10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2013

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, New Jersey 08037

(Address of principal executive offices, including zip code)

(609) 561-9000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:     Yes o      No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Act:     Yes o     No x

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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

All of the equity securities of the registrant are owned by South Jersey Industries, Inc., its parent company, a 1934 Act reporting company named in the registrants description of its business, which has itself fulfilled its 1934 Act filing requirements.

The registrant meets all of the conditions set forth in General Instruction I 1(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format.

Documents Incorporated by Reference:   None

TABLE OF CONTENTS

		Page No.
Forward-Looking Statements		4
	PART I
Item 1.	Business	5
Item 1A.	Risk Factors	8
Item 1B.	Unresolved Staff Comments	10
Item 2.	Properties	11
Item 3.	Legal Proceedings	11
Item 4.	Mine Safety Disclosures	11
	PART II
Item 5.	Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	11
Item 6.	Selected Financial Data	12
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	13
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	26
Item 8.	Financial Statements and Supplementary Data	28
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	69
Item 9A.	Controls and Procedures	69
Item 9B.	Other Information	69
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	69
Item 11.	Executive Compensation	69
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	69
Item 13.	Certain Relationships and Related Transactions, and Director Independence	70
Item 14.	Principal Accountant Fees and Services	70
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	71
Signatures		76
Financial Statement Schedules		77

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Forward Looking Statements

Certain statements contained in this Annual Report on form 10-K 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 South Jersey Gas (SJG or the Company) and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of the Company’s documents or oral presentations, 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 risks set forth under “Risk Factors” in Part I, Item 1A of this Annual Report on Form 10-K and elsewhere throughout this Report. These cautionary statements should not be construed by you to be exhaustive and they are made only as of the date of this Report. While the Company 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.

Available Information- Information regarding SJG can be found at the South Jersey Industries, Inc. (SJI) internet address, www.sjindustries.com. We make available free of charge on or through our website SJG’s annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (SEC). The SEC maintains an Internet site that contains these reports at http://www.sec.gov. The content on any web site referred to in this filing is not incorporated by reference into this filing unless expressly noted otherwise.

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PART I

Item 1. Business

Units of Measurement

For Natural Gas:
1 dt	= One decatherm
1 MMdt	= One million decatherms
Dts/d	= Decatherms per day
MDWQ	= Maximum daily withdrawal quantity

Description of Business

South Jersey Gas Company (SJG) is a regulated natural gas utility. SJG distributes natural gas in the seven southernmost counties of New Jersey.

Additional information on the nature of our business is incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Market Risk” and Note 3, “Rates and Regulatory Actions.”

Financial Information About Reportable Segments

Not applicable.

Rates and Regulation

Information on our rates and regulatory affairs is incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Note 3, “Rates and Regulatory Actions.”

Sources and Availability of Raw Materials

Transportation and Storage Agreements

SJG has direct connections to the interstate pipeline systems of both Transcontinental Gas Pipe Line Company, LLC (Transco) and Columbia Gas Transmission, LLC (Columbia). During 2013, SJG purchased and had delivered approximately 41.0 million decatherms (MMdts) of natural gas for distribution to both on-system and off-system customers and for injections into storage. Of this total, 23.8 MMdts were transported on the Transco pipeline system while 17.2 MMdts were transported on the Columbia pipeline system. Moreover, during 2013 third-party suppliers delivered 32.6 MMdts to SJG's system on behalf of end use customers behind our city gate stations. SJG also secures other long-term services from one additional pipeline upstream of the Transco and Columbia systems. This upstream pipeline is owned by Dominion Transmission, Inc. (Dominion). Services provided by Dominion are utilized to deliver gas into either the Transco or Columbia systems for ultimate delivery to SJG. Services provided by all of the above-mentioned pipelines are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).  Unless otherwise indicated, our intentions are to renew or extend these service agreements before they expire.

Transco:

Transco is SJG’s largest supplier of long-term gas transmission services which includes both year-round and seasonal firm transportation (FT) service arrangements. When combined, these FT services enable SJG to purchase gas from third parties and have delivered to its city gate stations by Transco a total of 297,958 dts per day (dts/d). Of this total, 133,917 dts/d is long-haul FT (where gas can be transported from the production areas of the Southwest to the market areas of the Northeast) while 164,041 dts/d is market area FT. The terms of SJG’s year-round agreements extend for various periods through 2025. SJG's seasonal agreements are currently operating under their respective evergreen provisions.

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Of the 297,958 dts/d of Transco services mentioned above, SJG has released a total of 39,800 dts/d of its long-haul FT and 49,041 dts/d of its market area FT service. These releases were made in association with SJG’s Conservation Incentive Program (CIP) discussed further under Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations."  In addition, SJG released 45,000 dts/d of its long-haul FT and 10,000 dts/d of market area FT as part of Asset Management Agreements (AMA). The AMA-related releases are discussed below under “Gas Supplies.”

SJG currently has six (6) long-term gas storage service agreements with Transco that, when combined, are capable of storing approximately 5.0 MMdts. Through these agreements, SJG can inject gas into market and production area storages during periods of low demand and extract gas at a Maximum Daily Withdrawal Quantity (MDWQ) of up to 107,407 dts during periods of high demand. The longest term of these storage service agreements extends through March 31, 2023.

Dominion:

SJG subscribes to a firm storage service from Dominion, under its Rate Schedule GSS.  This storage has a MDWQ of 10,000 dts during the period between November 16 and March 31 of each winter season, with an associated total storage capacity of 423,000 dts.  Gas withdrawn from Dominion GSS storage is delivered through both the Dominion and Transco (Leidy Line) pipeline systems for delivery to SJG service territory.  The primary term of this agreement extends through March 31, 2015. SJG has released this service under an AMA as discussed below under "Gas Supplies."

Columbia:

SJG subscribes to three firm transportation agreements with Columbia which provides for 54,022 dts/d of firm deliverability with 45,022 dts/d of this deliverability extending through October 31, 2019.   The remaining 9,000 dts per day had a primary term of one year which extended from November 1, 2011 through October 31, 2012. The agreement is subject to pre-granted abandonment upon its termination, with SJG having the right of first refusal to extend the agreement. By way of an agreement dated July 19, 2013, this service was extended through October 31, 2014. SJG had previously released 14,714 dts/d of this amount to South Jersey Resources Group, LLC (SJRG), an affiliate by common ownership, in conjunction with its CIP thereby reducing the combined availability of firm transportation on the Columbia system to 39,308 dts/d.

SJG also subscribes to a firm storage service with Columbia under its Rate Schedule FSS along with an associated firm transportation service under Rate Schedule SST, each of which extends through October 31, 2019. The Company has a total FSS MDWQ of 52,891 dts and a related 3,473,022 dts of storage capacity. SJG released to SJRG 19,029 dts of its FSS MDWQ along with 1,249,485 dts of its FSS storage capacity. Additionally, SJG released to SJRG 19,029 dts/d of its Columbia SST transportation service. Both releases made by SJG were in connection with its CIP and extend through September 30, 2014.

Gas Supplies

In 2013, SJG entered into an AMA with a gas marketer which extends through March 31, 2014. Under this agreement SJG released to the marketer its firm transportation rights equal to 30,000 dts/d of transportation capacity on Transco. The marketer manages this capacity and provides SJG with up to 30,000 dts/d of firm deliverability each day during the period November 1, 2013 through March 31, 2014. The marketer will seek to optimize the capacity released to it under this AMA and pay SJG a monthly Asset Management Fee in consideration for same.

Also during 2013, SJG entered into an AMA with a gas marketer which extends through October 31, 2014. Under this agreement SJG has released to the marketer its firm transportation rights equal to 15,000 dts/d of transportation capacity on Transco. The marketer manages this capacity and provides SJG with up to 15,000 dts/d of firm deliverability each day through October 31, 2014. The marketer will seek to optimize the capacity released to it under this AMA and pay SJG a one time Asset Management Fee in consideration for same.

Also in 2013, SJG entered into an AMA with a gas marketer which extends through March 31, 2014. Under this agreement SJG released its GSS storage capacity and deliverability held on the Dominion pipeline system to the marketer equal to 423,000 dts of storage capacity and 10,000 dts/d of deliverability on both the Dominion and Transco Leidy Line systems. The marketer manages this capacity and provides SJG with right to call on up to 10,000 dts/d into Transco’s Leidy Line for the period from November 1, 2013 through March 31, 2014. The marketer will seek to optimize the storage capacity released to it under this AMA and pay SJG a one time Asset Management Fee in consideration for same.

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In 2011, SJG entered into a long-term gas purchase agreement with a gas producer, the primary term of which extends through October 31, 2019. The maximum daily quantities (MDQ) available for purchase under this agreement initially starts at 6,250 dts/d and ratchets up to a MDQ of 25,000 dts/d. Gas purchased from this producer will be sourced in the Appalachian supply areas and delivered into the Columbia pipeline system for delivery to SJG.

As part of its gas purchasing strategy, SJG uses financial contracts to hedge against forward price risk. These contracts are recoverable through SJG’s BGSS, subject to BPU approval.

Supplemental Gas Supplies

SJG is utilizing an option inherent in its Transco’s Liquefied Natural Gas (LNG) storage service, which permits the withdrawal of gas as liquid (and/or vapor), as a supply source to replenish its LNG inventory in McKee City during the 2013-2014 winter season.

SJG operates peaking facilities which can store and vaporize LNG for injection into its distribution system. SJG’s LNG facility has a storage capacity equivalent to 434,300 dts of natural gas and has an installed capacity to vaporize up to 118,250 dts of LNG per day for injection into its distribution system.

Peak-Day Supply

SJG plans for a winter season peak-day demand on the basis of an average daily temperature of 2 degrees Fahrenheit (F). Gas demand on such a design day for the 2013-2014 winter season is estimated to be 486,110 dts (excluding industrial customers). SJG projects that it has adequate supplies and interstate pipeline entitlements to meet its design requirements. SJG experienced its highest peak-day demand for calendar year 2013 of 437,189 dts on January 22nd, while experiencing an average temperature of 17.3 degrees F that day.

Natural Gas Prices

SJG’s average cost of natural gas purchased and delivered in calendar years 2013, 2012 and 2011, including demand charges, was $4.81 per dt, $4.73 per dt and $6.11 per dt, respectively.

Patents and Franchises

SJG holds nonexclusive franchises granted by municipalities in the seven-county area of southern New Jersey that it serves. No other natural gas public utility presently serves the territory covered by SJG’s franchises. Otherwise, patents, trademarks, licenses, franchises and concessions are not material to the business of SJG.

Seasonal Aspects

SJG experiences seasonal fluctuations in sales when selling natural gas for heating purposes. SJG meets this seasonal fluctuation in demand from its firm customers by buying and storing gas during the summer months, and by drawing from storage and purchasing supplemental supplies during the heating season. As a result of this seasonality, SJG’s revenues and net income are significantly higher during the first and fourth quarters than during the second and third quarters of the year.

Working Capital Practices

Reference is made to “Liquidity and Capital Resources” included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of this report.

Customers

No material part of SJG’s business is dependent upon a single customer or a few customers, the loss of which would have a material adverse effect on SJG’s business. See Item 1, “Description of Business.”

Backlog

Backlog is not material to an understanding of SJG’s business.

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Government Contracts

No material portion of SJG’s business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of any government.

Competition

Information on competition is incorporated by reference to Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations, ” of this report.

Research

During the last three fiscal years, SJG did not engage in research activities to any material extent.

Environmental Matters

Information on environmental matters can be found in Note 12 of the financial statements included under Item 8 of this report.

Employees

SJG had a total of 475 employees as of December 31, 2013. Of that total, 286 employees are unionized. There are 36 unionized employees represented by the International Brotherhood of Electrical Workers (IBEW) that operate under a collective bargaining agreement that runs through February 28, 2017. The remaining unionized employees are represented by the International Association of Machinists and Aerospace Workers (IAM).  Employees represented by the IAM operate under a collective bargaining agreement that expires in August 2014.

Financial Information About Foreign and Domestic Operations and Export Sales

SJG has no foreign operations and export sales are not a part of its business.

Item 1A. Risk Factors

SJG operates in an environment that involves risks, many of which are beyond our control. The Company has identified the following risk factors that could cause the Company’s operating results and financial condition to be materially adversely affected. Security Holders should carefully consider these risk factors and should also be aware that this list is not all-inclusive of existing risks. In addition, new risks may emerge at any time, and the Company cannot predict those risks or the extent to which they may affect the Company’s businesses or financial performance.

• SJG’s business activities are concentrated in southern New Jersey. Changes in the economies of southern New Jersey and surrounding regions could negatively impact the growth opportunities available to SJG and the financial condition of customers and prospects of SJG.

• Changes in the regulatory environment or unfavorable rate regulation may have an unfavorable impact on SJG’s financial performance or condition.  SJG’s business is regulated by the New Jersey Board of Public Utilities which has authority over many of the activities of the business including, but not limited to, the rates it charges to its customers, the amount and type of securities it can issue, the nature of investments it can make, the nature and quality of services it provides, safety standards and other matters. The extent to which the actions of regulatory commissions restrict or delay SJG’s ability to earn a reasonable rate of return on invested capital and/or fully recover operating costs may adversely affect its results of operations, financial condition and cash flows.

• SJG may not be able to respond effectively to competition, which may negatively impact SJG’s financial performance or condition. Regulatory initiatives may provide or enhance opportunities for competitors that could reduce utility income obtained from existing or prospective customers. Also, competitors may be able to provide superior or less costly products or services based upon currently available or newly developed technologies.

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• Warm weather, high commodity costs, or customer conservation initiatives could result in reduced demand for natural gas. While SJG currently has a conservation incentive program clause that protects its revenues and gross margin against usage that is lower than a set level, the clause is currently approved as a pilot program through September 2014. Should this clause expire without replacement, lower customer energy utilization levels would likely reduce SJG’s net income.

• High natural gas prices could cause more of SJG’s receivables to be uncollectible. Higher levels of uncollectibles from utility customers would negatively impact SJG’s income and could result in higher working capital requirements.

• SJG’s net income could decrease if it is required to incur additional costs to comply with new governmental safety, health or environmental legislation. SJG is subject to extensive and changing federal and state laws and regulations that impact many aspects of its business; including the storage, transportation and distribution of natural gas, as well as the remediation of environmental contamination at former manufactured gas plant facilities.

• Increasing interest rates would negatively impact the net income of SJG. SJG is capital intensive, resulting in the incurrence of significant amounts of debt financing. SJG has issued all long-term debt either at fixed rates or has utilized interest rate swaps to mitigate changes in floating rates. However, new issues of long-term debt and all variable rate short-term debt are exposed to the impact of rising interest rates. 

• The inability to obtain capital, particularly short-term capital from commercial banks, could negatively impact the daily operations and financial performance of SJG. SJG uses short-term borrowings under both a commercial paper program and committed and uncommitted credit facilities provided by commercial banks to supplement cash provided by operations, to support working capital needs, and to finance capital expenditures, as incurred.If the customary sources of short-term capital were no longer available due to market conditions, SJG may not be able to meet its working capital and capital expenditure requirements and borrowing costs could increase.

• A downgrade in SJG’s credit ratings could negatively affect its ability to access adequate and cost effective capital. SJG’s ability to obtain adequate and cost effective capital depends largely on its credit ratings, which are greatly influenced by financial condition and results of operations. If the rating agencies downgrade SJG’s credit ratings, particularly below investment grade, SJG’s borrowing costs would increase. In addition, SJG would likely be required to pay higher interest rates in future financings and potential funding sources would likely decrease.

• The inability to obtain natural gas would negatively impact the financial performance of SJG.  SJG’s business is based upon the ability to deliver natural gas to customers. Disruption in the production of natural gas or transportation of that gas to SJG from its suppliers could prevent SJG from completing sales to its customers.

• Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs. SJG’s gas distribution activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, mechanical problems, natural disaster or terrorist activities, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution and impairment of operations, which in turn could lead to substantial losses. In accordance with customary industry practice, SJG maintains insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could adversely affect SJG’s financial position, results of operations and cash flow.

• Adverse results in legal proceedings could be detrimental to the financial condition of SJG. The outcomes of legal proceedings can be unpredictable and can result in adverse judgments.

• Climate change legislation could impact SJG’s financial performance and condition.  Climate change is receiving ever increasing attention from scientists and legislators alike.  The debate is ongoing as to the extent to which our climate is changing, the potential causes of this change and its future impacts.  Some attribute global warming to increased levels of greenhouse gases, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.  The outcome of federal and state actions to address global climate change could result in a variety of regulatory programs including additional charges to fund energy efficiency activities or other regulatory actions.  These actions could affect the demand for natural gas and electricity, result in increased costs to our business and impact the prices we charge our customers.  Because natural gas is a fossil fuel with low carbon content, it is possible that future carbon constraints could create additional demands for natural gas, both for production of electricity and direct use in homes and businesses.  Any adoption by federal or state governments mandating a substantial reduction in greenhouse gas emissions could have far-reaching and significant impacts on the energy industry.  We cannot predict the potential impact of such laws or regulations on our future financial condition, results of operations or cash flows.

• New legislation could have an impact on our ability to hedge risks associated with our business. The Dodd-Frank Act regulates derivative transactions, which include certain instruments used in our risk management activities. This legislation and any new regulations could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of available counterparties.

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• Failures in the security of our computer systems through cyberattacks, hackers or other sources, could have a material adverse impact on our business and results of operations. SJG uses computer systems and services that involve the storage of confidential information on our employees, customers and vendors. In addition, certain computer systems monitor and control our distribution processes. Experienced hackers may be able to develop and deploy viruses that exploit the security of our computer systems and thus obtain confidential information and/or disrupt significant business processes. Unauthorized access to confidential information or disruptions to significant business processes could damage our reputation and negatively impact our results of operations and financial condition.

Item 1B. Unresolved Staff Comments

None.

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Item 2. Properties

The principal property of SJG consists of its gas transmission and distribution systems that include mains, service connections and meters. The transmission facilities carry the gas from the connections with Transco and Columbia to SJG’s distribution systems for delivery to customers. As of December 31, 2013, there were approximately 122.7 miles of mains in the transmission systems and 6,247 miles of mains in the distribution systems.

SJG owns 154 acres of land in Folsom, New Jersey, which is the site of its corporate headquarters. Approximately 140 acres of this property are deed restricted.  SJG also has office and service buildings at six other locations in the territory. There is a liquefied natural gas storage and vaporization facility at one of these locations.

As of December 31, 2013, SJG’s utility plant had a gross book value of $1.8 billion and a net book value, after accumulated depreciation, of $1.4 billion.  In 2013, $161.5 million million was spent on additions to utility plant and there were retirements of property having an aggregate gross carrying value of $17.1 million.

Virtually all of SJG’s transmission pipeline, distribution mains and service connections are under streets or highways or on the property of others. The transmission and distribution systems are maintained under franchises or permits or rights-of-way, many of which are perpetual. SJG’s properties (other than property specifically excluded) are subject to a lien of mortgage under which its first mortgage bonds are outstanding. We believe these properties are well maintained and in good operating condition.

Item 3. Legal Proceedings

SJG is subject to claims which arise 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 $0.5 million related to all claims in the aggregate, as of both December 31, 2013 and 2012. Management does not believe that it is reasonably possible that there would 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 our financial position, results of operations or liquidity.

Item 4. Mine Safety Disclosures

Not Applicable

Part II

Item 5. Market for the Registrant’s Common Equity

Related Stockholder Matters, and Issuer Purchases of Equity Securities

Common equity securities of SJG, owned by its parent company, South Jersey Industries, Inc., are not traded on any stock exchange. SJG no longer has any preferred stock outstanding.

SJG is restricted under its First Mortgage Indenture, as supplemented, as to the amount of cash dividends or other distributions that may be paid on its common stock. As of December 31, 2013, these restrictions did not affect the amount that may be distributed from SJG’s retained earnings. No dividends were declared and paid on SJG’s common stock in 2013 or 2012.

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Item 6. Selected Financial Data

The following financial data has been obtained from SJG’s audited financial statements (In thousands, except for Ratio Data and Customers):

	Year Ended December 31,
	2013		2012		2011		2010		2009
Operating Revenues	$	446,480	$	421,874	$	412,449	$	475,982	$	484,376
Operating Income	$	105,822	$	101,762	$	102,663	$	90,701	$	81,439
Net Income	$	62,236	$	58,241	$	52,889	$	43,925	$	39,195
Average Shares of Common Stock Outstanding	2,339		2,339		2,339		2,339		2,339
Ratio of Earnings to Fixed Charges (1)	5.3x		5.5x		5.3x		5.1x		4.9x

	As of December 31,
	2013		2012		2011		2010		2009
Property, Plant and Equipment, Net	$	1,424,775	$	1,285,591	$	1,158,029	$	1,046,804	$	961,165
Total Assets	$	1,909,126	$	1,786,459	$	1,615,723	$	1,468,635	$	1,357,062
Capitalization:
Common Equity	$	610,969	$	521,395	$	464,186	$	426,885	$	431,530
Long-Term Debt	454,000		425,000		362,813		340,000		250,000
Total Capitalization	$	1,064,969	$	946,395	$	826,999	$	766,885	$	681,530
Total Customers	362,256		357,306		351,304		347,725		343,566

(1) The ratio of earnings to fixed charges represents, on a pre-tax basis, the number of times earnings cover fixed charges. Earnings consist of net income, to which has been added fixed charges and taxes based on income of the company. Fixed charges consist of interest charges.

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Item 7. 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.

Our service territory covers approximately 2,500 square miles in the southern part of New Jersey. It includes 112 municipalities throughout Atlantic, Cape May, Cumberland and Salem Counties and portions of Burlington, Camden and Gloucester Counties, with an estimated permanent population of 1.2 million. We benefit from our proximity to Philadelphia, PA and Wilmington, DE on the western side of our service territory and Atlantic City, NJ and the popular shore communities on the eastern side. Continuing expansion of our infrastructure throughout our seven county region has fueled annual customer growth and creates opportunities for future extension into areas not yet served by natural gas. In the past, economic growth in Atlantic City and the surrounding region has been primarily driven by new and proposed gaming and non-gaming investments that emphasize destination style attractions.

Combining with the gaming industry catalyst is the ongoing transition of southern New Jersey’s oceanfront communities from seasonal resorts to year round economies.  Building expansions in the medical, hospitality and education sectors throughout the service territory have contributed to our growth. In 2013, we serve approximately 69% of households within our territory with natural gas.   We also serve southern New Jersey’s diversified industrial base that includes processors of petroleum and agricultural products; chemical, glass and consumer goods manufacturers; and high technology parks.

As of December 31, 2013, we served 362,256 residential, commercial and industrial customers in southern New Jersey, compared with 357,306 customers at December 31, 2012.  No material part of our business is dependent upon a single customer or a few customers. Gas sales, transportation and capacity release for 2013 amounted to 111.7 MMdts (million dekatherms), of which 60.5 MMdts were firm sales and transportation, 1.5 MMdts were interruptible sales and transportation and 49.7 MMdts were off-system sales and capacity release. The breakdown of firm sales and transportation includes 42.0% residential, 20.1% commercial, 22.1% industrial, and 15.8% cogeneration and electric generation. At year-end 2013, we served 337,936 residential customers, 23,873 commercial customers and 447 industrial customers.  This includes 2013 net additions of 4,589 residential customers and 367 commercial customers.

We make wholesale gas sales to gas marketers for resale and ultimate delivery to end users. These “off-system” sales are made possible through the issuance of the Federal Energy Regulatory Commission (FERC) Orders No. 547 and 636. Order No. 547 issued a blanket certificate of public convenience and necessity authorizing all parties, which are not interstate pipelines, to make FERC jurisdictional gas sales for resale at negotiated rates, while Order No. 636 allowed us to deliver gas at delivery points on the interstate pipeline system other than our own city gate stations and release excess pipeline capacity to third parties. During 2013, off-system sales amounted to 9.7 MMdts and capacity release amounted to 40.1 MMdts.

Supplies of natural gas available to us that are in excess of the quantity required by those customers who use gas as their sole source of fuel (firm customers) make possible the sale and transportation of gas on an interruptible basis to commercial and industrial customers whose equipment is capable of using natural gas or other fuels, such as fuel oil and propane. The term “interruptible” is used in the sense that deliveries of natural gas may be terminated by us at any time if this action is necessary to meet the needs of higher priority customers as described in our tariffs. In 2013, usage by interruptible customers, excluding off-system customers, amounted to 1.5 MMdts, approximately 1.3% of the total throughput.

Our primary goals are to: 1) provide safe, reliable natural gas service at the lowest cost possible; 2) promote natural gas as the fuel of choice for residential, commercial and industrial customers; and 3) aid our customers in becoming more energy efficient.

13

The following is a summary of the primary factors we expect to have the greatest impact on our performance and our ability to achieve our goals going forward:

Business Model - We are the primary focus of our parent, SJI, and will continue to account for the majority of SJI’s net income by maximizing the growth potential of our service territory.

Customer Growth - Southern New Jersey, our primary area of operations, has not been immune to the issues impacting the new housing market nationally.  However, net customers for SJG still grew 1.4% for 2013 as we increased our focus on customer conversions.  In 2013, the 5,165 consumers converting their homes and businesses from other heating fuels, such as electric, propane or oil represented over 69% of the total new customer acquisitions for the year.  In comparison, conversions over the past five years averaged 4,142 annually.  Customers in our service territory typically base their decisions to convert on comparisons of fuel costs, environmental considerations and efficiencies.  As such, SJG began a comprehensive partnership with the State’s Office of Clean Energy to educate consumers on energy efficiency and to promote the rebates and incentives available to natural gas users.

Regulatory Environment - We are primarily regulated by the New Jersey Board of Public Utilities (BPU). The BPU sets the rates that we charge our rate-regulated customers for services provided and establishes the terms of service under which we operate. We expect the BPU to continue to set rates and establish terms of service that will enable us to obtain a fair and reasonable return on capital invested. The BPU approved a Conservation Incentive Program (CIP) effective October 1, 2006, discussed in greater detail under “Results of Operations,” that protects our net income from reductions in gas used by our residential, commercial, and small industrial customers.  In addition, in February 2013, the BPU issued a Board Order approving the Accelerated Infrastructure Replacement Program (AIRP), a $141.2 million program to replace cast iron and unprotected bare steel mains and services over a four-year period, with annual investments of approximately $35.3 million. The Company earns a return on AIRP investments until they are included in rate base in future base rate proceedings.

Weather Conditions and Customer Usage Patterns - Usage patterns can be affected by a number of factors, such as wind, precipitation, temperature extremes and customer conservation. Our earnings are largely protected from fluctuations in temperatures by the CIP. The CIP has a stabilizing effect on earnings as we adjust revenues when actual usage per customer experienced during an annual period varies from an established baseline usage per customer.

Changes in Natural Gas Prices -   Gas costs are passed on directly to customers without any profit margin added. For the vast majority of our customers, the price for natural gas is set annually, with a regulatory mechanism in place to make limited adjustments to that price during the course of a year. In the event that gas cost increases would justify customer price increases greater than those permitted under the regulatory mechanism, we can petition the BPU for an incremental rate increase. High prices can make it more difficult for our customers to pay their bills and may result in elevated levels of bad-debt expense.

Changes in Interest Rates- We have operated in a relatively low interest rate environment over the past several years. Rising interest rates would raise the expense associated with all issuances of new debt. We have sought to mitigate the impact of a potential rising rate environment by directly issuing fixed-rate debt, or by entering into derivative transactions to hedge against rising interest rates.

Labor and Benefit Costs - Labor and benefit costs have a significant impact on our profitability. Benefit costs, especially those related to pension and health care, have risen in recent years. We sought to manage these costs by revising health care plans offered to existing employees, capping postretirement health care benefits, and changing health care and pension packages offered to new hires.  We expect savings from these changes to gradually increase as new hires replace retiring employees. In an effort to accelerate the realization of those benefits, we had offered a voluntary separation program at the beginning of 2010 to our unionized employees. Our workforce totaled 475 employees at the end of 2013, with 286 of that total unionized.

Balance Sheet Strength - Our goal is to maintain a strong balance sheet with an average annual equity-to-capitalization ratio of 46% to 50%. Our equity-to-capitalization ratio, inclusive of short-term debt, was 53% and 49% at the end of 2013 and 2012, respectively. A strong balance sheet permits us the financial flexibility necessary to address volatile economic and commodity markets while maintaining a low-risk platform.

Critical Accounting Policies - Estimates and Assumptions - As described in the notes to our financial statements, management must make estimates and assumptions that affect the amounts reported in the financial statements and related disclosures. Actual results could differ from those estimates. Five types of transactions presented in our 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.

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Regulatory Accounting- We maintain our accounts according to the Uniform System of Accounts as prescribed by the New Jersey Board of Public Utilities (BPU). As a result of the ratemaking process, we are required to follow Financial Accounting Standards Board (FASB) ASC Topic 980 – “Regulated Operations.”  We are required under Topic 980 to recognize the impact of regulatory decisions on our financial statements. We are required under our Basic Gas Supply Service (BGSS) clause to forecast our natural gas costs and customer consumption in setting our rates. Subject to BPU approval, we are able to recover or return the difference between gas cost recoveries and the actual costs of gas through a BGSS charge to customers. We record any over/under recoveries as a regulatory asset or liability on the balance sheets and reflect it in the BGSS charge to customers in subsequent years. We also enter into derivatives that are used to hedge natural gas purchases. The offset of the resulting derivative assets or liabilities is also recorded as a regulatory asset or liability on the balance sheets. See additional detailed discussions on Rates and Regulatory Actions in Note 3 to the financial statements.

Derivatives - We recognize assets or liabilities for contracts that qualify as derivatives when contracts are executed. We record contracts at their fair value in accordance with FASB ASC Topic 815 – “Derivatives and Hedging.” We record changes in the fair value of the effective portion of derivatives qualifying as cash flow hedges, net of tax, in Accumulated Other Comprehensive Loss and recognize such changes in the income statement when the hedged item affects earnings. Changes in the fair value of derivatives not designated as hedges are recorded in earnings in the current period. Currently, we do not designate energy-related derivative instruments as cash flow hedges. Certain derivatives that result in the physical delivery of the commodity may meet the criteria to be accounted for as normal purchases and normal sales, if so designated, in which case the contract is not marked-to-market, but rather is accounted for when the commodity is delivered. Due to the application of regulatory accounting principles under GAAP, derivatives related to gas purchases that are marked-to-market are recorded through our BGSS.  We periodically enter into financial derivatives to hedge against forward price risk. These derivatives are recorded at fair value with an offset to regulatory assets and liabilities through our BGSS, subject to BPU approval (See Notes 3 and 4 to the financial statements). We adjust the fair value of the contracts each reporting period for changes in the market.

As discussed in Notes 13 and 14 of the financial statements, energy-related derivative instruments 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 established by FASB ASC Topic 820 – “Fair Value Measurements and Disclosures.” Certain non-exchange-based contracts are valued using indicative non-binding price quotations available through brokers or from 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. Management reviews and corroborates the price quotations with at least one additional source to ensure the prices are observable market information, which includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. Derivative instruments that are used to limit our exposure to changes in interest rates on variable-rate, long-term debt 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, as a result, these instruments are categorized in Level 2 in the fair value hierarchy.  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 in the fair value hierarchy as the model inputs generally are not observable.  Counterparty credit risk, and the credit risk of SJG, is incorporated and considered in the valuation of all derivative instruments as appropriate. The effect of counterparty credit risk and the credit risk of SJG on the derivative valuations is not significant.

Environmental Remediation Costs - We estimate a range of future costs based on projected investigation and work plans using existing technologies.  In preparing financial statements, we record liabilities for future costs using the lower end of the range because a single reliable estimation point is not feasible due to the amount of uncertainty involved in the nature of projected remediation efforts and the long period over which remediation efforts will continue. We update estimates each year to take into account past efforts, changes in work plans, remediation technologies, government regulations and site specific requirements (See Note 12 to the financial statements).

Pension and Other Postretirement Benefit Costs - The costs of providing pension and other postretirement employee benefits are impacted by actual plan experience as well as assumptions of future experience. Employee demographics, plan contributions, investment performance, and assumptions concerning mortality, return on plan assets, discount rates and health care cost trends all have a significant impact on determining our projected benefit obligations. We evaluate these assumptions annually and adjust them accordingly. These adjustments could result in significant changes to the net periodic benefit costs of providing such benefits and the related liabilities recognized by us.

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The combination of slowing equity markets and lower discount rates in 2011, which were used in determining plan costs in 2012, increased the cost of providing such plans in 2012. However, SJG took measures to manage this increase by making a $19.8 million pension plan contribution in January 2012. As such, the resulting financial impact on the company was not significant. Discount rates continued to decline in 2012 and are the primary cost driver used in determining plan costs in 2013. However, improvements in the equity markets during 2012 and a $ 9.1 million pension plan contribution in January 2013, significantly offset the negative impact of declining discount rates. As such, the resulting financial impact on the Company was not significant in 2013. During 2013, discount rates increased and equity markets continued to outperform management's expectations. As a result, the Company currently expects a $3.4 million decrease in the cost of providing such benefits in 2014. Additional information regarding investment returns and assumptions can be found in Pension and Other Postretirement Benefits in Note 11 to the financial statements.

Revenue Recognition - Gas revenues are recognized in the period the commodity is delivered to customers. We bill customers monthly at rates approved by the BPU. A majority of our customers have their meters read on a cycle basis throughout the month. As a result, recognized revenues include estimates. For customers that are not billed at the end of each month, we record an estimate to recognize unbilled revenues for gas delivered from the date of the last meter reading to the end of the month. Our unbilled revenue is estimated each month based on natural gas delivered monthly into the system; unaccounted for natural gas based on historical results; customer-specific use factors, when available; actual temperatures during the period; and applicable customer rates.

The BPU allows us to recover gas costs in rates through the BGSS price structure. We defer over/under recoveries of gas costs and include them in subsequent adjustments to the BGSS rate. These adjustments result in over/under recoveries of gas costs being included in rates during future periods. As a result of these deferrals, utility revenue recognition does not directly translate to profitability. While we realize profits on gas sales during the month of providing the utility service, significant shifts in revenue recognition may result from the various recovery clauses approved by the BPU. This revenue recognition process does not shift earnings between periods, as these clauses only provide for cost recovery on a dollar-for-dollar basis (See Notes 3 and 4 to the financial statements).

In January 2010, the BPU approved an extension of the Conservation Incentive Program (CIP) through September 2013, with an automatic one year extension through September 2014 if a request for an extension was filed by March 2013. A petition was filed in March 2013 to extend the CIP program.  Each CIP year begins October 1 and ends September 30 of the subsequent year.  On a monthly basis during the CIP year, we record adjustments to earnings based on weather and customer usage factors, as incurred.  Subsequent to each year, we make filings with the BPU to review and approve amounts recorded under the CIP.  BPU approved cash inflows or outflows generally will not begin until the next CIP year and have no impact on earnings at that time.

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

Rates and Regulation - As a public utility, we are subject to regulation by BPU. Additionally, the Natural Gas Policy Act, which was enacted in November 1978, contains provisions for Federal regulation of certain aspects of our business. We are affected by Federal regulation with respect to transportation and pricing policies applicable to pipeline capacity from Transcontinental Gas Pipeline Corporation (our major supplier), Columbia Gas Transmission Corporation and Dominion Transmission, Inc., since such services are provided under rates and terms established under the jurisdiction of the FERC. Our retail sales are made under rate schedules within a tariff filed with, and subject to the jurisdiction of, the BPU. These rate schedules provide primarily for either block rates or demand/commodity rate structures. Our primary rate mechanisms include base rates, the Basic Gas Supply Service Clause, Accelerated Infrastructure Programs (CIRT and AIRP), Energy Efficiency Tracker and the Conservation Incentive Program.

In September 2010, the BPU granted SJG a base rate increase of $42.1 million, which was predicated, in part, upon an 8.21% rate of return on rate base that included a 10.3% return on common equity.  The $42.1 million includes $16.6 million of revenue previously recovered through the CIP and $6.8 million of revenues previously recovered through the Capital Investment Recovery Tracker (CIRT), resulting in incremental revenue of $18.7 million.  SJG was permitted to recover regulatory assets contained in its petition and is allowed to defer certain federally mandated pipeline integrity management program costs for recovery in its next base rate case.  In addition, annual depreciation expense was reduced by $1.2 million as a result of the amortization of excess cost of removal recoveries.  The BPU also authorized a Phase II of the base rate proceeding to address the recovery of investment in CIRT not rolled into rate base in this case.

In November 2013, we filed a base rate case with the BPU to increase our base rates to obtain a certain level of return on our capital investments. We expect the base rate case to be concluded during 2014.

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In April 2009, the BPU approved the Capital Investment Recovery Tracker (CIRT), an accelerated infrastructure investment program and an associated rate tracker, which allowed SJG to accelerate $103.0 million of capital spending into 2009 and 2010.  As stated above, the BPU authorized a Phase II of its rate case proceeding to address the recovery of investments in CIRT not rolled into rate base in its September 2010 rate case settlement. The CIRT allows SJG to earn a return of, and return on, investment as the capital is spent. In March 2011, the BPU approved an extension of the Capital Investment Recovery Tracker (CIRT II) allowing SJG to accelerate $60.3 million of capital spending into 2011 and 2012. In May 2012, the BPU approved a modification and extension of CIRT II (CIRT III) allowing SJG to accelerate an incremental $35.0 million of capital spending through December 2012. Under CIRT II and CIRT III, the Company capitalizes a return on investments until they are recovered in rate base as utility plant in service. A proceeding took place in 2013 to roll into base rates the remaining $22.5 million of CIRT I project costs that were not included in the 2010 proceeding, as well as CIRT II and III investments totaling $95 million that were made subsequent to the 2010 base rate case. These costs were rolled into rate base and reflected in base rates effective October 2013.

The Conservation Incentive Program (CIP) is a BPU approved pilot program that is designed to eliminate the link between our profits and the quantity of natural gas we sell, and to foster conservation efforts. With the CIP, our profits are tied to the number of customers we serve and how efficiently we serve them, thus allowing us to focus on encouraging conservation and energy efficiency among our customers without negatively impacting our net income.  The CIP tracking mechanism adjusts earnings based on weather, and also adjusts our earnings when actual usage per customer experienced during an annual period varies from an established baseline usage per customer.  In January 2010, the BPU approved an extension of the CIP through September 2013, with an automatic one year extension through September 2014 if a request for an extension was filed by March 2013. A petition was filed in March 2013 to extend the CIP program.

Utility earnings are recognized during current periods based upon the application of the CIP. The cash impact of variations in customer usage will result in cash being collected from, or returned to, customers during the subsequent CIP year, which runs from October 1 to September 30.

The effects of the CIP on our net income for the last three years and the associated weather comparisons were as follows ($’s in millions):

	2013			2012		2011
Net Income Benefit:
CIP – Weather Related	(0.3		)	9.4		5.6
CIP – Usage Related	3.4			5.8		2.2
Total Net Income Benefit	$	3.1		$	15.2	$	7.8
Weather Compared to 20-Year Average	0.6% colder			17.7% warmer		10.0% warmer
Weather Compared to Prior Year	20.6% colder			8.6% warmer		7.8% warmer

As part of the CIP, we are required to implement additional conservation programs including customized customer communication and outreach efforts, targeted upgrade furnace efficiency packages, financing offers, and an outreach program to speak to local and state institutional constituents. We are also required to reduce gas supply and storage assets and their associated fees. Note that changes in fees associated with supply and storage assets have no effect on our net income as these costs are passed through directly to customers on a dollar-for-dollar basis.

Earnings accrued and payments received under the CIP are limited to a level that will not cause our return on equity to exceed 10.3% (excluding earnings from off-system gas sales and certain other tariff clauses) and the annualized savings attained from reducing gas supply and storage assets.

See additional detailed discussions on Rates and Regulatory Actions in Note 3 to the financial statements.

Environmental Remediation - See detailed discussion concerning Environment Remediation in Note 12 to the financial statements.

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Competition- Our franchises are non-exclusive. Currently, no other utility provides retail gas distribution services within our territory. We do not expect any other utilities to do so in the foreseeable future because of the extensive investment required for utility plant and related costs. We compete with oil, propane and electricity suppliers for residential, commercial and industrial users, with alternative fuel source providers (wind, solar and fuel cells) based upon price, convenience and environmental factors, and with other marketers/brokers in the selling of wholesale natural gas services. The market for natural gas commodity sales is subject to competition due to deregulation. We enhanced our competitive position while maintaining margins by using an unbundled tariff. This tariff allows full cost-of-service recovery when transporting gas for our customers. Under this tariff, we profit from transporting, rather than selling, the commodity. Our residential, commercial and industrial customers can choose their supplier, while we recover the cost of service through transportation service (see Customer Choice Legislation below).

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, where redesigned utility rate structures allow natural gas and electric consumers to choose their energy supplier. It also established time frames for instituting competitive services for customer account functions and for determining whether basic gas supply services should become competitive. 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 averaged 46,872, 39,398, and 37,829 during 2013, 2012 and 2011, respectively.  

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RESULTS OF OPERATIONS

The following table summarizes the composition of selected gas utility data for the three years ended December 31 (in thousands, except for customer and degree day data):

	2013				2012				2011
Utility Throughput – dth:
Firm Sales -
Residential	22,070		20	%	18,586		14	%	20,332		16	%
Commercial	5,408		5	%	4,733		4	%	5,426		4	%
Industrial	292		—		258		1	%	319		—
Cogeneration and electric generation	1,562		1	%	1,598		1	%	1,618		2	%
Firm Transportation -
Residential	3,319		3	%	2,335		2	%	2,382		2	%
Commercial	6,780		6	%	5,587		4	%	5,715		4	%
Industrial	13,051		12	%	12,892		10	%	13,024		10	%
Cogeneration and electric generation	7,977		7	%	9,816		8	%	6,110		5	%
Total Firm Throughput	60,459		54	%	55,805		44	%	54,926		43	%
Interruptible Sales	14		—		2		—		13		—
Interruptible Transportation	1,452		1	%	1,361		1	%	1,769		2	%
Off-System	9,685		9	%	8,318		6	%	8,009		6	%
Capacity Release	40,088		36	%	63,998		49	%	63,413		49	%
Total Utility Throughput	111,698		100	%	129,484		100	%	128,130		100	%
Utility Operating Revenues:
Firm Sales-
Residential	$	246,227	56	%	$	248,547	59	%	$	232,457	56	%
Commercial	57,126		13	%	53,726		13	%	58,122		14	%
Industrial	3,485		1	%	2,872		—		3,991		2	%
Cogeneration and electric generation	8,144		2	%	6,562		2	%	9,469		2	%
Firm Transportation -
Residential	21,392		5	%	16,388		4	%	15,161		4	%
Commercial	28,165		6	%	24,217		6	%	22,500		5	%
Industrial	23,551		5	%	21,637		5	%	18,827		5	%
Cogeneration and electric generation	6,982		2	%	7,555		2	%	3,742		1	%
Total Firm Revenues	395,072		90	%	381,504		91	%	364,269		89	%
Interruptible Sales	342		—		52		—		230		—
Interruptible Transportation	1,827		—		1,546		—		1,727		—
Off-System	41,488		9	%	30,249		7	%	37,413		9	%
Capacity Release	6,384		1	%	7,322		2	%	7,534		2	%
Other	1,367		—		1,201		—		1,276		—
Total Utility Operating Revenues	446,480		100	%	421,874		100	%	412,449		100	%
Less:
Cost of sales	200,081				188,710				187,866
Conservation recoveries *	15,909				9,019				7,159
RAC recoveries *	8,137				7,824				6,579
EET Recoveries *	4,509				3,350				2,499
Revenue taxes	5,247				5,974				8,021
Utility Margin	$	212,597			$	206,997			$	200,325

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Utility Margin:
Residential	$	138,136	65	%	$	118,015	57	%	$	124,882	62	%
Commercial and industrial	57,495		27	%	51,048		25	%	52,356		26	%
Cogeneration and electric generation	5,022		2	%	5,062		2	%	3,235		2	%
Interruptible	114		—		83		—		136		—
Off-system & capacity release	2,070		1	%	2,044		1	%	1,829		1	%
Other revenues	1,752		1	%	1,602		1	%	1,576		1	%
Margin before incentive mechanisms	204,589		96	%	177,854		86	%	184,014		92	%
CIRT mechanism	2,204		1	%	3,031		2	%	2,655		1	%
CIP mechanism	5,310		3	%	25,672		12	%	13,270		7	%
EET mechanism	494		—		440		—		386		—
Utility Margin	$	212,597	100	%	$	206,997	100	%	$	200,325	100	%
Number of Customers at Year End:
Residential	337,936		93	%	333,347		93	%	327,678		93	%
Commercial	23,873		7	%	23,506		7	%	23,169		7	%
Industrial	447		—		453		—		457		—
Total Customers	362,256		100	%	357,306		100	%	351,304		100	%
Annual Degree Days:	4,658				3,862				4,226

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

Throughput - Total gas throughput decreased 17.8 MMdts, or 13.7%, from 2012 to 2013 primarily due to lower throughput in the Capacity Release market which decreased 23.9 MMdts. SJG was releasing capacity in smaller segments ("segmenting") in 2012 and 2011 based on the demand in the market at that time. While segmenting has little impact on revenue and margin generated from such activity, it does increase throughput significantly. Due to colder weather experienced in the region in 2013, SJG also experienced increased demand from its firm customers, thereby creating fewer opportunities for Capacity Release during the winter months. Firm throughput increased 4.7 MMdts, or 8.3%, in 2013. This is most apparent in the heat sensitive residential and commercial markets whose throughput increased as a result of weather that was 20.6% colder in 2013, as compared with 2012. Also contributing to higher throughput was the addition of 4,950 customers over the last 12 months, representing 1.4% customer growth.

Total gas throughput increased 1.4 MMdts, or 1.1%, from 2011 to 2012. This increase is due to higher electric generation transportation throughput, which increased 3.7 MMdts, or 60.7%, as a result of the excessive heat during the summer months of 2012. As the third quarter of 2012 was one of the warmest on record in the region, higher electric consumption for air conditioning drove the demand for greater natural gas consumption by the region's electric producers. Partially offsetting this increase in throughput was lower consumption by residential and commercial customers. Residential and commercial firm sales decreased 1.7 MMdts and 0.7 MMdts, respectively, as a result of weather that was 8.6% warmer in 2012, compared with 2011.

