SOUTH JERSEY GAS Co - FORM 10-K

Attached files

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EX-23 - EXHIBIT 23 - SOUTH JERSEY GAS Co	ex23.htm
EX-21 - EXHIBIT 21 - SOUTH JERSEY GAS Co	ex21.htm
EX-12 - EXHIBIT 12 - SOUTH JERSEY GAS Co	ex12.htm
EX-3.B - EXHIBIT 3B - SOUTH JERSEY GAS Co	ex3b.htm
EX-31.2 - EXHIBIT 31.2 - SOUTH JERSEY GAS Co	ex31_2.htm
EX-32.1 - EXHIBIT 32.1 - SOUTH JERSEY GAS Co	ex32_1.htm
EX-32.2 - EXHIBIT 32.2 - SOUTH JERSEY GAS Co	ex32_2.htm
EX-31.1 - EXHIBIT 31.1 - SOUTH JERSEY GAS Co	ex31_1.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, 2009

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). o Yes o No

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

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

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

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

Documents Incorporated by Reference: None

TABLE OF CONTENTS

		Page No.

Forward-Looking Statements		3

	PART I

Item 1.	Business	4
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	13
Item 2.	Properties	13
Item 3.	Legal Proceedings	14
Item 4.	Reserved	14

	PART II

Item 5.	Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	14
Item 6.	Selected Financial Data	15
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	15
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 8.	Financial Statements and Supplementary Data	38
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	82
Item 9A.	Controls and Procedures	82
Item 9B.	Other Information	83

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	83
Item 11.	Executive Compensation	83
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	84
Item 13.	Certain Relationships and Related Transactions, and Director Independence	84
Item 14.	Principal Accounting Fees and Services	84

	PART IV

Item 15.	Exhibits, Financial Statement Schedules	85

Signatures		90
Financial Statement Schedules		91

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Forward Looking Statements

Certain statements contained in this Annual Report on form 10-K may qualify as “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report should be considered forward-looking statements made in good faith by 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 South Jersey Gas Company, Inc. (SJG or the Company) believes these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, SJG undertakes no obligation to update or revise any of its forward-looking statements whether as a result of new information, future events or otherwise.

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

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PART I

Item 1. Business

Units of Measurement

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

Description of Business

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

Additional information on the nature of our business is incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Market Risk” and Note 2, “Rates and Regulatory Actions”.

Financial Information About Reportable Segments

Not applicable.

Rates and Regulation

Information on our rates and regulatory affairs is incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Note 2, “Rates and Regulatory Actions”.

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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 2009, SJG purchased and had delivered approximately 34.4 million decatherms (MMdts) of natural gas for distribution to both on-system and off-system customers. Of this total, 22.5 MMdts were transported on the Transco pipeline system while 11.9 MMdts were transported on the Columbia pipeline system. SJG also secures firm transportation and other long term services from two additional pipelines upstream of the Transco and Columbia systems. They include Columbia Gulf Transmission Company, LLC (Columbia Gulf) and Dominion Transmission, Inc. (Dominion). Services provided by these upstream pipelines 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 280,525 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 146,608 dts/d is market area FT. The terms of SJG’s year-round agreements extend for various periods through 2025. The terms of its seasonal agreements vary in length with the longest extending into 2013.

Of the 280,525 dts/d of Transco services mentioned above, SJG has released a total of 89,800 dts/d of its long-haul FT and 25,565 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.

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 terms of these storage service agreements extend for various periods from 2009 to 2013. During 2008 SJG released 17,433 dts/d of Transco SS-1 storage demand and 1,353,159 dts of its SS-1 storage capacity (both represent 100 percent of this service) thereby reducing its Transco maximum daily storage withdrawal quantity daily to 107,407 dts/d, and its storage capacity to approximately 5.0 MMdts. Also released was 17,433 dts/d of winter season firm transportation service associated with SS-1 storage service.

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Dominion:

SJG currently subscribes to a single firm transportation service from Dominion under Rate Schedule FTNN. This service facilitates the transportation of up to 5,545 dts/d from various Appalachian aggregation points to Transco’s Leidy Line for ultimate delivery to SJG city gate stations during the winter season (November through March) each year. The initial primary term of this agreement extends through October 31, 2010.

SJG also 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.

Columbia:

SJG has two firm transportation agreements with Columbia which, when combined, provide for 45,022 dts/d of firm deliverability and extend through October 31, 2019. In 2009, SJG released 14,714 dts/d of this amount to SJRG in conjunction with its CIP thereby reducing the availability of firm transportation on the Columbia system to 30,308 dts/d.

SJG also subscribes to a firm storage service (FSS) with Columbia under three separate agreements, the longest of which extends through October 31, 2019. When combined, these three FSS storage agreements provide SJG with a winter season MDWQ of 52,891 dts with an associated 3,473,022 dts of storage capacity. During 2009, SJG released to SJRG 17,500 dts of its FSS MDWQ along with 1,249,485 dts of its Columbia FSS storage capacity. In addition, SJG also released to SJRG 17,500 dts of its Columbia SST MDWQ transportation service which is associated with FSS service. Both of these releases were made by SJG in connection with its CIP.

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Columbia Gulf

Entering 2009, SJG had one firm transportation agreement with Columbia Gulf which provided up to 45,985 dts/d of firm deliverability in the winter season and 43,137dts/d during the summer season. This service facilitates the movement of gas from the production area in southern Louisiana to an interconnect with the Columbia pipeline system at Leach, KY. During 2009, SJG permanently released this capacity to SJRG.

Gas Supplies

SJG no longer has long-term gas supply agreements with third party producer-suppliers. In recent years, due to increased liquidity in the market place, SJG has replaced its long-term gas supply agreements with short-term agreements and uses financial contracts secured through SJRG to hedge against forward price risk. Short-term agreements typically extend between one day and several months in duration. As such, its long-term contracts were allowed to expire under their terms.

Supplemental Gas Supplies

During 2009, SJG entered into two seasonal Liquefied Natural Gas (LNG) sales agreements with two separate third party suppliers. The term of the first agreement which was used during the 2009 summer season to refill SJG’s storage tank, extended through November 30, 2009, and had an associated contract quantity of 250,000 dts. The second agreement was acquired to replenish LNG in storage during the 2009-2010 winter season. This agreement extends through March 31, 2010 and provides SJG with up to 250,000 dts of LNG.

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 96,750 dts of LNG per day for injection into its distribution system.

Entering 2009, SJG operated a high-pressure pipe storage field at its New Jersey LNG facility which was capable of storing 12,420 dts of gas and injecting up to 10,350 dts/d into SJG’s distribution system. During 2009, SJG retired this high-pressure storage field as it was no longer required for peaking services.

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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 2009-2010 winter season is estimated to be 459,139 dts. 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 2009 of 429,281 dts on January 16th while experiencing an average temperature of 12.22 degrees F that day.

Natural Gas Prices

SJG’s average cost of natural gas purchased and delivered in 2009, 2008 and 2007, including demand charges, was $8.38 per dt, $9.90 per dt and $9.07 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.

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Customers

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

Backlog

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

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 “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 11 of the financial statements included under Item 8 of this report.

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Employees

SJG had a total of 396 employees as of December 31, 2009. Of that total, 255 employees are unionized. There are 38 unionized employees represented by the International Brotherhood of Electrical Workers (“IBEW”) that operate under a collective bargaining agreement that runs through February 2013. The remaining unionized employees are represented by the International Association of Machinists and Aerospace Workers (“IAM”). Employees represented by the IAM recently agreed to a new collective bargaining agreement that expires in August 2014.

Financial Information About Foreign and Domestic Operations and Export Sales

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

Item 1A. Risk Factors

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

•

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

•

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

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•

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. While SJG currently has a conservation incentive program clause that protects its revenues and gross margin against usage that is lower than a set level, the clause is currently approved as a pilot program through 2013. Should this clause expire without replacement, lower customer energy utilization levels would likely reduce SJG’s net income.

•

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

•

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

•

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

•

The inability to obtain capital, particularly short-term capital from commercial banks, could negatively impact the daily operations and financial performance of SJG. SJG uses short-term borrowings under 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.

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•

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

•

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

•

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

•

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

•

Proposed 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 potential 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 proposed 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 consolidated financial condition, results of operations or cash flows.

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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, 2009, there were approximately 107.3 miles of mains in the transmission systems and 5,867 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 is 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, 2009, SJG’s utility plant had a gross book value of $1.3 billion and a net book value, after accumulated depreciation, of $961.2 million. In 2009, $98.7 million was spent on additions to utility plant and there were retirements of property having an aggregate gross book cost of $7.2 million.

Virtually all of SJG’s transmission pipeline, distribution mains and service connections are in 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.

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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 determine the amount or range of amounts of probable settlement costs. Management does not currently anticipate the disposition of any known claims to have a material adverse affect on SJG’s financial position, results of operations or liquidity.

Item 4. (Reserved)

PART II

Item 5. Market for the Registrant’s Common Equity

Related Stockholder Matters, and Issuer Purchases of Equity Securities

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

SJG is restricted as to the amount of cash dividends or other distributions that may be paid on its common stock by an order issued by the New Jersey Board of Public Utilities in July 2004, that granted SJG an increase in base rates. Per the order, SJG is required to maintain Total Common Equity of no less than $289.2 million. SJG’s Total Common Equity balance was $431.5 million at December 31, 2009.

SJG is also 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, 2009, these restrictions did not affect the amount that may be distributed from SJG’s retained earnings. Dividends of $10.0 million were declared and paid on SJG’s common stock in 2009 and $14.9 million were declared and paid in 2008.

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Item 6. Selected Financial Data

The following financial data has been obtained from SJG’s audited financial statements:

(In Thousands of $’s)

	Year Ended December 31,
		2009			2008			2007			2006			2005

Operating Revenues		$	484,376		$	568,046		$	630,547		$	642,671		$	587,212

Operating Income		$	81,439		$	84,417		$	83,989		$	81,209		$	77,676

Income before Preferred Dividend Requirement		$	39,195		$	39,431		$	38,025		$	35,779		$	34,592

Preferred Dividend Requirements (1)			-			-			-			-			(45	)

Net Income Applicable to Common Stock		$	39,195		$	39,431		$	38,025		$	35,779		$	34,547

Average Shares of Common Stock Outstanding			2,339,139			2,339,139			2,339,139			2,339,139			2,339,139

Ratio of Earnings to Fixed Charges (2)			4.9	x		4.4	x		4.1	x		3.7	x		4.0	x

	As of December 31,
		2009			2008			2007			2006			2005

Property, Plant and Equipment, Net		$	961,165		$	876,582		$	847,691		$	821,833		$	788,787

Total Assets		$	1,357,062		$	1,354,015		$	1,227,162		$	1,228,076		$	1,170,975

Capitalization:
Common Equity (3)		$	431,530		$	401,739		$	378,348		$	360,353		$	344,568
Preferred Stock (1)			-			-			-			-			-
Long-Term Debt			250,000			269,873			294,873			294,893			272,235

Total Capitalization		$	681,530		$	671,612		$	673,221		$	655,246		$	616,803
Total Customers			343,566			340,136			335,663			330,049			322,424

(1) On May 2, 2005, we redeemed all of our 8% Redeemable Cumulative Preferred Stock.

(2) 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 and preferred securities dividend requirements.

(3) Included are SJI cash contributions to capital as follows: 2009, 2008, 2007 and 2006 - none; 2005 - $30.0 million.

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.

