.74%
Return on equity												9.75%
Number of capital investment projects | project												6
Originally filed petition for capital investments to Board of Public Utilities												$ 102,500
SAFE II and NJ RISE
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease), amount		$ 6,800			$ 4,100
Public utilities, approved equity capital structure, percentage												6.90%
SRL-Southern Reliability Link | Minimum
Public Utilities, General Disclosures [Line Items]
Estimated cost of the SRL												$ 180,000
SRL-Southern Reliability Link | Maximum
Public Utilities, General Disclosures [Line Items]
Estimated cost of the SRL												$ 215,000
LNG-Liquefied Natural Gas
Public Utilities, General Disclosures [Line Items]
Capital investments to be recovered approved by the Board of Public Utilities						$ 36,500

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DERIVATIVE INSTRUMENTS - BALANCE SHEET RELATED DISCLOSURES (Details) - USD ($) $ in Thousands		Sep. 30, 2018	Jan. 26, 2018	Sep. 30, 2017
Derivatives, Fair Value [Line Items]
Asset Derivatives, current		$ 27,396		$ 30,081
Asset Derivatives, noncurrent		10,560		9,164
Liability Derivatives, current		46,652		46,544
Liability Derivatives, noncurrent		22,982		11,330
Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives		37,956		39,245
Liability Derivatives		69,634		57,874
Interest rate swap
Derivatives, Fair Value [Line Items]
Fixed treasury rate			2.84%
Term loan | Credit Agreement Due August 16, 2019 | Interest rate swap
Derivatives, Fair Value [Line Items]
Long-term debt			$ 100,000
Home Services and Other | Interest rate contract | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current		381		0
Liability Derivatives, current		0		0
Natural Gas Distribution | Physical commodity contracts | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current		85		151
Liability Derivatives, current		192		72
Natural Gas Distribution | Financial commodity contracts | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current		94		0
Liability Derivatives, current		0		1,149
Natural Gas Distribution | Interest rate contract | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current	[1]	0		0
Liability Derivatives, current	[1]	0		8,467
Energy Services | Physical commodity contracts | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current		7,667		14,588
Asset Derivatives, noncurrent		3,930		7,127
Liability Derivatives, current		18,158		16,589
Liability Derivatives, noncurrent		11,316		8,710
Energy Services | Financial commodity contracts | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current		19,169		15,302
Asset Derivatives, noncurrent		6,630		2,033
Liability Derivatives, current		28,176		20,267
Liability Derivatives, noncurrent		11,548		2,620
Energy Services | Foreign currency contracts | Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives, current		0		40
Asset Derivatives, noncurrent		0		4
Liability Derivatives, current		126		0
Liability Derivatives, noncurrent		$ 118		$ 0

[1] Includes treasury lock which was settled in March 2018. See Note 8. Debt for more information.

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- OFFSETTING OF ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Sep. 30, 2017
Financial commodity contracts
Derivative assets:
Amounts Presented on the Balance Sheets	[1]	$ 94
Offsetting Derivative Instruments	[2]	0
Financial Collateral Received/Pledged	[3]	(94)
Net Amounts	[4]	0
Energy Services
Derivative assets:
Amounts Presented on the Balance Sheets	[1]	37,396	$ 39,094
Offsetting Derivative Instruments	[2]	(22,719)	(16,294)
Financial Collateral Received/Pledged	[3]	(200)	(200)
Net Amounts	[4]	14,477	22,600
Derivative liabilities:
Amounts Presented in Balance Sheets	[1]	69,442	48,186
Offsetting Derivative Instruments	[2]	(22,719)	(16,294)
Financial Collateral Received/Pledged	[3]	(20,949)	(8,766)
Net Amounts	[4]	25,774	23,126
Energy Services | Physical commodity contracts
Derivative assets:
Amounts Presented on the Balance Sheets	[1]	11,597	21,715
Offsetting Derivative Instruments	[2]	(3,944)	(2,173)
Financial Collateral Received/Pledged	[3]	(200)	(200)
Net Amounts	[4]	7,453	19,342
Derivative liabilities:
Amounts Presented in Balance Sheets	[1]	29,474	25,299
Offsetting Derivative Instruments	[2]	(3,944)	(2,173)
Financial Collateral Received/Pledged	[3]	0	0
Net Amounts	[4]	25,530	23,126
Energy Services | Financial commodity contracts
Derivative assets:
Amounts Presented on the Balance Sheets	[1]	25,799	17,335
Offsetting Derivative Instruments	[2]	(18,775)	(14,121)
Financial Collateral Received/Pledged	[3]	0	0
Net Amounts	[4]	7,024	3,214
Derivative liabilities:
Amounts Presented in Balance Sheets	[1]	39,724	22,887
Offsetting Derivative Instruments	[2]	(18,775)	(14,121)
Financial Collateral Received/Pledged	[3]	(20,949)	(8,766)
Net Amounts	[4]	0	0
Energy Services | Foreign currency contracts
Derivative assets:
Amounts Presented on the Balance Sheets	[1]		44
Offsetting Derivative Instruments	[2]		0
Financial Collateral Received/Pledged	[3]		0
Net Amounts	[4]		44
Derivative liabilities:
Amounts Presented in Balance Sheets	[1]	244
Offsetting Derivative Instruments	[2]	0
Financial Collateral Received/Pledged	[3]	0
Net Amounts	[4]	244
Natural Gas Distribution
Derivative assets:
Amounts Presented on the Balance Sheets	[1]	179	151
Offsetting Derivative Instruments	[2]	(3)	(20)
Financial Collateral Received/Pledged	[3]	(94)	0
Net Amounts	[4]	82	131
Derivative liabilities:
Amounts Presented in Balance Sheets	[1]	192	9,688
Offsetting Derivative Instruments	[2]	(3)	(20)
Financial Collateral Received/Pledged	[3]	0	(1,149)
Net Amounts	[4]	189	8,519
Natural Gas Distribution | Physical commodity contracts
Derivative assets:
Amounts Presented on the Balance Sheets	[1]	85	151
Offsetting Derivative Instruments	[2]	(3)	(20)
Financial Collateral Received/Pledged	[3]	0	0
Net Amounts	[4]	82	131
Derivative liabilities:
Amounts Presented in Balance Sheets	[1]	192	72
Offsetting Derivative Instruments	[2]	(3)	(20)
Financial Collateral Received/Pledged	[3]	0	0
Net Amounts	[4]	189	52
Natural Gas Distribution | Financial commodity contracts
Derivative liabilities:
Amounts Presented in Balance Sheets	[1]		1,149
Offsetting Derivative Instruments	[2]		0
Financial Collateral Received/Pledged	[3]		(1,149)
Net Amounts	[4]		0
Natural Gas Distribution | Interest rate contract
Derivative liabilities:
Amounts Presented in Balance Sheets	[1]		8,467
Offsetting Derivative Instruments	[2]		0
Financial Collateral Received/Pledged	[3]		0
Net Amounts	[4]		$ 8,467
Home Services and Other
Derivative assets:
Amounts Presented on the Balance Sheets	[1]	381
Offsetting Derivative Instruments	[2]	0
Financial Collateral Received/Pledged	[3]	0
Net Amounts	[4]	381
Home Services and Other | Interest rate contract
Derivative assets:
Amounts Presented on the Balance Sheets	[1]	381
Offsetting Derivative Instruments	[2]	0
Financial Collateral Received/Pledged	[3]	0
Net Amounts	[4]	$ 381

[1] Derivative assets and liabilities are presented on a gross basis in the balance sheet as the Company does not elect balance sheet offsetting under ASC 210-20.

[2] Offsetting derivative instruments include transactions with NAESB netting election, transactions held by FCMs with net margining and transactions with ISDA netting.

[3] Financial collateral includes cash balances at FCMs, as well as cash received from or pledged to other counterparties.

[4] Net amounts represent presentation of derivative assets and liabilities if the Company were to elect balance sheet offsetting under ASC 210-20.

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DERIVATIVE INSTRUMENTS - INCOME STATEMENT RELATED DISCLOSURES (Details) - Derivatives not designated as hedging instruments: - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ (34,175)	$ 8,055	$ 32,942
Natural Gas Distribution
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	11,543	7,898	(42,585)
Natural Gas Distribution | Physical commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	1,232	(12,303)	(15,756)
Natural Gas Distribution | Financial commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	1,844	5,595	(7,984)
Natural Gas Distribution | Interest rate contract
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	8,467	14,606	(18,845)
Energy Services | Physical commodity contracts | Operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	(9,311)	8,912	33,034
Energy Services | Physical commodity contracts | Gas purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	(197)	(27,461)	(45,637)
Energy Services | Financial commodity contracts | Gas purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	(24,622)	26,563	45,579
Energy Services | Foreign currency contracts | Gas purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	(379)	41	(34)
Home Services and Other | Interest rate contract | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 334	$ 0	$ 0

