SOUTH JERSEY GAS 10-Q 4 Nov 16 2016 Q3 Quarterly report Financial data

DOCUMENT AND ENTITY INFORMATION

DOCUMENT AND ENTITY INFORMATION - shares	9 Months Ended
	Sep. 30, 2016	Nov. 01, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTH JERSEY GAS Co
Entity Central Index Key	1,035,216
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		2,339,139

CONDENSED STATEMENTS OF INCOME

CONDENSED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Statement [Abstract]
Operating Revenues	$ 62,025	$ 58,634	$ 318,553	$ 402,104
Operating Expenses:
Cost of Sales (Excluding depreciation)	26,395	22,934	115,695	194,455
Operations	21,360	22,786	69,954	80,083
Maintenance	4,150	4,188	12,793	12,114
Depreciation	11,735	10,421	34,435	29,723
Energy and Other Taxes	838	806	2,425	3,080
Total Operating Expenses	64,478	61,135	235,302	319,455
Operating Loss	(2,453)	(2,501)	83,251	82,649
Other Income and Expense	1,189	1,010	3,104	3,440
Interest Charges	(4,058)	(4,809)	(13,397)	(15,112)
Income (Loss) Before Income Taxes	(5,322)	(6,300)	72,958	70,977
Income Taxes	2,007	2,871	(26,812)	(26,593)
Net Income (Loss)	$ (3,315)	$ (3,429)	$ 46,146	$ 44,384

CONDENSED STATEMENTS OF COMPREH

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net Income (Loss)		$ (3,315)	$ (3,429)	$ 46,146	$ 44,384
Other Comprehensive Income (Loss) - Net of Tax:
Unrealized Gain (Loss) on Available-for-Sale Securities	[1]	38	(98)	45	(81)
Unrealized Gain on Derivatives - Other	[1]	7	6	21	15
Other Comprehensive Income (Loss) - Net of Tax	[1]	45	(92)	66	(66)
Comprehensive Income (Loss)		$ (3,270)	$ (3,521)	$ 46,212	$ 44,318
[1]	Determined using a combined average statutory tax rate of 40%.

CONDENSED STATEMENTS OF COMPRE4

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Combined statutory tax rate	40.00%	40.00%	40.00%	40.00%

CONDENSED STATEMENTS OF CASH FL

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Statement of Cash Flows [Abstract]
Net Cash Provided by Operating Activities	$ 108,690	$ 124,750
Cash Flows from Investing Activities:
Capital Expenditures	(161,690)	(147,276)
Note Receivable	9,919	(9,919)
Net Proceeds from Restricted Investments in Margin Accounts	6,737	1,603
Net (Purchase of) Return of Restricted Investments in Escrow	(8,300)	101
Investment in Long-Term Receivables	(8,085)	(13,784)
Proceeds from Long-Term Receivables	7,528	6,556
Net Cash Used in Investing Activities	(153,891)	(162,719)
Cash Flows from Financing Activities:
Net Repayments of Short-Term Credit Facilities	(53,400)	(12,100)
Proceeds from Issuance of Long-Term Debt	61,000	80,000
Principal Repayments of Long-Term Debt	(27,000)	(10,100)
Payments for Issuance of Long-Term Debt	(7)	(8)
Dividends on Common Stock	0	(19,782)
Additional Investment by Shareholder	65,000	0
Net Cash Provided by Financing Activities	45,593	38,010
Net Increase in Cash and Cash Equivalents	392	41
Cash and Cash Equivalents at Beginning of Period	775	1,778
Cash and Cash Equivalents at End of Period	$ 1,167	$ 1,819

CONDENSED BALANCE SHEETS (UNAUD

CONDENSED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment:
Utility Plant, at original cost	$ 2,358,302	$ 2,211,239
Accumulated Depreciation	(467,359)	(440,473)
Property, Plant and Equipment - Net	1,890,943	1,770,766
Investments:
Available-for-Sale Securities	9,260	8,788
Restricted Investments	8,332	6,769
Total Investments	17,592	15,557
Current Assets:
Cash and Cash Equivalents	1,167	775
Note Receivable	0	9,916
Accounts Receivable	59,020	64,445
Accounts Receivable - Related Parties	1,680	1,972
Unbilled Revenues	13,432	25,613
Provision for Uncollectibles	(11,055)	(9,778)
Natural Gas in Storage, average cost	13,930	14,294
Materials and Supplies, average cost	931	937
Prepaid Taxes	24,385	21,483
Derivatives - Energy Related Assets	2,281	1,077
Other Prepayments and Current Assets	15,782	13,405
Total Current Assets	121,553	144,139
Regulatory and Other Noncurrent Assets:
Regulatory Assets	397,071	323,434
Long-Term Receivables	25,370	24,950
Derivatives - Energy Related Assets	281	64
Other	3,502	2,666
Total Regulatory and Other Noncurrent Assets	426,224	351,114
Total Assets	2,456,312	2,281,576
Common Equity:
Common Stock, Par Value $2.50 per share: Authorized - 4,000,000 shares, Outstanding - 2,339,139 shares	5,848	5,848
Other Paid-In Capital and Premium on Common Stock	315,827	250,827
Accumulated Other Comprehensive Loss	(12,796)	(12,862)
Retained Earnings	510,260	464,114
Total Common Equity	819,139	707,927
Long-Term Debt (see Note 1)	423,983	577,454
Total Capitalization	1,243,122	1,285,381
Current Liabilities:
Notes Payable	81,000	134,400
Current Portion of Long-Term Debt	215,909	27,909
Accounts Payable - Commodity	10,933	8,936
Accounts Payable - Other	26,121	40,579
Accounts Payable - Related Parties	5,668	7,552
Derivatives - Energy Related Liabilities	3,276	5,489
Derivatives - Other Current	535	0
Customer Deposits and Credit Balances	41,497	19,531
Environmental Remediation Costs	58,174	48,323
Taxes Accrued	1,678	1,930
Pension Benefits	2,227	2,227
Interest Accrued	4,641	5,989
Other Current Liabilities	3,564	5,686
Total Current Liabilities	455,223	308,551
Regulatory and Other Noncurrent Liabilities:
Regulatory Liabilities	51,050	42,841
Deferred Income Taxes - Net	460,464	432,674
Environmental Remediation Costs	102,413	74,871
Asset Retirement Obligations	58,377	57,219
Pension and Other Postretirement Benefits	70,564	65,491
Derivatives - Energy Related Liabilities	73	351
Derivatives - Other Noncurrent	9,811	7,631
Other	5,215	6,566
Total Regulatory and Other Noncurrent Liabilities	757,967	687,644
Commitments and Contingencies (Note 9)
Total Capitalization and Liabilities	$ 2,456,312	$ 2,281,576

CONDENSED BALANCE SHEETS (UNAU7

CONDENSED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 2.50	$ 2.50
Common stock, authorized (in shares)	4,000,000	4,000,000
Common stock, outstanding (in shares)	2,339,139	2,339,139

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: THE ENTITY - South Jersey Industries, Inc. (SJI) owns all of the outstanding common stock of South Jersey Gas Company (SJG or the Company), a regulated natural gas utility. SJG distributes natural gas in the seven southern most counties of New Jersey. In our opinion, the condensed financial statements reflect all normal and recurring adjustments needed to fairly present our financial position and operating results at the dates and for the periods presented. SJG’s business is subject to seasonal fluctuations, and accordingly, this interim financial information should not be the basis for estimating the full year’s operating results. As permitted by the rules and regulations of the Securities and Exchange Commission, the accompanying condensed financial statements contain certain condensed financial information and exclude certain note disclosures normally included in annual audited financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). These condensed financial statements should be read in conjunction with SJG’s Annual Report on Form 10-K for the year ended December 31, 2015 for a more complete discussion of our accounting policies and certain other information. Certain reclassifications have been made to the prior period's condensed balance sheets, as well as the prior period's long-term debt carrying value in Note 6, to conform to the current period presentation. The unamortized debt issuance costs previously included in "Regulatory and Other Noncurrent Assets" on the condensed balance sheets were reclassified to Long-Term Debt to conform to ASU 2015-03, which is described below under "New Accounting Pronouncements." This reclassification caused the prior period long-term debt carrying value in Note 6 to be adjusted. REVENUE - BASED TAXES - SJG collects certain revenue-based energy taxes from its customers. Such taxes include the New Jersey State Sales Tax and Public Utilities Assessment (PUA). State sales tax is recorded as a liability when billed to customers and is not included in revenue or operating expenses. The PUA is included in both revenues and energy and other taxes, and totaled $0.2 million for both the three months ended September 30, 2016 and 2015 , and $0.7 million and $1.0 million for the nine months ended September 30, 2016 and 2015 , respectively. NEW ACCOUNTING PRONOUNCEMENTS — Other than as described below, no new accounting pronouncement issued or effective during 2016 or 2015 had, or are expected to have, a material impact on the condensed financial statements. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes the revenue recognition requirements in FASB ASC 605, Revenue Recognition , and in most industry-specific topics. The new guidance identifies how and when entities should recognize revenue. The new rules establish a core principle requiring the recognition of revenue to depict the transfer of promised goods or services to customers in an amount reflecting the consideration to which the entity expects to be entitled in exchange for such goods or services. The new guidance is effective for fiscal years, and interim periods within those annual periods, beginning after December 15, 2017. Management has formed an implementation team that is currently inventorying the contracts with customers and evaluating the impact that adoption of this guidance will have on the Company's financial statement results, as well as the transition method the Company will elect to adopt the guidance. In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40); Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern . The new guidance requires management of a company to evaluate whether there is substantial doubt about the company's ability to continue as a going concern. This ASU is effective for the annual reporting period ending after December 15, 2016, and for interim and annual reporting periods thereafter, with early adoption permitted. Management does not expect this standard to have an impact on the Company's financial statements upon adoption. In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs . This ASU requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. The standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. Adoption of this guidance did not have an impact on the Company's results of operations; however, balance sheet presentations were modified to conform to this guidance. In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory . This ASU states that inventory for which cost is determined using a method other than last-in, first-out (LIFO) or the retail method should be subsequently measured at the lower of cost or net realizable value (NRV), rather than at the lower of cost or market. The standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities , which enhances the reporting model for financial instruments and includes amendments to address aspects of recognition, measurement, presentation and disclosure. The standard is effective for annual periods, including interim periods within those annual periods. beginning after December 15, 2017. Early adoption is permitted for only certain portions of the new guidance. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In March 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which establishes a new lease accounting model for lessees. The new standard requires substantially all leases be recognized by lessees on their balance sheet as a right-of-use asset and corresponding lease liability, including leases currently accounted for as operating leases. The new standard also will result in enhanced quantitative and qualitative disclosures, including significant judgments made by management, to provide greater insight into the extent of revenue and expense recognized and expected to be recognized from existing leases. The accounting for leases by the lessor remains relatively the same. The standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2018, with early adoption permitted. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships . The amendments in this guidance clarify that a change in the counterparty to a derivative instrument that has been designated as a hedging instrument under Topic 815 does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016, with early adoption permitted. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) . This standard amends ASU 2014-09 (discussed above), to improve the implementation guidance on principal versus agent considerations and whether an entity reports revenue on a gross or net basis. This standard will have the same effective date and transition requirements as ASU 2014-09. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In March 2016, the FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , which simplifies various aspects of accounting for share-based payment arrangements. The standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016, with early adoption permitted. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing . This standard amends ASU 2014-09 (discussed above) to clarify identifying performance obligations and the licensing implementation guidance. This standard will have the same effective date and transition requirements as ASU 2014-09. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients . This standard amends ASU 2014-09 (discussed above) to provide additional guidance on (a) the objective of the collectibility criterion, (b) the presentation of sales tax collected from customers, (c) the measurement date of non-cash consideration received, (d) practical expedients in respect of contract modifications and completed contracts at transition, and (e) disclosure of the effects of the accounting change in the period of adoption. This standard will have the same effective date and transition requirements as ASU 2014-09. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. This standard is intended to provide guidance concerning the classification of certain cash receipts and cash payments in the statement of cash flows and to eliminate the diversity in practice related to such classifications. This standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2017, with early adoption permitted. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