Operating Revenues – Revenues increased $24.6 million, or 5.8%, during 2013 compared with 2012 due to higher firm sales and Off-System Sales (OSS). Total firm revenue increased $13.6 million, or 3.6%, in 2013 as a result of 20.6% colder weather and 4,950 additional customers compared with 2012, as previously discussed under "Throughput." While these factors increased firm sales volumes significantly, associated revenue did not increase proportionately as a result of lower gas costs being passed through to those customers. In October 2012, SJG reduced its periodic BGSS rate by 18% and also gave a refund of $9.4 million to its periodic BGSS customers in January 2013. While changes in gas costs and BGSS recoveries/refunds fluctuate from period to period, SJG does not profit from the sale of the commodity. Therefore, corresponding fluctuations in Operating Revenue or Cost of Sales have no impact on Company profitability, as further discussed below under the caption "Margin".

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Higher OSS volume and unit prices resulted in an $11.2 million, or 37.2%, increase in revenues from 2012 to 2013. Colder weather led to greater demand and advantageous pricing spreads in the latter part of 2013, allowing 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 share 85% of the profits of such activity with our ratepayers. Earnings from OSS can be seen in the Margin table above.

Revenues increased $9.4 million, or 2.3%, during 2012 compared with 2011. Firm sales revenue increased $17.2 million, or 4.7%, during 2012 versus 2011, primarily as a result of two customer refunds in 2011, which reduced prior year revenue by $39.8 million (See Note 3 to the Financial Statements). There were no such refunds during 2012. In 2012, firm sales revenue was significantly impacted by weather that was 8.6% warmer than 2011 and lower natural gas costs. As a result, the change in revenue caused by the 2011 refunds was substantially offset by the impact of warm weather and lower gas costs on revenues during 2012. The average cost of natural gas purchased during 2012 was $4.56 per dt, representing an 23.2% decrease relative to the average cost of $5.94 per dt during 2011.

As previously stated under "Throughput," record warm weather during the summer season resulted in increased sales to area electric producers. This resulted in a $3.8 million increase in cogeneration and electric generation transportation revenue over 2011.

Off-System Sales revenue decreased $7.2 million, or 19.1%, despite throughput that was relatively consistent from 2011 to 2012. The decrease was primarily due to lower natural gas prices in 2012. As can be seen in the "Utility Margin" table above, this reduction in revenue had no adverse impact on SJG's margin in 2012.

Margin - Our margin is defined as natural gas revenues less natural gas costs; volumetric and revenue based energy taxes; and regulatory rider expenses. We believe that margin provides a more meaningful basis for evaluating utility operations than revenues since natural gas costs, energy taxes and regulatory rider expenses are passed through to customers, and therefore, have no effect on our profitability. 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 through our BGSS tariff.

Total margin in 2013 increased $5.6 million, or 2.7%, from 2012 primarily due to customer additions. SJG added 4,950 customers during 2013 representing growth of 1.4% over the prior year.

The CIP protected $5.3 million of pre-tax margin in 2013 that would have been lost due to lower customer usage, compared to $25.7 million in 2012.  Of these amounts, $(0.5) million and $15.8 million were related to weather variations and $5.8 million and $9.9 million were related to other customer usage variations in 2013 and 2012, respectively.

Total margin in 2012 increased $6.7 million, or 3.3%, from 2011 primarily due to customer additions and increased margins from cogeneration and electric generation due to the warmer temperatures noted above. SJG added 6,002 customers during 2012 representing growth of 1.7% over the prior year and a corresponding increase in margin.

The CIP protected $25.7 million of pre-tax margin in 2012 that would have been lost due to lower customer usage, compared to $13.3 million in 2011.  Of these amounts, $15.8 million and $9.6 million were related to weather variations and $9.9 million and $3.7 million were related to other customer usage variations in 2012 and 2011, respectively.

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

	2013 vs. 2012			2012 vs. 2011
Operations	$	7,380		$	10,276
Maintenance	$	(480	)	$	493
Depreciation	$	2,713		$	704
Energy and Other Taxes	$	(438	)	$	(1,991	)

21

Operations – Operations expense increased $7.4 million during 2013, as compared to 2012. The increase is primarily comprised of the following:

• Expenses associated with the New Jersey Clean Energy Program and Energy Efficiency Programs increased $8.0 million in 2013, compared with 2012. Such costs are recovered on a dollar-for-dollar basis; therefore, SJG experienced an offsetting increase in revenues during 2013.

• Distribution operations expenses increased $1.1 million in 2013, compared with 2012, as a result of colder weather and inclement condition during the year.

• These were partially offset by a $0.8 million decrease in the amortization of previously deferred regulatory expenses. Recovery of these costs was approved in the Company's September 2010 rate case settlement. As of late 2012, these costs were fully amortized.

Operations expense increased $10.3 million during 2012, as compared with 2011. The increase is primarily comprised of the following:

• Expense associated with the New Jersey Clean Energy Program and Energy Efficiency Programs experienced a net increase of $2.7 million in 2012, as compared to 2011. Such costs are recovered on a dollar-for-dollar basis; therefore, SJG experienced an offsetting increase in revenues during 2012.

• Expense associated with the write-off of uncollectible customer accounts receivable increased $1.3 million in 2012, as compared with 2011. This increase in write-offs results from an increase in the aging of receivables.

• SJG also increased its reserve for uncollectible accounts, resulting in $2.1 million of additional expense in 2012, as compared to 2011. Changes in the uncollectible reserve are the result of fluctuations in levels of customer accounts receivables balances, which are higher as of December 31, 2012 due to a 22.3% colder start to the 2012-2013 winter season. In addition, customer accounts receivable at December 31, 2011 was reduced by a $20.0 million customer bill credit during December 2011, which further reduced the reserve requirement in 2011.

• Insurance expense increased $0.9 million in 2012, as compared to 2011. Expense in 2012 was typical; however, 2011 benefited from a significant decrease in its reserve for pending litigation due to successful outcomes in various legal matters in 2011.

• SJG experienced a $1.3 million increase in expense associated with corporate support, governance and compliance costs, primarily attributable to our parent, SJI, in 2012.

• SJG also experienced higher expenses related to bank fees, communication system upgrades, pension expense (See Note 11 to the Financial Statements) and payroll expense.

Maintenance – Maintenance expense decreased $0.5 million during 2013, compared with 2012, as cost amortizations previously approved in the Company's September 2010 rate case settlement ceased. Such amortizations totaled $1.0 million in 2012; however, as of late 2012 these costs were fully amortized. This reduction in expense was partially offset by an increase in Remediation Adjustment Clause (RAC) expense amortization. As discussed in Notes 3 and 4 to the Financial Statements. RAC costs are recovered from ratepayers; therefore, SJG experienced an offsetting change in revenue during the year.

Maintenance expense increased $0.5 million during 2012, compared with 2011, primarily due to an increase in Remediation Adjustment Clause expense amortization.   

Depreciation - Depreciation expense increased $2.7 million and $0.7 million in 2013 and 2012, respectively, due mainly to our continuing investment in utility plant. SJG’s investment in utility plant during 2013, 2012 and 2011 was $161.5 million, $156.0 million and $142.6 million, respectively.  The increased spending in recent years was a direct result of the State’s stimulus efforts, which included the approval of SJG’s Capital Investment Recovery Tracker and Accelerated Infrastructure Replacement Program, as discussed under “Rates and Regulation.”

22

Energy and Other Taxes – Energy and Other Taxes decreased $0.4 million and $2.0 million in 2013 and 2012, respectively. This is primarily due to 25% annual decreases in the Company's primary energy tax, the Transitional Energy Facilities Assessment, in connection with a phase out plan of this tax which is completely eliminated effective January 1, 2014.  As this tax was passed through to customers, this decrease in expense had no impact on the financial results of the Company. Partially offsetting the impact of lower rates in 2013 was higher taxable firm throughput as a result of 20.6% colder weather.

Other Income and Expense - Other income and expense was higher in 2013 and 2011, when compared with 2012, primarily due to gains on the sale of certain available-for-sale securities during 2013 and 2011 in the amount of $0.8 million and $0.6 million, respectively. No such gain occurred in 2012.

Interest Charges –Changes in interest charges in 2013, when compared with 2012, were not significant.

Interest charges decreased $6.5 million in 2012, compared with 2011. This was primarily related to the positive impact of retiring $35.0 million of SJG's higher priced long-term debt during 2012 and higher capitalization of interest cost on construction. These decreases are partially offset by the issuance of $120.0 million aggregate principal long-term debt issued during 2012 at higher interest rates than the short-term debt previously used to finance our capital program See "Capitalized Interest" under Note 1 to the Financial Statement for additional information.

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 - Cash generated from operating activities constitutes our primary source of liquidity and varies from year-to-year due to the impact of weather on customer demand and related gas purchases, customer usage factors related to conservation efforts and the price of the natural gas commodity, inventory utilization and recoveries provided through our various rate mechanisms. Net cash provided by operating activities was $148.8 million in 2013, $93.4 million in 2012 and $110.5 million in 2011.

Net cash provided by operations improved in 2013 as compared with 2012 primarily as a result of $26 million higher collections under regulatory clauses during 2013 that were under-recovered as a result of warmer-than-normal weather in 2012. Lower pension contributions also improved cash flows for 2013 by approximately $11 million as discussed in Note 11 to the financial statements.  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.  While discount rates continued to decline, greater than expected asset performance during 2012 added significantly to improving the Company's funding status, which resulted in a decrease in the pension contribution during 2013. The Company contributed $9.1 million and $19.8 million to its pension plan in January 2013 and 2012, respectively.

Cash provided by operating activities declined in 2012 as compared with 2011 as a result of a  $19.8 million pension contribution that occurred in January 2012 coupled with the negative impact of warmer-than-normal weather on working capital. There were no pension contributions made by the Company in 2011. The December 2011 BGSS credit of $18.7 million also negatively impacted 2012 by reducing customer payments in early 2012. This was offset by lower natural gas costs, which resulted in lower cash requirements as inventory was being filled during the spring and summer months; and lower environmental remediation spending during 2012 as compared with 2011.

Cash Flows from Investing Activities - We have a continuing need for cash resources for capital purchases, primarily to invest in new and replacement facilities and equipment. Cash used for capital expenditures was $161.5 million, $156.0 million and $142.6 million in 2013, 2012 and 2011, respectively, primarily due to infrastructure improvements that continue to support SJG’s growth.  The increased capital expenditures during the past three years were the direct result of the Company’s CIRT and AIRP programs which began in 2009.  See additional details under “Rates and Regulation.”

23

For capital expenditures, including those under the CIRT and AIRP, SJG will use short-term borrowings under both our commercial paper program and lines of credit from commercial banks to finance capital expenditures as incurred.  From time to time, the Company will refinance the short-term debt incurred to support capital expenditures with long-term debt.

Cash Flows from Financing Activities - We use short-term borrowings under both our commercial paper program and lines of credit from commercial banks to supplement cash from operations, to support working capital needs and to finance capital expenditures as incurred. From time to time, we refinance 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.  

During the third quarter of 2013, SJG redeemed at par $10.5 million of 4.46% MTN's issued in July 2003 and $14.5 million of 5.027% MTN's issued in September 2003.

In November 2013, SJG issued $50.0 million of 4.01% MTN's that will be due November 2030, and issued $30.0 million of 4.23% MTN's in January 2014 that will be due January 2030.

In October 2013, SJG filed a petition with the New Jersey Board of Public Utilities to issue up to $200.0 million of long term debt securities in various forms including MTN's and unsecured debt, with maturities of more than 12 months, over the next three years. This petition was approved in January 2014.

In September 2013, SJG received an equity infusion of $25.0 million from SJI. SJI contributed no capital to us in 2012 or 2011.

Credit facilities and available liquidity as of December 31, 2013 were as follows (in thousands):

	Total Facility		Usage		Available Liquidity		Expiration Date
Commercial Paper/Revolving Credit Facility	$	200,000	$	65,500	$	134,500	May 2018
Uncommitted Bank Lines	10,000		—		10,000		August 2014
Total	$	210,000	$	65,500	$	144,500

SJG renewed the uncommitted bank lines of credit during the third quarter 2013. SJG amended and extended its revolving credit facility during the third quarter of 2013; as a result, the maturity date was extended from May 2015 to May 2018.

The revolving credit facility 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 December 31, 2013.

In July 2011, SJG began 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 will have fixed maturities which will vary by note, but may not exceed 270 days from the date of issue. Proceeds from the notes will be used for general corporate purposes.  SJG uses 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 these credit facilities during the twelve months ended December 31, 2013 and 2012 were $91.4 million and $142.4 million, respectively.  The maximum amount outstanding under these credit facilities during the twelve months ended December 31, 2013 and 2012 were $121.9 million and $180.5 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.

24

SJG supplements its operating cash flow and credit lines with both debt and equity capital.  Over the years, the Company has used long-term debt, primarily in the form of First Mortgage Bonds and Medium Term Notes (MTN), 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.  In April 2012, SJG issued an aggregate $35.0 million of 3.74% First Mortgage Bonds under a private placement (due April 2032) and concurrently redeemed an aggregate $35.0 million of 7.7% First Mortgage Bonds (due April 2027) at a 2% premium. In September 2012, SJG issued an aggregate $50.0 million of 3.00% First Mortgage Bonds under a private placement (due September 2024). In November 2012, SJG issued an aggregate $35.0 million of 3.03% First Mortgage Bonds under a private placement (due November 2024). No other long-term debt was issued during 2012 or 2011.

In December 2011, SJG received approval from the BPU to issue up to $200.0 million in long-term debt under its MTN program by September 30, 2014. At the end of 2013, there was $30.0 million available to be issued under this program. SJG issued $30.0 million of 4.23% MTN's in January 2014, due January 2030, which utilized this remaining availability.

As of December 31, our capital structure was as follows:

	2013		2012
Common Equity	53	%	49	%
Long-Term Debt	41	%	42	%
Short-Term Debt	6	%	9	%
Total	100	%	100	%

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 year of 2013 amounted to $161.5 million. Management estimates net cash outflows for construction projects for 2014, 2015 and 2016, to be approximately $181.8 million, $231.1 million and $198.6 million, respectively.  Costs for remediation projects for the year of 2013 amounted to $0.4 million, net of recoveries from ratepayers.  Total cash outflows for remediation projects are expected to be $12.6 million, $23.8 million and $20.9 million for 2014, 2015, and 2016, respectively, prior to recoveries from ratepayers.  As discussed in Notes 3 and 12 to the Financial Statements in Item 8, environmental remediation costs are subject to recovery from ratepayers: however, recovery from insurance carriers has been exhausted as policy limits have been reached.

STANDBY LETTER OF CREDIT - SJG provided a $25.2 million letter of credit, under a separate credit facility from those it borrows under to provide liquidity support for the remarketing of variable-rate demand bonds issued through the NJEDA. The bonds were used to finance the expansion of SJG’s natural gas distribution system as discussed in Note 7 to the financial statements. The replacement letter of credit expires in August 2015, and as a result, the related bonds are included in long-term debt.

We have certain commitments for both pipeline capacity and gas supply for which we pay fees regardless of usage. Those commitments as of December 31, 2013, average $47.4 million annually and total $210.4 million over the contracts’ lives. Approximately 39% of the financial commitments under these contracts expire during the next five years. We expect to renew each of these contracts under renewal provisions as provided in each contract. We recover all prudently incurred fees through rates via the Basic Gas Supply Service clause.

In 2011, while in its normal course of business, SJG has entered into long-term contracts for natural gas supplies.  SJG has committed to purchase a minimum of 6,250 dts/d and up to 25,000 dts/d of natural gas, from one supplier, for an original term of eight years at index-based prices. The obligation for this purchase has not been included in the Company's contractual obligations discussed below because the actual volumes and prices are not fixed.

25

The following table summarizes our contractual cash obligations and their applicable payment due dates as of December 31, 2013 (in thousands):

Contractual Cash Obligations	Total		Up to 1 Year		Years 2 & 3		Years 4 & 5		More than 5 Years
Principal Payments on Long-Term Debt	$	475,000	$	21,000	$	38,818	$	54,818	$	360,364
Interest on Long-Term Debt	256,187		21,148		39,740		35,852		159,447
Operating Leases	181		151		30		—		—
Construction Obligations	6,381		6,381		—		—		—
Commodity Supply Purchase Obligations	239,152		69,033		87,483		32,689		49,947
New Jersey Clean Energy Program	8,673		8,673		—		—		—
Other Purchase Obligations	359		359		—		—		—
Total Contractual Cash Obligations	$	985,933	$	126,745	$	166,071	$	123,359	$	569,758

Expected environmental remediation costs, asset retirement obligations and the liability for unrecognized tax benefits are not included in the table above as the total obligation cannot be calculated due to the subjective nature of these costs and timing of anticipated payments. SJG made contributions to its employee pension plans totaling $9.1 and $19.8 million in January 2013 and 2012, respectively.  However, future pension contributions beyond 2013 cannot be determined at this time. Our regulatory obligation to contribute $3.6 million annually to our postretirement benefit plans’ trusts, as discussed in Note 11 to the financial statements, is also not included as its duration is indefinite.

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

Pending Litigation - SJG is subject to claims which arise 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 $0.5 million related to all claims in the aggregate, as of both December 31, 2013 and 2012. Management does not believe that it is reasonably possible that there would 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 to have a material effect on our financial position, results of operations or liquidity.

Item 7a. 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. South Jersey Resources Group, LLC (SJRG), an affiliate by common ownership, manages some of our risk by entering into the types of transactions noted above. As part of our gas purchasing strategy, we use financial contracts through SJRG and another 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 December 31, 2013 is as follows (in thousands):

26

Assets
Source of Fair Value	Maturity < 1 Year		Maturity 1 - 3 Years		Total
Prices Actively Quoted (NYMEX)	$	1,131	$	278	$	1,409
Prices Provided by Other External Sources (Basis)	91		—		91
Total	$	1,222	$	278	$	1,500

Liabilities
	Maturity		Maturity
Source of Fair Value	< 1 Year		1 - 3 Years		Total
Prices Actively Quoted (NYMEX)	$	107	$	48	$	155
Prices Provided by Other External Sources (Basis)	604		—		604
Total	$	711	$	48	$	759

NYMEX (New York Mercantile Exchange) is the primary national commodities exchange on which natural gas is traded. 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 NYMEX contracts are 6.6 MMdt with a weighted-average settlement price of $4.00 per dt.  Contracted volumes of our Basis contracts are (1.4) MMdt with a weighted average settlement price of $0.68 per dt.

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

Net Derivatives — Energy Related Liability, January 1, 2013	$	(1,929	)
Contracts Settled During the Twelve Months ended December 31, 2013, Net	2,151
Other Changes in Fair Value from Continuing and New Contracts, Net	519
Net Derivatives — Energy Related Asset, December 31, 2013	$	741

The change in our derivative position from a $1.9 million liability at December 31, 2012 to a $0.7 million asset at December 31, 2013 is primarily due to the settlement of prior period financial positions. 

Interest Rate Risk - Our exposure to interest rate risk relates primarily to short-term, variable-rate borrowings. Short-term, variable-rate debt outstanding at December 31, 2013, was $65.5 million and averaged $91.4 million during 2013. A hypothetical 100 basis point (1%) increase in interest rates on our average variable-rate debt outstanding would result in a $0.5 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: 2013 - 14 b.p. decrease; 2012 - 1 b.p. decrease; 2011 - 14 b.p. decrease; 2010 – 5 b.p. increase; and 2009 – 29 b.p. decrease. As of December 31, 2013, our average interest rate on short-term, variable-rate debt was 0.31%.

We 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 December 31, 2013, the interest costs on all of our 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.

27

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

South Jersey Gas Company

Folsom, New Jersey

We have audited the accompanying balance sheets of South Jersey Gas Company (the "Company") as of December 31, 2013 and 2012, and the related statements of income, comprehensive income, cash flows, and changes in common equity and comprehensive income for each of the three years in the period ended December 31, 2013.  Our audits also included the financial statement schedule listed in the Index at Item 15(a)2.  These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of South Jersey Gas Company as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Philadelphia, Pennsylvania

February 28, 2014

28

SOUTH JERSEY GAS COMPANY

STATEMENTS OF INCOME

(In Thousands)

	Year Ended December 31,
	2013			2012			2011
Operating Revenues	$	446,480		$	421,874		$	412,449
Operating Expenses:
Cost of Sales (Excluding depreciation)	200,081			188,710			187,866
Operations	85,805			78,425			68,149
Maintenance	13,135			13,615			13,122
Depreciation	33,775			31,062			30,358
Energy and Other Taxes	7,862			8,300			10,291
Total Operating Expenses	340,658			320,112			309,786
Operating Income	105,822			101,762			102,663
Other Income and Expense	3,797			2,617			3,429
Interest Charges	(12,550		)	(12,427		)	(18,922		)
Income Before Income Taxes	97,069			91,952			87,170
Income Taxes	(34,833		)	(33,711		)	(34,281		)
Net Income	$	62,236		$	58,241		$	52,889

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

29

SOUTH JERSEY GAS COMPANY

STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

	Year Ended December 31,
	2013		2012			2011
Net Income	$	62,236	$	58,241		$	52,889
Other Comprehensive Income (Loss), Net of Tax:*
Postretirement Liability Adjustment	2,286		(1,683		)	(2,676		)
Unrealized Gain (Loss) on Available-for-Sale Securities	103		500			(360		)
Unrealized Gain on Derivatives - Other	27		27			27
Other Comprehensive Income (Loss) - Net of Tax*	2,416		(1,156		)	(3,009		)
Comprehensive Income	$	64,652	$	57,085		$	49,880

* Determined using a combined statutory tax rate of 41%.

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

30

SOUTH JERSEY GAS COMPANY

STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2013			2012			2011
Cash Flows from Operating Activities:
Net Income	$	62,236		$	58,241		$	52,889
Provided by Operating Activities:
Depreciation and Amortization	48,261			44,171			41,959
Provision for Losses on Accounts Receivable	4,232			4,775			1,410
CIP Receivable	21,160			(18,106		)	(1,289		)
Deferred Gas Costs - Net of Recoveries	5,473			25,050			(37,343		)
Deferred SBC Costs - Net of Recoveries	2,393			(4,183		)	(4,402		)
Environmental Remediation Costs - Net of Recoveries	(438		)	(188		)	(13,612		)
Deferred and Noncurrent Income Taxes and Credits - Net	31,940			38,353			35,037
Gas Plant Cost of Removal	(6,092		)	(2,133		)	(1,590		)
Pension Contribution	(9,100		)	(19,757		)	—
Changes in:
Accounts Receivable	(20,574		)	(34,263		)	37,428
Inventories	(7,153		)	13,449			(6,285		)
Prepaid and Accrued Taxes - Net	9,456			6,451			(7,831		)
Other Prepayments and Current Assets	(476		)	430			(1,420		)
Gas Purchases Payable	9,306			(2,941		)	(9,048		)
Accounts Payable and Other Accrued Liabilities	(5,107		)	(8,803		)	21,079
Other Assets	(7,323		)	(10,980		)	(6,294		)
Other Liabilities	10,565			3,807			9,789
Net Cash Provided by Operating Activities	148,759			93,373			110,477
Cash Flows from Investing Activities:
Capital Expenditures	(161,498		)	(156,041		)	(142,570		)
Net Proceeds from Restricted Investments in Margin Account	588			930			2,103
Investment in Long-Term Receivables	(7,182		)	(6,243		)	(4,926		)
Proceeds from Long-Term Receivables	5,764			8,182			6,312
Net Cash Used in Investing Activities	(162,328		)	(153,172		)	(139,081		)
Cash Flows from Financing Activities:
Net (Repayments of) Borrowings from Short-Term Credit Facilities	(36,600		)	(24,500		)	67,700
Proceeds from Issuance of Long-Term Debt	50,000			120,000			—
Principal Repayments of Long-Term Debt	(25,000		)	(35,000		)	(25,000		)
Premium for Early Retirement of Debt	—			(700		)	—
Payments for Issuance of Long-Term Debt	(411		)	(951		)	(43		)
Dividends on Common Stock	—			—			(12,664		)
Additional Investment by Shareholder	25,000			—			—
Excess Tax Benefit (Tax Deficiency) from Restricted Stock Plan	(78		)	124			85
Net Cash Provided by Financing Activities	12,911			58,973			30,078
Net (Decrease) Increase in Cash and Cash Equivalents	(658		)	(826		)	1,474
Cash and Cash Equivalents at Beginning of Period	2,678			3,504			2,030
Cash and Cash Equivalents at End of Period	$	2,020		$	2,678		$	3,504

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Supplemental Disclosures of Cash Flow Information
Interest (Net of Amounts Capitalized)	$	12,234		$	12,073		$	20,068
Income Taxes (Net of Refunds)	$	(5,056	)	$	(2,797	)	$	(1,044	)
Supplemental Disclosures of Noncash Investing Activities
Property and equipment acquired on account but not paid at year-end	$	20,055		$	11,069		$	12,171

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

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SOUTH JERSEY GAS COMPANY

BALANCE SHEETS

(In Thousands)

	December 31, 2013			December 31, 2012
Assets
Property, Plant and Equipment:
Utility Plant, at original cost	$	1,816,804		$	1,658,790
Accumulated Depreciation	(392,029		)	(373,199		)
Property, Plant and Equipment - Net	1,424,775			1,285,591
Investments:
Available-for-Sale Securities	8,696			7,520
Restricted Investments	680			1,268
Total Investments	9,376			8,788
Current Assets:
Cash and Cash Equivalents	2,020			2,678
Accounts Receivable	60,317			49,071
Accounts Receivable - Related Parties	968			961
Unbilled Revenues	41,510			35,351
Provision for Uncollectibles	(4,553		)	(3,985		)
Natural Gas in Storage, average cost	20,811			13,896
Materials and Supplies, average cost	1,798			1,560
Deferred Income Taxes - Net	23,309			—
Prepaid Taxes	7,683			17,046
Derivatives - Energy Related Assets	1,222			464
Other Prepayments and Current Assets	3,819			3,343
Total Current Assets	158,904			120,385
Regulatory and Other Noncurrent Assets:
Regulatory Assets	296,081			352,656
Unamortized Debt Issuance Costs	6,523			6,663
Long-Term Receivables	10,252			9,336
Derivatives - Energy Related Assets	278			302
Other	2,937			2,738
Total Regulatory and Other Noncurrent Assets	316,071			371,695
Total Assets	$	1,909,126		$	1,786,459

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

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SOUTH JERSEY GAS COMPANY

BALANCE SHEETS

(In Thousands, except per share amounts)

	December 31, 2013			December 31, 2012
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	225,972			201,050
Accumulated Other Comprehensive Loss	(10,869		)	(13,285		)
Retained Earnings	390,018			327,782
Total Common Equity	610,969			521,395
Long-Term Debt	454,000			425,000
Total Capitalization	1,064,969			946,395
Current Liabilities:
Notes Payable	65,500			102,100
Current Portion of Long-Term Debt	21,000			25,000
Accounts Payable - Commodity	24,232			14,926
Accounts Payable - Other	32,072			25,498
Accounts Payable - Related Parties	6,638			5,872
Derivatives - Energy Related Liabilities	711			2,615
Deferred Income Taxes - Net	—			10,432
Customer Deposits and Credit Balances	15,089			17,450
Environmental Remediation Costs	15,422			19,203
Taxes Accrued	1,767			1,674
Pension Benefits	1,241			1,236
Interest Accrued	6,039			6,277
Other Current Liabilities	5,629			6,492
Total Current Liabilities	195,340			238,775
Regulatory and Other Noncurrent Liabilities:
Regulatory Liabilities	60,949			56,517
Deferred Income Taxes - Net	380,975			310,357
Environmental Remediation Costs	104,070			88,207
Asset Retirement Obligations	41,178			38,892
Pension and Other Postretirement Benefits	48,197			89,193
Investment Tax Credits	360			618
Derivatives - Energy Related Liabilities	48			80
Derivatives - Other	3,735			7,761
Other	9,305			9,664
Total Regulatory and Other Noncurrent Liabilities	648,817			601,289
Commitments and Contingencies (Note 9)
Total Capitalization and Liabilities	$	1,909,126		$	1,786,459

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

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SOUTH JERSEY GAS COMPANY

STATEMENTS OF CHANGES IN COMMON EQUITY AND COMPREHENSIVE INCOME

(In Thousands)

	Common Stock		Other Paid-In Capital and Premium on Common Stock			Accumulated Other Comprehensive Loss			Retained Earnings			Total
Balance at January 1, 2011	$	5,848	$	200,841		$	(9,120	)	$	229,316		$	426,885
Net Income									52,889			52,889
Other Comprehensive Loss, Net of Tax: (a)						(3,009		)				(3,009		)
Cash Dividends Declared – Common Stock									(12,664		)	(12,664		)
Additional Investment by Shareholder			—									—
Excess Tax Benefit from Restricted Stock Plan			85									85
Balance at December 31, 2011	5,848		200,926			(12,129		)	269,541			464,186
Net Income									58,241			58,241
Other Comprehensive Loss, Net of Tax: (a)						(1,156		)				(1,156		)
Cash Dividends Declared – Common Stock									—			—
Additional Investment by Shareholder			—									—
Excess Tax Benefit from Restricted Stock Plan			124									124
Balance at December 31, 2012	5,848		201,050			(13,285		)	327,782			521,395
Net Income									62,236			62,236
Other Comprehensive Income, Net of Tax: (a)						2,416						2,416
Cash Dividends Declared – Common Stock									—			—
Additional Investment by Shareholder			25,000									25,000
Tax Deficiency from Restricted Stock Plan			(78		)							(78		)
Balance at December 31, 2013	$	5,848	$	225,972		$	(10,869	)	$	390,018		$	610,969

(a)  Determined using a combined statutory tax rate of 41%.

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

Disclosure of Changes in Accumulated Other Comprehensive Loss Balances (a)

(In Thousands)

	Postretirement Liability Adjustment			Unrealized Gain (Loss) on Available-for-Sale Securities			Unrealized Gain (Loss) on Derivatives			Accumulated Other Comprehensive Income (Loss)
Balance at January 1, 2011	$	(8,599	)	$	154		$	(675	)	$	(9,120	)
Changes During Year	(2,676		)	(360		)	27			(3,009		)
Balance at December 31, 2011	(11,275		)	(206		)	(648		)	(12,129		)
Changes During Year	(1,683		)	500			27			(1,156		)
Balance at December 31, 2012	(12,958		)	294			(621		)	(13,285		)
Changes During Year	2,286			103			27			2,416
Balance at December 31, 2013	$	(10,672	)	$	397		$	(594	)	$	(10,869	)

(a)  Determined using a combined statutory tax rate of 41%.

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

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NOTES TO 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). In our opinion, the 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. 

Certain reclassifications have been made to the prior periods regulatory assets disclosure to conform to the current period presentation. The deferred pipeline integrity cost previously included in "Other Regulatory Assets" was reclassified to the line item "Pipeline Integrity Cost" in the regulatory asset table disclosed in Note 4.

Equity Investments - Marketable equity securities that are purchased as long-term investments are classified as Available-for-Sale Securities and carried at their fair value on our balance sheets. Any unrealized gains or losses are included in Accumulated Other Comprehensive Loss.  An impairment loss is recorded when there is clear evidence that a decline in value is other than temporary.   No impairment losses were recorded on Investments during 2013, 2012 or 2011.

Estimates and Assumptions - We prepare our financial statements to conform with accounting principles generally accepted in the United States of America (GAAP). Management makes estimates and assumptions that affect the amounts reported in the financial statements and related disclosures. Therefore, actual results could differ from those estimates. Significant estimates include amounts related to regulatory accounting, energy derivatives, environmental remediation costs, pension and other postretirement benefit costs, and revenue recognition.

Regulation- We are subject to the rules and regulations of the New Jersey Board of Public Utilities (BPU). See Note 3 for a detailed discussion of our rate structure and regulatory actions. We maintain our accounts according to the BPU’s prescribed Uniform System of Accounts. We follow the accounting for regulated enterprises prescribed by the FASB ASC Topic 980 – “Regulated Operations.”  In general, Topic 980 allows for the deferral of certain costs (regulatory assets) and creation of certain obligations (regulatory liabilities) when it is probable that such items will be recovered from or refunded to customers in future periods. See Note 4 for a detailed discussion of regulatory assets and liabilities.

Operating Revenues - Gas revenues are recognized in the period the commodity is delivered to customers. For retail customers that are not billed at the end of the month, we record an estimate to recognize unbilled revenues for gas delivered from the date of the last meter reading to the end of the month.

Revenue and Throughput-Based Taxes - We collect certain revenue-based energy taxes from our customers. Such taxes include New Jersey State Sales Tax and Public Utilities Assessment (PUA). We also collect a throughput-based energy tax from customers in the form of a Transitional Energy Facility Assessment (TEFA). State sales tax is recorded as a liability when billed to customers and is not included in revenue or operating expenses. TEFA and PUA are included in both revenues and cost of sales and totaled $5.2 million, $6.0 million and $8.0 million in 2013, 2012 and 2011, respectively. TEFA is subject to a planned phase-out, which decreased the assessment in increments of 25.0% in 2013 and 2012 and is eliminated after December 31, 2013.

Accounts Receivable and Provision for Uncollectible Accounts - Accounts receivable are carried at the amount owed by customers. A provision for uncollectible accounts is established based on our collection experience and an assessment of the collectibility of specific accounts.

Natural Gas in Storage – Natural Gas in Storage is reflected at average cost on the balance sheets, and represents natural gas that will be utilized in the ordinary course of business.

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Property, Plant & Equipment - For regulatory purposes, utility plant is stated at original cost, which may be different than our cost if the assets were acquired from another regulated entity. The cost of adding, replacing and renewing property is charged to the appropriate plant account. Utility Plant balances as of December 31, 2013 and 2012 were comprised of the following (in thousands):

	2013		2012
Utility Plant:
Production Plant	$	296	$	296
Storage Plant	22,538		20,316
Transmission Plant	248,074		250,886
Distribution Plant	1,417,939		1,297,619
General Plant	53,162		49,586
Other Plant	1,855		1,855
Utility Plant in Service	1,743,864		1,620,558
Construction Work in Progress	72,940		38,232
Total Utility Plant	$	1,816,804	$	1,658,790

The increase in Utility Plant in Service is related to projects for distribution, some of which are part of the Company's Capital Investment Recovery Tracker (CIRT) and Accelerated Infrastructure Replacement Program (AIRP), as discussed under Note 3. The increase in Construction Work in Progress is primarily related to information technology projects.

Asset Retirement Obligations - The amounts included under Asset Retirement Obligations (ARO) are primarily related to the legal obligations we have to cut and cap our gas distribution pipelines when taking those pipelines out of service in future years. These liabilities are generally recognized upon the acquisition or construction of the asset. The related asset retirement cost is capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the liability. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

ARO activity during 2013 and 2012 was as follows (in thousands):

	2013			2012
ARO as of January 1,	$	38,892		$	29,388
Accretion	1,514			1,870
Additions	743			989
Settlements	(1,630		)	(1,603		)
Revisions in Estimated Cash Flows *	1,659			8,248
ARO as of December 31,	$	41,178		$	38,892

* The revision in estimated cash flows in 2013 reflects an increase in the inflation rate used to determine the ARO settlement amount. In 2012, the revision in estimated cash flows reflected increases in the contractual cost as well as changes in the discount rates used to determine the ARO. A corresponding increase was made to regulatory assets, thus having no impact on earnings.

Depreciation - We depreciate utility plant on a straight-line basis over the estimated remaining lives of the various property classes. These estimates are periodically reviewed and adjusted as required after BPU approval. The composite annual rate for all depreciable utility property was approximately 2.3% in 2013, 2.4% in 2012 and 2.3% in 2011. The actual composite rate may differ from the approved rate as the asset mix changes over time. Except for retirements outside of the normal course of business, accumulated depreciation is charged with the cost of depreciable utility property retired, less salvage.

Capitalized Interest - We capitalize interest on construction at the rate of return on rate base utilized by the BPU to set rates in our last base rate proceeding (See Note 3). Capitalized interest is included in Utility Plant on the balance sheets. Interest Charges are presented net of capitalized interest on the statements of income.  We capitalized interest of $8.2 million in 2013, $6.5 million in 2012 and $1.1 million in 2011. The increase in 2013 represents the interest on the Company's investment in Utility Plant under the BPU-approved CIRT and AIRP programs. Under the CIRT and AIRP, qualified capital expenditures continued to accrue interest on construction until such projects were rolled into customer rates and recovery of the expenditures commenced.

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All CIRT program investments have been rolled into rate base and the CIRT program is now concluded. See Note 3 for additional discussion of the CIRT programs.

Impairment of Long-Lived Assets - We review the carrying amount of long-lived assets for possible impairment whenever events or changes in circumstances indicate that such amounts may not be recoverable. For the years ended 2013, 2012 and 2011, no significant impairments were identified.

Derivative Instruments - SJG, through its affiliate, South Jersey Resources Group (SJRG) and another counterparty, uses a variety of derivative instruments to limit its exposure to market risk in accordance with strict guidelines (See Note 14).  These contracts, which 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 balance sheets.  The costs or benefits of these short-term contracts are recoverable through SJG’s Basic Gas Supply Service (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 balance sheets.

SJG 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 balance sheets.  The fair value represents the amount SJG would have to pay the counterparty to terminate these contracts as of those dates.  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 Other Regulatory Assets in the balance sheets.

Income Taxes - Deferred income taxes are provided for all significant temporary differences between the book and taxable basis of assets and liabilities in accordance with FASB ASC Topic 740 – “Income Taxes” (See Note 6). A valuation allowance is established when it is determined that it is more likely than not that a deferred tax asset will not be realized.

Cash and Cash Equivalents - For purposes of reporting cash flows, highly liquid investments with original maturities of three months or less are considered cash equivalents.

NEW ACCOUNTING PRONOUNCEMENTS- Other than as described below, no new accounting pronouncement issued or effective during 2013, 2012 or 2011 had, or is expected to have, a material impact on the financial statements.

In January 2012, the FASB issued Accounting Standards Update (ASU) 2011-11, Enhanced Disclosure Requirements Concerning Offsetting of Financial Assets and Financial Liabilities. This ASU amends ASC 210-20 to add disclosure requirements in respect of the offsetting of financial assets and financial liabilities. In February 2013, the FASB issued ASU 2013-01 Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which amends and clarifies the scope of the balance sheet offsetting disclosures required through ASU 2011-11. The new guidance was effective for fiscal years beginning on or after January 1, 2013. The adoption of this guidance modified the disclosures around derivative instruments, but did not have an impact on the Company's financial statement results.

In February 2013, the FASB issued ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This ASU expands the disclosure requirements in ASC 220 and requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective lines in net income. The ASU requires an entity to present information about significant items reclassified out of accumulated other comprehensive income by component either on the face of the statement where net income is presented, or as a separate disclosure in the notes to the financial statements. The new guidance was effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. The adoption of this guidance modified the disclosures around accumulated other comprehensive income, but did not have an impact on the Company's financial statement results.

In July 2013, the FASB issued ASU 2013-11, Balance Sheet Presentation of an Unrecognized Income Tax Benefit for a Net Operating Loss or Tax Credit Carryforward. This ASU provides that a liability related to an unrecognized tax benefit should be offset against a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. Management does not anticipate that the adoption of this guidance will have an impact on the Company's financial statement results.

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2. STOCK-BASED COMPENSATION PLANS:

Officers and other key employees of SJG participate in the Stock Option, Stock Appreciation Rights and Restricted Stock Award Plan ("Plan") of SJI. Restricted shares issued under this 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 between 0% to 150% of the original share units granted.

Grants containing market-based performance targets have been issued in each of the last three years and 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.

Beginning with 2012, grants containing earnings-based targets have also been issued. These new grants are based on SJI's earnings per share (EPS) growth rate relative to a peer group to measure performance. As EPS-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 goals.

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 December 31, 2013, and the assumptions used to estimate the fair value of the awards:

Grant Date	Shares Outstanding	Fair Value Per Share		Expected Volatility		Risk-Free Interest Rate
Jan. 2012 - TSR	3,533	$	51.23	22.5	%	0.43	%
Jan. 2012 - EPS	3,533	$	56.93	n/a		n/a
Jan. 2013 - TSR	4,001	$	44.38	21.1	%	0.40	%
Jan. 2013 - EPS	4,001	51.18		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 Officers' and other key employees' restricted shares. As notional dividend equivalents are credited to the holders, which are reinvested during the three year service period, no reduction to the fair value of the award is required.

The cost for restricted stock awards was $0.4 million in each of the years 2013, 2012 and 2011. Of these costs, $0.2 million was capitalized to Utility Plant in each of those years.

As of December 31, 2013, there was $0.4 million of total unrecognized compensation cost related to nonvested share-based compensation awards granted under the restricted stock plans. That cost is expected to be recognized over a weighted average period of 1.7 years.

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The following table summarizes information regarding restricted stock award activity during 2013, excluding accrued dividend equivalents:

	Shares		Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, January 1, 2013	15,108		$	52.55
Granted	9,324		$	47.78
Vested*	(7,116	)	$	50.94
Cancelled / Forfeited	(2,248	)	$	50.02
Nonvested Shares Outstanding, December 31, 2013	15,068		$	50.73

* Performance targets during the 3-year vesting period were not attained for the January 2011 grant. As a result, no shares will be awarded in 2014.

During 2013, SJG awarded 12,901 shares that had vested at December 31, 2012, to its officers and other key employees at a market value of $0.6 million. During 2012, SJG awarded 7,098 shares at a market value of $0.4 million. SJG has a policy of making cash payments to SJI to satisfy its obligations under this plan. Cash payments to SJI during 2013 and 2012 were approximately $0.4 million and $0.3 million, respectively, relating to stock awards. Additionally, a change in control could result in the nonvested shares becoming nonforfeitable or immediately payable in cash.

3. RATES AND REGULATORY ACTIONS:

Base Rates - SJG is subject to the rules and regulations of the BPU.  In September 2010, the BPU granted SJG a base rate increase of $42.1 million, which was predicated, in part, upon an 8.21% rate of return on rate base that included a 10.3% return on common equity.  The $42.1 million includes $16.6 million of revenue previously recovered through the Conservation Incentive Program (CIP) and $6.8 million of revenues previously recovered through the Capital Investment Recovery Tracker (CIRT), resulting in incremental revenue of $18.7 million.  SJG was permitted to recover regulatory assets contained in its petition and defer certain federally mandated pipeline integrity management program costs for recovery in its next base rate case.  In addition, annual depreciation expense will be reduced by $1.2 million as a result of the amortization of excess cost of removal recoveries.  The BPU also authorized a Phase II of the base rate proceeding to review the costs of CIRT projects not rolled into rate base in the September 2010 settlement. A proceeding took place in 2013 to roll into base rates the remaining $22.5 million of CIRT I project costs that were not included in the 2010 rate increase, as well as CIRT II and III investments totaling $95.0 million that were made subsequent to the 2010 base rate case. These costs were rolled into rate base and reflected in base rates effective October 2013.

In November 2013, we filed a base rate case with the BPU to increase our base rates to obtain a certain level of return on our capital investments. We expect the base rate case to be concluded during 2014. Other than the CIRT items discussed above, we have not sought a base rate increase from the BPU since the implementation of our base rate case approved in September 2010.

40

Rate Mechanisms - Our tariff, a schedule detailing the terms, conditions and rate information applicable to our various types of natural gas service, as approved by the BPU, has several primary rate mechanisms as discussed in detail below:

Basic Gas Supply Service (BGSS) Clause - The BGSS price structure was approved by the BPU in January 2003, and allows us to recover all prudently incurred gas costs. BGSS charges to customers can be either monthly or periodic (annual). Monthly BGSS charges are applicable to large use customers and are referred to as monthly because the rate changes on a monthly basis pursuant to a BPU-approved formula based on commodity market prices. Periodic BGSS charges are applicable to lower usage customers, which include all of our residential customers, and are evaluated at least annually by the BPU. However, to some extent, more frequent rate changes to the periodic BGSS are allowed. We collect gas costs from customers on a forecasted basis and defer periodic over/under recoveries to the following BGSS year, which runs from October 1 through September 30. If we are in a net cumulative undercollected position, gas costs deferrals are reflected on the balance sheet as a regulatory asset. If we are in a net

cumulative overcollected position, amounts due back to customers are reflected on the balance sheet as a regulatory liability. We pay interest on net overcollected BGSS balances at the rate of return on rate base utilized by the BPU to set rates in our last base rate proceeding.

Regulatory actions regarding the BGSS were as follows:

• March 2011 - We credited the accounts of our periodic BGSS customers with refunds totaling $21.1 million due to gas costs that were lower than projected during the winter season.

• June 2011 - We filed our annual BGSS filing with the BPU requesting a $10.6 million, or 2.9%, reduction in gas cost recoveries commencing on October 1, 2011.

• September 2011 - The BPU issued an Order finalizing the 2010-2011 provisional BGSS rate and approved, on a provisional basis, SJG's request for a $10.6 million, or 2.9%, reduction in gas cost recoveries.

• December 2011 - We credited the accounts of our periodic BGSS customers with refunds totaling $18.7 million due to gas costs that were lower than projections.

• May 2012 - The BPU issued an Order finalizing the 2011-2012 provisional BGSS rates.

• June 2012 - We filed our annual BGSS filing with the BPU requesting a $27.0 million, or 8.8%, reduction in gas cost recoveries commencing on October 1, 2012.

• September 2012 - The BPU issued an Order approving, on a provisional basis, SJG's request for a $27.0 million, or 8.8%, reduction in gas cost recoveries.

• January 2013 - We credited the accounts of our periodic BGSS customers with refunds totaling $9.4 million due to gas costs that were lower than projections.

• May 2013 - We filed our annual BGSS filing with the BPU requesting a $0.6 million reduction in gas cost recoveries.