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Our service territory covers approximately 2,500 square miles in the southern part of New Jersey. It includes 112 municipalities throughout Atlantic, Cape May, Cumberland and Salem Counties and portions of Burlington, Camden and Gloucester Counties, with an estimated permanent population of 1.2 million. We benefit from our proximity to Philadelphia, PA and Wilmington, DE on the western side of our service territory and Atlantic City, NJ and the popular shore communities on the eastern side. Economic development and housing growth have been long driven by the development of the Philadelphia metropolitan area. In recent years, housing growth in the eastern portion of our service territory has increased substantially and accounted for approximately half of our annual customer growth. Economic growth in Atlantic City and the surrounding region has been primarily driven by new gaming and non-gaming investments that emphasize destination style attractions. While many of these new projects were suspended or postponed due to the current economic environment, the casino industry is expected to remain a significant source of regional economic development going forward. The ripple effect from Atlantic City has produced new housing and commercial and industrial construction. Combining with the gaming industry catalyst is the ongoing conversion of southern New Jersey’s oceanfront communities from seasonal resorts to year round economies. New and expanded hospitals, schools, and large scale retail developments throughout the service territory have contributed to our growth. Presently, we serve approximately 65% 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, 2009, we served 343,566 residential, commercial and industrial customers in southern New Jersey, compared with 340,136 customers at December 31, 2008. No material part of our business is dependent upon a single customer or a few customers. Gas sales, transportation and capacity release for 2009 amounted to 98.7 MMdts (million dekatherms), of which 51.7 MMdts were firm sales and transportation, 2.3 MMdts were interruptible sales and transportation and 44.7 MMdts were off-system sales and capacity release. The breakdown of firm sales and transportation includes 47.9% residential, 23.2% commercial, 23.9% industrial, and 5.0% cogeneration and electric generation. At year-end 2009, we served 320,290 residential customers, 22,802 commercial customers and 474 industrial customers. This includes 2009 net additions of 3,264 residential customers and 166 commercial customers.

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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 2009, off-system sales amounted to 6.3 MMdts and capacity release amounted to 38.4 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 2009 usage by interruptible customers, excluding off-system customers, amounted to 2.3 MMdts, approximately 2.4% of the total throughput.

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

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

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

Customer Growth — Southern New Jersey, our primary area of operations, has not been immune to the issues impacting the new housing market nationally. However, net customers for SJG still grew 1.0% as we increased our focus on customer conversions. In 2009, the 3,053 consumers converting their homes and businesses from other heating fuels, such as electric, propane or oil represented over 50% of the total new customer acquisitions for the year. In comparison, conversions over the past five years averaged 2,274 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.

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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.

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 - In recent years, prices for natural gas have become increasingly volatile. 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 health care, have risen in recent years. We sought to manage these costs by revising health care plans offered to existing employees, capping postretirement health care benefits, and changing health care and pension packages offered to new hires. We expect savings from these changes to gradually increase as new hires replace retiring employees. In an effort to accelerate the realization of those benefits, we had offered a voluntary separation program at the end of 2007. Our workforce totaled 396 employees at the end of 2009, with 65% of that total covered under collective bargaining agreements.

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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 52.2% and 49.5% at the end of 2009 and 2008, respectively. A strong balance sheet permits us the financial flexibility necessary to address volatile economic and commodity markets while maintaining a low-risk platform.

Critical Accounting Policies - Estimates and Assumptions - As described in the notes to our financial statements, management must make estimates and assumptions that affect the amounts reported in the financial statements and related disclosures. Actual results could differ from those estimates. Five types of transactions presented in our financial statements require a significant amount of judgment and estimation. These relate to regulatory accounting, derivatives, environmental remediation costs, pension and other postretirement benefit costs, and revenue recognition.

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

The Conservation Incentive Program (CIP) is a BPU approved pilot program that is designed to eliminate the link between our profits and the quantity of natural gas we sell, and 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 where actual usage per customer experienced during an annual period varies from an established baseline usage per customer. 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.

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In addition to the BGSS and the CIP, other regulatory assets consist primarily of remediation costs associated with manufactured gas plant sites (discussed below under Environmental Remediation Costs), deferred pension and other postretirement benefit cost, and several other assets as detailed in Note 3 to the financial statements. If there are changes in future regulatory positions that indicate the recovery of such regulatory assets is not probable, we would charge the related cost to earnings. Currently, there are no such anticipated changes at the BPU.

Derivatives - We recognize assets or liabilities for contracts that qualify as derivatives when contracts are executed. We record contracts at their fair value in accordance with FASB ASC Topic 815 – “Derivatives and Hedging.” We record changes in the fair value of the effective portion of derivatives qualifying as cash flow hedges, net of tax, in Accumulated Other Comprehensive Loss and recognize such changes in the income statement when the hedged item affects earnings. Changes in the fair value of derivatives not designated as hedges are recorded in earnings in the current period. In 2007, we changed our policy to no longer designate energy-related derivative instruments as cash flow hedges. Certain derivatives that result in the physical delivery of the commodity may meet the criteria to be accounted for as normal purchases and normal sales, if so designated, in which case the contract is not marked-to-market, but rather is accounted for when the commodity is delivered. Due to the application of regulatory accounting principles under GAAP, derivatives related to gas purchases that are marked-to-market are recorded through our BGSS. We periodically enter into financial derivatives to hedge against forward price risk. These derivatives are recorded at fair value with an offset to regulatory assets and liabilities through our BGSS, subject to BPU approval (See Notes 2 and 3 to the financial statements). We adjust the fair value of the contracts each reporting period for changes in the market.

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As discussed in Note 12 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 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 11 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. In 2008, a 32 basis point increase in the discount rate, higher than expected returns on plan assets during 2007, and a pension contribution in the first quarter of 2008 reduced such benefit costs in 2009. While the discount rate and expected return on plan assets both decreased slightly in the determination of the 2009 benefit costs, the primary cost driver in 2009 was the erosion of plan assets during 2008. As evidenced by the tables in Note 10, “Pension and Other Postretirement Benefits,” the declines in the equity markets during 2008 resulted in significant unrealized losses in the assets of the plans. Such losses caused the 2009 cost of providing such benefits to more than double.

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The recognition of the unrealized losses originating in 2008 over the average remaining service period of active plan participants will continue to cause the cost of providing such plans to remain relatively high in 2010. While additional pension contributions and improvements in equity markets during 2009 should partially offset this increase, a 50 basis point decrease in the expected return on plan assets in 2010 will mitigate that benefit.

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 Basic Gas Supply Service (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 2 and 3 to the financial statements).

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

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

Rates and Regulation - As a public utility, we are subject to regulation by the New Jersey Board of Public Utilities (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, Columbia Gulf Transmission Company 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, Capital Investment Recovery Tracker (CIRT), Energy Efficiency Tracker (EET) and the Conservation Incentive Program.

Basic Gas Supply Service Clause (BGSS) - In December 2002, the BPU approved the BGSS price structure which gave customers the ability to make more informed decisions regarding their choices of an alternate supplier by having a utility price structure that is more consistent with market conditions. The cost of gas purchased from the utility by our periodic consumers is set annually by the BPU through a BGSS clause within our tariff. When actual gas costs experienced are less than those charged to customers under the BGSS, customer bills in the subsequent BGSS period(s) are reduced by returning the overrecovery with interest. When actual gas costs are more than is recovered through rates, we are permitted to charge customers more for gas in future periods to recover the shortfall.

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Capital Investment Recovery Tracker (CIRT) – In April 2009, the BPU approved an accelerated infrastructure investment program and an associated rate tracker, which allows SJG to accelerate $103.0 million of capital spending into 2009 and 2010. The CIRT allows SJG to earn a return of, and return on, investment as the capital is spent.

Energy Efficiency Tracker (EET) – In July 2009, the BPU approved an energy efficiency program to invest $17.0 million over two years in energy efficiency programs for residential, commercial and industrial customers. Under this program SJG can recover incremental operating and maintenance expenses and earn a return of, and return on, program investments.

Conservation Incentive Program (CIP) - The CIP is a BPU approved pilot program that is designed to eliminate the link between our profits and the quantity of natural gas we sell, and 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. Under the terms of the settlement, the CIP may be extended for a one year period in the absence of a Board order taking any affirmative action to the contrary with regard to the pilot program.

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

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

	2009		2008		2007
Net Income Benefit:
CIP – Weather Related		0.8		1.6		1.6
CIP – Usage Related		8.5		9.2		5.9
Total Net Income Benefit	$	9.3	$	10.8	$	7.5

Weather Compared to 20-Year Average	1.1% warmer		4.7% warmer		3.2% warmer
Weather Compared to Prior Year	3.9% colder		1.6% warmer		13.8% colder

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

Earnings accrued and payments received under the CIP are limited to a level that will not cause our return on equity to exceed 10% (excluding earnings from off-system gas sales and certain other tariff clauses) and the annualized savings attained from reducing gas supply and storage assets.

Other Rate Mechanisms - Our tariff also contains provisions permitting the recovery of environmental remediation costs associated with former manufactured gas plant sites, energy efficiency and renewable energy program costs, consumer education program costs and low-income program costs. These costs are recovered from customers through our Societal Benefits Clause.

See additional detailed discussions on Rates and Regulatory Actions in Note 2 to the financial statements.

Environmental Remediation - See detailed discussion concerning Environment Remediation in Note 11 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).

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Customer Choice Legislation - All residential natural gas customers in New Jersey can choose their natural gas commodity supplier under the terms of the “Electric Discount and Energy Competition Act of 1999.” This bill created the framework and necessary time schedules for the restructuring of the state’s electric and natural gas utilities. The Act established unbundling, 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 28,379, 28,637 and 25,309 during 2009, 2008 and 2007, 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):

	2009				2008				2007
Utility Throughput – dth:
Firm Sales -
Residential		22,736	23	%		21,530	15	%		22,523	16	%
Commercial		6,063	6	%		6,127	4	%		6,339	4	%
Industrial		331	1	%		188	-			193	-
Cogeneration and electric generation		322	-			561	-			1,335	1	%
Firm Transportation -
Residential		2,005	2	%		1,988	1	%		1,870	1	%
Commercial		5,930	6	%		5,687	4	%		5,927	4	%
Industrial		12,002	12	%		12,661	9	%		12,107	9	%
Cogeneration and electric generation		2,290	2	%		2,536	2	%		3,088	2	%

Total Firm Throughput		51,679	52	%		51,278	35	%		53,382	37	%

Interruptible Sales		5	-			35	-			68	-
Interruptible Transportation		2,314	2	%		2,716	2	%		3,002	2	%
Off-System		6,282	7	%		9,632	7	%		17,686	13	%
Capacity Release		38,387	39	%		80,665	56	%		67,430	48	%

Total Throughput		98,667	100	%		144,326	100	%		141,568	100	%

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Utility Operating Revenues:
Firm Sales-
Residential	$	318,143	66	%	$	320,401	57	%	$	342,809	54	%
Commercial		71,669	15	%		81,914	15	%		80,237	13	%
Industrial		3,824	1	%		5,434	1	%		8,381	1	%
Cogeneration and electric generation		2,709	1	%		7,940	1	%		11,722	2	%
Firm Transportation -
Residential		10,491	2	%		10,408	2	%		8,982	1	%
Commercial		19,722	4	%		18,286	3	%		17,299	3	%
Industrial		14,751	3	%		12,504	2	%		12,229	2	%
Cogeneration and electric generation		2,272	-			1,682	-			1,847	-

Total Firm Revenues		443,581	92	%		458,569	81	%		483,506	76	%

Interruptible Sales		89	-			403	-			785	-
Interruptible Transportation		2,122	-			1,786	-			1,970	-
Off-System		32,978	7	%		90,430	16	%		131,586	22	%
Capacity Release		4,282	1	%		15,549	3	%		11,208	2	%
Other		1,324	-			1,309	-			1,492	-

Total Utility Operating Revenues		484,376	100	%		568,046	100	%		630,547	100	%

Less:
Cost of sales		293,852				383,403				453,034
Conservation recoveries *		7,718				7,741				4,458
RAC recoveries *		5,189				3,079				2,056
EET Recoveries *		190				-				-
Revenue taxes		8,836				8,656				8,850
Utility Margin	$	168,591			$	165,167			$	162,149

Margin:
Residential	$	104,373	62	%	$	99,862	61	%	$	102,077	63	%
Commercial and industrial		39,853	24	%		38,995	24	%		40,036	25	%
Cogeneration and electric generation		2,251	1	%		1,997	1	%		2,212	1	%
Interruptible		144	-			143	-			195	-
Off-system & capacity release		1,416	1	%		3,349	2	%		2,994	2	%
Other revenues		2,511	1	%		2,440	1	%		1,952	1	%
Margin before weather normalization & decoupling		150,548	89	%		146,786	89	%		149,466	92	%
CIRT mechanism		2,198	1	%		-	-			-	-
CIP mechanism		15,809	10	%		18,381	11	%		12,683	8
EET mechanism		36	-			-	-			-	-
Utility Margin	$	168,591	100	%	$	165,167	100	%	$	162,149	100	%

Number of Customers at Year End:
Residential		320,290	93	%		317,026	93	%		312,969	93	%
Commercial		22,802	7	%		22,636	7	%		22,220	7	%
Industrial		474	-			474	-			474	-
Total Customers		343,566	100	%		340,136	100	%		335,663	100	%

Annual Degree Days:		4,588				4,417				4,488

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

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Throughput - Total gas throughput decreased 45.7 MMdts, or 31.6%, from 2008 to 2009. Off-System sales (OSS) and capacity release volume decreased substantially as SJG’s portfolio of assets available for such activities has been reduced in each of the past 3 years under the Conservation Incentive Program, as discussed under “Rates and Regulation.” As the majority of profits from OSS and capacity release are returned to the ratepayers via a BPU-approved sharing formula, the resulting impact of such decreased activity on SJG earnings is greatly mitigated, as reflected in the margin table above. Firm throughput increased in the residential market as a result of 3.9% colder weather and the addition of 3,264 residential customers during 2009. Total gas throughput increased 2.8 MMdts, or 1.9%, from 2007 to 2008. This increase was driven by greater capacity release activity during 2008 as market demand for such capacity had increased. Firm throughput declined as a result of warmer weather and customer conservation. As previously discussed, OSS volume decreased substantially as SJG’s portfolio of assets available for such activities was reduced. Changes in throughput in other customer categories were not significant.

