10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended September 30, 2015

OR

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

For the transition period from ________________ to ________________

Commission File Number 000-22211

SOUTH JERSEY GAS COMPANY

(Exact name of registrant as specified in its charter)

New Jersey	21-0398330
(State of incorporation)	(IRS employer identification no.)

1 South Jersey Plaza, Folsom, NJ 08037

(Address of principal executive offices, including zip code)

(609) 561-9000

(Registrant's telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x      No o

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

Large accelerated filer o	Accelerated filer o
Non-accelerated filer x (Do not check if a smaller reporting company)	Smaller reporting company o

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

As of November 2, 2015 there were 2,339,139 shares of the registrant’s common stock outstanding. All common shares are owned by South Jersey Industries, Inc., the parent company of South Jersey Gas Company.

TABLE OF CONTENTS

		Page No.
PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements	3
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	34
PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 6.	Exhibits	35
Signatures		36

2

SOUTH JERSEY GAS COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

(In Thousands)

	Three Months Ended
	September 30,
	2015			2014
Operating Revenues	$	58,634		$	60,952
Operating Expenses:
Cost of Sales (Excluding depreciation)	22,934			23,400
Operations	22,786			20,769
Maintenance	4,188			3,275
Depreciation	10,421			9,342
Energy and Other Taxes	806			798
Total Operating Expenses	61,135			57,584
Operating (Loss) Income	(2,501		)	3,368
Other Income and Expense	1,010			2,186
Interest Charges	(4,809		)	(4,046		)
Income (Loss) Before Income Taxes	(6,300		)	1,508
Income Taxes	2,871			(534		)
Net (Loss) Income	$	(3,429	)	$	974

The accompanying notes are an integral part of the unaudited condensed financial statements.

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	Nine Months Ended
	September 30,
	2015			2014
Operating Revenues	$	402,104		$	340,656
Operating Expenses:
Cost of Sales (Excluding depreciation)	194,455			151,572
Operations	80,083			73,181
Maintenance	12,114			9,715
Depreciation	29,723			27,562
Energy and Other Taxes	3,080			2,813
Total Operating Expenses	319,455			264,843
Operating Income	82,649			75,813
Other Income and Expense	3,440			4,749
Interest Charges	(15,112		)	(12,680		)
Income Before Income Taxes	70,977			67,882
Income Taxes	(26,593		)	(25,440		)
Net Income	$	44,384		$	42,442

The accompanying notes are an integral part of the unaudited condensed financial statements.

4

SOUTH JERSEY GAS COMPANY

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(In Thousands)

	Three Months Ended
	September 30,
	2015			2014
Net (Loss) Income	$	(3,429	)	$	974
Other Comprehensive (Loss) Gain - Net of Tax: *
Unrealized Loss on Available-for-Sale Securities	(98		)	(613		)
Unrealized Gain on Derivatives - Other	6			6
Other Comprehensive Loss - Net of Tax *	(92		)	(607		)
Comprehensive (Loss) Income	$	(3,521	)	$	367

	Nine Months Ended
	September 30,
	2015			2014
Net Income	$	44,384		$	42,442
Other Comprehensive Loss - Net of Tax: *
Unrealized Loss on Available-for-Sale Securities	(81		)	(397		)
Unrealized Gain on Derivatives - Other	15			21
Other Comprehensive Loss - Net of Tax *	(66		)	(376		)
Comprehensive Income	$	44,318		$	42,066

* Determined using a combined average statutory tax rate of 40% and 41% in 2015 and 2014, respectively.

The accompanying notes are an integral part of the unaudited condensed financial statements.

5

SOUTH JERSEY GAS COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In Thousands)

	Nine Months Ended
	September 30,
	2015			2014
Net Cash Provided by Operating Activities	$	124,750		$	55,242
Cash Flows from Investing Activities:
Capital Expenditures	(147,276		)	(139,393		)
Note Receivable	(9,919		)	—
Net Sale (Purchase) of Restricted Investments in Margin Accounts	1,603			(1,391		)
Net Sale of Restricted Investments from Escrowed Loan Proceeds	101			—
Investment in Long-Term Receivables	(13,784		)	(4,881		)
Proceeds from Long-Term Receivables	6,556			5,075
Net Cash Used in Investing Activities	(162,719		)	(140,590		)
Cash Flows from Financing Activities:
Net Repayments of Short-Term Credit Facilities	(12,100		)	(6,200		)
Proceeds from Issuance of Long-Term Debt	80,000			89,000
Principal Repayments of Long-Term Debt	(10,100		)	(21,000		)
Payments for Issuance of Long-Term Debt	(8		)	(627		)
Dividends on Common Stock	(19,782		)	—
Additional Investment by Shareholder	—			25,000
Net Cash Provided by Financing Activities	38,010			86,173
Net Increase in Cash and Cash Equivalents	41			825
Cash and Cash Equivalents at Beginning of Period	1,778			2,020
Cash and Cash Equivalents at End of Period	$	1,819		$	2,845

The accompanying notes are an integral part of the unaudited condensed financial statements.

6

SOUTH JERSEY GAS COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

(In Thousands)

	September 30, 2015			December 31, 2014
Assets
Property, Plant and Equipment:
Utility Plant, at original cost	$	2,151,526		$	2,002,966
Accumulated Depreciation	(431,327		)	(413,597		)
Property, Plant and Equipment - Net	1,720,199			1,589,369
Investments:
Available-for-Sale Securities	8,528			8,894
Restricted Investments	6,257			7,961
Total Investments	14,785			16,855
Current Assets:
Cash and Cash Equivalents	1,819			1,778
Note Receivable	9,919			—
Accounts Receivable	81,965			60,535
Accounts Receivable - Related Parties	958			1,157
Unbilled Revenues	10,473			49,910
Provision for Uncollectibles	(9,761		)	(6,601		)
Natural Gas in Storage, average cost	16,557			25,325
Materials and Supplies, average cost	955			1,104
Deferred Income Taxes - Net	40,006			44,064
Prepaid Taxes	16,656			13,601
Derivatives - Energy Related Assets	1,273			2,051
Other Prepayments and Current Assets	11,494			3,688
Total Current Assets	182,314			196,612
Regulatory and Other Noncurrent Assets:
Regulatory Assets	339,192			357,160
Unamortized Debt Issuance Costs	6,810			7,382
Long-Term Receivables	22,330			15,223
Other	2,673			3,071
Total Regulatory and Other Noncurrent Assets	371,005			382,836
Total Assets	$	2,288,303		$	2,185,672

The accompanying notes are an integral part of the unaudited condensed financial statements.

7

SOUTH JERSEY GAS COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

(In Thousands, except per share amounts)

	September 30, 2015			December 31, 2014
Capitalization and Liabilities
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	250,899			250,899
Accumulated Other Comprehensive Loss	(14,545		)	(14,479		)
Retained Earnings	462,902			438,300
Total Common Equity	705,104			680,568
Long-Term Debt	584,991			507,091
Total Capitalization	1,290,095			1,187,659
Current Liabilities:
Notes Payable	89,300			101,400
Current Portion of Long-Term Debt	27,909			35,909
Accounts Payable - Commodity	11,789			22,359
Accounts Payable - Other	41,088			32,711
Accounts Payable - Related Parties	6,338			11,249
Derivatives - Energy Related Liabilities	6,072			6,305
Customer Deposits and Credit Balances	20,023			17,626
Environmental Remediation Costs	44,042			28,480
Taxes Accrued	1,693			1,177
Pension Benefits	1,515			1,515
Interest Accrued	4,851			6,099
Other Current Liabilities	3,779			6,580
Total Current Liabilities	258,399			271,410
Regulatory and Other Noncurrent Liabilities:
Regulatory Liabilities	62,461			41,899
Deferred Income Taxes - Net	451,451			435,022
Environmental Remediation Costs	81,424			95,828
Asset Retirement Obligations	42,516			41,976
Pension and Other Postretirement Benefits	86,552			95,241
Investment Tax Credits	37			149
Derivatives - Energy Related Liabilities	397			1,298
Derivatives - Other	7,918			7,325
Other	7,053			7,865
Total Regulatory and Other Noncurrent Liabilities	739,809			726,603
Commitments and Contingencies (Note 9)
Total Capitalization and Liabilities	$	2,288,303		$	2,185,672

The accompanying notes are an integral part of the unaudited condensed financial statements.

8

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

1. 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, 2014 for a more complete discussion of our accounting policies and certain other information.

REVENUE AND THROUGHPUT - BASED TAXES - SJG collects certain revenue-based energy taxes from its customers. Such taxes include 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 each of the three month-periods ended September 30, 2015 and 2014, and $1.0 million and $0.8 million for the nine months ended September 30, 2015 and 2014, respectively.

NEW ACCOUNTING PRONOUNCEMENTS — Other than as described below, no new accounting pronouncement issued or effective during 2015 or 2014 had, or is 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 is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

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 February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis, which changes the analysis to be performed in determining whether certain types of legal entities should be consolidated. Specifically, the standard amends the evaluation of whether (a) fees paid to a decision maker or service providers represent a variable interest, (b) a limited partnership or similar entity has the characteristics of a Variable Interest Entity ("VIE") and (c) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods within those annual periods, 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 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. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

9

Also in April 2015, the FASB issued ASU 2015-5, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40). This ASU provides guidance to customers (1) in determining whether a cloud computing arrangement includes a software license, and (2) on how the arrangement should be accounted for, depending on whether or not it includes a software license. The amended guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

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 August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This ASU states that, given the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements within ASU 2015-03 (defined above), the SEC staff would not object to an entity deferring and presenting such costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of credit arrangement. The adoption of this standard did not have an impact on the companies financial statement results.

2. STOCK-BASED COMPENSATION PLANS:

Officers and other key employees of SJG participate in the stock-based compensation plans (collectively, the Plan) of SJI. Restricted performance-based shares issued under the Plan vest over a three-year period and are subject to SJI achieving certain market or earnings-based performance targets as compared to a peer group average, which can cause the actual amount of shares that ultimately vest to range from 0% to 200% of the original share units granted. In 2015, SJI also granted time-based shares of restricted stock, one-third of which vests annually over a three-year period and is limited to 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. In 2015, SJG officers and other key employees were granted 7,878 shares of time-based restricted stock.

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 per share (EPS) growth rate relative to a peer group to measure performance. Beginning in 2015, earning-based performance targets include predefined EPS and return on equity (ROE) goals to measure performance. As EPS-based and ROE-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 Plan, our expense recognition policy has been consistent with the expense recognition policy at SJI.

10

The following table summarizes the SJI nonvested restricted stock awards pertaining to SJG outstanding at September 30, 2015, 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
2013 - TSR	7,974	$	22.19	21.1	%	0.40	%
2013 - EPS	7,974	$	25.59	n/a		n/a
2014 - TSR	10,287	$	21.31	20.0	%	0.80	%
2014 - EPS	10,287	$	27.22	n/a		n/a
2015 - TSR	7,250	$	26.31	16.0	%	1.10	%
2015 - EPS, ROE, Time	18,651	$	29.47	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 2015 and 2014 is approximately $0.1 million per quarter. Of these costs, approximately one half was capitalized to Utility Plant.

As of September 30, 2015, there was $0.8 million of total unrecognized compensation cost related to nonvested share-based compensation awards granted under the Plan. 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, 2015, excluding accrued dividend equivalents:

	Shares		Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, January 1, 2015	36,794		$	24.10
Granted	26,266		$	28.58
Canceled / Forfeited	(637	)	26.71
Nonvested Shares Outstanding, September 30, 2015	62,423		$	25.96

Performance targets during the three-year vesting periods were not attained for the January 2011 grant that vested at December 31, 2013, or the January 2012 grant that vested at December 31, 2014. As a result, no shares were awarded in 2014 or 2015. 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, 2015 and 2014 were approximately $0.2 million and $0.4 million, respectively, relating to stock awards. Additionally, a change in control could result in the nonvested shares becoming nonforfeitable or immediately payable in cash.

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3. RATES AND REGULATORY ACTIONS:

SJG is subject to the rules and regulations of the New Jersey Board of Public Utilities (BPU).

In May 2015, the BPU approved an $18.2 million decrease in annual revenues collected from customers through the Societal Benefits Clause ("SBC") charge and the Transportation Initiation Clause ("TIC") charge, comprised of a $6.2 million decrease in revenues from the Remediation Adjustment Clause (“RAC”) component of the SBC, an $11.5 million decrease in revenues from the Clean Energy Program (“CLEP”) component of the SBC and a $0.5 million decrease in TIC revenues, effective June 1, 2015. The decreases in the RAC and CLEP components of the SBC are primarily driven by the accumulation of prior year over-recoveries, as rate recovery exceeded program costs. The decrease in the TIC is being caused by a decrease in costs. The SBC and TIC allow SJG to recover costs associated with certain State-mandated programs.

In June 2015, SJG filed its annual Energy Efficiency Tracker (“EET”) rate adjustment petition, requesting a $7.6 million decrease in revenues to continue recovering the costs of, and the allowed return on, prior investments associated with energy efficiency programs ("EEPs"). SJG's original EEPs, approved by the BPU in 2009, and its EEP extension, approved by the BPU in 2013, ended in July 2013 and June 2015, respectively. The revenue requirements associated with these prior investments decrease over time as they are amortized and recovered. Also contributing to the revenue decrease is the forecasted October 2015 over-recovery of $1.7 million, which further reduces the revenue requirement for the upcoming EET year. This petition is currently pending.

In August 2015, the BPU approved a two year extension of the Company’s EEPs through August 31, 2017, with a program budget of $36.3 million. SJG will recover the costs of these programs, and earn an allowed return on its investments, through the EET rate recovery mechanism that has been utilized for its EEPs since 2009. The BPU’s approval also permitted SJG to adjust its EET rate effective September 1, 2015 to increase annual revenues by $2.6 million to recover the projected costs of, and the allowed return on, the first year of its investments in the EEPs.

In September 2015, the BPU approved SJG’s request, related to its Storm Hardening and Reliability Program (“SHARP”), to increase annual revenues from base rates by $4.0 million to reflect approximately $36.6 million of investments made for storm hardening efforts for the period July 2014 through June 2015. This base rate adjustment became effective on October 1, 2015.

Also in September 2015, the BPU approved the Company’s annual Basic Gas Supply Service (“BGSS”) and Conservation Incentive Program (“CIP”) rate adjustment petition, which requested a $39.7 million decrease in annual revenues to be implemented on October 1, 2015, comprised of a $28.4 million decrease in BGSS revenues and an $11.3 million decrease in CIP revenues. The level of BGSS revenues is based on forecasted gas costs and customer usage information for the upcoming BGSS/CIP year, which runs from October to September. SJG’s request is based on decreases in forecasted gas commodity costs for the upcoming BGSS/CIP year. The decrease in CIP revenues is caused primarily by higher than normal customer usage caused by weather that was 10.4% colder than normal during the 2014-2015 winter season.

Additionally, in September 2015, the BPU approved the statewide Universal Service Fund (“USF”) budget of $46.4 million for all the State’s gas utilities. SJG’s portion of the total budget is approximately $5.2 million. Effective October 1, 2015, the BPU approved a $3.4 million decrease to SJG’s USF recoveries.

The BGSS, CIP and USF revenue decreases noted above do not impact SJG's earnings. They represent decreases in the cash requirements of the Company corresponding to lower costs and/or the return of previously over-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, 2014. See Note 3 to the Financial Statements in Item 8 of SJG's Form 10-K for the year ended December 31, 2014.

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4. REGULATORY ASSETS AND LIABILITIES:

There have been no significant changes to the nature of SJG’s regulatory assets and liabilities since December 31, 2014, 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, 2014.