• September 2013 - The BPU issued an Order approving, on a provisional basis, SJG’s request for a $0.6 million reduction in gas cost recoveries.

• January 2014 - We credited the accounts of our periodic BGSS customer with refunds totaling $11.2 million due to gas costs that were lower than projected.

Conservation Incentive Program (CIP) - The primary purpose of the CIP is to promote conservation efforts, without negatively impacting financial stability, and to base our profit margin on the number of customers rather than the amount of natural gas distributed to customers. In October 2006, the BPU approved the CIP as a three-year pilot program. In January 2010, the BPU approved an extension of this program through September 2013, with an automatic one year extension through September 2014 if a request for an extension was filed by March 2013. A petition was filed in March 2013 to extend the CIP program. Each CIP year begins October 1 and ends September 30 of the subsequent year. On a monthly basis during the CIP year, we record adjustments to earnings based on weather and customer usage factors, as incurred. Subsequent to each year, we make filings with the BPU to review and approve amounts recorded under the CIP. BPU approved cash inflows or outflows generally will not begin until the next CIP year.

Regulatory actions regarding the CIP were as follows:

• June 2011 - We made our annual CIP filing with the BPU requesting recovery of $2.5 million, which includes a $2.7 million credit to customers for the current 2011-2012 CIP year and prior year carryovers of $5.2 million. The CIP credit of $2.7 million includes $1.3 million non-weather related credits and $1.4 million weather related credits.

• September 2011 - The BPU issued an Order finalizing the 2010-2011 provisional CIP rates and also approved, on a provisional basis, the 2011-2012 CIP rates filed in June 2011, effective October 1, 2011.

• May 2012 - The BPU issued an Order finalizing the 2011-2012 provisional CIP rates.

• June 2012 - We made our annual CIP filing with the BPU requesting recovery of $28.0 million, which includes a $8.4 million non-weather related recovery and a $19.6 million weather related recovery.

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• September 2012 - The BPU issued an Order approving, on a provisional basis, the 2012-2013 CIP rates filed in June 2012, effective October 1, 2012.

• March 2013 - We filed a joint petition with another utility requesting modification to, and the continuation of, the CIP program effective October 1, 2013.

• May 2013 - We made our annual CIP filing with the BPU requesting a reduction in revenue of $17.8 million, which includes a $2.3 million reduction in non-weather related recovery and a $15.5 million reduction in weather related recovery.

• September 2013 - The BPU issued an Order approving, on a provisional basis, the 2013-2014 CIP rates filed in May 2013, effective October 1, 2013.

Capital Investment Recovery Tracker (CIRT) - In January 2009, we made a filing with the BPU requesting approval for an accelerated infrastructure investment program.  The purpose of the CIRT was to accelerate $103.0 million of capital expenditures from five years to two years.  The petition requested that we be allowed to earn a return of, and a return on, our investment.  Under the CIRT, 2009 spending was projected to be $70.5 million and 2010 spending was projected to be $32.5 million.  In September 2010, the BPU authorized $81.3 million of CIRT-related expenditures to be rolled into rate base and also authorized that the remaining balance of CIRT-related expenditures continue to be recovered.  These remaining expenditures were reviewed and rolled into rate base during Phase II of the base rate case. On a monthly basis during the CIRT year, we recorded adjustments to earnings based on actual CIRT program expenditures, as incurred.  Annually we made filings with the BPU for review and approval of expenditures recorded under the CIRT.

Regulatory actions regarding the CIRT were as follows:

• March 2011 - The BPU approved a CIRT II program allowing the Company to accelerate an additional $60.3 million of capital spending into 2011 and 2012. Under CIRT II, the Company continues to earn a return on investment as the capital is spent, as it did under the original CIRT. The return of investment begins when the investments are rolled into rate base. As such, the Company is permitted to earn a return on CIRT II investments until the roll in is approved and recovery commences.

• June 2011 - The Company filed a petition with the BPU requesting the recovery of a portion of CIRT II investments via a roll-in to rate base, and requested to increase the base rates by 0.5%.

• October 2011 - The Company filed a petition with the BPU requesting to modify and extend the CIRT II program. The petition requested an additional incremental investment of $40.0 million in 2012 and $50.0 million in 2013.

• May 2012 - The BPU approved a modification and extension of the CIRT II program (CIRT III), allowing the Company to accelerate an incremental $35.0 million of capital spending through December 2012.

• October 2012 - The Company filed a petition requesting a $13.2 million increase in annual revenues by rolling $110.6 million of CIRT I, II and III investments into base rates.

• September 2013 - The BPU approved the base rate roll in of the CIRT I, II and III program investments effective October 2013, resulting in a $15.5 million increase in annual revenue. This approval also concluded Phase II of the 2010 base rate case.

All CIRT program investments have been rolled into rate base and the CIRT program is now concluded.

Accelerated Infrastructure Replacement Program (AIRP) - In July 2012, the company filed a petition to implement a five-year, $250.0 million Accelerated Infrastructure Replacement Program to replace the annual CIRT programs. In February 2013, the BPU issued a Board Order approving a $141.2 million program to replace cast iron and unprotected bare steel mains and services over a four year period, with annual investments of approximately $35.3 million. Pursuant to the Board Order, AIRP investments are to be reviewed and included in rate base in future base rate proceedings.

Storm Hardening and Reliability Program (SHARP) - In September 2013, we filed with the BPU an asset hardening program pursuant to which SJG will invest approximately $280.0 million over seven years to replace low pressure distribution mains and services with high pressure mains and services in coastal areas that are susceptible to flooding during major storm events. This petition is currently pending.

Energy Efficiency Tracker (EET) - In January 2009, we filed a petition with the BPU requesting approval of an Energy Efficiency Program (EEP I) for residential, commercial and industrial customers.  The BPU approved this petition in July 2009. Under this program we were permitted to invest $17.0 million over two years in energy efficiency measures to be installed in customer homes and businesses. We also recover incremental operating and maintenance expenses and earn a return of, and return on, program investments.

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Regulatory actions regarding the EET were as follows:

• November 2010 - We filed a petition with the BPU requesting a one year extension of the program and a reallocation of investment dollars between the EET programs to fund the more popular programs. In January 2011, SJG’s request to reallocate investment dollars between the programs and a one year extension was approved by the BPU.

• June 2011 - We filed our annual 2011-2012 petition requesting approval of a $4.7 million increase in EET recovery. This petition was approved in September 2012, with rates effective October 1, 2012.

• October 2011 - We filed a petition requesting a modification of the EET with regards to the Combined Heat and Power (CHP) program. The BPU approved this petition in February 2012.

• May 2012 - We filed a petition requesting the approval of a new Energy Efficiency Program (“EEP II”) and to continue our existing EET to recover all costs associated with the EEP II through a $3.1 million increase in annual revenues. These programs provide customers with increased incentives to reduce their natural gas consumption. In June 2013, the BPU approved the EEP II program in the form of an extension of the existing EEP program, permitting SJG to invest $24.0 million in energy efficiency programs through June 2015. The BPU also approved in June 2013 an extension of the EET with a $2.1 million revenue increase effective July 2013.

• June 2012 - We filed a petition requesting a continuation of the original Energy Efficiency Program (“EEP I”) to bridge the gap between the expiration of the EEP I program on April 30, 2012, and the implementation of the proposed new EEP II program. This petition was approved by the BPU in August 2012. Also in June 2012, SJG filed its 2012 - 2013 annual EET rate adjustment petition requesting a $5.8 million increase in annual revenues to recover the costs associated with its EEP I program. This petition is still pending.

• May 2013 - we filed our annual petition requesting an increase of $2.2 million for current EET programs. This petition is still pending.

Societal Benefits Clause (SBC) - The SBC allows us to recover costs related to several BPU-mandated programs. Within the SBC are a Remediation Adjustment Clause (RAC), a New Jersey Clean Energy Program (NJCEP), a Universal Service Fund (USF) program and a Consumer Education Program (CEP).

Regulatory actions regarding the SBC, with the exception of USF which requires separate regulatory filings, were as follows:

• July 2011 - We made our annual 2011-2012 SBC filing requesting a $31.2 million increase in SBC recoveries. The BPU approved this filing in July 2013.

• September 2011 - The BPU finalized rates for the 2008-2009 and 2009-2010 SBC petitions.

• July 2012 - We made our annual 2012-2013 SBC filing requesting an $11.8 million increase in SBC recoveries. The BPU approved this filing in July 2013.

• September 2012 - The BPU finalized rates for the 2010-2011 SBC petition effective October 1, 2012.

• July 2013 - We made our annual 2013-2014 SBC filing requesting a $6.4 million decrease in SBC revenues. This petition is still pending.

Remediation Adjustment Clause (RAC) - The RAC recovers environmental remediation costs of 12 former gas manufacturing plants (See Note 12). The BPU allows us to recover such costs over seven-year amortization periods. The net between the amounts actually spent and amounts recovered from customers is recorded as a regulatory asset, Environmental Remediation Cost Expended - Net. Note that RAC activity affects revenue and cash flows but does not directly affect earnings because of the cost recovery over seven-year amortization periods. As of December 31, 2013 and 2012, we reflected the unamortized remediation costs of $29.9 million and $37.9 million, respectively, on the balance sheet under Regulatory Assets (See Note 4). Since implementing the RAC in 1992, we have recovered $92.6 million through rates.

New Jersey Clean Energy Program (NJCEP) - This mechanism recovers costs associated with our energy efficiency and renewable energy programs. In August 2008, the BPU approved the statewide funding of the NJCEP of $1.2 billion for the years 2009 through 2012. Of this amount, SJG was responsible for expensing approximately $41.5 million over the four-year period. In November 2012, the BPU approved a six-month extension of the program through June 2013. Under this extension, SJG is responsible for $7.5 million of funding. NJCEP adjustments affect revenue and cash flows but do not directly affect earnings as related costs are deferred and recovered through rates on an on-going basis.

Universal Service Fund (USF) - The USF is a statewide program through which funds for the USF and Lifeline Credit and Tenants Assistance Programs are collected from customers of all New Jersey electric and gas utilities. USF adjustments affect cash flows but do not directly affect revenue or earnings as related costs are deferred and recovered through rates on an ongoing basis.

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Separate regulatory actions regarding the USF were as follows:

• June 2011 - We made our annual USF filing, along with the state's other electric and gas utilities, proposing to decrease annual statewide gas revenues by $9.3 million. This proposal was designed to decrease our annual USF revenue by $0.8 million.

• October 2011 - The BPU approved the statewide budget of $57.4 million for all of the State's gas utilities. Our portion of the total is approximately $5.4 million, which decreased rates effective November 1, 2011, resulting in a $0.5 million decrease to our annual USF recoveries.

• June 2012 - We made our annual USF filing, along with the state's other electric and gas utilities, proposing to decrease annual statewide gas revenues by $0.5 million. This proposal was designed to decrease our annual USF revenue by $0.1 million.

• September 2012 - The BPU approved the statewide budget of $78.0 million for all of the State's gas utilities. Our portion of the total is approximately $8.2 million, which decreased rates effective October 1, 2012, resulting in a $0.1 million decrease to our annual USF recoveries.

• June 2013 - We made our annual USF filing, along with the state’s other electric and gas utilities, proposing to decrease the statewide gas revenues by $29.4 million. This proposal was designed to decrease our annual USF revenue by $3.7 million.

• September 2013 - The BPU approved the statewide USF budget of $54.4 million for all the State’s gas utilities.  Our portion of the total is approximately $5.8 million, which decreased rates effective October 1, 2013, resulting in a $3.4 million decrease to our USF recoveries.

Other Regulatory Matters -

Unbundling - In 2000, the BPU approved full unbundling of our system. This allows all natural gas consumers to select their natural gas commodity supplier. As of December 31, 2013, 47,074 of our customers were purchasing their gas commodity from someone other than us. Customers choosing to purchase natural gas from providers other than the utility are charged for the cost of gas by the marketer. The resulting decrease in our revenues is offset by a corresponding decrease in gas costs. While customer choice can reduce utility revenues, it does not negatively affect our net income or financial condition. The BPU continues to allow for full recovery of prudently incurred natural gas costs through the BGSS. Unbundling did not change the fact that we still recover cost of service, including certain deferred costs, through base rates.

Pipeline Integrity - In October 2005, we filed a petition with the BPU to implement a Pipeline Integrity Management Tracker (Tracker). The purpose of this Tracker was to recover incremental costs to be incurred by us as a result of new federal regulations, which are aimed at enhancing public safety and reliability. The regulations require that utilities use a comprehensive analysis to assess, evaluate, repair and validate the integrity of certain transmission lines in the event of a leak or failure. As part of our September 2010 base rate increase, we were permitted to recover previously deferred pipeline integrity costs incurred through September 2010.  In addition, we are authorized to defer future program costs, including related carrying costs, for recovery in our next base rate proceeding, subject to review by the BPU.  Accordingly, SJG withdrew its petition for the Pipeline Integrity Management Tracker.  As of December 31, 2013 and 2012, deferred pipeline integrity costs totaled $2.8 million and $1.6 million, respectively, and are included in other regulatory assets (See Note 4).

Superstorm Sandy - In June 2013, we filed a petition requesting deferral of incremental operating and maintenance expenses incurred due to Superstorm Sandy. These costs totaled $0.7 million and are expected to be recovered in SJG’s next base rate case. This petition is currently pending.

Filings and petitions described above are still pending unless otherwise indicated.

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4. REGULATORY ASSETS AND LIABILITIES:

The discussion under Note 3, Rates and Regulatory Actions, is integral to the following explanations of specific regulatory assets and liabilities.

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

	2013		2012
Environmental Remediation Costs:
Expended - Net	$	29,945	$	37,892
Liability for Future Expenditures	119,492		107,410
Deferred Asset Retirement Obligation Costs	31,142		30,199
Deferred Pension and Other Postretirement Benefit Costs	59,284		95,897
Conservation Incentive Program Receivable	10,526		31,686
Societal Benefit Costs Receivable	10,408		12,801
Premium for Early Retirement of Debt	955		1,075
Deferred Interest Rate Contracts	3,735		7,761
Energy Efficiency Tracker	10,420		12,306
Pipeline Supplier Service Charges	7,106		8,771
Pipeline Integrity Cost	2,902		1,584
Other Regulatory Assets	10,166		5,274
Total Regulatory Assets	$	296,081	$	352,656

Except where noted below, all regulatory assets are or will be recovered through utility rate charges, as detailed in the following discussion. We are currently permitted to recover interest on our Environmental Remediation Costs, Societal Benefit Costs Receivable, Energy Efficiency Tracker and Pipeline Integrity Costs, while the other assets are being recovered without a return on investment.

Environmental Remediation Costs - We have two regulatory assets associated with environmental costs related to the cleanup of 12 sites where we or our predecessors previously operated gas manufacturing plants. The first asset, Environmental Remediation Cost: Expended - Net, represents what was actually spent to clean up the sites, less recoveries through the RAC and insurance carriers. These costs meet the deferral requirements of GAAP, as the BPU allows us to recover such expenditures through the RAC. The other asset, Environmental Remediation Cost: Liability for Future Expenditures, relates to estimated future expenditures required to complete the remediation of these sites. We recorded this estimated amount as a regulatory asset with the corresponding current and noncurrent liabilities on the balance sheets under the captions Current Liabilities and Regulatory and Other Noncurrent Liabilities. The BPU allows us to recover the deferred costs over seven-year periods after they are spent (See Notes 3 and 12).

Deferred Asset Retirement Obligation Costs - This regulatory asset  resulted from the recording of asset retirement obligations (ARO) and additional utility plant, primarily related to a legal obligation we have for certain safety requirements upon the retirement of our gas distribution and transmission system. We recover asset retirement costs through rates charged to customers. All related accumulated accretion and depreciation amounts for these ARO represent timing differences in the recognition of retirement costs that we are currently recovering in rates and, as such, we are deferring such differences as regulatory assets.

Deferred Pension and Other Postretirement Benefit Costs  - The BPU authorized us to recover costs related to postretirement benefits under the accrual method of accounting consistent with  GAAP.  We deferred amounts accrued prior to that authorization and amortized them as allowed by the BPU over 15 years through 2012. In 2006, our regulatory asset was increased by $37.1 million representing the recognition of the underfunded positions of our pension and other postretirement benefit plans.  Subsequent adjustments to this balance occur annually to reflect changes in the funded positions of these benefit plans caused by changes in actual plan experience as well as assumptions of future experience (See Note 11).

Conservation Incentive Program Receivable - The impact of the CIP is recorded as an adjustment to earnings as incurred, while cash recovery under the CIP generally occurs during the subsequent CIP year (see Note 3).

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Societal Benefit Costs Receivable - This regulatory asset primarily represents cumulative costs less recoveries under the USF program (See Note 3). 

Premium for Early Retirement of Debt - At December 31, 2013, this regulatory asset represents unamortized debt issuance costs related to long-term debt refinancings. Unamortized debt issuance costs are being amortized over the term of the new debt issue pursuant to regulatory approval by the BPU.

Energy Efficiency Tracker - This regulatory asset represents cumulative investments less recoveries under the Energy Efficiency Program (See Note 3).

Deferred Interest Rate Contracts - These amounts represent the market value of interest rate derivatives as discussed further in Note 13.

Pipeline Supplier Service Charges - This regulatory asset represents costs necessary to maintain adequate supply and system pressures, which are being recovered on a monthly basis through the BGSS over the term of the underlying supplier contracts (See Note 3).

Pipeline Integrity Cost - As part of our September 2010 base rate increase, we were permitted to recover previously deferred pipeline integrity costs incurred through September 2010. In addition, we are authorized to defer future program costs, including related carrying costs, for recovery in our next base rate proceeding, subject to review by the BPU (see Note 3).

Other Regulatory Assets - Some of the assets included in Other Regulatory Assets are currently being recovered from ratepayers as approved by the BPU. Management believes the remaining deferred costs are probable of recovery from ratepayers through future utility rates.

Regulatory Liabilities at December 31 consisted of the following items (in thousands):

	2013		2012
Excess Plant Removal Costs	$	40,029	$	45,593
Deferred Revenue - Net	19,067		10,924
Other Regulatory Liabilities	1,853		—
Total Regulatory Liabilities	$	60,949	$	56,517

Excess Plant Removal Costs – Represents amounts accrued in excess of actual utility plant removal costs incurred to date.  As part of our September 2010 base rate increase, we are required to amortize approximately $1.2 million of this balance to depreciation expense each year.

Deferred Revenues – Net - Over/under collections of gas costs are monitored through our BGSS mechanism. Net undercollected gas costs are classified as a regulatory asset and net overcollected gas costs are classified as a regulatory liability (See Note 3). Derivative contracts used to hedge our natural gas purchases are also included in the BGSS, subject to BPU approval (See Note 14). The increase from a $10.9 million regulatory liability at December 31, 2012 to a $19.1 million regulatory liability at December 31, 2013 was due to gas costs recovered from customers exceeding the actual cost of the commodity incurred during 2013.

Other Regulatory Liabilities – All other regulatory liabilities are subject to being returned to ratepayers in future rate proceedings.

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5. RELATED PARTY TRANSACTIONS:

We conducted business with our parent, SJI, and several other related parties. A description of each of these affiliates and related transactions is as follows:

SJI Services, LLC (SJIS) - a wholly owned subsidiary of SJI, provides services, such as information technology, human resources, corporate communications, materials purchasing and fleet management to SJI and all of its subsidiaries.

South Jersey Energy Solutions, LLC (SJES) - a wholly owned subsidiary of SJI that serves as a holding company for all of SJI’s nonutility operating businesses:

• South Jersey Energy Company (SJE) - a wholly owned subsidiary of SJES and a third party energy marketer that acquires and markets natural gas and electricity to retail end users and provides total energy management services to commercial and industrial customers. We provide SJE with billing services. For SJE’s residential customers, for which we perform billing services, we purchase the related accounts receivable at book value less a factor for potential uncollectible accounts, and assume all risk associated with collection.

• South Jersey Resources Group, LLC (SJRG) - a wholly owned subsidiary of SJES and a wholesale gas and risk management business that supplies natural gas storage, commodity and transportation to retail marketers, utility businesses and electricity generators in the mid-Atlantic, Appalachian and southern states. We sell natural gas for resale and capacity release to SJRG and also meet some of our gas purchasing requirements by purchasing natural gas from SJRG. Additionally, SJRG manages our market risk associated with fluctuations in the cost of natural gas by entering into financial derivative contracts on our behalf. The gain or loss associated with these derivative contracts is included in our BGSS and in the SJRG receivable and payable amounts shown below.

• Marina Energy LLC (Marina) - a wholly owned subsidiary of SJES and developer, owner and operator of energy related projects. We provide natural gas transportation services to Marina under BPU-approved tariffs.

• South Jersey Energy Service Plus, LLC (SJESP) - a wholly owned subsidiary of SJES and an appliance service company. We provide billing services to SJESP.

Millennium Account Services, LLC (Millennium) - a partnership between SJI and Pepco Holdings, Inc, which reads our utility customers’ meters on a monthly basis for a fee.

Sales of gas to SJRG and SJE comply with Section 284.02 of the Regulations of the Federal Energy Regulatory Commission (FERC).

In addition to the above, we provide various administrative and professional services to SJI and each of the affiliates discussed above. Likewise, SJI and SJIS provide substantial administrative services on our behalf. For certain types of transactions, we served as central processing agents for the related parties discussed above. Amounts due to and due from these related parties for pass-through items are not considered material to the financial statements as a whole. A summary of these related party transactions, excluding pass-through items, included in Operating Revenues were as follows (in thousands):

	2013		2012		2011
Operating Revenues/Affiliates:
SJRG	$	1,390	$	884	$	6,532
Other	1,299		851		716
Total Operating Revenues/Affiliates	$	2,689	$	1,735	$	7,248

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

	2013			2012			2011
Costs of Sales/Affiliates
(Excluding depreciation):
SJRG	$	14,959		$	9,083		$	33,768
Derivative Losses (See Note 1):
SJRG	$	887		$	15,407		$	12,872
Operations Expense/Affiliates:
SJI	$	11,990		$	10,870		$	9,941
SJIS	5,531			5,397			4,956
Millennium	2,686			3,149			3,076
Other	(428		)	(500		)	(448		)
Total Operations Expense/Affiliates	$	19,779		$	18,916		$	17,525

6. INCOME TAXES AND CREDITS:

Total income taxes applicable to operations differ from the tax that would have resulted by applying the statutory Federal income tax rate to pre-tax income for the following reasons (in thousands):

	2013			2012			2011
Tax at Statutory Rate	$	33,974		$	32,183		$	30,510
Increase (Decrease) Resulting from:
State Income Taxes	4,833			5,302			5,316
Amortization of Investment Tax Credits	(258		)	(287		)	(302		)
ESOP Dividend	(1,058		)	(1,027		)	(956		)
AFUDC	(916		)	(1,048		)	(729		)
Amortization of Flowthrough Depreciation	—			—			526
Other - Net	(1,742		)	(1,412		)	(84		)
Net Income Taxes	$	34,833		$	33,711		$	34,281

The provision for Income Taxes is comprised of the following (in thousands):

	2013			2012			2011
Current:
Federal	$	(53	)	$	(4,635	)	$	(924	)
State	2,946			(7		)	168
Total Current	2,893			(4,642		)	(756		)
Deferred:
Federal	27,707			30,477			27,329
State	4,491			8,163			8,010
Total Deferred	32,198			38,640			35,339
Investment Tax Credits	(258		)	(287		)	(302		)
Net Income Taxes	$	34,833		$	33,711		$	34,281

Investment Tax Credits are deferred and amortized at the annual rate of 3%, which approximates the life of related assets.

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The net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and income tax purposes resulted in the following net deferred tax liabilities at December 31 (in thousands):

	2013			2012
Current:
Net Operating Loss Carryforward	$	(27,600	)	$	(2,586	)
Budget Billing - Customer Accounts	1,152			1,033
Provision for Uncollectibles	(1,726		)	(1,409		)
Conservation Incentive Program	4,631			13,942
Section 461 Prepayments	1,156			930
Other	(922		)	(1,478		)
Current Deferred Tax (Asset) Liability - Net	$	(23,309	)	$	10,432
Noncurrent:
Book Versus Tax Basis of Property	$	371,684		$	323,470
Deferred Fuel Costs - Net	1,330			3,325
Environmental Remediation	14,392			17,643
Deferred Regulatory Costs	13,665			15,374
Deferred State Tax	(15,471		)	(15,106		)
Investment Tax Credit Basis Gross-Up	(185		)	(318		)
Deferred Pension & Other Post Retirement Benefits	24,218			39,174
Pension & Other Post Retirement Benefits	(14,152		)	(28,846		)
Deferred Revenues	(9,266		)	(8,922		)
Net Operating Loss Carryforward	(8,764		)	(35,901		)
Other	3,524			464
Noncurrent Deferred Tax Liability – Net	$	380,975		$	310,357

SJG is included in the consolidated federal income tax return filed by SJI. The actual taxes, including credits, are allocated by SJI to its subsidiaries, generally on a separate return basis except for net operating loss and credit carryforwards. As of December 31, 2013 there were no income taxes due from SJI. As of December 31, 2012 income taxes due from SJI were approximately $4.6 million and are included in the balance sheets under the caption, Prepaid Taxes.

As of December 31, 2013, SJG has total federal net operating loss carryforwards of $103.7 million; $99.4 million of the federal NOL will expire in 2031 and $4.3 million will expire in 2032. A valuation allowance is recorded when it is more likely than not that any of our deferred income tax assets will not be realized. We believe that we will generate sufficient future taxable income to realize the income tax benefits related to our deferred tax assets.

A reconciliation of unrecognized tax benefits is as follows (in thousands):

	2013		2012		2011
Balance at January 1,	$	503	$	421	$	478
Increase as a result of tax position taken in prior years	44		82		119
Decrease due to a lapse in the statue of limitations	—		—		(90		)
Settlements	—		—		(86		)
Balance at December 31,	$	547	$	503	$	421

The total unrecognized tax benefits as of December 31, 2013 were $0.5 million, not including $0.6 million of accrued interest and penalties.  The total unrecognized tax benefits as of December 31, 2012 were $0.5 million not including $0.6 million of accrued interest and penalties. The total unrecognized tax benefits as of December 31, 2011 were $0.4 million, not including $0.6 million of accrued interest and penalties. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is not significant.  Our policy is to record interest and penalties related to unrecognized tax benefits as interest expense and other expense respectively. These amounts were not significant in 2013, 2012 or 2011. There have been no material changes to the unrecognized tax benefits during 2013, 2012 or 2011 and we do not anticipate any significant changes in the total unrecognized tax benefits within the next 12 months.

The unrecognized tax benefits are primarily related to an uncertainty of state income taxes.  Federal income tax returns from 2009 forward and state income tax returns from 2012 forward are open and subject to examination.

7. LONG-TERM DEBT:

A schedule of our long-term debt as of December 31, including current maturities, is as follows (in thousands):

			2013			2012
Long-Term Debt (A):
First Mortgage Bonds: (B)
4.46	%	Series due 2013 (C)	$	—		$	10,500
5.027	%	Series due 2013 (C)	—			14,500
4.52	%	Series due 2014	11,000			11,000
5.115	%	Series due 2014	10,000			10,000
5.387	%	Series due 2015	10,000			10,000
5.437	%	Series due 2016	10,000			10,000
4.60	%	Series due 2016	17,000			17,000
4.657	%	Series due 2017	15,000			15,000
7.97	%	Series due 2018	10,000			10,000
7.125	%	Series due 2018	20,000			20,000
5.587	%	Series due 2019	10,000			10,000
3.00	%	Series due 2024	50,000			50,000
3.03	%	Series due 2024	35,000			35,000
3.63	%	Series due 2025	10,000			10,000
4.84	%	Series due 2026	15,000			15,000
4.93	%	Series due 2026	45,000			45,000
4.03	%	Series due 2027	45,000			45,000
4.01	%	Series due 2030 (D)	50,000			—
3.74	%	Series due 2032	35,000			35,000
5.55	%	Series due 2033	32,000			32,000
6.213	%	Series due 2034	10,000			10,000
5.45	%	Series due 2035	10,000			10,000
Series A 2006 Tax-Exempt First Mortgage Bonds
Variable Rate, due 2036 (E)			25,000			25,000
Total Long-Term Debt Outstanding			475,000			450,000
Less Current Maturities (A)			(21,000		)	(25,000		)
Long-Term Debt			$	454,000		$	425,000

(A) Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2014, $21,000; 2015, $10,909; 2016, $27,909; 2017, $15,909; 2018, $38,909 .Our long-term debt agreements contain no financial covenants.

(B) Our First Mortgage dated October 1, 1947, as supplemented, securing the First Mortgage Bonds constitutes a direct first mortgage lien on substantially all utility plant.

(C) In July 2013, SJG called its $10.5 million, 4.46% Medium Term Notes (MTN) due July 2013 and $14.5 million, 5.027% MTN due September 2013.

(D) In November 2013, SJG issued $50.0 million of 4.01% aggregate principal amount of MTN due November 2030.

(E) These variable rate demand bonds bear interest at a floating rate that resets weekly. The interest rate as of December 31, 2013 was 0.07%. Liquidity support on these bonds is provided under a separate letter of credit facility that expires in August, 2015. These bonds contain no financial covenants.

In December 2011, SJG received approval from the BPU to issue up to $200.0 million in long-term debt under its MTN program by September 30, 2014. As of December 31, 2013, $30.0 million was available under this program. In January 2014, SJG issued the remaining $30.0 million aggregate principle amount of 4.23% MTN's due January 2030. We retire debt when it is cost effective as permitted by the debt agreements.

8. FINANCIAL INSTRUMENTS:

RESTRICTED INVESTMENTS - In accordance with the terms of our tax-exempt first mortgage bonds, unused proceeds are required to be escrowed pending approved construction expenditures. As of both December 31, 2013 and December 31, 2012, the escrowed proceeds, including interest earned, totaled $0.1 million. SJG established a margin account with SJRG in conjunction with SJG's risk management activities as detailed in Note 14. The funds provided by SJG will increase or decrease as the number and value of outstanding energy-related contracts held with SJRG changes. As of December 31, 2013 and December 31, 2012, the balance held with SJRG totaled $0.5 million and $1.1 million, respectively. During March 2013, SJG established a margin account with a counterparty in conjunction with SJG's risk management activities as detailed in Note 14. The funds provided by SJG will increase or decrease as the number and value of outstanding energy-related contracts held with this counterparty changes. The carrying amounts of the Restricted Investments approximate their fair value at December 31, 2013 and December 31, 2012, which would be included in Level 1 of the fair value hierarchy. (See Note 10 - Fair Value of Financial Assets and Financial Liabilities).

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 $15.0 million and $13.6 million as of December 31, 2013 and December 31, 2012, 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 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 December 31, 2013 and December 31, 2012.  The annual amortization to interest is not material to SJG’s financial statements.  The carrying amounts of these receivables approximate their fair value at December 31, 2013 and December 31, 2012, which would be included in Level 2 of the fair value hierarchy. (See Note 10 - Fair Value of Financial Assets and Financial Liabilities).

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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 that are not carried at fair value, including those financial instruments disclosed in this footnote, approximate their fair values at December 31, 2013 and December 31, 2012, 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 13 - Fair Value of Financial Assets and Financial Liabilities). The estimated fair values of SJG's long-term debt, including current maturities, as of December 31, 2013 and December 31, 2012, were $486.5 million and $502.0 million, respectively.  The carrying amounts of SJG's long-term debt, including current maturities, as of December 31, 2013 and December 31, 2012, were $475.0 million and $450.0 million, respectively.

9. LINES OF CREDIT:

Credit facilities and available liquidity as of December 31, 2013 were as follows (in thousands):

	Total Facility		Usage		Available Liquidity		Expiration Date
Commercial Paper Program/ Revolving Credit Facility	$	200,000	$	65,500	$	134,500	May 2018
Uncommitted Bank Lines	10,000		—		10,000		August 2014
Total	$	210,000	$	65,500	$	144,500

SJG renewed the uncommitted bank line of credit during the third quarter 2013. Also, SJG amended and extended its revolving credit facility during the third quarter of 2013; as a result, the maturity date was extended from May 2015 to May 2018.

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 December 31, 2013.

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, not including letters of credit, during the twelve months ended December 31, 2013 and 2012 were $91.4 million and $142.4 million, respectively.  The maximum amount outstanding under these credit facilities, not including letters of credit, during the twelve months ended December 31, 2013 and 2012 were $121.9 million and $180.5 million, respectively.

Based upon the existing credit facilities and a regular dialogue with our banks, we believe that there will continue to be sufficient credit available to meet our business’ future liquidity needs. Borrowings under these credit facilities are at market rates.  The weighted average interest rate on these borrowings, which changes daily, was 0.37% , 0.48% and 0.62% at December 31, 2013 , 2012 and 2011, respectively.

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10. RETAINED EARNINGS:

Various loan agreements contain potential restrictions regarding the amount of cash dividends or other distributions that we may pay on our common stock. As of December 31, 2013, these loan restrictions did not affect the amount that may be distributed from our retained earnings.

SJG received a $25 million equity infusion from SJI in 2013. No equity infusions were received from SJI in 2012 or 2011.  Future equity contributions will occur on an as needed basis.

11. PENSION AND OTHER POSTRETIREMENT BENEFITS:

We participate in the defined benefit pension plans and other postretirement benefit plans of SJI. The pension plans provide annuity payments to the majority of full-time, regular employees upon retirement. Participation in the SJI qualified defined benefit pension plans was closed to new employees beginning in 2003; however, employees who are not eligible for these pension plans are eligible to receive an enhanced version of SJI’s defined contribution plan. Certain officers of SJG also participate in the non-funded supplemental executive retirement plan (SERP) of SJI, a non-qualified defined benefit pension plan. The other postretirement benefit plans provide health care and life insurance benefits to some retirees.

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									Other Postretirement Benefits
	2013			2012			2011			2013			2012			2011
Service Cost	$	4,487		$	3,718		$	3,048		$	771		$	704		$	675
Interest Cost	7,886			8,008			7,828			2,221			2,443			2,621
Expected Return on Plan Assets	(9,435		)	(8,249		)	(7,415		)	(2,158		)	(1,910		)	(2,040		)
Amortization:
Prior Service Cost (Credits)	208			207			219			(195		)	(195		)	(254		)
Actuarial Loss	7,608			6,432			4,561			1,555			1,534			1,466
Net Periodic Benefit Cost	10,754			10,116			8,241			2,194			2,576			2,468
Capitalized Benefit Costs	(5,002		)	(4,684		)	(3,661		)	(1,172		)	(1,340		)	(1,222		)
Affiliate SERP Allocations	(1,389		)	(1,107		)	(845		)	—			—			—
Total Net Periodic Benefit Expense	$	4,363		$	4,325		$	3,735		$	1,022		$	1,236		$	1,246

Capitalized benefit costs reflected in the table above relate to our construction program.

Companies with publicly traded equity securities that sponsor a postretirement benefit plan are required to fully recognize, as an asset or liability, the overfunded or underfunded status of its benefit plans and recognize changes in the funded status in the year in which the changes occur. Changes in funded status are generally reported in Other Comprehensive Loss; however, since we recover all prudently incurred pension and postretirement benefit costs from our ratepayers, a significant portion of the charges resulting from the recording of additional liabilities under this statement are reported as regulatory assets (See Note 4).

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Details of the activity within the Regulatory Asset and Accumulated Other Comprehensive Loss associated with Pension and Other Postretirement Benefits are as follows (in thousands):

	Regulatory Assets						Accumulated Other Comprehensive Loss (pre-tax)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Balance at January 1, 2012	$	61,811		$	26,435		$	19,061		$	—
Amounts Arising during the Period:
Net Actuarial Loss	11,599			2,089			4,788			—
Amounts Amortized to Net Periodic Costs:
Net Actuarial Loss	(4,490		)	(1,535		)	(1,941		)	—
Prior Service (Cost) Credit	(207		)	195			—			—
Balance at December 31, 2012	68,713			27,184			21,908			—
Amounts Arising during the Period:
Net Actuarial Gain	(20,554		)	(9,171		)	(1,576		)	—
Amounts Amortized to Net Periodic Costs:
Net Actuarial Loss	(5,319		)	(1,555		)	(2,289		)	—
Prior Service (Cost) Credit	(208		)	194			—			—
Balance at December 31, 2013	$	42,632		$	16,652		$	18,043		$	—

The estimated costs that will be amortized from Regulatory Assets into net periodic benefit costs in 2014 are as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits
Prior Service Costs	$	158	$	133
Net Actuarial Loss	$	2,856	$	790

The estimated costs that will be amortized from Accumulated Other Comprehensive Loss into net periodic benefit costs in 2014 are as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits
Net Actuarial Loss	$	2,007	$	—

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A reconciliation of the plans’ benefit obligations, fair value of plan assets, funded status and amounts recognized in our balance sheets follows (in thousands):

							Other
	Pension Benefits						Postretirement Benefits
	2013			2012			2013			2012
Change in Benefit Obligations:
Benefit Obligation at Beginning of Year	$	186,899		$	160,319		$	55,615		$	51,656
Service Cost	4,487			3,718			771			704
Interest Cost	7,886			8,008			2,221			2,443
Actuarial (Gain) Loss	(11,514		)	21,990			(4,552		)	4,059
Retiree Contributions	—			—			335			313
Plan Amendments	—			—			—			—
Benefits Paid	(7,090		)	(7,136		)	(3,475		)	(3,560		)
Benefit Obligation at End of Year	$	180,668		$	186,899		$	50,915		$	55,615
Change in Plan Assets:
Fair Value of Plan Assets at Beginning of Year	$	119,391		$	91,738		$	32,694		$	28,942
Actual Return on Plan Assets	20,049			13,853			5,101			3,880
Employer Contributions	10,324			20,936			4,816			3,119
Retiree Contributions	—			—			335			313
Benefits Paid	(7,090		)	(7,136		)	(3,475		)	(3,560		)
Fair Value of Plan Assets at End of Year	$	142,674		$	119,391		$	39,471		$	32,694

Funded Status at End of Year:
Accrued  Net Benefit Cost at End of Year	$	(37,994	)	$	(67,508	)	$	(11,444	)	$	(22,921	)
Amounts Recognized in the Statement of Financial Position Consist of:
Current Liabilities	$	(1,241	)	$	(1,236	)	$	—		$	—
Noncurrent Liabilities	(36,753		)	(66,272		)	(11,444		)	(22,921		)
Net Amount Recognized at End of Year	$	(37,994	)	$	(67,508	)	$	(11,444	)	$	(22,921	)
Amounts Recognized in Regulatory Assets Consist of:
Prior Service Costs	$	634		$	842		$	952		$	758
Net Actuarial Loss	41,998			67,871			15,700			26,426
Net Amount Recognized at End of Year	$	42,632		$	68,713		$	16,652		$	27,184
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Net Actuarial Loss	$	18,043		$	21,908		$	—		$	—

The projected benefit obligation (PBO) and accumulated benefit obligation (ABO) of our qualified employee pension plans were $143.5 million and $131.4 million, respectively, as of December 31, 2013; and $149.5 million and $135.6 million, respectively, as of December 31, 2012. The ABO of these plans exceeded the value of the plan assets as of December 31, 2012. The value of these assets can be seen in the tables above. The PBO and ABO for our non-funded SERP were $37.2 million and $36.2 million, respectively, as of December 31, 2013; and $37.4 million and $35.7 million, respectively, as of December 31, 2012. The SERP obligation is reflected in the tables above and has no assets.

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The weighted-average assumptions used to determine benefit obligations at December 31 were:

	Pension Benefits				Other Postretirement Benefits
	2013		2012		2013		2012
Discount Rate	5.09	%	4.26	%	4.91	%	4.14	%
Rate of Compensation Increase	3.50	%	3.25	%	3.50	%	3.25	%

The weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 were:

	Pension Benefits						Other Postretirement Benefits
	2013		2012		2011		2013		2012		2011
Discount Rate	4.26	%	5.03	%	5.78	%	4.14	%	4.92	%	5.55	%
Expected Long-Term Return on Plan Assets	7.50	%	7.50	%	8.00	%	6.60	%	6.60	%	7.00	%
Rate of Compensation Increase	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%

All obligations disclosed herein reflect the use of the RP 2000 mortality tables.  

The discount rates used to determine the benefit obligations at December 31, 2013 and 2012, which are used to determine the net periodic benefit cost for the subsequent year, were based on a portfolio model of high-quality investments with maturities that match the expected benefit payments under our pension and other postretirement benefit plans.

The expected long-term return on plan assets (“return”) has been determined by applying long-term capital market projections provided by our pension plan Trustee to the asset allocation guidelines, as defined in the Company’s investment policy, to arrive at a weighted average return.  For certain other equity securities held by an investment manager outside of the control of the Trustee, the return has been determined based on historic performance in combination with long-term expectations.  The return for the other postretirement benefits plan is determined in the same manner as discussed above; however, the expected return is reduced based on the taxable nature of the underlying trusts.

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The assumed health care cost trend rates at December 31 were:

	2013		2012
Medical Care and Drug Cost Trend Rate Assumed for Next Year	7.00	%	7.00	%
Dental Care Cost Trend Rate Assumed for Next Year	4.75	%	4.75	%
Rate to which Cost Trend Rates are Assumed to Decline (the Ultimate Trend Rate)	4.75	%	4.75	%
Year that the Rate Reaches the Ultimate Trend Rate	2023		2019

Assumed health care cost trend rates have a significant effect on the amounts reported for our postretirement health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in thousands):

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on the Total of Service and Interest Cost	$	145	$	(115	)
Effect on Postretirement Benefit Obligation	$	2,406	$	(2,027	)

PLAN ASSETS — The Company’s overall investment strategy for pension plan assets is to achieve a diversification by asset class, style of manager, and sector and industry limits to achieve investment results that match the actuarially assumed rate of return, while preserving the inflation adjusted value of the plans.  The Company has implemented this diversification strategy primarily with commingled common/collective trust funds.  The target allocations for pension plan assets are 28-48 percent U.S. equity securities, 13-25 percent international equity securities, 32-42 percent fixed income investments, and 2-14 percent to all other types of investments.  Equity securities include investments in commingled common/collective trust funds as well as large-cap, mid-cap and small-cap companies.  Fixed income securities include commingled common/collective trust funds, group annuity contracts for pension payments, and hedge funds.  Other types of investments include investments in private equity funds and real estate funds that follow several different strategies.

The strategy recognizes that risk and volatility are present to some degree with all types of investments.  We seek to avoid high levels of risk at the total fund level through diversification by asset class, style of manager, and sector and industry limits.  Specifically prohibited investments include, but are not limited to, venture capital, margin trading, commodities and securities of companies with less than $250.0 million capitalization (except in the small-cap portion of the fund where capitalization levels as low as $50.0 million are permissible).  These restrictions are only applicable to individual investment managers with separately managed portfolios and do not apply to mutual funds or commingled trusts.

SJG evaluated its pension and other postretirement benefit plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2013.   Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund.  As of December 31, 2013, there were no significant concentrations (defined as greater than 10 percent of plan assets) of risk in SJG’s pension and other postretirement benefit plan assets.

GAAP establishes a hierarchy that prioritizes fair value measurements based on the types of inputs used for the various valuation techniques.  This hierarchy groups assets into three (3) distinct levels as fully described in Note 13, that will serve as the basis for presentation throughout the remainder of this Note.

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The fair values of SJG’s pension plan assets at December 31, 2013 and 2012 by asset category are as follows (in thousands):

Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2013:
Cash / Cash Equivalents:
Common/Collective Trust Funds (a)	$	334	$	—	$	334	$	—
STIF-Type Instrument (b)	943		—		943		—
Equity securities:
Common/Collective Trust Funds – U.S. (a)	41,527		—		41,527		—
Common/Collective Trust Funds – International (a)	27,312		—		27,312		—
U.S. Large-Cap (c)	9,342		9,342		—		—
U.S. Mid-Cap (c)	3,313		3,313		—		—
International (c)	2,935		2,935		—		—
Fixed Income:
Common/Collective Trust Funds (a)	36,728		—		36,728		—
Guaranteed Insurance Contract (d)	9,071		—		—		9,071
Hedge Funds (e)	3,328		—		—		3,328
Other types of investments:
Private Equity Fund (f)	2,440		—		—		2,440
Common/Collective Trust Fund – Real Estate (g)	5,401		—		—		5,401
Total	$	142,674	$	15,590	$	106,844	$	20,240

Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2012:
Cash / Cash Equivalents:
Common/Collective Trust Funds (a)	$	477	$	—	$	477	$	—
STIF-Type Instrument (b)	840		—		840		—
Equity securities:
Common/Collective Trust Funds – U.S. (a)	33,690		—		33,690		—
Common/Collective Trust Funds – International (a)	23,448		—		23,448		—
U.S. Large-Cap (c)	7,126		7,126		—		—
U.S. Mid-Cap (c)	4,194		4,194		—		—
U.S. Small-Cap (c)	8		8		—		—
International (c)	1,462		1,462		—		—
Fixed Income:
Common/Collective Trust Funds (a)	30,913		—		30,913		—
Guaranteed Insurance Contract (d)	9,898		—		—		9,898
Other types of investments:
Private Equity Fund (f)	2,557		—		—		2,557
Common/Collective Trust Fund – Real Estate (g)	4,778		—		—		4,778
Total	$	119,391	$	12,790	$	89,368	$	17,233

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(a) This category represents common/collective trust fund investments through a commingled employee benefit trust (excluding real estate).  These commingled funds are not traded publicly; however, the majority of the underlying assets held in these funds are stocks and bonds that are traded on active markets and prices for these assets are readily observable.  Also included in these funds are interest rate swaps, asset backed securities, mortgage backed securities and other investments with observable market values. Holdings in these commingled funds are classified as Level 2 investments.

(b) This category represents short-term investment funds held for the purpose of funding disbursement payment arrangements.  Underlying assets are valued based on quoted prices in active markets, or where quoted prices are not available, based on models using observable market information.  Since not all values can be obtained from quoted prices in active markets, these funds are classified as Level 2 investments.