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DERIVATIVE INSTRUMENTS - VOLUME (Details) $ in Millions	Sep. 30, 2018 USD ($) Bcf certificate	Sep. 30, 2017 Bcf
Foreign currency contracts
Derivative [Line Items]
Derivative, notional amount | $	$ 8.5
Natural Gas Distribution | Long | Futures
Derivative [Line Items]
Outstanding long (short) derivatives (in Bcf)	27.9	18.2
Natural Gas Distribution | Long | Physical
Derivative [Line Items]
Outstanding long (short) derivatives (in Bcf)	23.1	32.1
Energy Services | Physical commodity contracts
Derivative [Line Items]
Number of Solar Renewable Energy Certificates (in certificates) | certificate	(698,700)
Energy Services | Short | Futures
Derivative [Line Items]
Outstanding long (short) derivatives (in Bcf)	(7.0)	(16.4)
Energy Services | Short | Physical
Derivative [Line Items]
Outstanding long (short) derivatives (in Bcf)	51.2	(13.1)

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DERIVATIVE INSTRUMENTS - BROKER MARGIN DEPOSITS (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017
Natural Gas Distribution
Broker margin - Current assets	$ 2,038	$ 2,661
Energy Services
Broker margin - Current assets	$ 51,681	$ 23,166

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DERIVATIVE INSTRUMENTS - CREDIT RISK EXPOSURE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Credit Risk Exposure [Line Items]
Gross Credit Exposure	$ 280,004
Derivative, net liability position, aggregate fair value	124	$ 8,700
Additional collateral, aggregate fair value	33	$ 8,600
Investment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	179,982
Noninvestment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	43,486
Internally-rated investment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	30,786
Internally-rated noninvestment grade
Credit Risk Exposure [Line Items]
Gross Credit Exposure	$ 25,750

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FAIR VALUE - DEBT (Details) - Significant Other Observable Inputs (Level 2) - USD ($) $ in Thousands		Sep. 30, 2018	Sep. 30, 2017
Natural Gas Distribution | Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	[1]	$ 672,045	$ 672,045
Natural Gas Distribution | Fair market value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	[1]	669,162	673,051
NJR | Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	[1]	500,000	425,000
NJR | Fair market value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	[1]	$ 488,889	$ 434,625

[1] See Note 8. Debt for a reconciliation to long-term and short-term debt.

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FAIR VALUE - HIERARCHY (Details) - USD ($) $ in Thousands		6 Months Ended
		Mar. 31, 2018	Sep. 30, 2018	Sep. 30, 2017
Assets
Other			$ 1,800
Liabilities
Impairment of available for sale securities		$ 17,800
Available-for-sale		$ 28,200
Fair Value, Measurements, Recurring
Assets
Available for sale equity securities			32,917	$ 65,752
Other	[1]		1,217	1,202
Total assets at fair value			72,090	106,199
Liabilities
Total liabilities at fair value			69,634	57,874
Fair Value, Measurements, Recurring | Physical commodity contracts
Assets
Derivative assets			11,682	21,866
Liabilities
Derivative liabilities			29,666	25,371
Fair Value, Measurements, Recurring | Financial commodity contracts
Assets
Derivative assets			25,893	17,335
Liabilities
Derivative liabilities			39,724	24,036
Fair Value, Measurements, Recurring | Foreign currency contracts
Assets
Derivative assets			0	44
Liabilities
Derivative liabilities			244
Fair Value, Measurements, Recurring | Interest rate contract
Assets
Derivative assets			381
Liabilities
Derivative liabilities				8,467
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Available for sale equity securities			32,917	65,752
Other	[1]		1,217	1,202
Total assets at fair value			53,002	84,289
Liabilities
Total liabilities at fair value			39,724	24,036
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Physical commodity contracts
Assets
Derivative assets			0	0
Liabilities
Derivative liabilities			0	0
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Financial commodity contracts
Assets
Derivative assets			18,868	17,335
Liabilities
Derivative liabilities			39,724	24,036
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign currency contracts
Assets
Derivative assets			0	0
Liabilities
Derivative liabilities			0
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate contract
Assets
Derivative assets			0
Liabilities
Derivative liabilities				0
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets
Available for sale equity securities			0	0
Other	[1]		0	0
Total assets at fair value			19,088	21,910
Liabilities
Total liabilities at fair value			29,910	33,838
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Physical commodity contracts
Assets
Derivative assets			11,682	21,866
Liabilities
Derivative liabilities			29,666	25,371
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Financial commodity contracts
Assets
Derivative assets			7,025
Liabilities
Derivative liabilities			0	0
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Foreign currency contracts
Assets
Derivative assets			0	44
Liabilities
Derivative liabilities			244
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Interest rate contract
Assets
Derivative assets			381
Liabilities
Derivative liabilities				8,467
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets
Available for sale equity securities			0	0
Other	[1]		0	0
Total assets at fair value			0	0
Liabilities
Total liabilities at fair value			0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Physical commodity contracts
Assets
Derivative assets			0	0
Liabilities
Derivative liabilities			0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Financial commodity contracts
Assets
Derivative assets			0
Liabilities
Derivative liabilities			0	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Foreign currency contracts
Assets
Derivative assets			0	0
Liabilities
Derivative liabilities			0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Interest rate contract
Assets
Derivative assets			$ 0
Liabilities
Derivative liabilities				$ 0

[1] Includes money market funds.

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INVESTMENTS IN EQUITY INVESTEES (Details) $ in Thousands		12 Months Ended
		Sep. 30, 2018 USD ($) mi	Sep. 30, 2017 USD ($)
Schedule of Equity Method Investments [Line Items]
Investments in equity investees		$ 190,866	$ 172,585
Steckman Ridge
Schedule of Equity Method Investments [Line Items]
Investments in equity investees	[1]	117,001	120,262
Outstanding principal balance		70,400	70,400
PennEast
Schedule of Equity Method Investments [Line Items]
Investments in equity investees		$ 73,865	$ 52,323
Construction plan, pipeline distance (in miles) | mi		120

[1] Includes loans with a total outstanding principal balance of $70.4 million for both fiscal 2018 and 2017, which accrue interest at a variable rate that resets quarterly and are due October 1, 2023.

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EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended																12 Months Ended
		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2016
Earnings Per Share [Abstract]
Net income, as reported		$ (16,255)		$ (14,274)		$ 140,266		$ 123,699		$ (36,523)		$ 18,957		$ 114,702		$ 34,929		$ 233,436		$ 132,065		$ 131,672
Basic earnings per share
Weighted average shares of common stock outstanding-basic (in shares)																		87,689,000		86,321,000		85,884,000
Basic earnings per common share (in dollars per share)		$ (0.18)	[1]	$ (0.16)	[1]	$ 1.60	[1]	$ 1.42	[1]	$ (0.42)	[1]	$ 0.22	[1]	$ 1.33	[1]	$ 0.41	[1]	$ 2.66		$ 1.53		$ 1.53
Diluted earnings per share
Weighted average shares of common stock outstanding-basic (in shares)																		87,689,000		86,321,000		85,884,000
Incremental shares (in shares)	[2]																	626,000		823,000		847,000
Weighted average shares of common stock outstanding-diluted (in shares)																		88,315,000		87,144,000		86,731,000
Diluted earnings per common share (in dollars per share)		$ (0.18)	[1]	$ (0.16)	[1]	$ 1.59	[1]	$ 1.42	[1]	$ (0.42)	[1]	$ 0.22	[1]	$ 1.32	[1]	$ 0.40	[1]	$ 2.64	[3]	$ 1.52	[3]	$ 1.52	[3]
Anti-dilutive securities excluded from the calculation of diluted earnings per share (in shares)																		0		0		0

[1] The sum of quarterly amounts may not equal the annual amounts due to rounding.

[2] Incremental shares consist primarily of unvested stock awards and performance units.

[3] There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2018, 2017 and 2016.

