SOUTH JERSEY GAS Co - FORM 10-K

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EXCEL - IDEA: XBRL DOCUMENT - SOUTH JERSEY GAS Co	Financial_Report.xls
EX-32.2 - EXHIBIT 32.2 - SOUTH JERSEY GAS Co	sjg-123114ex322.htm
EX-32.1 - EXHIBIT 32.1 - SOUTH JERSEY GAS Co	sjg-123114ex321.htm
EX-12 - EXHIBIT 12 - SOUTH JERSEY GAS Co	sjg-123114exh12.htm
EX-31.2 - EXHIBIT 31.2 - SOUTH JERSEY GAS Co	sjg-123114ex312.htm
EX-31.1 - EXHIBIT 31.1 - SOUTH JERSEY GAS Co	sjg-123114ex311.htm

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, 2014



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, an Exchange Act reporting company named in the registrant's description of its business, which has itself fulfilled its Exchange Act filing requirements.

The registrant meets all of the conditions set forth in General Instruction I1(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	9
Item 2.	Properties	10
Item 3.	Legal Proceedings	10
Item 4.	Mine Safety Disclosures	10

	PART II

Item 5.	Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	10
Item 6.	Selected Financial Data	11
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	12
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	25
Item 8.	Financial Statements and Supplementary Data	27
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	69
Item 9A.	Controls and Procedures	69
Item 9B.	Other Information	70

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	70
Item 11.	Executive Compensation	70
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	70
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	72

Signatures		76
Financial Statement Schedules		77

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 Company (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 SJI's 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.

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 to the financial statements.

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 to the financial statements.

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 2014, SJG purchased and had delivered approximately 42.0 million decatherms (MMdts) of natural gas for distribution to both on-system and off-system customers and for injections into storage. Of this total, 26.3 MMdts were transported on the Transco pipeline system while 15.7 MMdts were transported on the Columbia pipeline system. Moreover, during 2014 third-party suppliers delivered 35.3 MMdts to SJG's system on behalf of end use customers behind our city gate stations. SJG also secures other long-term services from Dominion Transmission, Inc. (Dominion), a pipeline upstream of the Transco and Columbia systems. 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.

Of the 297,958 dts/d of Transco services mentioned above, SJG has released a total of 20,000 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 a total of 50,000 dts/d of its long-haul FT as part of Asset Management Agreements (AMA). The AMA-related releases are discussed below under “Gas Supplies.”

SJG currently has six 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 provide for an aggregate of 54,022 dts/d of firm service with 45,022 dts/d of this deliverability extending through October 31, 2019. The remaining 9,000 dts/d was extended through October 31, 2017. SJG released 8,671 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 45,351 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/d 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, 2016.

Gas Supplies

During 2014, SJG entered into an AMA with a gas marketer which extends through March 31, 2015. 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 through March 31, 2015. The marketer's intent was to optimize the capacity released to it under this AMA and pay SJG a monthly asset management fee.

Also during 2014, SJG entered into two additional AMA's with two separate gas marketers which both extend through October 31, 2015. Under these agreements, SJG has released to each of the marketers firm transportation rights equal to 10,000 dts/d of transportation capacity on Transco. The marketers manages this capacity and provides SJG with up to 10,000 dts/d each of firm deliverability every day through October 31, 2015. The marketers will seek to optimize the capacity released to it under these AMA's and pay SJG a one-time asset management fee.

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 start at 6,250 dts/d and ratchet 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 the New Jersey Board of Public Utilities (BPU) approval.

Supplemental Gas Supplies

During 2014, SJG purchased Liquefied Natural Gas (LNG) from a third party LNG supplier. This LNG was purchased as a supply source to replenish its LNG inventory at its storage facility, located in McKee City, NJ. SJG purchased LNG from this supplier during the 2013-14 winter season, the 2014 summer season and the 2014-15 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 2014-2015 winter season is estimated to be 487,997 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 2014 of 495,056 dts (including industrial customers) on January 7th, while experiencing an average temperature of 11.2 degrees F that day.

Natural Gas Prices

SJG’s average cost of natural gas purchased and delivered in calendar years 2014, 2013 and 2012, including demand charges, was $6.56 per dt, $4.81 per dt and $4.73 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 be expected to have a material adverse effect on SJG’s business.

Backlog

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

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 481 employees as of December 31, 2014. Of that total, 284 employees are unionized. There are 37 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 runs through August 31, 2017.

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 the 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 (BPU) 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.

•

Warm weather, high commodity costs, or customer conservation initiatives could result in reduced demand for natural gas. SJG currently has a conservation incentive program clause that protects its revenues and gross margin against usage that is lower than a set level. Should this clause be terminated 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 but $59.0 million of 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 to a significant degree 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 even if 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.

•

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.

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, 2014, there were approximately 122.7 miles of mains in the transmission systems and 6,339 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, 2014, SJG’s utility plant had a gross book value of $2.0 billion and a net book value, after accumulated depreciation, of $1.6 billion. In 2014, $200.0 million was spent on additions to utility plant and there were retirements of property having an aggregate gross carrying value of $16.6 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, 2014 and 2013. 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

All of the outstanding common stock of SJG (its only class of equity securities) is owned by its parent company, South Jersey Industries, Inc. The common stock is not traded on any stock exchange.

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, 2014, these restrictions did not affect the amount that may be distributed from SJG’s retained earnings. SJG declared and paid dividends totaling $18.2 million on its common stock in 2014; no dividends were declared and paid on SJG’s common stock in 2013.

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,
	2014		2013		2012		2011		2010
Operating Revenues	$	501,875	$	446,480	$	421,874	$	412,449	$	475,982

Operating Income	$	113,690	$	105,822	$	101,762	$	102,663	$	90,701

Net Income	$	66,483	$	62,236	$	58,241	$	52,889	$	43,925

Average Shares of Common Stock Outstanding	2,339		2,339		2,339		2,339		2,339

Ratio of Earnings to Fixed Charges (1)	5.4x		5.3x		5.5x		5.3x		5.1x



	As of December 31,
	2014		2013		2012		2011		2010
Property, Plant and Equipment, Net	$	1,589,369	$	1,424,775	$	1,285,591	$	1,158,029	$	1,046,804

Total Assets	$	2,185,672	$	1,909,126	$	1,786,459	$	1,615,723	$	1,468,635

Capitalization:
Common Equity	$	680,568	$	610,969	$	521,395	$	464,186	$	426,885
Long-Term Debt	507,091		454,000		425,000		362,813		340,000
Total Capitalization	$	1,187,659	$	1,064,969	$	946,395	$	826,999	$	766,885

Total Customers	366,854		362,256		357,306		351,304		347,725

(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.

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 117 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 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.

We believe there is an 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 also contributed to our growth. In 2014, 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, 2014, we served 366,854 residential, commercial and industrial customers in southern New Jersey, compared with 362,256 customers at December 31, 2013. No material part of our business is dependent upon a single customer or a few customers. Gas sales, transportation and capacity release for 2014 amounted to 138.2 MMdts (million dekatherms), of which 65.2 MMdts were firm sales and transportation, 1.4 MMdts were interruptible sales and transportation and 71.6 MMdts were off-system sales and capacity release. The breakdown of firm sales and transportation includes 42.6% residential, 19.4% commercial, 20.6% industrial, and 17.4% cogeneration and electric generation. At year-end 2014, we served 342,155 residential customers, 24,253 commercial customers and 446 industrial customers. This includes 2014 net additions of 4,219 residential customers and 380 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 2014, off-system sales amounted to 9.4 MMdts and capacity release amounted to 62.2 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 2014, usage by interruptible customers, excluding off-system customers, amounted to 1.4 MMdts, approximately 1.0% of the total throughput.

Our primary goals are to: 1) provide safe, reliable natural gas service at the lowest cost reasonably 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.

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 expect to 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 1.3% for 2014 as we increased our focus on customer conversions. In 2014, the 5,790 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 4,689 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 an 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. The BPU also issued an Order in August 2014 approving the Storm Hardening and Reliability Program (SHARP), a $103.5 million program to replace low-pressure distribution mains and services with high-pressure mains and services on the barrier islands over a three-year period, with annual investments of approximately $34.5 million. The Company earns a return on SHARP investments until they are included in rate base through annual rate adjustments.

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 seek 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.

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 51% and 53% at the end of 2014 and 2013, respectively. A strong balance sheet assists us in maintaining 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.

Regulatory Accounting- We maintain our accounts according to the Uniform System of Accounts as prescribed by the 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 such 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 Generally Accepted Accounting Principles (United States), 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.

Discount rates declined in 2012 and were the primary cost drivers 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 experienced a $4.8 million decrease in the cost of providing such benefits in 2014. During 2014, discount rates fell back to the low point experienced in 2012. This decrease in discount rates, coupled with lower than expected returns on plan assets and the impact of new mortality tables released by the Society of Actuaries in late 2014, result in an expected $5.2 million increase in the cost of providing such benefits in 2015. Management took measures to mitigate this increase by contributing an aggregate of $14.5 million to its pension and postretirement healthcare plans in January 2015. These contributions are expected to earn $1.0 million, resulting in an estimated net increase in retirement benefit costs of $4.2 million in 2015. 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).

SJG filed a petition in March 2013 to extend the Conservation Incentive Program (CIP) program and, in May 2014, the BPU approved the continuation of the CIP, with certain modifications. Each CIP year begins October 1 and ends September 30 of the subsequent year. On a monthly basis during a 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 (AIRP and SHARP), 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 included $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, SJG filed a base rate case with the BPU to increase base rates to obtain a certain level of return on capital investments. In September 2014, the BPU granted SJG a base rate increase of $20 million, which was predicated, in part, upon a 7.10% rate of return on rate base that included a 9.75% return on common equity. The $20 million includes approximately $7.5 million of revenue associated with previously approved Accelerated Infrastructure Replacement Program (AIRP) investments that were rolled into base rates. SJG was also permitted to recover certain regulatory assets and to reduce its composite depreciation rate from 2.4% to 2.1% These changes became effective on October 1, 2014.

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 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 and, in May 2014, the BPU approved the continuation of the CIP, with certain modifications.

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):



	2014			2013			2012
Net Income Benefit:
CIP – Weather Related	(4.7		)	(0.3		)	9.4
CIP – Usage Related	2.0			3.4			5.8
Total Net Income Benefit	$	(2.7	)	$	3.1		$	15.2

Weather Compared to 20-Year Average	7.5% colder			0.6% colder			17.7% warmer
Weather Compared to Prior Year	4.6% colder			20.6% colder			8.6% 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 9.75% (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.