(c) This category of equity investments represents a managed portfolio of common stock investments in five sectors: telecommunications, electric utilities, gas utilities, water and energy.  These common stocks are actively traded on exchanges and price quotes for these shares are readily available.  These common stocks are classified as Level 1 investments.

(d) This category represents SJI’s Group Annuity contracts with a nationally recognized life insurance company.  The contracts are the assets of the plan, while the underlying assets of the contracts are owned by the contract holder.  Valuation is based on a formula and calculation specified within the contract.  Since the valuation is based on the reporting entity’s own assumptions, these contracts are classified as Level 3 investments.

(e) This category represents a collection of underlying funds which are all domiciled outside of the United States. All of the underlying fund managers are based in the U.S.; however, they do not necessarily trade only in the U.S. markets. The fair value of these funds is determined by the underlying fund's general partner or manager. These funds are classified as Level 3 investments.

(f) This category represents a limited partnership which includes several investments in U.S. leveraged buyout, venture capital, and special situation funds.  Fund valuations are reported on a 90 day lag and, therefore, the value reported herein represents the market value as of September 30, 2013 and 2012, respectively.  The fund’s investments are stated at fair value, which is generally based on the valuations provided by the general partners or managers of such investments.  Fund investments are illiquid and resale is restricted.  These funds are classified as Level 3 investments.

(g) This category represents real estate common/collective trust fund investments through a commingled employee benefit trust. These commingled funds are part of a direct investment in a pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, the real estate funds are classified as Level 2 investments.

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Fair Value Measurement Using Significant

Unobservable Inputs (Level 3)

(In thousands)

	Guaranteed Insurance Contract			Hedge Funds		Private Equity Funds			Real Estate		Total
Balance at January 1, 2012	$	9,647		$	—	$	2,525		$	4,291	$	16,463
Actual return on plan assets:
Relating to assets still held at the reporting date	1,082			—		(122		)	487		1,447
Relating to assets sold during the period	(10		)	—		480			—		470
Purchases, Sales and Settlements	(821		)	—		(326		)	—		(1,147		)
Balance at December 31, 2012	$	9,898		$	—	$	2,557		$	4,778	$	17,233
Actual return on plan assets:
Relating to assets still held at the reporting date	(68		)	124		80			623		759
Relating to assets sold during the period	14			—		345			—		359
Purchases, Sales and Settlements	(773		)	3,204		(542		)	—		1,889
Balance at December 31, 2013	$	9,071		$	3,328	$	2,440		$	5,401	$	20,240

As with the pension plan assets, the Company’s overall investment strategy for post-retirement benefit plan assets is to achieve a diversification by asset class, style of manager, and sector and industry limits to achieve investment results that match the actuarially assumed rate of return, while preserving the inflation adjusted value of the plans.  The Company has implemented this diversification strategy with a mix of common/collective trust funds and mutual funds.  The target allocations for post-retirement benefit plan assets are 33-43 percent U.S. equity securities, 20-30 percent international equity securities, and 32-42 percent fixed income investments.  Equity securities include investments in large-cap, mid-cap and small-cap companies within mutual funds or common/collective trust funds.  Fixed income securities within the common/collective trust fund include primarily investment grade, U.S. Government and mortgage-backed financial instruments.

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The fair values of SJG’s other postretirement benefit plan assets at December 31, 2013 and 2012 by asset category are as follows (in thousands):

Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2013:
Equity Securities:
Common/Collective Trust Funds - U.S. (a)	$	12,412	$	—	$	12,412	$	—
Common/Collective Trust Funds - International (a)	10,031		—		10,031		—
Mutual Fund - U.S. Large-Cap (b)	2,814		2,814		—		—
Fixed Income:
Common/Collective Trust (a)	14,214		—		14,214		—
Total	$	39,471	$	2,814	$	36,657	$	—
Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2012:
Equity Securities:
Common/Collective Trust Funds - U.S. (a)	$	9,972	$	—	$	9,972	$	—
Common/Collective Trust Funds - International (a)	8,475		—		8,475		—
Mutual Fund - U.S. Large-Cap (b)	2,326		2,326		—		—
Fixed Income:
Common/Collective Trust (a)	11,921		—		11,921		—
Total	$	32,694	$	2,326	$	30,368	$	—

(a) This category represents common/collective trust fund investments through a commingled employee benefit trust (excluding real estate).  These commingled funds are not traded publicly; however, the majority of the underlying assets held in these funds are stocks and bonds that are traded on active markets and prices for these assets are readily observable.  Also included in these funds are interest rate swaps, asset backed securities, mortgage backed securities and other investments with observable market values. Holdings in these commingled funds are classified as Level 2 investments.

(b) This category represents mutual fund investments. The mutual funds are actively traded on exchanges and price quotes for the shares are readily available. These mutual funds are classified as Level 1 investments.

Future Benefit Payments - The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid during the following years (in thousands):

	Pension Benefits		Other Postretirement Benefits
2014	$	7,770	$	3,725
2015	$	8,303	$	3,825
2016	$	8,646	$	3,906
2017	$	9,021	$	3,955
2018	$	10,316	$	3,997
2019 - 2023	$	61,659	$	21,093

Contributions - SJG contributed $9.1 million and $19.8 million to our qualified employee pension plans during the years ended December 31, 2013 and 2012, respectively. No pension plan contributions are planned for 2014.  Payments related to the unfunded SERP plan are expected to approximate $1.2 million in 2014 and have been consistent over the past few years. We also have a regulatory obligation to contribute approximately $3.6 million annually to our other postretirement benefit plans’ trusts, less costs incurred directly by us.

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Defined Contribution Plan - We also offer an Employees’ Retirement Savings Plan (Savings Plan) to eligible employees. For employees eligible for participation in SJI's defined benefit pension plans, SJG matches 50% of participants’ contributions up to 6% of base compensation. For employees who are not eligible for participation in SJI’s defined benefit plans, we match 50% of participants’ contributions up to 8% of base compensation. Employees not eligible for the pension plans also receive a year-end contribution of $1,000 if 10 or fewer years of service, or $1,500 if more than 10 years of service. The amount expensed and contributed for the matching provision of the Savings Plan approximated $1.0 million, $0.9 million and $0.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.

12. COMMITMENTS AND CONTINGENCIES:

Standby Letter of Credit - SJG 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 New Jersey Economic Development Authority (NJEDA) to finance the expansion of SJG’s natural gas distribution system. 

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 2014. 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 $4.0 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 $0.5 million related to all claims in the aggregate, as of both December 31, 2013 and December 31, 2012. 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 60% of our workforce at December 31, 2013. The Company has collective bargaining agreements with two unions who represent these employees: the International Brotherhood of Electrical Workers (IBEW) that operates under a collective bargaining agreement that runs through February 28, 2017. The remaining unionized employees are represented by the International Association of Machinists and Aerospace Workers (IAM). Employees represented by the IAM operate under a collective bargaining agreement that expires in August 2014.

Environmental Remediation Costs - We incurred and recorded costs for environmental cleanup of 12 sites where we or our predecessors operated gas manufacturing plants. We stopped manufacturing gas in the 1950s.

We successfully entered into settlements with all of our historic comprehensive general liability carriers regarding the environmental remediation expenditures at our sites. Also, we had purchased a Cleanup Cost Cap Insurance Policy limiting the amount of remediation expenditures that we were required to make at 11 of our sites. This policy provided coverage up to $50.0 million, which was exhausted in 2012.

Since the early 1980s, we accrued environmental remediation costs of $326.5 million, of which $207.0 million has been spent as of December 31, 2013. The following table details the amounts accrued and expended for environmental remediation at December 31 (in thousands):

	2013			2012
Beginning of Year	$	107,410		$	89,984
Accruals	22,264			26,552
Expenditures	(10,182		)	(9,126		)
End of Year	$	119,492		$	107,410

The balances are segregated between current and noncurrent on the balance sheets under the captions Current Liabilities and Regulatory and Other Noncurrent Liabilities.

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Management estimates that undiscounted future costs to clean up our sites will range from $119.5 million to $223.5 million. We recorded the lower end of this range, $119.5 million, as a liability because a single reliable estimation point is not feasible due to the amount of uncertainty involved in the nature of projected remediation efforts and the long period over which remediation efforts will continue. Six of our sites comprise the majority of these estimates, the sum of the six sites range from a low of $100.4 million to a high of $192.8 million. Recorded amounts include estimated costs based on projected investigation and remediation work plans using existing technologies. Actual costs could differ from the estimates due to the long-term nature of the projects, changing technology, government regulations and site-specific requirements. Significant risks surrounding these estimates include unforeseen market price increases for remedial services, property owner acceptance of remedy selection, regulatory approval of selected remedy and remedial investigative findings.

The remediation efforts at our six most significant sites include the following:

Site 1 - Several interim remedial actions have been completed at the site. Steps remaining to remediate the balance of the site include completion of the remedial investigation of impacted soil and groundwater, selection of the appropriate remedial action, receiving confirmation of regulatory compliance of the selected remedy, and implementation of the approved remedy.

Site 2 - Remediation of the site is underway in accordance with the approved Remedial Action Work plan. Steps remaining to remediate the site include continued excavation of impacted soil and post remediation groundwater monitoring.

Site 3 - Various remedial investigation activities have been completed at this site and a final site remedy has been proposed to the regulatory authority.  Steps remaining to remediate the site include receiving confirmation of regulatory compliance of the selected remedy and implementation of the approved remedy.

Site 4 - Remedial investigation activities are ongoing at this site including pilot studies of potential remedial alternatives and continued soil and groundwater investigation.  Remaining steps to remediate include completion of the remedial investigation of impacted soil and groundwater, selection of the appropriate remedial action, receiving confirmation of regulatory compliance of the selected remedy, and implementation of the approved remedy.

Sites 5 and 6 - Remedial investigation activities are ongoing at these sites.  Remaining steps to remediate include completion of the remedial investigation of impacted soil and groundwater, selection of the appropriate remedial action, receiving confirmation of regulatory compliance of the selected remedy, and implementation of the approved remedy.

13. 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 December 31, 2013
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	8,696	$	8,696	$	—	$	—
Derivatives – Energy Related Assets (B)	1,500		1,409		91		—
	$	10,196	$	10,105	$	91	$	—
Liabilities
Derivatives – Energy Related Liabilities (B)	$	759	$	155	$	604	$	—
Derivatives – Other (C)	3,735		—		3,735		—
	$	4,494	$	155	$	4,339	$	—

As of December 31, 2012
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	7,520	$	769	$	6,751	$	—
Derivatives – Energy Related Assets (B)	766		447		319		—
	$	8,286	$	1,216	$	7,070	$	—
Liabilities
Derivatives – Energy Related Liabilities (B)	$	2,695	$	2,694	$	1	$	—
Derivatives – Other (C)	7,761		—		7,761		—
	$	10,456	$	2,694	$	7,762	$	—

(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. Management reviews and corroborates the price quotations to ensure the prices are observable which includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration.

(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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14. 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 its affiliate South Jersey Resources Group (SJRG) and another 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 December 31, 2013, SJG had outstanding derivative contracts intended to limit the exposure to market risk on 6.6 MMdts of expected future purchases of natural gas.. 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 balance sheets. The costs or benefits of these short-term contracts are recoverable through SJG’s Basic Gas Supply Service (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 balance sheets. As of December 31, 2013 and December 31, 2012, SJG had $0.7 million of unrealized gains and $1.9 million of unrealized losses, respectively, included in its BGSS related to open financial contracts.

The Company has also entered into interest rate derivatives to manage 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 balance sheets. The fair value represents the amount SJG would have to pay the counterparty to terminate these contracts as of those dates. 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 balance sheets.

We previously used derivative transactions known as “Treasury Locks” to mitigate 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 December 31, 2013 and December 31, 2012, the unamortized balance was approximately $1.0 million and $1.1 million, respectively.

As of December 31, 2013, SJG’s active interest rate swaps were as follows:

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

The fair values of all derivative instruments, as reflected in the balance sheets as of December 31, 2013 and December 31, 2012, are as follows (in thousands):

Derivatives not designated as hedging instruments under GAAP	2013				2012
	Assets		Liabilities		Assets		Liabilities
Energy related commodity contracts:
Derivatives – Energy Related – Current	$	1,222	$	711	$	464	$	2,615
Derivatives – Energy Related – Non-Current	278		48		302		80
Interest rate contracts:
Derivatives – Other	—		3,735		—		7,761
Total derivatives not designated as hedging instruments under GAAP	$	1,500	$	4,494	$	766	$	10,456

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For derivative instruments disclosed in the table above, information as to the presentation on the condensed balance sheets is as follows (in thousands):

As of December 31, 2013
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	$	1,500		$	—	$	1,500		$	(155	)	(A)	$	(498	)	$	847
Derivatives - Energy Related Liabilities	(759		)	—		(759		)	155			(B)	—			(604		)
Derivatives - Other	(3,735		)	—		(3,735		)	—				—			(3,735		)

As of December 31, 2012
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	$	766		$	—	$	766		$	(447	)	(A)	$	—	$	319
Derivatives - Energy Related Liabilities	(2,695		)	—		(2,695		)	447			(B)	1,136		(1,112		)
Derivatives - Other	(7,761		)	—		(7,761		)	—				—		(7,761		)

(A) The balances at December 31, 2013 and December 31, 2012 were related to derivative liabilities which can be net settled against derivative assets.

(B) The balances at December 31, 2013 and December 31, 2012 were related to derivative assets which can be net settled against derivative liabilities.

The effect of derivative instruments on the statements of income for 2013 , 2012 and 2011 are as follows (in thousands):

	Year ended December 31,
Derivatives in Cash Flow Hedging Relationships	2013			2012			2011
Interest Rate Contracts:
Losses reclassified from accumulated OCI into income (a)	$	(46	)	$	(46	)	$	(46	)

(a) Included in Interest Charges

Net realized losses associated with SJG’s energy-related financial commodity contracts of $0.4 million , $15.4 million and $12.9 million for 2013, 2012 and 2011, 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 and there is no impact to earnings.

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15. ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCL):

The following table summarizes the changes in accumulated other comprehensive loss (AOCL) for the year ended December 31, 2013 (in thousands):

	Postretirement Liability Adjustment			Unrealized Gain (Loss) on Derivatives-Other			Unrealized Gain (Loss) on Available-for-Sale Securities			Total
Balance at January 1, 2013 (a)	$	(12,958	)	$	(621	)	$	294		$	(13,285	)
Other comprehensive income before reclassifications	932			—			592			1,524
Amounts reclassified from AOCL (b)	1,354			27			(489		)	892
Net current period other comprehensive income	2,286			27			103			2,416
Balance at December 31, 2013 (a)	$	(10,672	)	$	(594	)	$	397		$	(10,869	)

(a) Determined using a combined statutory tax rate of 41%.

(b) See table below.

The following table provides details about reclassifications out of AOCL for the year ended December 31, 2013 (in thousands):

Components of AOCL	Amounts Reclassified from AOCL			Affected Line Item in the Statements of Income
	For the Year Ended December 31, 2013
Unrealized Loss on Derivatives-Other - Interest Rate Contracts designated as cash flow hedges	$	46		Interest Charges
Unrealized Gain on Available-for-Sale Securities	(828		)	Other Income & Expense
Actuarial Loss on Postretirement Benefits	2,289			Operating Expenses: Operations
	1,507			Loss (Income) Before Income Taxes
Income Taxes (a)	615			Income Taxes (a)
Losses (Gains) from reclassifications for the period net of tax	$	892

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16. QUARTERLY RESULTS OF OPERATIONS - UNAUDITED:

The summarized quarterly results of our operations are as follows (in thousands):  

	2013 Quarter Ended								2012 Quarter Ended
	March 31		June 30		Sept. 30		Dec. 31		March 31		June 30		Sept. 30		Dec. 31
Operating Revenues	$	174,098	$	66,536	$	59,674	$	146,172	$	179,436	$	59,177	$	54,251	$	129,010
Expenses:
Cost of Sales (excluding depreciation)	77,602		26,108		24,717		71,654		86,499		20,407		21,053		60,751
Operations and Maintenance
Including Fixed Charges	38,659		33,871		33,249		39,486		35,102		33,597		32,953		33,877
Income Taxes	20,771		2,269		471		11,322		20,977		1,887		258		10,589
Energy and Other Taxes	3,003		1,277		1,052		2,530		3,169		1,479		1,167		2,485
Total Expenses	140,035		63,525		59,489		124,992		145,747		57,370		55,431		107,702
Other Income and Expense	1,450		810		764		773		1,349		1,430		1,703		(1,865		)
Net Income	$	35,513	$	3,821	$	949	$	21,953	$	35,038	$	3,237	$	523	$	19,443

NOTE: Because of the seasonal nature of our business, statements for the 3-month periods are not indicative of the results for a full year.

17. SUBSEQUENT EVENT:

In January 2014, SJG issued $30 million aggregate principle amount of 4.23% Medium Term Notes due January 2030.

In October 2013, SJG filed a petition with the New Jersey Board of Public Utilities to issue up to $200.0 million of long term debt securities in various forms including Medium Term Notes and unsecured debt, with maturities of more than 12 months, over the next three years. This petition was approved in January, 2014.

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Item 9. Changes in and Disagreements with Accountants on

Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company’s management, with the participation of its chief executive officer and chief financial officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2013. Based on that evaluation, the Company’s chief executive officer and chief financial officer concluded that the disclosure controls and procedures employed at the Company are effective.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined under Exchange Act Rules 13a-15(f). The Company’s internal control system is designed to provide reasonable assurance to its management and board of directors regarding the preparation and fair presentation of published financial statements.Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on our evaluation under that framework, management concluded that our internal control over financial reporting was effective as of December 31, 2013.

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.  The Company's internal control over financial reporting was not subject to attestation by the Company’s registered public accounting firm pursuant to rules issued by the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

There has not been any change in the Company's internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, during the fiscal quarter ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 

Item 9B. Other Information

None.  

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Omitted in accordance with General Instruction I 1(a) and (b) of Form 10-K.

Item 11. Executive Compensation

Omitted in accordance with General Instruction I 1(a) and (b) of Form 10-K.

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Item 12. Security Ownership of Certain Beneficial Owners and Management

and Related Stockholder Matters

Omitted in accordance with General Instruction I 1(a) and (b) of Form 10-K.

Item 13. Certain Relationships and Related Transactions,

and Director Independence

Omitted in accordance with General Instruction I 1(a) and (b) of Form 10-K.

Item 14. Principal Accountant Fees and Services

Fees Paid to Auditors

Deloitte & Touche LLP served as the auditors of SJG and its parent, SJI, during 2013. In accordance with its charter, the Audit Committee pre-approved all services provided by Deloitte & Touche LLP. Audit services performed consisted of the audits of the financial statements and the preparation of various reports based on those audits and services related to filings with the United States Securities and Exchange Commission and New York Stock Exchange.

Audit Fees

The aggregate fees billed for the audit of SJG’s financial statements by Deloitte & Touche LLP totaled $477,000 and $435,000 in fiscal years 2013 and 2012, respectively.

Audit-Related Fees

None.

Tax Fees

None.

All Other Fees

None.

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Part IV

Item 15. Exhibits and Financial Statement Schedule

(a) Listed below are all financial statements and schedules filed as part of this report:

1 - The financial statements and notes to financial statements together with the report thereon of Deloitte & Touche LLP, February 28, 2014, are file as part of this report under Item 8 - Financial Statements and Supplementary Data.

2  - Supplementary Financial Information

Schedule II - Valuation and Qualifying Accounts. See page 77.

All schedules, other than that listed above, are omitted because the information called for is included in the financial statements filed or because they are not applicable or are not required.

(b) List of Exhibits (Exhibit Number is in Accordance with the Exhibit Table in Item 601 of Regulation S-K).

Exhibit Number	Description	Reference
(3)(a)	Certificate of Incorporation of South Jersey Gas Company.	Incorporated by reference from Exhibit (3)(a) of Form 10-K filed March 7, 1997.
(3)(b)	Bylaws of South Jersey Gas Company as amended and restated through January 1, 2013.	Incorporated by reference from Exhibit 3.1 of Form 8-K of SJG as filed January 3, 2013.
(4)(a)	Form of Stock Certificate for Common Stock.	Incorporated by reference from Exhibit (4)(a) of Form 10  filed March 7, 1997.
(4)(b)(i)	First Mortgage Indenture dated October 1, 1947.	Incorporated by reference from Exhibit (4)(b)(i) of Form 10-K of SJI for 1987 (1-6364).
(4)(b)(ii)	Nineteenth Supplemental Indenture dated as of April 1, 1992.	Incorporated by reference from Exhibit (4)(b)(xvii) of Form 10-K of SJI for 1992 (1-6364).
(4)(b)(iii)	Twenty-First Supplemental Indenture dated as of March 1, 1997.	Incorporated by reference from Exhibit (4)(b)(xviv) of Form 10-K of SJI for 1997 (1-6364).
(4)(b)(iv)	Twenty-Second Supplemental Indenture dated as of October 1, 1998.	Incorporated by reference from Exhibit (4)(b)(ix) of  Form S-3 (333-62019).
(4)(b)(v)	Twenty-Third Supplemental Indenture dated as of September 1, 2002.	Incorporated by reference from Exhibit (4)(b)(x) of Form S-3 (333-98411).
(4)(b)(vi)	Twenty-Fourth Supplemental Indenture dated as of September 1, 2005.	Incorporated by reference from Exhibit (4)(b)(vi) of Form S-3 (333-126822).
(4)(b)(vii)	Amendment to Twenty-Fourth Supplemental Indenture dated as of March 31, 2006.	Incorporated by reference from Exhibit 4 of Form 8-K as filed April 26, 2006.
(4)(b)(viii)	Amendment No. 2 to the Twenty-Fourth Supplemental Indenture dated as of December 20, 2010.	Incorporated by reference from Exhibit (4)(b)(viii) of Form 10-K for 2010.

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Exhibit Number	Description	Reference
(4)(b)(ix)	Loan Agreement by and between New Jersey Economic Development Authority and SJG dated April 1, 2006.	Incorporated by reference from Exhibit 10 of Form 8-K of SJG as filed April 26, 2006.
(4)(b)(x)	Twenty-Fifth Supplemental Indenture dated as of March 29, 2012.	Incorporated by reference from Exhibit 4.1 of Form 8-K of SJG as filed April 3, 2012.
(4)(c)(i)	Medium Term Note Indenture of Trust dated October 1, 1998.	Incorporated by reference from Exhibit (4)(e) of Form S-3 (333-62019).
(4)(c)(ii)	First Supplement to Indenture of Trust dated as of June 29, 2000.	Incorporated by reference from Exhibit 4.1 of Form 8-K of SJG dated July, 12, 2001.
(4)(c)(iii)	Second Supplement to Indenture of Trust dated as of July 5, 2000.	Incorporated by reference from Exhibit 4.2 of Form 8-K of SJG dated July, 12, 2001.
(4)(c)(iv)	Third Supplement to Indenture of Trust dated as of July 9, 2001.	Incorporated by reference from Exhibit 4.3 of Form 8-K of SJG dated July, 12, 2001.
(4)(c)(v)	Fourth Supplement to Indenture of Trust dated as of February 26, 2010.	Incorporated by reference from Exhibit 4.1 Form 8K dated March 5, 2010.
(10)(a)(i)	Gas storage agreement (GSS) between South Jersey Gas Company and Transco dated October 1, 1993.	Incorporated by reference from Exhibit (10)(d) of Form 10-K for 1993 (1-6364).
(10)(a)(ii)	Gas storage agreement (LG-A) between South Jersey Gas Company and Transco dated June 3, 1974.	Incorporated by reference from Exhibit (5)(f) of Form S-7 (2-56233).
(10)(a)(iii)	Gas storage agreement (LSS) between South Jersey Gas Company and Transco dated October 1, 1993.	Incorporated by reference from Exhibit (10)(i) of Form 10-K for 1993 (1-6364).
(10)(a)(iv)	Gas storage agreement (SS-1) between South Jersey Gas Company and Transco dated May 10, 1987 (effective April 1, 1988).	Incorporated by reference from Exhibit (10)(i)(a) of Form 10-K for 1988 (1-6364).
(10)(b)(i)	Gas storage agreement (SS-2) between South Jersey Gas Company and Transco dated July 25, 1990.	Incorporated by reference from Exhibit (10)(i)(i) of Form 10-K for 1991 (1-6364).
(10)(b)(ii)	Amendment to gas transportation agreement dated December 20, 1991 between South Jersey Gas Company and Transco dated October 5, 1993.	Incorporated by reference from Exhibit (10)(i)(k) of Form 10-K for 1993 (1-6364).
(10)(b)(iii)	CNJEP Service agreement between South Jersey Gas Company and Transco dated June 27, 2005.	Incorporated by reference from Exhibit (10)(i)(l) of  Form 10-K for 2005 (1-6364).
(10)(c)(i)	FTS Service Agreement No. 38099 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993.	Incorporated by reference from Exhibit (10)(k)(n) of Form 10-K for 1993 (1-6364).

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Exhibit Number	Description	Reference
(10)(c)(ii)	NTS Service Agreement No. 39305 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993.	Incorporated by reference from Exhibit (10)(k)(o) of Form 10-K for 1993 (1-6364).
(10)(c)(iii)	FSS Service Agreement No. 38130 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993.	Incorporated by reference from Exhibit (10)(k)(p) of Form 10-K for 1993 (1-6364).
(10)(d)(i)	SST Service Agreement No. 38086 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993.	Incorporated by reference from Exhibit (10)(k)(q) of Form 10-K for 1993 (1-6364).
(10)(h)(i)*	Deferred Payment Plan for Directors of South Jersey Industries, Inc., South Jersey Gas Company, Energy & Minerals, Inc., R&T Group, Inc. and South Jersey Energy Company as amended and restated October 21, 1994.	Incorporated by reference from Exhibit (10)(l) of Form 10-K of SJI for 1994 (1-6364).
(10)(h)(ii)*	Schedule of Deferred Compensation Agreements.	Incorporated by reference from Exhibit (10)(l)(b)  of Form 10-K of SJI for 1997 (1-6364).
(10)(h)(iii)*	Supplemental Executive Retirement Program, as amended and restated effective January 1, 2009, and Form of Agreement between certain South Jersey Industries, Inc. or subsidiary Company officers.	Incorporated by reference from Exhibit (10)(f)(ii)  of Form 10-K of SJI for 2009  (1-6364).
(10)(h)(iv)*	Form of Officer Change in Control Agreements, effective January 1, 2013, between certain officers and either South Jersey Industries, Inc. or its subsidiaries.	Incorporated by reference from Exhibit 10.1 of Form 8-K of SJI as filed January 25, 2013.
(10)(h)(v)*	Schedule of Officer Agreements.	Incorporated by reference from Exhibit 10(e)(iv) of Form 10-K of SJI as filed for 2013.
(10)(h)(vi)*	Officer Severance Plan.	Incorporated by reference from Exhibit 10(f)(i) of Form 10-K of SJI as filed for 2013
(10)(i)(i)	Note Purchase Agreement dated as of March 1, 2010.	Incorporated by reference from Exhibit 10 of Form 8-K dated March 5, 2010.
(10)(i)(ii)	Note Purchase Agreement dated as of December 30, 2010.	Incorporated by reference from Exhibit 10 of Form 8-K dated January 5, 2011.
(10)(i)(iii)	Four-Year Revolving Credit Agreement.	Incorporated by reference from Exhibit 10.1 of Form 8-K of SJG dated May 6, 2011.
(10)(i)(iv)	Commercial Paper Dealer Agreement, dated as of July 1, 2011.	Incorporated by reference from Exhibit 10.1 of Form 8-K of SJG dated July 1, 2011.
(10)(i)(v)	Commercial Paper Dealer Agreement, dated as of January 5, 2012.	Incorporated by reference from Exhibit 10.1 of Form 8-K of SJG dated January 9, 2012.

73

Exhibit Number	Description	Reference
(10)(i)(vi)	Note Purchase Agreement dated as of April 2, 2012.	Incorporated by reference from Exhibit 10.1 of Form 8-K of SJG dated April 3, 2012.
(10)(i)(vii)	Note Purchase Agreement, dated as of September 20, 2012, .	Incorporated by reference from Exhibit 10.1 of Form 8-K of SJG dated September 25, 2012.
(10)(i)(viii)	First Amendment to Credit Agreement, dated as of September 27, 2013.	Incorporated by reference from Exhibit 10.1 of Form 8-K of SJG as filed September 30, 2013.
(10)(i)(ix)	Note Purchase Agreement, dated as of November 21, 2013.	Incorporated by reference from Exhibit 10.1 of Form 8-K of SJG as filed November 22, 2013.
(12)	Calculation of Ratio of Earnings to Fixed Charges (Before Federal Income Taxes) (filed herewith).
(14)	Code of Ethics	Incorporated by reference from Exhibit (14) of Form 10-K of SJI as filed for 2007.
(21)	Subsidiaries of the Registrant (filed herewith).
(31.1)	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
(31.2)	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
(32.1)	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
(32.2)	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
(101.INS)	eXtensible Business Reporting Language (XBRL) Instance Document (filed herewith).
(101.SCH)	XBRL Taxonomy Extension Schema (filed herewith).
(101.CAL)	XBRL Taxonomy Extension Calculation Linkbase (filed herewith).
(101.DEF)	XBRL Taxonomy Extension Definition Linkbase (filed herewith).
(101.LAB)	XBRL Taxonomy Extension Label Linkbase (filed herewith).

74

Exhibit Number	Description	Reference
(101.PRE)	XBRL Taxonomy Extension Presentation Linkbase (filed herewith).

* Constitutes a management contract or a compensatory plan or arrangement.

75

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

			SOUTH JERSEY GAS COMPANY
Date:	February 28, 2014	BY:	/s/ Stephen H. Clark
			Stephen H. Clark, Chief Financial Officer & Treasurer
			(Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/  Jeffrey E. DuBois	President, Director	February 28, 2014
(Jeffrey E. DuBois)	(Principal Executive Officer)
/s/  Stephen H. Clark	Chief Financial Officer & Treasurer	February 28, 2014
(Stephen H. Clark)	(Principal Financial Officer)
/s/  Thomas S. Kavanaugh	Controller	February 28, 2014
(Thomas S. Kavanaugh)
/s/  Thomas A. Bracken	Director	February 28, 2014
(Thomas A. Bracken)
/s/  Victor Fortkiewicz	Director	February 28, 2014
(Victor Fortkiewicz)
/s/  Edward J. Graham	Director	February 28, 2014
(Edward J. Graham)
/s/ Sunita Holzer	Director	February 28, 2014
(Sunita Holzer)
/s/ Frank L. Sims	Director	February 28, 2014
(Frank L. Sims)

76

SOUTH JERSEY GAS COMPANY

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

(In Thousands)

Col. A	Col. B		Col. C					Col. D		Col. E
			Additions
Classification	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts - Describe (a)			Deductions - Describe (b)		Balance at End of Period
Provision for Uncollectible
Accounts for the Year Ended
December 31, 2013	$	3,985	$	4,232	$	(41	)	$	3,623	$	4,553
Provision for Uncollectible
Accounts for the Year Ended
December 31, 2012	$	3,060	$	4,775	$	110		$	3,960	$	3,985
Provision for Uncollectible
Accounts for the Year Ended
December 31, 2011	$	4,577	$	1,410	$	562		$	3,489	$	3,060

(a) Recoveries of accounts previously written off and minor adjustments.

(b) Uncollectible accounts written off.

77

EX-12

																	Exhibit 12
SOUTH JERSEY GAS COMPANY
Calculation of Ratio of Earnings to Fixed Charges
(IN THOUSANDS)
	Fiscal Year Ended December 31,
	2013				2012				2011				2010					2009
Net Income		$	62,236			$	58,241			$	52,889			$	43,925				$	39,195
Income Taxes, Net		34,833				33,711				34,281				29,678					27,104
Fixed Charges*		20,724				18,897				20,034				18,010					16,764
Capitalized Interest		(8,174		)		(6,470		)		(1,112		)		(369		)			(322		)
Total Available for Coverage		$	109,619			$	104,379			$	106,092			$	91,244			$	$	82,741
Total Available		5.3x				5.5x				5.3x				5.1x					4.9x
Fixed Charges
* Fixed charges consist of interest charges (rentals are not material).

EX-21

			Exhibit 21
SOUTH JERSEY GAS COMPANY
SUBSIDIARIES OF REGISTRANT
AS OF DECEMBER 31, 2013
	Percentage of
	Voting Securities		State of
	Owned by Parent	Relationship	Incorporation
South Jersey Gas Company	Registrant	Parent	New Jersey
SJG Capital Trust	100	Subsidiary	Delaware
(inactive as of November 5, 2003)

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Jeffrey E. DuBois, certify that:

1.  I have reviewed this Annual Report on Form 10-K for the period ended December 31, 2013 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:	February 28, 2014	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 Annual Report on Form 10-K for the period ended December 31, 2013, 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:	February 28, 2014	By:	/s/ Stephen H. Clark
			Stephen H. Clark
			Chief Financial Officer & Treasurer
			(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 Annual Report on Form 10-K of South Jersey Gas Company (the “Company”) for the period ended December 31, 2013, 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)

February 28, 2014

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 Annual Report on Form 10-K of South Jersey Gas Company (the “Company”) for the period ended December 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Stephen H. Clark, Chief Financial Officer & Treasurer (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 & Treasurer

(Principal Financial Officer)

February 28, 2014

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ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Schedule of changes in accumulated other comprehensive loss (AOCL)

The following table summarizes the changes in accumulated other comprehensive loss (AOCL) for the year ended December 31, 2013 (in thousands):

	Postretirement Liability Adjustment			Unrealized Gain (Loss) on Derivatives-Other			Unrealized Gain (Loss) on Available-for-Sale Securities			Total
Balance at January 1, 2013 (a)	$	(12,958	)	$	(621	)	$	294		$	(13,285	)
Other comprehensive income before reclassifications	932			—			592			1,524
Amounts reclassified from AOCL (b)	1,354			27			(489		)	892
Net current period other comprehensive income	2,286			27			103			2,416
Balance at December 31, 2013 (a)	$	(10,672	)	$	(594	)	$	397		$	(10,869	)

(a) Determined using a combined statutory tax rate of 41%.

(b) See table below.

Reclassifications out of AOCL

The following table provides details about reclassifications out of AOCL for the year ended December 31, 2013 (in thousands):

Components of AOCL	Amounts Reclassified from AOCL			Affected Line Item in the Statements of Income
	For the Year Ended December 31, 2013
Unrealized Loss on Derivatives-Other - Interest Rate Contracts designated as cash flow hedges	$	46		Interest Charges
Unrealized Gain on Available-for-Sale Securities	(828		)	Other Income & Expense
Actuarial Loss on Postretirement Benefits	2,289			Operating Expenses: Operations
	1,507			Loss (Income) Before Income Taxes
Income Taxes (a)	615			Income Taxes (a)
Losses (Gains) from reclassifications for the period net of tax	$	892

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PENSION AND OTHER POSTRETIREMENT BENEFITS 3 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior Service Costs	$ 158
Net Actuarial Loss	2,856
Net Actuarial Loss	2,007
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior Service Costs	133
Net Actuarial Loss	790
Net Actuarial Loss	$ 0

XML

LONG-TERM DEBT (Details) (USD $)																																																																																																						1 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Jan. 31, 2014 First Mortgage Bonds [Member] Subsequent Event [Member]	Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2013, 4.46% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2013, 4.46% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2013, 5.027% [Member]		Jul. 31, 2013 First Mortgage Bonds [Member] Series Due 2013, 5.027% [Member]	Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2013, 5.027% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2014, 4.52% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2014, 4.52% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2014, 5.115% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2014, 5.115% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2015, 5.387% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2015, 5.387% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2016, 5.437% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2016, 5.437% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2016, 4.60% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2016, 4.60% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2017, 4.657% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2017, 4.657% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2018, 7.97% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2018, 7.97% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2018, 7.125% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2018, 7.125% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2019, 5.587% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2019, 5.587% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2024, 3.00% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2024, 3.00% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2024, 3.03% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2024, 3.03% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2025, 3.63% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2025, 3.63% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2026, 4.84% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2026, 4.84% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2026, 4.93% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2026, 4.93% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2027, 4.03% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2027, 4.03% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2030, 4.01% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2030, 4.01% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2032, 3.74% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2032, 3.74% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2033, 5.55% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2033, 5.55% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2034, 6.213% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2034, 6.213% [Member]		Dec. 31, 2013 First Mortgage Bonds [Member] Series Due 2035, 5.45% [Member]		Dec. 31, 2012 First Mortgage Bonds [Member] Series Due 2035, 5.45% [Member]		Dec. 31, 2013 Bonds at variable rates [Member]		Dec. 31, 2012 Bonds at variable rates [Member]		Dec. 31, 2013 Bonds at variable rates [Member] Series A. 2006 Bonds [Member]	Dec. 31, 2013 Medium-term Notes [Member]	Dec. 31, 2011 Medium-term Notes [Member]	Jul. 31, 2013 Medium-term Notes [Member] Series Due 2013, 4.46% [Member]
Debt Instrument [Line Items]
Stated interest rate					4.23%	4.46%				5.027%		5.027%			4.52%				5.115%				5.387%				5.437%				4.60%				4.657%				7.97%				7.125%				5.587%				3.00%				3.03%				3.63%				4.84%				4.93%				4.03%				4.01%				3.74%				5.55%				6.213%				5.45%											4.46%
Total Long-Term Debt Outstanding	$ 475,000,000	[1]	$ 450,000,000	[1]		$ 0	[1],[2],[3]	$ 10,500,000	[1],[2],[3]	$ 0	[1],[2],[3]	$ 14,500,000	$ 14,500,000	[1],[2],[3]	$ 11,000,000	[1],[3]	$ 11,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 17,000,000	[1],[3]	$ 17,000,000	[1],[3]	$ 15,000,000	[1],[3]	$ 15,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 20,000,000	[1],[3]	$ 20,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 50,000,000	[1],[3]	$ 50,000,000	[1],[3]	$ 35,000,000	[1],[3]	$ 35,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 15,000,000	[1],[3]	$ 15,000,000	[1],[3]	$ 45,000,000	[1],[3]	$ 45,000,000	[1],[3]	$ 45,000,000	[1],[3]	$ 45,000,000	[1],[3]	$ 50,000,000	[1],[3],[4]	$ 0	[1],[3],[4]	$ 35,000,000	[1],[3]	$ 35,000,000	[1],[3]	$ 32,000,000	[1],[3]	$ 32,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 10,000,000	[1],[3]	$ 25,000,000	[1],[5]	$ 25,000,000	[1],[5]
Less Current Maturities	(21,000,000)	[1]	(25,000,000)	[1]
Long-Term Debt	454,000,000	[1]	425,000,000	[1]
Long-term Debt, Fiscal Year Maturity [Abstract]
2014	21,000,000
2015	10,909,000
2016	27,909,000
2017	15,909,000
2018	38,909,000
Extinguishment of Debt, Amount																																																																																																						10,500,000.0
Interest rate at end of period																																																																																																			0.07%
Approved borrowing capacity																																																																																																					200,000,000.0
Available borrowing capacity																																																																																																				30,000,000
Debt Instrument, Face Amount					$ 30,000,000

[1] Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2014, $21,000; 2015, $10,909; 2016, $27,909; 2017, $15,909; 2018, $38,909 .Our long-term debt agreements contain no financial covenants.

[2] In July 2013, SJG called its $10.5 million, 4.46% Medium Term Notes (MTN) due July 2013 and $14.5 million, 5.027% MTN due September 2013.

[3] Our First Mortgage dated October 1, 1947, as supplemented, securing the First Mortgage Bonds constitutes a direct first mortgage lien on substantially all utility plant.

[4] In November 2013, SJG issued $50.0 million of 4.01% aggregate principal amount of MTN due November 2030.

[5] These variable rate demand bonds bear interest at a floating rate that resets weekly. The interest rate as of December 31, 2013 was 0.07%. Liquidity support on these bonds is provided under a separate letter of credit facility that expires in August, 2015. These bonds contain no financial covenants.

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ACCUMULATED OTHER COMPREHENSIVE LOSS 2 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Interest Charges									$ (12,550)		$ (12,427)	$ (18,922)
Other Income & Expense									(3,797)		(2,617)	(3,429)
Operations									85,805		78,425	68,149
Income Before Income Taxes									(97,069)		(91,952)	(87,170)
Income Taxes	(11,322)	(471)	(2,269)	(20,771)	(10,589)	(258)	(1,887)	(20,977)	(34,833)		(33,711)	(34,281)
Net Income	(21,953)	(949)	(3,821)	(35,513)	(19,443)	(523)	(3,237)	(35,038)	(62,236)		(58,241)	(52,889)
Amounts Reclassified from AOCL [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Income Before Income Taxes									1,507
Income Taxes									615	[1]
Net Income									892
Amounts Reclassified from AOCL [Member] | Unrealized Loss on Derivatives-Other - Interest Rate Contracts designated as cash flow hedges [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Interest Charges									(46)
Amounts Reclassified from AOCL [Member] | Unrealized Gain (Loss) on Available-for-Sale Securities [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Income & Expense									(828)
Amounts Reclassified from AOCL [Member] | Postretirement Liability Adjustment [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Operations									$ 2,289

[1] Determined using a combined statutory tax rate of 41%.

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PENSION AND OTHER POSTRETIREMENT BENEFITS 4 (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Amounts Recognized in the Statement of Financial Position Consist of:
Current Liabilities	$ (1,241,000)	$ (1,236,000)
Noncurrent Liabilities	(48,197,000)	(89,193,000)
Pension Benefits [Member]
Change in Benefit Obligations:
Benefit Obligation at Beginning of Year	186,899,000	160,319,000
Service Cost	4,487,000	3,718,000	3,048,000
Interest Cost	7,886,000	8,008,000	7,828,000
Actuarial (Gain) Loss	(11,514,000)	21,990,000
Retiree Contributions	0	0
Plan Amendments	0	0
Benefits Paid	(7,090,000)	(7,136,000)
Benefit Obligation at End of Year	180,668,000	186,899,000	160,319,000
Change in Plan Assets:
Fair Value of Plan Assets at Beginning of Year	119,391,000	91,738,000
Actual Return on Plan Assets	20,049,000	13,853,000
Employer Contributions	10,324,000	20,936,000
Retiree Contributions	0	0
Benefits Paid	(7,090,000)	(7,136,000)
Fair Value of Plan Assets at End of Year	142,674,000	119,391,000	91,738,000
Amounts Recognized in the Statement of Financial Position Consist of:
Current Liabilities	(1,241,000)	(1,236,000)
Noncurrent Liabilities	(36,753,000)	(66,272,000)
Net Amount Recognized at End of Year	(37,994,000)	(67,508,000)
Amounts Recognized in Regulatory Assets Consist of:
Prior Service Costs	634,000	842,000
Net Actuarial Loss	41,998,000	67,871,000
Net Amount Recognized at End of Year	42,632,000	68,713,000	61,811,000
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Net Actuarial Loss	18,043,000	21,908,000
Projected benefit obligation	143,500,000	149,500,000
Accumulated benefit obligation	131,400,000	135,600,000
Other Postretirement Benefits [Member]
Change in Benefit Obligations:
Benefit Obligation at Beginning of Year	55,615,000	51,656,000
Service Cost	771,000	704,000	675,000
Interest Cost	2,221,000	2,443,000	2,621,000
Actuarial (Gain) Loss	(4,552,000)	4,059,000
Retiree Contributions	335,000	313,000
Plan Amendments	0	0
Benefits Paid	(3,475,000)	(3,560,000)
Benefit Obligation at End of Year	50,915,000	55,615,000	51,656,000
Change in Plan Assets:
Fair Value of Plan Assets at Beginning of Year	32,694,000	28,942,000
Actual Return on Plan Assets	5,101,000	3,880,000
Employer Contributions	4,816,000	3,119,000
Retiree Contributions	335,000	313,000
Benefits Paid	(3,475,000)	(3,560,000)
Fair Value of Plan Assets at End of Year	39,471,000	32,694,000	28,942,000
Amounts Recognized in the Statement of Financial Position Consist of:
Current Liabilities	0	0
Noncurrent Liabilities	(11,444,000)	(22,921,000)
Net Amount Recognized at End of Year	(11,444,000)	(22,921,000)
Amounts Recognized in Regulatory Assets Consist of:
Prior Service Costs	952,000	758,000
Net Actuarial Loss	15,700,000	26,426,000
Net Amount Recognized at End of Year	16,652,000	27,184,000	26,435,000
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Net Actuarial Loss	0	0
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Projected benefit obligation	37,200,000	37,400,000
Accumulated benefit obligation	36,200,000	35,700,000
SJI [Member] | Pension Benefits [Member]
Funded Status at End of Year:
Accrued Net Benefit Cost at End of Year	(37,994,000)	(67,508,000)
SJI [Member] | Other Postretirement Benefits [Member]
Funded Status at End of Year:
Accrued Net Benefit Cost at End of Year	$ (11,444,000)	$ (22,921,000)

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RELATED PARTY TRANSACTIONS (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues [Abstract]
Operating Revenues	$ 2,689	$ 1,735	$ 7,248
Energy-Related Derivative Losses	400	15,400	12,900
Operating Expenses [Abstract]
Operating Expenses	19,779	18,916	17,525
SJRG [Member]
Operating Revenues [Abstract]
Operating Revenues	1,390	884	6,532
Cost of Sales	14,959	9,083	33,768
Energy-Related Derivative Losses	887	15,407	12,872
SJI [Member]
Operating Expenses [Abstract]
Operating Expenses	11,990	10,870	9,941
SJIS [Member]
Operating Expenses [Abstract]
Operating Expenses	5,531	5,397	4,956
Millennium [Member]
Operating Expenses [Abstract]
Operating Expenses	2,686	3,149	3,076
Other [Member]
Operating Revenues [Abstract]
Operating Revenues	1,299	851	716
Operating Expenses [Abstract]
Operating Expenses	$ (428)	$ (500)	$ (448)

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LONG-TERM DEBT LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule of long-term debt

A schedule of our long-term debt as of December 31, including current maturities, is as follows (in thousands):

			2013			2012
Long-Term Debt (A):
First Mortgage Bonds: (B)
4.46	%	Series due 2013 (C)	$	—		$	10,500
5.027	%	Series due 2013 (C)	—			14,500
4.52	%	Series due 2014	11,000			11,000
5.115	%	Series due 2014	10,000			10,000
5.387	%	Series due 2015	10,000			10,000
5.437	%	Series due 2016	10,000			10,000
4.60	%	Series due 2016	17,000			17,000
4.657	%	Series due 2017	15,000			15,000
7.97	%	Series due 2018	10,000			10,000
7.125	%	Series due 2018	20,000			20,000
5.587	%	Series due 2019	10,000			10,000
3.00	%	Series due 2024	50,000			50,000
3.03	%	Series due 2024	35,000			35,000
3.63	%	Series due 2025	10,000			10,000
4.84	%	Series due 2026	15,000			15,000
4.93	%	Series due 2026	45,000			45,000
4.03	%	Series due 2027	45,000			45,000
4.01	%	Series due 2030 (D)	50,000			—
3.74	%	Series due 2032	35,000			35,000
5.55	%	Series due 2033	32,000			32,000
6.213	%	Series due 2034	10,000			10,000
5.45	%	Series due 2035	10,000			10,000
Series A 2006 Tax-Exempt First Mortgage Bonds
Variable Rate, due 2036 (E)			25,000			25,000
Total Long-Term Debt Outstanding			475,000			450,000
Less Current Maturities (A)			(21,000		)	(25,000		)
Long-Term Debt			$	454,000		$	425,000

(A) Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2014, $21,000; 2015, $10,909; 2016, $27,909; 2017, $15,909; 2018, $38,909 .Our long-term debt agreements contain no financial covenants.