STOCK-BASED COMPENSATION PLANS

STOCK-BASED COMPENSATION PLANS	9 Months Ended
	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
STOCK-BASED COMPENSATION PLANS	STOCK-BASED COMPENSATION PLANS: Officers and other key employees of SJG participate in the stock-based compensation plans of SJI. Performance-based restricted shares vest over a three-year period and are subject to SJI achieving certain market and earnings-based performance targets which can cause the actual amount of shares that ultimately vest to range from 0% to 200% of the original share units granted. Beginning in 2015, SJI granted time-based shares of restricted stock, one-third of which vest annually over a three -year period and are limited to a 100% payout. Vesting of time-based grants is contingent upon SJI achieving a return on equity (ROE) of at least 7% during the initial year of the grant and meeting the service requirement. Provided that the 7% ROE requirement is met in the initial year, payment is solely contingent upon the service requirement being met in years two and three of the grant. During the nine months ended September 30, 2016 and 2015 , SJG officers and other key employees were granted 9,965 and 7,878 shares of time-based restricted stock, respectively. Grants containing market-based performance targets use SJI's total shareholder return (TSR) relative to a peer group to measure performance. As TSR-based grants are contingent upon market and service conditions, SJI is required to measure and recognize stock-based compensation expense based on the fair value at the date of grant on a straight-line basis over the requisite three -year period of each award. In addition, SJI identifies specific forfeitures of share-based awards, and compensation expense is adjusted accordingly over the requisite service period. Compensation expense is not adjusted based on the actual achievement of performance goals. The fair value of TSR-based restricted stock awards on the date of grant is estimated using a Monte Carlo simulation model. Through 2014, grants containing earnings-based targets were based on SJI's earnings growth rate per share (EGR) relative to a peer group to measure performance. In 2015, earning-based performance targets included pre-defined EGR and return on equity (ROE) goals to measure performance. Beginning in 2016, performance targets include pre-defined compounded earnings annual growth rate (CEGR) for SJI. As EGR-based, ROE-based, and CEGR-based grants are contingent upon performance and service conditions, SJI is required to measure and recognize stock-based compensation expense based on the fair value at the date of grant over the requisite three -year period of each award. The fair value is measured as the market price at the date of grant. The initial accruals of compensation expense are based on the estimated number of shares expected to vest, assuming the requisite service is rendered and probable outcome of the performance condition is achieved. That estimate is revised if subsequent information indicates that the actual number of shares is likely to differ from previous estimates. Compensation expense is ultimately adjusted based on the actual achievement of service and performance targets. We are allocated a portion of SJI's compensation cost during the vesting period. We accrue a liability and record compensation cost over the requisite three -year service period based on the grant date fair value as described above for each type of grant. Upon vesting, we make a cash payment to SJI equal to the amounts accrued as compensation cost during the vesting period. Since the inception of the plans, our expense recognition policy has been consistent with the expense recognition policy at SJI. The following table summarizes the SJI nonvested restricted stock awards pertaining to SJG outstanding at September 30, 2016 , and the assumptions used to estimate the fair value of the awards: Grants Shares Outstanding Fair Value Per Share Expected Volatility Risk-Free Interest Rate 2014 - TSR 9,692 $ 21.31 20.0 % 0.80 % 2014 - EGR 9,692 $ 27.22 n/a n/a 2015 - TSR 6,884 $ 26.31 16.0 % 1.10 % 2015 - EGR, ROE, Time 15,211 $ 29.47 n/a n/a 2016 - TSR 11,472 $ 22.53 18.1 % 1.31 % 2016 - CEGR, Time 21,305 $ 23.52 n/a n/a Expected volatility is based on the actual volatility of SJI’s share price over the preceding three -year period as of the valuation date. The risk-free interest rate is based on the zero-coupon U.S. Treasury Bond, with a term equal to the three -year term of the restricted shares. As notional dividend equivalents are credited to the holders during the three -year service period, no reduction to the fair value of the award is required. The cost for restricted stock awards during the nine months ended September 30, 2016 and 2015 is approximately $0.2 million and $0.1 million per quarter, respectively. Of these costs, approximately one half was capitalized to Utility Plant. As of September 30, 2016 , there was $0.9 million of total unrecognized compensation cost related to nonvested share-based compensation awards granted under the plans. That cost is expected to be recognized over a weighted average period of 1.9 years. The following table summarizes information regarding restricted stock award activity during the nine months ended September 30, 2016 , excluding accrued dividend equivalents: Shares Weighted Average Grant Date Fair Value Nonvested Shares Outstanding, January 1, 2016 46,475 $ 26.67 Granted 33,218 $ 23.17 Canceled / Forfeited (2,827 ) $ 25.89 Vested (2,610 ) 29.47 Nonvested Shares Outstanding, September 30, 2016 74,256 $ 25.04 Performance targets during the three -year vesting periods were not attained for the January 2012 or 2013 grants that vested at December 31, 2014 and 2015, respectively. As a result, no shares were awarded in 2015 or 2016 associated with those grants. However, the initial performance hurdle for the 2015 time-based grant was met. As a result, 2,610 shares were awarded to Officers and other key employees during the nine months ended September 30, 2016 at a market value of $0.1 million . SJG has a policy of making cash payments to SJI to satisfy its obligations under the Plan. Cash payments to SJI during the nine months ended September 30, 2016 and 2015 were approximately $0.2 million in each period relating to stock awards. Additionally, a change in control could result in the nonvested shares becoming nonforfeitable or immediately payable in cash.

RATES AND REGULATORY ACTIONS

RATES AND REGULATORY ACTIONS	9 Months Ended
	Sep. 30, 2016
Public Utilities, General Disclosures [Abstract]
RATES AND REGULATORY ACTIONS	RATES AND REGULATORY ACTIONS: SJG is subject to the rules and regulations of the New Jersey Board of Public Utilities (BPU). In January 2016, SJG provided a Basic Gas Supply Service (BGSS) bill credit of approximately $20.0 million to its residential and small commercial customers. This credit is in addition to an overall rate reduction of 10.3% that was approved by the BPU and took effect in October 2015. SJG’s ability to offer the BGSS bill credit is a direct result of lower wholesale natural gas prices and the overall management of its gas supply portfolio. The BGSS clause serves as a method to pass along increases or decreases in gas costs to customers; therefore, SJG’s income is not affected by BGSS rate adjustments or bill credits. In February 2016, SJG filed a petition with the BPU for approval to continue its Accelerated Infrastructure Replacement Program (AIRP), which will expire at the end of 2016. In its petition, SJG has requested approval to continue its AIRP for an additional seven years, with program investments totaling approximately $500.0 million , to retire and replace bare steel and cast iron mains, bare steel services, and other aging infrastructure. The petition proposes to recover the costs of, and a return on, future AIRP investments through annual base rate adjustments. The petition also includes a request to reflect in base rates approximately $76.0 million of AIRP investments that will have been made since the conclusion of SJG’s last base rate case in October 2014 through the end of 2016. This petition was approved in October 2016 (see Note 15). Also in February 2016, the BPU approved a $7.9 million revenue decrease to SJG’s Energy Efficiency Tracker (EET), which recovers the cost of, and an allowed return on, investments in Energy Efficiency Programs (EEP). SJG’s original EEPs and its first EEP Extension, approved by the BPU in 2009 and 2013, respectively, ended in July 2013 and August 2015, respectively. The revenue requirements associated with these prior investments decrease over time as they are amortized and recovered. SJG is continuing to make energy efficiency investments under its most recent EEP Extension, which was approved by the BPU in August 2015, and is recovering the costs, and the allowed return on, those investments through the EET. In April 2016, the BPU approved a $2.6 million net decrease, including taxes, in annual revenues collected from SJG customers through the Societal Benefits Clause (SBC) charge and the Transportation Initiation Clause (TIC) charge, comprised of a $5.2 million increase in revenues from the Remediation Adjustment Clause (RAC) component of the SBC, a $7.1 million decrease in revenues from the Clean Energy Program (CLEP) component of the SBC, and a $0.7 million decrease in TIC revenues, effective May 7, 2016. The increase in the RAC is driven by an increase in costs associated with the remediation of former manufactured gas plants. The decrease in the CLEP component of the SBC is primarily related to the accumulation of prior year over-recoveries. The decrease in the TIC is driven by a decrease in costs. The SBC and TIC allow SJG to recover costs associated with certain State-mandated programs. SJG does not earn any profit from these charges. In June 2016, SJG filed its annual EET rate adjustment petition, requesting a $0.8 million decrease in revenues to continue recovering the costs of, and the allowed return on, prior investments associated with EEP's. The revenue adjustment was subsequently updated in September 2016 to reflect a revenue decrease of $1.6 million . The EET rate recovers the forecasted revenue requirements for the upcoming EET year of October 2016 to September 2017. The requested revenue decrease is the result of the investments associated with SJG's original EEPs, approved by the BPU in 2009, and its EEP extension, approved by the BPU in 2013, which ended in July 2013 and August 2015, respectively. The revenue requirements associated with these prior investments decreases over time as they are amortized. This petition was approved in October 2016. In September 2016, the BPU approved an increase in annual revenues from base rates of $3.9 million , including taxes, to reflect the roll-in of $33.7 million of investments made from July 1, 2015 through June 30, 2016 under SJG's’s Storm Hardening and Reliability Program (SHARP), with rates effective as of October 1, 2016. Also in September 2016, the BPU approved a $0.6 million net decrease in annual revenues to be implemented on October 1, 2016, comprised of a $47.1 million decrease in BGSS revenues and a $46.5 million increase in Conservation Incentive Program (CIP) revenues, both including taxes. The level of BGSS revenues requested in annual BGSS filings is based on forecasted gas costs and customer usage information for the upcoming BGSS/CIP year, which runs from October 1, 2016 to September 30, 2017. SJG’s request for a decrease of BGSS revenues was caused primarily by decreases in forecasted gas commodity costs for the upcoming BGSS/CIP year. The level of CIP revenues requested in annual CIP filings is based on historical customer usage information, comparing prior CIP year customer usage to normal customer usage. SJG’s request for an increase in CIP revenues was primarily due to lower than normal customer usage caused by weather that was 16.4% warmer than normal during the 2015- 2016 winter. Additionally, in September 2016, the BPU approved the statewide Universal Service Fund (USF) budget of $56.0 million for all the State’s gas utilities. SJG’s portion of the total budget is approximately $5.6 million . Effective October 1, 2016, the BPU approved a $1.1 million increase in SJG’s USF recoveries. The BGSS, CIP and USF approvals discussed above do not impact SJG's earnings. They represent changes in the cash requirements of SJG corresponding to cost changes and/or the return of previously under-recovered costs associated with each respective mechanism. There have been no other significant regulatory actions or changes to SJG's rate structure since December 31, 2015 . See Note 3 to the Financial Statements in Item 8 of SJG's Annual Report on Form 10-K for the year ended December 31, 2015 .

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES	9 Months Ended
	Sep. 30, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
REGULATORY ASSETS AND LIABILITIES	REGULATORY ASSETS AND LIABILITIES: There have been no significant changes to the nature of SJG’s regulatory assets and liabilities since December 31, 2015 , which are described in Notes 3 and 4 to the Financial Statements in Item 8 of SJG’s Form 10-K for the year ended December 31, 2015 . Regulatory Assets consisted of the following items (in thousands): September 30, 2016 December 31, 2015 Environmental Remediation Costs: Expended - Net $ 57,100 $ 42,032 Liability for Future Expenditures 160,587 123,194 Deferred Asset Retirement Obligation Costs 42,768 42,430 Deferred Pension and Other Postretirement Benefit Costs 79,779 79,779 Deferred Gas Costs - Net — 2,701 Conservation Incentive Program Receivable 23,485 2,624 Deferred Interest Rate Contracts (Note 11) 10,346 7,631 Energy Efficiency Tracker — 496 Pipeline Supplier Service Charges 2,527 3,776 Pipeline Integrity Cost 4,595 4,596 AFUDC - Equity Related Deferrals 12,357 11,423 Other Regulatory Assets 3,527 2,752 Total Regulatory Assets $ 397,071 $ 323,434 ENVIRONMENTAL REMEDIATION COSTS - We have two regulatory assets associated with environmental costs related to the cleanup of 12 sites where we or our predecessors previously operated gas manufacturing plants. The first asset, "Environmental Remediation Cost: Expended - Net," represents what was actually spent to clean up the sites, less recoveries through the Remediation Adjustment Clause (RAC) and insurance carriers. These costs meet the deferral requirements of GAAP, as the BPU allows us to recover such expenditures through the RAC. The other asset, "Environmental Remediation Cost: Liability for Future Expenditures," relates to estimated future expenditures required to complete the remediation of these sites. We recorded this estimated amount as a regulatory asset with the corresponding current and noncurrent liabilities on the balance sheets under the captions "Current Liabilities" and "Regulatory and Other Noncurrent Liabilities." The BPU allows us to recover the deferred costs over seven -year periods after they are spent. The increase from December 31, 2015 is a result of expenditures made during the first nine months of 2016 and an increase in the expected future expenditures for remediation activities primarily due to an increase in the scope of the remediation at a site related to additional contamination being discovered. DEFERRED GAS COSTS - NET - See discussion under "Deferred Revenues - Net" below. CONSERVATION INCENTIVE PROGRAM (CIP) RECEIVABLE – The CIP tracking mechanism adjusts earnings when actual usage per customer experienced during the period varies from an established baseline usage per customer. Actual usage per customer was less than the established baseline during the 2015 - 2016 winter season and during the first nine months of 2016, resulting in an increase in the receivable. This is primarily the result of warm weather experienced in the region. Regulatory Liabilities consisted of the following items (in thousands): September 30, 2016 December 31, 2015 Excess Plant Removal Costs $ 30,324 $ 32,644 Deferred Revenues-Net 14,418 — Societal Benefit Costs 5,907 10,197 Energy Efficiency Tracker 401 — Total Regulatory Liabilities $ 51,050 $ 42,841 DEFERED REVENUES - NET - Over/under collections of gas costs are monitored through SJG's BGSS mechanism. Net under collected gas costs are classified as a regulatory asset and net over collected gas costs are classified as a regulatory liability. Derivative contracts used to hedge natural gas purchases are also included in the BGSS, subject to BPU approval. The BGSS changed from a $2.7 million regulatory asset at December 31, 2015 to a $14.4 million regulatory liability at September 30, 2016, primarily due to the gas costs recovered from customers exceeding the actual cost of the commodity. ENERGY EFFICIENCY TRACKER (EET) - This regulatory liability primarily represents energy efficiency measures installed in customer homes and businesses. The change from a $0.5 million regulatory asset at December 31, 2015 to a $0.4 million regulatory liability at September 30, 2016 is due to recoveries being greater than the cost of, and allowed return on, investments in the EEP's. In February 2016, the BPU approved a $7.9 million revenue decrease to SJG’s EET (see Note 3).