Operating Revenues – Revenues decreased $83.7 million, or 14.7%, during 2009 compared with 2008. This was the result of a substantial decrease in Off-System Sales (OSS) and Capacity Release revenue, which decreased by $57.5 million and $11.3 million, respectively, during 2009 compared with 2008. These decreases were primarily related to continued reductions in SJG’s portfolio of assets available for such activities under the provisions of the CIP, as noted above under “Throughput”, and a significant decrease in the average cost per unit sold during 2009. The cost of natural gas had declined so dramatically during 2009 that OSS unit sales prices declined from an average of $9.39 per decatherm (Dt) during 2008 to only $5.25 per Dt during 2009. As reflected in the Margin table above, the impact of lower OSS and Capacity Release did not have a material impact on the earnings of the Company, as SJG is required to share 85% of the profits of such activity with the rate payers. Firm sales revenue decreased approximately $15.0 million as a result of significantly lower natural gas prices during 2009. The average cost of natural gas purchased during 2009 was $7.52 per Dt, representing a 27.5% decrease relative to the average cost of $10.38 per Dt in 2008. This decrease in natural gas costs precipitated a customer refund of over recovered gas costs through the BPU-approved Basic Gas Supply Service (BGSS) in October 2009 totaling approximately $20.4 million. While changes in gas costs, BGSS recoveries and refunds, when applicable, may 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 under “Margin.”

Revenues decreased $62.5 million, or 9.9%, during 2008 compared with 2007. Off-System sales revenue decreased $41.2 million as SJG’s portfolio of assets available for OSS had been reduced under the CIP. Total firm revenues decreased during 2008 compared to 2007 primarily due to warmer weather and lower residential revenues resulting from a lower BGSS rate in effect during most of 2008. For nearly the entire year, the 2008 BGSS rate was 12.7% lower than the rate in effect during the corresponding period in 2007. SJG reduced its BGSS rate in October 2007 primarily due to a combination of actual and forecasted decreases in wholesale gas costs. As previously stated, the Company does not profit from the sale of the commodity; therefore, the BGSS rate decrease did not have an impact on Company profitability. Finally, the Company experienced lower sales to the region’s electric utility, as their demand to consume natural gas to generate electric during the summer months decreased substantially. Since the majority of the Company’s profits from electric generation sales are contractually fixed, the decrease in volume and revenue had little impact on profitability. Partially offsetting these decreases, SJG added 4,473 customers during the 12-month period ended December 31 2008, which represents a 1.3% increase in total customers.

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Margin - Our margin is defined as natural gas revenues less natural gas costs; volumetric and revenue based energy taxes; and regulatory rider expenses. We believe that margin provides a more meaningful basis for evaluating utility operations than revenues since natural gas costs, energy taxes and regulatory rider expenses are passed through to customers, and therefore, have no effect on our profitability. Natural gas costs are charged to operating expenses on the basis of therm sales at the prices approved by the New Jersey Board of Public Utilities through our BGSS tariff.

Total margin in 2009 increased $3.4 million, or 2.1%, from 2008 primarily due to customer additions of 3,430 and approval in 2009 of SJG’s Capital Investment Recovery Tracker (CIRT), as discussed above under “Rates and Regulation.” The CIRT allows SJG to earn a return on approved infrastructure investments made under this program. Partially offsetting these increases was a decrease in off-system sales and capacity release margins due to continued reductions in SJG’s portfolio of assets available for such activities as discussed above.

The CIP protected $15.8 million of pre-tax margin that would have been lost due to lower customer usage, compared with $18.4 million in 2008. Of these amounts, $1.4 million and $2.7 million were related to weather variations and $14.4 million and $15.7 million were related to other customer usage variations in 2009 and 2008, respectively.

Total margin in 2008 increased $3.0 million, or 1.9%, from 2007 primarily due to customer additions, as noted above, increased margins from OSS and capacity release, and increased profits earned through the Company’s Storage Incentive Mechanism (SIM). The SIM allows the Company to retain 20% of storage-related gains and losses as measured against an established benchmark. The balance of these gains and losses are passed through to customers as part of the BGSS.

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The CIP protected $18.4 million of pre-tax margin in 2008 that would have been lost due to lower customer usage, compared to $12.7 million in 2007. Of these amounts, $2.7 million and $2.6 million were related to weather variations and $15.7 million and $10.1 million were related to other customer usage variations in 2008 and 2007, respectively.

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

	2009 vs. 2008		2008 vs. 2007

Operations	$	6,422	$	4,375
Maintenance		970		1,554
Depreciation		1,267		975
Energy and Other Taxes		200		(202	)

Operations – Operations expense increased $6.4 million during 2009, as compared with 2008. The increases are primarily comprised of the following factors.

First, the cost of providing pension and other postretirement benefit plans increased by $2.9 million and $1.0 million, respectively, as compared with 2008. This was the result of significant losses in the assets of those plans during 2008. Additional information regarding these benefit plans can be found in Note 10 of the Notes to Financial Statements. Second, corporate support, governance and compliance costs, primarily attributable to our parent, SJI, also rose $1.1 million in 2009 as compared with 2008. Third, our spending under the newly approved Energy Efficiency Tracker (EET) was $0.2 million in 2009. Such costs are recovered on a dollar-for-dollar basis; therefore, SJG experienced an offsetting increase in revenues during 2009. The BPU-approved EET allows for full recovery of costs, including carrying costs when applicable. As a result, this new item of expense had no impact on our net income. Finally, SJG experienced increases in various other areas including general compensation increases; higher bank fees to support higher lines of credit available to the Company; and higher insurance costs.

Operations expense increased $4.4 million during 2008, as compared with 2007, primarily due to increased spending under the New Jersey Clean Energy Program (NJCEP), which increased $3.3 million during 2008 compared with 2007. Such costs are recovered on a dollar-for-dollar basis; therefore, SJG experienced an offsetting increase in revenues during the period. The BPU-approved NJCEP allows for full recovery of costs, including carrying costs when applicable. As a result, the increase in expense had no impact on our net income. Second, corporate support, governance and compliance costs, primarily attributable to our parent, SJI, rose $0.9 million during 2008. Finally the Company also experienced moderate increases in insurance and employee compensation costs; however, these were offset by lower pension and other cost reductions during the year 2008.

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Maintenance – Maintenance expense increased $1.0 million during 2009, compared with 2008, primarily due to an increase in Remediation Adjustment Clause (RAC) expense amortization. As discussed in Notes 2 and 3 to the Financial Statements, these costs are recovered from ratepayers; therefore, SJG experienced an offsetting increase in revenue during 2009.

Maintenance expense increased $1.6 million during 2008, compared with 2007, primarily due to a $1.2 million increase in RAC expense amortization. The remaining increase was the result of installing safety devices on certain residential meters aimed at preventing unauthorized usage and maintenance of company equipment.

Depreciation - Depreciation expense increased $1.3 million and $1.0 million in 2009 and 2008, respectively, due mainly to our continuing investment in utility plant. SJG’s investment in utility plant during 2009, 2008 and 2007 was $98.7 million, $52.6 million and $48.1 million, respectively. The increased spending in 2009 was a direct result of the State’s stimulus efforts which included the approval of SJG’s Capital Investment Recovery Tracker, as discussed under “Rates and Regulation.”

Energy and Other Taxes – Energy and Other Taxes increased in 2009, compared with 2008, primarily due to higher taxable firm throughput in 2009. Higher taxable firm throughput in 2009 resulted from colder weather and customer growth in 2009. This was partially offset by lower revenue-based taxes as revenues decreased substantially during 2009.

Energy and Other Taxes decreased $0.2 million during 2008, compared with 2007, primarily due to lower taxable firm throughput in 2008, which resulted from warmer weather and conservation. These factors were partially offset by customer growth in 2008.

Other Income and Expense - Other income and expense was lower in 2008, when compared with both 2009 and 2007. This was primarily due to the poor earnings performance of our available-for-sale securities as a result of significant declines in the equity markets in 2008. In addition, the Company recognized an impairment loss of $0.7 million during 2008. No impairment losses were recognized in either 2009 or 2007. These securities represent assets held in trusts for the payment of postretirement healthcare costs.

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Interest Charges – Interest charges decreased by $2.5 million in 2009, compared with 2008, due primarily to significantly lower average short-term interest rates, partially offset by higher debt levels during 2009.

Interest charges decreased by $2.0 million for 2008, compared with 2007. The decrease was the result of lower average short-term interest rates and debt levels, partially offset by higher interest rates incurred on auction-rate securities during the first half of 2008.

LIQUIDITY AND CAPITAL RESOURCES:

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

Cash Flows from Operating Activities - Cash generated from operating activities constitutes our primary source of liquidity and varies from year-to-year due to the impact of weather on customer demand and related gas purchases, customer usage factors related to conservation efforts and the price of the natural gas commodity, inventory utilization and recoveries provided through our various rate mechanisms. Net cash provided by operating activities was $122.9 million in 2009, $30.3 million in 2008 and $89.4 million in 2007.

Cash provided from operating activities increased in 2009, as compared with 2008, primarily as a result of lower unit gas costs and the impact of those costs on natural gas inventory balances. The Company also incurred lower environmental remediation costs in 2009 as compared with 2008. The lower environmental remediation costs include a decrease in remediation expenditures as well as increased insurance recoveries during 2009.

Cash provided by operating activities decreased in 2008, as compared with 2007, primarily as a result of higher unit gas costs and the impact of those costs on natural gas inventory balances. Further, in anticipation of a large transmission pipeline project in 2009, SJG purchased and inventoried $9.3 million of pipe at the end of 2008. SJG also incurred significantly higher, planned environmental remediation costs in 2008 compared with the prior year. Finally, SJG made a $4.8 million pension contribution during 2008. No such contribution was made in the prior year.

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 $98.7 million, $52.6 million and $48.1 million in 2009, 2008 and 2007, respectively, primarily due to infrastructure improvements that continue to support SJG’s growth. The increase in the 2009 capital expenditures was the direct result of the Company’s CIRT program which began in 2009. See additional details under “Rates and Regulation”.

Cash Flows from Financing Activities - We use short-term borrowings under 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.

Credit facilities and available liquidity as of December 31, 2009 were as follows (in thousands):

	Total Facility		Usage		Available Liquidity		Expiration Date

Revolving Credit Facility	$	100,000	$	85,000	$	15,000	August 2011
Line of Credit		40,000		10,000		30,000	December 2010 (A)
Uncommitted Bank Lines		55,000		14,400		40,600	Various

Total	$	195,000	$	109,400	$	85,600

(A) SJG anticipates extending this line of credit during the fourth quarter of 2010. 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.

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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 September 2009, SJG received approval from the New Jersey Board of Public Utilities to issue up to $150.0 million in long-term debt by September 2011. The timing, terms and amount will vary depending on market conditions. SJG intends to borrow $15.0 million in March 2010 and $45.0 million by June 2010 in a delayed funding under a private placement. In November 2009, SJG completed an early redemption of $9.9 million of 6.5% bonds due in 2016. We redeemed this debt early to achieve significant interest expense savings due to the low interest rates available to SJG.