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DEBT - SCHEDULE OF LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017	Jun. 21, 2016	Mar. 22, 2016
Debt Instrument [Line Items]
Total long-term debt	$ 1,180,619	$ 997,080
Natural Gas Distribution
Debt Instrument [Line Items]
Debt issuance costs	(6,515)	(6,262)
Less: Current maturities of long-term debt	(9,502)	(135,800)
Total long-term debt	691,965	569,642
Natural Gas Distribution | First mortgage bonds: | Series LL
Debt Instrument [Line Items]
Long-term debt	0	125,000
Natural Gas Distribution | First mortgage bonds: | Series MM
Debt Instrument [Line Items]
Long-term debt	9,545	9,545
Natural Gas Distribution | First mortgage bonds: | Series NN
Debt Instrument [Line Items]
Long-term debt	41,000	41,000
Natural Gas Distribution | First mortgage bonds: | Series OO
Debt Instrument [Line Items]
Long-term debt	46,500	46,500
Natural Gas Distribution | First mortgage bonds: | Series PP
Debt Instrument [Line Items]
Long-term debt	$ 50,000	50,000
Stated interest rate	3.15%
Natural Gas Distribution | First mortgage bonds: | Series QQ
Debt Instrument [Line Items]
Long-term debt	$ 70,000	70,000
Stated interest rate	3.58%
Natural Gas Distribution | First mortgage bonds: | Series RR
Debt Instrument [Line Items]
Long-term debt	$ 55,000	55,000
Stated interest rate	4.61%
Natural Gas Distribution | First mortgage bonds: | Series SS
Debt Instrument [Line Items]
Long-term debt	$ 50,000	50,000
Stated interest rate	2.82%
Natural Gas Distribution | First mortgage bonds: | Series TT
Debt Instrument [Line Items]
Long-term debt	$ 100,000	100,000
Stated interest rate	3.66%
Natural Gas Distribution | First mortgage bonds: | Series UU
Debt Instrument [Line Items]
Long-term debt	$ 125,000	125,000
Stated interest rate	3.63%		3.63%
Natural Gas Distribution | First mortgage bonds: | Series VV
Debt Instrument [Line Items]
Long-term debt	$ 125,000	0
Stated interest rate	4.01%
Natural Gas Distribution | Capital lease obligations | Capital lease obligation-buildings
Debt Instrument [Line Items]
Long-term debt	$ 8,749	11,617
Natural Gas Distribution | Capital lease obligations | Capital lease obligation-meters
Debt Instrument [Line Items]
Long-term debt	27,188	28,042
NJR
Debt Instrument [Line Items]
Debt issuance costs	(1,136)	(770)
Less: Current maturities of long-term debt	(100,000)	(25,000)
Total long-term debt	398,864	399,230
NJR | Unsecured senior notes 2.51%
Debt Instrument [Line Items]
Long-term debt	$ 0	25,000
Stated interest rate	2.51%
NJR | Unsecured senior notes 3.25%
Debt Instrument [Line Items]
Long-term debt	$ 50,000	50,000
Stated interest rate	3.25%
NJR | Unsecured senior notes 3.48%
Debt Instrument [Line Items]
Long-term debt	$ 100,000	100,000
Stated interest rate	3.48%
NJR | Unsecured senior notes 3.20%
Debt Instrument [Line Items]
Long-term debt	$ 50,000	50,000
Stated interest rate				3.20%
NJR | Unsecured senior notes 3.54%
Debt Instrument [Line Items]
Long-term debt	100,000	100,000
Stated interest rate				3.54%
NJR | Unsecured senior notes 3.96%
Debt Instrument [Line Items]
Long-term debt	100,000	0
Stated interest rate				3.96%
NJR | Term loan | Credit Agreement Due August 16, 2019
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	100,000	100,000
Clean Energy Ventures
Debt Instrument [Line Items]
Long-term debt	103,923	32,790
Less: Current maturities of long-term debt	(14,133)	(4,582)
Long-term debt, excluding current maturities	$ 89,790	$ 28,208

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DEBT - REDEMPTION REQUIREMENTS (Details) $ in Thousands	Sep. 30, 2018 USD ($)
NJR
Debt Instrument [Line Items]
2019	$ 100,000
2020	0
2021	0
2022	50,000
2023	50,000
Thereafter	300,000
Natural Gas Distribution
Debt Instrument [Line Items]
2019	0
2020	0
2021	0
2022	0
2023	0
Thereafter	$ 672,045

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DEBT - FIRST MORTGAGE BONDS (Details) $ in Thousands			12 Months Ended
	Mar. 13, 2018 USD ($)	Jan. 17, 2017 USD ($) First_mortgage_bond	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Jun. 21, 2016	Jun. 01, 2015
Debt Instrument [Line Items]
NJBPU dividend restriction, equity to capitalization ratio			0.3
Debt to equity ratio			0.567
Number of first mortgage bonds completed | First_mortgage_bond		3
Payment of long-term debt			$ 165,486	$ 97,854	$ 13,289
Variable Rate Debt
Debt Instrument [Line Items]
Long-term debt			97,000
First mortgage bonds:
Debt Instrument [Line Items]
Maximum amount that can be issued			1,000,000
Natural Gas Distribution | Series LL
Debt Instrument [Line Items]
Long-term debt			$ 125,000
Stated interest rate			5.60%
Natural Gas Distribution | First mortgage bonds:
Debt Instrument [Line Items]
Payment of long-term debt		$ 35,800
Natural Gas Distribution | First mortgage bonds: | Series UU
Debt Instrument [Line Items]
Long-term debt			$ 125,000	125,000
Stated interest rate			3.63%			3.63%
Natural Gas Distribution | First mortgage bonds: | Series VV
Debt Instrument [Line Items]
Long-term debt			$ 125,000	0
Stated interest rate			4.01%
Natural Gas Distribution | First mortgage bonds: | Series LL
Debt Instrument [Line Items]
Long-term debt			$ 0	$ 125,000
Natural Gas Distribution | Variable demand rate notes
Debt Instrument [Line Items]
Interest rate on EDA Bonds			2.03%
Natural Gas Distribution | Minimum | First mortgage bonds: | Series II
Debt Instrument [Line Items]
Stated interest rate		4.50%
Natural Gas Distribution | Maximum | First mortgage bonds: | Series II
Debt Instrument [Line Items]
Stated interest rate		4.90%
Treasury lock
Debt Instrument [Line Items]
Stated interest rate							4.01%
Fixed treasury rate							3.26%
Amount of gain (loss) recognized in income on derivatives	$ 2,600

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DEBT - SALE-LEASEBACKS (Details) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)
Debt Instrument [Line Items]
Proceeds from sale-leaseback transaction			$ 7,820	$ 9,587	$ 7,107
Natural Gas Distribution
Debt Instrument [Line Items]
Sale leaseback transaction, lease term			25 years 6 months
Sale leaseback transaction, lease renewal term			5 years
Sale leaseback transaction, maximum lease renewal term (as a percent)			4
Proceeds from sale-leaseback transaction	$ 7,800	$ 9,600			7,100
Sale leaseback transaction, other payments required			$ 2,200	$ 2,400	$ 1,900

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DEBT - CONTRACTUAL COMMITMENTS (Details) $ in Thousands	Sep. 30, 2018 USD ($)
NJR
Debt Instrument [Line Items]
2019	$ 10,932
2020	7,989
2021	9,236
2022	3,775
2023	2,393
Thereafter	5,245
Subtotal	39,570
Less: Interest component	(3,633)
Total	35,937
Clean Energy Ventures
Debt Instrument [Line Items]
2019	9,794
2020	7,830
2021	7,803
2022	7,802
2023	7,878
Thereafter	38,303
Subtotal	79,410
Less: Interest component	(26,728)
Total	$ 52,682

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DEBT - NJR LONG-TERM DEBT (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016	Jan. 26, 2018	Mar. 22, 2016
Debt Instrument [Line Items]
Proceeds from sale-leaseback transaction - solar	$ 71,538	$ 32,901	$ 0
Clean Energy Ventures
Debt Instrument [Line Items]
Proceeds from sale-leaseback transaction - solar	71,538	32,901
Interest rate swap
Debt Instrument [Line Items]
Fixed treasury rate				2.84%
Interest rate swap | Credit Agreement Due August 16, 2019 | Term loan
Debt Instrument [Line Items]
Long-term debt				$ 100,000
NJR | Unsecured senior notes 3.20%
Debt Instrument [Line Items]
Long-term debt	50,000	50,000
Stated interest rate					3.20%
NJR | Unsecured senior notes 3.54%
Debt Instrument [Line Items]
Long-term debt	100,000	100,000
Stated interest rate					3.54%
NJR | Unsecured senior notes 3.96%
Debt Instrument [Line Items]
Long-term debt	$ 100,000	$ 0
Stated interest rate					3.96%
Minimum | Clean Energy Ventures
Debt Instrument [Line Items]
Term of lease	6 years
Maximum | Clean Energy Ventures
Debt Instrument [Line Items]
Term of lease	15 years

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DEBT - SHORT-TERM BANK FACILITIES (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017
Letters of credit
Short-term Debt [Line Items]
Letters of credit outstanding, amount			$ 13,400
NJR | Letters of credit
Short-term Debt [Line Items]
Letters of credit outstanding, amount		$ 14,900
NJR | Notes payable to banks
Short-term Debt [Line Items]
Outstanding at end of period		$ 87,950	$ 255,000
Weighted average interest rate at end of period		3.07%	2.14%
Amount available at end of period	[1]	$ 322,144	$ 156,601
NJR | Committed Credit Facilities Due September 2020
Short-term Debt [Line Items]
Bank revolving credit facilities	[2]	$ 425,000	425,000
NJR | Bank revolving credit facilities
Short-term Debt [Line Items]
Commitment fee percentage		0.075%
Natural Gas Distribution | Commercial paper
Short-term Debt [Line Items]
Outstanding at end of period		$ 64,000	$ 11,000
Weighted average interest rate at end of period		2.18%	1.13%
Amount available at end of period	[3]	$ 185,269	$ 238,269
Natural Gas Distribution | Letters of credit
Short-term Debt [Line Items]
Letters of credit outstanding, amount		$ 731	$ 731
Natural Gas Distribution | Bank revolving credit facilities
Short-term Debt [Line Items]
Commitment fee percentage		0.075%

[1] Letters of credit outstanding total $14.9 million and $13.4 million as of September 30, 2018 and 2017, respectively, which reduces amount available by the same amount.

[2] Committed credit facilities, which require commitment fees of .075 percent on the unused amounts.

[3] Letters of credit outstanding total $731,000 as of September 30, 2018 and 2017, which reduces amount available by the same amount.