RELATED-PARTY TRANSACTIONS

RELATED-PARTY TRANSACTIONS	9 Months Ended
	Sep. 30, 2016
Related Party Transactions [Abstract]
RELATED-PARTY TRANSACTIONS	RELATED-PARTY TRANSACTIONS: There have been no significant changes in the nature of SJG’s related-party transactions since December 31, 2015 . See Note 5 to the Financial Statements in Item 8 of SJG’s Annual Report on Form 10-K for the year ended December 31, 2015 for a detailed description of the related parties and their associated transactions. A summary of related-party transactions, excluding pass-through items, included in Operating Revenues were as follows (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 Operating Revenues/Affiliates: SJRG $ 977 $ 1,100 $ 5,399 $ 2,631 Marina 86 116 292 483 Total Operating Revenue/Affiliates $ 1,063 $ 1,216 $ 5,691 $ 3,114 Related-party transactions, excluding pass-through items, included in Operating Expenses were as follows (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 Costs of Sales/Affiliates (Excluding depreciation) SJRG $ 490 $ 574 $ 9,993 $ 21,105 Energy-Related Derivative Losses / (Gains) * SJRG $ — $ — $ — $ 65 * Contracts used to hedge natural gas purchases. Included in Cost of Sales on the Condensed Statements of Income. Operations Expense/Affiliates: SJI $ 4,632 $ 3,248 $ 14,502 $ 10,529 Millennium 703 695 2,098 2,048 Other (48 ) (95 ) (154 ) (312 ) Total Operations Expense/Affiliates $ 5,287 $ 3,848 $ 16,446 $ 12,265

FINANCIAL INSTRUMENTS

FINANCIAL INSTRUMENTS	9 Months Ended
	Sep. 30, 2016
Financial Instruments, Owned, at Fair Value [Abstract]
FINANCIAL INSTRUMENTS	FINANCIAL INSTRUMENTS: RESTRICTED INVESTMENTS - In accordance with the terms of our tax-exempt first mortgage bonds, unused proceeds are required to be escrowed pending approved construction expenditures. As of both September 30, 2016 and December 31, 2015 , the escrowed proceeds, including interest earned, totaled $32,225 . SJG maintains a margin account with a counterparty in conjunction with SJG's risk management activities as detailed in Note 11. The funds provided by SJG will increase or decrease as the number and value of outstanding energy-related contracts held with this counterparty change. As of September 30, 2016 , the balance owed to this counterparty totaled $0.3 million and as of December 31, 2015 , the balance held with this counterparty totaled $6.7 million . In September 2016, SJG placed $8.3 million in an escrow account to construct SJG's building in Atlantic City, New Jersey. The money is restricted until the final contracts are approved, at which time the money will be released for use in constructing SJG's building. The carrying amounts of the Restricted Investments approximate their fair value at September 30, 2016 and December 31, 2015 , which would be included in Level 1 of the fair value hierarchy. (See Note 10 - Fair Value of Financial Assets and Financial Liabilities.) NOTE RECEIVABLE - In June 2015, SJG advanced $10.0 million to a not-for-profit organization formed to spur economic development in Atlantic City, New Jersey. The Note included interest at 1% for an initial term of six months, with the borrower’s option to extend the term for two additional terms of three months each. In December 2015 and February 2016, the borrower exercised each option, respectively. In July 2016, the note was repaid in full, including interest. LONG-TERM RECEIVABLES – SJG provides financing to customers for the purpose of attracting conversions to natural gas heating systems from competing fuel sources. The terms of these loans call for customers to make monthly payments over a period of up to five to ten years with no interest. The carrying amounts of such loans were $10.2 million and $12.9 million as of September 30, 2016 and December 31, 2015 , respectively. The current portion of these receivables is reflected in Accounts Receivable and the non-current portion is reflected in Long-Term Receivables on the condensed balance sheets. The carrying amounts noted above are net of unamortized discounts resulting from imputed interest in the amount of $1.0 million and $1.3 million as of September 30, 2016 and December 31, 2015 , respectively. The annualized amortization to interest is not material to SJG’s financial statements. The carrying amounts of these receivables approximate their fair value at September 30, 2016 and December 31, 2015 , which would be included in Level 2 of the fair value hierarchy (See Note 10 - Fair Value of Financial Assets and Financial Liabilities). FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE - The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. The carrying amounts of SJG's financial instruments approximate their fair values at September 30, 2016 and December 31, 2015 , except as noted below. • For Long-Term Debt, in estimating the fair value, we use the present value of remaining cash flows at the balance sheet date. We based the estimates on interest rates available to SJG at the end of each period for debt with similar terms and maturities (Level 2 in the fair value hierarchy. See Note 10 - Fair Value of Financial Assets and Financial Liabilities). The estimated fair values of SJG's long-term debt, including current maturities, as of September 30, 2016 and December 31, 2015 , were $699.7 million and $657.4 million , respectively. The carrying amount of SJG's long-term debt, including current maturities, as of September 30, 2016 and December 31, 2015 , was $639.9 million and $605.4 million , respectively. The carrying amounts as of September 30, 2016 and December 31, 2015 are net of unamortized debt issuance costs of $6.1 million and $6.6 million , respectively (see Note 1).

LINES OF CREDIT

LINES OF CREDIT	9 Months Ended
	Sep. 30, 2016
Line of Credit Facility [Abstract]
LINES OF CREDIT	LINES OF CREDIT: Credit facilities and available liquidity as of September 30, 2016 were as follows (in thousands): Total Facility Usage Available Liquidity Expiration Date Commercial Paper Program/ Revolving Credit Facility $ 200,000 $ 81,800 (A) $ 118,200 May 2018 Uncommitted Bank Lines 10,000 — 10,000 August 2017 Total $ 210,000 $ 81,800 (A) $ 128,200 (A) Includes letters of credit outstanding in the amount of $0.8 million . The SJG revolving credit facility is provided by a syndicate of banks and contains one financial covenant limiting the ratio of indebtedness to total capitalization (as defined in the credit agreement) to not more than 0.65 to 1 measured at the end of each fiscal quarter. SJG was in compliance with this covenant as of September 30, 2016 . SJG manages a commercial paper program under which SJG may issue short-term, unsecured promissory notes to qualified investors up to a maximum aggregate amount outstanding at any time of $200.0 million . The notes have fixed maturities which vary by note, but may not exceed 270 days from the date of issue. Proceeds from the notes are used for general corporate purposes. SJG uses the commercial paper program in tandem with the $200.0 million revolving credit facility and does not expect the principal amount of borrowings outstanding under the commercial paper program and the credit facility at any time to exceed an aggregate of $200.0 million . Average borrowings outstanding under these credit facilities during the nine months ended September 30, 2016 and 2015 were $64.5 million and $117.9 million , respectively. The maximum amount outstanding under these credit facilities during the nine months ended September 30, 2016 and 2015 were $ 141.7 million and $ 162.3 million , respectively. Borrowings under these credit facilities are at market rates. The weighted average interest rate on these borrowings, which changes daily, was 0.76% and 0.40% at September 30, 2016 and 2015 , respectively.

PENSION AND OTHER POSTRETIREMEN

PENSION AND OTHER POSTRETIREMENT BENEFITS	9 Months Ended
	Sep. 30, 2016
Compensation and Retirement Disclosure [Abstract]
PENSION AND OTHER POSTRETIREMENT BENEFITS	PENSION AND OTHER POSTRETIREMENT BENEFITS: For the three and nine months ended September 30, 2016 and 2015 , net periodic benefit cost related to the employee and officer pension and other postretirement benefit plans consisted of the following components (in thousands): Pension Benefits Pension Benefits Three Months Ended Nine Months Ended 2016 2015 2016 2015 Service Cost $ 892 $ 996 $ 2,675 $ 2,988 Interest Cost 2,233 2,083 6,699 6,251 Expected Return on Plan Assets (2,488 ) (2,759 ) (7,463 ) (8,278 ) Amortizations: Prior Service Cost 39 40 117 119 Actuarial Loss 1,730 1,979 5,190 5,938 Net Periodic Benefit Cost 2,406 2,339 7,218 7,018 Capitalized Benefit Cost (1,251 ) (1,216 ) (3,651 ) (3,649 ) Deferred Benefit Cost (161 ) (341 ) (483 ) (666 ) Total Net Periodic Benefit Expense $ 994 $ 782 $ 3,084 $ 2,703 Other Postretirement Benefits Other Postretirement Benefits Three Months Ended Nine Months Ended 2016 2015 2016 2015 Service Cost $ 106 $ 186 $ 318 $ 558 Interest Cost 325 495 977 1,486 Expected Return on Plan Assets (386 ) (499 ) (1,159 ) (1,496 ) Amortizations: Prior Service Cost (43 ) 102 (129 ) 304 Actuarial Loss 138 224 414 671 Net Periodic Benefit Cost 140 508 421 1,523 Capitalized Benefit Cost (73 ) (264 ) (219 ) (792 ) Deferred Benefit Cost — (89 ) — (168 ) Total Net Periodic Benefit Expense $ 67 $ 155 202 563 Capitalized benefit costs reflected in the table above relate to our construction program. Deferred benefit costs relate to the deferral of incremental expenses associated with the adoption of new mortality tables effective December 31, 2014 and 2015. Deferred benefit costs are expected to be recovered through rates as part of our next base rate case. SJG contributed $12.0 million to the pension plans in January 2015. No contributions were made to the pension plans during the nine-months ended September 30, 2016. SJG does not expect to make any contributions to the pension plans in 2016; however, changes in future investment performance and discount rates may ultimately result in a contribution. Payments related to the unfunded Supplemental Executive Retirement Plan (SERP) are expected to approximate $2.2 million in 2016. We also have a regulatory obligation to contribute approximately $3.6 million annually to the other postretirement benefit plans’ trusts, less direct costs incurred. See Note 11 to the Financial Statements in Item 8 of SJG’s Annual Report on Form 10-K for the year ended December 31, 2015 for additional information related to SJG’s pension and other postretirement benefits.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES: STANDBY LETTER OF CREDIT - SJG provided a $0.8 million letter of credit under its revolving credit facility to support the remediation of environmental conditions at certain locations in our service territory. SJG also provided a $25.2 million letter of credit under a separate facility outside of its revolving credit facility to support variable-rate demand bonds issued through the New Jersey Economic Development Authority (NJEDA) to finance the expansion of SJG’s natural gas distribution system. ENVIRONMENTAL REMEDIATION COSTS - SJG incurred and recorded costs for environmental cleanup of 12 sites where SJG or its predecessors operated gas manufacturing plants. SJG stopped manufacturing gas in the 1950s. Other than the changes discussed in Note 4 to the condensed financial statements, there have been no significant changes to the status of SJG’s environmental remediation efforts since December 31, 2015 , as described in Note 12 to the Financial Statements in Item 8 of SJG’s Annual Report on Form 10-K for the year ended December 31, 2015 . GAS SUPPLY RELATED CONTRACTS - In the normal course of conducting business, we have entered into long-term contracts for natural gas supplies, firm transportation and gas storage service. The earliest date at which any of the primary terms of these contracts expire is October 2017. The transportation and storage agreements entered into between us and each of our interstate pipeline service providers were done in accordance with their respective FERC-approved tariffs. Our cumulative obligation for gas supply-related demand charges and reservation fees paid for these services averages approximately $5.8 million per month and is recovered on a current basis through the BGSS. PENDING LITIGATION - SJG is subject to claims arising in the ordinary course of business and other legal proceedings. SJG accrues liabilities related to these claims when SJG can reasonably estimate the amount or range of amounts of probable settlement costs or other charges for these claims. SJG has accrued approximately $0.7 million and $0.8 million related to all claims in the aggregate as of September 30, 2016 and December 31, 2015 , respectively. SJG is currently involved in a pricing dispute related to a long-term gas supply contract whereby SJG has sued the supplier to recover amounts that were improperly invoiced. Subsequently, the supplier counter-sued SJG claiming it is owed an additional $14.3 million through September 30, 2016 under the same contract, which would be recoverable in rates. Liabilities related to these claims are accrued when the amount or range of amounts of probable settlement costs or other charges for these claims can be reasonably estimated. COLLECTIVE BARGAINING AGREEMENTS - Unionized personnel represent approximately 61% of our workforce at September 30, 2016 . The Company has collective bargaining agreements with two unions who represent these employees: the International Brotherhood of Electrical Workers (IBEW) operates under a collective bargaining agreement that runs through February 2017; and the International Association of Machinists and Aerospace Workers (IAM) operates under a collective bargaining agreement that expires in August 2017.