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 41,837, 46,872, and 39,398 during 2014, 2013 and 2012, respectively.

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):



	2014				2013				2012
Utility Throughput – dth:
Firm Sales -
Residential	24,508		18	%	22,070		20	%	18,586		14	%
Commercial	5,530		4	%	5,408		5	%	4,733		4	%
Industrial	283		—		292		—		258		1	%
Cogeneration and electric generation	1,035		1	%	1,562		1	%	1,598		1	%
Firm Transportation -
Residential	3,291		2	%	3,319		3	%	2,335		2	%
Commercial	7,103		5	%	6,780		6	%	5,587		4	%
Industrial	13,168		10	%	13,051		12	%	12,892		10	%
Cogeneration and electric generation	10,307		7	%	7,977		7	%	9,816		8	%
Total Firm Throughput	65,225		47	%	60,459		54	%	55,805		44	%
Interruptible Sales	—		—		14		—		2		—
Interruptible Transportation	1,401		1	%	1,452		1	%	1,361		1	%
Off-System	9,411		7	%	9,685		9	%	8,318		6	%
Capacity Release	62,193		45	%	40,088		36	%	63,998		49	%
Total Utility Throughput	138,230		100	%	111,698		100	%	129,484		100	%
Utility Operating Revenues:
Firm Sales-
Residential	$	279,797	56	%	$	246,227	56	%	$	248,547	59	%
Commercial	63,584		13	%	57,126		13	%	53,726		13	%
Industrial	4,070		1	%	3,485		1	%	2,872		—
Cogeneration and electric generation	6,037		1	%	8,144		2	%	6,562		2	%
Firm Transportation -
Residential	20,648		4	%	21,392		5	%	16,388		4	%
Commercial	30,850		6	%	28,165		6	%	24,217		6	%
Industrial	25,737		5	%	23,551		5	%	21,637		5	%
Cogeneration and electric generation	9,531		2	%	6,982		2	%	7,555		2	%
Total Firm Revenues	440,254		88	%	395,072		90	%	381,504		91	%
Interruptible Sales	15		—		342		—		52		—
Interruptible Transportation	1,694		—		1,827		—		1,546		—
Off-System	52,809		11	%	41,488		9	%	30,249		7	%
Capacity Release	5,835		1	%	6,384		1	%	7,322		2	%
Other	1,268		—		1,367		—		1,201		—
Total Utility Operating Revenues	501,875		100	%	446,480		100	%	421,874		100	%
Less:
Cost of sales	231,216				200,081				188,710
Conservation recoveries *	24,836				15,909				9,019
RAC recoveries *	8,255				8,137				7,824
EET Recoveries *	4,169				4,509				3,350
Revenue taxes	1,141				5,247				5,974
Utility Margin **	$	232,258			$	212,597			$	206,997




Utility Margin:
Residential	$	159,780		69	%	$	138,136	65	%	$	118,015	57	%
Commercial and industrial	65,492			29	%	57,495		27	%	51,048		25	%
Cogeneration and electric generation	5,343			2	%	5,022		2	%	5,062		2	%
Interruptible	81			—		114		—		83		—
Off-system & capacity release	3,023			1	%	2,070		1	%	2,044		1	%
Other revenues	2,131			1	%	1,752		1	%	1,602		1	%
Margin before incentive mechanisms	235,850			102	%	204,589		96	%	177,854		86	%
CIRT mechanism	—			—	%	2,204		1	%	3,031		2	%
CIP mechanism	(4,529		)	(2	)%	5,310		3	%	25,672		12	%
EET mechanism	937			—		494		—		440		—
Utility Margin **	$	232,258		100	%	$	212,597	100	%	$	206,997	100	%
Number of Customers at Year End:
Residential	342,155			93	%	337,936		93	%	333,347		93	%
Commercial	24,253			7	%	23,873		7	%	23,506		7	%
Industrial	446			—		447		—		453		—
Total Customers	366,854			100	%	362,256		100	%	357,306		100	%
Annual Degree-Days***	4,872					4,658				3,862

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

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

*** Each day, each degree of average daily temperature below 65 degrees Fahrenheit is counted as one heating degree-day. Annual degree-days is the sum of the daily totals.

Throughput - Total gas throughput increased 26.5 million decatherms (MMdts), or 23.8%, from 2013 to 2014 primarily due to higher capacity release. Capacity release increased 22.1 MMdts as a result of the expiration of an Asset Management Agreement (AMA) that was in effect during 2013. Volumes released under AMA's are not included in the throughput table above. The capacity previously committed under the expired AMA was available to be released during 2014. While capacity release can create significant volatility in throughput, it has little impact on revenue and margin generated from such activity. Firm throughput increased 4.8 MMdts, or 7.9%, during 2014 as a result of weather that was 4.6% colder than the previous year and the addition of 4,598 customers during 2014, representing 1.3% customer growth. In addition, supply disruptions at a cogeneration facility in our territory during 2014 created opportunity for SJG. That customer was being supplied directly by an interstate pipeline. However, with the disruption, SJG has been transporting a significant volume of commodity to this cogeneration facility to meet its needs. Partially offsetting these increases was a 0.5 MMdts reduction in electric generation firm sales to a regional electric generation customer. This resulted from lower weather-driven demand for electric generation during the 2014 summer season as weather was not as hot as in the previous summer.

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 during 2013, representing 1.4% customer growth.

Operating Revenues – Revenues increased $55.4 million, or 12.4%, during 2014 compared with 2013, due to higher firm sales and Off-System Sales (OSS). Total firm revenue increased $45.2 million, or 11.4%, in 2014 as a result of 4.6% colder weather and 4,598 additional customers compared with 2013, as previously discussed under "Throughput." While colder weather increased firm sales revenue, the revenue increase has little impact on Company profitability under the operation of the Conservation Incentive Program, as discussed below under the captions "Conservation Incentive Program (CIP)" and "Margin (pre-tax)." As further discussed under "Margin (pre-tax)", the roll in of certain capital investments into base rates effective October 1, 2013, increased revenue by approximately $10.4 million during 2014. Effective October 1, 2014, the Company also had a base rate increase and a 22.1% increase in its periodic BGSS rate, as discussed in Note 3 and 4 to the Financial Statements. The impact of the these rate increases on revenue was $7.1 million and $4.9 million, respectively.

Higher OSS unit prices resulted in a $11.3 million, or 27.3%, increase in OSS revenues during 2014, compared with 2013. Colder weather led to greater demand during the first quarter of 2014, 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 return 85% of the profits of such activity to its ratepayers. Earnings from OSS can be seen in the "Margin" table above.

Revenues increased $24.6 million, or 5.8%, during 2013 compared with 2012 due to higher firm sales and 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".

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, as previously stated, the impact of changes in OSS activity does not have a material impact on the earnings of SJG.

Margin (pre-tax) - 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 BPU through our BGSS tariff.

Total Margin in 2014 increased $19.7 million, or 9.2%, from 2013 primarily due to the settlement of the base rate case effective October 1, 2014, CIRT investments that rolled into base rates effective October 1, 2013 and customer additions. The base rate case settlement contributed approximately $7.1 million in additional margin during the fourth quarter of 2014. The CIRT investments rolling into base rates effective October 1, 2013 contributed approximately $10.4 million in incremental margin through September 2014. In addition, SJG added 4,598 net customers over the twelve-month period ended December 31, 2014.

The CIP tracking mechanism adjusts earnings when actual usage per customer experienced during the period varies from an established baseline usage per customer. As reflected in the margin table and the CIP table above, the CIP mechanism reduced margin by $4.5 million, or $2.7 million after taxes, during 2014, primarily due to weather that was colder than normal. The CIP protected $5.3 million, or $3.1 million after taxes, of margin during the same period in 2013 that would have been lost due to lower customer usage.

Total margin in 2013 increased $5.6 million, or 2.7%, from 2012 primarily due to customer additions. SJG added 4,950 net 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.

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



	2014 vs. 2013			2013 vs. 2012
Operations	$	16,623		$	7,380
Maintenance	$	322		$	(480	)
Depreciation	$	3,549		$	2,713
Energy and Other Taxes	$	(4,102	)	$	(438	)

Operations – Operations expense increased $16.6 million during 2014, as compared with 2013. 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 $8.6 million in 2014, as compared to 2013. Such costs are recovered on a dollar-for-dollar basis; therefore, SJG experienced an offsetting increase in revenues during 2014.


•	Expenses associated with write-offs of uncollectible customer accounts receivable increased $3.6 million in 2014, as compared with 2013. The increase in write-offs results from an increase in the aging of receivables.

•

SJG also increased its reserve for uncollectible accounts, resulting in $1.3 million of additional expense in 2014, as compared to 2013. Changes in the uncollectible reserve are the result of fluctuations in levels of customer accounts receivables balances. Accounts receivable was higher as of December 31, 2014 due to higher customer billing rates, as approved by the BPU effective October 1, 2014, in addition to customer growth.


•	Distribution operations expense increased $1.0 million in 2014, compared with 2013, as a result of extremely harsh weather conditions, primarily in the first quarter of 2014 when the region was hit by a polar vortex and near record snowfall.


•	Customer accounting expense increased $1.3 million in 2014, compared with 2013, due to the need for additional resources to allow for testing, training and other transition costs associated with implementing a new customer service system.

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.

Maintenance – Maintenance expense increased $0.3 million during 2014, compared with 2013, primarily due to the amortization of previously deferred costs that were approved for recovery in the Company's September 2014 rate case settlement. See Notes 3 and 4 to the financial statements.

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.

Depreciation - Depreciation expense increased $3.5 million and $2.7 million in 2014 and 2013, respectively, due mainly to our continuing investment in utility plant. SJG’s investment in utility plant during 2014, 2013 and 2012 was $200.0 million, $161.5 million and $156.0 million, respectively. The increased spending in recent years was a direct result of New Jersey's stimulus and infrastructure improvement efforts, which included the approval of SJG’s Capital Investment Recovery Tracker, Accelerated Infrastructure Replacement Program and Storm Hardening and Reliability Program, as discussed under “Rates and Regulation.”