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DEBT - NJR SHORT-TERM DEBT (Details)			12 Months Ended
		Dec. 14, 2017 USD ($)	Sep. 30, 2018 USD ($) debt_instrument Mutual_option	Apr. 18, 2018 USD ($)	Jan. 19, 2018 USD ($)	Sep. 30, 2017 USD ($)
Short-term Debt [Line Items]
Number of mutual options | Mutual_option			2
Number of mutual options, extension period			1 year
Letters of credit
Short-term Debt [Line Items]
Letters of credit outstanding, amount						$ 13,400,000
Revolving line of credit, 4 months
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity		$ 75,000,000
Line of credit facility, maximum borrowing capacity, incremental increase					$ 100,000,000
Debt instrument, term		4 months
Line of credit facility, fair value of amount outstanding				$ 0
NJR | Letters of credit
Short-term Debt [Line Items]
Number of debt instruments (in debt instruments) | debt_instrument			6
Letters of credit outstanding, amount			$ 14,900,000
NJR | Letters of Credit on Behalf of NJRES
Short-term Debt [Line Items]
Number of debt instruments (in debt instruments) | debt_instrument			3
Letters of credit outstanding, amount			$ 11,900,000
NJR | Letters of Credit on Behalf of NJRCEV
Short-term Debt [Line Items]
Number of debt instruments (in debt instruments) | debt_instrument			3
Letters of credit outstanding, amount			$ 3,000,000
NJR | Committed Credit Facilities Due September 2020
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	[1]		425,000,000			$ 425,000,000
NJR | Bank revolving credit facilities
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity, incremental increase			5,000,000
Line of credit facility, maximum borrowing capacity, maximum increase			$ 100,000,000

[1] Committed credit facilities, which require commitment fees of .075 percent on the unused amounts.

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DEBT - NJNG SHORT-TERM DEBT (Details)		12 Months Ended
		Sep. 30, 2018 USD ($) debt_instrument	Sep. 30, 2017 USD ($)
Letters of credit
Line of Credit Facility [Line Items]
Letters of credit outstanding, amount			$ 13,400,000
Natural Gas Distribution | Letters of credit
Line of Credit Facility [Line Items]
Number of debt instruments (in debt instruments) | debt_instrument		2
Letters of credit outstanding, amount		$ 731,000	731,000
Natural Gas Distribution | Committed Credit Facilities Due May 2019 | Bank revolving credit facilities
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	[1]	$ 250,000,000	$ 250,000,000
Natural Gas Distribution | Bank revolving credit facilities
Line of Credit Facility [Line Items]
Debt instrument, term		5 years
Line of credit facility, maximum borrowing capacity, incremental increase		$ 15,000,000
Line of credit facility, maximum borrowing capacity, maximum increase		$ 50,000,000

[1] Committed credit facilities, which require commitment fees of .075 percent on the unused amounts.

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STOCK-BASED COMPENSATION - NARRATIVE (Details) - USD ($)		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for future issuance (in shares)		3,473,061.93
Performance Shares, Market Condition Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)		31,836	44,576	46,175
Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)		59,341	51,931	69,305
Deferred compensation related to unvested performance shares, period		1 year 8 months 12 days
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)	[1]	145,176	156,587	179,916	214,464
Deferred compensation related to unvested restricted and performance shares		$ 3,800,000
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)		44,168	51,154	73,071	81,492
Deferred compensation related to unvested restricted and performance shares		$ 612,964
Deferred compensation related to unvested performance shares, period		2 years
Vesting September 30, 2020 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)		29,608
Vesting Annually Over Three Year Period Beginning September 30, 2018 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)		29,733
Award vesting period		3 years
Vesting September 30, 2019 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)			25,806
Vesting Annually Over Three Year Period Beginning September 30, 2017 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)			26,125
Award vesting period			3 years
Vesting September 30, 2018 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)				38,789
Vesting Annually Over Three Year Period Beginning September 30, 2016 | Performance Shares, Subject to Performance Conditions
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)				30,516
Award vesting period				3 years
Vesting Annually Over Three Year Period Beginning October 15, 2018 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)		27,949
Award vesting period		3 years
Vesting Annually Over Three Year Period Beginning October 2017 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)			22,591
Award vesting period			3 years
Vesting Annually Over Three Year Period Beginning May 8, 2018 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)			6,143
Award vesting period			3 years
Vesting Annually Over a Three Year Period Beginning in October 2016 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)				41,909
Award vesting period				3 years
NJR 2007 Stock Award And Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted but not issued (in shares)			914,169
NJR 2017 Stock Award And Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional shares authorized for issuance (in shares)		3,135,000

[1] The number of common shares issued related to certain performance shares may range from zero to 150 percent of the number of shares shown in the table above based on the Company’s achievement of performance goals.

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STOCK-BASED COMPENSATION - STOCK-BASED COMPENSATION EXPENSE (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense		$ 12,845	$ 5,807	$ 7,234
Income tax benefit	[1]	(3,734)	(2,372)	(2,955)
Total, net of tax		9,111	3,435	4,279
Tax benefit of delivered shares from stock based compensation		2,950	1,285	1,755
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense		3,526	2,614	3,188
Restricted and non-restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense		2,191	1,732	2,161
Deferred retention stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense included in operation and maintenance expense		$ 7,128	$ 1,461	$ 1,885

[1] Excludes additional tax benefit related to delivered shares of $3 million, $1.3 million and $1.8 million as of September 30, 2018, 2017 and 2016, respectively.

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STOCK-BASED COMPENSATION - PERFORMANCE SHARES AND RESTRICTED STOCK ACTIVITY (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
		Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2016		Nov. 13, 2018	Nov. 14, 2017	Nov. 15, 2016
Performance share awards
Shares
Outstanding at beginning of period (in shares)	[1]	156,587		179,916		214,464
Granted (in shares)	[1]	91,177		96,507		115,480
Vested (in shares)	[1]	(100,146)	[2]	(95,407)	[3]	(137,053)	[4]
Cancelled/forfeited (in shares)	[1]	(2,442)		(24,429)		(12,975)	[5]
Outstanding at end of period (in shares)	[1]	145,176		156,587		179,916
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)		$ 30.12		$ 27.47		$ 23.40
Granted (in dollars per share)		44.67		33.57		27.37
Vested (in dollars per share)		29.49	[2]	28.88	[3]	21.40	[4]
Cancelled/forfeited (in dollars per share)		31.45		29.14		23.40	[5]
Outstanding at end of period (in dollars per share)		$ 39.67		$ 30.12		$ 27.47
Total Fair Value of Vested Shares		$ 4,714	[2]	$ 4,179	[3]	$ 5,657	[4]
Percent of awards to common stock									100.00%	150.00%
Number of common shared issued (in shares)									36,498.49	71,808
Percent of awards to common stock, target									119.00%	100.00%
Performance share awards | Minimum
Weighted Average Grant Date Fair Value
Percent of awards to common stock		0.00%
Performance share awards | Maximum
Weighted Average Grant Date Fair Value
Percent of awards to common stock		150.00%
Performance Shares, Subject to Performance Conditions
Shares
Outstanding at beginning of period (in shares)		51,931		69,305
Outstanding at end of period (in shares)		59,341		51,931		69,305
Weighted Average Grant Date Fair Value
Percent of awards to common stock										85.00%
Number of common shared issued (in shares)										55,702.2
Number of shares canceled (in shares)										9,366
Performance-based Restricted Stock
Weighted Average Grant Date Fair Value
Percent of awards to common stock									100.00%	100.00%
Number of common shared issued (in shares)									28,223	23,649
Performance Shares, TSR
Weighted Average Grant Date Fair Value
Percent of awards to common stock									108.44%
Number of common shared issued (in shares)									39,594.6972
Restricted Stock
Shares
Outstanding at beginning of period (in shares)		51,154		73,071		81,492
Granted (in shares)		27,949		28,734		41,909
Vested (in shares)		(33,815)		(38,752)		(48,089)
Cancelled/forfeited (in shares)		(1,120)		(11,899)		(2,241)
Outstanding at end of period (in shares)		44,168		51,154		73,071
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)		$ 32.40		$ 29.09		$ 27.17
Granted (in dollars per share)		45.00		35.79		30.03
Vested (in dollars per share)		31.23		28.92		26.66
Cancelled/forfeited (in dollars per share)		33.54		31.56		29.21
Outstanding at end of period (in dollars per share)		$ 41.24		$ 32.40		$ 29.09
Total Fair Value of Vested Shares		$ 1,438		$ 1,344		$ 1,469
Subsequent Event | Performance share awards
Weighted Average Grant Date Fair Value
Percent of awards to common stock								120.50%
Number of common shared issued (in shares)								39,694.05
Percent of awards to common stock, target								100.00%
Subsequent Event | Performance-based Restricted Stock
Weighted Average Grant Date Fair Value
Percent of awards to common stock								100.00%
Number of common shared issued (in shares)								36,998
Subsequent Event | Performance Shares, TSR
Weighted Average Grant Date Fair Value
Percent of awards to common stock								99.00%
Number of common shared issued (in shares)								38,660.49

[1] The number of common shares issued related to certain performance shares may range from zero to 150 percent of the number of shares shown in the table above based on the Company’s achievement of performance goals.

[2] As certified by the Company’s Leadership and Compensation Committee on November 13, 2018, the number of common shares earned related to TSR performance was 99 percent or 38,660 shares, the number of common shares earned related to NFE performance was 121 percent or 39,694 shares and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 36,998 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

[3] As certified by the Company’s Leadership and Compensation Committee on November 14, 2017, the number of common shares earned related to TSR performance was 108.44 percent or 39,595 shares, the number of common shares earned related to NFE performance was 119 percent or 36,498 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 28,223 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

[4] As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, the number of common shares related to performance shares earned was 85 percent, or 55,702 shares, the number of common shares earned related to NFE performance was 150 percent or 71,808 shares, and the number of common shares earned related to Performance Based Restricted Stock was 100 percent or 23,649 shares. Each award earned excludes accumulated dividends. The number represented on this line is the target number of 100 percent.