Regulatory Assets consisted of the following items (in thousands):

	September 30, 2015		December 31, 2014
Environmental Remediation Costs:
Expended - Net	$	32,797	$	29,540
Liability for Future Expenditures	125,466		124,308
Deferred Asset Retirement Obligation Costs	31,976		31,584
Deferred Pension and Other Postretirement Benefit Costs	99,040		99,040
Deferred Gas Costs - Net	19,187		32,202
Societal Benefit Costs Receivable	—		385
Deferred Interest Rate Contracts (Note 11)	7,918		7,325
Energy Efficiency Tracker	545		11,247
Pipeline Supplier Service Charges	4,192		5,441
Pipeline Integrity Cost	4,544		3,431
AFUDC - Equity Related Deferrals	11,188		10,781
Other Regulatory Assets	2,339		1,876
Total Regulatory Assets	$	339,192	$	357,160

DEFERRED GAS COSTS - NET - Over/under collections of gas costs are monitored through SJG's Basic Gas Supply Service (BGSS) mechanism. Net undercollected gas costs are classified as a regulatory asset and net overcollected 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 reduction in deferred gas costs from December 31, 2014 was due to gas costs recovered from customers exceeding the actual cost of the commodity incurred during 2015 as a result of lower natural gas prices and an increase in the BGSS rate effective October 2014. SJG's BGSS mechanism is designed to overcollect gas costs during the winter season when usage is highest.

ENERGY EFFICIENCY TRACKER - This regulatory asset primarily represents energy efficiency measures installed in customer homes and businesses. The decrease from December 31, 2014 is due to higher recoveries in the first nine months of 2015 resulting from extremely cold weather during the first half of the year.

Regulatory Liabilities consisted of the following items (in thousands):

	September 30, 2015		December 31, 2014
Excess Plant Removal Costs	$	34,040	$	35,940
Conservation Incentive Program Payable	18,616		4,700
Societal Benefit Costs	9,805		—
Other Regulatory Liabilities	—		1,259
Total Regulatory Liabilities	$	62,461	$	41,899

EXCESS PLANT REMOVAL COSTS - Represents amounts accrued in excess of actual utility plant removal costs incurred to date. The decrease in the balance from year end is due to an amortization as a credit to depreciation expense, as required as part of our September 2014 base rate increase.

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CONSERVATION INCENTIVE PROGRAM (CIP) PAYABLE – 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 greater than the established baseline during 2014 and more notably during the first nine months of 2015, resulting in a payable. This is primarily the result of extremely cold weather experienced in the region during the first half of the year.

SOCIETAL BENEFIT COSTS (SBC) - This regulatory liability primarily represents the excess recoveries over the expenses incurred under the New Jersey Clean Energy Program which is a mechanism designed to recover costs associated with energy efficiency and renewable energy programs. The change from a $0.4 million regulatory asset to a $9.8 million regulatory liability is due to current SBC rates, which are producing recoveries greater than SBC costs. In July 2014, SJG made its annual 2014-2015 SBC filing requesting a decrease in SBC revenues, in part, to avoid this liability. The petition was approved and new rates went into effect on June 1, 2015.

5. RELATED-PARTY TRANSACTIONS:

There have been no significant changes in the nature of SJG’s related-party transactions since December 31, 2014. See Note 5 to the Financial Statements in Item 8 of SJG’s Form 10-K for the year ended December 31, 2014 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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Operating Revenues/Affiliates:
SJRG	$	1,100	$	169	$	2,631	$	552
Marina	116		278		483		914
Total Operating Revenue/Affiliates	$	1,216	$	447	$	3,114	$	1,466

Related-party transactions, excluding pass-through items, included in Operating Expenses were as follows (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Costs of Sales/Affiliates (Excluding depreciation)
SJRG	$	574	$	1,686		$	21,105	$	8,612
Energy-Related Derivative Losses / (Gains) *
SJRG	$	—	$	(92	)	$	65	$	(1,612	)

* Contracts used to hedge natural gas purchases. Included in Cost of Sales on the Condensed Statements of Income.

Operations Expense/Affiliates:
SJI	$	3,248		$	2,901		$	10,529		$	10,079
Millennium	695			687			2,048			1,982
Other	(95		)	(111		)	(312		)	(327		)
Total Operations Expense/Affiliates	$	3,848		$	3,477		$	12,265		$	11,734

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6. 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 September 30, 2015 and December 31, 2014, the escrowed proceeds, including interest earned, totaled $32,200 and $132,300, respectively. 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, 2015 and December 31, 2014, the balance held with this counterparty totaled $6.2 million and $7.8 million, respectively. The carrying amounts of the Restricted Investments approximate their fair value at September 30, 2015 and December 31, 2014, 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 bears 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. SJG holds a first lien security interest on land in Atlantic City as collateral against this note.

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 years with no interest. The carrying amounts of such loans were $13.3 million and $15.0 million as of September 30, 2015 and December 31, 2014, 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 $1.3 million as of both September 30, 2015 and December 31, 2014. 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, 2015 and December 31, 2014, 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, 2015 and December 31, 2014, 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, 2015 and December 31, 2014, were $662.7 million and $587.3 million, respectively. The carrying amount of SJG's long-term debt, including current maturities, as of September 30, 2015 and December 31, 2014, was $612.9 million and $543.0 million, respectively .

7. LINES OF CREDIT:

Credit facilities and available liquidity as of September 30, 2015 were as follows (in thousands):

	Total Facility		Usage			Available Liquidity		Expiration Date
Commercial Paper Program/ Revolving Credit Facility	$	200,000	$	89,900	(A)	$	110,100	May 2018
Uncommitted Bank Lines	10,000		—			10,000		Various
Total	$	210,000	$	89,900	(A)	$	120,100

(A) Includes letters of credit outstanding in the amount of $0.6 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, 2015.

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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, 2015 and 2014 were $117.9 million and $40.9 million, respectively. The maximum amount outstanding under these credit facilities during the nine months ended September 30, 2015 and 2014 were $162.3 million and $70.1 million, respectively.

Borrowings under these credit facilities are at market rates. The weighted average interest rate on these borrowings, which changes daily, was 0.40% and 0.26% at September 30, 2015 and 2014, respectively.

8. PENSION AND OTHER POSTRETIREMENT BENEFITS:

For the three and nine months ended  September 30, 2015 and 2014, 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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Service Cost	$	996		$	536		$	2,988		$	2,468
Interest Cost	2,083			1,819			6,251			5,873
Expected Return on Plan Assets	(2,759		)	(2,233		)	(8,278		)	(7,143		)
Amortizations:
Prior Service Cost	40			30			119			96
Actuarial Loss	1,979			957			5,938			3,101
Net Periodic Benefit Cost	2,339			1,109			7,018			4,395
Capitalized Benefit Cost	(1,216		)	(577		)	(3,649		)	(2,285		)
Deferred Benefit Cost	(341		)	—			(666		)	—
Total Net Periodic Benefit Expense	$	782		$	532		$	2,703		$	2,110

	Other Postretirement Benefits						Other Postretirement Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Service Cost	$	186		$	28		$	558		$	372
Interest Cost	495			171			1,486			1,191
Expected Return on Plan Assets	(499		)	(202		)	(1,496		)	(1,148		)
Amortizations:
Prior Service Cost	102			11			304			63
Actuarial Loss	224			73			671			407
Net Periodic Benefit Cost	508			81			1,523			885
Capitalized Benefit Cost	(264		)	(42		)	(792		)	(460		)
Deferred Benefit Cost	(89		)	—			(168		)	—
Total Net Periodic Benefit Expense	$	155		$	39		563			425

Capitalized benefit cost 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 (RP-2014 base table with MP-2014 generational projection scale) in 2015. Deferred benefit costs are expected to be recovered through rates as part of our next base rate case.

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SJG contributed $12.0 million to the pension plans in January 2015. No contributions were made to the pension plans during 2014. Payments related to the unfunded Supplemental Executive Retirement Plan (SERP) are expected to approximate $1.5 million in 2015. 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 Form 10-K for the year ended December 31, 2014 for additional information related to SJG’s pension and other postretirement benefits.

9. COMMITMENTS AND CONTINGENCIES:

STANDBY LETTER OF CREDIT - SJG provided a $0.6 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. There have been no significant changes to the status of SJG’s environmental remediation efforts since December 31, 2014, as described in Note 12 to the Financial Statements in Item 8 of SJG’s Form 10-K for the year ended December 31, 2014.

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 so in accordance with their respective FERC-approved tariff. Our cumulative obligation for gas supply-related demand charges and reservation fees paid for these services averages approximately $6.3 million per month and is recovered on a current basis through the BGSS.

PENDING LITIGATION - We are subject to claims arising in the ordinary course of business and other legal proceedings. We accrue liabilities related to these claims when we can reasonably estimate the amount or range of amounts of probable settlement costs or other charges for these claims. The Company has accrued approximately $0.9 million and $0.5 million related to all claims in the aggregate as of September 30, 2015 and December 31, 2014, respectively. Management does not believe that it is reasonably possible that there will be a material change in the Company's estimated liability in the near term and does not currently anticipate the disposition of any known claims that would have a material effect on the Company's financial position, results of operations or cash flows.

COLLECTIVE BARGAINING AGREEMENTS - Unionized personnel represent approximately 61% of our workforce at September 30, 2015. 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.

10. 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.

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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, 2015
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	8,528	$	3,407	$	5,121	$	—
Derivatives – Energy Related Assets (B)	1,273		228		1		1,044
	$	9,801	$	3,635	$	5,122	$	1,044
Liabilities
Derivatives – Energy Related Liabilities (B)	$	6,469	$	5,691	$	185	$	593
Derivatives – Other (C)	7,918		—		7,918		—
	$	14,387	$	5,691	$	8,103	$	593

As of December 31, 2014
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	8,894	$	5,924	$	2,970	$	—
Derivatives - Energy Related Assets (B)	2,051		2		2,049		—
	$	10,945	$	5,926	$	5,019	$	—
Liabilities
Derivatives - Energy Related Liabilities (B)	$	7,603	$	7,254	$	349	$	—
Derivatives - Other (C)	7,325		—		7,325		—
	$	14,928	$	7,254	$	7,674	$	—

(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 forwards, 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.

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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, 2015		Valuation Technique	Significant Unobservable Input	Range [Weighted Average]
	Assets	Liabilities
Forward Contract - Natural Gas	$1,044	$593	Discounted Cash Flow	Forward price (per dt)	$1.08 - $7.00 [$3.71]

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	)	$	—
Total unrealized gains included in Regulatory Assets (see note 4)	1,035			451
Balance at end of period	451			451

There were no Derivatives - Energy Related Assets and Liabilities for the three and nine months ended September 30, 2014, using significant unobservable inputs (Level 3).

11. 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, 2015, SJG had outstanding derivative contracts intended to limit the exposure to market risk on 9.1 million decatherms (MMdts) of expected future purchases of natural gas and 0.60 MMdts of expected future sales of natural gas. In addition to these derivative contracts, SJG had basis and index related purchase and sales contracts totaling 2.3 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, 2015 and December 31, 2014, SJG had $5.2 million and $5.6 million of unrealized losses, respectively, included in its BGSS related to open financial contracts.

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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, 2014, 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, 2014. 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 September 30, 2015 and December 31, 2014, the unamortized balance was approximately $0.9 million, and $1.0 million, respectively.

The fair values of all derivative instruments, as reflected in the condensed balance sheets as of September 30, 2015 and December 31, 2014, are as follows (in thousands):

Derivatives not designated as hedging instruments under GAAP	September 30, 2015				December 31, 2014
	Assets		Liabilities		Assets		Liabilities
Energy related commodity contracts:
Derivatives – Energy Related – Current	$	1,273	$	6,072	$	2,051	$	6,305
Derivatives – Energy Related – Non-Current	—		397		—		1,298
Interest rate contracts:
Derivatives – Other	—		7,918		—		7,325
Total derivatives not designated as hedging instruments under GAAP	1,273		14,387		2,051		14,928
Total Derivatives	$	1,273	$	14,387	$	2,051	$	14,928

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, 2015, and December 31, 2014, information related to these offsetting arrangements were as follows (in thousands):

As of September 30, 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	$	1,273		$	—	$	1,273		$	(229	)	(A)	$	—	$	1,044
Derivatives - Energy Related Liabilities	(6,469		)	—		(6,469		)	229			(B)	5,462		(778		)
Derivatives - Other	(7,918		)	—		(7,918		)	—				—		(7,918		)

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As of December 31, 2014:
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	$	2,051		$	—	$	2,051		$	(2	)	(A)	$	—	$	2,049
Derivatives - Energy Related Liabilities	(7,603		)	—		(7,603		)	2			(B)	7,253		(348		)
Derivatives - Other	(7,325		)	—		(7,325		)	—				—		(7,325		)

(A) The balances at September 30, 2015 and December 31, 2014 were related to derivative liabilities which can be net settled against derivative assets.

(B) The balances at September 30, 2015 and December 31, 2014 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, 2015 and 2014 are as follows (in thousands):

	Three months ended September 30,						Nine months ended September 30,
Derivatives in Cash Flow Hedging Relationships	2015			2014			2015			2014
Interest Rate Contracts:
Losses reclassified from Accumulated Other Comprehensive Loss into income (a)	$	(12	)	$	(12	)	$	(36	)	$	(36	)

(a) Included in Interest Charges

Net realized loss of $1.6 million and $1.2 million associated with SJG's energy-related financial commodity contracts for the three months ended September 30, 2015 and 2014, respectively, and loss of $6.4 million and gain of $2.4 million for the nine month ended September 30, 2015 and 2014, 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.

12. LONG-TERM DEBT:

In August, SJG retired $10.0 million aggregate principal amount of 5.387% medium term notes (MTN's) at maturity.

In September, SJG issued $80.0 million of long-term debt under a $200.00 million aggregate syndicated bank term facility. The total outstanding amount under this facility as of September 30, 2015 was $139.0 million.

Also in September, SJG redeemed early $100,000 of the $25.0 million aggregate principal amount variable rate demand bonds that were issued in September 2008. SJG had previously spent all but $100,000 of the debt proceeds and was permitted under the debt agreement to utilize those remaining funds to redeem the debt early.

We retire debt when it is cost effective as permitted by the debt agreements.  

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13.    ACCUMULATED OTHER COMPREHENSIVE LOSS:

The changes in Accumulated Other Comprehensive Loss (AOCL) for the three and nine months ended September 30, 2015 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, 2015 (a)	$	(13,837	)	$	(558	)	$	(58	)	$	(14,453	)
Other comprehensive loss before reclassifications	—			—			(276		)	(276		)
Amounts reclassified from AOCL (b)	—			6			178			184
Net current period other comprehensive income (loss)	—			6			(98		)	(92		)
Balance at September 30, 2015 (a)	$	(13,837	)	$	(552	)	$	(156	)	$	(14,545	)

	Postretirement Liability Adjustment			Unrealized Gain (Loss) on Derivatives-Other			Unrealized Gain (Loss) on Available-for-Sale Securities			Total
Balance at January 1, 2015 (a)	$	(13,837	)	$	(567	)	$	(75	)	$	(14,479	)
Other comprehensive loss before reclassifications	—			—			(227		)	(227		)
Amounts reclassified from AOCL (b)	—			15			146			161
Net current period other comprehensive income (loss)	—			15			(81		)	(66		)
Balance at September 30, 2015 (a)	$	(13,837	)	$	(552	)	$	(156	)	$	(14,545	)

(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, 2015 are as follows (in thousands):

Components of AOCL	Amounts Reclassified from AOCL (in thousands)						Affected Line Item in the Condensed Statements of Income
	Three Months Ended September 30, 2015			Nine Months Ended September 30, 2015
Unrealized Loss in on Derivatives-Other - Interest Rate Contracts designated as cash flow hedges	$	11		$	35		Interest Charges
Unrealized Loss on Available-for-Sale Securities	298			245			Other Income & Expense
	309			280			Loss Before Income Taxes
Income Taxes (a)	(125		)	(119		)	Income Taxes
Losses from reclassifications for the period net of tax	$	184		$	161

(a) Determined using a combined average statutory tax rate of 40%.

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14.    SUBSEQUENT EVENTS:

On October 1, 2015, the Board of Directors of SJG declared a cash dividend of $10,491,000 payable to SJI. The dividend was paid on October 2, 2015.