Energy and Other Taxes – Energy and Other Taxes decreased $4.1 million and $0.4 million in 2014 and 2013, respectively. The 2014 reduction was due to the elimination of the Company's primary energy tax, the Transitional Energy Facilities Assessment (TEFA), 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. TEFA rates were lower in 2013 than 2012 as the TEFA was phasing out. However, higher taxable firm throughput resulted from 20.6% colder weather, as compared to 2012, and partially offset the impact of lower rates.

Other Income and Expense - Other income and expense was higher in 2014 and 2013, when compared with 2012, primarily due to gains on the sale of certain available-for-sale securities during 2014 and 2013 in the amount of $0.9 million and $0.8 million, respectively. No such gain occurred in 2012. Also adding to Other Income in 2014 was a higher allowance for equity funds used during construction as the Company made significant investment in new technology systems, as well as increasing investment in its natural gas distribution system.

Interest Charges – Interest charges increased $5.3 million in 2014, compared with 2013. This was primarily related to an incremental $68.0 million of higher-priced, long-term debt outstanding. In addition, capital investments under the Company's CIRT were permitted by the BPU to accrue interest on construction, which reduces interest expense, until such time they were rolled into base rates. With the roll in of the CIRT investment effective October 1, 2013, the resulting reduction of interest expense from this major program ceased.

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

Income Taxes – Income tax expense generally fluctuates as income before taxes changes. In 2014, SJG benefited from a $3.1 million State tax apportionment adjustment that lowered the Company's effective New Jersey Corporate Business Tax rate.

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 BGSS 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 $103.5 million in 2014, $148.8 million in 2013 and $93.4 million in 2012.

Net cash provided by operations declined in 2014 as compared with 2013 due to higher working capital requirements primarily as a result of higher gas costs which resulted from the extremely cold weather during the first three months of 2014. A portion of these higher gas costs was deferred and will be collected in future periods under the BGSS. These higher working capital needs were partially offset as SJG did not make a pension contribution during the first quarter of 2014, as compared to a contribution of $9.1 million for the first quarter of 2013. No contribution was required in 2014 due to an increase in the discount rate used to calculate the future liability and greater than expected asset performance, which significantly improved the pension plans' funding status.

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 pension plan'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 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 $200.0 million, $161.5 million and $156.0 million in 2014, 2013 and 2012, 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.”

For capital expenditures, including those under the CIRT and AIRP, SJG expects to 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 may 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.

In January 2014, SJG issued $30.0 million aggregate principal amount of 4.23% Medium Term Notes (MTN's) due January 2030. In June 2014, SJG entered into a $200.0 million multiple-draw term facility offered by a syndicate of banks, which expires in June 2017. SJG can draw under this facility through June, 2016 and this facility bears interest at a floating rate based on a variable base rate or LIBOR plus, in each case, a spread determined by SJG's credit ratings. As of December 31, 2014, SJG had borrowed an aggregate $59.0 million under this facility and the proceeds were used to pay down short-term debt.

In July 2014, SJG retired $11.0 million aggregate principal amount of 4.52% MTN's at maturity. In September 2014, SJG retired $10.0 million aggregate principal amount of 5.115% MTN's at maturity.

In the second quarter of 2014, SJG received equity infusions totalling $25.0 million from SJI. SJI also contributed an equity infusion of $25.0 million in 2013.

Credit facilities and available liquidity as of December 31, 2014 were as follows (in thousands):



	Total Facility		Usage		Available Liquidity		Expiration Date
Commercial Paper/Revolving Credit Facility	$	200,000	$	101,400	$	98,600	May 2018

Uncommitted Bank Lines	10,000		—		10,000		August 2015

Total	$	210,000	$	101,400	$	108,600

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, 2014.

SJG has 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, 2014 and 2013 were $52.3 million and $91.4 million, respectively. The maximum amount outstanding under these credit facilities during the twelve months ended December 31, 2014 and 2013 were $105.0 million and $121.9 million, respectively.

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

SJG supplements its operating cash flow and credit lines with both debt and equity capital. Over the years, 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 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. There is no capacity remaining under this petition as it was fully utilized when the company entered into the $200.0 million multiple-draw term facility discussed above.

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



	2014		2013
Common Equity	51	%	53	%
Long-Term Debt	41	%	41	%
Short-Term Debt	8	%	6	%

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 2014 amounted to $200.0 million. Management estimates net cash outflows for construction projects for 2015, 2016 and 2017, to be approximately $233.7 million, $241.0 million and $176.9 million, respectively. Costs for remediation projects for the year of 2014 amounted to $8.2 million, net of recoveries from ratepayers. Total cash outflows for remediation projects are expected to be $25.4 million, $26.9 million and $25.2 million for 2015, 2016, and 2017, respectively, prior to recoveries from ratepayers. As discussed in Notes 3 and 12 to the financial statements, 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 the current portion of 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, 2014, average $47.1 million annually and total $192.9 million over the contracts’ lives. Approximately 63% 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 BGSS clause.

In 2011, while in its normal course of business, SJG entered into long-term contracts for natural gas supplies. SJG 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.

The following table summarizes our contractual cash obligations and their applicable payment due dates as of December 31, 2014 (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	$	543,000	$	35,909	$	102,818	$	57,818	$	346,455
Interest on Long-Term Debt	222,514		22,004		41,209		34,917		124,384
Operating Leases	148		112		36		—		—
Construction Obligations	25,780		25,780		—		—		—
Commodity Supply Purchase Obligations	233,836		79,807		88,365		29,363		36,301
New Jersey Clean Energy Program	10,463		10,463		—		—		—
Other Purchase Obligations	1,319		1,319		—		—		—

Total Contractual Cash Obligations	$	1,037,060	$	175,394	$	232,428	$	122,098	$	507,140

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 $12.0 and $9.1 million in January 2015 and 2013, respectively. However, future pension contributions beyond January 2015 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, 2014 and 2013. 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.

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The fair value and maturity of these energy trading and hedging contracts determined using mark-to-market accounting as of December 31, 2014 is as follows (in thousands):



Assets
Source of Fair Value	Maturity < 1 Year		Maturity 1 - 3 Years		Total
Prices Actively Quoted (NYMEX)	$	2	$	—	$	2

Prices Provided by Other External Sources (Basis)	2,049		—		2,049

Total	$	2,051	$	—	$	2,051



Liabilities
	Maturity		Maturity
Source of Fair Value	< 1 Year		1 - 3 Years		Total
Prices Actively Quoted (NYMEX)	$	6,213	$	1,041	$	7,254

Prices Provided by Other External Sources (Basis)	92		257		349

Total	$	6,305	$	1,298	$	7,603

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 8.3 MMdt with a weighted-average settlement price of $3.89 per dt. Contracted volumes of our Basis contracts are (1.4) MMdt with a weighted average settlement price of $1.10 per dt.

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



Net Derivatives — Energy Related Asset, January 1, 2014	$	741
Contracts Settled During the Twelve Months ended December 31, 2014, Net	(510		)
Other Changes in Fair Value from Continuing and New Contracts, Net	(5,783		)
Net Derivatives — Energy Related Liability, December 31, 2014	$	(5,552	)

The change in our derivative position from a $0.7 million asset at December 31, 2013 to a $5.6 million liability at December 31, 2014 is primarily due to the change in fair value of our financial positions. The average future price was $0.77/dt less than the average contract price as of December 31, 2014 compared with the average future price being $0.14/dt greater that the average contract price as of December 31, 2013.

Interest Rate Risk - Our exposure to interest rate risk relates primarily to variable-rate borrowings. Variable-rate debt outstanding at December 31, 2014, was $160.4 million and averaged $83.2 million during 2014. 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: 2014 - 32 b.p. increase; 2013 - 14 b.p. decrease; 2012 - 1 b.p. decrease; 2011 - 14 b.p. decrease; and 2010 – 5 b.p. increase. As of December 31, 2014, our average interest rate on variable-rate debt was 0.66%.

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, 2014, the interest costs on all but $59.0 million 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.

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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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, 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 27, 2015

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SOUTH JERSEY GAS COMPANY

STATEMENTS OF INCOME

(In Thousands)



	Year Ended December 31,
	2014			2013			2012
Operating Revenues	$	501,875		$	446,480		$	421,874
Operating Expenses:
Cost of Sales (Excluding depreciation)	231,216			200,081			188,710
Operations	102,428			85,805			78,425
Maintenance	13,457			13,135			13,615
Depreciation	37,324			33,775			31,062
Energy and Other Taxes	3,760			7,862			8,300
Total Operating Expenses	388,185			340,658			320,112
Operating Income	113,690			105,822			101,762
Other Income and Expense	5,560			3,797			2,617
Interest Charges	(17,872		)	(12,550		)	(12,427		)
Income Before Income Taxes	101,378			97,069			91,952
Income Taxes	(34,895		)	(34,833		)	(33,711		)
Net Income	$	66,483		$	62,236		$	58,241

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

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SOUTH JERSEY GAS COMPANY

STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)



	Year Ended December 31,
	2014			2013		2012
Net Income	$	66,483		$	62,236	$	58,241

Other Comprehensive Income (Loss), Net of Tax:*

Postretirement Liability Adjustment	(3,165		)	2,286		(1,683		)
Unrealized (Loss) Gain on Available-for-Sale Securities	(472		)	103		500
Unrealized Gain on Derivatives - Other	27			27		27

Other Comprehensive (Loss) Income- Net of Tax*	(3,610		)	2,416		(1,156		)

Comprehensive Income	$	62,873		$	64,652	$	57,085

* Determined using a combined statutory tax rate of 40% in 2014 and 41% in 2013 and 2012.