FAIR VALUE OF FINANCIAL ASSETS

FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES	FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES: GAAP establishes a hierarchy that prioritizes fair value measurements based on the types of inputs used for the various valuation techniques. The levels of the hierarchy are described below: • Level 1: Observable inputs, such as quoted prices in active markets for identical assets or liabilities. • Level 2: Inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly; these include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. • Level 3: Unobservable inputs that reflect the reporting entity’s own assumptions. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of financial assets and financial liabilities and their placement within the fair value hierarchy. For financial assets and financial liabilities measured at fair value on a recurring basis, information about the fair value measurements for each major category is as follows (in thousands): As of September 30, 2016 Total Level 1 Level 2 Level 3 Assets Available-for-Sale Securities (A) $ 9,260 $ 1,825 $ 7,435 $ — Derivatives – Energy Related Assets (B) 2,562 1,771 7 784 $ 11,822 $ 3,596 $ 7,442 $ 784 Liabilities Derivatives – Energy Related Liabilities (B) $ 3,349 $ 582 $ 2,489 $ 278 Derivatives – Other (C) 10,346 — 10,346 — $ 13,695 $ 582 $ 12,835 $ 278 As of December 31, 2015 Total Level 1 Level 2 Level 3 Assets Available-for-Sale Securities (A) $ 8,788 $ 1,722 $ 7,066 $ — Derivatives - Energy Related Assets (B) 1,141 398 144 599 $ 9,929 $ 2,120 $ 7,210 $ 599 Liabilities Derivatives - Energy Related Liabilities (B) $ 5,840 $ 5,424 $ — $ 416 Derivatives - Other (C) 7,631 — 7,631 — $ 13,471 $ 5,424 $ 7,631 $ 416 (A) Available-for-Sale Securities include securities that are traded in active markets and securities that are not traded publicly. The securities traded in active markets are valued using the quoted principal market close prices that are provided by the trustees and are categorized in Level 1 in the fair value hierarchy. The remaining securities consist of funds that are not publicly traded. These funds, which consist of stocks and bonds that are traded individually in active markets, are valued using quoted prices for similar assets and are categorized in Level 2 in the fair value hierarchy. (B) Derivatives – Energy Related Assets and Liabilities are traded in both exchange-based and non-exchange-based markets. Exchange-based contracts are valued using unadjusted quoted market sources in active markets and are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based contracts are valued using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask mid-point prices and are obtained from sources that management believes provide the most liquid market. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. In instances where observable data is unavailable, management considers the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Significant Unobservable Inputs - Management uses the discounted cash flow model to value Level 3 physical and financial forward contracts, which calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return and credit spreads. Inputs to the valuation model are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third party pricing sources. The validity of the mark-to-market valuations and changes in mark-to-market valuations from period to period are examined and qualified against historical expectations by the risk management function. If any discrepancies are identified during this process, the mark-to-market valuations or the market pricing information is evaluated further and adjusted, if necessary. Level 3 valuation methods for natural gas derivative contracts include utilizing another location in close proximity adjusted for certain pipeline charges to derive a basis value. The significant unobservable inputs used in the fair value measurement of certain natural gas contracts consist of forward prices developed based on industry-standard methodologies. Significant increases (decreases) in these forward prices for purchases of natural gas would result in a directionally similar impact to the fair value measurement and for sales of natural gas would result in a directionally opposite impact to the fair value measurement. (C) Derivatives – Other, include interest rate swaps that are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. The following table provides quantitative information regarding significant unobservable inputs in Level 3 fair value measurements (in thousands): Type Fair Value at September 30, 2016 Valuation Technique Significant Unobservable Input Range Assets Liabilities Forward Contract - Natural Gas $784 $278 Discounted Cash Flow Forward price (per dt) $0.9 - $6.80 (A) Type Fair Value at December 31, 2015 Valuation Technique Significant Unobservable Input Range Assets Liabilities Forward Contract - Natural Gas $599 $416 Discounted Cash Flow Forward price (per dt) $1.18 - $5.21 (A) (A) Represents the range, along with the weighted average, of forward prices for the sale and purchase of natural gas. The changes in fair value measurements of Derivatives - Energy Related Assets and Liabilities for the three and nine months ended September 30, 2016, using significant unobservable inputs (Level 3), are as follows (in thousands): Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016 Balance at beginning of period $ (224 ) $ 183 Other Changes in Fair Value from Continuing and New Contracts, Net 730 506 Settlements — (183 ) Balance at end of period 506 506 The changes in fair value measurements of Derivatives - Energy Related Assets and Liabilities for the three and nine months ended September 30, 2015, using significant unobservable inputs (Level 3), are as follows (in thousands): Three Months Ended September 30, 2015 Nine Months Ended September 30, 2015 Balance at beginning of period $ (584 ) $ — Other Changes in Fair Value from Continuing and New Contracts, Net 1,035 451 Balance at end of period 451 451

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS: SJG is involved in buying, selling, transporting and storing natural gas and is subject to market risk on expected future purchases and sales due to commodity price fluctuations. The Company, through a counterparty, uses a variety of derivative instruments to limit this exposure to market risk in accordance with strict corporate guidelines. These derivative instruments include forward contracts, futures contracts, swap agreements and options contracts. As of September 30, 2016 , SJG had outstanding derivative contracts intended to limit the exposure to market risk on 8.7 million decatherms (MMdts) of expected future purchases of natural gas and 0.6 MMdts of expected future sales of natural gas. In addition to these derivative contracts, SJG had basis and index related purchase contracts of 4.6 MMdts and sales contracts of 9.0 MMdts for net contracted volumes of 4.4 MMdts. These contracts, which do not qualify for the normal purchase and sale exemption and have not been designated as hedging instruments under GAAP, are measured at fair value and recorded in Derivatives — Energy Related Assets or Derivatives — Energy Related Liabilities on the condensed balance sheets. The costs or benefits of these short-term contracts are recoverable through SJG’s BGSS clause, subject to BPU approval. As a result, the net unrealized pre-tax gains and losses for these energy-related commodity contracts are included with realized gains and losses in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets. As of September 30, 2016 and December 31, 2015 , SJG had $0.8 million and $4.7 million of unrealized gains, respectively, included in its BGSS related to open financial contracts. The Company has also entered into interest rate derivatives to hedge exposure to increasing interest rates and the impact of those rates on cash flows of variable-rate debt. These interest rate derivatives, which have not been designated as hedging instruments under GAAP, are measured at fair value and recorded in Derivatives-Other on the condensed balance sheets. The fair value represents the amount SJG would have to pay the counterparty to terminate these contracts as of those dates. There have been no significant changes to the Company’s active interest rate swaps since December 31, 2015 , which are described in Note 1 to the Financial Statements in Item 8 of SJG’s Annual Report on Form 10-K for the year ended December 31, 2015 . Subject to BPU approval, the market value upon termination of these interest rate derivatives can be recovered in rates and, therefore, these unrealized losses have been included in Regulatory Assets on the condensed balance sheets. We previously used derivative transactions known as “Treasury Locks” to hedge against the impact on our cash flows of possible interest rate increases on debt issued in September 2005. The initial $1.4 million cost of the Treasury Locks has been included in Accumulated Other Comprehensive Loss and is being amortized over the 30 -year life of the associated debt issue. As of both September 30, 2016 and December 31, 2015 , the unamortized balance was approximately $0.9 million . . The fair values of all derivative instruments, as reflected in the condensed balance sheets as of September 30, 2016 and December 31, 2015 , are as follows (in thousands): Derivatives not designated as hedging instruments under GAAP September 30, 2016 December 31, 2015 Assets Liabilities Assets Liabilities Energy related commodity contracts: Derivatives – Energy Related – Current $ 2,281 $ 3,276 $ 1,077 $ 5,489 Derivatives – Energy Related – Non-Current 281 73 64 351 Interest rate contracts: Derivatives – Other Current — 535 — — Derivatives – Other Noncurrent — 9,811 — 7,631 Total derivatives not designated as hedging instruments under GAAP 2,562 13,695 1,141 13,471 Total Derivatives $ 2,562 $ 13,695 $ 1,141 $ 13,471 The Company enters into derivative contracts with counterparties, some of which are subject to master netting arrangements, which allow net settlements under certain conditions. The Company presents derivatives at gross fair values on the condensed balance sheets. As of September 30, 2016 , and December 31, 2015 , information related to these offsetting arrangements were as follows (in thousands): As of September 30, 2016: Description Gross amounts of recognized assets/liabilities Gross amount offset in the balance sheet Net amounts of assets/liabilities in balance sheet Gross amounts not offset in the balance sheet Net amount Financial Instruments Cash Collateral Posted Derivatives - Energy Related Assets $ 2,562 $ — $ 2,562 $ (582 ) (A) $ (339 ) $ 1,641 Derivatives - Energy Related Liabilities (3,349 ) — (3,349 ) 582 (B) — (2,767 ) Derivatives - Other (10,346 ) — (10,346 ) — — (10,346 ) As of December 31, 2015: Description Gross amounts of recognized assets/liabilities Gross amount offset in the balance sheet Net amounts of assets/liabilities in balance sheet Gross amounts not offset in the balance sheet Net amount Financial Instruments Cash Collateral Posted Derivatives - Energy Related Assets $ 1,141 $ — $ 1,141 $ (399 ) (A) $ — $ 742 Derivatives - Energy Related Liabilities (5,840 ) — (5,840 ) 399 (B) 5,025 (416 ) Derivatives - Other (7,631 ) — (7,631 ) — — (7,631 ) (A) The balances at September 30, 2016 and December 31, 2015 were related to derivative liabilities which can be net settled against derivative assets. (B) The balances at September 30, 2016 and December 31, 2015 were related to derivative assets which can be net settled against derivative liabilities. The effect of derivative instruments on the condensed statements of income for the three and nine months ended September 30, 2016 and 2015 are as follows (in thousands): Three months ended Nine months ended Derivatives in Cash Flow Hedging Relationships 2016 2015 2016 2015 Interest Rate Contracts: Gains reclassified from Accumulated Other Comprehensive Loss into income (a) $ 12 $ 12 $ 36 $ 36 (a) Included in Interest Charges A net realized gain of $0.9 million and a net realized loss of $1.6 million associated with SJG's energy-related financial commodity contracts for the three months ended September 30, 2016 and 2015 , and loss of $3.5 million and $6.4 million for the nine months ended September 30, 2016 and 2015, respectively, are not included in the above table. These contracts are part of SJG’s regulated risk management activities that serve to mitigate BGSS costs passed on to its customers. As these transactions are entered into pursuant to, and recoverable through, regulatory riders, any changes in the value of SJG’s energy-related financial commodity contracts are deferred in Regulatory Assets or Liabilities, as applicable, and there is no impact to earnings.

LONG-TERM DEBT

LONG-TERM DEBT	9 Months Ended
	Sep. 30, 2016
Long-term Debt, Unclassified [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT: In January 2016, SJG issued $61.0 million of long-term debt at 1.37% under a $200.0 million aggregate syndicated bank term facility. The facility is now fully drawn. The total outstanding amount under this facility as of September 30, 2016 was $200.0 million , which was reclassified to current portion of long-term debt on the condensed balance sheets as it is due within one year. SJG is evaluating alternatives, including refinancing or renewing the facility. In July, SJG retired $17.0 million of 4.60% Medium Term Notes ("MTN's") at maturity. In August, SJG retired $10.0 million of 5.437% MTN's at maturity. The Company did not issue or retire any other long-term debt during the nine months ended September 30, 2016. We retire debt when it is cost effective as permitted by the debt agreements.

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE LOSS	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE LOSS	ACCUMULATED OTHER COMPREHENSIVE LOSS: The changes in Accumulated Other Comprehensive Loss (AOCL) for the three and nine months ended September 30, 2016 are as follows (in thousands): Postretirement Liability Adjustment Unrealized Gain (Loss) on Derivatives-Other Unrealized Gain (Loss) on Available-for-Sale Securities Total Balance at July 1, 2016 (a) $ (12,220 ) $ (530 ) $ (91 ) $ (12,841 ) Other comprehensive loss before reclassifications — — 167 167 Amounts reclassified from AOCL (b) — 7 (129 ) (122 ) Net current period other comprehensive income — 7 38 45 Balance at September 30, 2016 (a) $ (12,220 ) $ (523 ) $ (53 ) $ (12,796 ) Postretirement Liability Adjustment Unrealized Gain (Loss) on Derivatives-Other Unrealized Gain (Loss) on Available-for-Sale Securities Total Balance at January 1, 2016 (a) $ (12,220 ) $ (544 ) $ (98 ) $ (12,862 ) Other comprehensive loss before reclassifications — — 304 304 Amounts reclassified from AOCL (b) — 21 (259 ) (238 ) Net current period other comprehensive income (loss) — 21 45 66 Balance at September 30, 2016 (a) $ (12,220 ) $ (523 ) $ (53 ) $ (12,796 ) (a) Determined using a combined average statutory tax rate of 40% . (b) See table below. The reclassifications out of AOCL during the three and nine months ended September 30, 2016 are as follows (in thousands): Components of AOCL Amounts Reclassified from AOCL Affected Line Item in the Condensed Statements of Income Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016 Unrealized Loss in on Derivatives - Other - Interest Rate Contracts designated as cash flow hedges $ 12 $ 36 Interest Charges Income Taxes (5 ) (15 ) Income Taxes (a) $ 7 $ 21 Unrealized Gain on Available-for-Sale Securities $ (217 ) $ (432 ) Other Income & Expense Income Taxes 88 173 Income Taxes (a) $ (129 ) $ (259 ) Gains from reclassifications for the period net of tax $ (122 ) $ (238 ) (a) Determined using a combined average statutory tax rate of 40% .