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Item 2. Management’s Discussion and Analysis

of Financial Condition and Results of Operations

OVERVIEW:

Organization - We are an operating public utility company engaged in the purchase, transmission and sale of natural gas for residential, commercial and industrial use. We also sell natural gas and pipeline transportation capacity (off-system sales) on a wholesale basis to various customers on the interstate pipeline system and transport natural gas purchased directly from producers or suppliers to their customers. We served 369,807 customers at September 30, 2015 compared with 362,914 customers at September 30, 2014.

Forward-Looking Statements and Risk Factors- Certain statements contained in this Quarterly Report may qualify as “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report should be considered forward-looking statements made in good faith by the Company and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Words such as “anticipate”, “believe”, “expect”, “estimate”, “forecast”, “goal”, “intend”, “objective”, “plan”, “project”, “seek”, “strategy” and similar expressions are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include, but are not limited to, the following: general economic conditions on an international, national, state and local level; weather conditions in our marketing areas; changes in commodity costs; changes in the availability of natural gas; “non-routine” or “extraordinary” disruptions in our distribution system; regulatory, legislative and court decisions; competition; the availability and cost of capital; costs and effects of legal proceedings and environmental liabilities; the failure of customers or suppliers to fulfill their contractual obligations; and changes in business strategies.

A discussion of these and other risks and uncertainties may be found in SJG’s Form 10-K for the year ended December 31, 2014 and in other filings made by us with the Securities and Exchange Commission. These cautionary statements should not be construed by you to be exhaustive and they are made only as of the date of this Quarterly Report on Form 10-Q, or in any document incorporated by reference, at the date of such document. While SJG believes these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, SJG undertakes no obligation to update or revise any of its forward-looking statements, whether as a result of new information, future events or otherwise.

Critical Accounting Policies - Estimates and Assumptions - Management must make estimates and assumptions that affect the amounts reported in the condensed financial statements and related disclosures. Actual results could differ from those estimates. Five types of transactions presented in our condensed financial statements require a significant amount of judgment and estimation. These relate to regulatory accounting, derivatives, environmental remediation costs, pension and other postretirement benefit costs, and revenue recognition. A discussion of these estimates and assumptions may be found in SJG’s Form 10-K for the year ended December 31, 2014.

New Accounting Pronouncements-    See detailed discussions concerning New Accounting Pronouncements and their impact on SJG in Note 1 to the condensed financial statements.

Regulatory Actions– Other than the changes discussed in Note 3 to the condensed financial statements, there have been no significant regulatory actions since December 31, 2014. See detailed discussions concerning Regulatory Actions in Note 3 to the Financial Statements in item 8 of SJG’s Form 10-K for the year ended December 31, 2014.

Environmental Remediation– There have been no significant changes to the status of SJG’s environmental remediation efforts since December 31, 2014. See detailed discussion concerning Environmental Remediation Costs in Note 12 to the Financial Statements in Item 8 of SJG’s Form 10-K for the year ended December 31, 2014.

Competition- See detailed discussion concerning competition in SJG’s Form 10-K for the year ended December 31, 2014.

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Customer Choice Legislation- All residential natural gas customers in New Jersey can choose their natural gas commodity supplier under the terms of the “Electric Discount and Energy Competition Act of 1999.” This bill created the framework and necessary time schedules for the restructuring of the state’s electric and natural gas utilities. The Act established unbundling, under which redesigned utility rate structures allow natural gas and electric consumers to choose their energy supplier. Customers purchasing natural gas from a provider other than the local utility (marketer) are charged for the gas costs by the marketer and charged for the transportation costs by the utility. The number of customers purchasing their natural gas from marketers was 35,722 and 39,577 at September 30, 2015 and 2014, respectively.

RESULTS OF OPERATIONS:

The following table summarizes the composition of selected gas utility data for the three and nine month periods ended September 30, (in thousands, except for degree day data):

	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Utility Throughput – decatherms(dt):
Firm Sales -
Residential	1,499	1,407	18,788	17,425
Commercial	593	544	4,944	4,026
Industrial	113	18	378	208
Cogeneration & Electric Generation	781	273	1,277	828
Firm Transportation -
Residential	141	169	1,933	2,463
Commercial	920	643	5,292	5,175
Industrial	2,760	3,105	8,777	9,774
Cogeneration & Electric Generation	1,840	4,143	4,918	7,332
Total Firm Throughput	8,647	10,302	46,307	47,231
Interruptible Sales	—	—	20	—
Interruptible Transportation	346	258	998	964
Off-System Sales	2,031	2,489	8,652	6,007
Capacity Release	16,018	11,958	45,008	42,617
Total Throughput - Utility	27,042	25,007	100,985	96,819

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	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
Utility Operating Revenues:
Firm Sales -
Residential	$	25,986		$	24,149	$	238,571		$	184,436
Commercial	7,616			7,489		54,726			44,939
Industrial	1,032			278		4,154			2,945
Cogeneration & Electric Generation	2,619			1,487		4,907			5,148
Firm Transportation -
Residential	1,533			1,886		12,360			14,741
Commercial	4,292			3,577		22,769			21,540
Industrial	5,888			6,240		17,488			19,214
Cogeneration & Electric Generation	947			3,350		3,943			6,924
Total Firm Revenues	49,913			48,456		358,918			299,887
Interruptible Sales	—			—		298			2
Interruptible Transportation	312			311		1,076			1,170
Off-System Sales	5,586			10,032		35,682			33,998
Capacity Release	2,460			1,840		5,118			4,688
Other	363			313		1,012			911
Total Utility Operating Revenues	58,634			60,952		402,104			340,656
Less:
Cost of Sales (Excluding depreciation)	22,934			23,400		194,455			151,572
Conservation Recoveries*	1,648			3,453		18,772			19,171
RAC Recoveries*	2,281			2,021		6,842			6,064
EET Recoveries*	769			1,128		2,816			3,179
Revenue Taxes	165			154		952			765
Utility Margin**	$	30,837		$	30,796	$	178,267		$	159,905
Margin:
Residential	$	17,628		$	15,462	$	131,731		$	111,533
Commercial and Industrial	11,631			9,529		56,613			46,986
Cogeneration and Electric Generation	1,270			1,566		3,650			4,013
Interruptible	19			9		103			43
Off-System Sales & Capacity Release	670			625		2,748			1,745
Other Revenues	889			609		2,144			1,720
Margin Before Weather Normalization & Decoupling	32,107			27,800		196,989			166,040
CIP Mechanism	(1,822		)	2,721		(20,218		)	(6,698		)
EET Mechanism	552			275		1,496			563
Utility Margin**	$	30,837		$	30,796	$	178,267		$	159,905
Degree Days:	3			26		3,343			3,288

*Represents expenses for which there is a corresponding credit in operating revenues.  Therefore, such recoveries have no impact on our financial results.

**Utility Margin is further defined under the caption "Margin (pre-tax)" below.

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Throughput– Total gas throughput increased 2.0 MMdts and 4.2 MMdts during the three and nine months ended September 30, 2015, respectively, compared with the same periods in 2014. Capacity release increased 4.1 MMdts and 2.4 MMdts during the three and nine months ended September 30, 2015, respectively, as the market for long-haul capacity increased during the third quarter, thereby increasing throughput for both the quarter and year-to-date. The increase in Off-System sales (OSS) was primarily related to opportunities created on the interstate pipeline as a result of extremely cold weather in the northeast region of the country during the first quarter of 2015, which contributed to a 2.6 MMdts increase on a year-to-date basis over 2014.

Firm throughput decreased 1.7 MMdts and 0.9 MMdts during the three and nine months ended September 30, 2015, respectively, compared with the same periods in 2014. This was the result of a significant decrease in transportation of commodity to a cogeneration facility during the third quarter of 2015, compared to the same period in 2014, as reflected under “Firm Transportation - Cogeneration & Electric Generation” in the Throughput table above. During the third quarter of 2014, this facility had a disruption in its alternate supply of natural gas and turned to SJG to meet its operating needs. That disruption has since been remedied, resulting in lower firm transportation throughput in 2015.

Operating Revenues – Revenues decreased $2.3 million during the three months ended September 30, 2015, compared with the same period in 2014, due to lower OSS, partially offset by higher firm sales. Lower OSS unit volume, coupled with lower unit prices, resulted in a $4.4 million decrease in OSS revenues during the three months ended September 30, 2015, compared with the same period in 2014. However, the impact of changes in OSS activity does not have a material impact on the earnings of SJG, as the Company is required to return 85% of the profits of such activity to our ratepayers. Earnings from OSS can be seen in the “Margin” table above.

Total firm revenue increased $1.5 million for the three months ended September 30, 2015, as a result of a 22.1% increase in SJG’s rate for natural gas recoveries, effective October 1, 2014. This increased revenue by approximately $ 2.5 million during the three months ended September 30, 2015, compared to the same period in 2014. While changes in natural gas costs and Basic Gas Supply Service (“BGSS”) recoveries fluctuate from period to period, SJG does not profit from the sale of the commodity. Therefore, fluctuations in Operating Revenue and Cost of Sales, such as those caused by the recovery of an incremental $2.5 million in gas costs during the third quarter of 2015, did not impact SJG’s profitability. Also contributing to higher firm revenue was the addition of 6,893 customers compared with the same period in 2014. Partially offsetting the increase in firm revenues was a significant decrease in transportation sevice to a cogeneration facility during the third quarter of 2015, compared to the same period in 2014. During the third quarter of 2014, this facility had a disruption in its alternate supply of natural gas and turned to SJG to meet its operating needs. That disruption has since been remedied, resulting in lower firm transportation revenue in 2015.

Revenues increased $61.4 million during the nine months ended September 30, 2015, compared with the same period in 2014, due to higher firm sales and OSS. Total firm revenue increased $59.0 million for the nine months ended September 30, 2015, as a result of the settlement of SJG’s base rate case and a 22.1% increase in SJG’s rate for natural gas recoveries, both effective October 1, 2014. These two events increased revenue by approximately $15.5 million and $37.4 million, respectively, during the nine months ended September 30, 2015, compared to the same period in 2014. As previously stated, SJG does not profit from the sale of commodity; therefore, the recovery of an incremental $37.4 million in gas costs during 2015 has no impact on SJG’s profitability. Also contributing to higher revenue were 2.5% colder weather and the addition of 6,893 additional customers compared with the same period in 2014. While colder weather increased firm sales revenue, the revenue increase has little impact on Company profitability under the operation of the Conservation Incentive Program, as discussed below under the captions, “Conservation Incentive Program (CIP)” and “Margin (pre-tax).”

Higher OSS unit volume, partially offset by lower unit prices, resulted in a $1.7 million increase in OSS revenues during the nine months ended September 30, 2015, compared with the same period in 2014. Extremely cold weather in the northeast region of the country lead to greater demand during the first quarter of 2015, creating opportunity for the Company to increase revenue from such sales. However, the impact of changes in OSS activity does not have a material impact on the earnings of SJG, as the Company is required to return 85% of the profits of such activity to our ratepayers. Earnings from OSS can be seen in the “Margin” table above.

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Conservation Incentive Program (CIP) - The effects of the CIP on our net income and the associated weather comparisons are as follows ($’s in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
Net Income Impact:
CIP – Weather Related	$	—		$	—	$	(7.3	)	$	(5.7	)
CIP – Usage Related	(1.1		)	1.6		(4.7		)	1.7
Total Net Income Impact	$	(1.1	)	$	1.6	$	(12.0	)	$	(4.0	)
Weather Compared to 20-Year Average	n/a			n/a		14.7% Colder			13.4% Colder
Weather Compared to Prior Year	n/a			n/a		1.7% Colder			8.9% Colder

Margin (pre-tax)- SJG’s margin is defined as natural gas revenues less natural gas costs, regulatory rider expenses and related volumetric and revenue-based energy taxes. Management believes that margin provides a more meaningful basis for evaluating utility operations than revenues since natural gas costs, regulatory rider expenses and related energy taxes are passed through to customers and, therefore, have no effect on margin. Natural gas costs are charged to operating expenses on the basis of therm sales at the prices approved by the New Jersey Board of Public Utilities (BPU) through SJG’s Basic Gas Supply Service (BGSS) clause.

Total margin was relatively flat at $30.8 million for each of the three month periods ended September 30, 2015 and 2014, as residential, commercial and industrial margin increased in 2015 offset by the CIP tracking mechanism, as discussed below, Total margin increased $18.4 million, or 11.5%, for the nine months ended September 30, 2015, compared with the same period in 2014. The increase is primarily due to increases in rates as a result of the settlement of SJG's base rate case effective October 1, 2014, which increased margin by approximately $15.5 million for the nine months ended September 30, 2015, compared with the same period in 2014. In addition, SJG added 6,893 customers over the 12-month period ended September 30, 2015, contributing approximately $2.3 million in additional margin during the nine months ended September 30, 2015, compared with the same period of 2014.

The CIP tracking mechanism adjusts earnings when actual usage per customer experienced during the period varies from an established baseline usage per customer. As reflected in the margin and CIP tables above, the CIP mechanism reduced margin by $1.8 million, or $1.1 million after taxes, for the three month period ended September 30, 2015, primarily due to higher customer usage. The CIP mechanism protected $2.7 million, or $1.6 million after taxes, of margin for the three months ended September 30, 2014, that would have been lost due to lower customer usage.

The CIP mechanism reduced margin by $20.2 million, or $12.0 million after taxes, and $6.7 million, or $4.0 million after taxes, during the nine month periods ended September 30, 2015 and 2014, respectively, primarily due to weather that was colder than average. Also, during the nine month period ended September 30, 2015, higher customer usage contributed $7.8 million, or $4.7 million after taxes, to the reduction in margin noted above.

Operating Expenses - A summary of changes in operating expenses (in thousands):

	Three Months Ended September 30, 2015 vs. 2014		Nine Months Ended September 30, 2015 vs. 2014
Operations	$	2,017	$	6,902
Maintenance	$	913	$	2,399
Depreciation	$	1,079	$	2,161
Energy and Other Taxes	$	8	$	267

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Operations - Operations expense increased $2.0 million and $6.9 million for the three and nine month periods ended September 30, 2015, respectively, as compared with the same periods in 2014. The increase primarily resulted from the write-off of $2.9 million of additional uncollectible customer accounts receivable during the third quarter of 2015, when compared to the same period last year, resulting in a similar increase in both the quarterly and year-to-date expense. The increase in write-offs results from an increase in the aging of receivables following a very cold winter season. SJG increased its reserve for uncollectible accounts, resulting in $2.2 million of additional expense in the nine months ended September 30, 2015 as compared to the same period in 2014. Changes in the uncollectible reserve are the result of fluctuations in levels of customer accounts receivables balances. Accounts receivable was higher as of September 30, 2015 due to higher customer billing rates, as approved by the BPU effective October 1, 2014, in addition to a 1.9% customer growth over the 12-month period ended September 30, 2015.

Maintenance - Maintenance expense increased $0.9 million and $2.4 million during the three and nine months ended September 30, 2015, respectively, compared with the same periods in 2014, primarily due to the BPU-approved amortization and recovery of previously deferred maintenance costs, primarily those associated with a federally mandated pipeline integrity management program. Such amortizations, which are being recovered through an offsetting amount in revenues beginning in October 2014, total $0.3 million per quarter in 2015. Also contributing to the increase are higher levels of Remediation Adjustment Clause (RAC) amortization. This increase of approximately $0.3 million in RAC-related expenses in each of the first three quarters of 2015 does not affect earnings, as we recognize an offsetting amount in revenues.

Depreciation - Depreciation expense increased $1.1 million and $2.2 million during the three and nine month periods ended September 30, 2015, respectively, compared with the same periods in 2014, due mainly to our continuing investment in property, plant and equipment.

Energy and Other Taxes - Changes in Energy and Other Taxes during the three and nine month periods ended September 30, 2015, compared with the same periods in 2014 were not significant.

Other Income and Expense - Other Income and Expense decreased $1.2 million and $1.3 million during the three and nine month periods ended September 30, 2015, compared with the same periods in 2014, respectively. During the third quarter of 2014, the Company realized a gain of $0.9 million on the sale of available-for-sale securities. In 2015, there were no such sales. However, due to a capital market decline, the Company realized a loss of $0.3 million on its available-for-sale securities during the third quarter of 2015.