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

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SOUTH JERSEY GAS COMPANY

STATEMENTS OF CASH FLOWS

(In Thousands)



	Year Ended December 31,
	2014			2013			2012
Cash Flows from Operating Activities:
Net Income	$	66,483		$	62,236		$	58,241
Provided by Operating Activities:
Depreciation and Amortization	52,155			48,261			44,171
Provision for Losses on Accounts Receivable	9,417			4,232			4,775
CIP Receivable/Payable	15,226			21,160			(18,106		)
Deferred Gas Costs - Net of Recoveries	(44,976		)	5,473			25,050
Deferred SBC Costs - Net of Recoveries	11,048			2,393			(4,183		)
Environmental Remediation Costs - Net of Recoveries	(8,248		)	(438		)	(188		)
Deferred and Noncurrent Income Taxes and Credits - Net	32,193			31,940			38,353
Gas Plant Cost of Removal	(4,848		)	(6,092		)	(2,133		)
Pension Contribution	—			(9,100		)	(19,757		)
Changes in:
Accounts Receivable	(14,667		)	(20,574		)	(34,263		)
Inventories	(3,820		)	(7,153		)	13,449
Prepaid and Accrued Taxes - Net	(6,508		)	9,456			6,451
Other Prepayments and Current Assets	131			(476		)	430
Gas Purchases Payable	(1,873		)	9,306			(2,941		)
Accounts Payable and Other Accrued Liabilities	11,302			(5,107		)	(8,803		)
Other Assets	(7,481		)	(7,323		)	(10,980		)
Other Liabilities	(2,006		)	10,565			3,807
Net Cash Provided by Operating Activities	103,528			148,759			93,373

Cash Flows from Investing Activities:
Capital Expenditures	(200,008		)	(161,498		)	(156,041		)
Net (Investment in) Proceeds from Restricted Investments in Margin Account	(7,281		)	588			930
Investment in Long-Term Receivables	(13,024		)	(7,182		)	(6,243		)
Proceeds from Long-Term Receivables	6,544			5,764			8,182
Net Cash Used in Investing Activities	(213,769		)	(162,328		)	(153,172		)

Cash Flows from Financing Activities:
Net Borrowings from (Repayments of) Short-Term Credit Facilities	35,900			(36,600		)	(24,500		)
Proceeds from Issuance of Long-Term Debt	89,000			50,000			120,000
Principal Repayments of Long-Term Debt	(21,000		)	(25,000		)	(35,000		)
Premium for Early Retirement of Debt	—			—			(700		)
Payments for Issuance of Long-Term Debt	(627		)	(411		)	(951		)
Dividends on Common Stock	(18,201		)	—			—
Additional Investment by Shareholder	25,000			25,000			—
Excess (Tax Deficiency) Tax Benefit from Restricted Stock Plan	(73		)	(78		)	124
Net Cash Provided by Financing Activities	109,999			12,911			58,973

Net Decrease in Cash and Cash Equivalents	(242		)	(658		)	(826		)
Cash and Cash Equivalents at Beginning of Period	2,020			2,678			3,504

Cash and Cash Equivalents at End of Period	$	1,778		$	2,020		$	2,678

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Supplemental Disclosures of Cash Flow Information
Interest (Net of Amounts Capitalized)	$	17,832		$	12,234		$	12,073
Income Taxes (Net of Refunds)	$	(7,690	)	$	(5,056	)	$	(2,797	)

Supplemental Disclosures of Noncash Investing Activities
Property and equipment acquired on account but not paid at year-end	$	17,551		$	20,055		$	11,069

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, 2014			December 31, 2013
Assets
Property, Plant and Equipment:
Utility Plant, at original cost	$	2,002,966		$	1,816,804
Accumulated Depreciation	(413,597		)	(392,029		)

Property, Plant and Equipment - Net	1,589,369			1,424,775

Investments:
Available-for-Sale Securities	8,894			8,696
Restricted Investments	7,961			680

Total Investments	16,855			9,376

Current Assets:
Cash and Cash Equivalents	1,778			2,020
Accounts Receivable	60,535			60,317
Accounts Receivable - Related Parties	1,157			968
Unbilled Revenues	49,910			41,510
Provision for Uncollectibles	(6,601		)	(4,553		)
Natural Gas in Storage, average cost	25,325			20,811
Materials and Supplies, average cost	1,104			1,798
Deferred Income Taxes - Net	44,064			23,309
Prepaid Taxes	13,601			7,683
Derivatives - Energy Related Assets	2,051			1,222
Other Prepayments and Current Assets	3,688			3,819

Total Current Assets	196,612			158,904

Regulatory and Other Noncurrent Assets:
Regulatory Assets	357,160			296,081
Unamortized Debt Issuance Costs	7,382			6,523
Long-Term Receivables	15,223			10,252
Derivatives - Energy Related Assets	—			278
Other	3,071			2,937

Total Regulatory and Other Noncurrent Assets	382,836			316,071

Total Assets	$	2,185,672		$	1,909,126

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, 2014			December 31, 2013
Capitalization and Liabilities
Common Equity:
Common Stock, Par Value $2.50 per share:
Authorized - 4,000,000 shares
Outstanding - 2,339,139 shares	$	5,848		$	5,848
Other Paid-In Capital and Premium on Common Stock	250,899			225,972
Accumulated Other Comprehensive Loss	(14,479		)	(10,869		)
Retained Earnings	438,300			390,018

Total Common Equity	680,568			610,969

Long-Term Debt	507,091			454,000

Total Capitalization	1,187,659			1,064,969

Current Liabilities:
Notes Payable	101,400			65,500
Current Portion of Long-Term Debt	35,909			21,000
Accounts Payable - Commodity	22,359			24,232
Accounts Payable - Other	32,711			32,072
Accounts Payable - Related Parties	11,249			6,638
Derivatives - Energy Related Liabilities	6,305			711
Customer Deposits and Credit Balances	17,626			15,089
Environmental Remediation Costs	28,480			15,422
Taxes Accrued	1,177			1,767
Pension Benefits	1,515			1,241
Interest Accrued	6,099			6,039
Other Current Liabilities	6,580			5,629

Total Current Liabilities	271,410			195,340

Regulatory and Other Noncurrent Liabilities:
Regulatory Liabilities	41,899			60,949
Deferred Income Taxes - Net	435,022			380,975
Environmental Remediation Costs	95,828			104,070
Asset Retirement Obligations	41,976			41,178
Pension and Other Postretirement Benefits	95,241			48,197
Investment Tax Credits	149			360
Derivatives - Energy Related Liabilities	1,298			48
Derivatives - Other	7,325			3,735
Other	7,865			9,305

Total Regulatory and Other Noncurrent Liabilities	726,603			648,817

Commitments and Contingencies (Note 9)

Total Capitalization and Liabilities	$	2,185,672		$	1,909,126

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, 2012	$	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 Gain, 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
Net Income									66,483			66,483
Other Comprehensive Loss, Net of Tax: (a)						(3,610		)				(3,610		)
Cash Dividends Declared – Common Stock									(18,201		)	(18,201		)
Additional Investment by Shareholder			25,000									25,000
Tax Deficiency from Restricted Stock Plan			(73		)							(73		)

Balance at December 31, 2014	$	5,848	$	250,899		$	(14,479	)	$	438,300		$	680,568

(a) Determined using a combined statutory tax rate of 40% in 2014 and 41% in each of 2013 and 2012.

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, 2012	$	(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		)
Changes During Year	(3,165		)	(472		)	27			(3,610		)
Balance at December 31, 2014	$	(13,837	)	$	(75	)	$	(567	)	$	(14,479	)

(a) Determined using a combined statutory tax rate of 40% in 2014 and 41% in 2013 and 2012.

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 period's 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 2014, 2013 or 2012.

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 - SJG collects certain revenue-based energy taxes from our customers. Such taxes include New Jersey State Sales Tax and Public Utilities Assessment (PUA). State sales tax is recorded as a liability when billed to customers and is not included in revenue or operating expenses. The PUA is included in both revenues and cost of sales and totaled $1.1 million, $1.2 million and $0.9 million in 2014, 2013 and 2012, respectively. In prior years, SJG had collected a throughput-based energy tax from customers in the form of a Transitional Energy Facility Assessment (TEFA ). The TEFA was included in both revenues and cost of sales and totaled $4.0 million, and $5.1 million in 2013 and 2012, respectively. The TEFA was eliminated effective January 1, 2014.

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, 2014 and 2013 were comprised of the following (in thousands):



	2014		2013
Utility Plant:
Production Plant	$	296	$	296
Storage Plant	23,023		22,538
Transmission Plant	248,737		248,074
Distribution Plant	1,547,218		1,417,939
General Plant	103,604		53,162
Other Plant	1,855		1,855
Utility Plant in Service	1,924,733		1,743,864
Construction Work in Progress	78,233		72,940
Total Utility Plant	$	2,002,966	$	1,816,804

The increase in Utility Plant in Service is related to projects for distribution, some of which are part of the Company's Accelerated Infrastructure Replacement Program (AIRP), as discussed under Note 3.

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 2014 and 2013 was as follows (in thousands):



	2014			2013
ARO as of January 1,	$	41,178		$	38,892
Accretion	1,595			1,514
Additions	664			743
Settlements	(1,461		)	(1,630		)
Revisions in Estimated Cash Flows *	—			1,659
ARO as of December 31,	$	41,976		$	41,178

* The revision in estimated cash flows in 2013 reflects an increase in the inflation rate used to determine the ARO settlement amount.

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 2.2% in 2014, 2.3% in 2013 and 2.4% in 2012. 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. Effective October 1, 2014, SJG's composite depreciation rate was reduced from 2.4% to 2.1%. See Note 3.

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 $4.4 million in 2014, $8.2 million in 2013 and $6.5 million in 2012. The decrease in 2014 is related to the CIRT projects rolling into customer rates effective October 31, 2013 . Under the CIRT, 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.

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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 2014, 2013 and 2012, 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 2014, 2013 or 2012 had, or is expected to have, a material impact on the financial statements.

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. The adoption of this guidance did not have an impact on the Company's financial statement results.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), This ASU supersedes the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. The new guidance identifies how and when entities should recognize revenue. The new rules establish a core principle requiring the recognition of revenue to depict the transfer of promised goods or services to customers in an amount reflecting the consideration to which the entity expects to be entitled in exchange for such goods or services. The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Management is currently determining the impact that adoption of this guidance will have on the Company's financial statement results.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40); Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The new guidance requires management of a company to evaluate whether there is substantial doubt about the company's ability to continue as a going concern. This ASU is effective for the annual reporting period ending after December 15, 2016, and for interim and annual reporting periods thereafter, with early adoption permitted. The Company does not expect this standard to have an impact on its financial statements upon adoption.

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2.	STOCK-BASED COMPENSATION PLANS:

Officers and other key employees of SJG participate in the Stock-Based Compensation 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 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.

Grants containing earnings-based targets 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 targets.

We are allocated a portion of SJI's compensation cost during the vesting period. We accrue a liability and record compensation cost over the requisite three-year service period based on the grant date fair value as described above for each type of grant. Upon vesting, we make a cash payment to SJI equal to the amounts accrued as compensation cost during the vesting period. Since the inception of the Plan, our expense recognition policy has been consistent with the expense recognition policy at SJI.