(B) Our First Mortgage dated October 1, 1947, as supplemented, securing the First Mortgage Bonds constitutes a direct first mortgage lien on substantially all utility plant.

(C) In July 2013, SJG called its $10.5 million, 4.46% Medium Term Notes (MTN) due July 2013 and $14.5 million, 5.027% MTN due September 2013.

(D) In November 2013, SJG issued $50.0 million of 4.01% aggregate principal amount of MTN due November 2030.

(E) These variable rate demand bonds bear interest at a floating rate that resets weekly. The interest rate as of December 31, 2013 was 0.07%. Liquidity support on these bonds is provided under a separate letter of credit facility that expires in August, 2015. These bonds contain no financial covenants.

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SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance	$ 3,985		$ 3,060		$ 4,577
Charged to Costs and Expenses	4,232		4,775		1,410
Charged to Other Accounts	(41)	[1]	110	[1]	562	[1]
Deductions	3,623	[2]	3,960	[2]	3,489	[2]
Balance	$ 4,553		$ 3,985		$ 3,060

[1] Recoveries of accounts previously written off and minor adjustments.

[2] Uncollectible accounts written off.

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PENSION AND OTHER POSTRETIREMENT BENEFITS 6 (Details) (Other Postretirement Benefits [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Medical Care and Drug Cost Trend Rate Assumed for Next Year	7.00%	7.00%
Dental Care Cost Trend Rate Assumed for Next Year	4.75%	4.75%
Rate to which Cost Trend Rates are Assumed to Decline (the Ultimate Trend Rate)	4.75%	4.75%
Year that the Rate Reaches the Ultimate Trend Rate	2023	2019

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QUARTERLY RESULTS OF OPERATIONS - UNAUDITED (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]
Operating Revenues	$ 146,172	$ 59,674	$ 66,536	$ 174,098	$ 129,010	$ 54,251	$ 59,177	$ 179,436	$ 446,480	$ 421,874	$ 412,449
Expenses:
Cost of Sales (excluding depreciation)	71,654	24,717	26,108	77,602	60,751	21,053	20,407	86,499	200,081	188,710	187,866
Operations and Maintenance Including Fixed Charges	39,486	33,249	33,871	38,659	33,877	32,953	33,597	35,102
Income Taxes	11,322	471	2,269	20,771	10,589	258	1,887	20,977	34,833	33,711	34,281
Energy and Other Taxes	2,530	1,052	1,277	3,003	2,485	1,167	1,479	3,169	7,862	8,300	10,291
Total Expenses	124,992	59,489	63,525	140,035	107,702	55,431	57,370	145,747
Other Income and Expense	773	764	810	1,450	(1,865)	1,703	1,430	1,349
Net Income	$ 21,953	$ 949	$ 3,821	$ 35,513	$ 19,443	$ 523	$ 3,237	$ 35,038	$ 62,236	$ 58,241	$ 52,889

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SUBSEQUENT EVENT

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

SUBSEQUENT EVENT

SUBSEQUENT EVENT:

In January 2014, SJG issued $30 million aggregate principle amount of 4.23% Medium Term Notes due January 2030.

In October 2013, SJG filed a petition with the New Jersey Board of Public Utilities to issue up to $200.0 million of long term debt securities in various forms including Medium Term Notes and unsecured debt, with maturities of more than 12 months, over the next three years. This petition was approved in January, 2014.

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LINES OF CREDIT (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Line of Credit Facility [Line Items]
Total Facility	$ 210,000,000
Usage	65,500,000
Available Liquidity	144,500,000
Average borrowings outstanding during the period	91,400,000	142,400,000
Maximum amounts outstanding during the period	121,900,000	180,500,000
Weighted average borrowing cost	0.37%	0.48%	0.62%
Minimum [Member]
Line of Credit Facility [Line Items]
Financial covenant, ratio of indebtedness to consolidated total capitalization minimum	0.65
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total Facility	200,000,000
Usage	65,500,000
Available Liquidity	134,500,000
Expiration Date	May 2018
Uncommitted Bank Lines [Member]
Line of Credit Facility [Line Items]
Total Facility	10,000,000
Usage	0
Available Liquidity	10,000,000
Expiration Date	August 2014
South Jersey Gas Commercial Paper Program [Member]
Line of Credit Facility [Line Items]
Total Facility	$ 200,000,000.0
Fixed maturities of notes, at maximum number of days (in days)	270 days

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STOCK-BASED COMPENSATION PLANS (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	15,068		15,108
Fair Value Per Share (in dollars per share)	$ 50.73		$ 52.55
Expected volatility, measurement period	3 years
Vesting period of shares	3 years		3 years
Cost of Restricted Stock Awards	$ 0.4		$ 0.4	$ 0.4
Amount capitalized to Utility Plant	0.2		0.2	0.2
Unrecognized compensation cost of awards granted under the plan	0.4
Weighted average period over which unrecognized compensation cost is to be recognized (in years)	1 year 8 months 12 days
Restricted stock award activity, excluding accrued dividend equivalents [Roll Forward}
Nonvested Shares Outstanding, beginning balance (in shares)	15,108
Granted (in shares)	9,324
Vested (in shares)	(7,116)	[1]
Canceled / Forfeited (in shares)	(2,248)
Nonvested Shares Outstanding, ending balance (in shares)	15,068		15,108
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, beginning balance (in dollars per share)	$ 52.55
Weighted Average Grant Date Fair Value, Granted (in dollars per share)	$ 47.78
Weighted Average Grant Date Fair Value, Vested (in dollars per share)	$ 50.94	[1]
Weighted Average Grant Date Fair Value, Canceled / Forfeited (in dollars per share)	$ 50.02
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 50.73		$ 52.55
Number of shares awarded during the period	12,901		7,098
Market value of shares awarded	0.6		0.4
Cash payments to SJI relating to stock awards	$ 0.4		$ 0.3
Officers and Key Employees [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expected to be Granted in Subsequent Year	0
Grant Date January 2012 - TSR [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	3,533
Fair Value Per Share (in dollars per share)	$ 51.23
Expected Volatility	22.50%
Risk-Free Interest Rate	0.43%
Restricted stock award activity, excluding accrued dividend equivalents [Roll Forward}
Nonvested Shares Outstanding, ending balance (in shares)	3,533
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 51.23
Grant Date January 2012 - EPS [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	3,533
Fair Value Per Share (in dollars per share)	$ 56.93
Restricted stock award activity, excluding accrued dividend equivalents [Roll Forward}
Nonvested Shares Outstanding, ending balance (in shares)	3,533
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 56.93
Grant Date January 2013 - TSR [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	4,001
Fair Value Per Share (in dollars per share)	$ 44.38
Expected Volatility	21.10%
Risk-Free Interest Rate	0.40%
Restricted stock award activity, excluding accrued dividend equivalents [Roll Forward}
Nonvested Shares Outstanding, ending balance (in shares)	4,001
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 44.38
Grant Date January 2013 - EPS [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Shares Outstanding (in shares)	4,001
Fair Value Per Share (in dollars per share)	$ 51.18
Restricted stock award activity, excluding accrued dividend equivalents [Roll Forward}
Nonvested Shares Outstanding, ending balance (in shares)	4,001
Weighted Average Grant Date Fair Value, Nonvested Shares Outstanding, ending balance (in dollars per share)	$ 51.18
Minimum [Member]
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 [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Percentage of actual amount of shares that ultimately vest of original share units granted	150.00%

[1] Performance targets during the 3-year vesting period were not attained for the January 2011 grant. As a result, no shares will be awarded in 2014.

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FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2013

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 December 31, 2013
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	8,696	$	8,696	$	—	$	—
Derivatives – Energy Related Assets (B)	1,500		1,409		91		—
	$	10,196	$	10,105	$	91	$	—
Liabilities
Derivatives – Energy Related Liabilities (B)	$	759	$	155	$	604	$	—
Derivatives – Other (C)	3,735		—		3,735		—
	$	4,494	$	155	$	4,339	$	—

As of December 31, 2012
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	7,520	$	769	$	6,751	$	—
Derivatives – Energy Related Assets (B)	766		447		319		—
	$	8,286	$	1,216	$	7,070	$	—
Liabilities
Derivatives – Energy Related Liabilities (B)	$	2,695	$	2,694	$	1	$	—
Derivatives – Other (C)	7,761		—		7,761		—
	$	10,456	$	2,694	$	7,762	$	—

(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. Management reviews and corroborates the price quotations to ensure the prices are observable which includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration.

(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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PENSION AND OTHER POSTRETIREMENT BENEFITS (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Net periodic benefit cost [Abstract]
Service Cost	$ 4,487	$ 3,718	$ 3,048
Interest Cost	7,886	8,008	7,828
Expected Return on Plan Assets	(9,435)	(8,249)	(7,415)
Amortizations [Abstract]
Prior Service Cost (Credits)	208	207	219
Actuarial Loss	7,608	6,432	4,561
Net Periodic Benefit Cost	10,754	10,116	8,241
Capitalized Benefit Costs	(5,002)	(4,684)	(3,661)
Affiliate SERP Allocations	(1,389)	(1,107)	(845)
Total Net Periodic Benefit Expense	4,363	4,325	3,735
Other Postretirement Benefits [Member]
Net periodic benefit cost [Abstract]
Service Cost	771	704	675
Interest Cost	2,221	2,443	2,621
Expected Return on Plan Assets	(2,158)	(1,910)	(2,040)
Amortizations [Abstract]
Prior Service Cost (Credits)	(195)	(195)	(254)
Actuarial Loss	1,555	1,534	1,466
Net Periodic Benefit Cost	2,194	2,576	2,468
Capitalized Benefit Costs	(1,172)	(1,340)	(1,222)
Affiliate SERP Allocations	0	0	0
Total Net Periodic Benefit Expense	$ 1,022	$ 1,236	$ 1,246

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DERIVATIVE INSTRUMENTS 3 (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives - Energy Related [Member]
Offsetting Derivative Assets [Abstract]
Gross amounts of recognized assets/liabilities	$ 1,500	$ 766
Gross amount offset in the balance sheet	0	0
Net amounts of assets/liabilities in balance sheet	1,500	766
Gross amounts not offset in the balance sheet, Financial Instruments	(155)	(447)	[1]
Gross amounts not offset in the balance sheet, Cash Collateral Posted	(498)	0
Net amount	847	319
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets/liabilities	(759)	(2,695)
Gross amount offset in the balance sheet	0	0
Net amounts of assets/liabilities in balance sheet	(759)	(2,695)
Gross amounts not offset in the balance sheet, Financial Instruments	155	447	[2]
Gross amounts not offset in the balance sheet, Cash Collateral Posted	0	1,136
Net amount	(604)	(1,112)
Derivatives - Other [Member]
Offsetting Derivative Liabilities [Abstract]
Gross amounts of recognized assets/liabilities	(3,735)	(7,761)
Gross amount offset in the balance sheet	0	0
Net amounts of assets/liabilities in balance sheet	(3,735)	(7,761)
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	$ (3,735)	$ (7,761)

[1] The balances at December 31, 2013 and December 31, 2012 were related to derivative liabilities which can be net settled against derivative assets.

[2] The balances at December 31, 2013 and December 31, 2012 were related to derivative assets which can be net settled against derivative liabilities.

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PENSION AND OTHER POSTRETIREMENT BENEFITS 10 (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Pension Contributions	$ 9,100,000	$ 19,757,000	$ 0
Pension Benefits [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2014	7,770,000
2015	8,303,000
2016	8,646,000
2017	9,021,000
2018	10,316,000
2019- 2023	61,659,000
Pension Contributions	9,100,000	19,800,000
Other Postretirement Benefits [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2014	3,725,000
2015	3,825,000
2016	3,906,000
2017	3,955,000
2018	3,997,000
2019- 2023	21,093,000
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	3,600,000
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 1,200,000

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INCOME TAXES AND CREDITS (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Tax at Statutory Rate									$ 33,974,000	$ 32,183,000	$ 30,510,000
Increase (Decrease) Resulting from:
State Income Taxes									4,833,000	5,302,000	5,316,000
Amortization of Investment Tax Credits									(258,000)	(287,000)	(302,000)
ESOP Dividend									(1,058,000)	(1,027,000)	(956,000)
AFUDC									(916,000)	(1,048,000)	(729,000)
Amortization of Flowthrough Depreciation									0	0	526,000
Other - Net									(1,742,000)	(1,412,000)	(84,000)
Net Income Taxes	11,322,000	471,000	2,269,000	20,771,000	10,589,000	258,000	1,887,000	20,977,000	34,833,000	33,711,000	34,281,000
Current:
Federal									(53,000)	(4,635,000)	(924,000)
State									2,946,000	(7,000)	168,000
Total Current									2,893,000	(4,642,000)	(756,000)
Deferred:
Federal									27,707,000	30,477,000	27,329,000
State									4,491,000	8,163,000	8,010,000
Total Deferred									32,198,000	38,640,000	35,339,000
Investment Tax Credits									(258,000)	(287,000)	(302,000)
Net Income Taxes	11,322,000	471,000	2,269,000	20,771,000	10,589,000	258,000	1,887,000	20,977,000	34,833,000	33,711,000	34,281,000
Annual amortization rate of investment tax credits									3.00%
Current:
Current Deferred Tax (Asset) Liability - Net	(23,309,000)				10,432,000				(23,309,000)	10,432,000
Noncurrent:
Noncurrent Deferred Tax Liability – Net	380,975,000				310,357,000				380,975,000	310,357,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1,				503,000				421,000	503,000	421,000	478,000
Increase as a result of tax position taken in prior years									44,000	82,000	119,000
Decrease due to a lapse in the statue of limitations									0	0	(90,000)
Settlements									0	0	(86,000)
Balance at December 31,	547,000				503,000				547,000	503,000	421,000
Accrued interest and penalties on unrecognized tax benefits	600,000				600,000				600,000	600,000	600,000
Internal Revenue Service (IRS) [Member]
Noncurrent:
Operating loss carryforwards	103,700,000								103,700,000
Internal Revenue Service (IRS) [Member] | 2031 [Member]
Noncurrent:
Operating loss carryforwards	99,400,000								99,400,000
Internal Revenue Service (IRS) [Member] | 2032 [Member]
Noncurrent:
Operating loss carryforwards	4,300,000								4,300,000
SJI [Member] | Prepaid Taxes [Member]
Noncurrent:
Income taxes due from parent company	0				4,600,000				0	4,600,000
Classified as Current [Member]
Current:
Net Operating Loss Carryforward	(27,600,000)				(2,586,000)				(27,600,000)	(2,586,000)
Budget Billing - Customer Accounts	1,152,000				1,033,000				1,152,000	1,033,000
Provision for Uncollectibles	(1,726,000)				(1,409,000)				(1,726,000)	(1,409,000)
Conservation Incentive Program	4,631,000				13,942,000				4,631,000	13,942,000
Section 461 Prepayments	1,156,000				930,000				1,156,000	930,000
Other	(922,000)				(1,478,000)				(922,000)	(1,478,000)
Classified as Noncurrent [Member]
Current:
Net Operating Loss Carryforward	(8,764,000)				(35,901,000)				(8,764,000)	(35,901,000)
Noncurrent:
Book Versus Tax Basis of Property	371,684,000				323,470,000				371,684,000	323,470,000
Deferred Fuel Costs - Net	1,330,000				3,325,000				1,330,000	3,325,000
Environmental Remediation	14,392,000				17,643,000				14,392,000	17,643,000
Deferred Regulatory Costs	13,665,000				15,374,000				13,665,000	15,374,000
Deferred State Tax	(15,471,000)				(15,106,000)				(15,471,000)	(15,106,000)
Investment Tax Credit Basis Gross-Up	(185,000)				(318,000)				(185,000)	(318,000)
Deferred Pension & Other Post Retirement Benefits	24,218,000				39,174,000				24,218,000	39,174,000
Pension & Other Post Retirement Benefits	(14,152,000)				(28,846,000)				(14,152,000)	(28,846,000)
Deferred Revenues	(9,266,000)				(8,922,000)				(9,266,000)	(8,922,000)
Other	$ 3,524,000				$ 464,000				$ 3,524,000	$ 464,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2013

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). In our opinion, the 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. 

Certain reclassifications have been made to the prior periods regulatory assets disclosure to conform to the current period presentation. The deferred pipeline integrity cost previously included in "Other Regulatory Assets" was reclassified to the line item "Pipeline Integrity Cost" in the regulatory asset table disclosed in Note 4.

Equity Investments - Marketable equity securities that are purchased as long-term investments are classified as Available-for-Sale Securities and carried at their fair value on our balance sheets. Any unrealized gains or losses are included in Accumulated Other Comprehensive Loss.  An impairment loss is recorded when there is clear evidence that a decline in value is other than temporary.   No impairment losses were recorded on Investments during 2013, 2012 or 2011.

Estimates and Assumptions - We prepare our financial statements to conform with accounting principles generally accepted in the United States of America (GAAP). Management makes estimates and assumptions that affect the amounts reported in the financial statements and related disclosures. Therefore, actual results could differ from those estimates. Significant estimates include amounts related to regulatory accounting, energy derivatives, environmental remediation costs, pension and other postretirement benefit costs, and revenue recognition.

Regulation- We are subject to the rules and regulations of the New Jersey Board of Public Utilities (BPU). See Note 3 for a detailed discussion of our rate structure and regulatory actions. We maintain our accounts according to the BPU’s prescribed Uniform System of Accounts. We follow the accounting for regulated enterprises prescribed by the FASB ASC Topic 980 – “Regulated Operations.”  In general, Topic 980 allows for the deferral of certain costs (regulatory assets) and creation of certain obligations (regulatory liabilities) when it is probable that such items will be recovered from or refunded to customers in future periods. See Note 4 for a detailed discussion of regulatory assets and liabilities.

Operating Revenues - Gas revenues are recognized in the period the commodity is delivered to customers. For retail customers that are not billed at the end of the month, we record an estimate to recognize unbilled revenues for gas delivered from the date of the last meter reading to the end of the month.

Revenue and Throughput-Based Taxes - We collect certain revenue-based energy taxes from our customers. Such taxes include New Jersey State Sales Tax and Public Utilities Assessment (PUA). We also collect a throughput-based energy tax from customers in the form of a Transitional Energy Facility Assessment (TEFA). State sales tax is recorded as a liability when billed to customers and is not included in revenue or operating expenses. TEFA and PUA are included in both revenues and cost of sales and totaled $5.2 million, $6.0 million and $8.0 million in 2013, 2012 and 2011, respectively. TEFA is subject to a planned phase-out, which decreased the assessment in increments of 25.0% in 2013 and 2012 and is eliminated after December 31, 2013.

Accounts Receivable and Provision for Uncollectible Accounts - Accounts receivable are carried at the amount owed by customers. A provision for uncollectible accounts is established based on our collection experience and an assessment of the collectibility of specific accounts.

Natural Gas in Storage – Natural Gas in Storage is reflected at average cost on the balance sheets, and represents natural gas that will be utilized in the ordinary course of business.

Property, Plant & Equipment - For regulatory purposes, utility plant is stated at original cost, which may be different than our cost if the assets were acquired from another regulated entity. The cost of adding, replacing and renewing property is charged to the appropriate plant account. Utility Plant balances as of December 31, 2013 and 2012 were comprised of the following (in thousands):

	2013		2012
Utility Plant:
Production Plant	$	296	$	296
Storage Plant	22,538		20,316
Transmission Plant	248,074		250,886
Distribution Plant	1,417,939		1,297,619
General Plant	53,162		49,586
Other Plant	1,855		1,855
Utility Plant in Service	1,743,864		1,620,558
Construction Work in Progress	72,940		38,232
Total Utility Plant	$	1,816,804	$	1,658,790

The increase in Utility Plant in Service is related to projects for distribution, some of which are part of the Company's Capital Investment Recovery Tracker (CIRT) and Accelerated Infrastructure Replacement Program (AIRP), as discussed under Note 3. The increase in Construction Work in Progress is primarily related to information technology projects.

Asset Retirement Obligations - The amounts included under Asset Retirement Obligations (ARO) are primarily related to the legal obligations we have to cut and cap our gas distribution pipelines when taking those pipelines out of service in future years. These liabilities are generally recognized upon the acquisition or construction of the asset. The related asset retirement cost is capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the liability. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

ARO activity during 2013 and 2012 was as follows (in thousands):

	2013			2012
ARO as of January 1,	$	38,892		$	29,388
Accretion	1,514			1,870
Additions	743			989
Settlements	(1,630		)	(1,603		)
Revisions in Estimated Cash Flows *	1,659			8,248
ARO as of December 31,	$	41,178		$	38,892

* The revision in estimated cash flows in 2013 reflects an increase in the inflation rate used to determine the ARO settlement amount. In 2012, the revision in estimated cash flows reflected increases in the contractual cost as well as changes in the discount rates used to determine the ARO. A corresponding increase was made to regulatory assets, thus having no impact on earnings.

Depreciation - We depreciate utility plant on a straight-line basis over the estimated remaining lives of the various property classes. These estimates are periodically reviewed and adjusted as required after BPU approval. The composite annual rate for all depreciable utility property was approximately 2.3% in 2013, 2.4% in 2012 and 2.3% in 2011. The actual composite rate may differ from the approved rate as the asset mix changes over time. Except for retirements outside of the normal course of business, accumulated depreciation is charged with the cost of depreciable utility property retired, less salvage.

Capitalized Interest - We capitalize interest on construction at the rate of return on rate base utilized by the BPU to set rates in our last base rate proceeding (See Note 3). Capitalized interest is included in Utility Plant on the balance sheets. Interest Charges are presented net of capitalized interest on the statements of income.  We capitalized interest of $8.2 million in 2013, $6.5 million in 2012 and $1.1 million in 2011. The increase in 2013 represents the interest on the Company's investment in Utility Plant under the BPU-approved CIRT and AIRP programs. Under the CIRT and AIRP, qualified capital expenditures continued to accrue interest on construction until such projects were rolled into customer rates and recovery of the expenditures commenced.

All CIRT program investments have been rolled into rate base and the CIRT program is now concluded. See Note 3 for additional discussion of the CIRT programs.

Impairment of Long-Lived Assets - We review the carrying amount of long-lived assets for possible impairment whenever events or changes in circumstances indicate that such amounts may not be recoverable. For the years ended 2013, 2012 and 2011, no significant impairments were identified.

Derivative Instruments - SJG, through its affiliate, South Jersey Resources Group (SJRG) and another counterparty, uses a variety of derivative instruments to limit its exposure to market risk in accordance with strict guidelines (See Note 14).  These contracts, which 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 balance sheets.  The costs or benefits of these short-term contracts are recoverable through SJG’s Basic Gas Supply Service (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 balance sheets.

SJG 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 balance sheets.  The fair value represents the amount SJG would have to pay the counterparty to terminate these contracts as of those dates.  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 Other Regulatory Assets in the balance sheets.

Income Taxes - Deferred income taxes are provided for all significant temporary differences between the book and taxable basis of assets and liabilities in accordance with FASB ASC Topic 740 – “Income Taxes” (See Note 6). A valuation allowance is established when it is determined that it is more likely than not that a deferred tax asset will not be realized.

Cash and Cash Equivalents - For purposes of reporting cash flows, highly liquid investments with original maturities of three months or less are considered cash equivalents.

NEW ACCOUNTING PRONOUNCEMENTS- Other than as described below, no new accounting pronouncement issued or effective during 2013, 2012 or 2011 had, or is expected to have, a material impact on the financial statements.

In January 2012, the FASB issued Accounting Standards Update (ASU) 2011-11, Enhanced Disclosure Requirements Concerning Offsetting of Financial Assets and Financial Liabilities. This ASU amends ASC 210-20 to add disclosure requirements in respect of the offsetting of financial assets and financial liabilities. In February 2013, the FASB issued ASU 2013-01 Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which amends and clarifies the scope of the balance sheet offsetting disclosures required through ASU 2011-11. The new guidance was effective for fiscal years beginning on or after January 1, 2013. The adoption of this guidance modified the disclosures around derivative instruments, but did not have an impact on the Company's financial statement results.

In February 2013, the FASB issued ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This ASU expands the disclosure requirements in ASC 220 and requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective lines in net income. The ASU requires an entity to present information about significant items reclassified out of accumulated other comprehensive income by component either on the face of the statement where net income is presented, or as a separate disclosure in the notes to the financial statements. The new guidance was effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. The adoption of this guidance modified the disclosures around accumulated other comprehensive income, but did not have an impact on the Company's financial statement results.

In July 2013, the FASB issued ASU 2013-11, Balance Sheet Presentation of an Unrecognized Income Tax Benefit for a Net Operating Loss or Tax Credit Carryforward. This ASU provides that a liability related to an unrecognized tax benefit should be offset against a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. Management does not anticipate that the adoption of this guidance will have an impact on the Company's financial statement results.

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PENSION AND OTHER POSTRETIREMENT BENEFITS 11 (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized	$ 1.0	$ 0.9	$ 0.8
Employee Qualifying For Defined Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contribution Per Employee, Percent	50.00%
Defined Contribution Plan, Employer Matching Contribution, Percent	6.00%
Employee Not Qualifying For Defined Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contribution Per Employee, Percent	50.00%
Defined Contribution Plan, Employer Matching Contribution, Percent	8.00%
Year End Contribution for Employees With Less Then Ten Years of Service	1,000
Years of Service Threshold to Determine Year End Contribution	10 years
Year End Contribution for Employees With More Then Ten Years of Service	1,500

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RATES AND REGULATORY ACTIONS (Details) (USD $)	0 Months Ended	1 Months Ended											0 Months Ended	1 Months Ended										0 Months Ended	1 Months Ended		1 Months Ended									0 Months Ended	1 Months Ended									1 Months Ended													12 Months Ended	264 Months Ended			1 Months Ended
	Sep. 17, 2010	Sep. 30, 2013	Jun. 30, 2013	Feb. 28, 2013	Jul. 31, 2012	Dec. 31, 2013 customer	Oct. 31, 2013	Dec. 31, 2012 sites	Dec. 31, 2013 Environmental Restoration Costs Expended Net [Member]	Dec. 31, 2012 Environmental Restoration Costs Expended Net [Member]	Dec. 31, 2013 Other Regulatory Assets, Deferred Pipeline Integrity Costs [Member]	Dec. 31, 2012 Other Regulatory Assets, Deferred Pipeline Integrity Costs [Member]	Sep. 17, 2010 Conservation Incentive Program [Member]	Sep. 30, 2013 Conservation Incentive Program [Member]	May 31, 2013 Conservation Incentive Program [Member]	Jun. 30, 2012 Conservation Incentive Program [Member]	Jun. 30, 2011 Conservation Incentive Program [Member]	May 31, 2013 Conservation Incentive Program [Member] Non Weather [Member]	Jun. 30, 2012 Conservation Incentive Program [Member] Non Weather [Member]	Jun. 30, 2011 Conservation Incentive Program [Member] Non Weather [Member]	May 31, 2013 Conservation Incentive Program [Member] Weather [Member]	Jun. 30, 2012 Conservation Incentive Program [Member] Weather [Member]	Jun. 30, 2011 Conservation Incentive Program [Member] Weather [Member]	Sep. 17, 2010 Capital Investment Recovery Tracker [Member]	Sep. 30, 2013 Capital Investment Recovery Tracker [Member]	Oct. 31, 2012 Capital Investment Recovery Tracker [Member]	Jan. 31, 2009 Capital Investment Recovery Tracker [Member] Capital Expenditures [Member]	May 31, 2012 Capital Investment Recovery Tracker [Member] Capital Expenditures [Member]	Jun. 30, 2011 Capital Investment Recovery Tracker [Member] Capital Expenditures [Member]	Mar. 31, 2011 Capital Investment Recovery Tracker [Member] Capital Expenditures [Member]	Sep. 30, 2010 Capital Investment Recovery Tracker [Member] Capital Expenditures [Member]	Oct. 31, 2011 Capital Investment Recovery Tracker [Member] Recovered in 2012 [Member]	Oct. 31, 2011 Capital Investment Recovery Tracker [Member] Recovered in 2013 [Member]	Jan. 31, 2009 Capital Investment Recovery Tracker, 2009 Spending [Member] Capital Expenditures [Member]	Jan. 31, 2009 Capital Investment Recovery Tracker, 2010 Spending [Member] Capital Expenditures [Member]	Sep. 17, 2010 Incremental Revenue [Member]	Jan. 31, 2013 Basic Gas Supply Service [Member]	Dec. 31, 2011 Basic Gas Supply Service [Member]	Mar. 31, 2011 Basic Gas Supply Service [Member]	Sep. 30, 2013 Basic Gas Supply Service [Member]	May 31, 2013 Basic Gas Supply Service [Member]	Sep. 30, 2012 Basic Gas Supply Service [Member]	Jun. 30, 2012 Basic Gas Supply Service [Member]	Sep. 30, 2011 Basic Gas Supply Service [Member]	Jun. 30, 2011 Basic Gas Supply Service [Member]	Jan. 31, 2014 Basic Gas Supply Service [Member] Subsequent Event [Member]	Jan. 31, 2011 Energy Efficiency Tracker [Member]	Nov. 30, 2010 Energy Efficiency Tracker [Member]	Jan. 31, 2009 Energy Efficiency Tracker [Member]	Jul. 31, 2013 Energy Efficiency Tracker [Member]	Jun. 30, 2013 Energy Efficiency Tracker [Member]	May 31, 2013 Energy Efficiency Tracker [Member]	Jun. 30, 2012 Energy Efficiency Tracker [Member]	May 31, 2012 Energy Efficiency Tracker [Member]	Jun. 30, 2011 Energy Efficiency Tracker [Member]	Jul. 31, 2013 Societal Benefits Clause [Member]	Jul. 31, 2012 Societal Benefits Clause [Member]	Jul. 31, 2011 Societal Benefits Clause [Member]	Dec. 31, 2013 Remediation Adjustment Clause [Member] sites	Dec. 31, 2013 Remediation Adjustment Clause [Member] sites	Dec. 31, 2013 Remediation Adjustment Clause [Member] Environmental Restoration Costs Expended Net [Member]	Dec. 31, 2012 Remediation Adjustment Clause [Member] Environmental Restoration Costs Expended Net [Member]	Nov. 30, 2012 New Jersey Clean Energy Program [Member]	Aug. 31, 2008 New Jersey Clean Energy Program [Member]	Sep. 30, 2013 Universal Service Fund [Member]	Jun. 30, 2013 Universal Service Fund [Member]	Sep. 30, 2012 Universal Service Fund [Member]	Jun. 30, 2012 Universal Service Fund [Member]	Oct. 31, 2011 Universal Service Fund [Member]	Jun. 30, 2011 Universal Service Fund [Member]
Schedule of Capitalization [Line Items]
Public Utilities, Rate of Return on Base Rate	8.21%
Public Utilities, Return on Common Equity	10.30%
Public Utilities, Approved Base Rate Increase	$ 42,100,000												$ 16,600,000											$ 6,800,000												$ 18,700,000
Public Utilities, Annual Depreciation Reduction Attributable To Petition	1,200,000
Amount of Regulatory Costs Not yet Approved																	2,700,000	2,300,000	8,400,000	1,300,000	15,500,000	19,600,000	1,400,000			13,200,000	103,000,000	35,000,000		60,300,000		40,000,000	50,000,000	70,500,000	32,500,000						600,000		27,000,000									2,200,000	5,800,000	3,100,000	4,700,000	(6,400,000)	11,800,000	31,200,000
Amount of Regulatory Costs Not yet Approved, Percent Change in Recoveries																																											8.80%
Amount of Regulatory Costs Approved															17,800,000		2,700,000														81,300,000									600,000		27,000,000		10,600,000	10,600,000					2,100,000	24,000,000														5,800,000		8,200,000		5,400,000
Amount of Regulatory Costs Approved, Percent Change in Recoveries																													0.50%													(8.80%)		(2.90%)	(2.90%)
Proceeds from Refunds From Favorable Regulatory Action																																					9,400,000	18,700,000	21,100,000							11,200,000
Amount of Regulatory Costs Not yet Approved, Prior Year Carryover																28,000,000	2,500,000			5,200,000
Regulatory Costs, Original Recovery Period of Expenditures (in years)																											5 years
Regulatory Costs, Proposed Recovery Period of Expenditures (in years)																											2 years
Amount of Regulatory Costs Available Under Program																																																	17,000,000.0
Regulatory Costs, Period																																																	2 years
Number of sites for environmental cleanup								12																																																			12	12
Amortization Period of Environmental Remediation Costs (in years)																																																											7 years
Amount of Regulatory Costs Approved, Statewide																																																																1,200,000,000	54,400,000		78,000,000		57,400,000
Regulatory Costs For Which Reporting Entity is Responsible For																																																															7,500,000	41,500,000
Regulatory Costs For Which Reporting Entity is Responsible For, Period of Recovery (in years)																																																																4 years
Regulatory Costs, Extension Period														1 year																																	1 year	1 year															6 months
Regulatory Assets						296,081,000		352,656,000	29,945,000	37,892,000	2,800,000	1,600,000																																																	29,900,000	37,900,000
Regulated Costs Recovered																																																												92,600,000
Amount of Regulatory Costs Not yet Approved, Statewide																																																																		(29,400,000)		(500,000)		(9,300,000)
Amount of Regulatory Costs Not Yet Approved, Annual Revenue Impact																																																																		(3,700,000)		(100,000)		(800,000)
Amount of Regulatory Costs Approved, Annual Revenue Impact																																																																	3,400,000		100,000		500,000
Regulated Operations, Number of Customers Purchasing Energy Commodities From A Provider Other Then The Reporting Entity						47,074
Investment Requested to be Recovered through CIRT, Investments To Be Rolled to Base Rate						22,500,000	95,000,000																			110,600,000
Investment Requested to be Recovered through CIRT, Revenue Increase																									15,500,000.0
Investment Requested to be Recovered through CIRT III, Term of AIRP				4 years	5 years
Investment Requested to be Recovered through CIRT III, Amount of AIRP				141,200,000	250,000,000
Investment Requested to be Recovered through CIRT III, Annual Amount of AIRP				35,300,000
Investment Requested to be Recovered through SHARP		280,000,000
Investment Requested to be Recovered through SHARP, Term		7 years
Costs Requested for Deferral, Storm Related			$ 700,000

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STOCK-BASED COMPENSATION PLANS (Tables)

12 Months Ended

Dec. 31, 2013

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 December 31, 2013, and the assumptions used to estimate the fair value of the awards:

Grant Date	Shares Outstanding	Fair Value Per Share		Expected Volatility		Risk-Free Interest Rate
Jan. 2012 - TSR	3,533	$	51.23	22.5	%	0.43	%
Jan. 2012 - EPS	3,533	$	56.93	n/a		n/a
Jan. 2013 - TSR	4,001	$	44.38	21.1	%	0.40	%
Jan. 2013 - EPS	4,001	51.18		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 2013, excluding accrued dividend equivalents:

	Shares		Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, January 1, 2013	15,108		$	52.55
Granted	9,324		$	47.78
Vested*	(7,116	)	$	50.94
Cancelled / Forfeited	(2,248	)	$	50.02
Nonvested Shares Outstanding, December 31, 2013	15,068		$	50.73

* Performance targets during the 3-year vesting period were not attained for the January 2011 grant. As a result, no shares will be awarded in 2014.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Schedule of Utility Plant balances

Utility Plant balances as of December 31, 2013 and 2012 were comprised of the following (in thousands):

	2013		2012
Utility Plant:
Production Plant	$	296	$	296
Storage Plant	22,538		20,316
Transmission Plant	248,074		250,886
Distribution Plant	1,417,939		1,297,619
General Plant	53,162		49,586
Other Plant	1,855		1,855
Utility Plant in Service	1,743,864		1,620,558
Construction Work in Progress	72,940		38,232
Total Utility Plant	$	1,816,804	$	1,658,790

Asset retirement obligation activity

ARO activity during 2013 and 2012 was as follows (in thousands):

	2013			2012
ARO as of January 1,	$	38,892		$	29,388
Accretion	1,514			1,870
Additions	743			989
Settlements	(1,630		)	(1,603		)
Revisions in Estimated Cash Flows *	1,659			8,248
ARO as of December 31,	$	41,178		$	38,892

* The revision in estimated cash flows in 2013 reflects an increase in the inflation rate used to determine the ARO settlement amount. In 2012, the revision in estimated cash flows reflected increases in the contractual cost as well as changes in the discount rates used to determine the ARO. A corresponding increase was made to regulatory assets, thus having no impact on earnings.

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PENSION AND OTHER POSTRETIREMENT BENEFITS 5 (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	5.09%	4.26%
Rate of Compensation Increase	3.50%	3.25%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	4.26%	5.03%	5.78%
Expected Long-Term Return on Plan Assets	7.50%	7.50%	8.00%
Rate of Compensation Increase	3.25%	3.25%	3.25%
Other Postretirement Benefits [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	4.91%	4.14%
Rate of Compensation Increase	3.50%	3.25%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	4.14%	4.92%	5.55%
Expected Long-Term Return on Plan Assets	6.60%	6.60%	7.00%
Rate of Compensation Increase	3.25%	3.25%	3.25%

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REGULATORY ASSETS AND LIABILITIES (Details) (USD $)	12 Months Ended								12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013 sites regulatory_assets	Dec. 31, 2013 Environmental Restoration Costs: Expended - Net [Member]	Dec. 31, 2012 Environmental Restoration Costs: Expended - Net [Member]	Dec. 31, 2013 Environmental Restoration Costs: Liability for Future Expenditures [Member]	Dec. 31, 2012 Environmental Restoration Costs: Liability for Future Expenditures [Member]	Dec. 31, 2013 Deferred Asset Retirement Obligation Costs [Member]	Dec. 31, 2012 Deferred Asset Retirement Obligation Costs [Member]	Dec. 31, 2006 Deferred Pension and Other Postretirement Benefit Costs [Member]	Dec. 31, 2013 Deferred Pension and Other Postretirement Benefit Costs [Member]	Dec. 31, 2012 Deferred Pension and Other Postretirement Benefit Costs [Member]	Dec. 31, 2013 Conservation Incentive Program Receivable [Member]	Dec. 31, 2012 Conservation Incentive Program Receivable [Member]	Dec. 31, 2013 Societal Benefit Costs Receivable [Member]	Dec. 31, 2012 Societal Benefit Costs Receivable [Member]	Dec. 31, 2013 Premium for Early Retirement of Debt [Member]	Dec. 31, 2012 Premium for Early Retirement of Debt [Member]	Dec. 31, 2013 Deferred Interest Rate Contracts (Note 11) [Member]	Dec. 31, 2012 Deferred Interest Rate Contracts (Note 11) [Member]	Dec. 31, 2013 Energy Efficiency Tracker [Member]	Dec. 31, 2012 Energy Efficiency Tracker [Member]	Dec. 31, 2013 Pipeline Supplier Service Charges [Member]	Dec. 31, 2012 Pipeline Supplier Service Charges [Member]	Dec. 31, 2013 Pipeline Integrity Cost [Member]	Dec. 31, 2012 Pipeline Integrity Cost [Member]	Dec. 31, 2013 Other Regulatory Assets [Member]	Dec. 31, 2012 Other Regulatory Assets [Member]
Regulatory Assets [Line Items]
Total regulatory assets	$ 352,656,000	$ 296,081,000	$ 29,945,000	$ 37,892,000	$ 119,492,000	$ 107,410,000	$ 31,142,000	$ 30,199,000		$ 59,284,000	$ 95,897,000	$ 10,526,000	$ 31,686,000	$ 10,408,000	$ 12,801,000	$ 955,000	$ 1,075,000	$ 3,735,000	$ 7,761,000	$ 10,420,000	$ 12,306,000	$ 7,106,000	$ 8,771,000	$ 2,902,000	$ 1,584,000	$ 10,166,000	$ 5,274,000
Number regulatory assets associated with environmental costs related to the cleanup of 12 sites where SJG or their predecessors previously operated gas manufacturing plants (in regulatory assets)		2
Number of sites where SJG or their predecessors previously operated gas manufacturing plants (in sites)		12
Amortization period deferred costs	15 years
Regulatory asset increased									$ 37,100,000

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REGULATORY ASSETS AND LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets

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

	2013		2012
Environmental Remediation Costs:
Expended - Net	$	29,945	$	37,892
Liability for Future Expenditures	119,492		107,410
Deferred Asset Retirement Obligation Costs	31,142		30,199
Deferred Pension and Other Postretirement Benefit Costs	59,284		95,897
Conservation Incentive Program Receivable	10,526		31,686
Societal Benefit Costs Receivable	10,408		12,801
Premium for Early Retirement of Debt	955		1,075
Deferred Interest Rate Contracts	3,735		7,761
Energy Efficiency Tracker	10,420		12,306
Pipeline Supplier Service Charges	7,106		8,771
Pipeline Integrity Cost	2,902		1,584
Other Regulatory Assets	10,166		5,274
Total Regulatory Assets	$	296,081	$	352,656

Schedule of Regulatory Liabilities

Regulatory Liabilities at December 31 consisted of the following items (in thousands):

	2013		2012
Excess Plant Removal Costs	$	40,029	$	45,593
Deferred Revenue - Net	19,067		10,924
Other Regulatory Liabilities	1,853		—
Total Regulatory Liabilities	$	60,949	$	56,517

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RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Summary of related party transactions

A summary of these related party transactions, excluding pass-through items, included in Operating Revenues were as follows (in thousands):

	2013		2012		2011
Operating Revenues/Affiliates:
SJRG	$	1,390	$	884	$	6,532
Other	1,299		851		716
Total Operating Revenues/Affiliates	$	2,689	$	1,735	$	7,248

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

	2013			2012			2011
Costs of Sales/Affiliates
(Excluding depreciation):
SJRG	$	14,959		$	9,083		$	33,768
Derivative Losses (See Note 1):
SJRG	$	887		$	15,407		$	12,872
Operations Expense/Affiliates:
SJI	$	11,990		$	10,870		$	9,941
SJIS	5,531			5,397			4,956
Millennium	2,686			3,149			3,076
Other	(428		)	(500		)	(448		)
Total Operations Expense/Affiliates	$	19,779		$	18,916		$	17,525

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STATEMENTS OF CHANGES IN COMMON EQUITY AND COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Change In Accumulated Other Comprehensive Loss Balances [Roll Forward]
Beginning balance	$ (13,285)	[1]
Changes During Year	2,416	[1]	(1,156)	[1]	(3,009)	[1]
Ending balance	(10,869)	[1]	(13,285)	[1]
Postretirement Liability Adjustment [Member]
Change In Accumulated Other Comprehensive Loss Balances [Roll Forward]
Beginning balance	(12,958)	[1]	(11,275)	[1]	(8,599)	[1]
Changes During Year	2,286	[1]	(1,683)	[1]	(2,676)	[1]
Ending balance	(10,672)	[1]	(12,958)	[1]	(11,275)	[1]
Unrealized Gain (Loss) on Available-for-Sale Securities [Member]
Change In Accumulated Other Comprehensive Loss Balances [Roll Forward]
Beginning balance	294	[1]	(206)	[1]	154	[1]
Changes During Year	103	[1]	500	[1]	(360)	[1]
Ending balance	397	[1]	294	[1]	(206)	[1]
Unrealized Gain (Loss) on Derivatives [Member]
Change In Accumulated Other Comprehensive Loss Balances [Roll Forward]
Beginning balance	(621)	[1]	(648)	[1]	(675)	[1]
Changes During Year	27	[1]	27	[1]	27	[1]
Ending balance	(594)	[1]	(621)	[1]	(648)	[1]
Accumulated Other Comprehensive Income (Loss) [Member]
Change In Accumulated Other Comprehensive Loss Balances [Roll Forward]
Beginning balance	(13,285)	[1]	(12,129)	[1]	(9,120)	[1]
Changes During Year	2,416	[1]	(1,156)	[1]	(3,009)	[1]
Ending balance	$ (10,869)	[1]	$ (13,285)	[1]	$ (12,129)	[1]

[1] Determined using a combined statutory tax rate of 41%.