OTHER PAID IN CAPITAL

OTHER PAID IN CAPITAL	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
OTHER PAID IN CAPITAL	OTHER PAID IN CAPITAL: In June 2016, SJG received an equity infusion of $65.0 million from SJI.

SUBSEQUENT EVENT

SUBSEQUENT EVENT	9 Months Ended
	Sep. 30, 2016
Subsequent Events [Abstract]
SUBSEQUENT EVENT	SUBSEQUENT EVENT: In October 2016, the BPU approved SJG’s request to extend its AIRP for a five -year period commencing October 1, 2016 and ending September 30, 2021, with authorized investments of up to $302.5 million to continue replacing cast iron and unprotected bare steel mains and associated services (AIRP II). Cost recovery of AIRP II investments, including a return on SJG’s investments, will be accomplished through annual base rate adjustments that will occur on October 1 st of each year of the program. The BPU also approved an increase in annual revenues from base rates of $11.0 million , including taxes, to reflect the roll-in of the remaining $74.5 million of prior AIRP investments, made from the time of SJG’s last base rate case through the end of the first AIRP program, that were not yet reflected in rates. These rates will be effective as of December 1, 2016.

SUMMARY OF SIGNIFICANT ACCOUN23

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
RECLASSIFICATIONS	Certain reclassifications have been made to the prior period's condensed balance sheets, as well as the prior period's long-term debt carrying value in Note 6, to conform to the current period presentation. The unamortized debt issuance costs previously included in "Regulatory and Other Noncurrent Assets" on the condensed balance sheets were reclassified to Long-Term Debt to conform to ASU 2015-03, which is described below under "New Accounting Pronouncements." This reclassification caused the prior period long-term debt carrying value in Note 6 to be adjusted.
REVENUE-BASED TAXES	REVENUE - BASED TAXES - SJG collects certain revenue-based energy taxes from its customers. Such taxes include the New Jersey State Sales Tax and Public Utilities Assessment (PUA). State sales tax is recorded as a liability when billed to customers and is not included in revenue or operating expenses.
NEW ACCOUNTING PRONOUNCEMENTS	NEW ACCOUNTING PRONOUNCEMENTS — Other than as described below, no new accounting pronouncement issued or effective during 2016 or 2015 had, or are expected to have, a material impact on the condensed financial statements. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes the revenue recognition requirements in FASB ASC 605, Revenue Recognition , and in most industry-specific topics. The new guidance identifies how and when entities should recognize revenue. The new rules establish a core principle requiring the recognition of revenue to depict the transfer of promised goods or services to customers in an amount reflecting the consideration to which the entity expects to be entitled in exchange for such goods or services. The new guidance is effective for fiscal years, and interim periods within those annual periods, beginning after December 15, 2017. Management has formed an implementation team that is currently inventorying the contracts with customers and evaluating the impact that adoption of this guidance will have on the Company's financial statement results, as well as the transition method the Company will elect to adopt the guidance. In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40); Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern . The new guidance requires management of a company to evaluate whether there is substantial doubt about the company's ability to continue as a going concern. This ASU is effective for the annual reporting period ending after December 15, 2016, and for interim and annual reporting periods thereafter, with early adoption permitted. Management does not expect this standard to have an impact on the Company's financial statements upon adoption. In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs . This ASU requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. The standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. Adoption of this guidance did not have an impact on the Company's results of operations; however, balance sheet presentations were modified to conform to this guidance. In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory . This ASU states that inventory for which cost is determined using a method other than last-in, first-out (LIFO) or the retail method should be subsequently measured at the lower of cost or net realizable value (NRV), rather than at the lower of cost or market. The standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities , which enhances the reporting model for financial instruments and includes amendments to address aspects of recognition, measurement, presentation and disclosure. The standard is effective for annual periods, including interim periods within those annual periods. beginning after December 15, 2017. Early adoption is permitted for only certain portions of the new guidance. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In March 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which establishes a new lease accounting model for lessees. The new standard requires substantially all leases be recognized by lessees on their balance sheet as a right-of-use asset and corresponding lease liability, including leases currently accounted for as operating leases. The new standard also will result in enhanced quantitative and qualitative disclosures, including significant judgments made by management, to provide greater insight into the extent of revenue and expense recognized and expected to be recognized from existing leases. The accounting for leases by the lessor remains relatively the same. The standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2018, with early adoption permitted. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships . The amendments in this guidance clarify that a change in the counterparty to a derivative instrument that has been designated as a hedging instrument under Topic 815 does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016, with early adoption permitted. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) . This standard amends ASU 2014-09 (discussed above), to improve the implementation guidance on principal versus agent considerations and whether an entity reports revenue on a gross or net basis. This standard will have the same effective date and transition requirements as ASU 2014-09. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In March 2016, the FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , which simplifies various aspects of accounting for share-based payment arrangements. The standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016, with early adoption permitted. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing . This standard amends ASU 2014-09 (discussed above) to clarify identifying performance obligations and the licensing implementation guidance. This standard will have the same effective date and transition requirements as ASU 2014-09. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients . This standard amends ASU 2014-09 (discussed above) to provide additional guidance on (a) the objective of the collectibility criterion, (b) the presentation of sales tax collected from customers, (c) the measurement date of non-cash consideration received, (d) practical expedients in respect of contract modifications and completed contracts at transition, and (e) disclosure of the effects of the accounting change in the period of adoption. This standard will have the same effective date and transition requirements as ASU 2014-09. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. This standard is intended to provide guidance concerning the classification of certain cash receipts and cash payments in the statement of cash flows and to eliminate the diversity in practice related to such classifications. This standard is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2017, with early adoption permitted. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.
FAIR VALUE	FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES: GAAP establishes a hierarchy that prioritizes fair value measurements based on the types of inputs used for the various valuation techniques. The levels of the hierarchy are described below: • Level 1: Observable inputs, such as quoted prices in active markets for identical assets or liabilities. • Level 2: Inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly; these include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. • Level 3: Unobservable inputs that reflect the reporting entity’s own assumptions. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of financial assets and financial liabilities and their placement within the fair value hierarchy. (A) Available-for-Sale Securities include securities that are traded in active markets and securities that are not traded publicly. The securities traded in active markets are valued using the quoted principal market close prices that are provided by the trustees and are categorized in Level 1 in the fair value hierarchy. The remaining securities consist of funds that are not publicly traded. These funds, which consist of stocks and bonds that are traded individually in active markets, are valued using quoted prices for similar assets and are categorized in Level 2 in the fair value hierarchy. (B) Derivatives – Energy Related Assets and Liabilities are traded in both exchange-based and non-exchange-based markets. Exchange-based contracts are valued using unadjusted quoted market sources in active markets and are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based contracts are valued using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask mid-point prices and are obtained from sources that management believes provide the most liquid market. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. In instances where observable data is unavailable, management considers the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Significant Unobservable Inputs - Management uses the discounted cash flow model to value Level 3 physical and financial forward contracts, which calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return and credit spreads. Inputs to the valuation model are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third party pricing sources. The validity of the mark-to-market valuations and changes in mark-to-market valuations from period to period are examined and qualified against historical expectations by the risk management function. If any discrepancies are identified during this process, the mark-to-market valuations or the market pricing information is evaluated further and adjusted, if necessary. Level 3 valuation methods for natural gas derivative contracts include utilizing another location in close proximity adjusted for certain pipeline charges to derive a basis value. The significant unobservable inputs used in the fair value measurement of certain natural gas contracts consist of forward prices developed based on industry-standard methodologies. Significant increases (decreases) in these forward prices for purchases of natural gas would result in a directionally similar impact to the fair value measurement and for sales of natural gas would result in a directionally opposite impact to the fair value measurement. (C) Derivatives – Other, include interest rate swaps that are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

STOCK-BASED COMPENSATION PLANS

STOCK-BASED COMPENSATION PLANS (Tables)	9 Months Ended
	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of the SJI nonvested restricted stock awards pertaining to SJG outstanding at and the assumptions used to estimate the fair value of the awards	The following table summarizes the SJI nonvested restricted stock awards pertaining to SJG outstanding at September 30, 2016 , and the assumptions used to estimate the fair value of the awards: Grants Shares Outstanding Fair Value Per Share Expected Volatility Risk-Free Interest Rate 2014 - TSR 9,692 $ 21.31 20.0 % 0.80 % 2014 - EGR 9,692 $ 27.22 n/a n/a 2015 - TSR 6,884 $ 26.31 16.0 % 1.10 % 2015 - EGR, ROE, Time 15,211 $ 29.47 n/a n/a 2016 - TSR 11,472 $ 22.53 18.1 % 1.31 % 2016 - CEGR, Time 21,305 $ 23.52 n/a n/a
Summary of the information regarding restricted stock award activity excluding accrued dividend equivalents	The following table summarizes information regarding restricted stock award activity during the nine months ended September 30, 2016 , excluding accrued dividend equivalents: Shares Weighted Average Grant Date Fair Value Nonvested Shares Outstanding, January 1, 2016 46,475 $ 26.67 Granted 33,218 $ 23.17 Canceled / Forfeited (2,827 ) $ 25.89 Vested (2,610 ) 29.47 Nonvested Shares Outstanding, September 30, 2016 74,256 $ 25.04

REGULATORY ASSETS AND LIABILI25

REGULATORY ASSETS AND LIABILITIES (Tables)	9 Months Ended
	Sep. 30, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets	Regulatory Assets consisted of the following items (in thousands): September 30, 2016 December 31, 2015 Environmental Remediation Costs: Expended - Net $ 57,100 $ 42,032 Liability for Future Expenditures 160,587 123,194 Deferred Asset Retirement Obligation Costs 42,768 42,430 Deferred Pension and Other Postretirement Benefit Costs 79,779 79,779 Deferred Gas Costs - Net — 2,701 Conservation Incentive Program Receivable 23,485 2,624 Deferred Interest Rate Contracts (Note 11) 10,346 7,631 Energy Efficiency Tracker — 496 Pipeline Supplier Service Charges 2,527 3,776 Pipeline Integrity Cost 4,595 4,596 AFUDC - Equity Related Deferrals 12,357 11,423 Other Regulatory Assets 3,527 2,752 Total Regulatory Assets $ 397,071 $ 323,434
Schedule of Regulatory Liabilities	Regulatory Liabilities consisted of the following items (in thousands): September 30, 2016 December 31, 2015 Excess Plant Removal Costs $ 30,324 $ 32,644 Deferred Revenues-Net 14,418 — Societal Benefit Costs 5,907 10,197 Energy Efficiency Tracker 401 — Total Regulatory Liabilities $ 51,050 $ 42,841

RELATED-PARTY TRANSACTIONS (Tab

RELATED-PARTY TRANSACTIONS (Tables)	9 Months Ended
	Sep. 30, 2016
Related Party Transactions [Abstract]
Summary of related party transactions	A summary of related-party transactions, excluding pass-through items, included in Operating Revenues were as follows (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 Operating Revenues/Affiliates: SJRG $ 977 $ 1,100 $ 5,399 $ 2,631 Marina 86 116 292 483 Total Operating Revenue/Affiliates $ 1,063 $ 1,216 $ 5,691 $ 3,114 Related-party transactions, excluding pass-through items, included in Operating Expenses were as follows (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 Costs of Sales/Affiliates (Excluding depreciation) SJRG $ 490 $ 574 $ 9,993 $ 21,105 Energy-Related Derivative Losses / (Gains) * SJRG $ — $ — $ — $ 65 * Contracts used to hedge natural gas purchases. Included in Cost of Sales on the Condensed Statements of Income. Operations Expense/Affiliates: SJI $ 4,632 $ 3,248 $ 14,502 $ 10,529 Millennium 703 695 2,098 2,048 Other (48 ) (95 ) (154 ) (312 ) Total Operations Expense/Affiliates $ 5,287 $ 3,848 $ 16,446 $ 12,265

LINES OF CREDIT (Tables)

LINES OF CREDIT (Tables)	9 Months Ended
	Sep. 30, 2016
Line of Credit Facility [Abstract]
Summary of credit facilities and available liquidity	Credit facilities and available liquidity as of September 30, 2016 were as follows (in thousands): Total Facility Usage Available Liquidity Expiration Date Commercial Paper Program/ Revolving Credit Facility $ 200,000 $ 81,800 (A) $ 118,200 May 2018 Uncommitted Bank Lines 10,000 — 10,000 August 2017 Total $ 210,000 $ 81,800 (A) $ 128,200 (A) Includes letters of credit outstanding in the amount of $0.8 million .