The following table summarizes the SJI nonvested restricted stock awards pertaining to SJG outstanding at December 31, 2014, 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. 2013 - TSR	4,001	$	44.38	21.1	%	0.40	%
Jan. 2013 - EPS	4,001	$	51.18	n/a		n/a
Jan. 2014 - TSR	5,197	$	42.62	20.0	%	0.80	%
Jan. 2014 - EPS	5,197	$	54.44	n/a		n/a

Expected volatility is based on the actual volatility of SJI’s share price over the preceding three-year period as of the valuation date. The risk-free interest rate is based on the zero-coupon U.S. Treasury Bond, with a term equal to the three-year term of the restricted shares. As notional dividend equivalents are credited to the holders, 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 $0.2 million, $0.4 million and $0.4 million in 2014, 2013 and 2012, respectively. Of these costs, approximately one half was capitalized to Utility Plant in each of those years. The cost for 2014 reflects the reversal of approximately $0.2 million of previously recorded costs. This reversal was associated with the January 2012 EPS-based grant for which performance goals were not met.

As of December 31, 2014, there was $0.5 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 2014, excluding accrued dividend equivalents:



	Shares		Weighted Average Grant Date Fair Value
Nonvested Shares Outstanding, January 1, 2014	15,068		$	50.73

Granted	10,394		$	48.53
Vested*	(7,065	)	$	54.08
Nonvested Shares Outstanding, December 31, 2014	18,397		$	48.20

* Performance targets during the three-year vesting period were not attained for the January 2012 grant. As a result, no shares will be awarded in 2015.

Performance targets during the three-year vesting period were not attained for the January 2011 grant that vested at

December 31, 2013. As a result, no shares were 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 the Plan. Cash payments to SJI during 2014, 2013 and 2012 were approximately $0.4 million, $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 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 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 September 2014, the BPU granted SJG a base rate increase of $20 million, which was predicated, in part, upon a 7.10% rate of return on rate base that included a 9.75% return on common equity. The $20 million includes approximately $7.5 million of revenue associated with previously approved Accelerated Infrastructure Replacement Program (AIRP) investments that were rolled into base rates. SJG was also permitted to recover certain regulatory assets and to reduce its composite depreciate rate from 2.4% to 2.1%. These changes became effective on October 1, 2014.

Rate Mechanisms - SJG's tariff, a schedule detailing the terms, conditions and rate information applicable to its 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 allows SJG 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. SJG collects gas costs from customers on a forecasted basis and defers periodic over/under recoveries to the following BGSS year, which runs from October 1 through September 30. If SJG is in a net cumulative undercollected position, gas costs deferrals are reflected on the balance sheet as a regulatory asset. If SJG is in a net cumulative overcollected position, amounts due back to customers are reflected on the balance sheet as a regulatory liability. SJG pays 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.

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Regulatory actions regarding the BGSS were as follows:


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


•	June 2012 - SJG filed its 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 - SJG credited the accounts of its periodic BGSS customers with refunds totaling $9.4 million due to gas costs that were lower than projections.


•	May 2013 - SJG filed its 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 - SJG credited the accounts of its periodic BGSS customer with refunds totaling $11.2 million due to gas costs that were lower than projected.


•	May 2014 - SJG filed its annual BGSS filing with the BPU requesting a $27.0 million, or a 9.3%, increase in gas cost recoveries.


•	September 2014 - The BPU issued an Order approving, on a provisional basis, SJG’s request for a $27.0 million increase in gas cost recoveries.

Conservation Incentive Program (CIP) - The primary purpose of the CIP is to promote conservation efforts, without negatively impacting financial stability, and to base SJG's 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 and in May 2014 the BPU approved the continuation of the CIP. Each CIP year begins October 1 and ends September 30 of the subsequent year. On a monthly basis during the CIP year, SJG records adjustments to earnings based on weather and customer usage factors, as incurred. Subsequent to each year, SJG makes 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:


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


•	June 2012 - SJG made its 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 - SJG filed a joint petition with another utility requesting modification to, and the continuation of, the CIP program effective October 1, 2013.


•	May 2013 - SJG made its 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.


•	May 2014 - SJG made its annual CIP filing with the BPU requesting a revenue reduction of $21.8 million, which includes a $4.2 million increase in non-weather related revenues and a $26.0 million reduction in weather related revenues.


•	September 2014 - The BPU issued an Order approving, on a provisional basis, the 2014-2015 CIP rates filed in May 2014, effective October 1 2014.

Capital Investment Recovery Tracker (CIRT) - The purpose of the CIRT was to accelerate capital expenditures in an effort to stimulate the economy. The petition requested that we be allowed to earn a return of, and a return on, our investment. 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. On a monthly basis during the CIRT year, SJG recorded adjustments to earnings based on actual CIRT program expenditures, as incurred. Annually SJG made filings with the BPU for review and approval of expenditures recorded under the CIRT.

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Regulatory actions regarding the CIRT were as follows:

•

March 2011 - The BPU approved a CIRT II program allowing SJG to accelerate an additional $60.3 million of capital spending into 2011 and 2012. Under CIRT II, SJG 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, SJG is permitted to earn a return on CIRT II investments until the roll in is approved and recovery commences.


•	June 2011 - SJG 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 - SJG 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 SJG to accelerate an incremental $35.0 million of capital spending through December 2012.


•	October 2012 - SJG 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 effective October 1, 2013 and the CIRT program is now concluded.

Accelerated Infrastructure Replacement Program (AIRP) - In July 2012, SJG 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 an 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 Order, AIRP investments are to be reviewed and included in rate base in future base rate proceedings.

Regulatory actions regarding AIRP were as follows:


•	September 2014 - The BPU approved SJG’s base rate case, which included a $7.5 million increase in revenues associated with the roll in of $69.9 million of AIRP investments into base rates.

Storm Hardening and Reliability Program (SHARP) - In September 2013, SJG filed with the BPU an asset hardening program pursuant to which it 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.

Regulatory actions regarding SHARP were as follows:


•	August 2014 - The BPU approved the Storm Hardening and Reliability Program (SHARP), authorizing SJG to invest $103.5 million over three years for system hardening on barrier islands. SJG will earn on a return on these investments as they are made and will reflect the investments in base rates through annual rate adjustments.

Energy Efficiency Tracker (EET) - In January 2009, SJG 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 SJG was permitted to invest $17.0 million over two years in energy efficiency measures to be installed in customer homes and businesses. SJG also recovered incremental operating and maintenance expenses and earn a return of, and return on, program investments.

Regulatory actions regarding the EET were as follows:


•	June 2011 - SJG 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 - SJG 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.

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•

May 2012 - SJG 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 - SJG 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. The BPU approved this petition in September 2014.


•	May 2013 - SJG filed its annual petition requesting an increase of $2.2 million for current EET programs. The BPU approved this petition in September 2014.


•	May 2014 - SJG filed its annual EET rate adjustment petition requesting an $1.4 million increase in revenues to recover the costs of, and the allowed return on, prior investments associated with energy efficiency programs. The petition is currently pending.


•	September 2014 - The BPU approved a revenue increase of $2.2 million associated with the 2012-2013 annual EET rate adjustment filing, with rates effective October 1, 2014.


•	In January 2015 - SJG filed a petition with the BPU seeking to continue offering energy efficiency programs through June 2018 with a proposed budget of $56 million and with the same rate recovery mechanism that exists for its current energy efficiency programs.

Societal Benefits Clause (SBC) - The SBC allows SJG 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) and a Universal Service Fund (USF) program.

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


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


•	July 2012 - SJG made its 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 - SJG made its annual 2013-2014 SBC filing requesting a $6.4 million decrease in SBC revenues. The BPU approved this filing in September 2014.


•	July 2014 - SJG made its annual 2014-2015 SBC filing requesting a $25.7 million decrease in SBC revenues.

Remediation Adjustment Clause (RAC) - The RAC recovers environmental remediation costs of 12 former gas manufacturing plants (See Note 12). The BPU allows SJG 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, 2014 and 2013, we reflected the unamortized remediation costs of $29.5 million and $29.9 million, respectively, on the balance sheet under Regulatory Assets (See Note 4). Since implementing the RAC in 1992, SJG has recovered $106.1 million through rates.

New Jersey Clean Energy Program (NJCEP) - This mechanism recovers costs associated with SJG's 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. In June 2013, the BPU approved a NJCEP funding level of $345 million through June 2014, of which SJG was responsible for $14.5 million. 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.

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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 2012 - SJG made its 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. SJG's portion of the total is approximately $8.2 million, which decreased rates effective October 1, 2012, resulting in a $0.1 million decrease to its annual USF recoveries.


•	June 2013 - SJG made its 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 SJG's 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. SJG's 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.


•	June 2014 - SJG made its annual USF filing, along with the State’s other electric and gas utilities, proposing to increase the statewide gas revenues by $19.9 million. This proposal was designed to increase SJG’s annual USF revenue by $2.6 million.


•	September 2014 - The BPU approved the statewide budget of $71.8 million for all the State’s gas utilities. SJG's portion of the total is approximately $7.9 million, which increased rates effective October 1, 2014, resulting in a $2.6 million increase to its USF recoveries.

Other Regulatory Matters -

Unbundling - Effective January 10, 2000, the BPU approved full unbundling of SJG's system. This allows all natural gas consumers to select their natural gas commodity supplier. As of December 31, 2014, 38,347 of SJG's 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 SJG's revenues is offset by a corresponding decrease in gas costs. While customer choice can reduce utility revenues, it does not negatively affect SJG's 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 SJG still recover cost of service, including certain deferred costs, through base rates.

Pipeline Integrity Costs - SJG is permitted to defer and recover incremental costs incurred as a result of Pipeline Integrity Management regulations that became effective January 14, 2004, 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, SJG was permitted to recover previously deferred pipeline integrity costs incurred through September 2010. As part of SJG's 2014 base rate case, it was permitted to recover previously deferred pipeline integrity costs incurred from October 2010 through June 2014. In addition, SJG is authorized to defer future program costs, including related carrying costs, for recovery in our next base rate proceeding, subject to review by the BPU. As of December 31, 2014 and 2013, deferred pipeline integrity costs totaled $3.4 million and $2.8 million, respectively, and are included in other regulatory assets (See Note 4).

Superstorm Sandy - In June 2013, SJG filed a petition requesting deferral of $0.7 million of incremental operating and maintenance expenses incurred due to Superstorm Sandy. The BPU approved the recovery of these expenses through base rates in SJG’s 2014 base rate case.