Interest Charges–  Interest Charges increased $0.8 million and $2.4 million during the three and nine month periods ended September 30, 2015, respectively, compared with the same periods in 2014, primarily due to lower capitalization of interest costs on construction during 2015. This was a result of the roll-in of capital investments under the Company's Accelerated Infrastructure Replacement Program (AIRP) into base rates effective October 1, 2014 and a lower allowance for debt funds used during construction as a result of placing two major technology systems in service during the fourth quarter of 2014. AIRP investments are approved by the BPU to accrue interest on construction until such time they were rolled into base rates.

Income Taxes– Income tax expense generally fluctuates as income before income taxes changes. Minor variations will occur period to period as a result of effective tax rate adjustments.

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LIQUIDITY AND CAPITAL RESOURCES:

Liquidity needs are driven by factors that include natural gas commodity prices; the impact of weather on customer bills; lags in fully collecting gas costs from customers under the Basic Gas Supply Service charge; the timing of construction and remediation expenditures and related permanent financings; mandated tax payment dates; both discretionary and required repayments of long-term debt; and the amounts and timing of dividend payments.

Cash Flows from Operating Activities - Liquidity needs are first met with net cash provided by operating activities. Net cash provided by operating activities totaled $124.8 million and $55.2 million in the first nine months of 2015 and 2014, respectively. Net cash provided by operating activities varies from year-to-year primarily due to the impact of weather on customer demand and related gas purchases, customer usage factors related to conversion efforts and the price of the natural gas commodity, inventory utilization, and gas cost recoveries. Net cash provided by operations improved due to higher collections of gas costs under the BGSS that were deferred in 2014 as a result of the extremely cold weather experienced during the first quarter of 2014. This benefit was offset by a $12.0 million pension contribution made by SJG as a result of a decline in the discount rate and new mortality tables released at the end of 2014, both of which negatively impacted the funding status of the pension plans. No such contribution was made in 2014. The Company strives to keep its pension plans fully funded. When factors such as lesser than expected asset performance and/or declining discount rates negatively impact the funding status of the plans, the Company increases its contributions to supplant that funding shortfall. 

Cash Flows from Investing Activities - SJG has a continuing need for cash resources for capital expenditures, primarily to invest in new and replacement facilities and equipment. Cash used for capital expenditures was $147.3 million and $139.4 million during the first nine months of 2015 and 2014, respectively. We estimate the net cash outflows for capital expenditures for fiscal years 2015, 2016 and 2017 to be approximately $228.0 million, $244.0 million and $309.0 million, respectively. For capital expenditures, including those under the AIRP, SJG expects to use short-term borrowings to finance capital expenditures as incurred. From time to time, the Company may refinance the short-term debt incurred to support capital expenditures with long-term debt. 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 bears 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. SJG holds a first lien security interest on land in Atlantic City as collateral against this note.

Cash Flows from Financing Activities - SJG uses short-term borrowings under lines of credit from commercial banks, or under its commercial paper program discussed below, to supplement cash from operations, to support working capital needs and to finance capital expenditures as incurred. From time to time, the Company refinances short-term debt incurred to finance capital expenditures with long-term debt. Debt is incurred primarily to expand and upgrade our gas transmission and distribution system and to support seasonal working capital needs related to inventories and customer receivables. In August, SJG retired $10.0 million aggregate principal amount of 5.387% MTN's at maturity. In September, the Company issued $80.0 million of long-term debt under a $200.0 million aggregate syndicated bank term facility. The total outstanding amount under this facility as of September 30, 2015 was $139.0 million. Also in September, SJG redeemed early $0.1 million of the $25.0 million aggregate principal amount variable rate demand bonds that were issued in September 2008. SJG had previously spent all but $0.1 million of the debt proceeds and was permitted under the debt agreement to utilize those remaining funds to redeem the debt early.

Credit facilities and available liquidity as of September 30, 2015 were as follows (in thousands):

	Total Facility		Usage			Available  Liquidity		Expiration Date
Commercial Paper/Revolving Credit Facilities	$	200,000	$	89,900	(A)	$	110,100	May 2018
Uncommitted Bank Lines	10,000		—			10,000		Various
Total	$	210,000	$	89,900	(A)	$	120,100

(A) Includes letters of credit outstanding in the amount of $0.6 million.

The SJG 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, 2015.

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. 

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SJG intends to use the commercial paper program in tandem with its $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 the commercial paper program/revolving credit facility, during the nine months ended September 30, 2015 and 2014 were $117.9 million and $40.9 million, respectively. The maximum amount outstanding under these credit facilities, not including letters of credit, during the nine months ended September 30, 2015 and 2014 were $162.3 million and $70.1 million, respectively.

Based upon the existing credit facilities and a regular dialogue with our banks, we believe there will continue to be sufficient credit available to meet our future liquidity needs.

SJG supplements its operating cash flow and credit lines with both debt and equity capital. Over the years, SJG has used long-term debt, primarily in the form of First Mortgage Bonds and MTN's, secured by the same pool of utility assets, to finance our long-term borrowing needs. These needs are primarily capital expenditures for property, plant and equipment.

SJG’s capital structure was as follows:

	As of September 30,  2015		As of December 31, 2014
Common Equity	50	%	51	%
Long-Term Debt	44	%	41	%
Short-Term Debt	6	%	8	%
Total	100	%	100	%

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COMMITMENTS AND CONTINGENCIES:

SJG has a continuing need for cash resources and capital, primarily to invest in new and replacement facilities and equipment, working capital, and for environmental remediation costs. Cash outflows for capital expenditures for the first nine months of 2015 and 2014 amounted to $147.3 million and $139.4 million, respectively. Management estimates net cash outflows for construction projects for 2015, 2016 and 2017, to be approximately $228.0 million, $244.0 million and $309.0 million, respectively.  Costs for remediation projects, net of insurance reimbursements, for the first nine months of 2015 and 2014 amounted to net cash outflows of $10.4 million and $4.9 million, respectively.  Total cash outflows for remediation projects are expected to be $17.4 million, $39.3 million and $23.8 million for 2015, 2016 and 2017, respectively.  As discussed in Notes 4 and 12 to the Financial Statements in Item 8 of SJG’s 10-K for the year ended December 31, 2014, environmental remediation costs are subject to recovery from ratepayers.

SJG provided a $0.6 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 the revolving credit facility, to support variable-rate demand bonds issued through the NJEDA to finance the expansion of SJG's natural gas distribution system.  

SJG has certain commitments for interstate pipeline capacity, storage services, Liquefied Natural Gas (LNG) and LNG transportation services, which carry demand type charges for which it pays fees regardless of usage. Those commitments as of September 30, 2015, average $75.7 million annually and total $343.5 million over the contracts’ lives.  Approximately 39% of the financial commitments under these contracts expire during the next five years. SJG expects to renew each of these contracts under renewal provisions as provided in each contract. SJG recovers all such prudently incurred fees through rates via the BGSS.

Contractual Cash Obligations – Details concerning contractual cash obligations may be found in SJG’s Form 10-K for the year ended December 31, 2014.  SJG's contractual cash obligations increased $231.1 million from December 31, 2014 primarily due to the addition of a 15-year gas supply contract, for $160.1 million beginning in November 2015, and the issuance of $80.0 million of long-term debt under a $200.00 million aggregate syndicated bank term facility.

Off-Balance Sheet Arrangements- We have no off-balance sheet arrangements.

Pending Litigation - We are subject to claims arising in the ordinary course of business and other legal proceedings. We accrue liabilities related to claims when we can reasonably estimate the amount or range of amounts of probable settlement costs or other charges for these claims. The Company has accrued approximately $0.9 million and $0.5 million, respectively, related to all claims in the aggregate, as of September 30, 2015 and December 31, 2014. Management does not believe that it is reasonably possible that there will be a material change in the Company's estimated liability in the near term and does not currently anticipate the disposition of any known claims that would have a material effect on the Company's financial position, results of operations or cash flows.

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Item 3. Quantitative and Qualitative Disclosures about Market Risks

MARKET RISKS:

Commodity Market Risks - We are involved in buying, selling, transporting and storing natural gas and are subject to market risk due to price fluctuations. To hedge against this risk, we enter into a variety of physical and financial transactions including forward contracts, futures and options agreements. To manage these transactions, we have a well-defined risk management policy approved by our Board of Directors that includes volumetric and monetary limits. Management reviews reports detailing activity daily. Generally, the derivative activities described above are entered into for risk management purposes.

We transact commodities on a physical and financial basis. As part of our gas purchasing strategy, we use financial contracts through a counterparty to hedge against forward price risk. These contracts are recoverable through our BGSS, subject to BPU approval. The majority of our contracts are typically less than 12-months long.

The fair value and maturity of these energy trading and hedging contracts determined using mark-to-market accounting as of September 30, 2015 are as follows (in thousands):

Assets
Source of Fair Value	Maturity < 1 Year		Maturity 1 - 3 Years		Total
Prices Actively Quoted (NYMEX)	$	228	$	—	$	228
Prices Provided by Other External Sources (Basis)	1		—		1
Prices based on internal models or other valuable methods	1,044		—		1,044
Total	$	1,273	$	—	$	1,273

Liabilities
	Maturity		Maturity
Source of Fair Value	< 1 Year		1 - 3 Years		Total
Prices Actively Quoted (NYMEX)	$	5,294	$	397	$	5,691
Prices Provided by Other External Sources (Basis)	185		$	—	185
Prices based on internal models or other valuable methods	593		—		593
Total	$	6,072	$	397	$	6,469

NYMEX (New York Mercantile Exchange) is the primary national commodities exchange on which natural gas is traded. Contracted volumes of our NYMEX contracts are 8.5 MMdt with a weighted-average settlement price of $3.35 per dt. Basis represents the price of a NYMEX natural gas futures contract adjusted for the difference in price for delivering the gas at another location. Contracted volumes of our Basis contracts are 2.3 MMdt with a weighted-average settlement price of $0.36 per dt.

A reconciliation of our estimated net fair value of energy-related derivatives follows (in thousands):

Net Derivatives — Energy Related Liability, January 1, 2015	$	(5,552	)
Contracts Settled During the Nine Months ended September 30, 2015, Net	3,683
Other Changes in Fair Value from Continuing and New Contracts, Net	(3,327		)
Net Derivatives — Energy Related Liability, September 30, 2015	$	(5,196	)

33

Interest Rate Risk - Our exposure to interest rate risk relates primarily to variable-rate borrowings. Variable-rate debt outstanding at September 30, 2015, was $228.3 million and averaged $185.3 million during the first nine months of 2015. A hypothetical 100 basis point (1%) increase in interest rates on our average variable-rate debt outstanding would result in a $1.1 million increase in our annual interest expense, net of tax. The 100 basis point increase was chosen for illustrative purposes, as it provides a simple basis for calculating the impact of interest rate changes under a variety of interest rate scenarios. Over the past five years, the change in basis points (b.p.) of our average monthly interest rates from the beginning to end of each year was as follows: 2014 - 32 b.p. increase; 2013 - 14 b.p. decrease; 2012 - 1 b.p. decrease; 2011 - 14 b.p. decrease; and 2010 - 5 b.p. increase.  As of September 30, 2015, our average interest rate on variable-rate debt was 0.80%.

We typically issue long-term debt either at fixed rates or use interest rate derivatives to limit our exposure to changes in interest rates on variable-rate, long-term debt. As of September 30, 2015, the interest costs on all but $139.0 million of long-term debt was either at a fixed-rate or hedged via an interest rate derivative. Consequently, interest expense on existing long-term debt is not significantly impacted by changes in market interest rates.

As of September 30, 2015, SJG’s active interest rate swaps were as follows:

Amount		Fixed Interest Rate		Start Date	Maturity	Type
$	12,500,000	3.43	%	12/1/2006	2/1/2036	Tax-exempt
$	12,500,000	3.43	%	12/1/2006	2/1/2036	Tax-exempt

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

SJG’s management, with the participation of its president (principal executive officer) and chief financial officer (principal financial officer), evaluated the effectiveness of the design and operation of SJG’s disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act) as of September 30, 2015. Based on that evaluation, SJG’s president and chief financial officer concluded that the disclosure controls and procedures employed at SJG are effective.

Changes in Internal Control Over Financial Reporting

There has not been any change in SJG’s internal control over financial reporting, as defined in Rules 13a-15(f) or 15d-15(f) under the Securities Exchange Act, during the fiscal quarter ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, SJG’s internal control over financial reporting.

34

PART II — OTHER INFORMATION

Item l. Legal Proceedings

Information required by this Item is incorporated by reference to Part I, Item 2, Pending Litigation, beginning on page 32.

Item 1A. Risk Factors

There have been no material changes in our risk factors from those disclosed in Part I, Item 1A of SJG’s Annual Report on Form 10-K for the year ended December 31, 2014.

Item 6. Exhibits

(a)           Exhibits

Exhibit No.	Description
31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a) of the Exchange Act.
31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a) of the Exchange Act.
32.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(b) of the Exchange Act as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
32.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(b) of the Exchange Act as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
101	The following financial statements from South Jersey Gas’ Quarterly Report on Form 10-Q for the three months ended September 30, 2015, filed with the Securities and Exchange Commission on November 5, 2015 formatted in XBRL (eXtensible Business Reporting Language): (i) the Condensed Statements of Income; (ii) the Condensed Statements of Comprehensive Income; (iii) the Condensed Statements of Cash Flows; (iv) the Condensed Balance Sheets and (v) the Notes to Condensed Financial Statements.

35

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

SOUTH JERSEY GAS COMPANY

(Registrant)

Dated:	November 5, 2015	By:	/s/ Stephen H. Clark
			Stephen H. Clark
			Chief Financial Officer
			(Principal Financial Officer)

36

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Jeffrey E. DuBois, certify that:

1.  I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2015 of South Jersey Gas Company;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15 d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.  The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

		South Jersey Gas Company
Date:	November 5, 2015	By:	/s/ Jeffrey E. DuBois
			Jeffrey E. DuBois
			President
			(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Stephen H. Clark, certify that:

1.  I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2015, of South Jersey Gas Company;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15 d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.  The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

		South Jersey Gas Company
Date:	November 5, 2015	By:	/s/ Stephen H. Clark
			Stephen H. Clark
			Chief Financial Officer
			(Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF

THE SARBANES-OXLEY ACT OF 2002

In connection with the filing of the Quarterly Report on Form 10-Q of South Jersey Gas Company (the “Company”) for the period ended September 30, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey E. DuBois, President (Principal Executive Officer) of the Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

(1)           The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2)           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Jeffrey E. DuBois

Name:  Jeffrey E. DuBois

Title:  President

(Principal Executive Officer)

November 5, 2015

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF

THE SARBANES-OXLEY ACT OF 2002

In connection with the filing of the Quarterly Report on Form 10-Q of South Jersey Gas Company (the “Company”) for the period ended September 30, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Stephen H. Clark, Chief Financial Officer (Principal Financial Officer) of the Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

(1)           The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2)           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Stephen H. Clark

Name:  Stephen H. Clark

Title:  Chief Financial Officer

(Principal Financial Officer)

November 5, 2015

XML

PENSION AND OTHER POSTRETIREMENT BENEFITS (Details) - USD ($)	1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Jan. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Pension Benefits
Net periodic benefit cost
Service Cost		$ 996,000	$ 536,000	$ 2,988,000	$ 2,468,000
Interest Cost		2,083,000	1,819,000	6,251,000	5,873,000
Expected Return on Plan Assets		(2,759,000)	(2,233,000)	(8,278,000)	(7,143,000)
Amortizations:
Prior Service Cost		40,000	30,000	119,000	96,000
Actuarial Loss		1,979,000	957,000	5,938,000	3,101,000
Net Periodic Benefit Cost		2,339,000	1,109,000	7,018,000	4,395,000
Capitalized Benefit Cost		(1,216,000)	(577,000)	(3,649,000)	(2,285,000)
Deferred Benefit Cost		(341,000)	0	(666,000)	0
Total Net Periodic Benefit Expense		782,000	532,000	2,703,000	2,110,000
Contributions	$ 12,000,000					$ 0
Other Postretirement Benefits
Net periodic benefit cost
Service Cost		186,000	28,000	558,000	372,000
Interest Cost		495,000	171,000	1,486,000	1,191,000
Expected Return on Plan Assets		(499,000)	(202,000)	(1,496,000)	(1,148,000)
Amortizations:
Prior Service Cost		102,000	11,000	304,000	63,000
Actuarial Loss		224,000	73,000	671,000	407,000
Net Periodic Benefit Cost		508,000	81,000	1,523,000	885,000
Capitalized Benefit Cost		(264,000)	(42,000)	(792,000)	(460,000)
Deferred Benefit Cost		(89,000)	0	(168,000)	0
Total Net Periodic Benefit Expense		$ 155,000	$ 39,000	563,000	$ 425,000
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				$ 1,500,000

XML

ACCUMULATED OTHER COMPREHENSIVE LOSS (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		$ (14,453)		$ (14,479)
Other comprehensive loss before reclassifications		(276)		(227)
Amounts reclassified from AOCL		184		161
Other Comprehensive Loss - Net of Tax	[1]	(92)	$ (607)	(66)	$ (376)
Ending balance		$ (14,545)		$ (14,545)
Combined statutory tax rate		40.00%	41.00%	40.00%	41.00%
Postretirement Liability Adjustment
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		$ (13,837)		$ (13,837)
Other comprehensive loss before reclassifications		0		0
Amounts reclassified from AOCL		0		0
Other Comprehensive Loss - Net of Tax		0		0
Ending balance		(13,837)		(13,837)
Unrealized Gain (Loss) on Derivatives-Other
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		(558)		(567)
Other comprehensive loss before reclassifications		0		0
Amounts reclassified from AOCL		6		15
Other Comprehensive Loss - Net of Tax		6		15
Ending balance		(552)		(552)
Unrealized Gain (Loss) on Available-for-Sale Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		(58)		(75)
Other comprehensive loss before reclassifications		(276)		(227)
Amounts reclassified from AOCL		178		146
Other Comprehensive Loss - Net of Tax		(98)		(81)
Ending balance		$ (156)		$ (156)

[1] Determined using a combined average statutory tax rate of 40% and 41% in 2015 and 2014, respectively.