In June 2008, SJG repurchased $25.0 million of its auction-rate securities at par by drawing under its lines of credit. That action resulted in a $25.0 million reduction in long-term debt on SJG’s balance sheet. SJG converted these repurchased auction-rate securities to variable-rate demand bonds and remarketed them to the public during the third quarter of 2008. No other long-term debt was issued during 2008 or 2009. We repaid long-term debt totaling $9.9 million, $25.0 million and $2.3 million in 2009, 2008 and 2007, respectively.

SJI contributed no capital to us in 2009, 2008 or 2007.

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

	2009			2008

Common Equity		52.2	%		49.5	%
Long-Term Debt		30.3	%		36.4	%
Short-Term Debt		17.5	%		14.1	%

Total		100.0	%		100.0	%

Our long-term, senior secured debt is rated “A” and “A2” by Standard & Poor’s and Moody’s Investor Services, respectively. These ratings had not changed in at least the past five years until August 2009 when Moody’s Investor Services raised SJG’s senior secured rating to “A2” from “Baal”.

We are restricted as to the amount of cash dividends or other distributions that may be paid on our common stock by an order issued by the BPU in July 2004, that granted us an increase in base rates. Per the order, we are required to maintain total common equity of no less than $289.2 million. Our total common equity balance was $431.5 million at December 31, 2009.

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COMMITMENTS AND CONTINGENCIES:

We have a continuing need for cash resources and capital, primarily to invest in new and replacement facilities and equipment and for environmental remediation costs. Net cash outflows for construction and remediation projects for 2009 amounted to $98.7 million and $0.4 million, respectively. We estimate total cash outflows for construction and remediation projects for 2010, 2011 and 2012, to be approximately $153.9 million, $69.5 million and $65.5 million, respectively. As discussed in Notes 3 and 11 to the financial statements, certain environmental costs are subject to recovery from insurance carriers and ratepayers.

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 6 to the financial statements. This letter of credit expires in August 2010.

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, 2009, average $44.3 million annually and total $177.2 million over the contracts’ lives. Approximately 28% of the financial commitments under these contracts expire during the next five years. We expect to renew each of these contracts under renewal provisions as provided in each contract. We recover all prudently incurred fees through rates via the Basic Gas Supply Service clause.

The following table summarizes our contractual cash obligations and their applicable payment due dates as of December 31, 2009 (in thousands):

			Up to		Years		Years		More than
Contractual Cash Obligations	Total		1 Year		2 & 3		4 & 5		5 Years

Principal Payments on Long-Term Debt	$	285,000	$	35,000	$	27,187	$	50,375	$	172,438
Interest on Long-Term Debt		179,317		16,352		29,735		26,254		106,976
Operating Leases		82		63		19		-		-
Construction Obligations		239		239		-		-		-
Commodity Supply Purchase Obligations		177,175		39,403		33,470		24,364		79,938
New Jersey Clean Energy Program (Note 2)		33,117		9,205		23,912		-		-
Other Purchase Obligations		418		418		-		-		-

Total Contractual Cash Obligations	$	675,348	$	100,680	$	114,323	$	100,993	$	359,352

As discussed in Note 6 to the financial statements, SJG’s variable-rate debt of $25.0 million has been included in the current portion of long-term debt above. However, interest on long-term debt in the table above includes the related interest obligations through maturity, as well as the impact of the related interest rate swap agreements on this variable-rate debt.

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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 has no obligation to make a contribution to its employee pension plans in 2010. Furthermore, future pension contributions beyond 2010 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 10 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 - We are subject to claims arising in the ordinary course of business and other legal proceedings. We accrue liabilities related to claims when we can determine the amount or range of amounts of probable settlement costs. Management does not currently anticipate the disposition of any known claims to have a material adverse 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.

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We transact commodities on a physical basis and typically do not enter into financial derivative positions directly. South Jersey Resources Group, LLC, an affiliate by common ownership, manages our risk by entering into the types of transactions noted above. As part of our gas purchasing strategy, we use financial contracts to hedge against forward price risk. These contracts are recoverable through our BGSS, subject to BPU approval. It is management’s policy, to the extent practical, within predetermined risk management policy guidelines, to have limited unmatched positions on a deal or portfolio basis while conducting these activities. As a result of holding open positions to a minimal level, the economic impact of changes in value of a particular transaction is substantially offset by an opposite change in the related hedge transaction. The majority of our contracts are typically less than 12-months long. The fair value and maturity of all these energy trading and hedging contracts determined using mark-to-market accounting as of December 31, 2009 is as follows (in thousands):

Assets:		Maturity		Maturity
	Source of Fair Value	<1 Year		1 - 3 Years		Total

Prices Actively Quoted	NYMEX	$	797	$	192	$	989
Other External Sources	Basis		-		141		141
Total		$	797	$	333	$	1,130

Liabilities:		Maturity		Maturity
	Source of Fair Value	<1 Year		1 - 3 Years		Total

Prices Actively Quoted	NYMEX	$	8,229	$	336	$	8,565
Other External Sources	Basis		1,570		168		1,738
Total		$	9,799	$	504	$	10,303

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 14.3 MMdts with a weighted-average settlement price of $6.45 per dt. Contracted volumes of our Basis contracts are 6.3 MMdts with a weighted-average settlement price of $1.23 per dt.

A reconciliation of our estimated net fair value of energy-related derivatives, including energy trading and hedging contracts follows (in thousands):

Net Derivatives — Energy Related Liability, January 1, 2009	$	(28,970	)
Contracts Settled During 2009, Net		26,318
Other Changes in Fair Value from Continuing and New Contracts, Net		(6,521	)
Net Derivatives — Energy Related Liability, December 31, 2009	$	(9,173	)

The change in our derivative position from a $29.0 million liability at December 31, 2008 to a $9.2 million liability at December 31, 2009 is primarily due to the change in value of our financial positions held with SJRG. As of December 31, 2008 the average future price was approximately $6.15 per dt vs. $5.80 per dt as of December 31, 2009.

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Interest Rate Risk - Our exposure to interest rate risk relates primarily to short-term, variable-rate borrowings. Short-term, variable-rate debt outstanding at December 31, 2009, was $109.4 million and averaged $94.4 million during 2009. The months where average outstanding variable-rate debt was at its highest and lowest levels were December, at $109.4 million, and April, at $73.3 million. A hypothetical 100 basis point (1%) increase in interest rates on our average variable-rate debt outstanding would result in a $556,200 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: 2009 – 29 b.p. decrease; 2008 - 317 b.p. decrease; 2007 – 36 b.p. decrease; 2006 - 72 b.p. increase; and 2005 - 191 b.p. increase. As of December 31, 2009, our average borrowing cost, which changes daily, was 0.80%.

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, 2009, the interest costs on all of our long-term debt was either at a fixed-rate or hedged via an interest rate derivative. Consequently, interest expense on existing long-term debt is not significantly impacted by changes in market interest rates. However, due to general market conditions during 2008, the demand for auction-rate securities was disrupted resulting in increased interest rate volatility for tax-exempt auction-rate debt. As a result, the $25.0 million of tax-exempt auction-rate debt issued by the Company (and repurchased in June 2008) was exposed to changes in interest rates that were not completely mitigated by the related interest rate derivatives. The auction-rate debt was converted to another form of variable- rate debt and resold in the public market in August 2008. The original interest rate derivatives remain in place and are expected to substantially offset changes in interest rates on the security.

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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, 2009 and 2008, and the related statements of income, cash flows, and changes in common equity and comprehensive income for each of the three years in the period ended December 31, 2009. 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 these 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, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, 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 26, 2010

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SOUTH JERSEY GAS COMPANY

STATEMENTS OF INCOME
(In Thousands)
	Year Ended December 31,
	2009			2008			2007

Operating Revenues	$	484,376		$	568,046		$	630,547

Operating Expenses:
Cost of Sales (Excluding depreciation)		293,852			383,403			453,034
Operations		62,533			56,111			51,736
Maintenance		8,869			7,899			6,345
Depreciation		26,856			25,589			24,614
Energy and Other Taxes		10,827			10,627			10,829

Total Operating Expenses		402,937			483,629			546,558

Operating Income		81,439			84,417			83,989

Other Income and Expense		1,302			459			1,673

Interest Charges		(16,442	)		(18,937	)		(20,985	)

Income Before Income Taxes		66,299			65,939			64,677

Income Taxes		(27,104	)		(26,508	)		(26,652	)

Net Income	$	39,195		$	39,431		$	38,025

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,
	2009			2008			2007

Cash Flows from Operating Activities:
Net Income	$	39,195		$	39,431		$	38,025
Provided by Operating Activities:
Depreciation and Amortization		34,507			31,506			29,317
Provision for Losses on Accounts Receivable		2,418			2,281			2,672
TAC/CIP Receivable		5,376			2,641			(7,946	)
Deferred Gas Costs - Net of Recoveries		(7,910	)		5,885			7,755
Deferred SBC Costs - Net of Recoveries		(119	)		1,199			3,960
Environmental Remediation Costs - Net of Recoveries		(444	)		(26,177	)		(10,926	)
Deferred and Noncurrent Income Taxes and Credits - Net		22,104			21,378			12,957
Gas Plant Cost of Removal		(1,678	)		(1,463	)		(1,275	)
Changes in:
Accounts Receivable		3,526			(4,531	)		(8,528	)
Inventories		47,934			(18,659	)		24,884
Prepaid and Accrued Taxes - Net		4,321			(1,657	)		(2,099	)
Other Prepayments and Current Assets		168			(138	)		(14	)
Gas Purchases Payable		(16,957	)		1,717			(8,817	)
Accounts Payable and Other Accrued Liabilities		(5,856	)		(13,857	)		9,787
Other Assets		(2,132	)		(375	)		(121	)
Other Liabilities		(1,534	)		(8,920	)		(272	)

Net Cash Provided by Operating Activities		122,919			30,261			89,359

Cash Flows from Investing Activities:
Capital Expenditures		(98,673	)		(52,580	)		(48,070	)
Investment in Long-Term Receivables		(4,730	)		(5,558	)		(4,123	)
Proceeds from Long-Term Receivables		5,399			3,399			3,877
Purchase of Restricted Investment with Escrowed Loan Proceeds		-			(39	)		(363	)
Restricted Investment - Escrowed Loan Proceeds		-			2,146			6,710

Net Cash Used in Investing Activities		(98,004	)		(52,632	)		(41,969	)

Cash Flows from Financing Activities:
Net (Repayments of) Borrowing from Lines of Credit		(5,150	)		36,210			(25,160	)
Proceeds from Issuance of Long-Term Debt		-			25,000			-
Principal Repayments of Long-Term Debt		(9,873	)		(25,000	)		(2,290	)
Dividends on Common Stock		(10,002	)		(14,867	)		(18,732	)
Payments for Issuance of Long-Term Debt		(178	)		(320	)		-
Excess Tax Benefit from Restricted Stock Plan		53			346			55

Net Cash (Used in) Provided by Financing Activities		(25,150	)		21,369			(46,127	)

Net (Decrease) Increase in Cash and Cash Equivalents		(235	)		(1,002	)		1,263
Cash and Cash Equivalents at Beginning of Period		2,228			3,230			1,967

Cash and Cash Equivalents at End of Period	$	1,993		$	2,228		$	3,230

Supplemental Disclosures of Cash Flow Information:
Interest (Net of Amounts Applicable to Gas Cost Overcollections and Amounts Capitalized)	$	17,926		$	19,550		$	20,863
Income Taxes (Net of Refunds)	$	(4,308	)	$	7,315		$	15,684

Supplemental Disclosures of Noncash Investing Activities:
Capital property and equipment acquired on account but not paid at year-end	$	19,166		$	7,590		$	4,182

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,
	2009			2008
Assets

Property, Plant and Equipment:
Utility Plant, at original cost	$	1,275,792		$	1,172,014
Accumulated Depreciation		(314,627	)		(295,432	)

Property, Plant and Equipment – Net		961,165			876,582

Investments:
Available-for-Sale Securities		5,941			4,841
Restricted Investments		132			132

Total Investments		6,073			4,973

Current Assets:
Cash and Cash Equivalents		1,993			2,228
Accounts Receivable		41,392			47,787
Accounts Receivable - Related Parties		974			624
Unbilled Revenues		47,333			48,225
Provision for Uncollectibles		(3,915	)		(3,628	)
Natural Gas in Storage, average cost		23,711			65,252
Materials and Supplies, average cost		4,854			11,247
Prepaid Taxes		13,796			11,860
Derivatives - Energy Related Assets		797			380
Other Prepayments and Current Assets		2,248			2,416