PENSION AND OTHER POSTRETIREM28

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	9 Months Ended
	Sep. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Schedule of pension and other postretirement benefits	For the three and nine months ended September 30, 2016 and 2015 , net periodic benefit cost related to the employee and officer pension and other postretirement benefit plans consisted of the following components (in thousands): Pension Benefits Pension Benefits Three Months Ended Nine Months Ended 2016 2015 2016 2015 Service Cost $ 892 $ 996 $ 2,675 $ 2,988 Interest Cost 2,233 2,083 6,699 6,251 Expected Return on Plan Assets (2,488 ) (2,759 ) (7,463 ) (8,278 ) Amortizations: Prior Service Cost 39 40 117 119 Actuarial Loss 1,730 1,979 5,190 5,938 Net Periodic Benefit Cost 2,406 2,339 7,218 7,018 Capitalized Benefit Cost (1,251 ) (1,216 ) (3,651 ) (3,649 ) Deferred Benefit Cost (161 ) (341 ) (483 ) (666 ) Total Net Periodic Benefit Expense $ 994 $ 782 $ 3,084 $ 2,703 Other Postretirement Benefits Other Postretirement Benefits Three Months Ended Nine Months Ended 2016 2015 2016 2015 Service Cost $ 106 $ 186 $ 318 $ 558 Interest Cost 325 495 977 1,486 Expected Return on Plan Assets (386 ) (499 ) (1,159 ) (1,496 ) Amortizations: Prior Service Cost (43 ) 102 (129 ) 304 Actuarial Loss 138 224 414 671 Net Periodic Benefit Cost 140 508 421 1,523 Capitalized Benefit Cost (73 ) (264 ) (219 ) (792 ) Deferred Benefit Cost — (89 ) — (168 ) Total Net Periodic Benefit Expense $ 67 $ 155 202 563

FAIR VALUE OF FINANCIAL ASSET29

FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES (Tables)	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Fair value of assets and liabilities	For financial assets and financial liabilities measured at fair value on a recurring basis, information about the fair value measurements for each major category is as follows (in thousands): As of September 30, 2016 Total Level 1 Level 2 Level 3 Assets Available-for-Sale Securities (A) $ 9,260 $ 1,825 $ 7,435 $ — Derivatives – Energy Related Assets (B) 2,562 1,771 7 784 $ 11,822 $ 3,596 $ 7,442 $ 784 Liabilities Derivatives – Energy Related Liabilities (B) $ 3,349 $ 582 $ 2,489 $ 278 Derivatives – Other (C) 10,346 — 10,346 — $ 13,695 $ 582 $ 12,835 $ 278 As of December 31, 2015 Total Level 1 Level 2 Level 3 Assets Available-for-Sale Securities (A) $ 8,788 $ 1,722 $ 7,066 $ — Derivatives - Energy Related Assets (B) 1,141 398 144 599 $ 9,929 $ 2,120 $ 7,210 $ 599 Liabilities Derivatives - Energy Related Liabilities (B) $ 5,840 $ 5,424 $ — $ 416 Derivatives - Other (C) 7,631 — 7,631 — $ 13,471 $ 5,424 $ 7,631 $ 416 (A) Available-for-Sale Securities include securities that are traded in active markets and securities that are not traded publicly. The securities traded in active markets are valued using the quoted principal market close prices that are provided by the trustees and are categorized in Level 1 in the fair value hierarchy. The remaining securities consist of funds that are not publicly traded. These funds, which consist of stocks and bonds that are traded individually in active markets, are valued using quoted prices for similar assets and are categorized in Level 2 in the fair value hierarchy. (B) Derivatives – Energy Related Assets and Liabilities are traded in both exchange-based and non-exchange-based markets. Exchange-based contracts are valued using unadjusted quoted market sources in active markets and are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based contracts are valued using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask mid-point prices and are obtained from sources that management believes provide the most liquid market. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. In instances where observable data is unavailable, management considers the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Significant Unobservable Inputs - Management uses the discounted cash flow model to value Level 3 physical and financial forward contracts, which calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return and credit spreads. Inputs to the valuation model are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third party pricing sources. The validity of the mark-to-market valuations and changes in mark-to-market valuations from period to period are examined and qualified against historical expectations by the risk management function. If any discrepancies are identified during this process, the mark-to-market valuations or the market pricing information is evaluated further and adjusted, if necessary. Level 3 valuation methods for natural gas derivative contracts include utilizing another location in close proximity adjusted for certain pipeline charges to derive a basis value. The significant unobservable inputs used in the fair value measurement of certain natural gas contracts consist of forward prices developed based on industry-standard methodologies. Significant increases (decreases) in these forward prices for purchases of natural gas would result in a directionally similar impact to the fair value measurement and for sales of natural gas would result in a directionally opposite impact to the fair value measurement. (C) Derivatives – Other, include interest rate swaps that are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.
Quantitative information regarding significant unobservable inputs of assets in Level 3 fair value measurements	The following table provides quantitative information regarding significant unobservable inputs in Level 3 fair value measurements (in thousands): Type Fair Value at September 30, 2016 Valuation Technique Significant Unobservable Input Range Assets Liabilities Forward Contract - Natural Gas $784 $278 Discounted Cash Flow Forward price (per dt) $0.9 - $6.80 (A) Type Fair Value at December 31, 2015 Valuation Technique Significant Unobservable Input Range Assets Liabilities Forward Contract - Natural Gas $599 $416 Discounted Cash Flow Forward price (per dt) $1.18 - $5.21 (A) (A) Represents the range, along with the weighted average, of forward prices for the sale and purchase of natural gas.
Quantitative information regarding significant unobservable inputs of liabilities in Level 3 fair value measurements	The following table provides quantitative information regarding significant unobservable inputs in Level 3 fair value measurements (in thousands): Type Fair Value at September 30, 2016 Valuation Technique Significant Unobservable Input Range Assets Liabilities Forward Contract - Natural Gas $784 $278 Discounted Cash Flow Forward price (per dt) $0.9 - $6.80 (A) Type Fair Value at December 31, 2015 Valuation Technique Significant Unobservable Input Range Assets Liabilities Forward Contract - Natural Gas $599 $416 Discounted Cash Flow Forward price (per dt) $1.18 - $5.21 (A) (A) Represents the range, along with the weighted average, of forward prices for the sale and purchase of natural gas.
Changes in fair value of assets using significant unobservable inputs	The changes in fair value measurements of Derivatives - Energy Related Assets and Liabilities for the three and nine months ended September 30, 2016, using significant unobservable inputs (Level 3), are as follows (in thousands): Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016 Balance at beginning of period $ (224 ) $ 183 Other Changes in Fair Value from Continuing and New Contracts, Net 730 506 Settlements — (183 ) Balance at end of period 506 506 The changes in fair value measurements of Derivatives - Energy Related Assets and Liabilities for the three and nine months ended September 30, 2015, using significant unobservable inputs (Level 3), are as follows (in thousands): Three Months Ended September 30, 2015 Nine Months Ended September 30, 2015 Balance at beginning of period $ (584 ) $ — Other Changes in Fair Value from Continuing and New Contracts, Net 1,035 451 Balance at end of period 451 451

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value of derivative instruments	The fair values of all derivative instruments, as reflected in the condensed balance sheets as of September 30, 2016 and December 31, 2015 , are as follows (in thousands): Derivatives not designated as hedging instruments under GAAP September 30, 2016 December 31, 2015 Assets Liabilities Assets Liabilities Energy related commodity contracts: Derivatives – Energy Related – Current $ 2,281 $ 3,276 $ 1,077 $ 5,489 Derivatives – Energy Related – Non-Current 281 73 64 351 Interest rate contracts: Derivatives – Other Current — 535 — — Derivatives – Other Noncurrent — 9,811 — 7,631 Total derivatives not designated as hedging instruments under GAAP 2,562 13,695 1,141 13,471 Total Derivatives $ 2,562 $ 13,695 $ 1,141 $ 13,471
Offsetting assets	As of September 30, 2016 , and December 31, 2015 , information related to these offsetting arrangements were as follows (in thousands): As of September 30, 2016: Description Gross amounts of recognized assets/liabilities Gross amount offset in the balance sheet Net amounts of assets/liabilities in balance sheet Gross amounts not offset in the balance sheet Net amount Financial Instruments Cash Collateral Posted Derivatives - Energy Related Assets $ 2,562 $ — $ 2,562 $ (582 ) (A) $ (339 ) $ 1,641 Derivatives - Energy Related Liabilities (3,349 ) — (3,349 ) 582 (B) — (2,767 ) Derivatives - Other (10,346 ) — (10,346 ) — — (10,346 ) As of December 31, 2015: Description Gross amounts of recognized assets/liabilities Gross amount offset in the balance sheet Net amounts of assets/liabilities in balance sheet Gross amounts not offset in the balance sheet Net amount Financial Instruments Cash Collateral Posted Derivatives - Energy Related Assets $ 1,141 $ — $ 1,141 $ (399 ) (A) $ — $ 742 Derivatives - Energy Related Liabilities (5,840 ) — (5,840 ) 399 (B) 5,025 (416 ) Derivatives - Other (7,631 ) — (7,631 ) — — (7,631 ) (A) The balances at September 30, 2016 and December 31, 2015 were related to derivative liabilities which can be net settled against derivative assets. (B) The balances at September 30, 2016 and December 31, 2015 were related to derivative assets which can be net settled against derivative liabilities.
Offsetting liabilities	As of September 30, 2016 , and December 31, 2015 , information related to these offsetting arrangements were as follows (in thousands): As of September 30, 2016: Description Gross amounts of recognized assets/liabilities Gross amount offset in the balance sheet Net amounts of assets/liabilities in balance sheet Gross amounts not offset in the balance sheet Net amount Financial Instruments Cash Collateral Posted Derivatives - Energy Related Assets $ 2,562 $ — $ 2,562 $ (582 ) (A) $ (339 ) $ 1,641 Derivatives - Energy Related Liabilities (3,349 ) — (3,349 ) 582 (B) — (2,767 ) Derivatives - Other (10,346 ) — (10,346 ) — — (10,346 ) As of December 31, 2015: Description Gross amounts of recognized assets/liabilities Gross amount offset in the balance sheet Net amounts of assets/liabilities in balance sheet Gross amounts not offset in the balance sheet Net amount Financial Instruments Cash Collateral Posted Derivatives - Energy Related Assets $ 1,141 $ — $ 1,141 $ (399 ) (A) $ — $ 742 Derivatives - Energy Related Liabilities (5,840 ) — (5,840 ) 399 (B) 5,025 (416 ) Derivatives - Other (7,631 ) — (7,631 ) — — (7,631 ) (A) The balances at September 30, 2016 and December 31, 2015 were related to derivative liabilities which can be net settled against derivative assets. (B) The balances at September 30, 2016 and December 31, 2015 were related to derivative assets which can be net settled against derivative liabilities.
Derivatives in cash flow hedging relationships	The effect of derivative instruments on the condensed statements of income for the three and nine months ended September 30, 2016 and 2015 are as follows (in thousands): Three months ended Nine months ended Derivatives in Cash Flow Hedging Relationships 2016 2015 2016 2015 Interest Rate Contracts: Gains reclassified from Accumulated Other Comprehensive Loss into income (a) $ 12 $ 12 $ 36 $ 36 (a) Included in Interest Charges

ACCUMULATED OTHER COMPREHENSI31

ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Schedule of changes in accumulated other comprehensive loss (AOCL)	The changes in Accumulated Other Comprehensive Loss (AOCL) for the three and nine months ended September 30, 2016 are as follows (in thousands): Postretirement Liability Adjustment Unrealized Gain (Loss) on Derivatives-Other Unrealized Gain (Loss) on Available-for-Sale Securities Total Balance at July 1, 2016 (a) $ (12,220 ) $ (530 ) $ (91 ) $ (12,841 ) Other comprehensive loss before reclassifications — — 167 167 Amounts reclassified from AOCL (b) — 7 (129 ) (122 ) Net current period other comprehensive income — 7 38 45 Balance at September 30, 2016 (a) $ (12,220 ) $ (523 ) $ (53 ) $ (12,796 ) Postretirement Liability Adjustment Unrealized Gain (Loss) on Derivatives-Other Unrealized Gain (Loss) on Available-for-Sale Securities Total Balance at January 1, 2016 (a) $ (12,220 ) $ (544 ) $ (98 ) $ (12,862 ) Other comprehensive loss before reclassifications — — 304 304 Amounts reclassified from AOCL (b) — 21 (259 ) (238 ) Net current period other comprehensive income (loss) — 21 45 66 Balance at September 30, 2016 (a) $ (12,220 ) $ (523 ) $ (53 ) $ (12,796 ) (a) Determined using a combined average statutory tax rate of 40% . (b) See table below.
Reclassifications out of AOCL	The reclassifications out of AOCL during the three and nine months ended September 30, 2016 are as follows (in thousands): Components of AOCL Amounts Reclassified from AOCL Affected Line Item in the Condensed Statements of Income Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016 Unrealized Loss in on Derivatives - Other - Interest Rate Contracts designated as cash flow hedges $ 12 $ 36 Interest Charges Income Taxes (5 ) (15 ) Income Taxes (a) $ 7 $ 21 Unrealized Gain on Available-for-Sale Securities $ (217 ) $ (432 ) Other Income & Expense Income Taxes 88 173 Income Taxes (a) $ (129 ) $ (259 ) Gains from reclassifications for the period net of tax $ (122 ) $ (238 ) (a) Determined using a combined average statutory tax rate of 40% .