XML

DERIVATIVE INSTRUMENTS 4 (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Losses reclassified from Accumulated Other Comprehensive Loss into income	$ (12)	$ (12)	$ (36)	$ (36)
Net Realized gains (losses), derivative instruments, energy-related contracts	$ (1,600)	$ 1,200	$ (6,400)	$ 2,400

XML

RATES AND REGULATORY ACTIONS (Details) - USD ($) $ in Millions	1 Months Ended
	Sep. 30, 2015	Aug. 31, 2015	Oct. 01, 2015	Jun. 30, 2015	May. 31, 2015
Subsequent Event
Schedule of Capitalization [Line Items]
Public Utilities, Amount of Regulatory Costs Approved, Annual Revenue Impact Increase (Decrease)			$ (3.4)
Societal Benefits Clause And Transportation Initiation Clause
Schedule of Capitalization [Line Items]
Increase (Decrease) in Amount of Regulatory Costs Approved					$ (18.2)
Remediation Adjustment Clause
Schedule of Capitalization [Line Items]
Increase (Decrease) in Amount of Regulatory Costs Approved					(6.2)
Clean Energy Program
Schedule of Capitalization [Line Items]
Increase (Decrease) in Amount of Regulatory Costs Approved					(11.5)
Transportation Initiation Clause
Schedule of Capitalization [Line Items]
Increase (Decrease) in Amount of Regulatory Costs Approved					$ (0.5)
Energy Efficiency Tracker
Schedule of Capitalization [Line Items]
Increase (Decrease) in Amount of Regulatory Costs Approved		$ 2.6		$ (7.6)
Regulatory Costs, Extension Period		2 years
Amount of regulatory costs approved, statewide		$ 36.3
Energy Efficiency Tracker, Over Under Recovery
Schedule of Capitalization [Line Items]
Increase (Decrease) in Amount of Regulatory Costs Approved	$ (1.7)
SHARP
Schedule of Capitalization [Line Items]
Public utilities, approved base rate increase	4.0
Public Utilities, Investment To Be Recovered	36.6
Basic Gas Supply Service And Conservation Incentive Program
Schedule of Capitalization [Line Items]
Increase (Decrease) in Amount of Regulatory Costs Approved	(39.7)
Basic Gas Supply Service
Schedule of Capitalization [Line Items]
Increase (Decrease) in Amount of Regulatory Costs Approved	(28.4)
Conservation Incentive Program
Schedule of Capitalization [Line Items]
Increase (Decrease) in Amount of Regulatory Costs Approved	$ (11.3)
Public Utilities, Colder Than Normal, Percentage	10.40%
Universal Services Fund
Schedule of Capitalization [Line Items]
Increase (Decrease) in Amount of Regulatory Costs Approved	$ 5.2
Amount of regulatory costs approved, statewide	$ 46.4

XML

RELATED-PARTY TRANSACTIONS (Tables)

9 Months Ended

Sep. 30, 2015

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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Operating Revenues/Affiliates:
SJRG	$	1,100	$	169	$	2,631	$	552
Marina	116		278		483		914
Total Operating Revenue/Affiliates	$	1,216	$	447	$	3,114	$	1,466

Related-party transactions, excluding pass-through items, included in Operating Expenses were as follows (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Costs of Sales/Affiliates (Excluding depreciation)
SJRG	$	574	$	1,686		$	21,105	$	8,612
Energy-Related Derivative Losses / (Gains) *
SJRG	$	—	$	(92	)	$	65	$	(1,612	)

* Contracts used to hedge natural gas purchases. Included in Cost of Sales on the Condensed Statements of Income.

Operations Expense/Affiliates:
SJI	$	3,248		$	2,901		$	10,529		$	10,079
Millennium	695			687			2,048			1,982
Other	(95		)	(111		)	(312		)	(327		)
Total Operations Expense/Affiliates	$	3,848		$	3,477		$	12,265		$	11,734

XML

SUBSEQUENT EVENTS (Details) $ in Thousands	Oct. 01, 2015 USD ($)
Subsequent Event
Subsequent Event [Line Items]
Dividends Payable	$ 10,491

XML

FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES - Level Three Inputs (Details) - Natural Gas - Forward Contracts - Level 3 $ in Thousands	Sep. 30, 2015 USD ($) $ / decatherm
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset | $	$ 1,044
Derivative Liability | $	$ 593
Minimum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward price (in dollars per dt)	1.08
Maximum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward price (in dollars per dt)	7.00
Weighted Average
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward price (in dollars per dt)	3.71

XML

FINANCIAL INSTRUMENTS (Details)	1 Months Ended	9 Months Ended
	Jun. 30, 2015 USD ($) term	Sep. 30, 2015 USD ($)	Dec. 31, 2014 USD ($)
Schedule of Financial Instruments [Line Items]
Restricted investments held in escrow		$ 32,200	$ 132,300
Restricted investments, energy-related contracts		6,200,000	7,800,000
Estimated fair value of long-term debt		662,700,000	587,300,000
Long-term Debt		$ 612,900,000	543,000,000
Financing Receivable
Schedule of Financial Instruments [Line Items]
Receivable With Imputed Interest, Term		5 years
Long-term receivables, net of unamortized discount		$ 13,300,000	15,000,000
Imputed interest		$ 1,300,000	$ 1,300,000
Atlantic City Note Receivable
Schedule of Financial Instruments [Line Items]
Receivable with Imputed Interest, Face Amount	$ 10,000,000
Receivable with Imputed Interest, Effective Yield (Interest Rate)	1.00%
Receivable With Imputed Interest, Term	6 months
Receivable With Imputed Interest, Number Of Additional Terms | term	2
Receivable With Imputed Interest, Extension Term	3 months

XML

LONG-TERM DEBT (Details) - USD ($)	1 Months Ended
	Sep. 30, 2015	Aug. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 210,000,000
Long-term Debt	612,900,000		$ 543,000,000
Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200,000,000.00
September 2008 Variable Rate Demand Bonds
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	100,000
Debt Instrument, Face Amount	25,000,000.0
Medium-term Notes | Series Due 2015, 5.387%
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount		$ 10,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.387%
Loans Payable | Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Increase (Decrease), Net	80,000,000
Long-term Debt	$ 139,000,000

XML

STOCK-BASED COMPENSATION PLANS

9 Months Ended

Sep. 30, 2015

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 (collectively, the Plan) of SJI. Restricted performance-based shares issued under the Plan vest over a three-year period and are subject to SJI achieving certain market or earnings-based performance targets as compared to a peer group average, which can cause the actual amount of shares that ultimately vest to range from 0% to 200% of the original share units granted. In 2015, SJI also granted time-based shares of restricted stock, one-third of which vests annually over a three-year period and is limited to 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. In 2015, SJG officers and other key employees were granted 7,878 shares of time-based restricted stock.

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 per share (EPS) growth rate relative to a peer group to measure performance. Beginning in 2015, earning-based performance targets include predefined EPS and return on equity (ROE) goals to measure performance. As EPS-based and ROE-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 Plan, 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, 2015, 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
2013 - TSR	7,974	$	22.19	21.1	%	0.40	%
2013 - EPS	7,974	$	25.59	n/a		n/a
2014 - TSR	10,287	$	21.31	20.0	%	0.80	%
2014 - EPS	10,287	$	27.22	n/a		n/a
2015 - TSR	7,250	$	26.31	16.0	%	1.10	%
2015 - EPS, ROE, Time	18,651	$	29.47	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 2015 and 2014 is approximately $0.1 million per quarter. Of these costs, approximately one half was capitalized to Utility Plant.

As of September 30, 2015, there was $0.8 million of total unrecognized compensation cost related to nonvested share-based compensation awards granted under the Plan. 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, 2015, excluding accrued dividend equivalents:

	Shares		Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, January 1, 2015	36,794		$	24.10
Granted	26,266		$	28.58
Canceled / Forfeited	(637	)	26.71
Nonvested Shares Outstanding, September 30, 2015	62,423		$	25.96

Performance targets during the three-year vesting periods were not attained for the January 2011 grant that vested at December 31, 2013, or the January 2012 grant that vested at December 31, 2014. As a result, no shares were awarded in 2014 or 2015. 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, 2015 and 2014 were approximately $0.2 million and $0.4 million, respectively, relating to stock awards. Additionally, a change in control could result in the nonvested shares becoming nonforfeitable or immediately payable in cash.

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DERIVATIVE INSTRUMENTS (Details) dts in Thousands, $ in Millions	1 Months Ended
	Sep. 30, 2005 USD ($)	Sep. 30, 2015 USD ($) dts	Dec. 31, 2014 USD ($)
Derivative [Line Items]
Unrealized gains (losses) included in its BGSS related to open financial contracts		$ (5.2)	$ (5.6)
Initial cost of Treasury Locks	$ 1.4
Amortization period of Treasury Locks (in years)	30 years
Unamortized balance of Treasury Locks		$ 0.9	$ 1.0
Basis and Index Related Purchase and Sales Contracts
Derivative [Line Items]
Outstanding derivative contracts notional amount (dts) | dts		2,300
Natural Gas (in MMdts) | Derivative Transaction Type, Purchase
Derivative [Line Items]
Outstanding derivative contracts notional amount (dts) | dts		9,100
Natural Gas (in MMdts) | Derivative Transaction Type, Sale
Derivative [Line Items]
Outstanding derivative contracts notional amount (dts) | dts		600

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DERIVATIVE INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 2015

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, 2015 and December 31, 2014, are as follows (in thousands):

Derivatives not designated as hedging instruments under GAAP	September 30, 2015				December 31, 2014
	Assets		Liabilities		Assets		Liabilities
Energy related commodity contracts:
Derivatives – Energy Related – Current	$	1,273	$	6,072	$	2,051	$	6,305
Derivatives – Energy Related – Non-Current	—		397		—		1,298
Interest rate contracts:
Derivatives – Other	—		7,918		—		7,325
Total derivatives not designated as hedging instruments under GAAP	1,273		14,387		2,051		14,928
Total Derivatives	$	1,273	$	14,387	$	2,051	$	14,928

Offsetting assets

As of September 30, 2015, and December 31, 2014, information related to these offsetting arrangements were as follows (in thousands):

As of September 30, 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	$	1,273		$	—	$	1,273		$	(229	)	(A)	$	—	$	1,044
Derivatives - Energy Related Liabilities	(6,469		)	—		(6,469		)	229			(B)	5,462		(778		)
Derivatives - Other	(7,918		)	—		(7,918		)	—				—		(7,918		)

As of December 31, 2014:
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	$	2,051		$	—	$	2,051		$	(2	)	(A)	$	—	$	2,049
Derivatives - Energy Related Liabilities	(7,603		)	—		(7,603		)	2			(B)	7,253		(348		)
Derivatives - Other	(7,325		)	—		(7,325		)	—				—		(7,325		)

(A) The balances at September 30, 2015 and December 31, 2014 were related to derivative liabilities which can be net settled against derivative assets.

(B) The balances at September 30, 2015 and December 31, 2014 were related to derivative assets which can be net settled against derivative liabilities.

Offsetting liabilities

As of September 30, 2015, and December 31, 2014, information related to these offsetting arrangements were as follows (in thousands):

As of September 30, 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	$	1,273		$	—	$	1,273		$	(229	)	(A)	$	—	$	1,044
Derivatives - Energy Related Liabilities	(6,469		)	—		(6,469		)	229			(B)	5,462		(778		)
Derivatives - Other	(7,918		)	—		(7,918		)	—				—		(7,918		)

As of December 31, 2014:
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	$	2,051		$	—	$	2,051		$	(2	)	(A)	$	—	$	2,049
Derivatives - Energy Related Liabilities	(7,603		)	—		(7,603		)	2			(B)	7,253		(348		)
Derivatives - Other	(7,325		)	—		(7,325		)	—				—		(7,325		)

(A) The balances at September 30, 2015 and December 31, 2014 were related to derivative liabilities which can be net settled against derivative assets.

(B) The balances at September 30, 2015 and December 31, 2014 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, 2015 and 2014 are as follows (in thousands):

	Three months ended September 30,						Nine months ended September 30,
Derivatives in Cash Flow Hedging Relationships	2015			2014			2015			2014
Interest Rate Contracts:
Losses reclassified from Accumulated Other Comprehensive Loss into income (a)	$	(12	)	$	(12	)	$	(36	)	$	(36	)

(a) Included in Interest Charges

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FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2015

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, 2015
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	8,528	$	3,407	$	5,121	$	—
Derivatives – Energy Related Assets (B)	1,273		228		1		1,044
	$	9,801	$	3,635	$	5,122	$	1,044
Liabilities
Derivatives – Energy Related Liabilities (B)	$	6,469	$	5,691	$	185	$	593
Derivatives – Other (C)	7,918		—		7,918		—
	$	14,387	$	5,691	$	8,103	$	593

As of December 31, 2014
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	8,894	$	5,924	$	2,970	$	—
Derivatives - Energy Related Assets (B)	2,051		2		2,049		—
	$	10,945	$	5,926	$	5,019	$	—
Liabilities
Derivatives - Energy Related Liabilities (B)	$	7,603	$	7,254	$	349	$	—
Derivatives - Other (C)	7,325		—		7,325		—
	$	14,928	$	7,254	$	7,674	$	—

(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 forwards, 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.