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INCOME TAXES AND CREDITS (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Schedule of effective income tax rate reconciliation

Total income taxes applicable to operations differ from the tax that would have resulted by applying the statutory Federal income tax rate to pre-tax income for the following reasons (in thousands):

	2013			2012			2011
Tax at Statutory Rate	$	33,974		$	32,183		$	30,510
Increase (Decrease) Resulting from:
State Income Taxes	4,833			5,302			5,316
Amortization of Investment Tax Credits	(258		)	(287		)	(302		)
ESOP Dividend	(1,058		)	(1,027		)	(956		)
AFUDC	(916		)	(1,048		)	(729		)
Amortization of Flowthrough Depreciation	—			—			526
Other - Net	(1,742		)	(1,412		)	(84		)
Net Income Taxes	$	34,833		$	33,711		$	34,281

Schedule of components of provision for income taxes

The provision for Income Taxes is comprised of the following (in thousands):

	2013			2012			2011
Current:
Federal	$	(53	)	$	(4,635	)	$	(924	)
State	2,946			(7		)	168
Total Current	2,893			(4,642		)	(756		)
Deferred:
Federal	27,707			30,477			27,329
State	4,491			8,163			8,010
Total Deferred	32,198			38,640			35,339
Investment Tax Credits	(258		)	(287		)	(302		)
Net Income Taxes	$	34,833		$	33,711		$	34,281

Schedule of deferred tax assets and liabilities

The net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and income tax purposes resulted in the following net deferred tax liabilities at December 31 (in thousands):

	2013			2012
Current:
Net Operating Loss Carryforward	$	(27,600	)	$	(2,586	)
Budget Billing - Customer Accounts	1,152			1,033
Provision for Uncollectibles	(1,726		)	(1,409		)
Conservation Incentive Program	4,631			13,942
Section 461 Prepayments	1,156			930
Other	(922		)	(1,478		)
Current Deferred Tax (Asset) Liability - Net	$	(23,309	)	$	10,432
Noncurrent:
Book Versus Tax Basis of Property	$	371,684		$	323,470
Deferred Fuel Costs - Net	1,330			3,325
Environmental Remediation	14,392			17,643
Deferred Regulatory Costs	13,665			15,374
Deferred State Tax	(15,471		)	(15,106		)
Investment Tax Credit Basis Gross-Up	(185		)	(318		)
Deferred Pension & Other Post Retirement Benefits	24,218			39,174
Pension & Other Post Retirement Benefits	(14,152		)	(28,846		)
Deferred Revenues	(9,266		)	(8,922		)
Net Operating Loss Carryforward	(8,764		)	(35,901		)
Other	3,524			464
Noncurrent Deferred Tax Liability – Net	$	380,975		$	310,357

Reconciliation of unrecognized tax benefits

A reconciliation of unrecognized tax benefits is as follows (in thousands):

	2013		2012		2011
Balance at January 1,	$	503	$	421	$	478
Increase as a result of tax position taken in prior years	44		82		119
Decrease due to a lapse in the statue of limitations	—		—		(90		)
Settlements	—		—		(86		)
Balance at December 31,	$	547	$	503	$	421

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QUARTERLY RESULTS OF OPERATIONS - UNAUDITED (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

The summarized quarterly results of our operations are as follows (in thousands):  

	2013 Quarter Ended								2012 Quarter Ended
	March 31		June 30		Sept. 30		Dec. 31		March 31		June 30		Sept. 30		Dec. 31
Operating Revenues	$	174,098	$	66,536	$	59,674	$	146,172	$	179,436	$	59,177	$	54,251	$	129,010
Expenses:
Cost of Sales (excluding depreciation)	77,602		26,108		24,717		71,654		86,499		20,407		21,053		60,751
Operations and Maintenance
Including Fixed Charges	38,659		33,871		33,249		39,486		35,102		33,597		32,953		33,877
Income Taxes	20,771		2,269		471		11,322		20,977		1,887		258		10,589
Energy and Other Taxes	3,003		1,277		1,052		2,530		3,169		1,479		1,167		2,485
Total Expenses	140,035		63,525		59,489		124,992		145,747		57,370		55,431		107,702
Other Income and Expense	1,450		810		764		773		1,349		1,430		1,703		(1,865		)
Net Income	$	35,513	$	3,821	$	949	$	21,953	$	35,038	$	3,237	$	523	$	19,443

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PENSION AND OTHER POSTRETIREMENT BENEFITS 2 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Regulatory Assets
Beginning Balance	$ 68,713	$ 61,811
Amounts Arising During the Period, Net Actuarial Gain (Loss)	(20,554)	11,599
Amounts Amortized to Net Periodic Costs, Net Actuarial Loss	(5,319)	(4,490)
Amounts Amortized to Net Periodic Costs, Prior Service (Cost) Credit	(208)	(207)
Ending Balance	42,632	68,713
Accumulated Other Comprehensive Loss (pre-tax)
Beginning Balance	21,908	19,061
Amounts Arising During the Period, Net Actuarial Gain (Loss)	(1,576)	4,788
Amounts Amortized to Net Periodic Costs, Net Actuarial Loss	(2,289)	(1,941)
Amounts Amortized to Net Periodic Costs, Prior Service (Cost) Credit	0	0
Ending Balance	18,043	21,908
Other Postretirement Benefits [Member]
Regulatory Assets
Beginning Balance	27,184	26,435
Amounts Arising During the Period, Net Actuarial Gain (Loss)	(9,171)	2,089
Amounts Amortized to Net Periodic Costs, Net Actuarial Loss	(1,555)	(1,535)
Amounts Amortized to Net Periodic Costs, Prior Service (Cost) Credit	194	195
Ending Balance	16,652	27,184
Accumulated Other Comprehensive Loss (pre-tax)
Beginning Balance	0	0
Amounts Arising During the Period, Net Actuarial Gain (Loss)	0	0
Amounts Amortized to Net Periodic Costs, Net Actuarial Loss	0	0
Amounts Amortized to Net Periodic Costs, Prior Service (Cost) Credit	0	0
Ending Balance	$ 0	$ 0

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SUBSEQUENT EVENT (Details) (USD $)	1 Months Ended
	Oct. 31, 2013	Oct. 31, 2013 Maximum [Member]	Jan. 31, 2014 Subsequent Event [Member] Mortgages [Member]
Subsequent Event [Line Items]
Debt Instrument, Face Amount			$ 30,000,000
Debt Instrument, Interest Rate, Stated Percentage			4.23%
Amount of Additional Debt Petitioned For		$ 200,000,000
Amount of Additional Debt Petitioned For, Period	3 years

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STATEMENTS OF INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]
Operating Revenues	$ 446,480	$ 421,874	$ 412,449
Operating Expenses:
Cost of Sales (Excluding depreciation)	200,081	188,710	187,866
Operations	85,805	78,425	68,149
Maintenance	13,135	13,615	13,122
Depreciation	33,775	31,062	30,358
Energy and Other Taxes	7,862	8,300	10,291
Total Operating Expenses	340,658	320,112	309,786
Operating Income	105,822	101,762	102,663
Other Income and Expense	3,797	2,617	3,429
Interest Charges	(12,550)	(12,427)	(18,922)
Income Before Income Taxes	97,069	91,952	87,170
Income Taxes	(34,833)	(33,711)	(34,281)
Net Income	$ 62,236	$ 58,241	$ 52,889

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REGULATORY ASSETS AND LIABILITIES REGULATORY ASSETS AND LIABILITIES 2 (Details) (USD $)	1 Months Ended
	Sep. 30, 2010	Dec. 31, 2013	Dec. 31, 2012
Regulatory Liabilities [Line Items]
Regulatory Liabilities		$ 60,949,000	$ 56,517,000
Excess Plant Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		40,029,000	45,593,000
Annual amortization reflected in depreciation expense	1,200,000
Deferred Revenues - Net [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		19,067,000	10,924,000
Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		$ 1,853,000	$ 0

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BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 2.50	$ 2.50
Common stock, shares authorized	4,000,000	4,000,000
Common stock, shares outstanding	2,339,139	2,339,139

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PENSION AND OTHER POSTRETIREMENT BENEFITS 8 (Details) (Pension Benefits [Member], USD $)	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Required Capitalization for Plan Asset Allocation	$ 250,000,000.0
Defined Benefit Plan, Required Capitalization for Plan Asset Allocation, Small Cap	$ 50,000,000.0
Equity Securities, U.S. Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	28.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	48.00%
Equity Securities, International Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	13.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	25.00%
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	32.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	42.00%
Other Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	2.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	14.00%

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PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)

12 Months Ended

Dec. 31, 2013

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Net Benefit Costs

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									Other Postretirement Benefits
	2013			2012			2011			2013			2012			2011
Service Cost	$	4,487		$	3,718		$	3,048		$	771		$	704		$	675
Interest Cost	7,886			8,008			7,828			2,221			2,443			2,621
Expected Return on Plan Assets	(9,435		)	(8,249		)	(7,415		)	(2,158		)	(1,910		)	(2,040		)
Amortization:
Prior Service Cost (Credits)	208			207			219			(195		)	(195		)	(254		)
Actuarial Loss	7,608			6,432			4,561			1,555			1,534			1,466
Net Periodic Benefit Cost	10,754			10,116			8,241			2,194			2,576			2,468
Capitalized Benefit Costs	(5,002		)	(4,684		)	(3,661		)	(1,172		)	(1,340		)	(1,222		)
Affiliate SERP Allocations	(1,389		)	(1,107		)	(845		)	—			—			—
Total Net Periodic Benefit Expense	$	4,363		$	4,325		$	3,735		$	1,022		$	1,236		$	1,246

Schedule Defined Benefit Plans, Changes in Regulatory Assets and Accumulated Other Comprehensive Income (Loss)

Details of the activity within the Regulatory Asset and Accumulated Other Comprehensive Loss associated with Pension and Other Postretirement Benefits are as follows (in thousands):

	Regulatory Assets						Accumulated Other Comprehensive Loss (pre-tax)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Balance at January 1, 2012	$	61,811		$	26,435		$	19,061		$	—
Amounts Arising during the Period:
Net Actuarial Loss	11,599			2,089			4,788			—
Amounts Amortized to Net Periodic Costs:
Net Actuarial Loss	(4,490		)	(1,535		)	(1,941		)	—
Prior Service (Cost) Credit	(207		)	195			—			—
Balance at December 31, 2012	68,713			27,184			21,908			—
Amounts Arising during the Period:
Net Actuarial Gain	(20,554		)	(9,171		)	(1,576		)	—
Amounts Amortized to Net Periodic Costs:
Net Actuarial Loss	(5,319		)	(1,555		)	(2,289		)	—
Prior Service (Cost) Credit	(208		)	194			—			—
Balance at December 31, 2013	$	42,632		$	16,652		$	18,043		$	—

Schedule of Amounts in Regulatory Assets to be Recognized over Next Fiscal Year

The estimated costs that will be amortized from Regulatory Assets into net periodic benefit costs in 2014 are as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits
Prior Service Costs	$	158	$	133
Net Actuarial Loss	$	2,856	$	790

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year

The estimated costs that will be amortized from Accumulated Other Comprehensive Loss into net periodic benefit costs in 2014 are as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits
Net Actuarial Loss	$	2,007	$	—

Schedule of Net Funded Status and Amounts Recognized in Balance Sheet

A reconciliation of the plans’ benefit obligations, fair value of plan assets, funded status and amounts recognized in our balance sheets follows (in thousands):

							Other
	Pension Benefits						Postretirement Benefits
	2013			2012			2013			2012
Change in Benefit Obligations:
Benefit Obligation at Beginning of Year	$	186,899		$	160,319		$	55,615		$	51,656
Service Cost	4,487			3,718			771			704
Interest Cost	7,886			8,008			2,221			2,443
Actuarial (Gain) Loss	(11,514		)	21,990			(4,552		)	4,059
Retiree Contributions	—			—			335			313
Plan Amendments	—			—			—			—
Benefits Paid	(7,090		)	(7,136		)	(3,475		)	(3,560		)
Benefit Obligation at End of Year	$	180,668		$	186,899		$	50,915		$	55,615
Change in Plan Assets:
Fair Value of Plan Assets at Beginning of Year	$	119,391		$	91,738		$	32,694		$	28,942
Actual Return on Plan Assets	20,049			13,853			5,101			3,880
Employer Contributions	10,324			20,936			4,816			3,119
Retiree Contributions	—			—			335			313
Benefits Paid	(7,090		)	(7,136		)	(3,475		)	(3,560		)
Fair Value of Plan Assets at End of Year	$	142,674		$	119,391		$	39,471		$	32,694

Funded Status at End of Year:
Accrued  Net Benefit Cost at End of Year	$	(37,994	)	$	(67,508	)	$	(11,444	)	$	(22,921	)
Amounts Recognized in the Statement of Financial Position Consist of:
Current Liabilities	$	(1,241	)	$	(1,236	)	$	—		$	—
Noncurrent Liabilities	(36,753		)	(66,272		)	(11,444		)	(22,921		)
Net Amount Recognized at End of Year	$	(37,994	)	$	(67,508	)	$	(11,444	)	$	(22,921	)
Amounts Recognized in Regulatory Assets Consist of:
Prior Service Costs	$	634		$	842		$	952		$	758
Net Actuarial Loss	41,998			67,871			15,700			26,426
Net Amount Recognized at End of Year	$	42,632		$	68,713		$	16,652		$	27,184
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Net Actuarial Loss	$	18,043		$	21,908		$	—		$	—

Schedule of Assumptions Used

The weighted-average assumptions used to determine benefit obligations at December 31 were:

	Pension Benefits				Other Postretirement Benefits
	2013		2012		2013		2012
Discount Rate	5.09	%	4.26	%	4.91	%	4.14	%
Rate of Compensation Increase	3.50	%	3.25	%	3.50	%	3.25	%

The weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 were:

	Pension Benefits						Other Postretirement Benefits
	2013		2012		2011		2013		2012		2011
Discount Rate	4.26	%	5.03	%	5.78	%	4.14	%	4.92	%	5.55	%
Expected Long-Term Return on Plan Assets	7.50	%	7.50	%	8.00	%	6.60	%	6.60	%	7.00	%
Rate of Compensation Increase	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%

Schedule of Health Care Cost Trend Rates

The assumed health care cost trend rates at December 31 were:

	2013		2012
Medical Care and Drug Cost Trend Rate Assumed for Next Year	7.00	%	7.00	%
Dental Care Cost Trend Rate Assumed for Next Year	4.75	%	4.75	%
Rate to which Cost Trend Rates are Assumed to Decline (the Ultimate Trend Rate)	4.75	%	4.75	%
Year that the Rate Reaches the Ultimate Trend Rate	2023		2019

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

A one-percentage-point change in assumed health care cost trend rates would have the following effects (in thousands):

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on the Total of Service and Interest Cost	$	145	$	(115	)
Effect on Postretirement Benefit Obligation	$	2,406	$	(2,027	)

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets

Fair Value Measurement Using Significant

Unobservable Inputs (Level 3)

(In thousands)

	Guaranteed Insurance Contract			Hedge Funds		Private Equity Funds			Real Estate		Total
Balance at January 1, 2012	$	9,647		$	—	$	2,525		$	4,291	$	16,463
Actual return on plan assets:
Relating to assets still held at the reporting date	1,082			—		(122		)	487		1,447
Relating to assets sold during the period	(10		)	—		480			—		470
Purchases, Sales and Settlements	(821		)	—		(326		)	—		(1,147		)
Balance at December 31, 2012	$	9,898		$	—	$	2,557		$	4,778	$	17,233
Actual return on plan assets:
Relating to assets still held at the reporting date	(68		)	124		80			623		759
Relating to assets sold during the period	14			—		345			—		359
Purchases, Sales and Settlements	(773		)	3,204		(542		)	—		1,889
Balance at December 31, 2013	$	9,071		$	3,328	$	2,440		$	5,401	$	20,240

Schedule of Expected Benefit Payments

Future Benefit Payments - The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid during the following years (in thousands):

	Pension Benefits		Other Postretirement Benefits
2014	$	7,770	$	3,725
2015	$	8,303	$	3,825
2016	$	8,646	$	3,906
2017	$	9,021	$	3,955
2018	$	10,316	$	3,997
2019 - 2023	$	61,659	$	21,093

Pension Benefits [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Allocation of Plan Assets

The fair values of SJG’s pension plan assets at December 31, 2013 and 2012 by asset category are as follows (in thousands):

Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2013:
Cash / Cash Equivalents:
Common/Collective Trust Funds (a)	$	334	$	—	$	334	$	—
STIF-Type Instrument (b)	943		—		943		—
Equity securities:
Common/Collective Trust Funds – U.S. (a)	41,527		—		41,527		—
Common/Collective Trust Funds – International (a)	27,312		—		27,312		—
U.S. Large-Cap (c)	9,342		9,342		—		—
U.S. Mid-Cap (c)	3,313		3,313		—		—
International (c)	2,935		2,935		—		—
Fixed Income:
Common/Collective Trust Funds (a)	36,728		—		36,728		—
Guaranteed Insurance Contract (d)	9,071		—		—		9,071
Hedge Funds (e)	3,328		—		—		3,328
Other types of investments:
Private Equity Fund (f)	2,440		—		—		2,440
Common/Collective Trust Fund – Real Estate (g)	5,401		—		—		5,401
Total	$	142,674	$	15,590	$	106,844	$	20,240

Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2012:
Cash / Cash Equivalents:
Common/Collective Trust Funds (a)	$	477	$	—	$	477	$	—
STIF-Type Instrument (b)	840		—		840		—
Equity securities:
Common/Collective Trust Funds – U.S. (a)	33,690		—		33,690		—
Common/Collective Trust Funds – International (a)	23,448		—		23,448		—
U.S. Large-Cap (c)	7,126		7,126		—		—
U.S. Mid-Cap (c)	4,194		4,194		—		—
U.S. Small-Cap (c)	8		8		—		—
International (c)	1,462		1,462		—		—
Fixed Income:
Common/Collective Trust Funds (a)	30,913		—		30,913		—
Guaranteed Insurance Contract (d)	9,898		—		—		9,898
Other types of investments:
Private Equity Fund (f)	2,557		—		—		2,557
Common/Collective Trust Fund – Real Estate (g)	4,778		—		—		4,778
Total	$	119,391	$	12,790	$	89,368	$	17,233

(a) This category represents common/collective trust fund investments through a commingled employee benefit trust (excluding real estate).  These commingled funds are not traded publicly; however, the majority of the underlying assets held in these funds are stocks and bonds that are traded on active markets and prices for these assets are readily observable.  Also included in these funds are interest rate swaps, asset backed securities, mortgage backed securities and other investments with observable market values. Holdings in these commingled funds are classified as Level 2 investments.

(b) This category represents short-term investment funds held for the purpose of funding disbursement payment arrangements.  Underlying assets are valued based on quoted prices in active markets, or where quoted prices are not available, based on models using observable market information.  Since not all values can be obtained from quoted prices in active markets, these funds are classified as Level 2 investments.

(c) This category of equity investments represents a managed portfolio of common stock investments in five sectors: telecommunications, electric utilities, gas utilities, water and energy.  These common stocks are actively traded on exchanges and price quotes for these shares are readily available.  These common stocks are classified as Level 1 investments.

(d) This category represents SJI’s Group Annuity contracts with a nationally recognized life insurance company.  The contracts are the assets of the plan, while the underlying assets of the contracts are owned by the contract holder.  Valuation is based on a formula and calculation specified within the contract.  Since the valuation is based on the reporting entity’s own assumptions, these contracts are classified as Level 3 investments.

(e) This category represents a collection of underlying funds which are all domiciled outside of the United States. All of the underlying fund managers are based in the U.S.; however, they do not necessarily trade only in the U.S. markets. The fair value of these funds is determined by the underlying fund's general partner or manager. These funds are classified as Level 3 investments.

(f) This category represents a limited partnership which includes several investments in U.S. leveraged buyout, venture capital, and special situation funds.  Fund valuations are reported on a 90 day lag and, therefore, the value reported herein represents the market value as of September 30, 2013 and 2012, respectively.  The fund’s investments are stated at fair value, which is generally based on the valuations provided by the general partners or managers of such investments.  Fund investments are illiquid and resale is restricted.  These funds are classified as Level 3 investments.

(g) This category represents real estate common/collective trust fund investments through a commingled employee benefit trust. These commingled funds are part of a direct investment in a pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, the real estate funds are classified as Level 2 investments.

Other Postretirement Benefits [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Allocation of Plan Assets

The fair values of SJG’s other postretirement benefit plan assets at December 31, 2013 and 2012 by asset category are as follows (in thousands):

Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2013:
Equity Securities:
Common/Collective Trust Funds - U.S. (a)	$	12,412	$	—	$	12,412	$	—
Common/Collective Trust Funds - International (a)	10,031		—		10,031		—
Mutual Fund - U.S. Large-Cap (b)	2,814		2,814		—		—
Fixed Income:
Common/Collective Trust (a)	14,214		—		14,214		—
Total	$	39,471	$	2,814	$	36,657	$	—
Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2012:
Equity Securities:
Common/Collective Trust Funds - U.S. (a)	$	9,972	$	—	$	9,972	$	—
Common/Collective Trust Funds - International (a)	8,475		—		8,475		—
Mutual Fund - U.S. Large-Cap (b)	2,326		2,326		—		—
Fixed Income:
Common/Collective Trust (a)	11,921		—		11,921		—
Total	$	32,694	$	2,326	$	30,368	$	—

(a) This category represents common/collective trust fund investments through a commingled employee benefit trust (excluding real estate).  These commingled funds are not traded publicly; however, the majority of the underlying assets held in these funds are stocks and bonds that are traded on active markets and prices for these assets are readily observable.  Also included in these funds are interest rate swaps, asset backed securities, mortgage backed securities and other investments with observable market values. Holdings in these commingled funds are classified as Level 2 investments.

(b) This category represents mutual fund investments. The mutual funds are actively traded on exchanges and price quotes for the shares are readily available. These mutual funds are classified as Level 1 investments.

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DERIVATIVE INSTRUMENTS (Details) (USD $)	1 Months Ended
	Sep. 30, 2005	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Unrealized gain (losses) included in its BGSS related to open financial contracts		$ 700,000	$ (1,900,000)
Initial cost of Treasury Locks	1,400,000
Amortization period of Treasury Locks	30 years
Unamortized balance of Treasury Locks		1,000,000	1,100,000
South Jersey Gas Company [Member] | Interest Rate Swap, $12,500,000 Contract 1 [Member]
Derivative [Line Items]
Derivative, Notional Amount		12,500,000,000
Derivative, Fixed Interest Rate		3.43%
South Jersey Gas Company [Member] | Interest Rate Swap, $12,500,000 Contract 2 [Member]
Derivative [Line Items]
Derivative, Notional Amount		$ 12,500,000,000
Derivative, Fixed Interest Rate		3.43%
Natural Gas (in MMdts) [Member] | Derivative Transaction Type, Purchase [Member]
Derivative [Line Items]
Outstanding derivative contracts notional amount		6.6

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DERIVATIVE INSTRUMENTS

12 Months Ended

Dec. 31, 2013

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 its affiliate South Jersey Resources Group (SJRG) and another 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 December 31, 2013, SJG had outstanding derivative contracts intended to limit the exposure to market risk on 6.6 MMdts of expected future purchases of natural gas.. 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 balance sheets. The costs or benefits of these short-term contracts are recoverable through SJG’s Basic Gas Supply Service (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 balance sheets. As of December 31, 2013 and December 31, 2012, SJG had $0.7 million of unrealized gains and $1.9 million of unrealized losses, respectively, included in its BGSS related to open financial contracts.

The Company has also entered into interest rate derivatives to manage 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 balance sheets. The fair value represents the amount SJG would have to pay the counterparty to terminate these contracts as of those dates. 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 balance sheets.

We previously used derivative transactions known as “Treasury Locks” to mitigate 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 December 31, 2013 and December 31, 2012, the unamortized balance was approximately $1.0 million and $1.1 million, respectively.

As of December 31, 2013, SJG’s active interest rate swaps were as follows:

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

The fair values of all derivative instruments, as reflected in the balance sheets as of December 31, 2013 and December 31, 2012, are as follows (in thousands):

Derivatives not designated as hedging instruments under GAAP	2013				2012
	Assets		Liabilities		Assets		Liabilities
Energy related commodity contracts:
Derivatives – Energy Related – Current	$	1,222	$	711	$	464	$	2,615
Derivatives – Energy Related – Non-Current	278		48		302		80
Interest rate contracts:
Derivatives – Other	—		3,735		—		7,761
Total derivatives not designated as hedging instruments under GAAP	$	1,500	$	4,494	$	766	$	10,456

For derivative instruments disclosed in the table above, information as to the presentation on the condensed balance sheets is as follows (in thousands):

As of December 31, 2013
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	$	1,500		$	—	$	1,500		$	(155	)	(A)	$	(498	)	$	847
Derivatives - Energy Related Liabilities	(759		)	—		(759		)	155			(B)	—			(604		)
Derivatives - Other	(3,735		)	—		(3,735		)	—				—			(3,735		)

As of December 31, 2012
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	$	766		$	—	$	766		$	(447	)	(A)	$	—	$	319
Derivatives - Energy Related Liabilities	(2,695		)	—		(2,695		)	447			(B)	1,136		(1,112		)
Derivatives - Other	(7,761		)	—		(7,761		)	—				—		(7,761		)

(A) The balances at December 31, 2013 and December 31, 2012 were related to derivative liabilities which can be net settled against derivative assets.

(B) The balances at December 31, 2013 and December 31, 2012 were related to derivative assets which can be net settled against derivative liabilities.

The effect of derivative instruments on the statements of income for 2013 , 2012 and 2011 are as follows (in thousands):

	Year ended December 31,
Derivatives in Cash Flow Hedging Relationships	2013			2012			2011
Interest Rate Contracts:
Losses reclassified from accumulated OCI into income (a)	$	(46	)	$	(46	)	$	(46	)

(a) Included in Interest Charges

Net realized losses associated with SJG’s energy-related financial commodity contracts of $0.4 million , $15.4 million and $12.9 million for 2013, 2012 and 2011, 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 and there is no impact to earnings.

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Schedule of Environmental Loss Contingencies

The following table details the amounts accrued and expended for environmental remediation at December 31 (in thousands):

	2013			2012
Beginning of Year	$	107,410		$	89,984
Accruals	22,264			26,552
Expenditures	(10,182		)	(9,126		)
End of Year	$	119,492		$	107,410

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QUARTERLY RESULTS OF OPERATIONS - UNAUDITED

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

QUARTERLY RESULTS OF OPERATIONS - UNAUDITED

QUARTERLY RESULTS OF OPERATIONS - UNAUDITED:

The summarized quarterly results of our operations are as follows (in thousands):  

	2013 Quarter Ended								2012 Quarter Ended
	March 31		June 30		Sept. 30		Dec. 31		March 31		June 30		Sept. 30		Dec. 31
Operating Revenues	$	174,098	$	66,536	$	59,674	$	146,172	$	179,436	$	59,177	$	54,251	$	129,010
Expenses:
Cost of Sales (excluding depreciation)	77,602		26,108		24,717		71,654		86,499		20,407		21,053		60,751
Operations and Maintenance
Including Fixed Charges	38,659		33,871		33,249		39,486		35,102		33,597		32,953		33,877
Income Taxes	20,771		2,269		471		11,322		20,977		1,887		258		10,589
Energy and Other Taxes	3,003		1,277		1,052		2,530		3,169		1,479		1,167		2,485
Total Expenses	140,035		63,525		59,489		124,992		145,747		57,370		55,431		107,702
Other Income and Expense	1,450		810		764		773		1,349		1,430		1,703		(1,865		)
Net Income	$	35,513	$	3,821	$	949	$	21,953	$	35,038	$	3,237	$	523	$	19,443

NOTE: Because of the seasonal nature of our business, statements for the 3-month periods are not indicative of the results for a full year.

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DERIVATIVE INSTRUMENTS 4 (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Losses reclassified from accumulated OCI into income	$ (46,000)	[1]	$ (46,000)	[1]	$ (46,000)	[1]
Realized gains losses, derivative instruments on energy-related contracts	$ 400,000		$ 15,400,000		$ 12,900,000

[1] Included in Interest Charges

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STATEMENTS OF CHANGES IN COMMON EQUITY AND COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified		Total	Common Stock [Member]	Other Paid-In Capital and Premium on Common Stock [Member]	Accumulated Other Comprehensive Loss [Member]	Retained Earnings [Member]
Balance at Dec. 31, 2010		$ 426,885	$ 5,848	$ 200,841	$ (9,120)	$ 229,316
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		52,889				52,889
Other Comprehensive (Loss) Income, Net of Tax	[1]	(3,009)			(3,009)
Cash Dividends Declared – Common Stock		(12,664)				(12,664)
Additional Investment by Shareholder		0		0
Excess Tax Benefit from Restricted Stock Plan		85		85
Balance at Dec. 31, 2011		464,186	5,848	200,926	(12,129)	269,541
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		58,241				58,241
Other Comprehensive (Loss) Income, Net of Tax	[1]	(1,156)			(1,156)
Cash Dividends Declared – Common Stock		0				0
Additional Investment by Shareholder		0		0
Excess Tax Benefit from Restricted Stock Plan		124		124
Balance at Dec. 31, 2012		521,395	5,848	201,050	(13,285)	327,782
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		62,236				62,236
Other Comprehensive (Loss) Income, Net of Tax	[1]	2,416			2,416
Cash Dividends Declared – Common Stock		0				0
Additional Investment by Shareholder		25,000		25,000
Excess Tax Benefit from Restricted Stock Plan		(78)		(78)
Additional Statement Information [Abstract]
Combined statutory rate		41.00%
Balance at Dec. 31, 2013		$ 610,969	$ 5,848	$ 225,972	$ (10,869)	$ 390,018

[1] Determined using a combined statutory tax rate of 41%.

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STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Statement of Other Comprehensive Income [Abstract]
Net Income	$ 62,236		$ 58,241		$ 52,889
Other Comprehensive Gain (Loss), Net of Tax:
Postretirement Liability Adjustment	2,286	[1]	(1,683)	[1]	(2,676)	[1]
Unrealized Gain (Loss) on Available-for-Sale Securities	103	[1]	500	[1]	(360)	[1]
Unrealized Gain on Derivatives - Other	27	[1]	27	[1]	27	[1]
Other Comprehensive Gain (Loss) - Net of Tax	2,416	[1]	(1,156)	[1]	(3,009)	[1]
Comprehensive Income	$ 64,652		$ 57,085		$ 49,880
Combined statutory rate	41.00%

[1] Determined using a combined statutory tax rate of 41%.

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LINES OF CREDIT

12 Months Ended

Dec. 31, 2013

Line of Credit Facility [Abstract]

LINES OF CREDIT

LINES OF CREDIT:

Credit facilities and available liquidity as of December 31, 2013 were as follows (in thousands):

	Total Facility		Usage		Available Liquidity		Expiration Date
Commercial Paper Program/ Revolving Credit Facility	$	200,000	$	65,500	$	134,500	May 2018
Uncommitted Bank Lines	10,000		—		10,000		August 2014
Total	$	210,000	$	65,500	$	144,500

SJG renewed the uncommitted bank line of credit during the third quarter 2013. Also, SJG amended and extended its revolving credit facility during the third quarter of 2013; as a result, the maturity date was extended from May 2015 to May 2018.

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 December 31, 2013.

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, not including letters of credit, during the twelve months ended December 31, 2013 and 2012 were $91.4 million and $142.4 million, respectively.  The maximum amount outstanding under these credit facilities, not including letters of credit, during the twelve months ended December 31, 2013 and 2012 were $121.9 million and $180.5 million, respectively.

Based upon the existing credit facilities and a regular dialogue with our banks, we believe that there will continue to be sufficient credit available to meet our business’ future liquidity needs. Borrowings under these credit facilities are at market rates.  The weighted average interest rate on these borrowings, which changes daily, was 0.37% , 0.48% and 0.62% at December 31, 2013 , 2012 and 2011, respectively.

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DOCUMENT AND ENTITY INFORMATION (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 15, 2014	Jun. 30, 2013
Entity [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-K
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		2,339,139
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0

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RETAINED EARNINGS

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

RETAINED EARNINGS

RETAINED EARNINGS:

Various loan agreements contain potential restrictions regarding the amount of cash dividends or other distributions that we may pay on our common stock. As of December 31, 2013, these loan restrictions did not affect the amount that may be distributed from our retained earnings.

SJG received a $25 million equity infusion from SJI in 2013. No equity infusions were received from SJI in 2012 or 2011.  Future equity contributions will occur on an as needed basis.

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STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income	$ 62,236	$ 58,241	$ 52,889
Provided by Operating Activities:
Depreciation and Amortization	48,261	44,171	41,959
Provision for Losses on Accounts Receivable	4,232	4,775	1,410
CIP Receivable	21,160	(18,106)	(1,289)
Deferred Gas Costs - Net of Recoveries	5,473	25,050	(37,343)
Deferred SBC Costs - Net of Recoveries	2,393	(4,183)	(4,402)
Environmental Remediation Costs - Net of Recoveries	(438)	(188)	(13,612)
Deferred and Noncurrent Income Taxes and Credits - Net	31,940	38,353	35,037
Gas Plant Cost of Removal	(6,092)	(2,133)	(1,590)
Pension Contribution	(9,100)	(19,757)	0
Changes in:
Accounts Receivable	(20,574)	(34,263)	37,428
Inventories	(7,153)	13,449	(6,285)
Prepaid and Accrued Taxes - Net	9,456	6,451	(7,831)
Other Prepayments and Current Assets	(476)	430	(1,420)
Gas Purchases Payable	9,306	(2,941)	(9,048)
Accounts Payable and Other Accrued Liabilities	(5,107)	(8,803)	21,079
Other Assets	(7,323)	(10,980)	(6,294)
Other Liabilities	10,565	3,807	9,789
Net Cash Provided by Operating Activities	148,759	93,373	110,477
Cash Flows from Investing Activities:
Capital Expenditures	(161,498)	(156,041)	(142,570)
Net Proceeds from Restricted Investments in Margin Account	588	930	2,103
Investment in Long-Term Receivables	(7,182)	(6,243)	(4,926)
Proceeds from Long-Term Receivables	5,764	8,182	6,312
Net Cash Used in Investing Activities	(162,328)	(153,172)	(139,081)
Cash Flows from Financing Activities:
Net (Repayments of) Borrowings from Lines of Credit	(36,600)	(24,500)	67,700
Proceeds from Issuance of Long-Term Debt	50,000	120,000	0
Principal Repayments of Long-Term Debt	(25,000)	(35,000)	(25,000)
Premium for Early Retirement of Debt	0	(700)	0
Payments for Issuance of Long-Term Debt	(411)	(951)	(43)
Dividends on Common Stock	0	0	(12,664)
Additional Investment by Shareholder	25,000	0	0
Excess Tax Benefit (Tax Deficiency) from Restricted Stock Plan	(78)	124	85
Net Cash Provided by Financing Activities	12,911	58,973	30,078
Net (Decrease) Increase in Cash and Cash Equivalents	(658)	(826)	1,474
Cash and Cash Equivalents at Beginning of Period	2,678	3,504	2,030
Cash and Cash Equivalents at End of Period	2,020	2,678	3,504
Supplemental Disclosures of Cash Flow Information
Interest (Net of Amounts Capitalized)	12,234	12,073	20,068
Income Taxes (Net of Refunds)	(5,056)	(2,797)	(1,044)
Supplemental Disclosures of Noncash Investing Activities
Property and equipment acquired on account but not paid at year-end	$ 20,055	$ 11,069	$ 12,171

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REGULATORY ASSETS AND LIABILITIES

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

REGULATORY ASSETS AND LIABILITIES

REGULATORY ASSETS AND LIABILITIES:

The discussion under Note 3, Rates and Regulatory Actions, is integral to the following explanations of specific regulatory assets and liabilities.

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

	2013		2012
Environmental Remediation Costs:
Expended - Net	$	29,945	$	37,892
Liability for Future Expenditures	119,492		107,410
Deferred Asset Retirement Obligation Costs	31,142		30,199
Deferred Pension and Other Postretirement Benefit Costs	59,284		95,897
Conservation Incentive Program Receivable	10,526		31,686
Societal Benefit Costs Receivable	10,408		12,801
Premium for Early Retirement of Debt	955		1,075
Deferred Interest Rate Contracts	3,735		7,761
Energy Efficiency Tracker	10,420		12,306
Pipeline Supplier Service Charges	7,106		8,771
Pipeline Integrity Cost	2,902		1,584
Other Regulatory Assets	10,166		5,274
Total Regulatory Assets	$	296,081	$	352,656

Except where noted below, all regulatory assets are or will be recovered through utility rate charges, as detailed in the following discussion. We are currently permitted to recover interest on our Environmental Remediation Costs, Societal Benefit Costs Receivable, Energy Efficiency Tracker and Pipeline Integrity Costs, while the other assets are being recovered without a return on investment.

Environmental Remediation Costs - We have two regulatory assets associated with environmental costs related to the cleanup of 12 sites where we or our predecessors previously operated gas manufacturing plants. The first asset, Environmental Remediation Cost: Expended - Net, represents what was actually spent to clean up the sites, less recoveries through the RAC and insurance carriers. These costs meet the deferral requirements of GAAP, as the BPU allows us to recover such expenditures through the RAC. The other asset, Environmental Remediation Cost: Liability for Future Expenditures, relates to estimated future expenditures required to complete the remediation of these sites. We recorded this estimated amount as a regulatory asset with the corresponding current and noncurrent liabilities on the balance sheets under the captions Current Liabilities and Regulatory and Other Noncurrent Liabilities. The BPU allows us to recover the deferred costs over seven-year periods after they are spent (See Notes 3 and 12).

Deferred Asset Retirement Obligation Costs - This regulatory asset  resulted from the recording of asset retirement obligations (ARO) and additional utility plant, primarily related to a legal obligation we have for certain safety requirements upon the retirement of our gas distribution and transmission system. We recover asset retirement costs through rates charged to customers. All related accumulated accretion and depreciation amounts for these ARO represent timing differences in the recognition of retirement costs that we are currently recovering in rates and, as such, we are deferring such differences as regulatory assets.

Deferred Pension and Other Postretirement Benefit Costs  - The BPU authorized us to recover costs related to postretirement benefits under the accrual method of accounting consistent with  GAAP.  We deferred amounts accrued prior to that authorization and amortized them as allowed by the BPU over 15 years through 2012. In 2006, our regulatory asset was increased by $37.1 million representing the recognition of the underfunded positions of our pension and other postretirement benefit plans.  Subsequent adjustments to this balance occur annually to reflect changes in the funded positions of these benefit plans caused by changes in actual plan experience as well as assumptions of future experience (See Note 11).

Conservation Incentive Program Receivable - The impact of the CIP is recorded as an adjustment to earnings as incurred, while cash recovery under the CIP generally occurs during the subsequent CIP year (see Note 3).

Societal Benefit Costs Receivable - This regulatory asset primarily represents cumulative costs less recoveries under the USF program (See Note 3). 

Premium for Early Retirement of Debt - At December 31, 2013, this regulatory asset represents unamortized debt issuance costs related to long-term debt refinancings. Unamortized debt issuance costs are being amortized over the term of the new debt issue pursuant to regulatory approval by the BPU.

Energy Efficiency Tracker - This regulatory asset represents cumulative investments less recoveries under the Energy Efficiency Program (See Note 3).

Deferred Interest Rate Contracts - These amounts represent the market value of interest rate derivatives as discussed further in Note 13.

Pipeline Supplier Service Charges - This regulatory asset represents costs necessary to maintain adequate supply and system pressures, which are being recovered on a monthly basis through the BGSS over the term of the underlying supplier contracts (See Note 3).

Pipeline Integrity Cost - As part of our September 2010 base rate increase, we were permitted to recover previously deferred pipeline integrity costs incurred through September 2010. In addition, we are authorized to defer future program costs, including related carrying costs, for recovery in our next base rate proceeding, subject to review by the BPU (see Note 3).

Other Regulatory Assets - Some of the assets included in Other Regulatory Assets are currently being recovered from ratepayers as approved by the BPU. Management believes the remaining deferred costs are probable of recovery from ratepayers through future utility rates.

Regulatory Liabilities at December 31 consisted of the following items (in thousands):

	2013		2012
Excess Plant Removal Costs	$	40,029	$	45,593
Deferred Revenue - Net	19,067		10,924
Other Regulatory Liabilities	1,853		—
Total Regulatory Liabilities	$	60,949	$	56,517

Excess Plant Removal Costs – Represents amounts accrued in excess of actual utility plant removal costs incurred to date.  As part of our September 2010 base rate increase, we are required to amortize approximately $1.2 million of this balance to depreciation expense each year.

Deferred Revenues – Net - Over/under collections of gas costs are monitored through our BGSS mechanism. Net undercollected gas costs are classified as a regulatory asset and net overcollected gas costs are classified as a regulatory liability (See Note 3). Derivative contracts used to hedge our natural gas purchases are also included in the BGSS, subject to BPU approval (See Note 14). The increase from a $10.9 million regulatory liability at December 31, 2012 to a $19.1 million regulatory liability at December 31, 2013 was due to gas costs recovered from customers exceeding the actual cost of the commodity incurred during 2013.

Other Regulatory Liabilities – All other regulatory liabilities are subject to being returned to ratepayers in future rate proceedings.

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RATES AND REGULATORY ACTIONS

12 Months Ended

Dec. 31, 2013

Public Utilities, General Disclosures [Abstract]

RATES AND REGULATORY ACTIONS

RATES AND REGULATORY ACTIONS:

Base Rates - SJG is subject to the rules and regulations of the BPU.  In September 2010, the BPU granted SJG a base rate increase of $42.1 million, which was predicated, in part, upon an 8.21% rate of return on rate base that included a 10.3% return on common equity.  The $42.1 million includes $16.6 million of revenue previously recovered through the Conservation Incentive Program (CIP) and $6.8 million of revenues previously recovered through the Capital Investment Recovery Tracker (CIRT), resulting in incremental revenue of $18.7 million.  SJG was permitted to recover regulatory assets contained in its petition and defer certain federally mandated pipeline integrity management program costs for recovery in its next base rate case.  In addition, annual depreciation expense will be reduced by $1.2 million as a result of the amortization of excess cost of removal recoveries.  The BPU also authorized a Phase II of the base rate proceeding to review the costs of CIRT projects not rolled into rate base in the September 2010 settlement. A proceeding took place in 2013 to roll into base rates the remaining $22.5 million of CIRT I project costs that were not included in the 2010 rate increase, as well as CIRT II and III investments totaling $95.0 million that were made subsequent to the 2010 base rate case. These costs were rolled into rate base and reflected in base rates effective October 2013.

In November 2013, we filed a base rate case with the BPU to increase our base rates to obtain a certain level of return on our capital investments. We expect the base rate case to be concluded during 2014. Other than the CIRT items discussed above, we have not sought a base rate increase from the BPU since the implementation of our base rate case approved in September 2010.

Rate Mechanisms - Our tariff, a schedule detailing the terms, conditions and rate information applicable to our various types of natural gas service, as approved by the BPU, has several primary rate mechanisms as discussed in detail below:

Basic Gas Supply Service (BGSS) Clause - The BGSS price structure was approved by the BPU in January 2003, and allows us to recover all prudently incurred gas costs. BGSS charges to customers can be either monthly or periodic (annual). Monthly BGSS charges are applicable to large use customers and are referred to as monthly because the rate changes on a monthly basis pursuant to a BPU-approved formula based on commodity market prices. Periodic BGSS charges are applicable to lower usage customers, which include all of our residential customers, and are evaluated at least annually by the BPU. However, to some extent, more frequent rate changes to the periodic BGSS are allowed. We collect gas costs from customers on a forecasted basis and defer periodic over/under recoveries to the following BGSS year, which runs from October 1 through September 30. If we are in a net cumulative undercollected position, gas costs deferrals are reflected on the balance sheet as a regulatory asset. If we are in a net

cumulative overcollected position, amounts due back to customers are reflected on the balance sheet as a regulatory liability. We pay interest on net overcollected BGSS balances at the rate of return on rate base utilized by the BPU to set rates in our last base rate proceeding.

Regulatory actions regarding the BGSS were as follows:

• March 2011 - We credited the accounts of our periodic BGSS customers with refunds totaling $21.1 million due to gas costs that were lower than projected during the winter season.

• June 2011 - We filed our annual BGSS filing with the BPU requesting a $10.6 million, or 2.9%, reduction in gas cost recoveries commencing on October 1, 2011.

• September 2011 - The BPU issued an Order finalizing the 2010-2011 provisional BGSS rate and approved, on a provisional basis, SJG's request for a $10.6 million, or 2.9%, reduction in gas cost recoveries.

• December 2011 - We credited the accounts of our periodic BGSS customers with refunds totaling $18.7 million due to gas costs that were lower than projections.

• May 2012 - The BPU issued an Order finalizing the 2011-2012 provisional BGSS rates.

• June 2012 - We filed our annual BGSS filing with the BPU requesting a $27.0 million, or 8.8%, reduction in gas cost recoveries commencing on October 1, 2012.

• September 2012 - The BPU issued an Order approving, on a provisional basis, SJG's request for a $27.0 million, or 8.8%, reduction in gas cost recoveries.

• January 2013 - We credited the accounts of our periodic BGSS customers with refunds totaling $9.4 million due to gas costs that were lower than projections.

• May 2013 - We filed our annual BGSS filing with the BPU requesting a $0.6 million reduction in gas cost recoveries.

• September 2013 - The BPU issued an Order approving, on a provisional basis, SJG’s request for a $0.6 million reduction in gas cost recoveries.

• January 2014 - We credited the accounts of our periodic BGSS customer with refunds totaling $11.2 million due to gas costs that were lower than projected.

Conservation Incentive Program (CIP) - The primary purpose of the CIP is to promote conservation efforts, without negatively impacting financial stability, and to base our profit margin on the number of customers rather than the amount of natural gas distributed to customers. In October 2006, the BPU approved the CIP as a three-year pilot program. In January 2010, the BPU approved an extension of this program through September 2013, with an automatic one year extension through September 2014 if a request for an extension was filed by March 2013. A petition was filed in March 2013 to extend the CIP program. Each CIP year begins October 1 and ends September 30 of the subsequent year. On a monthly basis during the CIP year, we record adjustments to earnings based on weather and customer usage factors, as incurred. Subsequent to each year, we make filings with the BPU to review and approve amounts recorded under the CIP. BPU approved cash inflows or outflows generally will not begin until the next CIP year.