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



	2014		2013
Environmental Remediation Costs:
Expended - Net	$	29,540	$	29,945
Liability for Future Expenditures	124,308		119,492
Deferred Asset Retirement Obligation Costs	31,584		31,142
Deferred Pension and Other Postretirement Benefit Costs	99,040		59,284
Deferred Gas Costs - Net	32,202		—
Conservation Incentive Program - Receivable	—		10,526
Societal Benefit Costs Receivable	385		10,408
Premium for Early Retirement of Debt	—		955
Deferred Interest Rate Contracts	7,325		3,735
Energy Efficiency Tracker	11,247		10,420
Pipeline Supplier Service Charges	5,441		7,106
Pipeline Integrity Cost	3,431		2,902
AFUDC - Equity Related Deferrals	10,781		7,810
Other Regulatory Assets	1,876		2,356

Total Regulatory Assets	$	357,160	$	296,081

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. 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).

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Deferred Gas Costs - Net - Over/under collections of gas costs are monitored through SJG's 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 natural gas purchases are also included in the BGSS, subject to BPU approval (see note 14). The change from a $19.1 million regulatory liability at December 31, 2013 to a $32.2 million regulatory asset at December 31, 2014 was due to the actual cost of the commodity incurred during 2014 exceeding the gas cost recovered from customers as a result of higher prices.

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, 2014, 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 2014 base rate increase, we were permitted to recover previously deferred pipeline integrity costs incurred through September 2014. 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).

AFUDC Equity Related Deferrals - This regulatory asset represents the future revenue to recover the future income taxes related to the deferred tax liability for the equity component of AFUDC. Included in the balance is $3.6 million which is being recovered over a period of three years, as approved by the BPU in SJG’s recent rate case settlement. The remaining balance is being amortized over the life of the associated utility plant.

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):



	2014		2013
Excess Plant Removal Costs	$	35,940	$	40,029
Deferred Revenue - Net	—		19,067
Conservation Incentive Program - Payable	4,700		—
Other Regulatory Liabilities	1,259		1,853

Total Regulatory Liabilities	$	41,899	$	60,949

Excess Plant Removal Costs – Represents amounts accrued in excess of actual utility plant removal costs incurred to date. As part of our September 2014 base rate increase, we are required to amortize approximately $1.1 million of this balance to depreciation expense each year.

Deferred Revenues – Net - See previous discussion under "Deferred Gas Costs - Net" above.

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Conservation Incentive Program - Payable - See previous discussion under "Conservation Incentive Program - Receivable" above.

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


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) - was a wholly owned subsidiary of SJI, which provided services, such as information technology, human resources, corporate communications, materials purchasing and fleet management to SJI and all of its subsidiaries. SJIS was dissolved effective January 1, 2014. All services previously provided by SJIS are currently being provided by SJI.

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 provides 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):



	2014		2013		2012
Operating Revenues/Affiliates:
SJRG	$	959	$	1,390	$	884
Marina	1,083		1,297		841
Other	—		2		10
Total Operating Revenues/Affiliates	$	2,042	$	2,689	$	1,735

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



	2014			2013			2012
Costs of Sales/Affiliates
(Excluding depreciation):
SJRG	$	15,265		$	14,959		$	9,083
Derivative (Gains)/Losses (See Note 1):
SJRG	$	(1,582	)	$	887		$	15,407
Operations Expense/Affiliates:
SJI	$	14,110		$	11,990		$	10,870
SJIS	—			5,531			5,397
Millennium	2,668			2,686			3,149
Other	(434		)	(428		)	(500		)
Total Operations Expense/Affiliates	$	16,344		$	19,779		$	18,916


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):



	2014			2013			2012
Tax at Statutory Rate	$	35,482		$	33,974		$	32,183
Increase (Decrease) Resulting from:
State Income Taxes	1,935			4,833			5,302
Amortization of Investment Tax Credits	(211		)	(258		)	(287		)
ESOP Dividend	(1,109		)	(1,058		)	(1,027		)
AFUDC	(1,481		)	(916		)	(1,048		)
Other - Net	279			(1,742		)	(1,412		)
Net Income Taxes	$	34,895		$	34,833		$	33,711

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



	2014			2013			2012
Current:
Federal	$	60		$	(53	)	$	(4,635	)
State	2,642			2,946			(7		)
Total Current	2,702			2,893			(4,642		)
Deferred:
Federal	32,069			27,707			30,477
State	335			4,491			8,163
Total Deferred	32,404			32,198			38,640
Investment Tax Credits	(211		)	(258		)	(287		)
Net Income Taxes	$	34,895		$	34,833		$	33,711

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):



	2014			2013
Current:
Net Operating Loss Carryforward	$	(40,573	)	$	(27,600	)
Budget Billing - Customer Accounts	1,138			1,152
Provision for Uncollectibles	(2,676		)	(1,726		)
Conservation Incentive Program	(2,027		)	4,631
Section 461 Prepayments	1,026			1,156
Other	(952		)	(922		)
Current Deferred Tax Asset - Net	$	(44,064	)	$	(23,309	)
Noncurrent:
Book Versus Tax Basis of Property	$	417,178		$	371,684
Deferred Fuel Costs - Net	22,959			1,330
Environmental Remediation	13,500			14,392
Deferred Regulatory Costs	6,333			13,665
Deferred State Tax	(17,390		)	(15,471		)
Investment Tax Credit Basis Gross-Up	(77		)	(185		)
Deferred Pension & Other Post Retirement Benefits	39,891			24,218
Pension & Other Post Retirement Benefits	(27,782		)	(14,152		)
Deferred Revenues	(11,452		)	(9,266		)
Net Operating Loss Carryforward	(12,887		)	(8,764		)
Other	4,749			3,524
Noncurrent Deferred Tax Liability – Net	$	435,022		$	380,975

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, 2014 and December 31, 2013, there were no income taxes due to or from SJI.

As of December 31, 2014, SJG has total federal net operating loss carryforwards of $152.7 million; $63.0 million will expire in 2031, $4.2 million will expire in 2032 and $85.5 million will expire in 2034 . 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):



	2014		2013		2012
Balance at January 1,	$	547	$	503	$	421
Increase as a result of tax position taken in prior years	5		44		82
Decrease due to a lapse in the statue of limitations	—		—		—
Settlements	—		—		—
Balance at December 31,	$	552	$	547	$	503

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The total unrecognized tax benefits as of December 31, 2014 were $0.6 million, not including $0.7 million of accrued interest and penalties. 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 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 2014, 2013 or 2012. There have been no material changes to the unrecognized tax benefits during 2014, 2013 or 2012 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 tax issues relating to the Company's nexus in certain states. Federal income tax returns from 2011 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):



			2014			2013
Long-Term Debt (A):
First Mortgage Bonds: (B)
4.52	%	Series due 2014 (C)	—			11,000
5.115	%	Series due 2014 (D)	—			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 (E)	50,000			50,000
4.23	%	Series due 2030 (F)	30,000			—
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 (G)			25,000			25,000
Variable Rate Bank Term Facility, due 2017 (H)			59,000			—
Total Long-Term Debt Outstanding			543,000			475,000
Less Current Maturities (A) (G)			(35,909		)	(21,000		)
Long-Term Debt			$	507,091		$	454,000

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(A)	Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2015, $35,909; 2016, $27,909; 2017, $74,909; 2018, $38,909; 2019, $18,909.


(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 2014, SJG retired $11.0 million aggregate principal amount of 4.52% Medium Term Notes (MTN's) at maturity.


(D)	In September 2014, SJG retired $10.0 million aggregate principal amount of 5.115% MTN's at maturity.


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


(F)	In January 2014, SJG issued $30.0 million aggregate principal amount of 4.23% MTN's due January 2030.


(G)	These variable rate demand bonds bear interest at a floating rate that resets weekly. The interest rate as of December 31, 2014 was 0.08%. Liquidity support on these bonds is provided under a separate letter of credit facility that expires in August, 2015; as such, these bonds have been included in the current portion of long-term debt. These bonds contain no financial covenants.

(H)

In June 2014, SJG entered into a $200.0 million multiple-draw term facility offered by a syndicate of banks which expires in June 2017. SJG can draw under this facility through June 2016 and this facility bears interest at a floating rate based on LIBOR plus a spread determined by SJG's credit ratings. As of December 31, 2014, SJG had borrowed an aggregate $59.0 million under this facility and the proceeds were used to pay down short-term debt.

In October 2013, SJG filed a petition with the BPU 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. There is no capacity remaining under this petition.


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, 2014 and December 31, 2013, the escrowed proceeds, including interest earned, totaled $0.1 million. SJG has a margin account with SJRG in conjunction with SJG's risk management activities as detailed in Note 14. As of December 31, 2014 and December 31, 2013, the balance held with SJRG totaled $0.0 million and $0.5 million, respectively. This account is being closed. During March 2013, SJG established a separate 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. As of December 31, 2014 and 2013, the balance held by the counterparty was $7.8 million and $(0.3) million, respectively. The carrying amounts of the Restricted Investments approximate their fair value at December 31, 2014 and December 31, 2013, which would be included in Level 1 of the fair value hierarchy. (See Note 13 - 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 as of both December 31, 2014 and December 31, 2013. 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, 2014 and December 31, 2013. 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, 2014 and December 31, 2013, which would be included in Level 2 of the fair value hierarchy. (See Note 13 - 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, 2014 and December 31, 2013, 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, 2014 and December 31, 2013, were $587.3 million and $486.5 million, respectively. The carrying amounts of SJG's long-term debt, including current maturities, as of December 31, 2014 and December 31, 2013, were $543.0 million and $475.0 million, respectively.


9.	LINES OF CREDIT:

Credit facilities and available liquidity as of December 31, 2014 were as follows (in thousands):



	Total Facility		Usage		Available Liquidity		Expiration Date
Commercial Paper Program/ Revolving Credit Facility	$	200,000	$	101,400	$	98,600	May 2018
Uncommitted Bank Lines	10,000		—		10,000		August 2015

Total	$	210,000	$	101,400	$	108,600

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, 2014.

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, 2014 and 2013 were $52.3 million and $91.4 million, respectively. The maximum amount outstanding under these credit facilities, not including letters of credit, during the twelve months ended December 31, 2014 and 2013 were $105.0 million and $121.9 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 0.45% , 0.37% and 0.48% at December 31, 2014, 2013 and 2012, 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, 2014, these loan restrictions did not affect the amount that may be distributed from our retained earnings.