Fair Value Inputs, Assets, Quantitative Information

The following table provides quantitative information regarding significant unobservable inputs in Level 3 fair value measurements (in thousands):

Type	Fair Value at September 30, 2015		Valuation Technique	Significant Unobservable Input	Range [Weighted Average]
	Assets	Liabilities
Forward Contract - Natural Gas	$1,044	$593	Discounted Cash Flow	Forward price (per dt)	$1.08 - $7.00 [$3.71]

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

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	)	$	—
Total unrealized gains included in Regulatory Assets (see note 4)	1,035			451
Balance at end of period	451			451

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DERIVATIVE INSTRUMENTS 2 (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Fair value Derivative Assets	$ 1,273	$ 2,051
Fair value Derivative Liabilities	14,387	14,928
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Fair value Derivative Assets	1,273	2,051
Fair value Derivative Liabilities	14,387	14,928
Commodity Contract
Derivatives, Fair Value [Line Items]
Fair value Derivative Assets	1,273	2,051
Fair value Derivative Liabilities	0	0
Commodity Contract | Not Designated as Hedging Instrument | Derivatives-Energy Related-Current
Derivatives, Fair Value [Line Items]
Fair value Derivative Assets	1,273	2,051
Fair value Derivative Liabilities	6,072	6,305
Commodity Contract | Not Designated as Hedging Instrument | Derivatives-Energy Related-NonCurrent
Derivatives, Fair Value [Line Items]
Fair value Derivative Assets	0	0
Fair value Derivative Liabilities	397	1,298
Interest Rate Contract | Not Designated as Hedging Instrument | Derivatives-Other
Derivatives, Fair Value [Line Items]
Fair value Derivative Assets	0	0
Fair value Derivative Liabilities	$ 7,918	$ 7,325

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ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)

9 Months Ended

Sep. 30, 2015

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, 2015 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, 2015 (a)	$	(13,837	)	$	(558	)	$	(58	)	$	(14,453	)
Other comprehensive loss before reclassifications	—			—			(276		)	(276		)
Amounts reclassified from AOCL (b)	—			6			178			184
Net current period other comprehensive income (loss)	—			6			(98		)	(92		)
Balance at September 30, 2015 (a)	$	(13,837	)	$	(552	)	$	(156	)	$	(14,545	)

	Postretirement Liability Adjustment			Unrealized Gain (Loss) on Derivatives-Other			Unrealized Gain (Loss) on Available-for-Sale Securities			Total
Balance at January 1, 2015 (a)	$	(13,837	)	$	(567	)	$	(75	)	$	(14,479	)
Other comprehensive loss before reclassifications	—			—			(227		)	(227		)
Amounts reclassified from AOCL (b)	—			15			146			161
Net current period other comprehensive income (loss)	—			15			(81		)	(66		)
Balance at September 30, 2015 (a)	$	(13,837	)	$	(552	)	$	(156	)	$	(14,545	)

(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, 2015 are as follows (in thousands):

Components of AOCL	Amounts Reclassified from AOCL (in thousands)						Affected Line Item in the Condensed Statements of Income
	Three Months Ended September 30, 2015			Nine Months Ended September 30, 2015
Unrealized Loss in on Derivatives-Other - Interest Rate Contracts designated as cash flow hedges	$	11		$	35		Interest Charges
Unrealized Loss on Available-for-Sale Securities	298			245			Other Income & Expense
	309			280			Loss Before Income Taxes
Income Taxes (a)	(125		)	(119		)	Income Taxes
Losses from reclassifications for the period net of tax	$	184		$	161

(a) Determined using a combined average statutory tax rate of 40%.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accounting Policies [Abstract]
Amount of Transitional Energy Facility Assessment and Public Utilities Assessment included in revenues and cost of sales	$ 0.2	$ 0.2	$ 1.0	$ 0.8

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2015

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, 2014 for a more complete discussion of our accounting policies and certain other information.

REVENUE AND THROUGHPUT - BASED TAXES - SJG collects certain revenue-based energy taxes from its customers. Such taxes include 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 each of the three month-periods ended September 30, 2015 and 2014, and $1.0 million and $0.8 million for the nine months ended September 30, 2015 and 2014, respectively.

NEW ACCOUNTING PRONOUNCEMENTS — Other than as described below, no new accounting pronouncement issued or effective during 2015 or 2014 had, or is 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 is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

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 February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis, which changes the analysis to be performed in determining whether certain types of legal entities should be consolidated. Specifically, the standard amends the evaluation of whether (a) fees paid to a decision maker or service providers represent a variable interest, (b) a limited partnership or similar entity has the characteristics of a Variable Interest Entity ("VIE") and (c) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods within those annual periods, 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 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. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

Also in April 2015, the FASB issued ASU 2015-5, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40). This ASU provides guidance to customers (1) in determining whether a cloud computing arrangement includes a software license, and (2) on how the arrangement should be accounted for, depending on whether or not it includes a software license. The amended guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

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 August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This ASU states that, given the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements within ASU 2015-03 (defined above), the SEC staff would not object to an entity deferring and presenting such costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of credit arrangement. The adoption of this standard did not have an impact on the companies financial statement results.

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STOCK-BASED COMPENSATION PLANS (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended						9 Months Ended		12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Sep. 30, 2015
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Granted (in shares)							26,266
Shares Outstanding (in shares)	62,423		36,794				36,794		36,794	62,423
Fair Value Per Share (in dollars per share)	$ 25.96		$ 24.10				$ 24.10		$ 24.10	$ 25.96
Expected volatility, measurement period							3 years
Service period of shares							3 years
Cost of Restricted Stock Awards	$ 0.1	$ 0.1	$ 0.1	$ 0.1	$ 0.1	$ 0.1
Restricted stock awards percentage capitalized							50.00%
Unrecognized compensation cost of awards granted under the plan										$ 0.8
Weighted average period over which unrecognized compensation cost is to be recognized (in years)							1 year 10 months 24 days
Shares [Roll Forward]
Nonvested Shares Outstanding, beginning balance (in shares)			36,794				36,794
Granted (in shares)							26,266
Canceled / Forfeited (in shares)							(637)
Nonvested Shares Outstanding, ending balance (in shares)	62,423						62,423		36,794
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, beginning balance (in dollars per share)			$ 24.10				$ 24.10
Weighted Average Grant Date Fair Value, Granted (in dollars per share)							28.58
Weighted Average Grant Date Fair Value, Canceled / Forfeited (in dollars per share)							26.71
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 25.96						$ 25.96		$ 24.10
Number of shares awarded during the period							0		0
Cash payments to SJI relating to stock awards							$ 0.2	$ 0.4
2013 - TSR
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	7,974						7,974			7,974
Fair Value Per Share (in dollars per share)	$ 22.19						$ 22.19			$ 22.19
Expected Volatility							21.10%
Risk-Free Interest Rate							0.40%
Shares [Roll Forward]
Nonvested Shares Outstanding, ending balance (in shares)	7,974						7,974
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 22.19						$ 22.19
2013 - EPS
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	7,974						7,974			7,974
Fair Value Per Share (in dollars per share)	$ 25.59						$ 25.59			$ 25.59
Shares [Roll Forward]
Nonvested Shares Outstanding, ending balance (in shares)	7,974						7,974
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 25.59						$ 25.59
2014 - TSR
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	10,287						10,287			10,287
Fair Value Per Share (in dollars per share)	$ 21.31						$ 21.31			$ 21.31
Expected Volatility							20.00%
Risk-Free Interest Rate							0.80%
Shares [Roll Forward]
Nonvested Shares Outstanding, ending balance (in shares)	10,287						10,287
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 21.31						$ 21.31
2014 - EPS
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	10,287						10,287			10,287
Fair Value Per Share (in dollars per share)	$ 27.22						$ 27.22			$ 27.22
Shares [Roll Forward]
Nonvested Shares Outstanding, ending balance (in shares)	10,287						10,287
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 27.22						$ 27.22
2015 - TSR
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	7,250						7,250			7,250
Fair Value Per Share (in dollars per share)	$ 26.31						$ 26.31			$ 26.31
Expected Volatility							16.00%
Risk-Free Interest Rate							1.10%
Shares [Roll Forward]
Nonvested Shares Outstanding, ending balance (in shares)	7,250						7,250
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 26.31						$ 26.31
2015 - EPS, ROE, Time
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	18,651						18,651			18,651
Fair Value Per Share (in dollars per share)	$ 29.47						$ 29.47			$ 29.47
Shares [Roll Forward]
Nonvested Shares Outstanding, ending balance (in shares)	18,651						18,651
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 29.47						$ 29.47
Restricted Stock
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Vesting period of shares							3 years
Share-based Compensation Arrangement by Share-based Payment Award, Payout Limit, Percentage							100.00%
Share-based Compensation Arrangement by Share-based Payment Award, Return On Equity Award Threshold							7.00%
Granted (in shares)							7,878
Shares [Roll Forward]
Granted (in shares)							7,878
Performance Shares
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Vesting period of shares							3 years
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%

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COMMITMENTS AND CONTINGENCIES (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2015 USD ($) unions	Dec. 31, 2014 USD ($) sites
Loss Contingencies [Line Items]
Letter of credit provided	$ 210,000
Number of sites for environmental cleanup | sites		12
Monthly gas supply related demand charges and reservation fees	6,300
Estimated litigation liability	$ 900	$ 500
Percentage of personnel represented in collective bargaining agreements	61.00%
Number of unions | unions	2
Standby Letter of Credit
Loss Contingencies [Line Items]
Letter of credit provided	$ 25,200
Revolving Credit Facility
Loss Contingencies [Line Items]
Letters of Credit Outstanding, Amount	600
Letter of credit provided	$ 200,000

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CONDENSED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Statement [Abstract]
Operating Revenues	$ 58,634	$ 60,952	$ 402,104	$ 340,656
Operating Expenses:
Cost of Sales (Excluding depreciation)	22,934	23,400	194,455	151,572
Operations	22,786	20,769	80,083	73,181
Maintenance	4,188	3,275	12,114	9,715
Depreciation	10,421	9,342	29,723	27,562
Energy and Other Taxes	806	798	3,080	2,813
Total Operating Expenses	61,135	57,584	319,455	264,843
Operating (Loss) Income	(2,501)	3,368	82,649	75,813
Other Income and Expense	1,010	2,186	3,440	4,749
Interest Charges	(4,809)	(4,046)	(15,112)	(12,680)
Income (Loss) Before Income Taxes	(6,300)	1,508	70,977	67,882
Income Taxes	2,871	(534)	(26,593)	(25,440)
Net (Loss) Income	$ (3,429)	$ 974	$ 44,384	$ 42,442

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DERIVATIVE INSTRUMENTS 3 (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized assets/liabilities	$ 1,273	$ 2,051
Offsetting Derivative Liabilities [Abstract]
Gross amount offset in the balance sheet	14,387	14,928
Commodity Contract
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized assets/liabilities	1,273	2,051
Gross amount offset in the balance sheet	0	0
Net amounts of assets/liabilities in balance sheet	1,273	2,051
Gross amounts not offset in the balance sheet, Financial Instruments	(229)	(2)
Gross amounts not offset in the balance sheet, Cash Collateral Posted	0	0
Net amount	1,044	2,049
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets/liabilities	(6,469)	(7,603)
Gross amount offset in the balance sheet	0	0
Net amounts of assets/liabilities in balance sheet	(6,469)	(7,603)
Gross amounts not offset in the balance sheet, Financial Instruments	229	2
Gross amounts not offset in the balance sheet, Cash Collateral Posted	5,462	7,253
Net amount	(778)	(348)
Other Contract
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets/liabilities	(7,918)	(7,325)
Gross amount offset in the balance sheet	0	0
Net amounts of assets/liabilities in balance sheet	(7,918)	(7,325)
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	$ (7,918)	$ (7,325)

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CONDENSED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Property, Plant and Equipment:
Utility Plant, at original cost	$ 2,151,526	$ 2,002,966
Accumulated Depreciation	(431,327)	(413,597)
Property, Plant and Equipment - Net	1,720,199	1,589,369
Investments:
Available-for-Sale Securities	8,528	8,894
Restricted Investments	6,257	7,961
Total Investments	14,785	16,855
Current Assets:
Cash and Cash Equivalents	1,819	1,778
Note Receivable	9,919	0
Accounts Receivable	81,965	60,535
Accounts Receivable - Related Parties	958	1,157
Unbilled Revenues	10,473	49,910
Provision for Uncollectibles	(9,761)	(6,601)
Natural Gas in Storage, average cost	16,557	25,325
Materials and Supplies, average cost	955	1,104
Deferred Income Taxes - Net	40,006	44,064
Prepaid Taxes	16,656	13,601
Derivatives - Energy Related Assets	1,273	2,051
Other Prepayments and Current Assets	11,494	3,688
Total Current Assets	182,314	196,612
Regulatory and Other Noncurrent Assets:
Regulatory Assets	339,192	357,160
Unamortized Debt Issuance Costs	6,810	7,382
Long-Term Receivables	22,330	15,223
Other	2,673	3,071
Total Regulatory and Other Noncurrent Assets	371,005	382,836
Total Assets	2,288,303	2,185,672
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	250,899	250,899
Accumulated Other Comprehensive Loss	(14,545)	(14,479)
Retained Earnings	462,902	438,300
Total Common Equity	705,104	680,568
Long-Term Debt	584,991	507,091
Total Capitalization	1,290,095	1,187,659
Current Liabilities:
Notes Payable	89,300	101,400
Current Portion of Long-Term Debt	27,909	35,909
Accounts Payable - Commodity	11,789	22,359
Accounts Payable - Other	41,088	32,711
Accounts Payable - Related Parties	6,338	11,249
Derivatives - Energy Related Liabilities	6,072	6,305
Customer Deposits and Credit Balances	20,023	17,626
Environmental Remediation Costs	44,042	28,480
Taxes Accrued	1,693	1,177
Pension Benefits	1,515	1,515
Interest Accrued	4,851	6,099
Other Current Liabilities	3,779	6,580
Total Current Liabilities	258,399	271,410
Regulatory and Other Noncurrent Liabilities:
Regulatory Liabilities	62,461	41,899
Deferred Income Taxes - Net	451,451	435,022
Environmental Remediation Costs	81,424	95,828
Asset Retirement Obligations	42,516	41,976
Pension and Other Postretirement Benefits	86,552	95,241
Investment Tax Credits	37	149
Derivatives - Energy Related Liabilities	397	1,298
Derivatives - Other	7,918	7,325
Other	7,053	7,865
Total Regulatory and Other Noncurrent Liabilities	$ 739,809	$ 726,603
Commitments and Contingencies
Total Capitalization and Liabilities	$ 2,288,303	$ 2,185,672

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REGULATORY ASSETS AND LIABILITIES 2 (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 62,461	$ 41,899
Excess Plant Removal Costs
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	34,040	35,940
Conservation Incentive Program Payable
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	18,616	4,700
Societal Benefit Costs
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	9,805	0
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 0	$ 1,259

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

REVENUE AND THROUGHPUT BASED TAXES

REVENUE AND THROUGHPUT - BASED TAXES - SJG collects certain revenue-based energy taxes from its customers. Such taxes include 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 2015 or 2014 had, or is 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 is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

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 February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis, which changes the analysis to be performed in determining whether certain types of legal entities should be consolidated. Specifically, the standard amends the evaluation of whether (a) fees paid to a decision maker or service providers represent a variable interest, (b) a limited partnership or similar entity has the characteristics of a Variable Interest Entity ("VIE") and (c) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods within those annual periods, 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 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. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

Also in April 2015, the FASB issued ASU 2015-5, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40). This ASU provides guidance to customers (1) in determining whether a cloud computing arrangement includes a software license, and (2) on how the arrangement should be accounted for, depending on whether or not it includes a software license. The amended guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

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 August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This ASU states that, given the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements within ASU 2015-03 (defined above), the SEC staff would not object to an entity deferring and presenting such costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of credit arrangement. The adoption of this standard did not have an impact on the companies financial statement results.

FAIR VALUE

(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 forwards, 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.