Total Current Assets		133,183			186,391

Regulatory and Other Noncurrent Assets:
Regulatory Assets		240,462			270,434
Unamortized Debt Issuance Costs		5,829			6,147
Long-Term Receivables		7,693			7,081
Derivatives - Energy Related Assets		333			15
Other		2,324			2,392

Total Regulatory and Other Noncurrent Assets		256,641			286,069

Total Assets	$	1,357,062		$	1,354,015

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

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SOUTH JERSEY GAS COMPANY

BALANCE SHEETS
(In Thousands, except for share data)

	December 31,
	2009			2008

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		200,716			200,663
Accumulated Other Comprehensive Loss		(6,330	)		(6,875	)
Retained Earnings		231,296			202,103

Total Common Equity		431,530			401,739

Long-Term Debt		250,000			269,873

Total Capitalization		681,530			671,612

Current Liabilities:
Notes Payable		109,400			114,550
Current Portion of Long-Term Debt		35,000			25,000
Accounts Payable – Commodity		19,630			36,587
Accounts Payable – Other		21,947			12,051
Accounts Payable - Related Parties		12,120			16,744
Derivatives - Energy Related Liabilities		9,799			26,698
Deferred Income Taxes – Net		11,642			12,475
Customer Deposits and Credit Balances		13,542			14,219
Environmental Remediation Costs		22,499			13,117
Taxes Accrued		8,548			2,291
Pension Benefits		1,066			991
Interest Accrued		5,979			6,244
Other Current Liabilities		7,839			6,449

Total Current Liabilities		279,011			287,416

Regulatory and Other Noncurrent Liabilities:
Regulatory Liabilities		50,193			50,447
Deferred Income Taxes – Net		210,925			187,050
Environmental Remediation Costs		46,557			50,976
Asset Retirement Obligations		22,960			22,299
Pension and Other Postretirement Benefits		57,699			67,566
Investment Tax Credits		1,517			1,832
Derivatives - Energy Related Liabilities		504			2,667
Derivatives – Other		1,956			7,578
Other		4,210			4,572

Total Regulatory and Other Noncurrent Liabilities		396,521			394,987

Commitments and Contingencies (Note 11)

Total Capitalization and Liabilities	$	1,357,062		$	1,354,015

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, 2007	$	5,848	$	200,317		$	(4,429	)	$	158,246		$	359,982
Net Income										38,025			38,025
Other Comprehensive Income (Loss), Net of Tax: (a)
Postretirement Liability Adjustment							(307	)					(307	)
Unrealized Loss on Available-for-Sale Securities							(195	)					(195	)
Unrealized Loss on Derivatives							(425	)					(425	)
Other Comprehensive Loss, Net of Tax: (a)													(927	)
Comprehensive Income													37,098
Cash Dividends Declared - Common Stock										(18,732	)		(18,732	)

Balance at December 31, 2007		5,848		200,317			(5,356	)		177,539			378,348
Net Income										39,431			39,431
Other Comprehensive Income (Loss), Net of Tax (a)
Postretirement Liability Adjustment							(1,181	)					(1,181	)
Unrealized Loss on Available-for-Sale Securities							(731	)					(731	)
Unrealized Gain on Derivatives							393						393
Other Comprehensive Loss, Net of Tax (a)													(1,519	)
Comprehensive Income													37,912
Cash Dividends Declared - Common Stock										(14,867	)		(14,867	)
Excess Tax Benefit from Restricted Stock Plan				346									346

Balance at December 31, 2008		5,848		200,663			(6,875	)		202,103			401,739
Net Income										39,195			39,195
Other Comprehensive Income (Loss), Net of Tax: (a)
Postretirement Liability Adjustment							(15	)					(15	)
Unrealized Gain on Available-for-Sale Securities							533						533
Unrealized Gain on Derivatives							27						27
Other Comprehensive Gain, Net of Tax: (a)													545
Comprehensive Income													39,740
Cash Dividends Declared – Common Stock										(10,002	)		(10,002	)
Excess Tax Benefit from Restricted Stock Plan				53									53

Balance at December 31, 2009	$	5,848	$	200,716		$	(6,330	)	$	231,296		$	431,530


Disclosure of Changes in Accumulated Other Comprehensive Loss Balances (a)
(In Thousands)
			Postretirement Liability Adjustment			Unrealized Gain (Loss) on Available-for-Sale Securities			Unrealized (Loss) Gain on Derivatives			Accumulated Other Comprehensive Loss

Balance at January 1, 2007			$	(3,940	)	$	208		$	(697	)	$	(4,429	)
Changes During Year				(307	)		(195	)		(425	)		(927	)
Balance at December 31, 2007				(4,247	)		13			(1,122	)		(5,356	)
Changes During Year				(1,181	)		(731	)		393			(1,519	)
Balance at December 31, 2008				(5,428	)		(718	)		(729	)		(6,875	)
Changes During Year				(15	)		533			27			545
Balance at December 31, 2009			$	(5,443	)	$	(185	)	$	(702	)	$	(6,330	)

(a) Determined using a combined statutory tax rate of 41.08%.

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.

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.

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 2 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 3 for a detailed discussion of regulatory assets and liabilities.

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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 Based Taxes - We collect certain revenue-based energy taxes from our customers. Such taxes include New Jersey State Sales Tax, Transitional Energy Facility Assessment (TEFA) 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. TEFA and PUA are included in both revenues and cost of sales and totaled $8.8 million, $8.7 million and $8.8 million in 2009, 2008 and 2007, respectively.

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 collectability of specific accounts.

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

Property, Plant & Equipment - For regulatory purposes, utility plant is stated at original cost, which may be different than our cost if the assets were acquired from another regulated entity. The cost of adding, replacing and renewing property is charged to the appropriate plant account. Utility Plant balances as of December 31, 2009 and 2008 were comprised of the following (in thousands):

	2009		2008
Utility Plant:
Production Plant	$	302	$	302
Storage Plant		12,193		11,543
Transmission Plant		153,393		151,546
Distribution Plant		1,021,233		959,807
General Plant		45,008		41,122
Other Plant		3,665		3,665
Utility Plant in Service		1,235,794		1,167,985
Construction Work in Progress		39,998		4,029

Total Utility Plant	$	1,275,792	$	1,172,014

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The significant increase in Construction Work in Progress is related to a major transmission project under construction as of December 31, 2009. This project is part of the Company’s Capital Investment Recovery Tracker (CIRT) program, as discussed under Note 2.

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 2009 and 2008 was as follows (in thousands):

	2009			2008
AROs as of January 1,	$	22,299		$	24,364
Accretion		492			427
Additions		193			136
Settlements		(24	)		(37	)
Revisions in Estimated Cash Flows *		-			(2,591	)
AROs as of December 31,	$	22,960		$	22,299

* A corresponding reduction was made to Regulatory Assets, thus having no impact on Earnings.

Depreciation - We depreciate utility plant on a straight-line basis over the estimated remaining lives of the various property classes. These estimates are periodically reviewed and adjusted as required after BPU approval. The composite annual rate for all depreciable utility property was approximately 2.3% in 2009, 2008 and 2007. The actual composite rate may differ from the approved rate as the asset mix changes over time. Except for retirements outside of the normal course of business, accumulated depreciation is charged with the cost of depreciable utility property retired, less salvage.

Capitalized Interest - We capitalize interest on construction at the rate of return on rate base utilized by the BPU to set rates in our last base rate proceeding (See Note 2). Capitalized interest is included in Utility Plant on the balance sheets. Interest Charges are presented net of capitalized interest on the statements of income. The amount of interest capitalized by SJG for the years ended December 31, 2009, 2008 and 2007 was not significant.

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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 2009, 2008 and 2007, no significant impairments were identified.

Derivative Instruments - We are involved in buying, selling, transporting and storing natural gas and are subject to market risk due to commodity price fluctuations. Our affiliate, South Jersey Resources Group (SJRG), manages this risk for us by entering into a variety of physical and financial transactions including forward contracts, swap agreements, options contracts and futures contracts on our behalf. Management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in identifying, assessing and controlling various risks. Management reviews any open positions in accordance with strict policies to limit exposure to market risk.

We account for derivative instruments in accordance with FASB ASC Topic 815 – “Derivatives and Hedging.” We record all derivatives, whether designated in hedging relationships or not, on the balance sheets at fair value unless the derivative contracts qualify for the normal purchase and sale exemption. In general, if the derivative is designated as a fair value hedge, we recognize the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk in earnings. We currently have no fair value hedges. If the derivative is designated as a cash flow hedge, we record the effective portion of the hedge in Accumulated Other Comprehensive Loss and recognize it in the income statement when the hedged item affects earnings. We recognize ineffective portions of cash flow hedges immediately in earnings. In 2007, we changed our policy to no longer designate energy-related derivative instruments as cash flow hedges. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction.

Initially and on an ongoing basis, we assess whether our derivatives are highly effective in offsetting changes in cash flows or fair values of the hedged items. We discontinue hedge accounting prospectively if we decide to discontinue the hedging relationship; determine that the anticipated transaction is no longer likely to occur; or determine that a derivative is no longer highly effective as a hedge. In the event that hedge accounting is discontinued, we will continue to carry the derivative on our balance sheet at its current fair value and recognize subsequent changes in fair value in current period earnings. Unrealized gains and losses on the discontinued hedges that were previously included in Accumulated Other Comprehensive Loss are reclassified into earnings when the forecasted transaction occurs, or when it is probable that it will not occur.

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Due to the application of regulatory accounting principles under FASB ASC Topic 980, the costs or benefits of derivative contracts related to gas purchases are recovered through our Basic Gas Supply Service (BGSS) Clause, subject to BPU approval (See Note 2). As of December 31, 2009 and 2008, we had $9.2 million and $29.0 million of costs, respectively, included in our BGSS related to open financial contracts (See Note 3).

The Company has entered into interest rate derivatives and similar agreements to hedge exposure to increasing interest rates, and the impact of those rates on cash flows of variable-rate debt. These interest rate derivatives are included in Derivatives-Other on the balance sheets.

We previously used derivative transactions known as “Treasury Locks” to hedge against the impact on our cash flows of possible interest rate increases on debt issued in September 2005. The initial $1.4 million cost of the Treasury Locks has been included in Accumulated Other Comprehensive Loss and is being amortized over the 30 year life of the associated debt issue. As of December 31, 2009, the unamortized balance is approximately $1.2 million.

We currently have two long-term interest rate swaps under which we pay a fixed interest rate at 3.43% through January 2036 on $25.0 million of variable-rate, tax-exempt debt which was issued in April 2006. The differential to be paid or received as a result of these swap agreements is accrued as interest rates change and is recognized as an adjustment to interest expense.

As of December 31, 2009 and 2008, the fair value of these interest rate derivative agreements was $2.0 million and $7.6 million, respectively, and is included on the balance sheet under the caption Regulatory and Other Noncurrent Liabilities: Derivatives - Other. The fair value represents the amount we would have expected to pay to the counterparties if the contracts had been terminated on those dates. Management believes that, subject to BPU approval, the market value upon termination can be recovered in rates, and therefore, the unrealized loss has been included in Other Regulatory Assets in the balance sheets.

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As of December 31, 2009, SJG’s active interest rate swaps were as follows:

Notional Amount

Fixed

Interest Rate

Start Date

Maturity

Type of Debt

Obligor

12,500,000

3.430

12/01/2006

02/01/2036

Tax-exempt

SJG

12,500,000

3.430

12/01/2006

02/01/2036

Tax-exempt

SJG

The fair values of all derivative instruments, as reflected in the balance sheets as of December 31, 2009 and 2008, are as follows (in thousands):

Derivatives not designated as hedging instruments under GAAP	2009				2008
	Assets		Liabilities		Assets		Liabilities


Energy related commodity contracts:
Derivatives – Energy Related – Current	$	797	$	9,799	$	380	$	26,698
Derivatives – Energy Related – Non-Current		333		504		15		2,667
Interest rate contracts:
Derivatives - Other		-		1,956		-		7,578
Total derivatives not designated as hedging instruments under GAAP		1,130		12,259		395		36,943

The effect of derivative instruments on the statements of income for 2009, 2008 and 2007 are as follows (in thousands):

	Year ended December 31,
Derivatives in Cash Flow Hedging Relationships	2009			2008			2007

Interest Rate Contracts:
Gains recognized in OCI on effective portion	$	-		$	621		$	(768	)
Losses reclassified from accumulated OCI into income (a)	$	(46	)	$	(46	)	$	(46	)

(a) Included in Interest Charges

Stock-Based Compensation Plans Officers and other key employees of SJG participate in the Stock Option, Stock Appreciation Rights and Restricted Stock Award Plan (“Plan”) of SJI. As the vesting requirements under the plan 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 for share-based awards on a straight-line basis over the requisite service 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 Officers’ restricted stock awards on the date of grant is estimated using a Monte Carlo simulation model.