Regulatory actions regarding the CIP were as follows:

• June 2011 - We made our annual CIP filing with the BPU requesting recovery of $2.5 million, which includes a $2.7 million credit to customers for the current 2011-2012 CIP year and prior year carryovers of $5.2 million. The CIP credit of $2.7 million includes $1.3 million non-weather related credits and $1.4 million weather related credits.

• September 2011 - The BPU issued an Order finalizing the 2010-2011 provisional CIP rates and also approved, on a provisional basis, the 2011-2012 CIP rates filed in June 2011, effective October 1, 2011.

• May 2012 - The BPU issued an Order finalizing the 2011-2012 provisional CIP rates.

• June 2012 - We made our annual CIP filing with the BPU requesting recovery of $28.0 million, which includes a $8.4 million non-weather related recovery and a $19.6 million weather related recovery.

• September 2012 - The BPU issued an Order approving, on a provisional basis, the 2012-2013 CIP rates filed in June 2012, effective October 1, 2012.

• March 2013 - We filed a joint petition with another utility requesting modification to, and the continuation of, the CIP program effective October 1, 2013.

• May 2013 - We made our annual CIP filing with the BPU requesting a reduction in revenue of $17.8 million, which includes a $2.3 million reduction in non-weather related recovery and a $15.5 million reduction in weather related recovery.

• September 2013 - The BPU issued an Order approving, on a provisional basis, the 2013-2014 CIP rates filed in May 2013, effective October 1, 2013.

Capital Investment Recovery Tracker (CIRT) - In January 2009, we made a filing with the BPU requesting approval for an accelerated infrastructure investment program.  The purpose of the CIRT was to accelerate $103.0 million of capital expenditures from five years to two years.  The petition requested that we be allowed to earn a return of, and a return on, our investment.  Under the CIRT, 2009 spending was projected to be $70.5 million and 2010 spending was projected to be $32.5 million.  In September 2010, the BPU authorized $81.3 million of CIRT-related expenditures to be rolled into rate base and also authorized that the remaining balance of CIRT-related expenditures continue to be recovered.  These remaining expenditures were reviewed and rolled into rate base during Phase II of the base rate case. On a monthly basis during the CIRT year, we recorded adjustments to earnings based on actual CIRT program expenditures, as incurred.  Annually we made filings with the BPU for review and approval of expenditures recorded under the CIRT.

Regulatory actions regarding the CIRT were as follows:

• March 2011 - The BPU approved a CIRT II program allowing the Company to accelerate an additional $60.3 million of capital spending into 2011 and 2012. Under CIRT II, the Company continues to earn a return on investment as the capital is spent, as it did under the original CIRT. The return of investment begins when the investments are rolled into rate base. As such, the Company is permitted to earn a return on CIRT II investments until the roll in is approved and recovery commences.

• June 2011 - The Company filed a petition with the BPU requesting the recovery of a portion of CIRT II investments via a roll-in to rate base, and requested to increase the base rates by 0.5%.

• October 2011 - The Company filed a petition with the BPU requesting to modify and extend the CIRT II program. The petition requested an additional incremental investment of $40.0 million in 2012 and $50.0 million in 2013.

• May 2012 - The BPU approved a modification and extension of the CIRT II program (CIRT III), allowing the Company to accelerate an incremental $35.0 million of capital spending through December 2012.

• October 2012 - The Company filed a petition requesting a $13.2 million increase in annual revenues by rolling $110.6 million of CIRT I, II and III investments into base rates.

• September 2013 - The BPU approved the base rate roll in of the CIRT I, II and III program investments effective October 2013, resulting in a $15.5 million increase in annual revenue. This approval also concluded Phase II of the 2010 base rate case.

All CIRT program investments have been rolled into rate base and the CIRT program is now concluded.

Accelerated Infrastructure Replacement Program (AIRP) - In July 2012, the company filed a petition to implement a five-year, $250.0 million Accelerated Infrastructure Replacement Program to replace the annual CIRT programs. In February 2013, the BPU issued a Board Order approving a $141.2 million program to replace cast iron and unprotected bare steel mains and services over a four year period, with annual investments of approximately $35.3 million. Pursuant to the Board Order, AIRP investments are to be reviewed and included in rate base in future base rate proceedings.

Storm Hardening and Reliability Program (SHARP) - In September 2013, we filed with the BPU an asset hardening program pursuant to which SJG will invest approximately $280.0 million over seven years to replace low pressure distribution mains and services with high pressure mains and services in coastal areas that are susceptible to flooding during major storm events. This petition is currently pending.

Energy Efficiency Tracker (EET) - In January 2009, we filed a petition with the BPU requesting approval of an Energy Efficiency Program (EEP I) for residential, commercial and industrial customers.  The BPU approved this petition in July 2009. Under this program we were permitted to invest $17.0 million over two years in energy efficiency measures to be installed in customer homes and businesses. We also recover incremental operating and maintenance expenses and earn a return of, and return on, program investments.

Regulatory actions regarding the EET were as follows:

• November 2010 - We filed a petition with the BPU requesting a one year extension of the program and a reallocation of investment dollars between the EET programs to fund the more popular programs. In January 2011, SJG’s request to reallocate investment dollars between the programs and a one year extension was approved by the BPU.

• June 2011 - We filed our annual 2011-2012 petition requesting approval of a $4.7 million increase in EET recovery. This petition was approved in September 2012, with rates effective October 1, 2012.

• October 2011 - We filed a petition requesting a modification of the EET with regards to the Combined Heat and Power (CHP) program. The BPU approved this petition in February 2012.

• May 2012 - We filed a petition requesting the approval of a new Energy Efficiency Program (“EEP II”) and to continue our existing EET to recover all costs associated with the EEP II through a $3.1 million increase in annual revenues. These programs provide customers with increased incentives to reduce their natural gas consumption. In June 2013, the BPU approved the EEP II program in the form of an extension of the existing EEP program, permitting SJG to invest $24.0 million in energy efficiency programs through June 2015. The BPU also approved in June 2013 an extension of the EET with a $2.1 million revenue increase effective July 2013.

• June 2012 - We filed a petition requesting a continuation of the original Energy Efficiency Program (“EEP I”) to bridge the gap between the expiration of the EEP I program on April 30, 2012, and the implementation of the proposed new EEP II program. This petition was approved by the BPU in August 2012. Also in June 2012, SJG filed its 2012 - 2013 annual EET rate adjustment petition requesting a $5.8 million increase in annual revenues to recover the costs associated with its EEP I program. This petition is still pending.

• May 2013 - we filed our annual petition requesting an increase of $2.2 million for current EET programs. This petition is still pending.

Societal Benefits Clause (SBC) - The SBC allows us to recover costs related to several BPU-mandated programs. Within the SBC are a Remediation Adjustment Clause (RAC), a New Jersey Clean Energy Program (NJCEP), a Universal Service Fund (USF) program and a Consumer Education Program (CEP).

Regulatory actions regarding the SBC, with the exception of USF which requires separate regulatory filings, were as follows:

• July 2011 - We made our annual 2011-2012 SBC filing requesting a $31.2 million increase in SBC recoveries. The BPU approved this filing in July 2013.

• September 2011 - The BPU finalized rates for the 2008-2009 and 2009-2010 SBC petitions.

• July 2012 - We made our annual 2012-2013 SBC filing requesting an $11.8 million increase in SBC recoveries. The BPU approved this filing in July 2013.

• September 2012 - The BPU finalized rates for the 2010-2011 SBC petition effective October 1, 2012.

• July 2013 - We made our annual 2013-2014 SBC filing requesting a $6.4 million decrease in SBC revenues. This petition is still pending.

Remediation Adjustment Clause (RAC) - The RAC recovers environmental remediation costs of 12 former gas manufacturing plants (See Note 12). The BPU allows us to recover such costs over seven-year amortization periods. The net between the amounts actually spent and amounts recovered from customers is recorded as a regulatory asset, Environmental Remediation Cost Expended - Net. Note that RAC activity affects revenue and cash flows but does not directly affect earnings because of the cost recovery over seven-year amortization periods. As of December 31, 2013 and 2012, we reflected the unamortized remediation costs of $29.9 million and $37.9 million, respectively, on the balance sheet under Regulatory Assets (See Note 4). Since implementing the RAC in 1992, we have recovered $92.6 million through rates.

New Jersey Clean Energy Program (NJCEP) - This mechanism recovers costs associated with our energy efficiency and renewable energy programs. In August 2008, the BPU approved the statewide funding of the NJCEP of $1.2 billion for the years 2009 through 2012. Of this amount, SJG was responsible for expensing approximately $41.5 million over the four-year period. In November 2012, the BPU approved a six-month extension of the program through June 2013. Under this extension, SJG is responsible for $7.5 million of funding. NJCEP adjustments affect revenue and cash flows but do not directly affect earnings as related costs are deferred and recovered through rates on an on-going basis.

Universal Service Fund (USF) - The USF is a statewide program through which funds for the USF and Lifeline Credit and Tenants Assistance Programs are collected from customers of all New Jersey electric and gas utilities. USF adjustments affect cash flows but do not directly affect revenue or earnings as related costs are deferred and recovered through rates on an ongoing basis.

Separate regulatory actions regarding the USF were as follows:

• June 2011 - We made our annual USF filing, along with the state's other electric and gas utilities, proposing to decrease annual statewide gas revenues by $9.3 million. This proposal was designed to decrease our annual USF revenue by $0.8 million.

• October 2011 - The BPU approved the statewide budget of $57.4 million for all of the State's gas utilities. Our portion of the total is approximately $5.4 million, which decreased rates effective November 1, 2011, resulting in a $0.5 million decrease to our annual USF recoveries.

• June 2012 - We made our annual USF filing, along with the state's other electric and gas utilities, proposing to decrease annual statewide gas revenues by $0.5 million. This proposal was designed to decrease our annual USF revenue by $0.1 million.

• September 2012 - The BPU approved the statewide budget of $78.0 million for all of the State's gas utilities. Our portion of the total is approximately $8.2 million, which decreased rates effective October 1, 2012, resulting in a $0.1 million decrease to our annual USF recoveries.

• June 2013 - We made our annual USF filing, along with the state’s other electric and gas utilities, proposing to decrease the statewide gas revenues by $29.4 million. This proposal was designed to decrease our annual USF revenue by $3.7 million.

• September 2013 - The BPU approved the statewide USF budget of $54.4 million for all the State’s gas utilities.  Our portion of the total is approximately $5.8 million, which decreased rates effective October 1, 2013, resulting in a $3.4 million decrease to our USF recoveries.

Other Regulatory Matters -

Unbundling - In 2000, the BPU approved full unbundling of our system. This allows all natural gas consumers to select their natural gas commodity supplier. As of December 31, 2013, 47,074 of our customers were purchasing their gas commodity from someone other than us. Customers choosing to purchase natural gas from providers other than the utility are charged for the cost of gas by the marketer. The resulting decrease in our revenues is offset by a corresponding decrease in gas costs. While customer choice can reduce utility revenues, it does not negatively affect our net income or financial condition. The BPU continues to allow for full recovery of prudently incurred natural gas costs through the BGSS. Unbundling did not change the fact that we still recover cost of service, including certain deferred costs, through base rates.

Pipeline Integrity - In October 2005, we filed a petition with the BPU to implement a Pipeline Integrity Management Tracker (Tracker). The purpose of this Tracker was to recover incremental costs to be incurred by us as a result of new federal regulations, which are aimed at enhancing public safety and reliability. The regulations require that utilities use a comprehensive analysis to assess, evaluate, repair and validate the integrity of certain transmission lines in the event of a leak or failure. As part of our September 2010 base rate increase, we were permitted to recover previously deferred pipeline integrity costs incurred through September 2010.  In addition, we are authorized to defer future program costs, including related carrying costs, for recovery in our next base rate proceeding, subject to review by the BPU.  Accordingly, SJG withdrew its petition for the Pipeline Integrity Management Tracker.  As of December 31, 2013 and 2012, deferred pipeline integrity costs totaled $2.8 million and $1.6 million, respectively, and are included in other regulatory assets (See Note 4).

Superstorm Sandy - In June 2013, we filed a petition requesting deferral of incremental operating and maintenance expenses incurred due to Superstorm Sandy. These costs totaled $0.7 million and are expected to be recovered in SJG’s next base rate case. This petition is currently pending.

Filings and petitions described above are still pending unless otherwise indicated.

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ACCUMULATED OTHER COMPREHENSIVE LOSS

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

ACCUMULATED OTHER COMPREHENSIVE LOSS

ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCL):

The following table summarizes the changes in accumulated other comprehensive loss (AOCL) for the year ended December 31, 2013 (in thousands):

	Postretirement Liability Adjustment			Unrealized Gain (Loss) on Derivatives-Other			Unrealized Gain (Loss) on Available-for-Sale Securities			Total
Balance at January 1, 2013 (a)	$	(12,958	)	$	(621	)	$	294		$	(13,285	)
Other comprehensive income before reclassifications	932			—			592			1,524
Amounts reclassified from AOCL (b)	1,354			27			(489		)	892
Net current period other comprehensive income	2,286			27			103			2,416
Balance at December 31, 2013 (a)	$	(10,672	)	$	(594	)	$	397		$	(10,869	)

(a) Determined using a combined statutory tax rate of 41%.

(b) See table below.

The following table provides details about reclassifications out of AOCL for the year ended December 31, 2013 (in thousands):

Components of AOCL	Amounts Reclassified from AOCL			Affected Line Item in the Statements of Income
	For the Year Ended December 31, 2013
Unrealized Loss on Derivatives-Other - Interest Rate Contracts designated as cash flow hedges	$	46		Interest Charges
Unrealized Gain on Available-for-Sale Securities	(828		)	Other Income & Expense
Actuarial Loss on Postretirement Benefits	2,289			Operating Expenses: Operations
	1,507			Loss (Income) Before Income Taxes
Income Taxes (a)	615			Income Taxes (a)
Losses (Gains) from reclassifications for the period net of tax	$	892

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PENSION AND OTHER POSTRETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

PENSION AND OTHER POSTRETIREMENT BENEFITS

PENSION AND OTHER POSTRETIREMENT BENEFITS:

We participate in the defined benefit pension plans and other postretirement benefit plans of SJI. The pension plans provide annuity payments to the majority of full-time, regular employees upon retirement. Participation in the SJI qualified defined benefit pension plans was closed to new employees beginning in 2003; however, employees who are not eligible for these pension plans are eligible to receive an enhanced version of SJI’s defined contribution plan. Certain officers of SJG also participate in the non-funded supplemental executive retirement plan (SERP) of SJI, a non-qualified defined benefit pension plan. The other postretirement benefit plans provide health care and life insurance benefits to some retirees.

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									Other Postretirement Benefits
	2013			2012			2011			2013			2012			2011
Service Cost	$	4,487		$	3,718		$	3,048		$	771		$	704		$	675
Interest Cost	7,886			8,008			7,828			2,221			2,443			2,621
Expected Return on Plan Assets	(9,435		)	(8,249		)	(7,415		)	(2,158		)	(1,910		)	(2,040		)
Amortization:
Prior Service Cost (Credits)	208			207			219			(195		)	(195		)	(254		)
Actuarial Loss	7,608			6,432			4,561			1,555			1,534			1,466
Net Periodic Benefit Cost	10,754			10,116			8,241			2,194			2,576			2,468
Capitalized Benefit Costs	(5,002		)	(4,684		)	(3,661		)	(1,172		)	(1,340		)	(1,222		)
Affiliate SERP Allocations	(1,389		)	(1,107		)	(845		)	—			—			—
Total Net Periodic Benefit Expense	$	4,363		$	4,325		$	3,735		$	1,022		$	1,236		$	1,246

Capitalized benefit costs reflected in the table above relate to our construction program.

Companies with publicly traded equity securities that sponsor a postretirement benefit plan are required to fully recognize, as an asset or liability, the overfunded or underfunded status of its benefit plans and recognize changes in the funded status in the year in which the changes occur. Changes in funded status are generally reported in Other Comprehensive Loss; however, since we recover all prudently incurred pension and postretirement benefit costs from our ratepayers, a significant portion of the charges resulting from the recording of additional liabilities under this statement are reported as regulatory assets (See Note 4).

Details of the activity within the Regulatory Asset and Accumulated Other Comprehensive Loss associated with Pension and Other Postretirement Benefits are as follows (in thousands):

	Regulatory Assets						Accumulated Other Comprehensive Loss (pre-tax)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Balance at January 1, 2012	$	61,811		$	26,435		$	19,061		$	—
Amounts Arising during the Period:
Net Actuarial Loss	11,599			2,089			4,788			—
Amounts Amortized to Net Periodic Costs:
Net Actuarial Loss	(4,490		)	(1,535		)	(1,941		)	—
Prior Service (Cost) Credit	(207		)	195			—			—
Balance at December 31, 2012	68,713			27,184			21,908			—
Amounts Arising during the Period:
Net Actuarial Gain	(20,554		)	(9,171		)	(1,576		)	—
Amounts Amortized to Net Periodic Costs:
Net Actuarial Loss	(5,319		)	(1,555		)	(2,289		)	—
Prior Service (Cost) Credit	(208		)	194			—			—
Balance at December 31, 2013	$	42,632		$	16,652		$	18,043		$	—

The estimated costs that will be amortized from Regulatory Assets into net periodic benefit costs in 2014 are as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits
Prior Service Costs	$	158	$	133
Net Actuarial Loss	$	2,856	$	790

The estimated costs that will be amortized from Accumulated Other Comprehensive Loss into net periodic benefit costs in 2014 are as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits
Net Actuarial Loss	$	2,007	$	—

A reconciliation of the plans’ benefit obligations, fair value of plan assets, funded status and amounts recognized in our balance sheets follows (in thousands):

							Other
	Pension Benefits						Postretirement Benefits
	2013			2012			2013			2012
Change in Benefit Obligations:
Benefit Obligation at Beginning of Year	$	186,899		$	160,319		$	55,615		$	51,656
Service Cost	4,487			3,718			771			704
Interest Cost	7,886			8,008			2,221			2,443
Actuarial (Gain) Loss	(11,514		)	21,990			(4,552		)	4,059
Retiree Contributions	—			—			335			313
Plan Amendments	—			—			—			—
Benefits Paid	(7,090		)	(7,136		)	(3,475		)	(3,560		)
Benefit Obligation at End of Year	$	180,668		$	186,899		$	50,915		$	55,615
Change in Plan Assets:
Fair Value of Plan Assets at Beginning of Year	$	119,391		$	91,738		$	32,694		$	28,942
Actual Return on Plan Assets	20,049			13,853			5,101			3,880
Employer Contributions	10,324			20,936			4,816			3,119
Retiree Contributions	—			—			335			313
Benefits Paid	(7,090		)	(7,136		)	(3,475		)	(3,560		)
Fair Value of Plan Assets at End of Year	$	142,674		$	119,391		$	39,471		$	32,694

Funded Status at End of Year:
Accrued  Net Benefit Cost at End of Year	$	(37,994	)	$	(67,508	)	$	(11,444	)	$	(22,921	)
Amounts Recognized in the Statement of Financial Position Consist of:
Current Liabilities	$	(1,241	)	$	(1,236	)	$	—		$	—
Noncurrent Liabilities	(36,753		)	(66,272		)	(11,444		)	(22,921		)
Net Amount Recognized at End of Year	$	(37,994	)	$	(67,508	)	$	(11,444	)	$	(22,921	)
Amounts Recognized in Regulatory Assets Consist of:
Prior Service Costs	$	634		$	842		$	952		$	758
Net Actuarial Loss	41,998			67,871			15,700			26,426
Net Amount Recognized at End of Year	$	42,632		$	68,713		$	16,652		$	27,184
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Net Actuarial Loss	$	18,043		$	21,908		$	—		$	—

The projected benefit obligation (PBO) and accumulated benefit obligation (ABO) of our qualified employee pension plans were $143.5 million and $131.4 million, respectively, as of December 31, 2013; and $149.5 million and $135.6 million, respectively, as of December 31, 2012. The ABO of these plans exceeded the value of the plan assets as of December 31, 2012. The value of these assets can be seen in the tables above. The PBO and ABO for our non-funded SERP were $37.2 million and $36.2 million, respectively, as of December 31, 2013; and $37.4 million and $35.7 million, respectively, as of December 31, 2012. The SERP obligation is reflected in the tables above and has no assets.

The weighted-average assumptions used to determine benefit obligations at December 31 were:

	Pension Benefits				Other Postretirement Benefits
	2013		2012		2013		2012
Discount Rate	5.09	%	4.26	%	4.91	%	4.14	%
Rate of Compensation Increase	3.50	%	3.25	%	3.50	%	3.25	%

The weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 were:

	Pension Benefits						Other Postretirement Benefits
	2013		2012		2011		2013		2012		2011
Discount Rate	4.26	%	5.03	%	5.78	%	4.14	%	4.92	%	5.55	%
Expected Long-Term Return on Plan Assets	7.50	%	7.50	%	8.00	%	6.60	%	6.60	%	7.00	%
Rate of Compensation Increase	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%	3.25	%

All obligations disclosed herein reflect the use of the RP 2000 mortality tables.  

The discount rates used to determine the benefit obligations at December 31, 2013 and 2012, which are used to determine the net periodic benefit cost for the subsequent year, were based on a portfolio model of high-quality investments with maturities that match the expected benefit payments under our pension and other postretirement benefit plans.

The expected long-term return on plan assets (“return”) has been determined by applying long-term capital market projections provided by our pension plan Trustee to the asset allocation guidelines, as defined in the Company’s investment policy, to arrive at a weighted average return.  For certain other equity securities held by an investment manager outside of the control of the Trustee, the return has been determined based on historic performance in combination with long-term expectations.  The return for the other postretirement benefits plan is determined in the same manner as discussed above; however, the expected return is reduced based on the taxable nature of the underlying trusts.

The assumed health care cost trend rates at December 31 were:

	2013		2012
Medical Care and Drug Cost Trend Rate Assumed for Next Year	7.00	%	7.00	%
Dental Care Cost Trend Rate Assumed for Next Year	4.75	%	4.75	%
Rate to which Cost Trend Rates are Assumed to Decline (the Ultimate Trend Rate)	4.75	%	4.75	%
Year that the Rate Reaches the Ultimate Trend Rate	2023		2019

Assumed health care cost trend rates have a significant effect on the amounts reported for our postretirement health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in thousands):

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on the Total of Service and Interest Cost	$	145	$	(115	)
Effect on Postretirement Benefit Obligation	$	2,406	$	(2,027	)

PLAN ASSETS — The Company’s overall investment strategy for pension plan assets is to achieve a diversification by asset class, style of manager, and sector and industry limits to achieve investment results that match the actuarially assumed rate of return, while preserving the inflation adjusted value of the plans.  The Company has implemented this diversification strategy primarily with commingled common/collective trust funds.  The target allocations for pension plan assets are 28-48 percent U.S. equity securities, 13-25 percent international equity securities, 32-42 percent fixed income investments, and 2-14 percent to all other types of investments.  Equity securities include investments in commingled common/collective trust funds as well as large-cap, mid-cap and small-cap companies.  Fixed income securities include commingled common/collective trust funds, group annuity contracts for pension payments, and hedge funds.  Other types of investments include investments in private equity funds and real estate funds that follow several different strategies.

The strategy recognizes that risk and volatility are present to some degree with all types of investments.  We seek to avoid high levels of risk at the total fund level through diversification by asset class, style of manager, and sector and industry limits.  Specifically prohibited investments include, but are not limited to, venture capital, margin trading, commodities and securities of companies with less than $250.0 million capitalization (except in the small-cap portion of the fund where capitalization levels as low as $50.0 million are permissible).  These restrictions are only applicable to individual investment managers with separately managed portfolios and do not apply to mutual funds or commingled trusts.

SJG evaluated its pension and other postretirement benefit plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2013.   Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund.  As of December 31, 2013, there were no significant concentrations (defined as greater than 10 percent of plan assets) of risk in SJG’s pension and other postretirement benefit plan assets.

GAAP establishes a hierarchy that prioritizes fair value measurements based on the types of inputs used for the various valuation techniques.  This hierarchy groups assets into three (3) distinct levels as fully described in Note 13, that will serve as the basis for presentation throughout the remainder of this Note.

The fair values of SJG’s pension plan assets at December 31, 2013 and 2012 by asset category are as follows (in thousands):

Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2013:
Cash / Cash Equivalents:
Common/Collective Trust Funds (a)	$	334	$	—	$	334	$	—
STIF-Type Instrument (b)	943		—		943		—
Equity securities:
Common/Collective Trust Funds – U.S. (a)	41,527		—		41,527		—
Common/Collective Trust Funds – International (a)	27,312		—		27,312		—
U.S. Large-Cap (c)	9,342		9,342		—		—
U.S. Mid-Cap (c)	3,313		3,313		—		—
International (c)	2,935		2,935		—		—
Fixed Income:
Common/Collective Trust Funds (a)	36,728		—		36,728		—
Guaranteed Insurance Contract (d)	9,071		—		—		9,071
Hedge Funds (e)	3,328		—		—		3,328
Other types of investments:
Private Equity Fund (f)	2,440		—		—		2,440
Common/Collective Trust Fund – Real Estate (g)	5,401		—		—		5,401
Total	$	142,674	$	15,590	$	106,844	$	20,240

Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2012:
Cash / Cash Equivalents:
Common/Collective Trust Funds (a)	$	477	$	—	$	477	$	—
STIF-Type Instrument (b)	840		—		840		—
Equity securities:
Common/Collective Trust Funds – U.S. (a)	33,690		—		33,690		—
Common/Collective Trust Funds – International (a)	23,448		—		23,448		—
U.S. Large-Cap (c)	7,126		7,126		—		—
U.S. Mid-Cap (c)	4,194		4,194		—		—
U.S. Small-Cap (c)	8		8		—		—
International (c)	1,462		1,462		—		—
Fixed Income:
Common/Collective Trust Funds (a)	30,913		—		30,913		—
Guaranteed Insurance Contract (d)	9,898		—		—		9,898
Other types of investments:
Private Equity Fund (f)	2,557		—		—		2,557
Common/Collective Trust Fund – Real Estate (g)	4,778		—		—		4,778
Total	$	119,391	$	12,790	$	89,368	$	17,233

(a) This category represents common/collective trust fund investments through a commingled employee benefit trust (excluding real estate).  These commingled funds are not traded publicly; however, the majority of the underlying assets held in these funds are stocks and bonds that are traded on active markets and prices for these assets are readily observable.  Also included in these funds are interest rate swaps, asset backed securities, mortgage backed securities and other investments with observable market values. Holdings in these commingled funds are classified as Level 2 investments.

(b) This category represents short-term investment funds held for the purpose of funding disbursement payment arrangements.  Underlying assets are valued based on quoted prices in active markets, or where quoted prices are not available, based on models using observable market information.  Since not all values can be obtained from quoted prices in active markets, these funds are classified as Level 2 investments.

(c) This category of equity investments represents a managed portfolio of common stock investments in five sectors: telecommunications, electric utilities, gas utilities, water and energy.  These common stocks are actively traded on exchanges and price quotes for these shares are readily available.  These common stocks are classified as Level 1 investments.

(d) This category represents SJI’s Group Annuity contracts with a nationally recognized life insurance company.  The contracts are the assets of the plan, while the underlying assets of the contracts are owned by the contract holder.  Valuation is based on a formula and calculation specified within the contract.  Since the valuation is based on the reporting entity’s own assumptions, these contracts are classified as Level 3 investments.

(e) This category represents a collection of underlying funds which are all domiciled outside of the United States. All of the underlying fund managers are based in the U.S.; however, they do not necessarily trade only in the U.S. markets. The fair value of these funds is determined by the underlying fund's general partner or manager. These funds are classified as Level 3 investments.

(f) This category represents a limited partnership which includes several investments in U.S. leveraged buyout, venture capital, and special situation funds.  Fund valuations are reported on a 90 day lag and, therefore, the value reported herein represents the market value as of September 30, 2013 and 2012, respectively.  The fund’s investments are stated at fair value, which is generally based on the valuations provided by the general partners or managers of such investments.  Fund investments are illiquid and resale is restricted.  These funds are classified as Level 3 investments.

(g) This category represents real estate common/collective trust fund investments through a commingled employee benefit trust. These commingled funds are part of a direct investment in a pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, the real estate funds are classified as Level 2 investments.

Fair Value Measurement Using Significant

Unobservable Inputs (Level 3)

(In thousands)

	Guaranteed Insurance Contract			Hedge Funds		Private Equity Funds			Real Estate		Total
Balance at January 1, 2012	$	9,647		$	—	$	2,525		$	4,291	$	16,463
Actual return on plan assets:
Relating to assets still held at the reporting date	1,082			—		(122		)	487		1,447
Relating to assets sold during the period	(10		)	—		480			—		470
Purchases, Sales and Settlements	(821		)	—		(326		)	—		(1,147		)
Balance at December 31, 2012	$	9,898		$	—	$	2,557		$	4,778	$	17,233
Actual return on plan assets:
Relating to assets still held at the reporting date	(68		)	124		80			623		759
Relating to assets sold during the period	14			—		345			—		359
Purchases, Sales and Settlements	(773		)	3,204		(542		)	—		1,889
Balance at December 31, 2013	$	9,071		$	3,328	$	2,440		$	5,401	$	20,240

As with the pension plan assets, the Company’s overall investment strategy for post-retirement benefit plan assets is to achieve a diversification by asset class, style of manager, and sector and industry limits to achieve investment results that match the actuarially assumed rate of return, while preserving the inflation adjusted value of the plans.  The Company has implemented this diversification strategy with a mix of common/collective trust funds and mutual funds.  The target allocations for post-retirement benefit plan assets are 33-43 percent U.S. equity securities, 20-30 percent international equity securities, and 32-42 percent fixed income investments.  Equity securities include investments in large-cap, mid-cap and small-cap companies within mutual funds or common/collective trust funds.  Fixed income securities within the common/collective trust fund include primarily investment grade, U.S. Government and mortgage-backed financial instruments.

The fair values of SJG’s other postretirement benefit plan assets at December 31, 2013 and 2012 by asset category are as follows (in thousands):

Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2013:
Equity Securities:
Common/Collective Trust Funds - U.S. (a)	$	12,412	$	—	$	12,412	$	—
Common/Collective Trust Funds - International (a)	10,031		—		10,031		—
Mutual Fund - U.S. Large-Cap (b)	2,814		2,814		—		—
Fixed Income:
Common/Collective Trust (a)	14,214		—		14,214		—
Total	$	39,471	$	2,814	$	36,657	$	—
Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2012:
Equity Securities:
Common/Collective Trust Funds - U.S. (a)	$	9,972	$	—	$	9,972	$	—
Common/Collective Trust Funds - International (a)	8,475		—		8,475		—
Mutual Fund - U.S. Large-Cap (b)	2,326		2,326		—		—
Fixed Income:
Common/Collective Trust (a)	11,921		—		11,921		—
Total	$	32,694	$	2,326	$	30,368	$	—

(a) This category represents common/collective trust fund investments through a commingled employee benefit trust (excluding real estate).  These commingled funds are not traded publicly; however, the majority of the underlying assets held in these funds are stocks and bonds that are traded on active markets and prices for these assets are readily observable.  Also included in these funds are interest rate swaps, asset backed securities, mortgage backed securities and other investments with observable market values. Holdings in these commingled funds are classified as Level 2 investments.

(b) This category represents mutual fund investments. The mutual funds are actively traded on exchanges and price quotes for the shares are readily available. These mutual funds are classified as Level 1 investments.

Future Benefit Payments - The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid during the following years (in thousands):

	Pension Benefits		Other Postretirement Benefits
2014	$	7,770	$	3,725
2015	$	8,303	$	3,825
2016	$	8,646	$	3,906
2017	$	9,021	$	3,955
2018	$	10,316	$	3,997
2019 - 2023	$	61,659	$	21,093

Contributions - SJG contributed $9.1 million and $19.8 million to our qualified employee pension plans during the years ended December 31, 2013 and 2012, respectively. No pension plan contributions are planned for 2014.  Payments related to the unfunded SERP plan are expected to approximate $1.2 million in 2014 and have been consistent over the past few years. We also have a regulatory obligation to contribute approximately $3.6 million annually to our other postretirement benefit plans’ trusts, less costs incurred directly by us.

Defined Contribution Plan - We also offer an Employees’ Retirement Savings Plan (Savings Plan) to eligible employees. For employees eligible for participation in SJI's defined benefit pension plans, SJG matches 50% of participants’ contributions up to 6% of base compensation. For employees who are not eligible for participation in SJI’s defined benefit plans, we match 50% of participants’ contributions up to 8% of base compensation. Employees not eligible for the pension plans also receive a year-end contribution of $1,000 if 10 or fewer years of service, or $1,500 if more than 10 years of service. The amount expensed and contributed for the matching provision of the Savings Plan approximated $1.0 million, $0.9 million and $0.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

LONG-TERM DEBT

LONG-TERM DEBT:

A schedule of our long-term debt as of December 31, including current maturities, is as follows (in thousands):

			2013			2012
Long-Term Debt (A):
First Mortgage Bonds: (B)
4.46	%	Series due 2013 (C)	$	—		$	10,500
5.027	%	Series due 2013 (C)	—			14,500
4.52	%	Series due 2014	11,000			11,000
5.115	%	Series due 2014	10,000			10,000
5.387	%	Series due 2015	10,000			10,000
5.437	%	Series due 2016	10,000			10,000
4.60	%	Series due 2016	17,000			17,000
4.657	%	Series due 2017	15,000			15,000
7.97	%	Series due 2018	10,000			10,000
7.125	%	Series due 2018	20,000			20,000
5.587	%	Series due 2019	10,000			10,000
3.00	%	Series due 2024	50,000			50,000
3.03	%	Series due 2024	35,000			35,000
3.63	%	Series due 2025	10,000			10,000
4.84	%	Series due 2026	15,000			15,000
4.93	%	Series due 2026	45,000			45,000
4.03	%	Series due 2027	45,000			45,000
4.01	%	Series due 2030 (D)	50,000			—
3.74	%	Series due 2032	35,000			35,000
5.55	%	Series due 2033	32,000			32,000
6.213	%	Series due 2034	10,000			10,000
5.45	%	Series due 2035	10,000			10,000
Series A 2006 Tax-Exempt First Mortgage Bonds
Variable Rate, due 2036 (E)			25,000			25,000
Total Long-Term Debt Outstanding			475,000			450,000
Less Current Maturities (A)			(21,000		)	(25,000		)
Long-Term Debt			$	454,000		$	425,000

(A) Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2014, $21,000; 2015, $10,909; 2016, $27,909; 2017, $15,909; 2018, $38,909 .Our long-term debt agreements contain no financial covenants.

(B) Our First Mortgage dated October 1, 1947, as supplemented, securing the First Mortgage Bonds constitutes a direct first mortgage lien on substantially all utility plant.

(C) In July 2013, SJG called its $10.5 million, 4.46% Medium Term Notes (MTN) due July 2013 and $14.5 million, 5.027% MTN due September 2013.

(D) In November 2013, SJG issued $50.0 million of 4.01% aggregate principal amount of MTN due November 2030.

(E) These variable rate demand bonds bear interest at a floating rate that resets weekly. The interest rate as of December 31, 2013 was 0.07%. Liquidity support on these bonds is provided under a separate letter of credit facility that expires in August, 2015. These bonds contain no financial covenants.

In December 2011, SJG received approval from the BPU to issue up to $200.0 million in long-term debt under its MTN program by September 30, 2014. As of December 31, 2013, $30.0 million was available under this program. In January 2014, SJG issued the remaining $30.0 million aggregate principle amount of 4.23% MTN's due January 2030. We retire debt when it is cost effective as permitted by the debt agreements.

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PENSION AND OTHER POSTRETIREMENT BENEFITS 9 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended																																																																																																																																																						12 Months Ended																																				12 Months Ended																																																																																								12 Months Ended
	Dec. 31, 2013 Pension Benefits [Member]	Dec. 31, 2011 Pension Benefits [Member]	Dec. 31, 2013 Pension Benefits [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] STIF-Type Instrument [Member]		Dec. 31, 2012 Pension Benefits [Member] STIF-Type Instrument [Member]		Dec. 31, 2013 Pension Benefits [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2012 Pension Benefits [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2013 Pension Benefits [Member] U.S. Large-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] U.S. Large-Cap [Member]		Dec. 31, 2013 Pension Benefits [Member] U.S. Mid-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] U.S. Mid-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] U.S. Small-Cap [Member]		Dec. 31, 2013 Pension Benefits [Member] Equity Securities, International Securities [Member]		Dec. 31, 2012 Pension Benefits [Member] Equity Securities, International Securities [Member]		Dec. 31, 2013 Pension Benefits [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Guaranteed Insurance Contract [Member]		Dec. 31, 2012 Pension Benefits [Member] Guaranteed Insurance Contract [Member]		Dec. 31, 2013 Pension Benefits [Member] Hedge Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Private Equity Fund [Member]		Dec. 31, 2012 Pension Benefits [Member] Private Equity Fund [Member]		Dec. 31, 2013 Pension Benefits [Member] Common/Collective Trust Fund – Real Estate [Member]		Dec. 31, 2012 Pension Benefits [Member] Common/Collective Trust Fund – Real Estate [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member]	Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member]	Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] STIF-Type Instrument [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] STIF-Type Instrument [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] U.S. Large-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] U.S. Large-Cap [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] U.S. Mid-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] U.S. Mid-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] U.S. Small-Cap [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] Equity Securities, International Securities [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] Equity Securities, International Securities [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] Guaranteed Insurance Contract [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] Guaranteed Insurance Contract [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] Hedge Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] Private Equity Fund [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] Private Equity Fund [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 1 [Member] Common/Collective Trust Fund – Real Estate [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 1 [Member] Common/Collective Trust Fund – Real Estate [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member]	Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member]	Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] STIF-Type Instrument [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] STIF-Type Instrument [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] U.S. Large-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] U.S. Large-Cap [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] U.S. Mid-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] U.S. Mid-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] U.S. Small-Cap [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] Equity Securities, International Securities [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] Equity Securities, International Securities [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] Guaranteed Insurance Contract [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] Guaranteed Insurance Contract [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] Hedge Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] Private Equity Fund [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] Private Equity Fund [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 2 [Member] Common/Collective Trust Fund – Real Estate [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 2 [Member] Common/Collective Trust Fund – Real Estate [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member]	Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member]	Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] STIF-Type Instrument [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] STIF-Type Instrument [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] U.S. Large-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] U.S. Large-Cap [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] U.S. Mid-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] U.S. Mid-Cap [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] U.S. Small-Cap [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] Equity Securities, International Securities [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] Equity Securities, International Securities [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] Guaranteed Insurance Contract [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] Guaranteed Insurance Contract [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] Hedge Funds [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] Hedge Funds [Member]	Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] Private Equity Fund [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] Private Equity Fund [Member]		Dec. 31, 2013 Pension Benefits [Member] Level 3 [Member] Common/Collective Trust Fund – Real Estate [Member]		Dec. 31, 2012 Pension Benefits [Member] Level 3 [Member] Common/Collective Trust Fund – Real Estate [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member]	Dec. 31, 2012 Other Postretirement Benefits [Member]	Dec. 31, 2011 Other Postretirement Benefits [Member]	Dec. 31, 2013 Other Postretirement Benefits [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Mutual Fund - U.S. Large-Cap [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Mutual Fund - U.S. Large-Cap [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Common/Collective Trust [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Common/Collective Trust [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 1 [Member]	Dec. 31, 2012 Other Postretirement Benefits [Member] Level 1 [Member]	Dec. 31, 2013 Other Postretirement Benefits [Member] Level 1 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 1 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 1 [Member] Mutual Fund - U.S. Large-Cap [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 1 [Member] Mutual Fund - U.S. Large-Cap [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 1 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 1 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 1 [Member] Common/Collective Trust [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 1 [Member] Common/Collective Trust [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 2 [Member]	Dec. 31, 2012 Other Postretirement Benefits [Member] Level 2 [Member]	Dec. 31, 2013 Other Postretirement Benefits [Member] Level 2 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 2 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 2 [Member] Mutual Fund - U.S. Large-Cap [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 2 [Member] Mutual Fund - U.S. Large-Cap [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 2 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 2 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 2 [Member] Common/Collective Trust [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 2 [Member] Common/Collective Trust [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 3 [Member]	Dec. 31, 2012 Other Postretirement Benefits [Member] Level 3 [Member]	Dec. 31, 2013 Other Postretirement Benefits [Member] Level 3 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 3 [Member] Common/Collective Trust Funds – U.S. [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 3 [Member] Mutual Fund - U.S. Large-Cap [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 3 [Member] Mutual Fund - U.S. Large-Cap [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 3 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 3 [Member] Common/Collective Trust Funds [Member]		Dec. 31, 2013 Other Postretirement Benefits [Member] Level 3 [Member] Common/Collective Trust [Member]		Dec. 31, 2012 Other Postretirement Benefits [Member] Level 3 [Member] Common/Collective Trust [Member]		Dec. 31, 2013 Minimum [Member] Other Postretirement Benefits [Member] Equity Securities, U.S. Securities [Member]	Dec. 31, 2013 Minimum [Member] Other Postretirement Benefits [Member] Equity Securities, International Securities [Member]	Dec. 31, 2013 Minimum [Member] Other Postretirement Benefits [Member] Fixed Income Funds [Member]	Dec. 31, 2013 Maximum [Member] Other Postretirement Benefits [Member] Equity Securities, U.S. Securities [Member]	Dec. 31, 2013 Maximum [Member] Other Postretirement Benefits [Member] Equity Securities, International Securities [Member]	Dec. 31, 2013 Maximum [Member] Other Postretirement Benefits [Member] Fixed Income Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	$ 142,674	$ 91,738	$ 334	[1]	$ 477	[1]	$ 943	[2]	$ 840	[2]	$ 41,527	[1]	$ 33,690	[1]	$ 9,342	[3]	$ 7,126	[3]	$ 3,313	[3]	$ 4,194	[3]	$ 8	[3]	$ 2,935	[3]	$ 1,462	[3]	$ 27,312	[1]	$ 23,448	[1]	$ 36,728	[1]	$ 30,913	[1]	$ 9,071	[4]	$ 9,898	[4]	$ 3,328	[5]	$ 2,440	[6]	$ 2,557	[6]	$ 5,401	[7]	$ 4,778	[7]	$ 15,590	$ 12,790	$ 0	[1]	$ 0	[1]	$ 0	[2]	$ 0	[2]	$ 0	[1]	$ 0	[1]	$ 9,342	[3]	$ 7,126	[3]	$ 3,313	[3]	$ 4,194	[3]	$ 8	[3]	$ 2,935	[3]	$ 1,462	[3]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[4]	$ 0	[4]	$ 0	[5]	$ 0	[6]	$ 0	[6]	$ 0	[7]	$ 0	[7]	$ 106,844	$ 89,368	$ 334	[1]	$ 477	[1]	$ 943	[2]	$ 840	[2]	$ 41,527	[1]	$ 33,690	[1]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 27,312	[1]	$ 23,448	[1]	$ 36,728	[1]	$ 30,913	[1]	$ 0	[4]	$ 0	[4]	$ 0	[5]	$ 0	[6]	$ 0	[6]	$ 0	[7]	$ 0	[7]	$ 20,240	$ 17,233	$ 0	[1]	$ 0	[1]	$ 0	[2]	$ 0	[2]	$ 0	[1]	$ 0	[1]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 9,071	[4]	$ 9,898	[4]	$ 3,328	[5]	$ 0	$ 2,440	[6]	$ 2,557	[6]	$ 5,401	[7]	$ 4,778	[7]	$ 39,471	$ 32,694	$ 28,942	$ 12,412	[1]	$ 9,972	[1]	$ 2,814	[8]	$ 2,326	[8]	$ 10,031	[1]	$ 8,475	[1]	$ 14,214	[1]	$ 11,921	[1]	$ 2,814	$ 2,326	$ 0	[1]	$ 0	[1]	$ 2,814	[8]	$ 2,326	[8]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 36,657	$ 30,368	$ 12,412	[1]	$ 9,972	[1]	$ 0	[8]	$ 0	[8]	$ 10,031	[1]	$ 8,475	[1]	$ 14,214	[1]	$ 11,921	[1]	$ 0	$ 0	$ 0	[1]	$ 0	[1]	$ 0	[8]	$ 0	[8]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]
Fund Valuations Lag Period	90 days
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value of Plan Assets at Beginning of Year	119,391	91,738	334	[1]	477	[1]	943	[2]	840	[2]	41,527	[1]	33,690	[1]	9,342	[3]	7,126	[3]	3,313	[3]	4,194	[3]	8	[3]	2,935	[3]	1,462	[3]	27,312	[1]	23,448	[1]	36,728	[1]	30,913	[1]	9,071	[4]	9,898	[4]	3,328	[5]	2,440	[6]	2,557	[6]	5,401	[7]	4,778	[7]	15,590	12,790	0	[1]	0	[1]	0	[2]	0	[2]	0	[1]	0	[1]	9,342	[3]	7,126	[3]	3,313	[3]	4,194	[3]	8	[3]	2,935	[3]	1,462	[3]	0	[1]	0	[1]	0	[1]	0	[1]	0	[4]	0	[4]	0	[5]	0	[6]	0	[6]	0	[7]	0	[7]	106,844	89,368	334	[1]	477	[1]	943	[2]	840	[2]	41,527	[1]	33,690	[1]	0	[3]	0	[3]	0	[3]	0	[3]	0	[3]	0	[3]	0	[3]	27,312	[1]	23,448	[1]	36,728	[1]	30,913	[1]	0	[4]	0	[4]	0	[5]	0	[6]	0	[6]	0	[7]	0	[7]	17,233	16,463	0	[1]	0	[1]	0	[2]	0	[2]	0	[1]	0	[1]	0	[3]	0	[3]	0	[3]	0	[3]	0	[3]	0	[3]	0	[3]	0	[1]	0	[1]	0	[1]	0	[1]	9,898	[4]	9,647		0		0	2,557	[6]	2,525		4,778	[7]	4,291		39,471	32,694	28,942	12,412	[1]	9,972	[1]	2,814	[8]	2,326	[8]	10,031	[1]	8,475	[1]	14,214	[1]	11,921	[1]	2,814	2,326	0	[1]	0	[1]	2,814	[8]	2,326	[8]	0	[1]	0	[1]	0	[1]	0	[1]	36,657	30,368	12,412	[1]	9,972	[1]	0	[8]	0	[8]	10,031	[1]	8,475	[1]	14,214	[1]	11,921	[1]	0	0	0	[1]	0	[1]	0	[8]	0	[8]	0	[1]	0	[1]	0	[1]	0	[1]
Actual return on plan assets [Abstract]
Relating to assets still held at the reporting date																																																																																																																																																							759	1,447																																			(68)		1,082		124		0	80		(122)		623		487
Relating to assets sold during the period																																																																																																																																																							359	470																																			14		(10)		0		0	345		480		0		0
Purchases, Sales, and Settlements																																																																																																																																																							1,889	(1,147)																																			(773)		(821)		3,204		0	(542)		(326)		0		0
Fair Value of Plan Assets at End of Year	$ 142,674	$ 91,738	$ 334	[1]	$ 477	[1]	$ 943	[2]	$ 840	[2]	$ 41,527	[1]	$ 33,690	[1]	$ 9,342	[3]	$ 7,126	[3]	$ 3,313	[3]	$ 4,194	[3]	$ 8	[3]	$ 2,935	[3]	$ 1,462	[3]	$ 27,312	[1]	$ 23,448	[1]	$ 36,728	[1]	$ 30,913	[1]	$ 9,071	[4]	$ 9,898	[4]	$ 3,328	[5]	$ 2,440	[6]	$ 2,557	[6]	$ 5,401	[7]	$ 4,778	[7]	$ 15,590	$ 12,790	$ 0	[1]	$ 0	[1]	$ 0	[2]	$ 0	[2]	$ 0	[1]	$ 0	[1]	$ 9,342	[3]	$ 7,126	[3]	$ 3,313	[3]	$ 4,194	[3]	$ 8	[3]	$ 2,935	[3]	$ 1,462	[3]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[4]	$ 0	[4]	$ 0	[5]	$ 0	[6]	$ 0	[6]	$ 0	[7]	$ 0	[7]	$ 106,844	$ 89,368	$ 334	[1]	$ 477	[1]	$ 943	[2]	$ 840	[2]	$ 41,527	[1]	$ 33,690	[1]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 27,312	[1]	$ 23,448	[1]	$ 36,728	[1]	$ 30,913	[1]	$ 0	[4]	$ 0	[4]	$ 0	[5]	$ 0	[6]	$ 0	[6]	$ 0	[7]	$ 0	[7]	$ 20,240	$ 17,233	$ 0	[1]	$ 0	[1]	$ 0	[2]	$ 0	[2]	$ 0	[1]	$ 0	[1]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[3]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 9,071	[4]	$ 9,898	[4]	$ 3,328	[5]	$ 0	$ 2,440	[6]	$ 2,557	[6]	$ 5,401	[7]	$ 4,778	[7]	$ 39,471	$ 32,694	$ 28,942	$ 12,412	[1]	$ 9,972	[1]	$ 2,814	[8]	$ 2,326	[8]	$ 10,031	[1]	$ 8,475	[1]	$ 14,214	[1]	$ 11,921	[1]	$ 2,814	$ 2,326	$ 0	[1]	$ 0	[1]	$ 2,814	[8]	$ 2,326	[8]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 36,657	$ 30,368	$ 12,412	[1]	$ 9,972	[1]	$ 0	[8]	$ 0	[8]	$ 10,031	[1]	$ 8,475	[1]	$ 14,214	[1]	$ 11,921	[1]	$ 0	$ 0	$ 0	[1]	$ 0	[1]	$ 0	[8]	$ 0	[8]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]
Target plan allocations																																																																																																																																																																																																																																																																																			33.00%	20.00%	32.00%	43.00%	30.00%	42.00%

[1] This category represents common/collective trust fund investments through a commingled employee benefit trust (excluding real estate). These commingled funds are not traded publicly; however, the majority of the underlying assets held in these funds are stocks and bonds that are traded on active markets and prices for these assets are readily observable. Also included in these funds are interest rate swaps, asset backed securities, mortgage backed securities and other investments with observable market values. Holdings in these commingled funds are classified as Level 2 investments.