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RELATED-PARTY TRANSACTIONS (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Related Party Transaction [Line Items]
Operating Revenues/Affiliates	$ 1,216	$ 447	$ 3,114	$ 1,466
Operations Expense/Affiliates:	3,848	3,477	12,265	11,734
SJRG
Related Party Transaction [Line Items]
Operating Revenues/Affiliates	1,100	169	2,631	552
Costs of Sales/Affiliates (Excluding depreciation)	574	1,686	21,105	8,612
Energy-Related Derivative Losses / (Gains)	0	(92)	65	(1,612)
Marina
Related Party Transaction [Line Items]
Operating Revenues/Affiliates	116	278	483	914
SJI
Related Party Transaction [Line Items]
Operations Expense/Affiliates:	3,248	2,901	10,529	10,079
Millennium
Related Party Transaction [Line Items]
Operations Expense/Affiliates:	695	687	2,048	1,982
Other
Related Party Transaction [Line Items]
Operations Expense/Affiliates:	$ (95)	$ (111)	$ (312)	$ (327)

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REGULATORY ASSETS AND LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2015

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets

Regulatory Assets consisted of the following items (in thousands):

	September 30, 2015		December 31, 2014
Environmental Remediation Costs:
Expended - Net	$	32,797	$	29,540
Liability for Future Expenditures	125,466		124,308
Deferred Asset Retirement Obligation Costs	31,976		31,584
Deferred Pension and Other Postretirement Benefit Costs	99,040		99,040
Deferred Gas Costs - Net	19,187		32,202
Societal Benefit Costs Receivable	—		385
Deferred Interest Rate Contracts (Note 11)	7,918		7,325
Energy Efficiency Tracker	545		11,247
Pipeline Supplier Service Charges	4,192		5,441
Pipeline Integrity Cost	4,544		3,431
AFUDC - Equity Related Deferrals	11,188		10,781
Other Regulatory Assets	2,339		1,876
Total Regulatory Assets	$	339,192	$	357,160

Schedule of Regulatory Liabilities

Regulatory Liabilities consisted of the following items (in thousands):

	September 30, 2015		December 31, 2014
Excess Plant Removal Costs	$	34,040	$	35,940
Conservation Incentive Program Payable	18,616		4,700
Societal Benefit Costs	9,805		—
Other Regulatory Liabilities	—		1,259
Total Regulatory Liabilities	$	62,461	$	41,899

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CONDENSED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Sep. 30, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common Stock, Par Value (in dollars per share)	$ 2.50	$ 2.50
Authorized (in shares)	4,000,000	4,000,000
Outstanding (in shares)	2,339,139	2,339,139

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CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Net (Loss) Income		$ (3,429)	$ 974	$ 44,384	$ 42,442
Other Comprehensive (Loss) Gain - Net of Tax:
Unrealized Loss on Available-for-Sale Securities	[1]	(98)	(613)	(81)	(397)
Unrealized Gain on Derivatives - Other	[1]	6	6	15	21
Other Comprehensive Loss - Net of Tax	[1]	(92)	(607)	(66)	(376)
Comprehensive (Loss) Income		$ (3,521)	$ 367	$ 44,318	$ 42,066

[1] Determined using a combined average statutory tax rate of 40% and 41% in 2015 and 2014, respectively.

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FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES

9 Months Ended

Sep. 30, 2015

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, 2015
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	8,528	$	3,407	$	5,121	$	—
Derivatives – Energy Related Assets (B)	1,273		228		1		1,044
	$	9,801	$	3,635	$	5,122	$	1,044
Liabilities
Derivatives – Energy Related Liabilities (B)	$	6,469	$	5,691	$	185	$	593
Derivatives – Other (C)	7,918		—		7,918		—
	$	14,387	$	5,691	$	8,103	$	593

As of December 31, 2014
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	8,894	$	5,924	$	2,970	$	—
Derivatives - Energy Related Assets (B)	2,051		2		2,049		—
	$	10,945	$	5,926	$	5,019	$	—
Liabilities
Derivatives - Energy Related Liabilities (B)	$	7,603	$	7,254	$	349	$	—
Derivatives - Other (C)	7,325		—		7,325		—
	$	14,928	$	7,254	$	7,674	$	—

(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 forwards, 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, 2015		Valuation Technique	Significant Unobservable Input	Range [Weighted Average]
	Assets	Liabilities
Forward Contract - Natural Gas	$1,044	$593	Discounted Cash Flow	Forward price (per dt)	$1.08 - $7.00 [$3.71]

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	)	$	—
Total unrealized gains included in Regulatory Assets (see note 4)	1,035			451
Balance at end of period	451			451

There were no Derivatives - Energy Related Assets and Liabilities for the three and nine months ended September 30, 2014, using significant unobservable inputs (Level 3).

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DOCUMENT AND ENTITY INFORMATION - shares	9 Months Ended
	Sep. 30, 2015	Nov. 02, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTH JERSEY GAS Co
Entity Central Index Key	0001035216
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		2,339,139

XML

DERIVATIVE INSTRUMENTS

9 Months Ended

Sep. 30, 2015

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, 2015, SJG had outstanding derivative contracts intended to limit the exposure to market risk on 9.1 million decatherms (MMdts) of expected future purchases of natural gas and 0.60 MMdts of expected future sales of natural gas. In addition to these derivative contracts, SJG had basis and index related purchase and sales contracts totaling 2.3 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, 2015 and December 31, 2014, SJG had $5.2 million and $5.6 million of unrealized losses, 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, 2014, 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, 2014. 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 September 30, 2015 and December 31, 2014, the unamortized balance was approximately $0.9 million, and $1.0 million, respectively.

The fair values of all derivative instruments, as reflected in the condensed balance sheets as of September 30, 2015 and December 31, 2014, are as follows (in thousands):

Derivatives not designated as hedging instruments under GAAP	September 30, 2015				December 31, 2014
	Assets		Liabilities		Assets		Liabilities
Energy related commodity contracts:
Derivatives – Energy Related – Current	$	1,273	$	6,072	$	2,051	$	6,305
Derivatives – Energy Related – Non-Current	—		397		—		1,298
Interest rate contracts:
Derivatives – Other	—		7,918		—		7,325
Total derivatives not designated as hedging instruments under GAAP	1,273		14,387		2,051		14,928
Total Derivatives	$	1,273	$	14,387	$	2,051	$	14,928

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, 2015, and December 31, 2014, information related to these offsetting arrangements were as follows (in thousands):

As of September 30, 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	$	1,273		$	—	$	1,273		$	(229	)	(A)	$	—	$	1,044
Derivatives - Energy Related Liabilities	(6,469		)	—		(6,469		)	229			(B)	5,462		(778		)
Derivatives - Other	(7,918		)	—		(7,918		)	—				—		(7,918		)

As of December 31, 2014:
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	$	2,051		$	—	$	2,051		$	(2	)	(A)	$	—	$	2,049
Derivatives - Energy Related Liabilities	(7,603		)	—		(7,603		)	2			(B)	7,253		(348		)
Derivatives - Other	(7,325		)	—		(7,325		)	—				—		(7,325		)

(A) The balances at September 30, 2015 and December 31, 2014 were related to derivative liabilities which can be net settled against derivative assets.

(B) The balances at September 30, 2015 and December 31, 2014 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, 2015 and 2014 are as follows (in thousands):

	Three months ended September 30,						Nine months ended September 30,
Derivatives in Cash Flow Hedging Relationships	2015			2014			2015			2014
Interest Rate Contracts:
Losses reclassified from Accumulated Other Comprehensive Loss into income (a)	$	(12	)	$	(12	)	$	(36	)	$	(36	)

(a) Included in Interest Charges

Net realized loss of $1.6 million and $1.2 million associated with SJG's energy-related financial commodity contracts for the three months ended September 30, 2015 and 2014, respectively, and loss of $6.4 million and gain of $2.4 million for the nine month ended September 30, 2015 and 2014, 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.

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CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Combined statutory tax rate	40.00%	41.00%	40.00%	41.00%

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RELATED-PARTY TRANSACTIONS

9 Months Ended

Sep. 30, 2015

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, 2014. See Note 5 to the Financial Statements in Item 8 of SJG’s Form 10-K for the year ended December 31, 2014 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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Operating Revenues/Affiliates:
SJRG	$	1,100	$	169	$	2,631	$	552
Marina	116		278		483		914
Total Operating Revenue/Affiliates	$	1,216	$	447	$	3,114	$	1,466

Related-party transactions, excluding pass-through items, included in Operating Expenses were as follows (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Costs of Sales/Affiliates (Excluding depreciation)
SJRG	$	574	$	1,686		$	21,105	$	8,612
Energy-Related Derivative Losses / (Gains) *
SJRG	$	—	$	(92	)	$	65	$	(1,612	)

* Contracts used to hedge natural gas purchases. Included in Cost of Sales on the Condensed Statements of Income.

Operations Expense/Affiliates:
SJI	$	3,248		$	2,901		$	10,529		$	10,079
Millennium	695			687			2,048			1,982
Other	(95		)	(111		)	(312		)	(327		)
Total Operations Expense/Affiliates	$	3,848		$	3,477		$	12,265		$	11,734

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REGULATORY ASSETS AND LIABILITIES

9 Months Ended

Sep. 30, 2015

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, 2014, 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, 2014.

Regulatory Assets consisted of the following items (in thousands):

	September 30, 2015		December 31, 2014
Environmental Remediation Costs:
Expended - Net	$	32,797	$	29,540
Liability for Future Expenditures	125,466		124,308
Deferred Asset Retirement Obligation Costs	31,976		31,584
Deferred Pension and Other Postretirement Benefit Costs	99,040		99,040
Deferred Gas Costs - Net	19,187		32,202
Societal Benefit Costs Receivable	—		385
Deferred Interest Rate Contracts (Note 11)	7,918		7,325
Energy Efficiency Tracker	545		11,247
Pipeline Supplier Service Charges	4,192		5,441
Pipeline Integrity Cost	4,544		3,431
AFUDC - Equity Related Deferrals	11,188		10,781
Other Regulatory Assets	2,339		1,876
Total Regulatory Assets	$	339,192	$	357,160

DEFERRED GAS COSTS - NET - Over/under collections of gas costs are monitored through SJG's Basic Gas Supply Service (BGSS) mechanism. Net undercollected gas costs are classified as a regulatory asset and net overcollected 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 reduction in deferred gas costs from December 31, 2014 was due to gas costs recovered from customers exceeding the actual cost of the commodity incurred during 2015 as a result of lower natural gas prices and an increase in the BGSS rate effective October 2014. SJG's BGSS mechanism is designed to overcollect gas costs during the winter season when usage is highest.

ENERGY EFFICIENCY TRACKER - This regulatory asset primarily represents energy efficiency measures installed in customer homes and businesses. The decrease from December 31, 2014 is due to higher recoveries in the first nine months of 2015 resulting from extremely cold weather during the first half of the year.

Regulatory Liabilities consisted of the following items (in thousands):

	September 30, 2015		December 31, 2014
Excess Plant Removal Costs	$	34,040	$	35,940
Conservation Incentive Program Payable	18,616		4,700
Societal Benefit Costs	9,805		—
Other Regulatory Liabilities	—		1,259
Total Regulatory Liabilities	$	62,461	$	41,899

EXCESS PLANT REMOVAL COSTS - Represents amounts accrued in excess of actual utility plant removal costs incurred to date. The decrease in the balance from year end is due to an amortization as a credit to depreciation expense, as required as part of our September 2014 base rate increase.

CONSERVATION INCENTIVE PROGRAM (CIP) PAYABLE – 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 greater than the established baseline during 2014 and more notably during the first nine months of 2015, resulting in a payable. This is primarily the result of extremely cold weather experienced in the region during the first half of the year.

SOCIETAL BENEFIT COSTS (SBC) - This regulatory liability primarily represents the excess recoveries over the expenses incurred under the New Jersey Clean Energy Program which is a mechanism designed to recover costs associated with energy efficiency and renewable energy programs. The change from a $0.4 million regulatory asset to a $9.8 million regulatory liability is due to current SBC rates, which are producing recoveries greater than SBC costs. In July 2014, SJG made its annual 2014-2015 SBC filing requesting a decrease in SBC revenues, in part, to avoid this liability. The petition was approved and new rates went into effect on June 1, 2015.

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STOCK-BASED COMPENSATION PLANS (Tables)

9 Months Ended

Sep. 30, 2015

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, 2015, 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
2013 - TSR	7,974	$	22.19	21.1	%	0.40	%
2013 - EPS	7,974	$	25.59	n/a		n/a
2014 - TSR	10,287	$	21.31	20.0	%	0.80	%
2014 - EPS	10,287	$	27.22	n/a		n/a
2015 - TSR	7,250	$	26.31	16.0	%	1.10	%
2015 - EPS, ROE, Time	18,651	$	29.47	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, 2015, excluding accrued dividend equivalents:

	Shares		Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, January 1, 2015	36,794		$	24.10
Granted	26,266		$	28.58
Canceled / Forfeited	(637	)	26.71
Nonvested Shares Outstanding, September 30, 2015	62,423		$	25.96

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LONG-TERM DEBT

9 Months Ended

Sep. 30, 2015

Long-term Debt, Unclassified [Abstract]

LONG-TERM DEBT

LONG-TERM DEBT:

In August, SJG retired $10.0 million aggregate principal amount of 5.387% medium term notes (MTN's) at maturity.

In September, SJG issued $80.0 million of long-term debt under a $200.00 million aggregate syndicated bank term facility. The total outstanding amount under this facility as of September 30, 2015 was $139.0 million.

Also in September, SJG redeemed early $100,000 of the $25.0 million aggregate principal amount variable rate demand bonds that were issued in September 2008. SJG had previously spent all but $100,000 of the debt proceeds and was permitted under the debt agreement to utilize those remaining funds to redeem the debt early.

We retire debt when it is cost effective as permitted by the debt agreements.

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PENSION AND OTHER POSTRETIREMENT BENEFITS

9 Months Ended

Sep. 30, 2015

Compensation and Retirement Disclosure [Abstract]

PENSION AND OTHER POSTRETIREMENT BENEFITS

PENSION AND OTHER POSTRETIREMENT BENEFITS:

For the three and nine months ended  September 30, 2015 and 2014, 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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Service Cost	$	996		$	536		$	2,988		$	2,468
Interest Cost	2,083			1,819			6,251			5,873
Expected Return on Plan Assets	(2,759		)	(2,233		)	(8,278		)	(7,143		)
Amortizations:
Prior Service Cost	40			30			119			96
Actuarial Loss	1,979			957			5,938			3,101
Net Periodic Benefit Cost	2,339			1,109			7,018			4,395
Capitalized Benefit Cost	(1,216		)	(577		)	(3,649		)	(2,285		)
Deferred Benefit Cost	(341		)	—			(666		)	—
Total Net Periodic Benefit Expense	$	782		$	532		$	2,703		$	2,110

	Other Postretirement Benefits						Other Postretirement Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Service Cost	$	186		$	28		$	558		$	372
Interest Cost	495			171			1,486			1,191
Expected Return on Plan Assets	(499		)	(202		)	(1,496		)	(1,148		)
Amortizations:
Prior Service Cost	102			11			304			63
Actuarial Loss	224			73			671			407
Net Periodic Benefit Cost	508			81			1,523			885
Capitalized Benefit Cost	(264		)	(42		)	(792		)	(460		)
Deferred Benefit Cost	(89		)	—			(168		)	—
Total Net Periodic Benefit Expense	$	155		$	39		563			425

Capitalized benefit cost 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 (RP-2014 base table with MP-2014 generational projection scale) in 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 2014. Payments related to the unfunded Supplemental Executive Retirement Plan (SERP) are expected to approximate $1.5 million in 2015. 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 Form 10-K for the year ended December 31, 2014 for additional information related to SJG’s pension and other postretirement benefits.

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FINANCIAL INSTRUMENTS

9 Months Ended

Sep. 30, 2015

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 September 30, 2015 and December 31, 2014, the escrowed proceeds, including interest earned, totaled $32,200 and $132,300, respectively. 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, 2015 and December 31, 2014, the balance held with this counterparty totaled $6.2 million and $7.8 million, respectively. The carrying amounts of the Restricted Investments approximate their fair value at September 30, 2015 and December 31, 2014, 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 bears 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. SJG holds a first lien security interest on land in Atlantic City as collateral against this note.

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 years with no interest. The carrying amounts of such loans were $13.3 million and $15.0 million as of September 30, 2015 and December 31, 2014, 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 $1.3 million as of both September 30, 2015 and December 31, 2014. 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, 2015 and December 31, 2014, 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, 2015 and December 31, 2014, 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, 2015 and December 31, 2014, were $662.7 million and $587.3 million, respectively. The carrying amount of SJG's long-term debt, including current maturities, as of September 30, 2015 and December 31, 2014, was $612.9 million and $543.0 million, respectively .