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We are allocated a portion of SJI's compensation cost during the vesting period. We accrue a liability and record compensation cost on a straight-line basis over the requisite three-year service period based on the grant date fair value. 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, 2009, and the assumptions used to estimate the fair value of the awards:

Grant	Shares		Fair Value		Expected			Risk-Free
Date	Outstanding		Per Share		Volatility			Interest Rate

Jan. 2008		9,238	$	34.030		21.7	%		2.9	%
Jan. 2009		8,318	$	39.350		28.6	%		1.2	%

Expected volatility is based on the actual daily volatility of SJI’s share price over the preceding 3-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 3-year term of the restricted shares. As notional dividend equivalents are credited to the holders, which are reinvested during the 3-year service period, no reduction to the fair value of the award is required.

For the years ended December 31, 2009, 2008 and 2007, the cost of restricted stock awards was $0.3 million, $0.3 million and $0.2 million, respectively. Of these costs, $0.2, $0.1 and $0.1 million was capitalized to Utility Plant in each of those years, respectively.

As of December 31, 2009, there was $0.3 million of total unrecognized compensation cost related to nonvested share-based compensation awards granted under the restricted stock plans. That cost is expected to be recognized over a weighted average period of 1.7 years.

The following table summarizes information regarding restricted stock award activity during 2009, excluding accrued dividend equivalents:

				Weighted Average
				Grant Date
	Shares			Fair Value
Nonvested Shares Outstanding, January 1, 2009		18,283		$	31.645
Granted		8,318		$	39.350
Vested*		(9,045	)	$	29.210
Nonvested Shares Outstanding, December 31, 2009		17,556		$	36.551

* Actual shares expected to be awarded to SJG officers and other key employees during the first quarter of 2010, including dividend equivalents and adjustments for performance measures, total 14,400 shares.

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During 2009, SJI awarded 13,640 shares that had vested at December 31, 2008, to SJG officers and other key employees at a market value of $0.5 million. During 2008, 12,299 shares were awarded to SJG officers and other key employees at a market value of $0.4 million. As discussed earlier, we have a policy of making cash payments to SJI to satisfy our allocated obligations under this plan. Cash payments to SJI during 2009 and 2008, were approximately $0.2 million and $0.6 million, respectively, relating to stock awards. Additionally, a change in control could result in the nonvested shares becoming nonforfeitable or immediately payable in cash.

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 Note5). 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 2009 had, or is expected to have, a material impact on the financial statements.

In September 2006, the FASB issued new accounting guidance which defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America, and expands disclosures about fair value measurements. In October 2008, the FASB issued additional guidance to provide clarification in a market that is not active and to provide an example to illustrate key considerations in determining the fair value of a financial asset in such a non-active market. This guidance was effective in fiscal years beginning after November 15, 2007. However, for nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis, this guidance was effective in fiscal years beginning after November 15, 2008. The adoption of this guidance did not have a material effect on the Company’s financial statements.

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In March 2008, the FASB issued new accounting guidance on disclosures about derivative instruments and hedging activities. This guidance requires disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This guidance was effective for fiscal years beginning after November 15, 2008. The adoption of this guidance did not have a material effect on the Company’s financial statements. See disclosures above.

In December 2008, the FASB issued new accounting guidance on employers’ disclosures about postretirement benefit plan assets. This guidance requires more detailed disclosures about employers’ plan assets, including employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets, and valuation techniques used to measure the fair value of plan assets. This guidance is effective for reporting periods ending after December 15, 2009. The adoption of this guidance did not have a material effect on the Company’s financial statements. See disclosures in Note 10.

In June 2009, the FASB issued new accounting guidance on The FASB Accounting Standards Codification™ (the “Codification”) which has become the single official source of authoritative, nongovernmental GAAP. The current GAAP hierarchy consists of four levels of authoritative accounting and reporting guidance. The Codification eliminates this hierarchy and replaces current GAAP (other than rules and interpretive releases of the SEC) as used by all nongovernmental entities, with just two levels of literature: authoritative and nonauthoritative. The Codification was effective for interim and annual periods ending after September 15, 2009. Calendar year-end companies were required to initially apply the Codification to their third-quarter interim financial statements. The application of the Codification did not have a material effect on the Company’s financial statements.

In August 2009 the FASB issued new accounting guidance for measuring the fair value of a liability in circumstances in which a quoted price in an active market for the identical liability is not available. In such instances, a reporting entity is required to measure fair value utilizing a valuation technique that uses (i) the quoted price of the identical liability when traded as an asset, (ii) quoted prices for similar liabilities or similar liabilities when traded as assets, or (iii) another valuation technique that is consistent with existing principles, such as an income approach or market approach. The new accounting guidance also clarifies that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. This guidance was effective for the period ending December 31, 2009 and did not have a material effect on the Company’s financial statements.

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2. RATES AND REGULATORY ACTIONS:

Base Rates - In July 2004 the BPU approved our current rate structure based on a 7.97% rate of return on rate base that included a 10.0% return on common equity. We were also permitted to recover regulatory assets contained in our petition and to reduce our composite depreciation rate from 2.9% to 2.4%. Included in the base rate increase was also a change to the sharing of pre-tax margins on interruptible, off system sales and transportation. The sharing of pre-tax margins begins from dollar one, with our retaining 20% through June 30, 2006. Effective July 1, 2006, the 20% retained by us decreased to 15% of such margins.

In January 2010, we filed a base rate case with the BPU to increase our base rates to obtain a certain level of return on our investment of capital. We expect the rate case to be concluded during 2010. We have not sought a base rate increase from the BPU since the implementation of our base rate case approved in July 2004.

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

Basic Gas Supply Service (BGSS) Clause - The BGSS price structure was approved by the BPU in January 2003, and allows us to recover all prudently incurred gas costs. BGSS charges to customers can be either monthly or periodic (annual). Monthly BGSS charges are applicable to large use customers and are referred to as monthly because the rate changes on a monthly basis pursuant to a BPU-approved formula based on commodity market prices. Periodic BGSS charges are applicable to lower usage customers, which include all of our residential customers, and are evaluated at least annually by the BPU. However, to some extent, more frequent rate changes to the periodic BGSS are allowed. We collect gas costs from customers on a forecasted basis and defer periodic over/under recoveries to the following BGSS year, which runs from October 1 through September 30. If we are in a net cumulative undercollected position, gas costs deferrals are reflected on the balance sheet as a regulatory asset. If we are in a net cumulative overcollected position, amounts due back to customers are reflected on the balance sheet as a regulatory liability. We pay interest on net overcollected BGSS balances at the rate of return on rate base of 7.97% 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:

June 2007 – We made our annual periodic BGSS filing with the BPU requesting a $16.9 million, or 5.0%, decrease in gas cost recoveries in response to decreasing wholesale gas costs and a $5.4 million benefit derived from the Company electing not to extend the terms of two firm transportation contracts beyond their primary terms.

October 2007 – The BPU approved on a provisional basis, a $36.7 million, or 11%, annual decrease in gas cost recoveries due to the continuing decrease in wholesale gas costs subsequent to our June 2007 filing.

May 2008 - We made our annual periodic BGSS filing with the BPU requesting a $73.7 million, or 23%, increase in gas cost recoveries in response to increasing wholesale gas costs.

November 2008 – The BPU approved, on a provisional basis, a $38.0 million, or 12% increase in gas cost recoveries reflecting a lower increase in gas costs than originally projected in our May 2008 filing.

December 2008 - As part of a global settlement, the BPU approved on a provisional basis, a decrease in gas cost recoveries of $9.0 million, or 3%, due to the continued decline in projections in the wholesale gas market.

June 2009 - We made our annual BGSS filing to the BPU requesting a $54.7 million reduction, or 17.5% decrease, in gas cost recoveries in response to projected decreases in wholesale gas.

August 2009 - The BPU issued an Order finalizing the 2008-2009 provisional BGSS rates.

September 2009 - The BPU approved, on a provisional basis, a $54.7 million, or 17.5%, decrease 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 our profit margin on the number of customers rather than the amount of natural gas distributed to customers. In October 2006, the BPU approved the CIP as a three-year pilot program. In January 2010, the BPU approved an extension of this program through September 2013. Each CIP year begins October 1 and ends September 30 of the subsequent year. On a monthly basis during the CIP year, we record adjustments to earnings based on weather and customer usage factors, as incurred. Subsequent to each year, we will 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.

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Regulatory actions regarding the CIP were as follows:

June 2007 – We made our first annual CIP filing, requesting recovery of $14.3 million in deficiency, of which $9.6 million was non-weather related.

October 2007 – The BPU approved on a provisional basis, recovery of $15.5 million in deficiency, of which $9.1 million was non-weather related.

May 2008 - We made our annual CIP filing, requesting recovery of $19.1 million, of which $14.1 million was non-weather related.

December 2008 - As part of a global settlement, the BPU approved, on a provisional basis, the recovery of CIP revenue of $20.4 million, of which $16.4 million was non-weather related.

June 2009 - We made our annual CIP filing to the BPU requesting recovery of $13.4 million which included a $13.7 million non-weather related recovery, partially offset by a credit of $0.3 million which was weather related.

August 2009 - The BPU issued an Order finalizing the 2008-2009 provisional CIP rates.

September 2009 - The BPU approved, on a provisional basis, the recovery of CIP revenue of $13.4 million.

Capital Investment Recovery Tracker (CIRT) - In January 2009, we made a filing with the BPU requesting approval for an accelerated infrastructure investment program. The purpose of the CIRT was to accelerate $103.0 million of capital expenditures from five years to two years. The petition requested that the Company be allowed to earn a return of, and a return on, our investment. Under the CIRT, 2009 spending was projected to be $70.5 million and 2010 spending was projected to be $32.5 million. On a monthly basis during the CIRT year, we record adjustments to earnings based on actual CIRT program expenditures, as incurred. Annually we make a filing to the BPU for review and approval of expenditures recorded under the CIRT.

January 2009 - We filed a petition with the BPU for approval of an accelerated infrastructure investment program and associated rate tracker as discussed above.

April 2009 – The BPU approved our petition for the CIRT, including a first year estimated capital expenditure level of $70.5 million, and estimated revenue of $3.2 million.

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November 2009 - We made our annual CIRT filing, requesting $10.6 million in additional revenue.

December 2009 – The BPU approved, on a provisional basis, recovery of an additional $9.9 million in CIRT revenue.

Energy Efficiency Tracker (EET) - In January 2009 we filed a petition with the BPU requesting approval of an energy efficiency program for residential, commercial and industrial customers. Under this program we will invest $17.0 million over two years in energy efficiency measures to be installed in customer homes and businesses. We can recover incremental operating and maintenance expenses and earn a return of, and return on, program investments. 2009 revenue was projected to be $1.7 million.

January 2009 - Filed a petition with the BPU for approval of an energy efficiency program as noted above.

July 2009 - The BPU approved our petition for the EET with a revenue recovery of $1.3 million.

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

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

December 2007 – We made our annual SBC filing, superseding our 2005 and 2006 SBC filings, requesting a $7.4 million increase in annual SBC recoveries.

December 2008 – As part of the global settlement, the BPU approved an increase in the RAC portion of the SBC, resulting in an increase in revenue of $8.5 million. In addition, the BPU approved a reduction in the interest rate utilized to calculate deferred tax on the RAC.

January 2009 - We made our annual 2008-2009 SBC filing requesting $7.9 million increase in SBC recoveries, which includes a net increase in Remediation Adjustment Clause, Clean Energy Program Clause and Transportation Initiation Clause.

August 2009 - We made our annual 2009-2010 SBC filing, requesting a $15.5 million increase in SBC recoveries, which includes a net increase in Remediation Adjustment Clause, Clean Energy Program Clause and Transportation Initiation Clause.