SUMMARY OF SIGNIFICANT ACCOUN32

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016USD ($)county	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)county	Sep. 30, 2015USD ($)
Accounting Policies [Abstract]
Number of counties in which entity operates | county	7		7
Amount of Public Utilities Assessment included in revenues and cost of sales | $	$ 0.2	$ 0.2	$ 0.7	$ 1

STOCK-BASED COMPENSATION PLAN33

STOCK-BASED COMPENSATION PLANS (Details) - USD ($) $ / shares in Units, $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Sep. 30, 2016
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Service period of shares	3 years
Granted (in shares)	33,218
Shares Outstanding (in shares)	46,475		46,475	74,256
Fair Value Per Share (in dollars per share)	$ 26.67		$ 26.67	$ 25.04
Expected volatility, measurement period	3 years
Unrecognized compensation cost of awards granted under the plan				$ 0.9
Weighted average period over which unrecognized compensation cost is to be recognized	1 year 11 months
Shares
Nonvested Shares Outstanding, beginning balance (in shares)	46,475
Granted (in shares)	33,218
Canceled / Forfeited (in shares)	(2,827)
Vested (in shares)	(2,610)
Nonvested Shares Outstanding, ending balance (in shares)	74,256		46,475
Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, beginning balance (in dollars per share)	$ 26.67
Granted (in dollars per share)	23.17
Canceled / Forfeited (in dollars per share)	25.89
Vested (in dollars per share)	29.47
Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 25.04		$ 26.67
Cash payments to SJI relating to stock awards	$ 0.2	$ 0.2
2014 - TSR
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	9,692			9,692
Fair Value Per Share (in dollars per share)	$ 21.31			$ 21.31
Expected Volatility	20.00%
Risk-Free Interest Rate	0.80%
Shares
Nonvested Shares Outstanding, ending balance (in shares)	9,692
Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 21.31
2014 - EGR
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	9,692			9,692
Fair Value Per Share (in dollars per share)	$ 27.22			$ 27.22
Shares
Nonvested Shares Outstanding, ending balance (in shares)	9,692
Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 27.22
2015 - TSR
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	6,884			6,884
Fair Value Per Share (in dollars per share)	$ 26.31			$ 26.31
Expected Volatility	16.00%
Risk-Free Interest Rate	1.10%
Shares
Nonvested Shares Outstanding, ending balance (in shares)	6,884
Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 26.31
2015 - EGR, ROE, Time
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	15,211			15,211
Fair Value Per Share (in dollars per share)	$ 29.47			$ 29.47
Shares
Nonvested Shares Outstanding, ending balance (in shares)	15,211
Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 29.47
2016 - TSR
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	11,472			11,472
Fair Value Per Share (in dollars per share)	$ 22.53			$ 22.53
Expected Volatility	18.10%
Risk-Free Interest Rate	1.31%
Shares
Nonvested Shares Outstanding, ending balance (in shares)	11,472
Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 22.53
2016 - CEGR, Time
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	21,305			21,305
Fair Value Per Share (in dollars per share)	$ 23.52			$ 23.52
Shares
Nonvested Shares Outstanding, ending balance (in shares)	21,305
Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 23.52
Officers and key employees | 2015 - Time
Weighted Average Grant Date Fair Value
Number of shares awarded during the period (in shares)	2,610
Fair value of shares issued	$ 0.1
Restricted stock
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Vesting period of shares			3 years
Payout limit			100.00%
Return on equity award threshold			7.00%
Cost of restricted stock awards	$ 0.2	$ 0.1
Cost of restricted stock awards, capitalized	50.00%	50.00%
Restricted stock | Officers and key employees
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Granted (in shares)	9,965	7,878
Shares
Granted (in shares)	9,965	7,878
Restricted stock | Year two
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Service period of shares			2 years
Restricted stock | Year three
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Service period of shares			3 years
Performance shares | 2012 and 2013 Grants
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Vesting period of shares	3 years
Weighted Average Grant Date Fair Value
Number of shares awarded during the period (in shares)	0		0
Minimum
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Percentage of actual amount of shares that ultimately vest of original share units granted	0.00%
Maximum
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Percentage of actual amount of shares that ultimately vest of original share units granted	200.00%

RATES AND REGULATORY ACTIONS (D

RATES AND REGULATORY ACTIONS (Details) - USD ($)	Oct. 01, 2016	Feb. 29, 2016	Sep. 30, 2016	Jun. 30, 2016	Apr. 30, 2016	Jan. 31, 2016	Oct. 31, 2015	Jun. 30, 2016
Storm Hardening and Reliability Program | Building
Schedule of Capitalization [Line Items]
Roll-in of investments								$ 33,700,000
New Jersey Board of Public Utilities
Schedule of Capitalization [Line Items]
Approved revenue increase (decrease)			$ (600,000)
Universal Service Fund			56,000,000
New Jersey Board of Public Utilities | Subsequent event
Schedule of Capitalization [Line Items]
Increase (decrease) in Universal Service Fund	$ 1,100,000
New Jersey Board of Public Utilities | New Jersey
Schedule of Capitalization [Line Items]
Universal Service Fund			5,600,000
New Jersey Board of Public Utilities | Transportation Initiation Clause
Schedule of Capitalization [Line Items]
Approved revenue increase (decrease)					$ 5,200,000
New Jersey Board of Public Utilities | Clean Energy Program
Schedule of Capitalization [Line Items]
Approved revenue increase (decrease)					(7,100,000)
New Jersey Board of Public Utilities | Tenants in Common
Schedule of Capitalization [Line Items]
Approved revenue increase (decrease)					(700,000)
New Jersey Board of Public Utilities | Storm Hardening and Reliability Program
Schedule of Capitalization [Line Items]
Approved revenue increase (decrease)			3,900,000
New Jersey Board of Public Utilities | Conservation Incentive Program
Schedule of Capitalization [Line Items]
Approved revenue increase (decrease)			46,500,000
Energy Efficiency Tracker
Schedule of Capitalization [Line Items]
Increase (decrease) in amount of regulatory costs approved		$ (7,900,000)
Requested revenue increase (decrease)				$ (800,000)
Energy Efficiency Tracker | New Jersey Board of Public Utilities
Schedule of Capitalization [Line Items]
Requested revenue increase (decrease)			(1,600,000)
Basic Gas Supply Service
Schedule of Capitalization [Line Items]
Credits to customers						$ 20,000,000
Approved rate reduction							10.30%
Basic Gas Supply Service | New Jersey Board of Public Utilities
Schedule of Capitalization [Line Items]
Approved revenue increase (decrease)			$ (47,100,000)
Accelerated Infrastructure Replacement Program
Schedule of Capitalization [Line Items]
Extension period of AIRP		7 years
Total amount of investment requested for approval		$ 500,000,000
Total amount of investment request for approval through the end of 2016		$ 76,000,000
Societal Benefits Clause
Schedule of Capitalization [Line Items]
Approved revenue increase (decrease)					$ (2,600,000)

REGULATORY ASSETS AND LIABILI35

REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 397,071	$ 323,434
Environmental Remediation Costs: Expended - Net
Regulatory Assets [Line Items]
Total Regulatory Assets	57,100	42,032
Environmental Remediation Costs: Liability for Future Expenditures
Regulatory Assets [Line Items]
Total Regulatory Assets	160,587	123,194
Deferred Asset Retirement Obligation Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	42,768	42,430
Deferred Pension and Other Postretirement Benefit Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	79,779	79,779
Deferred Gas Costs - Net
Regulatory Assets [Line Items]
Total Regulatory Assets	0	2,701
Conservation Incentive Program Receivable
Regulatory Assets [Line Items]
Total Regulatory Assets	23,485	2,624
Deferred Interest Rate Contracts (Note 11)
Regulatory Assets [Line Items]
Total Regulatory Assets	10,346	7,631
Energy Efficiency Tracker
Regulatory Assets [Line Items]
Total Regulatory Assets	0	496
Pipeline Supplier Service Charges
Regulatory Assets [Line Items]
Total Regulatory Assets	2,527	3,776
Pipeline Integrity Cost
Regulatory Assets [Line Items]
Total Regulatory Assets	4,595	4,596
AFUDC - Equity Related Deferrals
Regulatory Assets [Line Items]
Total Regulatory Assets	12,357	11,423
Other Regulatory Assets
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 3,527	$ 2,752

REGULATORY ASSETS AND LIABILI36

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 51,050	$ 42,841
Excess Plant Removal Costs
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	30,324	32,644
Deferred Revenues-Net
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	14,418	0
Societal Benefit Costs
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	5,907	10,197
Energy Efficiency Tracker
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 401	$ 0

REGULATORY ASSETS AND LIABILI37

REGULATORY ASSETS AND LIABILITIES - Narrative (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016USD ($)siteasset	Feb. 29, 2016USD ($)	Dec. 31, 2015USD ($)
Regulatory Assets [Line Items]
Number of sites for environmental cleanup | site	12
Regulatory assets	$ 397,071		$ 323,434
Regulatory Liabilities [Line Items]
Regulatory liabilities	51,050		42,841
Deferred Revenues - Net
Regulatory Liabilities [Line Items]
Regulatory liabilities	14,418		0
Energy Efficiency Tracker
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 401		0
Environmental Restoration Costs
Regulatory Assets [Line Items]
Number of regulatory assets associated with environmental costs | asset	2
Number of sites for environmental cleanup | site	12
Recovery period for expenditures	7 years
Deferred Revenues - Net
Regulatory Assets [Line Items]
Regulatory assets			2,700
Energy Efficiency Tracker
Regulatory Assets [Line Items]
Regulatory assets	$ 0		$ 496
Regulatory Liabilities [Line Items]
Increase (decrease) in amount of regulatory costs approved		$ (7,900)

RELATED-PARTY TRANSACTIONS (Det

RELATED-PARTY TRANSACTIONS (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Related Party Transaction [Line Items]
Operating Revenues/Affiliates	$ 1,063	$ 1,216	$ 5,691	$ 3,114
Total Operations Expense/Affiliates	5,287	3,848	16,446	12,265
SJRG
Related Party Transaction [Line Items]
Operating Revenues/Affiliates	977	1,100	5,399	2,631
Costs of Sales/Affiliates (Excluding depreciation)	490	574	9,993	21,105
Energy-Related Derivative Losses / (Gains)	0	0	0	65
Marina
Related Party Transaction [Line Items]
Operating Revenues/Affiliates	86	116	292	483
SJI
Related Party Transaction [Line Items]
Total Operations Expense/Affiliates	4,632	3,248	14,502	10,529
Millennium
Related Party Transaction [Line Items]
Total Operations Expense/Affiliates	703	695	2,098	2,048
Other
Related Party Transaction [Line Items]
Other	$ (48)	$ (95)	$ (154)	$ (312)

FINANCIAL INSTRUMENTS (Details)

FINANCIAL INSTRUMENTS (Details)	1 Months Ended	9 Months Ended
	Jun. 30, 2015USD ($)term	Sep. 30, 2016USD ($)	Dec. 31, 2015USD ($)
Schedule of Financial Instruments [Line Items]
Restricted investments held in escrow		$ 32,225	$ 32,225
Restricted investments, energy-related contracts		300,000	6,700,000
Estimated fair value of long-term debt		699,700,000	657,400,000
Carrying value of long-term debt		639,900,000	605,400,000
Unamortized debt issuance costs		6,100,000	6,600,000
Financing Receivable
Schedule of Financial Instruments [Line Items]
Long-term receivables, net of unamortized discount		10,200,000	12,900,000
Imputed interest		$ 1,000,000	$ 1,300,000
Financing Receivable | Minimum
Schedule of Financial Instruments [Line Items]
Term of receivable		5 years
Financing Receivable | Maximum
Schedule of Financial Instruments [Line Items]
Term of receivable		10 years
Atlantic City Note Receivable
Schedule of Financial Instruments [Line Items]
Amount of receivable	$ 10,000,000
Interest rate	1.00%
Term of receivable	6 months
Number of additional terms | term	2
Period of each additional term	3 months
Domestic
Schedule of Financial Instruments [Line Items]
Amount placed in escrow account		$ 8,300,000

LINES OF CREDIT (Details)

LINES OF CREDIT (Details)	9 Months Ended
	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Line of Credit Facility [Line Items]
Total Facility	$ 210,000,000
Usage	81,800,000
Available Liquidity	$ 128,200,000
Financial covenant, ratio of indebtedness to consolidated total capitalization (not more than)	0.65
Average borrowings outstanding	$ 64,500,000	$ 117,900,000
Maximum amounts outstanding	$ 141,700,000	$ 162,300,000
Weighted average borrowing cost	0.76%	0.40%
Revolving Credit Facility
Line of Credit Facility [Line Items]
Total Facility	$ 200,000,000
Usage	81,800,000
Available Liquidity	118,200,000
Letters of credit outstanding	800,000
Uncommitted Bank Lines
Line of Credit Facility [Line Items]
Total Facility	10,000,000
Usage	0
Available Liquidity	10,000,000
South Jersey Gas Commercial Paper Program
Line of Credit Facility [Line Items]
Total Facility	$ 200,000,000
Fixed maturities of notes, at maximum number of days (in days)	270 days