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LINES OF CREDIT

9 Months Ended

Sep. 30, 2015

Line of Credit Facility [Abstract]

LINES OF CREDIT

LINES OF CREDIT:

Credit facilities and available liquidity as of September 30, 2015 were as follows (in thousands):

	Total Facility		Usage			Available Liquidity		Expiration Date
Commercial Paper Program/ Revolving Credit Facility	$	200,000	$	89,900	(A)	$	110,100	May 2018
Uncommitted Bank Lines	10,000		—			10,000		Various
Total	$	210,000	$	89,900	(A)	$	120,100

(A) Includes letters of credit outstanding in the amount of $0.6 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, 2015.

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, 2015 and 2014 were $117.9 million and $40.9 million, respectively. The maximum amount outstanding under these credit facilities during the nine months ended September 30, 2015 and 2014 were $162.3 million and $70.1 million, respectively.

Borrowings under these credit facilities are at market rates. The weighted average interest rate on these borrowings, which changes daily, was 0.40% and 0.26% at September 30, 2015 and 2014, respectively.

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES:

STANDBY LETTER OF CREDIT - SJG provided a $0.6 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. There have been no significant changes to the status of SJG’s environmental remediation efforts since December 31, 2014, as described in Note 12 to the Financial Statements in Item 8 of SJG’s Form 10-K for the year ended December 31, 2014.

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 so in accordance with their respective FERC-approved tariff. Our cumulative obligation for gas supply-related demand charges and reservation fees paid for these services averages approximately $6.3 million per month and is recovered on a current basis through the BGSS.

PENDING LITIGATION - We are subject to claims arising in the ordinary course of business and other legal proceedings. We accrue liabilities related to these claims when we can reasonably estimate the amount or range of amounts of probable settlement costs or other charges for these claims. The Company has accrued approximately $0.9 million and $0.5 million related to all claims in the aggregate as of September 30, 2015 and December 31, 2014, respectively. Management does not believe that it is reasonably possible that there will be a material change in the Company's estimated liability in the near term and does not currently anticipate the disposition of any known claims that would have a material effect on the Company's financial position, results of operations or cash flows.

COLLECTIVE BARGAINING AGREEMENTS - Unionized personnel represent approximately 61% of our workforce at September 30, 2015. 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.

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REGULATORY ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 339,192	$ 357,160
Environmental Remediation Costs: Expended - Net
Regulatory Assets [Line Items]
Total Regulatory Assets	32,797	29,540
Environmental Remediation Costs: Liability for Future Expenditures
Regulatory Assets [Line Items]
Total Regulatory Assets	125,466	124,308
Deferred Asset Retirement Obligation Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	31,976	31,584
Deferred Pension and Other Postretirement Benefit Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	99,040	99,040
Deferred Gas Costs - Net
Regulatory Assets [Line Items]
Total Regulatory Assets	19,187	32,202
Societal Benefit Costs Receivable
Regulatory Assets [Line Items]
Total Regulatory Assets	0	385
Deferred Interest Rate Contracts
Regulatory Assets [Line Items]
Total Regulatory Assets	7,918	7,325
Energy Efficiency Tracker
Regulatory Assets [Line Items]
Total Regulatory Assets	545	11,247
Pipeline Supplier Service Charges
Regulatory Assets [Line Items]
Total Regulatory Assets	4,192	5,441
Pipeline Integrity Cost
Regulatory Assets [Line Items]
Total Regulatory Assets	4,544	3,431
AFUDC - Equity Related Deferrals
Regulatory Assets [Line Items]
Total Regulatory Assets	11,188	10,781
Other Regulatory Assets
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 2,339	$ 1,876

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SUBSEQUENT EVENTS

9 Months Ended

Sep. 30, 2015

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS:

On October 1, 2015, the Board of Directors of SJG declared a cash dividend of $10,491,000 payable to SJI. The dividend was paid on October 2, 2015.

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LINES OF CREDIT (Tables)

9 Months Ended

Sep. 30, 2015

Line of Credit Facility [Abstract]

Schedule of lines of credit

Credit facilities and available liquidity as of September 30, 2015 were as follows (in thousands):

	Total Facility		Usage			Available Liquidity		Expiration Date
Commercial Paper Program/ Revolving Credit Facility	$	200,000	$	89,900	(A)	$	110,100	May 2018
Uncommitted Bank Lines	10,000		—			10,000		Various
Total	$	210,000	$	89,900	(A)	$	120,100

(A) Includes letters of credit outstanding in the amount of $0.6 million.

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ACCUMULATED OTHER COMPREHENSIVE LOSS 2 (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Interest Charges	$ 4,809	$ 4,046	$ 15,112	$ 12,680
Other Income & Expense	(1,010)	(2,186)	(3,440)	(4,749)
Loss Before Income Taxes	6,300	(1,508)	(70,977)	(67,882)
Income Taxes	(2,871)	534	26,593	25,440
Net Income	3,429	$ (974)	(44,384)	$ (42,442)
Reclassification out of Accumulated Other Comprehensive Income
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Loss Before Income Taxes	309		280
Income Taxes	(125)		(119)
Net Income	184		161
Reclassification out of Accumulated Other Comprehensive Income | Unrealized Loss in on Derivatives-Other - Interest Rate Contracts designated as cash flow hedges
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Interest Charges	11		35
Reclassification out of Accumulated Other Comprehensive Income | Unrealized Loss on Available-for-Sale Securities
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Income & Expense	$ 298		$ 245

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FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015	Dec. 31, 2014
Fair Value, Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ (584)	$ 0
Total unrealized gains included in Regulatory Assets	1,035	451
Balance at end of period	451	451
Fair Value, Measurements, Recurring
Assets
Available-for-sale Securities	8,528	8,528	$ 8,894
Derivatives - Energy Related Assets	1,273	1,273	2,051
Total Assets	9,801	9,801	10,945
Liabilities
Derivatives - Energy Related Liabilities	6,469	6,469	7,603
Derivatives - Other	7,918	7,918	7,325
Total Liabilities	14,387	14,387	14,928
Fair Value, Measurements, Recurring | Level 1
Assets
Available-for-sale Securities	3,407	3,407	5,924
Derivatives - Energy Related Assets	228	228	2
Total Assets	3,635	3,635	5,926
Liabilities
Derivatives - Energy Related Liabilities	5,691	5,691	7,254
Derivatives - Other	0	0	0
Total Liabilities	5,691	5,691	7,254
Fair Value, Measurements, Recurring | Level 2
Assets
Available-for-sale Securities	5,121	5,121	2,970
Derivatives - Energy Related Assets	1	1	2,049
Total Assets	5,122	5,122	5,019
Liabilities
Derivatives - Energy Related Liabilities	185	185	349
Derivatives - Other	7,918	7,918	7,325
Total Liabilities	8,103	8,103	7,674
Fair Value, Measurements, Recurring | Level 3
Assets
Available-for-sale Securities	0	0	0
Derivatives - Energy Related Assets	1,044	1,044	0
Total Assets	1,044	1,044	0
Liabilities
Derivatives - Energy Related Liabilities	593	593	0
Derivatives - Other	0	0	0
Total Liabilities	$ 593	$ 593	$ 0

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Statement of Cash Flows [Abstract]
Net Cash Provided by Operating Activities	$ 124,750	$ 55,242
Cash Flows from Investing Activities:
Capital Expenditures	(147,276)	(139,393)
Note Receivable	(9,919)	0
Net Sale (Purchase) of Restricted Investments in Margin Accounts	1,603	(1,391)
Net Sale of Restricted Investments from Escrowed Loan Proceeds	101	0
Investment in Long-Term Receivables	(13,784)	(4,881)
Proceeds from Long-Term Receivables	6,556	5,075
Net Cash Used in Investing Activities	(162,719)	(140,590)
Cash Flows from Financing Activities:
Net Repayments of Short-Term Credit Facilities	(12,100)	(6,200)
Proceeds from Issuance of Long-Term Debt	80,000	89,000
Principal Repayments of Long-Term Debt	(10,100)	(21,000)
Payments for Issuance of Long-Term Debt	(8)	(627)
Dividends on Common Stock	(19,782)	0
Additional Investment by Shareholder	0	25,000
Net Cash Provided by Financing Activities	38,010	86,173
Net Increase in Cash and Cash Equivalents	41	825
Cash and Cash Equivalents at Beginning of Period	1,778	2,020
Cash and Cash Equivalents at End of Period	$ 1,819	$ 2,845

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RATES AND REGULATORY ACTIONS

9 Months Ended

Sep. 30, 2015

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 May 2015, the BPU approved an $18.2 million decrease in annual revenues collected from customers through the Societal Benefits Clause ("SBC") charge and the Transportation Initiation Clause ("TIC") charge, comprised of a $6.2 million decrease in revenues from the Remediation Adjustment Clause (“RAC”) component of the SBC, an $11.5 million decrease in revenues from the Clean Energy Program (“CLEP”) component of the SBC and a $0.5 million decrease in TIC revenues, effective June 1, 2015. The decreases in the RAC and CLEP components of the SBC are primarily driven by the accumulation of prior year over-recoveries, as rate recovery exceeded program costs. The decrease in the TIC is being caused by a decrease in costs. The SBC and TIC allow SJG to recover costs associated with certain State-mandated programs.

In June 2015, SJG filed its annual Energy Efficiency Tracker (“EET”) rate adjustment petition, requesting a $7.6 million decrease in revenues to continue recovering the costs of, and the allowed return on, prior investments associated with energy efficiency programs ("EEPs"). SJG's original EEPs, approved by the BPU in 2009, and its EEP extension, approved by the BPU in 2013, ended in July 2013 and June 2015, respectively. The revenue requirements associated with these prior investments decrease over time as they are amortized and recovered. Also contributing to the revenue decrease is the forecasted October 2015 over-recovery of $1.7 million, which further reduces the revenue requirement for the upcoming EET year. This petition is currently pending.

In August 2015, the BPU approved a two year extension of the Company’s EEPs through August 31, 2017, with a program budget of $36.3 million. SJG will recover the costs of these programs, and earn an allowed return on its investments, through the EET rate recovery mechanism that has been utilized for its EEPs since 2009. The BPU’s approval also permitted SJG to adjust its EET rate effective September 1, 2015 to increase annual revenues by $2.6 million to recover the projected costs of, and the allowed return on, the first year of its investments in the EEPs.

In September 2015, the BPU approved SJG’s request, related to its Storm Hardening and Reliability Program (“SHARP”), to increase annual revenues from base rates by $4.0 million to reflect approximately $36.6 million of investments made for storm hardening efforts for the period July 2014 through June 2015. This base rate adjustment became effective on October 1, 2015.

Also in September 2015, the BPU approved the Company’s annual Basic Gas Supply Service (“BGSS”) and Conservation Incentive Program (“CIP”) rate adjustment petition, which requested a $39.7 million decrease in annual revenues to be implemented on October 1, 2015, comprised of a $28.4 million decrease in BGSS revenues and an $11.3 million decrease in CIP revenues. The level of BGSS revenues is based on forecasted gas costs and customer usage information for the upcoming BGSS/CIP year, which runs from October to September. SJG’s request is based on decreases in forecasted gas commodity costs for the upcoming BGSS/CIP year. The decrease in CIP revenues is caused primarily by higher than normal customer usage caused by weather that was 10.4% colder than normal during the 2014-2015 winter season.

Additionally, in September 2015, the BPU approved the statewide Universal Service Fund (“USF”) budget of $46.4 million for all the State’s gas utilities. SJG’s portion of the total budget is approximately $5.2 million. Effective October 1, 2015, the BPU approved a $3.4 million decrease to SJG’s USF recoveries.

The BGSS, CIP and USF revenue decreases noted above do not impact SJG's earnings. They represent decreases in the cash requirements of the Company corresponding to lower costs and/or the return of previously over-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, 2014. See Note 3 to the Financial Statements in Item 8 of SJG's Form 10-K for the year ended December 31, 2014.

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PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)

9 Months Ended

Sep. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Schedule of defined benefit plans disclosures

For the three and nine months ended  September 30, 2015 and 2014, 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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Service Cost	$	996		$	536		$	2,988		$	2,468
Interest Cost	2,083			1,819			6,251			5,873
Expected Return on Plan Assets	(2,759		)	(2,233		)	(8,278		)	(7,143		)
Amortizations:
Prior Service Cost	40			30			119			96
Actuarial Loss	1,979			957			5,938			3,101
Net Periodic Benefit Cost	2,339			1,109			7,018			4,395
Capitalized Benefit Cost	(1,216		)	(577		)	(3,649		)	(2,285		)
Deferred Benefit Cost	(341		)	—			(666		)	—
Total Net Periodic Benefit Expense	$	782		$	532		$	2,703		$	2,110

	Other Postretirement Benefits						Other Postretirement Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Service Cost	$	186		$	28		$	558		$	372
Interest Cost	495			171			1,486			1,191
Expected Return on Plan Assets	(499		)	(202		)	(1,496		)	(1,148		)
Amortizations:
Prior Service Cost	102			11			304			63
Actuarial Loss	224			73			671			407
Net Periodic Benefit Cost	508			81			1,523			885
Capitalized Benefit Cost	(264		)	(42		)	(792		)	(460		)
Deferred Benefit Cost	(89		)	—			(168		)	—
Total Net Periodic Benefit Expense	$	155		$	39		563			425

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LINES OF CREDIT (Details)	9 Months Ended
	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)
Line of Credit Facility [Line Items]
Total Facility	$ 210,000,000
Usage	89,900,000
Available Liquidity	120,100,000
Average borrowings outstanding during the period	117,900,000	$ 40,900,000
Maximum amounts outstanding during the period	$ 162,300,000	$ 70,100,000
Weighted average borrowing cost	0.40%	0.26%
Minimum
Line of Credit Facility [Line Items]
Financial covenant, ratio of indebtedness to consolidated total capitalization minimum	0.65
Revolving Credit Facility
Line of Credit Facility [Line Items]
Total Facility	$ 200,000,000
Usage	89,900,000
Available Liquidity	110,100,000
Letters of Credit Outstanding, Amount	600,000
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

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ACCUMULATED OTHER COMPREHENSIVE LOSS

9 Months Ended

Sep. 30, 2015

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, 2015 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, 2015 (a)	$	(13,837	)	$	(558	)	$	(58	)	$	(14,453	)
Other comprehensive loss before reclassifications	—			—			(276		)	(276		)
Amounts reclassified from AOCL (b)	—			6			178			184
Net current period other comprehensive income (loss)	—			6			(98		)	(92		)
Balance at September 30, 2015 (a)	$	(13,837	)	$	(552	)	$	(156	)	$	(14,545	)

	Postretirement Liability Adjustment			Unrealized Gain (Loss) on Derivatives-Other			Unrealized Gain (Loss) on Available-for-Sale Securities			Total
Balance at January 1, 2015 (a)	$	(13,837	)	$	(567	)	$	(75	)	$	(14,479	)
Other comprehensive loss before reclassifications	—			—			(227		)	(227		)
Amounts reclassified from AOCL (b)	—			15			146			161
Net current period other comprehensive income (loss)	—			15			(81		)	(66		)
Balance at September 30, 2015 (a)	$	(13,837	)	$	(552	)	$	(156	)	$	(14,545	)

(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, 2015 are as follows (in thousands):

Components of AOCL	Amounts Reclassified from AOCL (in thousands)						Affected Line Item in the Condensed Statements of Income
	Three Months Ended September 30, 2015			Nine Months Ended September 30, 2015
Unrealized Loss in on Derivatives-Other - Interest Rate Contracts designated as cash flow hedges	$	11		$	35		Interest Charges
Unrealized Loss on Available-for-Sale Securities	298			245			Other Income & Expense
	309			280			Loss Before Income Taxes
Income Taxes (a)	(125		)	(119		)	Income Taxes
Losses from reclassifications for the period net of tax	$	184		$	161

(a) Determined using a combined average statutory tax rate of 40%.