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Remediation Adjustment Clause (RAC) - The RAC recovers environmental remediation costs of 12 former gas manufacturing plants (See Note 11). The BPU allows us to recover such costs over 7-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 7-year amortization periods. As of December 31, 2009 and 2008, we reflected the unamortized remediation costs of $42.9 million and $48.1 million, respectively, on the balance sheet under Regulatory Assets (See Note 3). Since implementing the RAC in 1992, we have recovered $44.1 million through rates.

New Jersey Clean Energy Program (NJCEP) - This mechanism recovers costs associated with our energy efficiency and renewable energy programs. In August 2008, the BPU approved the statewide funding of the NJCEP of $1.2 billion for the years 2009 through 2012. Of this amount, we will be responsible for approximately $41.5 million over the 4-year period. NJCEP adjustments affect revenue and cash flows but do not directly affect earnings as related costs are deferred and recovered through rates on an on-going basis.

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

Separate regulatory actions regarding the USF were as follows:

July 2007 – We made our annual USF filing, along with the state’s other electric and gas utilities, proposing to decrease annual statewide gas revenues to $78.1 million. This rate proposal was approved by the BPU in October 2007, on an interim basis, and were designed to decrease our annual USF revenues by $3.4 million. The revised rates were effective from October 5, 2007 through September 30, 2008.

June 2008 – We made our annual USF filing, along with the state’s other electric and gas utilities, proposing to increase annual statewide gas revenues to $97.3 million. This proposal was designed to increase our annual USF revenues by $ 2.6 million.

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October 2008 – The BPU approved the statewide budget of $96.7 million for all of the State’s gas utilities. Our portion of this total is approximately $8.8 million and increased rates were implemented effective October 27, 2008 resulting in a $2.5 million increase to our annual USF recoveries.

June 2009 - We made our annual USF filing, along with the state’s other electric and gas utilities, proposing to decrease annual statewide gas revenues by $39.1 million. This proposal was designed to decrease our annual USF revenue by $4.9 million.

October 2009 – The BPU approved the statewide budget of $60.1 million for all of the State’s gas utilities. Our portion of this total is approximately $5.1 million and decreased rates were implemented effective October 12, 2009 resulting in a $4.1 million decrease to our annual USF recoveries.

Other Regulatory Matters -

Unbundling - Effective January 10, 2000, the BPU approved full unbundling of our system. This allows all natural gas consumers to select their natural gas commodity supplier. As of December 31, 2009, 24,807 of our residential customers were purchasing their gas commodity from someone other than us. Customers choosing to purchase natural gas from providers other than the utility are charged for the cost of gas by the marketer. The resulting decrease in our revenues is offset by a corresponding decrease in gas costs. While customer choice can reduce utility revenues, it does not negatively affect our net income or financial condition. The BPU continues to allow for full recovery of prudently incurred natural gas costs through the BGSS. Unbundling did not change the fact that we still recover cost of service, including certain deferred costs, through base rates.

Pipeline Integrity - In October 2005, we filed a petition with the BPU to implement a Pipeline Integrity Management Tracker (Tracker). The purpose of the Tracker is to recover incremental costs to be incurred by us as a result of new federal regulations, which are aimed at enhancing public safety and reliability. The regulations require that utilities use a comprehensive analysis to assess, evaluate, repair and validate the integrity of certain transmission lines in the event of a leak or failure. As of December 31, 2009 and 2008, costs incurred under this program totaled $1.2 million and $1.1 million, respectively, and are included in Other Regulatory Assets (See Note 3). We continue to engage in settlement negotiations in which we are proposing to modify the original request and provide for deferred accounting treatment of Pipeline Integrity related operating expenses. We have proposed recovery of these deferred costs in our base rate case filed in January 2010.

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

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3. REGULATORY ASSETS AND LIABILITIES:

The discussion under Note 2, Rates and Regulatory Actions, is integral to the following explanations of specific regulatory assets and liabilities.

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

	2009		2008
Environmental Remediation Costs:
Expended – Net	$	42,924	$	48,143
Liability for Future Expenditures		69,056		64,093
Income Taxes - Flowthrough Depreciation		1,752		2,729
Deferred Asset Retirement Obligation Costs		22,438		21,901
Deferred Gas Costs – Net		6,519		18,406
Deferred Pension and Other Postretirement Benefit Costs		71,192		80,162
Conservation Incentive Program Receivable		16,672		22,048
Societal Benefit Costs Receivable		1,872		1,753
Premium for Early Retirement of Debt		1,046		1,208
Other Regulatory Assets		6,991		9,991
Total Regulatory Assets	$	240,462	$	270,434

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 and Societal Benefit Costs Receivable 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.

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Income Taxes - Flowthrough Depreciation - This regulatory asset represents unamortized excess tax depreciation over book depreciation on utility plant because of temporary differences for which, prior to 1993, deferred taxes previously were not provided. We previously passed these tax benefits through to ratepayers and are recovering the amortization of the regulatory asset through rates until 2011.

Deferred Asset Retirement Obligation Costs - This regulatory asset resulted from the recording of asset retirement obligations (ARO’s) 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’s 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 Gas Costs - Net - Over/under collections of gas costs are monitored through our BGSS mechanism. Net undercollected gas costs are classified as a regulatory asset and net overcollected gas costs are classified as a regulatory liability. Derivative contracts used to hedge our natural gas purchases are also included in the BGSS, subject to BPU approval. See detailed discussion under Derivative Instruments in Note 1.

Deferred Pension and Other Postretirement Benefit Costs - The BPU authorized us to recover costs related to postretirement benefits under the accrual method of accounting consistent with GAAP. We deferred amounts accrued prior to that authorization and are amortizing them as allowed by the BPU over 15 years through 2012. The unamortized balance was $1.1 million at December 31, 2009. 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 10).

Conservation Incentive Program Receivable - The impact of the CIP is recorded as an adjustment to earnings as incurred. The first year of cash recovery under the CIP began October 2007.

Societal Benefit Costs Receivable - At both December 31, 2009 and 2008, this regulatory asset primarily represents cumulative costs less recoveries under the USF program.

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Premium for Early Retirement of Debt - This regulatory asset represents unamortized debt issuance costs related to long-term debt refinancings and a call premium associated with the retirement of debt, all occurring in 2005 and 2004. Unamortized debt issuance costs are being amortized over the term of the new debt issue pursuant to regulatory approval by the BPU. The call premium is expected to be approved for recovery through future rate proceedings.

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):

	2009		2008
Excess Plant Removal Costs	$	48,715	$	48,820
Other		1,478		1,627
Total Regulatory Liabilities	$	50,193	$	50,447

Excess Plant Removal Costs – Represents amounts accrued in excess of actual utility plant removal costs incurred to date, which we have an obligation to either expend or return to ratepayers in future periods.

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

4. RELATED PARTY TRANSACTIONS:

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

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

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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 SJI 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 previously sold natural gas for resale to SJE and also provide them 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 SJI 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 and southern regions. 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 SJI 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 SJI and an appliance service and installation of heating and cooling systems company. We lease vehicles and provide billing services to SJESP.

Millennium Account Services, LLC (Millennium) - a partnership between SJI and Conectiv Solutions, LLC, 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).

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In addition to the above, we provide various administrative and professional services to SJI and each of the affiliates discussed above. Likewise, SJI and SJIS provide substantial administrative services on our behalf. For certain types of transactions, we served as central processing agents for the related parties discussed above. Amounts due to and due from these related parties for pass-through items are not considered material to the financial statements as a whole.

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

	2009		2008		2007

Operating Revenues/Affiliates:
SJRG	$	3,782	$	7,604	$	19,328
Other		456		402		386
Total Operating Revenues/Affiliates	$	4,238	$	8,006	$	19,714

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

	2009			2008			2007

Costs of Sales/Affiliates
(Excluding depreciation):
SJRG	$	38,643		$	28,565		$	24,601

Derivative Gains (Losses) (See Note 1):
SJRG	$	51,856		$	(6,215	)	$	19,169

Operations Expense/Affiliates
SJI	$	8,042		$	6,957		$	6,650
SJIS		4,768			4,154			4,550
Millennium		2,904			2,982			2,872
Other		(288	)		(226	)		139
Total Operations Expense/Affiliates	$	15,426		$	13,867		$	14,211

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5. 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):

	2009			2008			2007

Tax at Statutory Rate	$	23,205		$	23,078		$	22,637
Increase (Decrease) Resulting from:
State Income Taxes		4,471			4,491			4,396
Amortization of Investment Tax Credits		(314	)		(318	)		(320	)
ESOP Dividend		(730	)		(736	)		(610	)
Amortization of Flowthrough Depreciation		664			664			664
Other - Net		(192	)		(671	)		(115	)
Net Income Taxes	$	27,104		$	26,508		$	26,652

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

	2009			2008			2007
Current:
Federal	$	3,158		$	1,042		$	9,951
State		1,842			4,088			3,744
Total Current		5,000			5,130			13,695
Deferred:
Federal		17,381			18,877			10,258
State		5,037			2,819			3,019
Total Deferred		22,418			21,696			13,277
Investment Tax Credits		(314	)		(318	)		(320	)
Net Income Taxes	$	27,104		$	26,508		$	26,652

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

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

	2009			2008

Current:
Deferred Fuel Costs - Net	$	4,121		$	4,121
Uncollectibles		(1,322	)		(1,208	)
Deferred Revenues		7,396			9,055
Section 461 Prepayments		709			514
Other		738			(7	)
Current Deferred Tax Liability - Net	$	11,642		$	12,475

Noncurrent:
Book Versus Tax Basis of Property	$	201,546		$	174,208
Deferred Fuel Costs - Net		7,568			5,470
Environmental		17,247			20,608
Deferred Regulatory Costs		1,259			1,246
Deferred State Tax		(9,075	)		(7,366	)
Investment Tax Credit Basis Gross-Up		(782	)		(944	)
Deferred Pension & Other Post Retirement Benefits		28,783			32,311
Pension & Other Post Retirement Benefits		(20,882	)		(27,063	)
Deferred Revenues		(14,455	)		(11,226	)
Other		(284	)		(194	)
Noncurrent Deferred Tax Liability – Net	$	210,925		$	187,050

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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. As of December 31, 2009 and 2008, income taxes due to and (from) SJI were approximately $6.0 million and $(5.8) million, respectively, and are included in the balance sheets under the caption, Prepaid Taxes.

On January 1, 2007 SJG adopted new provisions of FASB ASC Topic 740 – “Income Taxes.” As a result, SJG recognized a $0.4 million reduction to beginning retained earnings as a cumulative effect adjustment and a noncurrent deferred tax asset of $1.1 million. A reconciliation of unrecognized tax benefits is as follows (in thousands):

	2009			2008			2007

Balance at January 1,	$	910		$	907		$	1,112
Increase as a result of tax position taken in prior years		42			253			28
Decrease due to a lapse in the statue of limitations		(376	)		(250	)		(233	)
Balance at December 31,	$	576		$	910		$	907

The total unrecognized tax benefits as of December 31, 2009 were $0.6 million, not including $0.5 million of accrued interest and penalties. The total unrecognized tax benefits as of December 31, 2008 were $0.9 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 2009, 2008 or 2007. There have been no material changes to the unrecognized tax benefits during 2009, 2008 or 2007 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 and the timing of certain deductions taken on our income tax returns. Federal income tax returns from 2006 forward and state income tax returns primarily from 2005 forward are open and subject to examination.

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6. LONG-TERM DEBT: (A)

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

				2009			2008

First Mortgage Bonds: (B)
	6.12	%	Series due 2010	$	10,000		$	10,000
	6.74	%	Series due 2011		10,000			10,000
	6.57	%	Series due 2011		15,000			15,000
	4.46	%	Series due 2013		10,500			10,500
	5.027	%	Series due 2013		14,500			14,500
	4.52	%	Series due 2014		11,000			11,000
	5.115	%	Series due 2014		10,000			10,000
	5.387	%	Series due 2015		10,000			10,000
	6.50	%	Series due 2016 (C)		-			9,873
	4.60	%	Series due 2016		17,000			17,000
	5.437	%	Series due 2016		10,000			10,000
	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
	7.7	%	Series due 2027		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 (D)					25,000			25,000

Total Long-Term Debt Outstanding					285,000			294,873
Current Portion of Long-Term Debt (D)					(35,000	)		(25,000	)
Long-Term Debt				$	250,000		$	269,873

(A)	Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2010, $10,000; 2011, $25,000; 2012, $2,187; 2013, $27,187; 2014, $23,188 (See Note (D) below). Our long-term debt agreements contain no financial covenants.