[5] As certified by the Company’s Leadership and Compensation Committee on November 15, 2016, 9,366 shares were canceled due to not achieving a certain performance target. The remainder were forfeitures due to individuals departing the Company.

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STOCK-BASED COMPENSATION - DEFERRED RETENTION STOCK/NON-EMPLOYEE DIRECTOR STOCK (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2016
Deferred retention stock
Shares
Outstanding at beginning of period (in shares)	672,578		662,479	632,730
Number of shares granted (in shares)	24,167		63,977	159,831
Delivered (in shares)	(452,694)		(53,878)	(121,764)
Forfeited (in shares)	(1,969)			(8,318)
Outstanding at end of period (in shares)	242,082		672,578	662,479
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)	$ 29.54		$ 29.06	$ 27.03
Granted/Vested (in dollars per share)	45.00		35.64	30.37
Delivered (in dollars per share)	29.42		23.11	20.31
Forfeited (in dollars per share)	35.56			28.14
Outstanding at end of period (in dollars per share)	$ 32.99		$ 29.54	$ 29.06
Total Fair Value of Vested Shares
Delivered	$ 19,581		$ 1,774	$ 3,751
Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation costs not yet recognized	$ 264
Scheduled to Vest Immediately | Director
Shares
Number of shares granted (in shares)	26,524	[1]	27,972	27,481
Weighted Average Grant Date Fair Value
Granted (in dollars per share)	$ 39.85		$ 35.59	$ 32.75

[1] $264,000 of expense remains as of September 30, 2018, to be recognized through December 31, 2018.

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EMPLOYEE BENEFIT PLANS - PENSION AND OTHER POSTEMPLOYMENT BENEFIT PLANS, NARRATIVE (Details)		3 Months Ended	12 Months Ended
		Dec. 31, 2015 USD ($)	Sep. 30, 2018 USD ($) plan	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)
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
Long-term real rate of return on assets (as a percent)			5.00%
Other assets, fair value			$ 1,800,000
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions			6,222,000	$ 6,049,000	$ 3,200,000
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			8,000,000
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer discretionary contributions		$ 30,000,000	0.0	0
Employer contributions	[1]		137,000	$ 74,000
Special Termination Benefits | Voluntary Early Retirement Program
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and other postretirement benefits cost			4,200,000
Other Severance Benefits | Voluntary Early Retirement Program
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and other postretirement benefits cost			2,200,000
Natural Gas Distribution | Voluntary Early Retirement Program
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and other postretirement benefits cost			5,100,000
Home Services and Other | Voluntary Early Retirement Program
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and other postretirement benefits cost			$ 1,300,000

[1] Includes the Company’s PEP.

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EMPLOYEE BENEFIT PLANS - SUMMARY OF CHANGE IN FUNDED STATUS AND LIABILITIES (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2016
Postemployment employee (liability)
Noncurrent		$ (137,007)		$ (128,888)
Pension
Change in Benefit Obligation
Benefit obligation at beginning of year	[1]	297,835		293,654
Service cost		8,139	[1]	8,347	[1]	$ 7,591
Interest cost		10,493	[1]	9,771	[1]	11,342
Plan participants’ contributions	[1],[2]	45		45
Special termination benefit		3,730	[1],[3]	0	[1],[3]	0
Actuarial (gain) loss	[1]	(12,846)		(5,995)
Benefits paid, net of retiree subsidies received	[1]	(8,821)		(7,987)
Benefit obligation at end of year	[1]	298,575		297,835		293,654
Change in plan assets
Fair value of plan assets at beginning of year	[1]	271,743		249,875
Actual return on plan assets	[1]	16,306		29,736
Employer contributions	[1]	137		74
Benefits paid, net of plan participants’ contributions	[1],[2]	(8,776)		(7,942)
Fair value of plan assets at end of year	[1]	279,410		271,743		249,875
Funded status	[1]	(19,165)		(26,092)
Postemployment employee (liability)
Current	[1]	(294)		(158)
Noncurrent	[1]	(18,871)		(25,934)
Total	[1]	(19,165)		(26,092)
OPEB
Change in Benefit Obligation
Benefit obligation at beginning of year		175,090		160,393
Service cost		4,607		4,380		4,521
Interest cost		6,365		5,545		6,256
Plan participants’ contributions	[2]	161		120
Special termination benefit		490	[3]	0	[3]	0
Actuarial (gain) loss		15,145		8,985
Benefits paid, net of retiree subsidies received		(5,073)		(4,333)
Benefit obligation at end of year		196,785		175,090		160,393
Change in plan assets
Fair value of plan assets at beginning of year		71,534		62,035
Actual return on plan assets		5,284		7,953
Employer contributions		6,222		6,049		3,200
Benefits paid, net of plan participants’ contributions	[2]	(5,060)		(4,503)
Fair value of plan assets at end of year		77,980		71,534		$ 62,035
Funded status		(118,805)		(103,556)
Postemployment employee (liability)
Current		(669)		(602)
Noncurrent		(118,136)		(102,954)
Total		$ (118,805)		$ (103,556)

[1] Includes the Company’s PEP.

[2] Prior to July 1, 1998, employees were eligible to elect an additional participant contribution to enhance their benefits and contributions made during the periods were insignificant.

[3] Related to the voluntary early retirement program offered during fiscal 2018, as previously discussed.

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EMPLOYEE BENEFIT PLANS - REGULATORY ASSETS AND AOCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Pension
Amounts amortized to net periodic costs:
Net actuarial (loss)	$ (7,537)	$ (8,827)	$ (7,281)
Prior service (cost) credit	(106)	(111)	(111)
OPEB
Amounts amortized to net periodic costs:
Net actuarial (loss)	(4,660)	(4,370)	(3,274)
Prior service (cost) credit	365	365	365
Regulatory Assets | Pension
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Regulatory Assets, Balance at beginning of period	78,605	94,941
Amounts arising during the period, Net actuarial loss (gain)	(6,090)	(9,429)
Amounts amortized to net periodic costs:
Net actuarial (loss)	(6,177)	(6,799)
Prior service (cost) credit	(105)	(108)
Regulatory Assets, Balance at end of period	66,233	78,605	94,941
Regulatory Assets | OPEB
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Regulatory Assets, Balance at beginning of period	60,460	59,147
Amounts arising during the period, Net actuarial loss (gain)	12,378	5,211
Amounts amortized to net periodic costs:
Net actuarial (loss)	(4,464)	(4,209)
Prior service (cost) credit	311	311
Regulatory Assets, Balance at end of period	68,685	60,460	59,147
Accumulated Other Comprehensive Income (Loss) | Pension
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss), Balance at beginning of period	19,415	28,436
Amounts arising during the period, Net actuarial loss (gain)	(3,422)	(6,990)
Amounts amortized to net periodic costs:
Net actuarial (loss)	(1,359)	(2,028)
Prior service (cost) credit	(1)	(3)
Accumulated Other Comprehensive Income (Loss), Balance at end of period	14,633	19,415	28,436
Accumulated Other Comprehensive Income (Loss) | OPEB
Regulatory Assets and Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss), Balance at beginning of period	4,967	4,486
Amounts arising during the period, Net actuarial loss (gain)	2,834	587
Amounts amortized to net periodic costs:
Net actuarial (loss)	(196)	(160)
Prior service (cost) credit	54	54
Accumulated Other Comprehensive Income (Loss), Balance at end of period	$ 7,659	$ 4,967	$ 4,486

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EMPLOYEE BENEFIT PLANS - AMOUNTS NOT YET RECOGNIZED AS NET PERIODIC COST (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Regulatory Assets | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss	$ 65,664	$ 77,930
Prior service cost (credit)	569	675
Regulatory Assets, Total	66,233	78,605	$ 94,941
Regulatory Assets | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss	69,477	61,563
Prior service cost (credit)	(792)	(1,103)
Regulatory Assets, Total	68,685	60,460	59,147
Accumulated Other Comprehensive Income (Loss) | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss	14,633	19,414
Prior service cost (credit)	0	1
Accumulated Other Comprehensive Income (Loss), Total	14,633	19,415	28,436
Accumulated Other Comprehensive Income (Loss) | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial loss	7,750	5,113
Prior service cost (credit)	(91)	(146)
Accumulated Other Comprehensive Income (Loss), Total	$ 7,659	$ 4,967	$ 4,486

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EMPLOYEE BENEFIT PLANS - AMOUNTS EXPECTED TO BE RECOGNIZED IN NET PERIODIC BENEFIT COST (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2018 USD ($)
Pension
Regulatory Assets
Net actuarial loss	$ 4,662
Prior service cost (credit)	102
Total	4,764
Accumulated Other Comprehensive Income (Loss)
Net actuarial loss	1,103
Prior service cost (credit)	0
Total	1,103
OPEB
Regulatory Assets
Net actuarial loss	5,527
Prior service cost (credit)	(312)
Total	5,215
Accumulated Other Comprehensive Income (Loss)
Net actuarial loss	643
Prior service cost (credit)	(53)
Total	$ 590

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EMPLOYEE BENEFIT PLANS - ACCUMULATED BENEFIT OBLIGATION (Details) - Pension - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 298,575	$ 297,835
Accumulated benefit obligation	263,279	258,514
Fair value of plan assets	$ 279,410	$ 271,743

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EMPLOYEE BENEFIT PLANS - COMPONENTS OF NET PERIODIC COST (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2016
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 8,139	[1]	$ 8,347	[1]	$ 7,591
Interest cost	10,493	[1]	9,771	[1]	11,342
Expected return on plan assets	(19,639)		(19,313)		(20,118)
Recognized actuarial loss	7,537		8,827		7,281
Prior service cost (credit) amortization	106		111		111
Net periodic benefit cost	6,636		7,743		6,207
Special termination benefit	3,730	[1],[2]	0	[1],[2]	0
Net periodic benefit cost recognized as expense	10,366		7,743		6,207
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	4,607		4,380		4,521
Interest cost	6,365		5,545		6,256
Expected return on plan assets	(5,352)		(4,767)		(4,845)
Recognized actuarial loss	4,660		4,370		3,274
Prior service cost (credit) amortization	(365)		(365)		(365)
Net periodic benefit cost	9,915		9,163		8,841
Special termination benefit	490	[2]	0	[2]	0
Net periodic benefit cost recognized as expense	$ 10,405		$ 9,163		$ 8,841

[1] Includes the Company’s PEP.