PENSION AND OTHER POSTRETIREM41

PENSION AND OTHER POSTRETIREMENT BENEFITS (Details) - USD ($)	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service Cost		$ 892,000	$ 996,000	$ 2,675,000	$ 2,988,000
Interest Cost		2,233,000	2,083,000	6,699,000	6,251,000
Expected Return on Plan Assets		(2,488,000)	(2,759,000)	(7,463,000)	(8,278,000)
Amortizations:
Prior Service Cost		39,000	40,000	117,000	119,000
Actuarial Loss		1,730,000	1,979,000	5,190,000	5,938,000
Net Periodic Benefit Cost		2,406,000	2,339,000	7,218,000	7,018,000
Capitalized Benefit Cost		(1,251,000)	(1,216,000)	(3,651,000)	(3,649,000)
Deferred Benefit Cost		(161,000)	(341,000)	(483,000)	(666,000)
Total Net Periodic Benefit Expense		994,000	782,000	3,084,000	2,703,000
Contributions	$ 12,000,000			0
Estimated future contributions				0
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service Cost		106,000	186,000	318,000	558,000
Interest Cost		325,000	495,000	977,000	1,486,000
Expected Return on Plan Assets		(386,000)	(499,000)	(1,159,000)	(1,496,000)
Amortizations:
Prior Service Cost		(43,000)	102,000	(129,000)	304,000
Actuarial Loss		138,000	224,000	414,000	671,000
Net Periodic Benefit Cost		140,000	508,000	421,000	1,523,000
Capitalized Benefit Cost		(73,000)	(264,000)	(219,000)	(792,000)
Deferred Benefit Cost		0	(89,000)	0	(168,000)
Total Net Periodic Benefit Expense		$ 67,000	$ 155,000	202,000	$ 563,000
Defined benefit plan regulatory obligation to contribute to the plan during the period				3,600,000
Supplemental Employee Retirement Plans, Defined Benefit
Amortizations:
Estimated future contributions				$ 2,200,000

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Details)	9 Months Ended
	Sep. 30, 2016USD ($)siteunion	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Letter of credit provided	$ 210,000,000
Number of sites for environmental cleanup | site	12
Monthly gas supply related demand charges and reservation fees	$ 5,800,000
Estimated litigation liability	$ 700,000	$ 800,000
Percentage of personnel represented in collective bargaining agreements	61.00%
Number of unions | union	2
Pending litigation
Loss Contingencies [Line Items]
Amount claimed to be owed	$ 14,300,000
Standby Letter of Credit
Loss Contingencies [Line Items]
Letter of credit provided	25,200,000
Revolving Credit Facility
Loss Contingencies [Line Items]
Letters of credit outstanding	800,000
Letter of credit provided	$ 200,000,000

FAIR VALUE OF FINANCIAL ASSET43

FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES - Measured on a Recurring Basis (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Assets
Available-for-sale Securities	$ 9,260	$ 8,788
Derivatives - Energy Related Assets	2,562	1,141
Total Assets	11,822	9,929
Liabilities
Derivatives - Energy Related Liabilities	3,349	5,840
Derivatives - Other	10,346	7,631
Total Liabilities	13,695	13,471
Level 1
Assets
Available-for-sale Securities	1,825	1,722
Derivatives - Energy Related Assets	1,771	398
Total Assets	3,596	2,120
Liabilities
Derivatives - Energy Related Liabilities	582	5,424
Derivatives - Other	0	0
Total Liabilities	582	5,424
Level 2
Assets
Available-for-sale Securities	7,435	7,066
Derivatives - Energy Related Assets	7	144
Total Assets	7,442	7,210
Liabilities
Derivatives - Energy Related Liabilities	2,489	0
Derivatives - Other	10,346	7,631
Total Liabilities	12,835	7,631
Level 3
Assets
Available-for-sale Securities	0	0
Derivatives - Energy Related Assets	784	599
Total Assets	784	599
Liabilities
Derivatives - Energy Related Liabilities	278	416
Derivatives - Other	0	0
Total Liabilities	$ 278	$ 416

FAIR VALUE OF FINANCIAL ASSET44

FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES - Quantitative Information Regarding Unobservable Inputs (Details) - Level 3 - Natural Gas - Forward Contracts $ in Thousands	Sep. 30, 2016USD ($)$ / decatherm	Dec. 31, 2015USD ($)$ / decatherm
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative asset | $	$ 784	$ 599
Derivative liability | $	$ 278	$ 416
Minimum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward price (in dollars per dt)	0.9	1.18
Maximum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward price (in dollars per dt)	6.80	5.21
Weighted Average
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward price (in dollars per dt)	4.24	2.90

FAIR VALUE OF FINANCIAL ASSET45

FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES - Changes in Measurements (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ (224)	$ (584)	$ 183	$ 0
Other Changes in Fair Value from Continuing and New Contracts, Net	730	1,035	506	451
Settlements	0		(183)
Balance at end of period	$ 506	$ 451	$ 506	$ 451

DERIVATIVE INSTRUMENTS - Narrat

DERIVATIVE INSTRUMENTS - Narrative (Details) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2005USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)MMcfe	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Derivative [Line Items]
Unrealized gains (losses) included in its BGSS related to open financial contracts | $		$ 0.8		$ 0.8		$ 4.7
Initial cost of Treasury Locks | $	$ 1.4
Amortization period of Treasury Locks	30 years
Unamortized balance of Treasury Locks | $		0.9		0.9		$ 0.9
Net realized gains (losses), derivative instruments, energy-related contracts | $		$ 0.9	$ (1.6)	$ (3.5)	$ (6.4)
Basis and Index Related Purchase and Sales Contracts
Derivative [Line Items]
Notional amount (in mmcfe)				4,400
Basis and Index Related Purchase Contracts
Derivative [Line Items]
Notional amount (in mmcfe)				4,600
Basis and Index Related Sales Contracts
Derivative [Line Items]
Notional amount (in mmcfe)				9,000
Derivative Transaction Type, Purchase
Derivative [Line Items]
Notional amount (in mmcfe)				8,700
Derivative Transaction Type, Sale
Derivative [Line Items]
Notional amount (in mmcfe)				600

DERIVATIVE INSTRUMENTS - Fair V

DERIVATIVE INSTRUMENTS - Fair Value (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Assets	$ 2,562	$ 1,141
Liabilities	13,695	13,471
Commodity Contract
Derivatives, Fair Value [Line Items]
Assets	2,562	1,141
Liabilities	0	0
Derivatives not designated as hedging instruments under GAAP
Derivatives, Fair Value [Line Items]
Assets	2,562	1,141
Liabilities	13,695	13,471
Derivatives not designated as hedging instruments under GAAP | Commodity Contract | Derivatives – Energy Related – Current
Derivatives, Fair Value [Line Items]
Assets	2,281	1,077
Liabilities	3,276	5,489
Derivatives not designated as hedging instruments under GAAP | Commodity Contract | Derivatives – Energy Related – Non-Current
Derivatives, Fair Value [Line Items]
Assets	281	64
Liabilities	73	351
Derivatives not designated as hedging instruments under GAAP | Interest Rate Contract | Derivatives – Other Current
Derivatives, Fair Value [Line Items]
Assets	0	0
Liabilities	535	0
Derivatives not designated as hedging instruments under GAAP | Interest Rate Contract | Derivatives – Other Noncurrent
Derivatives, Fair Value [Line Items]
Assets	0	0
Liabilities	$ 9,811	$ 7,631

DERIVATIVE INSTRUMENTS - Offset

DERIVATIVE INSTRUMENTS - Offsetting Arrangements (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized assets/liabilities	$ 2,562	$ 1,141
Offsetting Derivative Liabilities [Abstract]
Gross amount offset in the balance sheet	13,695	13,471
Commodity Contract
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized assets/liabilities	2,562	1,141
Gross amount offset in the balance sheet	0	0
Net amounts of assets/liabilities in balance sheet	2,562	1,141
Gross amounts not offset in the balance sheet, Financial Instruments	(582)	(399)
Gross amounts not offset in the balance sheet, Cash Collateral Posted	(339)	0
Net amount	1,641	742
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets/liabilities	(3,349)	(5,840)
Gross amount offset in the balance sheet	0	0
Net amounts of assets/liabilities in balance sheet	(3,349)	(5,840)
Gross amounts not offset in the balance sheet, Financial Instruments	582	399
Gross amounts not offset in the balance sheet, Cash Collateral Posted	0	5,025
Net amount	(2,767)	(416)
Derivatives - Other
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets/liabilities	(10,346)	(7,631)
Gross amount offset in the balance sheet	0	0
Net amounts of assets/liabilities in balance sheet	(10,346)	(7,631)
Gross amounts not offset in the balance sheet, Financial Instruments	0	0
Gross amounts not offset in the balance sheet, Cash Collateral Posted	0	0
Net amount	$ (10,346)	$ (7,631)

DERIVATIVE INSTRUMENTS - Effect

DERIVATIVE INSTRUMENTS - Effect on the Condensed Statements of Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gains reclassified from Accumulated Other Comprehensive Loss into income	$ 12	$ 12	$ 36	$ 36

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($)	1 Months Ended			9 Months Ended
	Aug. 31, 2016	Jul. 31, 2016	Jan. 31, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Proceeds from issuance of long term debt				$ 61,000,000	$ 80,000,000
Line of credit, maximum borrowing capacity				210,000,000
Long-term debt				639,900,000		$ 605,400,000
Medium-term notes | Medium-term notes, 4.60%
Debt Instrument [Line Items]
Extinguishment of Debt, Amount		$ 17,000,000
Debt Instrument, Interest Rate, Stated Percentage		4.60%
Medium-term notes | Medium-term notes, 5.437%
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 10,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.437%
Line of Credit | Loans payable
Debt Instrument [Line Items]
Proceeds from issuance of long term debt			$ 61,000,000
Interest rate (as percent)			1.37%
Line of credit, maximum borrowing capacity			$ 200,000,000
Long-term debt				$ 200,000,000

ACCUMULATED OTHER COMPREHENSI51

ACCUMULATED OTHER COMPREHENSIVE LOSS (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance				$ 707,927
Other comprehensive loss before reclassifications		$ 167		304
Amounts reclassified from AOCL		(122)		(238)
Other Comprehensive Income (Loss) - Net of Tax	[1]	45	$ (92)	66	$ (66)
Ending balance		$ 819,139		$ 819,139
Combined statutory tax rate		40.00%	40.00%	40.00%	40.00%
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance		$ (12,841)		$ (12,862)
Ending balance		(12,796)		(12,796)
Postretirement Liability Adjustment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance		(12,220)		(12,220)
Other comprehensive loss before reclassifications		0		0
Amounts reclassified from AOCL		0		0
Other Comprehensive Income (Loss) - Net of Tax		0		0
Ending balance		(12,220)		(12,220)
Unrealized Gain (Loss) on Derivatives-Other
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance		(530)		(544)
Other comprehensive loss before reclassifications		0		0
Amounts reclassified from AOCL		7		21
Other Comprehensive Income (Loss) - Net of Tax		7		21
Ending balance		(523)		(523)
Unrealized Gain (Loss) on Available-for-Sale Securities
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance		(91)		(98)
Other comprehensive loss before reclassifications		167		304
Amounts reclassified from AOCL		(129)		(259)
Other Comprehensive Income (Loss) - Net of Tax		38		45
Ending balance		$ (53)		$ (53)
[1]	Determined using a combined average statutory tax rate of 40%.

ACCUMULATED OTHER COMPREHENSI52

ACCUMULATED OTHER COMPREHENSIVE LOSS - RECLASSIFICATIONS OUT OF AOCL (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Income Taxes	$ (2,007)	$ (2,871)	$ 26,812	$ 26,593
(Gains) losses from reclassifications for the period net of tax	3,315	$ 3,429	(46,146)	$ (44,384)
Gains from reclassifications for the period net of tax	$ (122)		$ (238)
Combined statutory tax rate	40.00%	40.00%	40.00%	40.00%
Unrealized Loss in on Derivatives - Other - Interest Rate Contracts designated as cash flow hedges
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Gains from reclassifications for the period net of tax	$ 7		$ 21
Unrealized Gain (Loss) on Available-for-Sale Securities
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Gains from reclassifications for the period net of tax	(129)		(259)
Amounts Reclassified from AOCL | Unrealized Loss in on Derivatives - Other - Interest Rate Contracts designated as cash flow hedges
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Income Taxes	(5)		(15)
(Gains) losses from reclassifications for the period net of tax	7		21
Amounts Reclassified from AOCL | Unrealized Loss in on Derivatives - Other - Interest Rate Contracts designated as cash flow hedges | Interest Rate Contract
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Interest Charges	12		36
Amounts Reclassified from AOCL | Unrealized Gain (Loss) on Available-for-Sale Securities
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Income & Expense	(217)		(432)
Income Taxes	88		173
(Gains) losses from reclassifications for the period net of tax	$ (129)		$ (259)

OTHER PAID IN CAPITAL (Details)

OTHER PAID IN CAPITAL (Details) - USD ($) $ in Thousands	1 Months Ended	9 Months Ended
	Jun. 30, 2016	Sep. 30, 2016	Sep. 30, 2015
Equity [Abstract]
Additional investment from SJI	$ 65,000	$ 65,000	$ 0

SUBSEQUENT EVENT (Details)

SUBSEQUENT EVENT (Details) - New Jersey Board of Public Utilities - USD ($)	1 Months Ended	9 Months Ended
	Oct. 31, 2016	Sep. 30, 2016
Subsequent Event [Line Items]
Base rate		$ 11,000,000
Remaining balance of prior AIRP investments		$ 74,500,000
Subsequent event
Subsequent Event [Line Items]
Approved request to extend Accelerated Infrastructure Replacement Program (AIRP) (up to)	5 years
Authorized investment for AIRP	$ 302,500,000