SJG received $25 million equity infusion from SJI in both 2014 and 2013. No equity infusions were received from SJI in 2012. 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
	2014			2013			2012			2014			2013			2012
Service Cost	$	3,697		$	4,487		$	3,718		$	585		$	771		$	704
Interest Cost	8,952			7,886			8,008			2,297			2,221			2,443
Expected Return on Plan Assets	(10,818		)	(9,435		)	(8,249		)	(2,467		)	(2,158		)	(1,910		)
Amortization:
Prior Service Cost (Credits)	177			208			207			133			(195		)	(195		)
Actuarial Loss	4,864			7,608			6,432			770			1,555			1,534
Net Periodic Benefit Cost	6,872			10,754			10,116			1,318			2,194			2,576
Capitalized Benefit Costs	(3,047		)	(5,002		)	(4,684		)	(722		)	(1,172		)	(1,340		)
Affiliate SERP Allocations	(1,313		)	(1,389		)	(1,107		)	—			—			—
Total Net Periodic Benefit Expense	$	2,512		$	4,363		$	4,325		$	596		$	1,022		$	1,236

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, 2013	$	68,713		$	27,184		$	21,908		$	—
Amounts Arising during the Period:
Net Actuarial Loss	(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			—
Amounts Arising during the Period:
Net Actuarial Loss	31,075			7,826			7,102			—
Prior Service Cost (Credit)	486			4,146			—
Amounts Amortized to Net Periodic Costs:
Net Actuarial Loss	(2,841		)	(628		)	(1,975		)	—
Prior Service (Cost) Credit	(175		)	(133		)	—			—
Balance at December 31, 2014	$	71,177		$	27,863		$	23,170		$	—

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	$	199	$	499
Net Actuarial Loss	$	5,922	$	1,235

The estimated costs that will be amortized from Accumulated Other Comprehensive Loss into net periodic benefit costs in 2015 are as follows (in thousands):



	Pension Benefits		Other Postretirement Benefits
Net Actuarial Loss	$	2,750	$	—

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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
	2014			2013			2014			2013
Change in Benefit Obligations:
Benefit Obligation at Beginning of Year	$	180,668		$	186,899		$	50,915		$	55,615
Service Cost	3,697			4,487			585			771
Interest Cost	8,952			7,886			2,297			2,221
Actuarial (Gain) Loss	35,634			(11,514		)	6,008			(4,552		)
Retiree Contributions	—			—			452			335
Plan Amendments	534			—			4,146			—
Benefits Paid	(7,880		)	(7,090		)	(3,733		)	(3,475		)
Benefit Obligation at End of Year	$	221,605		$	180,668		$	60,670		$	50,915
Change in Plan Assets:
Fair Value of Plan Assets at Beginning of Year	$	142,674		$	119,391		$	39,471		$	32,694
Actual Return on Plan Assets	8,275			20,049			507			5,101
Employer Contributions	1,499			10,324			4,254			4,816
Retiree Contributions	—			—			452			335
Benefits Paid	(7,880		)	(7,090		)	(3,733		)	(3,475		)
Fair Value of Plan Assets at End of Year	$	144,568		$	142,674		$	40,951		$	39,471



Funded Status at End of Year:
Accrued Net Benefit Cost at End of Year	$	(77,037	)	$	(37,994	)	$	(19,719	)	$	(11,444	)
Amounts Recognized in the Statement of Financial Position Consist of:
Current Liabilities	$	(1,515	)	$	(1,241	)	$	—		$	—
Noncurrent Liabilities	(75,522		)	(36,753		)	(19,719		)	(11,444		)
Net Amount Recognized at End of Year	$	(77,037	)	$	(37,994	)	$	(19,719	)	$	(11,444	)
Amounts Recognized in Regulatory Assets Consist of:
Prior Service Costs	$	944		$	634		$	4,965		$	952
Net Actuarial Loss	70,233			41,998			22,898			15,700
Net Amount Recognized at End of Year	$	71,177		$	42,632		$	27,863		$	16,652
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Net Actuarial Loss	$	23,170		$	18,043		$	—		$	—

The projected benefit obligation (PBO) and accumulated benefit obligation (ABO) of our qualified employee pension plans were $176.3 million and $161.3 million, respectively, as of December 31, 2014; and $143.5 million and $131.4 million, respectively, as of December 31, 2013. The ABO of these plans exceeded the value of the plan assets as of December 31, 2014. The value of these assets were $144.6 million and $142.7 million as of December 31, 2014 and 2013, respectively, and can be seen in the tables above. The PBO and ABO for our non-funded SERP were $45.3 million and $44.0 million, respectively, as of December 31, 2014; and $37.2 million and $36.2 million, respectively, as of December 31, 2013. 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
	2014		2013		2014		2013
Discount Rate	4.25	%	5.09	%	4.20	%	4.91	%
Rate of Compensation Increase	3.50	%	3.50	%	3.50	%	3.50	%

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



	Pension Benefits						Other Postretirement Benefits
	2014		2013		2012		2014		2013		2012
Discount Rate	5.09	%	4.26	%	5.03	%	4.91	%	4.14	%	4.92	%
Expected Long-Term Return on Plan Assets	7.75	%	7.50	%	7.50	%	6.25	%	6.60	%	6.60	%
Rate of Compensation Increase	3.50	%	3.25	%	3.25	%	3.50	%	3.25	%	3.25	%

Obligations as of December 31, 2013, disclosed herein reflect the use of the RP 2000 mortality tables. In 2014, the Society of Actuaries released new mortality tables (RP-2014 base table with MP-2014 generational projection scale), which indicate that the average life expectancy of both our active and retired plan participants has increased. Obligations as of December 31, 2014, disclosed herein reflect the use of the new tables. While the adoption of the new tables increase liabilities significantly as of December 31, 2014, no impact on expense will occur until 2015.

The discount rates used to determine the benefit obligations at December 31, 2014 and 2013, 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:



	2014		2013
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		2023

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	$	112	$	(94	)
Effect on Postretirement Benefit Obligation	$	3,806	$	(3,065	)

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, 2014. 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, 2014, 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, 2014 and 2013 by asset category are as follows (in thousands):



Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2014:
Cash / Cash Equivalents:
Common/Collective Trust Funds (a)	$	554	$	—	$	554	$	—
STIF-Type Instrument (b)	1,003		—		1,003		—
Equity securities:
Common/Collective Trust Funds – U.S. (a)	41,000		—		41,000		—
Common/Collective Trust Funds – International (a)	24,796		—		24,796		—
U.S. Large-Cap (c)	10,380		10,380		—		—
U.S. Mid-Cap (c)	4,122		4,122		—		—
U.S. Small-Cap (c)	186		186		—
International (c)	2,698		2,698		—		—
Fixed Income:
Common/Collective Trust Funds (a)	38,740		—		38,740		—
Guaranteed Insurance Contract (d)	8,738		—		—		8,738
Hedge Funds (e)	3,469		—		—		3,469
Other types of investments:
Private Equity Fund (f)	2,895		—		—		2,895
Common/Collective Trust Fund – Real Estate (g)	5,987		—		—		5,987
Total	$	144,568	$	17,386	$	106,093	$	21,089



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

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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, 2014 and 2013, 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, 2013	$	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
Actual return on plan assets:
Relating to assets still held at the reporting date	396			141		(20		)	586		1,103
Relating to assets sold during the period	10			—		260			—		270
Purchases, Sales and Settlements	(739		)	—		215			—		(524		)
Balance at December 31, 2014	$	8,738		$	3,469	$	2,895		$	5,987	$	21,089

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, mutual funds and Company-owned life insurance policies. 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 insurance policies are backed by a series of commingled trust investments held by the insurance carrier.

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The fair values of SJG’s other postretirement benefit plan assets at December 31, 2014 and 2013 by asset category are as follows (in thousands):



Asset Category	Total		Level 1		Level 2		Level 3
As of December 31, 2014:
Cash	$	142	$	142	$	—	$	—
Equity Securities:
Common/Collective Trust Funds - U.S. (a)	10,006		—		10,006		$	—
Common/Collective Trust Funds - International (a)	7,030		—		7,030		—
Mutual Fund - U.S. (b)	4,447		4,447		—		—
Mutual Funds - International (b)	1,671		1,671		—		—
Fixed Income:
Common/Collective Trust Funds - Bonds (a)	11,059		—		11,059		—
Mutual Funds - Bonds (b)	2,624		2,624		—		—
Other Types of Investments:
Mutual Funds - REITS (b)	286		286		—		—
Company Owned Life Insurance (c)	3,686		—		3,686		—
Total	$	40,951	$	9,170	$	31,781	$	—

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. (b)	2,814		2,814		—		—
Fixed Income:
Common/Collective Trust Funds - Bonds (a)	14,214		—		14,214		—
Total	$	39,471	$	2,814	$	36,657	$	—

(a)


(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.


(c)	This category represents Company-owned life insurance policies with a nationally known life insurance company. The value of these policies is backed by a series of common/collective trust funds held by the insurance carrier similar to category (a) above. Holdings in these insurance policies are classified as Level 2 investments.

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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
2015	$	8,444	$	3,999
2016	$	8,886	$	4,199
2017	$	9,143	$	4,222
2018	$	10,263	$	4,285
2019	$	11,174	$	4,389
2020 - 2024	$	65,205	$	23,421

Contributions - No pension plan contributions were made to our qualified employee pension plans during the year ended December 31, 2014 . SJG contributed$9.1 million to our qualified employee pension plans during the year ended December 31, 2013. In January 2015, SJG made a pension plan contribution of $12.0 million. Payments related to the unfunded SERP plan are expected to approximate $1.5 million in 2015 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 $1,500 if 10 or fewer years of service, or $2,000 if more than 10 years of service. The amount expensed and contributed for the matching provision of the Savings Plan approximated $1.2 million, $1.0 million and $0.9 million for the years ended December 31, 2014, 2013 and 2012, 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 2017. The transportation and storage agreements entered into between us and each of our interstate pipeline service providers were done so in accordance with their respective FERC approved tariff. Our cumulative obligation for gas supply related demand charges and reservation fees paid for these services averages approximately $3.9 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, 2014 and December 31, 2013. 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 59% of our workforce at December 31, 2014. 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 runs through August 2017.