[2] Related to the voluntary early retirement program offered during fiscal 2018, as previously discussed.

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EMPLOYEE BENEFIT PLANS - WEIGHTED AVERAGE ASSUMPTIONS (Details)		12 Months Ended
		Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2016
Represented
Obligations:
Compensation increase				3.25%
Nonrepresented
Obligations:
Compensation increase				3.50%
Pension
Benefit costs:
Discount rate						4.50%
Expected asset return		7.50%		7.75%		8.75%
Obligations:
Discount rate	[1]			4.03%
Pension | Represented
Benefit costs:
Discount rate		4.04%		3.96%
Compensation increase		3.25%	[1]	3.25%	[1]	3.25%
Obligations:
Discount rate		4.36%				3.96%
Compensation increase	[1]	3.25%		3.25%		3.25%
Pension | Nonrepresented
Benefit costs:
Discount rate		4.03%		3.94%
Compensation increase		3.50%	[1]	3.50%	[1]	3.50%
Obligations:
Discount rate		4.35%				3.94%
Compensation increase	[1]	3.50%		3.50%		3.50%
OPEB
Benefit costs:
Expected asset return		7.50%		7.75%		8.75%
Compensation increase						3.50%
Obligations:
Compensation increase						3.50%
OPEB | Represented
Benefit costs:
Discount rate		4.12%	[1]	4.08%	[1]	4.60%
Compensation increase		3.25%	[1]	3.25%
Obligations:
Discount rate	[1]	4.38%		4.12%		4.08%
Compensation increase	[1]	3.25%
OPEB | Nonrepresented
Benefit costs:
Discount rate		4.08%	[1]	4.01%	[1]	4.55%
Compensation increase		3.50%	[1]	3.50%
Obligations:
Discount rate	[1]	4.37%		4.08%		4.01%
Compensation increase	[1]	3.50%

[1] Percentages for represented and nonrepresented plans, respectively.

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EMPLOYEE BENEFIT PLANS - ASSUMED HCCTR (Details) - OPEB - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
HCCTR	7.90%	8.30%	8.50%
Ultimate HCCTR	4.50%	4.50%	4.50%
Year ultimate HCCTR reached	2024	2025	2025
Effect of a 1 percentage point increase in the HCCTR on:
Year-end benefit obligation	$ 36,260	$ 32,019	$ 28,803
Total service and interest cost	2,482	2,468	2,331
Effect of a 1 percentage point decrease in the HCCTR on:
Year-end benefit obligation	(28,743)	(25,466)	(22,862)
Total service and interest costs	$ (1,937)	$ (1,909)	$ (1,801)

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EMPLOYEE BENEFIT PLANS - MIX AND TARGETED ALLOCATION (Details)	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	100.00%
Assets	100.00%	100.00%
U.S. equity securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	34.00%
Assets	41.00%	39.00%
International equity securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	17.00%
Assets	19.00%	21.00%
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	41.00%
Assets	37.00%	40.00%
Other assets
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	8.00%
Assets	3.00%	0.00%

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EMPLOYEE BENEFIT PLANS - EXPECTED BENEFIT PAYMENTS (Details) $ in Thousands	Sep. 30, 2018 USD ($)
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2019	$ 10,320
2020	11,769
2021	12,399
2022	13,239
2023	14,217
2024 - 2028	85,426
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2019	5,450
2020	6,512
2021	7,096
2022	7,810
2023	8,413
2024 - 2028	$ 50,869

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EMPLOYEE BENEFIT PLANS - ESTIMATED SUBSIDY PAYMENTS (Details) $ in Thousands	Sep. 30, 2018 USD ($)
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt [Abstract]
2019	$ 280
2020	316
2021	347
2022	375
2023	417
2024 - 2028	$ 2,787

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EMPLOYEE BENEFIT PLANS - FAIR VALUE (Details) - USD ($) $ in Thousands		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Pension
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets	[1]	$ 279,410	$ 271,743	$ 249,875
OPEB
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		77,980	71,534	$ 62,035
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		277,993	271,743
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		8,207	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Large Cap Index
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		97,016	88,321
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		17,741	16,329
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		53,516	56,446
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		11,754	13,516
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Core Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Opportunistic Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | Ultra Short Duration
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension | High Yield Bond Fund
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		25,720	26,540
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		64,039	70,591
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		77,599	71,534
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		2,273	11
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		27,340	23,986
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		5,014	4,409
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		14,874	15,000
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Emerging Markets
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		3,264	3,551
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		7,970	8,082
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Opportunistic Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		4,798	4,744
Quoted Prices in Active Markets for Identical Assets (Level 1) | OPEB | Ultra Short Duration
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, fair value of plan assets		4,830	4,673
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		7,236	7,078
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

[1] Includes the Company’s PEP.

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EMPLOYEE BENEFIT PLANS - DEFINED CONTRIBUTION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined contribution, company match of employee contribution	65.00%
Defined contribution plan, maximum employer contribution by percentage of employee salary	6.00%
Defined contribution plan, cost recognized	$ 3,900	$ 2,900	$ 2,800
Deferred compensation arrangement with individual, employer contribution	$ 959	$ 781	$ 571
NJRHS | Minimum
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan, employer contribution for employees not qualifying for the defined benefit plan	3.00%
NJRHS | Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan, employer contribution for employees not qualifying for the defined benefit plan	4.00%

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ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Estimated Accretion
2018	$ 1,557
2019	1,627
2020	1,702
2021	1,778
2022	1,863
Total	8,527
Natural Gas Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at period beginning	24,825	$ 23,521
Accretion	1,366	1,304
Additions	1,880	729
Revisions in estimated cash flows	(2,133)	(245)
Retirements	(298)	(484)
Reclassification to held for sale or sold	0	0
Balance at period end	25,640	24,825
Clean Energy Ventures
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at period beginning	6,595	4,858
Accretion	198	245
Additions	517	1,492
Revisions in estimated cash flows	0	0
Retirements	0	0
Reclassification to held for sale or sold	(4,262)	0
Balance at period end	$ 3,048	$ 6,595

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INCOME TAXES - COMPONENTS OF INCOME TAX PROVISION (BENEFIT) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Current:
Federal	$ (2,848)	$ (16,023)	$ (23,597)
State	4,563	2,470	(2,209)
Deferred:
Federal	(40,785)	54,965	70,386
State	6,731	11,457	11,441
Investment/production tax credits	(21,446)	(34,526)	(32,491)
Income tax (benefit) provision	$ (53,785)	$ 18,343	$ 23,530

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INCOME TAXES - DEFERRED TAX ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands		Sep. 30, 2018	Sep. 30, 2017
Deferred tax assets
Investment tax credits	[1]	$ 123,258	$ 111,642
Deferred service contract revenue		0	3,877
Incentive compensation		4,646	6,260
Fair value of derivatives		8,411	11,519
Federal net operating losses	[2]	24,500	28,487
State net operating losses		34,754	23,597
Amortization of intangibles		3,737	2,747
Conservation incentive plan		1,955	0
Other		8,213	11,098
Total deferred tax assets		209,474	199,227
Deferred tax liabilities
Property related items		(392,886)	(620,850)
Remediation costs		(9,229)	(11,625)
Equity investments		(31,956)	(38,370)
Postemployment benefits		(353)	(6,855)
Conservation incentive plan		0	(7,195)
Underrecovered gas costs		(1,156)	(4,035)
Other		(7,826)	(16,643)
Total deferred tax liabilities		(443,406)	(705,573)
Total net deferred tax liabilities		(233,932)	(506,346)
Natural Gas Distribution
Deferred tax liabilities
Tax credit carryforward		2,200	2,300
Clean Energy Ventures
Deferred tax liabilities
Tax credit carryforward		$ 121,100	$ 109,300

[1] Includes $2.2 million and $2.3 million for NJNG for fiscal 2018 and 2017, respectively, which is being amortized over the life of the related assets, and$121.1 million and $109.3 million for Clean Energy Ventures for fiscal 2018 and 2017, respectively, which is ITC carryforward.

[2] See discussion of federal net operating loss utilization in the Other Tax Items section of this note.