[2] This category represents short-term investment funds held for the purpose of funding disbursement payment arrangements. Underlying assets are valued based on quoted prices in active markets, or where quoted prices are not available, based on models using observable market information. Since not all values can be obtained from quoted prices in active markets, these funds are classified as Level 2 investments.

[3] This category of equity investments represents a managed portfolio of common stock investments in five sectors: telecommunications, electric utilities, gas utilities, water and energy. These common stocks are actively traded on exchanges and price quotes for these shares are readily available. These common stocks are classified as Level 1 investments.

[4] This category represents SJI’s Group Annuity contracts with a nationally recognized life insurance company. The contracts are the assets of the plan, while the underlying assets of the contracts are owned by the contract holder. Valuation is based on a formula and calculation specified within the contract. Since the valuation is based on the reporting entity’s own assumptions, these contracts are classified as Level 3 investments.

[5] This category represents a collection of underlying funds which are all domiciled outside of the United States. All of the underlying fund managers are based in the U.S.; however, they do not necessarily trade only in the U.S. markets. The fair value of these funds is determined by the underlying fund's general partner or manager. These funds are classified as Level 3 investments.

[6] This category represents a limited partnership which includes several investments in U.S. leveraged buyout, venture capital, and special situation funds. Fund valuations are reported on a 90 day lag and, therefore, the value reported herein represents the market value as of September 30, 2013 and 2012, respectively. The fund’s investments are stated at fair value, which is generally based on the valuations provided by the general partners or managers of such investments. Fund investments are illiquid and resale is restricted. These funds are classified as Level 3 investments.

[7] This category represents real estate common/collective trust fund investments through a commingled employee benefit trust. These commingled funds are part of a direct investment in a pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, the real estate funds are classified as Level 2 investments.

[8] This category represents mutual fund investments. The mutual funds are actively traded on exchanges and price quotes for the shares are readily available. These mutual funds are classified as Level 1 investments.

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS:

We conducted business with our parent, SJI, and several other related parties. A description of each of these affiliates and related transactions is as follows:

SJI Services, LLC (SJIS) - a wholly owned subsidiary of SJI, provides services, such as information technology, human resources, corporate communications, materials purchasing and fleet management to SJI and all of its subsidiaries.

South Jersey Energy Solutions, LLC (SJES) - a wholly owned subsidiary of SJI that serves as a holding company for all of SJI’s nonutility operating businesses:

• South Jersey Energy Company (SJE) - a wholly owned subsidiary of SJES and a third party energy marketer that acquires and markets natural gas and electricity to retail end users and provides total energy management services to commercial and industrial customers. We provide SJE with billing services. For SJE’s residential customers, for which we perform billing services, we purchase the related accounts receivable at book value less a factor for potential uncollectible accounts, and assume all risk associated with collection.

• South Jersey Resources Group, LLC (SJRG) - a wholly owned subsidiary of SJES and a wholesale gas and risk management business that supplies natural gas storage, commodity and transportation to retail marketers, utility businesses and electricity generators in the mid-Atlantic, Appalachian and southern states. We sell natural gas for resale and capacity release to SJRG and also meet some of our gas purchasing requirements by purchasing natural gas from SJRG. Additionally, SJRG manages our market risk associated with fluctuations in the cost of natural gas by entering into financial derivative contracts on our behalf. The gain or loss associated with these derivative contracts is included in our BGSS and in the SJRG receivable and payable amounts shown below.

• Marina Energy LLC (Marina) - a wholly owned subsidiary of SJES and developer, owner and operator of energy related projects. We provide natural gas transportation services to Marina under BPU-approved tariffs.

• South Jersey Energy Service Plus, LLC (SJESP) - a wholly owned subsidiary of SJES and an appliance service company. We provide billing services to SJESP.

Millennium Account Services, LLC (Millennium) - a partnership between SJI and Pepco Holdings, Inc, which reads our utility customers’ meters on a monthly basis for a fee.

Sales of gas to SJRG and SJE comply with Section 284.02 of the Regulations of the Federal Energy Regulatory Commission (FERC).

In addition to the above, we provide various administrative and professional services to SJI and each of the affiliates discussed above. Likewise, SJI and SJIS provide substantial administrative services on our behalf. For certain types of transactions, we served as central processing agents for the related parties discussed above. Amounts due to and due from these related parties for pass-through items are not considered material to the financial statements as a whole. A summary of these related party transactions, excluding pass-through items, included in Operating Revenues were as follows (in thousands):

	2013		2012		2011
Operating Revenues/Affiliates:
SJRG	$	1,390	$	884	$	6,532
Other	1,299		851		716
Total Operating Revenues/Affiliates	$	2,689	$	1,735	$	7,248

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

	2013			2012			2011
Costs of Sales/Affiliates
(Excluding depreciation):
SJRG	$	14,959		$	9,083		$	33,768
Derivative Losses (See Note 1):
SJRG	$	887		$	15,407		$	12,872
Operations Expense/Affiliates:
SJI	$	11,990		$	10,870		$	9,941
SJIS	5,531			5,397			4,956
Millennium	2,686			3,149			3,076
Other	(428		)	(500		)	(448		)
Total Operations Expense/Affiliates	$	19,779		$	18,916		$	17,525

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INCOME TAXES AND CREDITS

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

INCOME TAXES AND CREDITS

INCOME TAXES AND CREDITS:

Total income taxes applicable to operations differ from the tax that would have resulted by applying the statutory Federal income tax rate to pre-tax income for the following reasons (in thousands):

	2013			2012			2011
Tax at Statutory Rate	$	33,974		$	32,183		$	30,510
Increase (Decrease) Resulting from:
State Income Taxes	4,833			5,302			5,316
Amortization of Investment Tax Credits	(258		)	(287		)	(302		)
ESOP Dividend	(1,058		)	(1,027		)	(956		)
AFUDC	(916		)	(1,048		)	(729		)
Amortization of Flowthrough Depreciation	—			—			526
Other - Net	(1,742		)	(1,412		)	(84		)
Net Income Taxes	$	34,833		$	33,711		$	34,281

The provision for Income Taxes is comprised of the following (in thousands):

	2013			2012			2011
Current:
Federal	$	(53	)	$	(4,635	)	$	(924	)
State	2,946			(7		)	168
Total Current	2,893			(4,642		)	(756		)
Deferred:
Federal	27,707			30,477			27,329
State	4,491			8,163			8,010
Total Deferred	32,198			38,640			35,339
Investment Tax Credits	(258		)	(287		)	(302		)
Net Income Taxes	$	34,833		$	33,711		$	34,281

Investment Tax Credits are deferred and amortized at the annual rate of 3%, which approximates the life of related assets.

The net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and income tax purposes resulted in the following net deferred tax liabilities at December 31 (in thousands):

	2013			2012
Current:
Net Operating Loss Carryforward	$	(27,600	)	$	(2,586	)
Budget Billing - Customer Accounts	1,152			1,033
Provision for Uncollectibles	(1,726		)	(1,409		)
Conservation Incentive Program	4,631			13,942
Section 461 Prepayments	1,156			930
Other	(922		)	(1,478		)
Current Deferred Tax (Asset) Liability - Net	$	(23,309	)	$	10,432
Noncurrent:
Book Versus Tax Basis of Property	$	371,684		$	323,470
Deferred Fuel Costs - Net	1,330			3,325
Environmental Remediation	14,392			17,643
Deferred Regulatory Costs	13,665			15,374
Deferred State Tax	(15,471		)	(15,106		)
Investment Tax Credit Basis Gross-Up	(185		)	(318		)
Deferred Pension & Other Post Retirement Benefits	24,218			39,174
Pension & Other Post Retirement Benefits	(14,152		)	(28,846		)
Deferred Revenues	(9,266		)	(8,922		)
Net Operating Loss Carryforward	(8,764		)	(35,901		)
Other	3,524			464
Noncurrent Deferred Tax Liability – Net	$	380,975		$	310,357

SJG is included in the consolidated federal income tax return filed by SJI. The actual taxes, including credits, are allocated by SJI to its subsidiaries, generally on a separate return basis except for net operating loss and credit carryforwards. As of December 31, 2013 there were no income taxes due from SJI. As of December 31, 2012 income taxes due from SJI were approximately $4.6 million and are included in the balance sheets under the caption, Prepaid Taxes.

As of December 31, 2013, SJG has total federal net operating loss carryforwards of $103.7 million; $99.4 million of the federal NOL will expire in 2031 and $4.3 million will expire in 2032. A valuation allowance is recorded when it is more likely than not that any of our deferred income tax assets will not be realized. We believe that we will generate sufficient future taxable income to realize the income tax benefits related to our deferred tax assets.

A reconciliation of unrecognized tax benefits is as follows (in thousands):

	2013		2012		2011
Balance at January 1,	$	503	$	421	$	478
Increase as a result of tax position taken in prior years	44		82		119
Decrease due to a lapse in the statue of limitations	—		—		(90		)
Settlements	—		—		(86		)
Balance at December 31,	$	547	$	503	$	421

The total unrecognized tax benefits as of December 31, 2013 were $0.5 million, not including $0.6 million of accrued interest and penalties.  The total unrecognized tax benefits as of December 31, 2012 were $0.5 million not including $0.6 million of accrued interest and penalties. The total unrecognized tax benefits as of December 31, 2011 were $0.4 million, not including $0.6 million of accrued interest and penalties. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is not significant.  Our policy is to record interest and penalties related to unrecognized tax benefits as interest expense and other expense respectively. These amounts were not significant in 2013, 2012 or 2011. There have been no material changes to the unrecognized tax benefits during 2013, 2012 or 2011 and we do not anticipate any significant changes in the total unrecognized tax benefits within the next 12 months.

The unrecognized tax benefits are primarily related to an uncertainty of state income taxes.  Federal income tax returns from 2009 forward and state income tax returns from 2012 forward are open and subject to examination.

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FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2013

Investments, All Other Investments [Abstract]

FINANCIAL INSTRUMENTS

FINANCIAL INSTRUMENTS:

RESTRICTED INVESTMENTS - In accordance with the terms of our tax-exempt first mortgage bonds, unused proceeds are required to be escrowed pending approved construction expenditures. As of both December 31, 2013 and December 31, 2012, the escrowed proceeds, including interest earned, totaled $0.1 million. SJG established a margin account with SJRG in conjunction with SJG's risk management activities as detailed in Note 14. The funds provided by SJG will increase or decrease as the number and value of outstanding energy-related contracts held with SJRG changes. As of December 31, 2013 and December 31, 2012, the balance held with SJRG totaled $0.5 million and $1.1 million, respectively. During March 2013, SJG established a margin account with a counterparty in conjunction with SJG's risk management activities as detailed in Note 14. The funds provided by SJG will increase or decrease as the number and value of outstanding energy-related contracts held with this counterparty changes. The carrying amounts of the Restricted Investments approximate their fair value at December 31, 2013 and December 31, 2012, which would be included in Level 1 of the fair value hierarchy. (See Note 10 - Fair Value of Financial Assets and Financial Liabilities).

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 $15.0 million and $13.6 million as of December 31, 2013 and December 31, 2012, 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 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 December 31, 2013 and December 31, 2012.  The annual amortization to interest is not material to SJG’s financial statements.  The carrying amounts of these receivables approximate their fair value at December 31, 2013 and December 31, 2012, 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 that are not carried at fair value, including those financial instruments disclosed in this footnote, approximate their fair values at December 31, 2013 and December 31, 2012, 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 13 - Fair Value of Financial Assets and Financial Liabilities). The estimated fair values of SJG's long-term debt, including current maturities, as of December 31, 2013 and December 31, 2012, were $486.5 million and $502.0 million, respectively.  The carrying amounts of SJG's long-term debt, including current maturities, as of December 31, 2013 and December 31, 2012, were $475.0 million and $450.0 million, respectively.

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FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Total [Member]
Assets [Abstract]
Available-for-sale Securities	$ 8,696	[1]	$ 7,520	[1]
Derivatives - Energy Related Assets	1,500	[2]	766	[2]
Total Assets	10,196		8,286
Liabilities [Abstract]
Derivatives - Energy Related Liabilities	759	[2]	2,695	[2]
Derivatives - Other	3,735	[3]	7,761	[3]
Total Liabilities	4,494		10,456
Level 1 [Member]
Assets [Abstract]
Available-for-sale Securities	8,696	[1]	769	[1]
Derivatives - Energy Related Assets	1,409	[2]	447	[2]
Total Assets	10,105		1,216
Liabilities [Abstract]
Derivatives - Energy Related Liabilities	155	[2]	2,694	[2]
Derivatives - Other	0	[3]	0	[3]
Total Liabilities	155		2,694
Level 2 [Member]
Assets [Abstract]
Available-for-sale Securities	0	[1]	6,751	[1]
Derivatives - Energy Related Assets	91	[2]	319	[2]
Total Assets	91		7,070
Liabilities [Abstract]
Derivatives - Energy Related Liabilities	604	[2]	1	[2]
Derivatives - Other	3,735	[3]	7,761	[3]
Total Liabilities	4,339		7,762
Level 3 [Member]
Assets [Abstract]
Available-for-sale Securities	0	[1]	0	[1]
Derivatives - Energy Related Assets	0	[2]	0	[2]
Total Assets	0		0
Liabilities [Abstract]
Derivatives - Energy Related Liabilities	0	[2]	0	[2]
Derivatives - Other	0	[3]	0	[3]
Total Liabilities	$ 0		$ 0

[1] 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.

[2] 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. Management reviews and corroborates the price quotations to ensure the prices are observable which includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration.

[3] 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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DERIVATIVE INSTRUMENTS 2 (Details) (Not Designated as Hedging Instrument [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Fair value Derivative Assets	$ 1,500	$ 766
Fair value Derivative Liabilities	4,494	10,456
Commodity Contract [Member] | Derivatives-Energy Related-Current [Member]
Derivatives, Fair Value [Line Items]
Fair value Derivative Assets	1,222	464
Fair value Derivative Liabilities	711	2,615
Commodity Contract [Member] | Derivatives-Energy Related-NonCurrent [Member]
Derivatives, Fair Value [Line Items]
Fair value Derivative Assets	278	302
Fair value Derivative Liabilities	48	80
Interest Rate Contract [Member] | Derivatives-Other [Member]
Derivatives, Fair Value [Line Items]
Fair value Derivative Assets	0	0
Fair value Derivative Liabilities	$ 3,735	$ 7,761

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COMMITMENTS AND CONTINGENCIES (Details) (USD $)	12 Months Ended		408 Months Ended
	Dec. 31, 2013 unions sites	Dec. 31, 2012 sites	Dec. 31, 2013 unions
Loss Contingencies [Line Items]
Letter of credit provided	$ 210,000,000		$ 210,000,000
Monthly gas supply related demand charges and reservation fees	4,000,000
Estimated litigation liability	500,000	500,000	500,000
Percentage of personnel represented in collective bargaining agreements	60.00%		60.00%
Number of unions	2		2
Number of sites for environmental cleanup		12
Number of sites covered by insurance		11
Insurance policy limit		50,000,000.0
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning of Year	107,410,000	89,984,000
Accruals	22,264,000	26,552,000	326,500,000
Expenditures	(10,182,000)	(9,126,000)	(207,000,000)
End of Year	119,492,000	107,410,000	119,492,000
Standby Letter of Credit [Member]
Loss Contingencies [Line Items]
Letter of credit provided	25,200,000		25,200,000
Environmental Restoration Costs [Member]
Accrual for Environmental Loss Contingencies [Roll Forward]
Range of possible loss, minimum	119,500,000		119,500,000
Range of possible loss, maximum	223,500,000		223,500,000
Environmental Restoration Costs [Member] | Sites Comprising the Majority the Environmental Remediation [Member]
Accrual for Environmental Loss Contingencies [Roll Forward]
Range of possible loss, minimum	100,400,000		100,400,000
Range of possible loss, maximum	$ 192,800,000		$ 192,800,000
Number of sites affected by environmental remediation	6		6

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LINES OF CREDIT (Tables)

12 Months Ended

Dec. 31, 2013

Line of Credit Facility [Abstract]

Schedule of lines of credit

Credit facilities and available liquidity as of December 31, 2013 were as follows (in thousands):

	Total Facility		Usage		Available Liquidity		Expiration Date
Commercial Paper Program/ Revolving Credit Facility	$	200,000	$	65,500	$	134,500	May 2018
Uncommitted Bank Lines	10,000		—		10,000		August 2014
Total	$	210,000	$	65,500	$	144,500

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RETAINED EARNINGS (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity [Abstract]
Equity infusions from SJI	$ 25,000	$ 0	$ 0

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FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES

12 Months Ended

Dec. 31, 2013

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 December 31, 2013
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	8,696	$	8,696	$	—	$	—
Derivatives – Energy Related Assets (B)	1,500		1,409		91		—
	$	10,196	$	10,105	$	91	$	—
Liabilities
Derivatives – Energy Related Liabilities (B)	$	759	$	155	$	604	$	—
Derivatives – Other (C)	3,735		—		3,735		—
	$	4,494	$	155	$	4,339	$	—

As of December 31, 2012
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	7,520	$	769	$	6,751	$	—
Derivatives – Energy Related Assets (B)	766		447		319		—
	$	8,286	$	1,216	$	7,070	$	—
Liabilities
Derivatives – Energy Related Liabilities (B)	$	2,695	$	2,694	$	1	$	—
Derivatives – Other (C)	7,761		—		7,761		—
	$	10,456	$	2,694	$	7,762	$	—

(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. Management reviews and corroborates the price quotations to ensure the prices are observable which includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration.

(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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SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Notes)

12 Months Ended

Dec. 31, 2013

Valuation and Qualifying Accounts [Abstract]

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

SOUTH JERSEY GAS COMPANY

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

(In Thousands)

Col. A	Col. B		Col. C					Col. D		Col. E
			Additions
Classification	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts - Describe (a)			Deductions - Describe (b)		Balance at End of Period
Provision for Uncollectible
Accounts for the Year Ended
December 31, 2013	$	3,985	$	4,232	$	(41	)	$	3,623	$	4,553
Provision for Uncollectible
Accounts for the Year Ended
December 31, 2012	$	3,060	$	4,775	$	110		$	3,960	$	3,985
Provision for Uncollectible
Accounts for the Year Ended
December 31, 2011	$	4,577	$	1,410	$	562		$	3,489	$	3,060

(a) Recoveries of accounts previously written off and minor adjustments.

(b) Uncollectible accounts written off.

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FINANCIAL INSTRUMENTS (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Schedule of Financial Instruments [Line Items]
Term	5 years
Carrying amount of long-term debt	$ 475,000,000	[1]	$ 450,000,000	[1]
Fair Value, Inputs, Level 1 [Member]
Schedule of Financial Instruments [Line Items]
Restricted investments held in escrow	100,000		100,000
Margin accounts with selected counterparties to support risk management activities	500,000		1,100,000
Fair Value, Inputs, Level 2 [Member]
Schedule of Financial Instruments [Line Items]
Estimated fair value of long-term debt	486,500,000		502,000,000
Carrying amount of long-term debt	475,000,000		450,000,000
Fair Value, Inputs, Level 2 [Member] | Financing Receivable [Member]
Schedule of Financial Instruments [Line Items]
Long-term receivables, net of unamortized discount	15,000,000		13,600,000
Imputed interest on long term receivables	$ 1,300,000		$ 1,300,000

[1] Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2014, $21,000; 2015, $10,909; 2016, $27,909; 2017, $15,909; 2018, $38,909 .Our long-term debt agreements contain no financial covenants.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Accounting Policies [Abstract]
Equity investment impairments	$ 0		$ 0		$ 0
TEFA and PUA included in both utility revenue and cost of sales	5,200,000		6,000,000		8,000,000
Decrease in TEFA revenue based tax rate	25.00%		25.00%
Utility Plant:
Production Plant	296,000		296,000
Storage Plant	22,538,000		20,316,000
Transmission Plant	248,074,000		250,886,000
Distribution Plant	1,417,939,000		1,297,619,000
General Plant	53,162,000		49,586,000
Other Plant	1,855,000		1,855,000
Utility Plant in Service	1,743,864,000		1,620,558,000
Construction Work in Progress	72,940,000		38,232,000
Total Utility Plant	1,816,804,000		1,658,790,000
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO as of January 1,	38,892,000		29,388,000
Accretion	1,514,000		1,870,000
Additions	743,000		989,000
Settlements	(1,630,000)		(1,603,000)
Revisions in Estimated Cash Flows	1,659,000	[1]	8,248,000	[1]
ARO as of December 31,	41,178,000		38,892,000		29,388,000
Composite annual rate for all depreciable utility property	2.30%		2.40%		2.30%
Interest capitalized	$ 8,200,000		$ 6,500,000		$ 1,100,000

[1] The revision in estimated cash flows in 2013 reflects an increase in the inflation rate used to determine the ARO settlement amount. In 2012, the revision in estimated cash flows reflected increases in the contractual cost as well as changes in the discount rates used to determine the ARO. A corresponding increase was made to regulatory assets, thus having no impact on earnings.

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BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Property, Plant and Equipment:
Utility Plant, at original cost	$ 1,816,804		$ 1,658,790
Accumulated Depreciation	(392,029)		(373,199)
Property, Plant and Equipment - Net	1,424,775		1,285,591
Investments:
Available-for-Sale Securities	8,696		7,520
Restricted Investments	680		1,268
Total Investments	9,376		8,788
Current Assets:
Cash and Cash Equivalents	2,020		2,678
Accounts Receivable	60,317		49,071
Accounts Receivable - Related Parties	968		961
Unbilled Revenues	41,510		35,351
Provision for Uncollectibles	(4,553)		(3,985)
Natural Gas in Storage, average cost	20,811		13,896
Materials and Supplies, average cost	1,798		1,560
Deferred Income Taxes - Net	23,309		0
Prepaid Taxes	7,683		17,046
Derivatives - Energy Related Assets	1,222		464
Other Prepayments and Current Assets	3,819		3,343
Total Current Assets	158,904		120,385
Regulatory and Other Noncurrent Assets:
Regulatory Assets	296,081		352,656
Unamortized Debt Issuance Costs	6,523		6,663
Long-Term Receivables	10,252		9,336
Derivatives - Energy Related Assets	278		302
Other	2,937		2,738
Total Regulatory and Other Noncurrent Assets	316,071		371,695
Total Assets	1,909,126		1,786,459
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	225,972		201,050
Accumulated Other Comprehensive Loss	(10,869)	[1]	(13,285)	[1]
Retained Earnings	390,018		327,782
Total Common Equity	610,969		521,395
Long-Term Debt	454,000	[2]	425,000	[2]
Total Capitalization	1,064,969		946,395
Current Liabilities:
Notes Payable	65,500		102,100
Current Portion of Long-Term Debt	21,000	[2]	25,000	[2]
Accounts Payable - Commodity	24,232		14,926
Accounts Payable - Other	32,072		25,498
Accounts Payable - Related Parties	6,638		5,872
Derivatives - Energy Related Liabilities	711		2,615
Deferred Income Taxes - Net	0		10,432
Customer Deposits and Credit Balances	15,089		17,450
Environmental Remediation Costs	15,422		19,203
Taxes Accrued	1,767		1,674
Pension Benefits	1,241		1,236
Interest Accrued	6,039		6,277
Other Current Liabilities	5,629		6,492
Total Current Liabilities	195,340		238,775
Regulatory and Other Noncurrent Liabilities:
Regulatory Liabilities	60,949		56,517
Deferred Income Taxes - Net	380,975		310,357
Environmental Remediation Costs	104,070		88,207
Asset Retirement Obligations	41,178		38,892
Pension and Other Postretirement Benefits	48,197		89,193
Investment Tax Credits	360		618
Derivatives - Energy Related Liabilities	48		80
Derivatives - Other	3,735		7,761
Other	9,305		9,664
Total Regulatory and Other Noncurrent Liabilities	648,817		601,289
Commitments and Contingencies (Note 9)
Total Capitalization and Liabilities	$ 1,909,126		$ 1,786,459

[1] Determined using a combined statutory tax rate of 41%.

[2] Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2014, $21,000; 2015, $10,909; 2016, $27,909; 2017, $15,909; 2018, $38,909 .Our long-term debt agreements contain no financial covenants.

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STOCK-BASED COMPENSATION PLANS

12 Months Ended

Dec. 31, 2013

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 Option, Stock Appreciation Rights and Restricted Stock Award Plan ("Plan") of SJI. Restricted shares issued under this 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 between 0% to 150% of the original share units granted.

Grants containing market-based performance targets have been issued in each of the last three years and 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.

Beginning with 2012, grants containing earnings-based targets have also been issued. These new grants are based on SJI's earnings per share (EPS) growth rate relative to a peer group to measure performance. As EPS-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 goals.

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 December 31, 2013, and the assumptions used to estimate the fair value of the awards:

Grant Date	Shares Outstanding	Fair Value Per Share		Expected Volatility		Risk-Free Interest Rate
Jan. 2012 - TSR	3,533	$	51.23	22.5	%	0.43	%
Jan. 2012 - EPS	3,533	$	56.93	n/a		n/a
Jan. 2013 - TSR	4,001	$	44.38	21.1	%	0.40	%
Jan. 2013 - EPS	4,001	51.18		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 Officers' and other key employees' restricted shares. As notional dividend equivalents are credited to the holders, which are reinvested during the three year service period, no reduction to the fair value of the award is required.

The cost for restricted stock awards was $0.4 million in each of the years 2013, 2012 and 2011. Of these costs, $0.2 million was capitalized to Utility Plant in each of those years.

As of December 31, 2013, there was $0.4 million of total unrecognized compensation cost related to nonvested share-based compensation awards granted under the restricted stock plans. That cost is expected to be recognized over a weighted average period of 1.7 years.

The following table summarizes information regarding restricted stock award activity during 2013, excluding accrued dividend equivalents:

	Shares		Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, January 1, 2013	15,108		$	52.55
Granted	9,324		$	47.78
Vested*	(7,116	)	$	50.94
Cancelled / Forfeited	(2,248	)	$	50.02
Nonvested Shares Outstanding, December 31, 2013	15,068		$	50.73

* Performance targets during the 3-year vesting period were not attained for the January 2011 grant. As a result, no shares will be awarded in 2014.

During 2013, SJG awarded 12,901 shares that had vested at December 31, 2012, to its officers and other key employees at a market value of $0.6 million. During 2012, SJG awarded 7,098 shares at a market value of $0.4 million. SJG has a policy of making cash payments to SJI to satisfy its obligations under this plan. Cash payments to SJI during 2013 and 2012 were approximately $0.4 million and $0.3 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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PENSION AND OTHER POSTRETIREMENT BENEFITS 7 (Details) (Other Postretirement Benefits [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Other Postretirement Benefits [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
1 - Percentage Point Increase, Effect on the Total of Service and Interest Cost	$ 145
1 - Percentage Point Increase, Effect on Postretirement Benefit Obligation	2,406
1 - Percentage Point Decrease, Effect on the Total of Service and Interest Cost	(115)
1 - Percentage Point Decrease, Effect on Postretirement Benefit Obligation	$ (2,027)

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ACCUMULATED OTHER COMPREHENSIVE LOSS (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	$ (13,285)	[1]
Other comprehensive income before reclassifications	1,524
Amounts reclassified from AOCL	892	[2]
Other Comprehensive Gain (Loss) - Net of Tax	2,416	[1]	(1,156)	[1]	(3,009)	[1]
Ending balance	(10,869)	[1]	(13,285)	[1]
Combined statutory tax rate	41.00%
Postretirement Liability Adjustment [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	(12,958)	[1]	(11,275)	[1]	(8,599)	[1]
Other comprehensive income before reclassifications	932
Amounts reclassified from AOCL	1,354	[2]
Other Comprehensive Gain (Loss) - Net of Tax	2,286	[1]	(1,683)	[1]	(2,676)	[1]
Ending balance	(10,672)	[1]	(12,958)	[1]	(11,275)	[1]
Unrealized Gain (Loss) on Derivatives-Other [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	(621)	[1]	(648)	[1]	(675)	[1]
Other comprehensive income before reclassifications	0
Amounts reclassified from AOCL	27	[2]
Other Comprehensive Gain (Loss) - Net of Tax	27	[1]	27	[1]	27	[1]
Ending balance	(594)	[1]	(621)	[1]	(648)	[1]
Unrealized Gain (Loss) on Available-for-Sale Securities [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	294	[1]	(206)	[1]	154	[1]
Other comprehensive income before reclassifications	592
Amounts reclassified from AOCL	(489)	[2]
Other Comprehensive Gain (Loss) - Net of Tax	103	[1]	500	[1]	(360)	[1]
Ending balance	$ 397	[1]	$ 294	[1]	$ (206)	[1]

[1] Determined using a combined statutory tax rate of 41%.

[2] See table below.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

The Entity

The Entity - South Jersey Industries, Inc. (SJI) owns all of the outstanding common stock of South Jersey Gas Company (SJG). In our opinion, the 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. 

Certain reclassifications have been made to the prior periods regulatory assets disclosure to conform to the current period presentation. The deferred pipeline integrity cost previously included in "Other Regulatory Assets" was reclassified to the line item "Pipeline Integrity Cost" in the regulatory asset table disclosed in Note 4.

Equity Investments

Equity Investments - Marketable equity securities that are purchased as long-term investments are classified as Available-for-Sale Securities and carried at their fair value on our balance sheets. Any unrealized gains or losses are included in Accumulated Other Comprehensive Loss.  An impairment loss is recorded when there is clear evidence that a decline in value is other than temporary.  

Estimates and Assumptions

Estimates and Assumptions - We prepare our financial statements to conform with accounting principles generally accepted in the United States of America (GAAP). Management makes estimates and assumptions that affect the amounts reported in the financial statements and related disclosures. Therefore, actual results could differ from those estimates. Significant estimates include amounts related to regulatory accounting, energy derivatives, environmental remediation costs, pension and other postretirement benefit costs, and revenue recognition.

Regulation

Regulation- We are subject to the rules and regulations of the New Jersey Board of Public Utilities (BPU). See Note 3 for a detailed discussion of our rate structure and regulatory actions. We maintain our accounts according to the BPU’s prescribed Uniform System of Accounts. We follow the accounting for regulated enterprises prescribed by the FASB ASC Topic 980 – “Regulated Operations.”  In general, Topic 980 allows for the deferral of certain costs (regulatory assets) and creation of certain obligations (regulatory liabilities) when it is probable that such items will be recovered from or refunded to customers in future periods. See Note 4 for a detailed discussion of regulatory assets and liabilities.

Operating Revenues

Operating Revenues - Gas revenues are recognized in the period the commodity is delivered to customers. For retail customers that are not billed at the end of the month, we record an estimate to recognize unbilled revenues for gas delivered from the date of the last meter reading to the end of the month.

Revenue and Throughput-Based Taxes

Revenue and Throughput-Based Taxes - We collect certain revenue-based energy taxes from our customers. Such taxes include New Jersey State Sales Tax and Public Utilities Assessment (PUA). We also collect a throughput-based energy tax from customers in the form of a Transitional Energy Facility Assessment (TEFA). State sales tax is recorded as a liability when billed to customers and is not included in revenue or operating expenses.

Accounts Receivable and Provision for Uncollectible Accounts

Accounts Receivable and Provision for Uncollectible Accounts - Accounts receivable are carried at the amount owed by customers. A provision for uncollectible accounts is established based on our collection experience and an assessment of the collectibility of specific accounts.

Natural Gas in Storage

Natural Gas in Storage – Natural Gas in Storage is reflected at average cost on the balance sheets, and represents natural gas that will be utilized in the ordinary course of business.

Property, Plant & Equipment

Property, Plant & Equipment - For regulatory purposes, utility plant is stated at original cost, which may be different than our cost if the assets were acquired from another regulated entity. The cost of adding, replacing and renewing property is charged to the appropriate plant account.

Asset Retirement Obligations

Asset Retirement Obligations - The amounts included under Asset Retirement Obligations (ARO) are primarily related to the legal obligations we have to cut and cap our gas distribution pipelines when taking those pipelines out of service in future years. These liabilities are generally recognized upon the acquisition or construction of the asset. The related asset retirement cost is capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the liability. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

Depreciation

Depreciation - We depreciate utility plant on a straight-line basis over the estimated remaining lives of the various property classes. These estimates are periodically reviewed and adjusted as required after BPU approval. The composite annual rate for all depreciable utility property was approximately 2.3% in 2013, 2.4% in 2012 and 2.3% in 2011. The actual composite rate may differ from the approved rate as the asset mix changes over time. Except for retirements outside of the normal course of business, accumulated depreciation is charged with the cost of depreciable utility property retired, less salvage.

Capitalized Interest

Capitalized Interest - We capitalize interest on construction at the rate of return on rate base utilized by the BPU to set rates in our last base rate proceeding (See Note 3). Capitalized interest is included in Utility Plant on the balance sheets. Interest Charges are presented net of capitalized interest on the statements of income.  We capitalized interest of $8.2 million in 2013, $6.5 million in 2012 and $1.1 million in 2011. The increase in 2013 represents the interest on the Company's investment in Utility Plant under the BPU-approved CIRT and AIRP programs. Under the CIRT and AIRP, qualified capital expenditures continued to accrue interest on construction until such projects were rolled into customer rates and recovery of the expenditures commenced.

All CIRT program investments have been rolled into rate base and the CIRT program is now concluded. See Note 3 for additional discussion of the CIRT programs.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets - We review the carrying amount of long-lived assets for possible impairment whenever events or changes in circumstances indicate that such amounts may not be recoverable. For the years ended 2013, 2012 and 2011, no significant impairments were identified.

Derivative Instruments

Derivative Instruments - SJG, through its affiliate, South Jersey Resources Group (SJRG) and another counterparty, uses a variety of derivative instruments to limit its exposure to market risk in accordance with strict guidelines (See Note 14).  These contracts, which 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 balance sheets.  The costs or benefits of these short-term contracts are recoverable through SJG’s Basic Gas Supply Service (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 balance sheets.

SJG 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 balance sheets.  The fair value represents the amount SJG would have to pay the counterparty to terminate these contracts as of those dates.  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 Other Regulatory Assets in the balance sheets.

Income Taxes

Income Taxes - Deferred income taxes are provided for all significant temporary differences between the book and taxable basis of assets and liabilities in accordance with FASB ASC Topic 740 – “Income Taxes” (See Note 6). A valuation allowance is established when it is determined that it is more likely than not that a deferred tax asset will not be realized.

Cash and Cash Equivalents

Cash and Cash Equivalents - For purposes of reporting cash flows, highly liquid investments with original maturities of three months or less are considered cash equivalents.

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS- Other than as described below, no new accounting pronouncement issued or effective during 2013, 2012 or 2011 had, or is expected to have, a material impact on the financial statements.

In January 2012, the FASB issued Accounting Standards Update (ASU) 2011-11, Enhanced Disclosure Requirements Concerning Offsetting of Financial Assets and Financial Liabilities. This ASU amends ASC 210-20 to add disclosure requirements in respect of the offsetting of financial assets and financial liabilities. In February 2013, the FASB issued ASU 2013-01 Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which amends and clarifies the scope of the balance sheet offsetting disclosures required through ASU 2011-11. The new guidance was effective for fiscal years beginning on or after January 1, 2013. The adoption of this guidance modified the disclosures around derivative instruments, but did not have an impact on the Company's financial statement results.

In February 2013, the FASB issued ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This ASU expands the disclosure requirements in ASC 220 and requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective lines in net income. The ASU requires an entity to present information about significant items reclassified out of accumulated other comprehensive income by component either on the face of the statement where net income is presented, or as a separate disclosure in the notes to the financial statements. The new guidance was effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. The adoption of this guidance modified the disclosures around accumulated other comprehensive income, but did not have an impact on the Company's financial statement results.

In July 2013, the FASB issued ASU 2013-11, Balance Sheet Presentation of an Unrecognized Income Tax Benefit for a Net Operating Loss or Tax Credit Carryforward. This ASU provides that a liability related to an unrecognized tax benefit should be offset against a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. Management does not anticipate that the adoption of this guidance will have an impact on the Company's 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. Management reviews and corroborates the price quotations to ensure the prices are observable which includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration.

(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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DERIVATIVE INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of notional amounts of outstanding derivative positions

As of December 31, 2013, SJG’s active interest rate swaps were as follows:

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

Fair value of derivative instruments

The fair values of all derivative instruments, as reflected in the balance sheets as of December 31, 2013 and December 31, 2012, are as follows (in thousands):

Derivatives not designated as hedging instruments under GAAP	2013				2012
	Assets		Liabilities		Assets		Liabilities
Energy related commodity contracts:
Derivatives – Energy Related – Current	$	1,222	$	711	$	464	$	2,615
Derivatives – Energy Related – Non-Current	278		48		302		80
Interest rate contracts:
Derivatives – Other	—		3,735		—		7,761
Total derivatives not designated as hedging instruments under GAAP	$	1,500	$	4,494	$	766	$	10,456

Offsetting arrangements

For derivative instruments disclosed in the table above, information as to the presentation on the condensed balance sheets is as follows (in thousands):

As of December 31, 2013
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	$	1,500		$	—	$	1,500		$	(155	)	(A)	$	(498	)	$	847
Derivatives - Energy Related Liabilities	(759		)	—		(759		)	155			(B)	—			(604		)
Derivatives - Other	(3,735		)	—		(3,735		)	—				—			(3,735		)

As of December 31, 2012
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	$	766		$	—	$	766		$	(447	)	(A)	$	—	$	319
Derivatives - Energy Related Liabilities	(2,695		)	—		(2,695		)	447			(B)	1,136		(1,112		)
Derivatives - Other	(7,761		)	—		(7,761		)	—				—		(7,761		)

(A) The balances at December 31, 2013 and December 31, 2012 were related to derivative liabilities which can be net settled against derivative assets.

(B) The balances at December 31, 2013 and December 31, 2012 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 statements of income for 2013 , 2012 and 2011 are as follows (in thousands):

	Year ended December 31,
Derivatives in Cash Flow Hedging Relationships	2013			2012			2011
Interest Rate Contracts:
Losses reclassified from accumulated OCI into income (a)	$	(46	)	$	(46	)	$	(46	)

(a) Included in Interest Charges

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES:

Standby Letter of Credit - SJG 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 New Jersey Economic Development Authority (NJEDA) to finance the expansion of SJG’s natural gas distribution system. 

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 2014. 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 $4.0 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 $0.5 million related to all claims in the aggregate, as of both December 31, 2013 and December 31, 2012. 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 60% of our workforce at December 31, 2013. The Company has collective bargaining agreements with two unions who represent these employees: the International Brotherhood of Electrical Workers (IBEW) that operates under a collective bargaining agreement that runs through February 28, 2017. The remaining unionized employees are represented by the International Association of Machinists and Aerospace Workers (IAM). Employees represented by the IAM operate under a collective bargaining agreement that expires in August 2014.

Environmental Remediation Costs - We incurred and recorded costs for environmental cleanup of 12 sites where we or our predecessors operated gas manufacturing plants. We stopped manufacturing gas in the 1950s.

We successfully entered into settlements with all of our historic comprehensive general liability carriers regarding the environmental remediation expenditures at our sites. Also, we had purchased a Cleanup Cost Cap Insurance Policy limiting the amount of remediation expenditures that we were required to make at 11 of our sites. This policy provided coverage up to $50.0 million, which was exhausted in 2012.

Since the early 1980s, we accrued environmental remediation costs of $326.5 million, of which $207.0 million has been spent as of December 31, 2013. The following table details the amounts accrued and expended for environmental remediation at December 31 (in thousands):

	2013			2012
Beginning of Year	$	107,410		$	89,984
Accruals	22,264			26,552
Expenditures	(10,182		)	(9,126		)
End of Year	$	119,492		$	107,410

The balances are segregated between current and noncurrent on the balance sheets under the captions Current Liabilities and Regulatory and Other Noncurrent Liabilities.

Management estimates that undiscounted future costs to clean up our sites will range from $119.5 million to $223.5 million. We recorded the lower end of this range, $119.5 million, as a liability because a single reliable estimation point is not feasible due to the amount of uncertainty involved in the nature of projected remediation efforts and the long period over which remediation efforts will continue. Six of our sites comprise the majority of these estimates, the sum of the six sites range from a low of $100.4 million to a high of $192.8 million. Recorded amounts include estimated costs based on projected investigation and remediation work plans using existing technologies. Actual costs could differ from the estimates due to the long-term nature of the projects, changing technology, government regulations and site-specific requirements. Significant risks surrounding these estimates include unforeseen market price increases for remedial services, property owner acceptance of remedy selection, regulatory approval of selected remedy and remedial investigative findings.

The remediation efforts at our six most significant sites include the following:

Site 1 - Several interim remedial actions have been completed at the site. Steps remaining to remediate the balance of the site include completion of the remedial investigation of impacted soil and groundwater, selection of the appropriate remedial action, receiving confirmation of regulatory compliance of the selected remedy, and implementation of the approved remedy.

Site 2 - Remediation of the site is underway in accordance with the approved Remedial Action Work plan. Steps remaining to remediate the site include continued excavation of impacted soil and post remediation groundwater monitoring.

Site 3 - Various remedial investigation activities have been completed at this site and a final site remedy has been proposed to the regulatory authority.  Steps remaining to remediate the site include receiving confirmation of regulatory compliance of the selected remedy and implementation of the approved remedy.

Site 4 - Remedial investigation activities are ongoing at this site including pilot studies of potential remedial alternatives and continued soil and groundwater investigation.  Remaining steps to remediate include completion of the remedial investigation of impacted soil and groundwater, selection of the appropriate remedial action, receiving confirmation of regulatory compliance of the selected remedy, and implementation of the approved remedy.

Sites 5 and 6 - Remedial investigation activities are ongoing at these sites.  Remaining steps to remediate include completion of the remedial investigation of impacted soil and groundwater, selection of the appropriate remedial action, receiving confirmation of regulatory compliance of the selected remedy, and implementation of the approved remedy.