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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 $343.9 million, of which $219.6 million has been spent as of December 31, 2014. The following table details the amounts accrued and expended for environmental remediation at December 31 (in thousands):



	2014			2013
Beginning of Year	$	119,492		$	107,410
Accruals	16,453			22,264
Expenditures	(11,637		)	(10,182		)
End of Year	$	124,308		$	119,492

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 $124.3 million to $223.3 million. We recorded the lower end of this range, $124.3 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 $110.2 million to a high of $198.4 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 selection of the remedial action, confirmation of regulatory compliance of the selected remedy, implementation of the approved remedy and issuance of a Response Action Outcome.

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 and issuance of a Response Action Outcome.

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 installation of a sub-surface containment unit, operation of a product recovery system, post remediation groundwater monitoring, and issuance of a Response Action Outcome.

Site 4 - Remedial investigation activities are ongoing at this site including pilot studies of potential remedial alternatives and continued soil and groundwater investigation. Steps remaining to remediate the site include in-situ remediation of impacted soil, post remediation groundwater monitoring, and issuance of a Response Action Outcome.

Sites 5 and 6 - Remedial investigation activities are ongoing at these sites. Steps remaining to remediate the sites include selection of the remedial action, approval of the selected remedy, implementation of the remedy, and issuance of a Response Action Outcome.

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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.

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, 2014
	Total		Level 1		Level 2		Level 3
Assets
Available-for-Sale Securities (A)	$	8,894	$	5,924	$	2,970	$	—
Derivatives – Energy Related Assets (B)	2,051		2		2,049		—
	$	10,945	$	5,926	$	5,019	$	—

Liabilities

Derivatives – Energy Related Liabilities (B)	$	7,603	$	7,254	$	349	$	—
Derivatives – Other (C)	7,325		—		7,325		—
	$	14,928	$	7,254	$	7,674	$	—



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	$	—

(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.

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(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.


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, 2014, SJG had outstanding NYMEX contracts intended to limit the exposure to market risk on 8.9 MMdts of expected future purchases of natural gas and 0.6 MMdts of expected future sales of natural gas. In addition to these derivative contracts, SJG had basis related purchase and sales contracts totaling 3.7 MMdts.These contracts, which do not qualify for the normal purchase and sale exemption and have not been designated as hedging instruments under GAAP, are measured at fair value and recorded in Derivatives —Energy Related Assets or Derivatives — Energy Related Liabilities on the 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, 2014 and December 31, 2013, SJG had $5.6 million of unrealized losses and $0.7 million of unrealized gains, respectively, included in its BGSS related to open financial contracts.

The Company has also entered into interest rate derivatives to 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 both December 31, 2014 and December 31, 2013, the unamortized balance was approximately $1.0 million.

As of December 31, 2014, 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

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The fair values of all derivative instruments, as reflected in the balance sheets as of December 31, 2014 and December 31, 2013, are as follows (in thousands):



Derivatives not designated as hedging instruments under GAAP	2014				2013
	Assets		Liabilities		Assets		Liabilities
Energy related commodity contracts:
Derivatives – Energy Related – Current	$	2,051	$	6,305	$	1,222	$	711

Derivatives – Energy Related – Non-Current	—		1,298		278		48

Interest rate contracts:

Derivatives – Other	—		7,325		—		3,735

Total derivatives not designated as hedging instruments under GAAP	$	2,051	$	14,928	$	1,500	$	4,494

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, 2014
Description	Gross amounts of recognized assets/liabilities			Gross amount offset in the balance sheet		Net amounts of assets/liabilities in balance sheet			Gross amounts not offset in the balance sheet						Net amount
Description	Gross amounts of recognized assets/liabilities			Gross amount offset in the balance sheet		Net amounts of assets/liabilities in balance sheet			Financial Instruments				Cash Collateral Posted		Net amount
Derivatives - Energy Related Assets	$	2,051		$	—	$	2,051		$	(2	)	(A)	$	—	$	2,049
Derivatives - Energy Related Liabilities	(7,603		)	—		(7,603		)	2			(B)	7,253		(348		)
Derivatives - Other	(7,325		)	—		(7,325		)	—				—		(7,325		)



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
Description	Gross amounts of recognized assets/liabilities			Gross amount offset in the balance sheet		Net amounts of assets/liabilities in balance sheet			Financial Instruments				Cash Collateral Posted			Net amount
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		)

(A) The balances at December 31, 2014 and December 31, 2013 were related to derivative liabilities which can be net settled against derivative assets.

(B) The balances at December 31, 2014 and December 31, 2013 were related to derivative assets which can be net settled against derivative liabilities.

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The effect of derivative instruments on the statements of income for 2014 , 2013 and 2012 are as follows (in thousands):



	Year ended December 31,
Derivatives in Cash Flow Hedging Relationships	2014			2013			2012
Interest Rate Contracts:
Losses reclassified from accumulated OCI into income (a)	$	(46	)	$	(46	)	$	(46	)

(a) Included in Interest Charges

Net realized gains (losses) associated with SJG’s energy-related financial commodity contracts of $1.7 million, $(0.4) million and $(15.4) million for 2014, 2013 and 2012, 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 on earnings.

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15.	ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCL):

The following tables summarizes the changes in accumulated other comprehensive loss (AOCL) for the years ended December 31, 2014 and 2013, respectively (in thousands):



	Postretirement Liability Adjustment			Unrealized Gain (Loss) on Derivatives-Other			Unrealized Gain (Loss) on Available-for-Sale Securities			Total
Balance at January 1, 2014 (a)	(10,672		)	(594		)	$	397		$	(10,869	)
Other comprehensive income before reclassifications	(4,345		)	—			76			(4,269		)
Amounts reclassified from AOCL (b)	1,180			27			(548		)	659
Net current period other comprehensive income	(3,165		)	27			(472		)	(3,610		)
Balance at December 31, 2014 (a)	$	(13,837	)	$	(567	)	$	(75	)	$	(14,479	)



	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 40% and 41% in 2014 and 2013, respectively.

(b) See table below.

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The reclassifications out of AOCL for the years ended December 31, 2014 and 2013 is as follows (in thousands):



Components of AOCL	Amounts Reclassified from AOCL						Affected Line Item in the Statements of Income
	For the Year Ended December 31, 2014			For the Year Ended December 31, 2013
Unrealized Loss on Derivatives-Other - Interest Rate Contracts designated as cash flow hedges	$	46		$	46		Interest Charges
Unrealized Gain on Available-for-Sale Securities	(918		)	(828		)	Other Income & Expense
Actuarial Loss on Postretirement Benefits	1,975			2,289			Operating Expenses: Operations
	1,103			1,507			Loss (Income) Before Income Taxes
Income Taxes (a)	444			615			Income Taxes (a)
Losses (Gains) from reclassifications for the period net of tax	$	659		$	892

(a) Determined using a combined statutory tax rate of 40% and 41% in 2014 and 2013, respectively.

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16.	QUARTERLY RESULTS OF OPERATIONS - UNAUDITED:

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



	2014 Quarter Ended								2013 Quarter Ended
	March 31		June 30		Sept. 30		Dec. 31		March 31		June 30		Sept. 30		Dec. 31
Operating Revenues	$	210,545	$	69,159	$	60,952	$	161,219	$	174,098	$	66,536	$	59,674	$	146,172
Expenses:
Cost of Sales (excluding depreciation)	103,293		24,879		23,400		79,644		77,602		26,108		24,717		71,654
Operations and Maintenance
Including Fixed Charges	46,969		38,737		37,432		47,943		38,659		33,871		33,249		39,486
Income Taxes	22,527		2,379		534		9,455		20,771		2,269		471		11,322
Energy and Other Taxes	1,185		830		798		947		3,003		1,277		1,052		2,530
Total Expenses	173,974		66,825		62,164		137,989		140,035		63,525		59,489		124,992
Other Income and Expense	1,086		1,477		2,186		811		1,450		810		764		773
Net Income	$	37,657	$	3,811	$	974	$	24,041	$	35,513	$	3,821	$	949	$	21,953

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

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 Rule 13a-15(e) under the Exchange Act) as of December 31, 2014. 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 Rule 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. In May 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control - Integrated Framework (2013 Framework). As such, 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 2013 framework issued by the COSO. Based on our evaluation under that framework, management concluded that our internal control over financial reporting was effective as of December 31, 2014.

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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 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 Rule 13a-15(f) under the Exchange Act, during the fiscal quarter ended December 31, 2014 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.

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 2014. 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 $519,000 and $477,000 in fiscal years 2014 and 2013, respectively.

Audit-Related Fees

None.

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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 27, 2015, 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-K 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)	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)(b)(x)	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)(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).

(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).

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Exhibit Number	Description	Reference

(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 February 27, 2015.

(10)(h)(vi)*	Officer Severance Plan.	Incorporated by reference from Exhibit 10(f)(i) of Form 10-K of SJI as filed February 27, 2015.

(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.

(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.

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Exhibit Number	Description	Reference
(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.

(10)(i)(x)	Term Loan Credit Agreement, dated as of June 5, 2014.	Incorporated by reference from Exhibit 10.1 of Form 8-K of SJG dated June 5, 2014.

(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.

(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).

(101.PRE)	XBRL Taxonomy Extension Presentation Linkbase (filed herewith).

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

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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 27, 2015	BY:	/s/ Stephen H. Clark
			Stephen H. Clark, Chief Financial Officer

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



Signature	Title	Date

/s/ Jeffrey E. DuBois	President, Director	February 27, 2015
(Jeffrey E. DuBois)	(Principal Executive Officer)

/s/ Stephen H. Clark	Chief Financial Officer	February 27, 2015
(Stephen H. Clark)	(Principal Financial Officer)

/s/ Thomas S. Kavanaugh	Controller	February 27, 2015
(Thomas S. Kavanaugh)

/s/ Thomas A. Bracken	Director	February 27, 2015
(Thomas A. Bracken)

/s/ Victor A. Fortkiewicz	Director	February 27, 2015
(Victor A. Fortkiewicz)

/s/ Edward J. Graham	Director	February 27, 2015
(Edward J. Graham)

/s/ Sunita Holzer	Director	February 27, 2015
(Sunita Holzer)

/s/ Frank L. Sims	Director	February 27, 2015
(Frank L. Sims)

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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, 2014	$	4,553	$	9,417	$	(102	)	$	7,267	$	6,601
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

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

(b) Uncollectible accounts written off.

SOUTH JERSEY GAS Co - FORM 10-K - February 27, 2015

Attached files

SOUTH JERSEY GAS Co Reports