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INCOME TAXES - INCOME TAX RECONCILIATION (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Federal statutory rate		24.50%	35.00%
Federal statutory rate without Tax Act impact		12.38%
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory income tax expense		$ 44,014	$ 52,643	$ 54,321
Change resulting from:
Tax Act - excess deferred income taxes	[1]	(59,627)	0	0
Tax Act - utility excess deferred income taxes refunded to customers (1)	[1]	(14,323)	0	0
Tax Act - utility excess deferred income taxes amortized (1)	[1]	(1,786)	0	0
State income taxes		7,092	8,222	6,044
Cost of removal of assets placed in service prior to1981		(5,829)	(6,886)	(5,738)
Investment/production tax credits		(21,446)	(34,526)	(32,491)
Basis adjustment of solar assets due to ITC		1,080	4,256	4,453
AFUDC equity		(2,117)	(2,624)	(1,531)
Other		(843)	(2,742)	(1,528)
Income tax (benefit) provision		$ (53,785)	$ 18,343	$ 23,530
Effective income tax rate	[2],[3]	(29.94%)	12.20%	15.20%

[1] For a more detailed description, see The Tax Act section of this note.

[2] The U.S. federal statutory rate was 24.5 percent for fiscal 2018 and 35 percent for fiscal 2017 and 2016.

[3] The effective tax rate without the impact of the Tax Act would have been 12.4 percent for fiscal 2018.

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INCOME TAXES (Details) - USD ($) $ in Thousands					12 Months Ended
		Dec. 31, 2019	May 22, 2018	Dec. 31, 2016	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2024	Dec. 31, 2021	Dec. 31, 2020
Income Tax Contingency [Line Items]
Federal statutory rate						24.50%	35.00%
Change in tax rate, deferred tax liability, provisional income tax (expense) benefit						$ 228,400
Change in tax rate, deferred income taxes						164,300
Change in tax rate, provisional income tax expense (benefit)						64,100
Initial revaluation of excess deferred income taxes			$ 20,100
Overcollection of taxes			9,000
Deferred income tax expense (benefit), remeasurement						14,300
Amortization of excess deferred income taxes						1,800
Revaluation of deferred income taxes not included in base rates						880
Regulatory liability, excess deferred income taxes						205,400
Tax estimate adjustment						(2,100)
Deferred Tax Assets, Operating Loss Carryforwards, Domestic, Refundable and Receivables						$ 23,000	$ 15,400
Net operating losses, life						20 years
Federal net operating losses	[1]					$ 24,500	28,487
Valuation allowance						4,000	1,000
Investment tax credit, project phase out				3 years
Domestic Tax Authority
Income Tax Contingency [Line Items]
Net operating losses						136,800	125,300
State and Local Jurisdiction
Income Tax Contingency [Line Items]
Net operating losses						578,800	471,700
Forecast
Income Tax Contingency [Line Items]
Federal statutory rate					21.00%
Investment tax credit, solar property, percentage		30.00%						10.00%	22.00%	26.00%
Investment tax credit, project phase out		5 years
March 2018 BGSS/CIP Filing
Income Tax Contingency [Line Items]
Approved customer refunds			$ 31,000
Clean Energy Ventures
Income Tax Contingency [Line Items]
Tax credit carryforward						121,100	109,300
Natural Gas Distribution
Income Tax Contingency [Line Items]
Income tax expense (benefit) provision						17,000
Tax credit carryforward						$ 2,200	$ 2,300
Minimum | State and Local Jurisdiction
Income Tax Contingency [Line Items]
Net operating losses, life						7 years
Maximum
Income Tax Contingency [Line Items]
Net operating losses, life						20 years

[1] See discussion of federal net operating loss utilization in the Other Tax Items section of this note.

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INCOME TAXES - IMPACT OF TAX ACT (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2018 USD ($)
Income Tax Contingency [Line Items]
Income tax (benefit) provision	$ (59,627)
Clean Energy Ventures
Income Tax Contingency [Line Items]
Income tax (benefit) provision	(61,423)
Energy Services
Income Tax Contingency [Line Items]
Income tax (benefit) provision	6,062
Midstream
Income Tax Contingency [Line Items]
Income tax (benefit) provision	(13,946)
Home Services and Other
Income Tax Contingency [Line Items]
Income tax (benefit) provision	$ 9,680

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COMMITMENTS AND CONTINGENT LIABILITIES - SCHEDULE OF FUTURE COMMITTED EXPENSES (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2018 USD ($)
Long-term Purchase Commitment [Line Items]
Current charges recoverable through BGSS	$ 112,000
Purchase Obligation, Fiscal Year Maturity [Abstract]
2019	689,609
2020	256,336
2021	189,877
2022	171,479
2023	152,560
Thereafter	$ 634,236
Minimum
Long-term Purchase Commitment [Line Items]
Storage and pipeline capacity, fixed period	1 year
Maximum
Long-term Purchase Commitment [Line Items]
Storage and pipeline capacity, fixed period	10 years
Energy Services
Purchase Obligation, Fiscal Year Maturity [Abstract]
2019	$ 511,879
2020	98,105
2021	52,652
2022	33,057
2023	23,200
Thereafter	6,142
Energy Services | Natural gas purchases
Purchase Obligation, Fiscal Year Maturity [Abstract]
2019	428,015
2020	28,389
2021	10,965
2022	0
2023	0
Thereafter	0
Energy Services | Storage demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2019	31,716
2020	19,926
2021	13,478
2022	8,904
2023	4,212
Thereafter	991
Energy Services | Pipeline demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2019	52,148
2020	49,790
2021	28,209
2022	24,153
2023	18,988
Thereafter	5,151
Natural Gas Distribution
Purchase Obligation, Fiscal Year Maturity [Abstract]
2019	177,730
2020	158,231
2021	137,225
2022	138,422
2023	129,360
Thereafter	628,094
Natural Gas Distribution | Natural gas purchases
Purchase Obligation, Fiscal Year Maturity [Abstract]
2019	65,737
2020	37,727
2021	33,738
2022	33,546
2023	34,221
Thereafter	35,762
Natural Gas Distribution | Storage demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2019	31,384
2020	24,263
2021	14,251
2022	12,930
2023	7,899
Thereafter	6,066
Natural Gas Distribution | Pipeline demand fees
Purchase Obligation, Fiscal Year Maturity [Abstract]
2019	80,609
2020	96,241
2021	89,236
2022	91,946
2023	87,240
Thereafter	$ 586,266

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COMMITMENTS AND CONTINGENT LIABILITIES - CAPITAL EXPENDITURES (Details) $ in Millions	Sep. 30, 2018 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Operating leases, future minimum payments due, next five years (not more than)	$ 3.7
Operating leases, future minimum payments, due thereafter	$ 50.0

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COMMITMENTS AND CONTINGENT LIABILITIES - GUARANTEES (Details) $ in Millions	Sep. 30, 2018 USD ($)
Guarantee Obligations
Guarantor Obligations [Line Items]
Loss contingency, estimate of possible loss	$ 418.1

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COMMITMENTS AND CONTINGENT LIABILITIES - LEGAL PROCEEDINGS (Details) $ in Thousands		1 Months Ended	12 Months Ended
	Sep. 17, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) site
Loss Contingencies [Line Items]
Number of manufactured gas plant sites (in sites) | site			5
Recovery period			7 years
Regulatory assets		$ 375,919	$ 368,592
Minimum
Loss Contingencies [Line Items]
Litigation settlement, gross			117,700
Maximum
Loss Contingencies [Line Items]
Litigation settlement, gross			204,100
Environmental remediation costs, Expended, net of recoveries
Loss Contingencies [Line Items]
Regulatory assets		28,547	33,017
Environmental remediation costs, Liability for future expenditures
Loss Contingencies [Line Items]
Regulatory assets		149,000	130,800
RAC
Loss Contingencies [Line Items]
Approved rate, amount			9,400
Public utilities, requested rate			$ 7,000
Approved rate increase (decrease), amount	$ 1,400	$ (2,400)

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BUSINESS SEGMENT AND OTHER OPERATIONS DATA - RECONCILIATION OF SEGMENT INCOME TO CONSOLIDATED (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Utility										$ 731,865	$ 695,637	$ 594,346
Nonutility										2,183,244	1,572,980	1,286,559
Total operating revenues		$ 647,326	$ 543,435	$ 1,019,043	$ 705,305	$ 536,520	$ 457,523	$ 733,546	$ 541,028	2,915,109	2,268,617	1,880,905
Depreciation and amortization										85,701	81,841	72,748
Interest income										614	2,034	128
Interest expense, net of capitalized interest										46,286	44,886	31,044
Income tax (benefit) provision										(53,785)	18,343	23,530
Equity in earnings of affiliates										13,008	13,813	9,515
Net financial earnings (loss)										240,486	149,392	138,085
Capital expenditures										384,588	328,083	356,092
Investments in equity investees										16,151	27,070	11,176
Operating Segments
Segment Reporting Information [Line Items]
Total operating revenues										2,916,044	2,222,712	1,845,139
Depreciation and amortization										85,167	81,250	71,893
Interest income	[1]									4,228	2,756	1,737
Interest expense, net of capitalized interest										49,231	45,788	31,616
Income tax (benefit) provision										(65,394)	14,129	21,519
Net financial earnings (loss)										244,642	143,214	135,837
Capital expenditures										383,375	325,649	354,196
Operating Segments | Natural Gas Distribution
Segment Reporting Information [Line Items]
Utility										731,865	695,637	594,346
Depreciation and amortization										53,208	49,347	47,828
Interest income	[1]									614	555	115
Interest expense, net of capitalized interest										25,299	25,818	19,930
Income tax (benefit) provision										(1,910)	43,485	34,951
Net financial earnings (loss)										84,048	86,930	76,104
Capital expenditures										254,523	176,249	205,133
Operating Segments | Clean Energy Ventures
Segment Reporting Information [Line Items]
Nonutility										71,375	64,394	53,540
Depreciation and amortization										31,877	31,834	23,971
Interest expense, net of capitalized interest										18,320	16,263	10,304
Income tax (benefit) provision										(79,932)	(31,161)	(26,592)
Net financial earnings (loss)										75,849	24,873	28,393
Capital expenditures										123,421	149,400	149,063
Operating Segments | Energy Services
Segment Reporting Information [Line Items]
Nonutility	[2]									2,064,477	1,462,365	1,187,754
Depreciation and amortization	[3]									76	63	88
Interest income	[1]									240	6	98
Interest expense, net of capitalized interest										3,945	2,747	1,095
Income tax (benefit) provision										24,996	(4,015)	7,030
Net financial earnings (loss)										60,378	18,554	21,934
Operating Segments | Midstream
Segment Reporting Information [Line Items]
Depreciation and amortization										6	6	6
Interest income	[1]									3,374	2,195	1,524
Interest expense, net of capitalized interest										1,667	960	287
Income tax (benefit) provision										(8,548)	5,820	6,130
Equity in earnings of affiliates										16,165	17,797	13,936
Net financial earnings (loss)										24,367	12,857	9,406
Capital expenditures										5,431	0	0
Investments in equity investees										16,151	27,070	11,176
Intercompany
Segment Reporting Information [Line Items]
Nonutility										2,665	3,370	3,232
Intercompany | Energy Services
Segment Reporting Information [Line Items]
Nonutility										48,327	316	9,499
Home Services and Other
Segment Reporting Information [Line Items]
Nonutility										47,392	46,221	45,265
Depreciation and amortization										780	798	981
Interest income										1,476	590	397
Interest expense, net of capitalized interest										7	410	252
Income tax (benefit) provision										11,944	3,857	1,387
Net financial earnings (loss)										(3,829)	6,811	2,882
Capital expenditures										1,213	2,434	1,896
Eliminations
Segment Reporting Information [Line Items]
Nonutility										(50,992)	(3,686)	(12,731)
Depreciation and amortization										(246)	(207)	(126)
Interest income										(5,090)	(1,312)	(2,006)
Interest expense, net of capitalized interest										(2,952)	(1,312)	(824)
Income tax (benefit) provision										(335)	357	624
Equity in earnings of affiliates										(3,157)	(3,984)	(4,421)
Net financial earnings (loss)										$ (327)	$ (633)	$ (634)

[1] Included in other income, net on the Consolidated Statements of Operations.

[2] Includes sales to Canada, which are immaterial.

[3] The amortization of acquired wholesale energy contracts is excluded above and is included in gas purchases - nonutility on the Unaudited Condensed Consolidated Statements of Operations.

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BUSINESS SEGMENT AND OTHER OPERATIONS DATA - NET FINANCIAL EARNINGS LOSS RECONCILIATION (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting [Abstract]
Consolidated net financial earnings									$ 240,486	$ 149,392	$ 138,085
Less:
Unrealized loss (gain) on derivative instruments and related transactions									26,770	(11,241)	46,883
Unrealized loss (gain) on derivative instruments and related transactions, tax effect									(4,512)	4,062	(17,018)
Effects of economic hedging related to natural gas inventory									(22,570)	38,470	(36,816)
Effects of economic hedging related to natural gas inventory, tax effect									7,362	(13,964)	13,364
NET INCOME	$ (16,255)	$ (14,274)	$ 140,266	$ 123,699	$ (36,523)	$ 18,957	$ 114,702	$ 34,929	$ 233,436	$ 132,065	$ 131,672

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BUSINESS SEGMENT AND OTHER OPERATIONS DATA - RECONCILIATION OF SEGMENT ASSETS TO CONSOLIDATED (Details) - USD ($) $ in Thousands		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		$ 4,143,664	$ 3,928,507	$ 3,718,570
Asset held for sale		206,905	0
Operating Segments
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		4,166,993	3,922,001	3,696,982
Operating Segments | Natural Gas Distribution
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		2,663,054	2,519,578	2,517,401
Operating Segments | Clean Energy Ventures
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	[1]	865,018	771,340	665,696
Asset held for sale		206,900
Operating Segments | Energy Services
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		396,852	398,277	327,626
Operating Segments | Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		242,069	232,806	186,259
Home Services and Other
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		114,732	114,801	109,487
Eliminations
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	[2]	$ (138,061)	$ (108,295)	$ (87,899)

[1] Includes assets held for sale of $206.9 million for September 30, 2018

[2] Consists of transactions between subsidiaries that are eliminated and reclassified in consolidation.

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RELATED PARTY TRANSACTIONS (Details) DTH in Thousands, $ in Thousands		12 Months Ended
	Apr. 01, 2010 USD ($) Bcf	Sep. 30, 2018 USD ($) DTH contract	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)
Related Party Transaction [Line Items]
Demand fees recognized pertaining to related party agreement		$ 8,505	$ 8,340	$ 8,351
Due to related parties		$ 1,150	1,152
Number of asset management agreements | contract		4
NJNG to NJRES Affiliate
Related Party Transaction [Line Items]
Asset management agreement, period	10 years
NJNG to Steckman RIdge Affiliate - National Gas Distribution
Related Party Transaction [Line Items]
Natural gas sold at cost under asset management agreement (in Bcf) | Bcf	3
Approximate annual demand fees under agreement	$ 9,300
Demand fees recognized pertaining to related party agreement		$ 5,730	5,590	5,562
Due to related parties		775	775
NJRES to Steckman Ridge Affiliate - Energy Services
Related Party Transaction [Line Items]
Demand fees recognized pertaining to related party agreement		2,775	2,750	$ 2,789
Due to related parties		$ 375	$ 377
NJNG to PennEast Affiliate
Related Party Transaction [Line Items]
Transportation precedent agreement, period		15 years
Transportation capacity under precedent agreement from NJNG with PennEast (in Dths per day) | DTH		180

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ACQUISITION (Details) $ in Thousands			12 Months Ended
	Nov. 07, 2017 USD ($)	Oct. 27, 2017 USD ($) mi	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)
Business Acquisition [Line Items]
Initial payment			$ 10,000	$ 0	$ 0
Adelphia | Talen's Membership Interests In IEC
Business Acquisition [Line Items]
Base purchase price		$ 166,000
Additional contingent consideration (up to $23 million)		$ 23,000
Initial payment	$ 10,000
Pipeline length owned | mi		84
Transportation precedent agreement, period		10 years

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DISPOSITIONS (Details) $ in Thousands			12 Months Ended
	Jun. 01, 2018 USD ($) MW	Feb. 28, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of businesses, net of closing costs			$ 27,916	$ 0	$ 0
Issued And Outstanding Shares Of NRJ Retail Services
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of businesses, net of closing costs		$ 9,500
Proceeds from sale of business		(3,700)
Clean Energy Ventures
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of business	$ (951)
Wind farm total capacity (in MW) | MW	9.7
Disposal group consideration	$ 18,500
Natural Gas | Issued And Outstanding Shares Of NRJ Retail Services
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Derivative gain		$ 14,600

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SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2016
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 647,326		$ 543,435		$ 1,019,043		$ 705,305		$ 536,520		$ 457,523		$ 733,546		$ 541,028		$ 2,915,109		$ 2,268,617		$ 1,880,905
Operating income (loss)	(19,295)		(37,666)		177,792		75,245		(32,051)		17,967		139,653		41,475		196,076		167,044		167,535
Net income (loss)	$ (16,255)		$ (14,274)		$ 140,266		$ 123,699		$ (36,523)		$ 18,957		$ 114,702		$ 34,929		$ 233,436		$ 132,065		$ 131,672
Earnings (loss) per share
Basic (in dollars per share)	$ (0.18)	[1]	$ (0.16)	[1]	$ 1.60	[1]	$ 1.42	[1]	$ (0.42)	[1]	$ 0.22	[1]	$ 1.33	[1]	$ 0.41	[1]	$ 2.66		$ 1.53		$ 1.53
Diluted (in dollars per share)	$ (0.18)	[1]	$ (0.16)	[1]	$ 1.59	[1]	$ 1.42	[1]	$ (0.42)	[1]	$ 0.22	[1]	$ 1.32	[1]	$ 0.40	[1]	$ 2.64	[2]	$ 1.52	[2]	$ 1.52	[2]

[1] The sum of quarterly amounts may not equal the annual amounts due to rounding.

[2] There were no anti-dilutive shares excluded from the calculation of diluted earnings per share for fiscal 2018, 2017 and 2016.

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VALUATION AND QUALIFYING ACCOUNTS (Details) - Allowance for doubtful accounts - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
BEGINNING BALANCE	$ 5,181	$ 4,865	$ 5,189
ADDITIONS CHARGED TO EXPENSE	2,579	2,023	1,616
OTHER	(2,056)	(1,707)	(1,940)
ENDING BALANCE	$ 5,704	$ 5,181	$ 4,865