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

(C)	On November 19, 2009, SJG retired its 6.5% Medium Term Notes, at par.

(D)

On April 20, 2006, SJG issued $25.0 million of tax-exempt, auction-rate debt through the New Jersey Economic Development Authority (NJEDA) under its $150.0 million MTN Program. These bonds were repurchased by the Company in June 2008 and remarketed to the public in August 2008 as variable-rate demand bonds with liquidity support provided by a letter of credit from a commercial bank. The current letter of credit expires in August 2010, and as such, these bonds have been included in the current portion of long-term debt. Material terms of the original bonds, such as the 2036 maturity date, floating rate interest that resets weekly, and a first mortgage collateral position, remain unchanged.

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We estimated the fair values of our long-term debt, including current maturities, as of December 31, 2009 and 2008, to be $331.5 million and $381.4 million, respectively. Carrying amounts as of both December 31, 2009 and 2008 are $285.0 million and $294.9 million, respectively. We base the estimates on interest rates available to us at the end of each year for debt with similar terms and maturities. We retire debt when it is cost effective as permitted by the debt agreements.

7. 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, 2009 and 2008, the escrowed proceeds, including interest earned, totaled $0.1 million.

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 $10.8 million and $10.1 million as of December 31, 2009 and 2008, respectively. The current portion of these receivables is reflected in Accounts Receivable and the non-current portion is reflected in Long-Term Receivables on the balance sheet. The carrying amounts noted above are net of unamortized discounts resulting from imputed interest in the amount of $1.2 million as of both December 31, 2009 and 2008. 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, 2009 and 2008.

Other Financial Instruments - The carrying amounts of our other financial instruments approximate their fair values at December 31, 2009 and 2008.

8. UNUSED LINES OF CREDIT:

Credit facilities and available liquidity as of December 31, 2009 were as follows (in thousands):

	Total Facility		Usage		Available Liquidity		Expiration Date

Revolving Credit Facility	$	100,000	$	85,000	$	15,000	August 2011
Line of Credit		40,000		10,000		30,000	December 2010 (A)
Uncommitted Bank Lines		55,000		14,400		40,600	Various

Total	$	195,000	$	109,400	$	85,600

All committed facilities contain one financial covenant regarding the ratio of total debt to total capitalization, measured on a quarterly basis. SJG was in compliance with these covenants as of December 31, 2009. Borrowings under these credit facilities are at market rates. The weighted average borrowing cost, which changes daily, was 0.80%, 1.06%, and 5.30% at December 31, 2009, 2008, and 2007, respectively.

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9. RETAINED EARNINGS:

Various loan agreements also contain potential restrictions regarding the amount of cash dividends or other distributions that we may pay on our common stock. As of December 31, 2009, these loan restrictions did not affect the amount that may be distributed from our retained earnings.

We received no equity infusions from SJI in 2009, 2008 or 2007. Future equity contributions will occur on an as needed basis.

10. 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.

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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
	2009			2008			2007			2009			2008			2007

Service Cost	$	2,412		$	2,408		$	2,442		$	622		$	605		$	661
Interest Cost		7,125			6,843			6,376			2,712			2,497			2,295
Expected Return on Plan Assets		(6,035	)		(8,394	)		(8,068	)		(1,405	)		(1,995	)		(1,895	)
Amortization:
Prior Service Cost (Credits)		227			239			239			(254	)		(254	)		(254	)
Actuarial Loss		4,421			1,365			1,624			1,746			677			560
Net Periodic Benefit Cost		8,150			2,461			2,613			3,421			1,530			1,367
Capitalized Benefit Costs		(3,798	)		(1,073	)		(1,131	)		(1,676	)		(765	)		(648	)
Affiliate SERP Allocations		(399	)		(315	)		(232	)		-			-			-
Total Net Periodic Benefit Expense	$	3,953		$	1,073		$	1,250		$	1,745		$	765		$	719

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 3).

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):

							Accumulated Other
	Regulatory Assets						Comprehensive Loss (pre-tax)
				Other						Other
	Pension			Postretirement			Pension			Postretirement
	Benefits			Benefits			Benefits			Benefits
Balance at January 1, 2008	$	20,533		$	10,263		$	7,208		$	-

Amounts Arising during the Period:
Net Actuarial Loss		36,171			13,036			2,678			-

Amounts Amortized to Net Periodic Costs:
Net Actuarial Loss		(691	)		(677	)		(674	)		-
Prior Service (Cost) Credit		(239	)		254			-			-

Balance at December 31, 2008	$	55,774		$	22,876		$	9,212		$	-

Amounts Arising during the Period:
Net Actuarial (Gain) Loss		(4,188	)		610			804			-
Prior Service Cost		347			-			-			-
Amounts Amortized to Net Periodic Costs:
Net Actuarial Loss		(3,642	)		(1,746	)		(779	)		-
Prior Service (Cost) Credit		(227	)		254			-			-

Balance at December 31, 2009	$	48,064		$	21,994		$	9,237		$	-

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The estimated costs that will be amortized from Regulatory Assets into net periodic benefit costs in 2010 are as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits
Prior Service Costs (Credits)	$	237	$	(254	)
Net Actuarial Loss	$	3,137	$	1,409

The estimated costs that will be amortized from Accumulated Other Comprehensive Loss into net periodic benefit costs in 2010 are as follows (in thousands):

		Pension Benefits				Other Postretirement Benefits
Net Actuarial Loss		$	891			$	-

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
	2009			2008			2009			2008

Change in Benefit Obligations:
Benefit Obligation at Beginning of Year	$	117,321		$	109,301		$	42,488		$	39,499
Service Cost		2,412			2,408			622			605
Interest Cost		7,125			6,843			2,712			2,497
Actuarial Loss		2,213			5,071			3,889			2,947
Retiree Contributions		-			-			192			164
Plan Amendments		347			-			-			-
Benefits Paid		(6,876	)		(6,302	)		(3,149	)		(3,224	)
Benefit Obligation at End of Year	$	122,542		$	117,321		$	46,754		$	42,488

Change in Plan Assets:
Fair Value of Plan Assets at Beginning of Year	$	70,588		$	96,541		$	20,665		$	28,284
Actual Return on Plan Assets		11,631			(25,384	)		4,684			(8,094	)
Employer Contributions		9,338			5,733			3,458			3,535
Retiree Contributions		-			-			192			164
Benefits Paid		(6,876	)		(6,302	)		(3,149	)		(3,224	)
Fair Value of Plan Assets at End of Year	$	84,681		$	70,588		$	25,850		$	20,665

Funded Status at End of Year:
Accrued Net Benefit Cost at End of Year	$	(37,861	)	$	(46,733	)	$	(20,904	)	$	(21,823	)

Amounts Recognized in the Statement of Financial Position Consist of:
Current Liabilities	$	(1,066	)	$	(991	)	$	-		$	-
Noncurrent Liabilities		(36,795	)		(45,742	)		(20,904	)		(21,823	)
Net Amount Recognized at End of Year	$	(37,861	)	$	(46,733	)	$	(20,904	)	$	(21,823	)

Amounts Recognized in Regulatory Assets Consist of:
Prior Service Costs (Credit)	$	1,500		$	1,381		$	(469	)	$	(723	)
Net Actuarial Loss		46,564			54,393			22,463			23,599
	$	48,064		$	55,774		$	21,994		$	22,876

Amounts Recognized in Accumulated Other
Comprehensive Loss Consist of:
Net Actuarial Loss	$	9,237		$	9,212		$	-		$	-

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The projected benefit obligation (PBO) and accumulated benefit obligation (ABO) of our qualified employee pension plans were $104.6 million and $95.0 million, respectively, as of December 31, 2009, and $100.2 million and $90.8 million, respectively, as of December 31, 2008. The ABO of these plans exceeded the value of the plan assets as of December 31, 2009 and December 31, 2008. The value of these assets can be seen in the tables above. The PBO and ABO for our non-funded SERP were $18.0 million and $17.8 million, respectively, as of December 31, 2009, and $17.1 million and $16.7 million, respectively, as of December 31, 2008. The SERP is reflected in the tables above and has no assets.

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

	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008

Discount Rate		6.22	%		6.24	%		6.22	%		6.24	%
Rate of Compensation Increase		3.60	%		3.60	%		-			-

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

	Pension Benefits									Other Postretirement Benefits
	2009			2008			2007			2009			2008			2007

Discount Rate		6.24	%		6.36	%		6.04	%		6.24	%		6.36	%		6.04	%
Expected Long-Term Return on Plan Assets		8.25	%		8.50	%		8.75	%		6.80	%		7.00	%		7.25	%
Rate of Compensation Increase		3.60	%		3.60	%		3.60	%		-			-			-

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

The discount rates used to determine the benefit obligations at December 31, 2009 and 2008, which are used to determine the net periodic benefit cost for the subsequent year, were based on a portfolio model of high-quality instruments with maturities that match the expected benefit payments under our pension and other postretirement benefit plans.

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

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

	2009			2008

Medical Care and Drug Cost Trend Rate Assumed for Next Year	9.00		%	9.00	%
Dental Care Cost Trend Rate Assumed for Next Year		4.75	%	6.33	%
Rate to which Cost Trend Rates are Assumed to Decline (the Ultimate Trend Rate)		4.75	%	5.00	%
Year that the Rate Reaches the Ultimate Trend Rate		2019		2012

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-			1-Percentage-
	Point Increase			Point Decrease

Effect on the Total of Service and Interest Cost		$	77		$	(64	)
Effect on Postretirement Benefit Obligation			1,602			(1,439	)

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 38 percent U.S. equity securities, 15 percent international equity securities, 27 percent fixed income investments, and 20 percent to all other types of investments. Equity securities include investments in large-cap, mid-cap and small-cap companies. Fixed income securities include commingled common/collective trust funds and group annuity contracts for pension payments. Other types of investments include investments in hedge funds, private equity funds, and real estate funds that follow several different strategies.

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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.

We evaluated its pension and other postretirement benefit plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2009. 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, 2009, there were no significant concentrations (defined as greater than 10 percent of plan assets) of risk in SJI’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 12, that will serve as the basis for presentation throughout the remainder of this Note.

The fair values of SJG’s pension plan assets at December 31, 2009 by asset category are as follows (in thousands):

Asset Category	Total		Level 1		Level 2		Level 3
Cash / Cash Equivalents:
Common/Collective Trust Funds (a)	$	420	$	-	$	420	$	-
STIF-Type Instrument (b)		852		-		852		-
Equity securities:
Common/Collective Trust Funds (a)		39,572		-		39,572		-
U.S. Large-Cap (c)		5,205		5,205		-		-
U.S. Mid-Cap (c)		4,177		4,177		-		-
U.S. Small-Cap (c)		46		46		-		-
International (c)		408		408		-		-
Fixed Income:
Common/Collective Trust Funds (a)		18,095		-		18,095		-
Guaranteed Insurance Contract (d)		9,338		-		-		9,338
Other types of investments:
Hedge Funds (e)		881		-		-		881
Private Equity Fund (f)		2,163		-		-		2,163
Real Estate:
Common/Collective Trust Fund (g)		3,524		-		-		3,524
Total	$	84,681	$	9,836	$	58,939	$	15,906

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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 underlying assets (stocks and bonds) held in these funds are traded on active markets and prices for these assets are readily observable. 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 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. Most of the underlying fund managers are based in the U.S.; however, they do not necessarily trade only in U.S. markets. It is important to note that the SJI Pension Funds are in the process of divesting investments from this fund of funds. 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, 2009. 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 3 investments.

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Fair Value Measurement Using Significant
Unobservable Inputs (Level 3)
(In thousands)

	Guaranteed						Private
	Insurance			Hedge			Equity			Real
	Contract			Funds			Funds			Estate			Total

Balance at December 31, 2008	$	9,875		$	2,454		$	2,268		$	5,188		$	19,785
Actual return on plan assets:
Relating to assets still held at the reporting date		568			(103	)		(220	)		(1,664	)		(1,419	)
Relating to assets sold during the period		18			(352	)		-			-			(334	)
Purchases, Sales and Settlements		(1,123	)		(1,118	)		115			-			(2,126	)
Balance at December 31, 2009	$	9,338		$	881		$	2,163		$	3,524		$	15,906

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 entirely with mutual funds. The target allocations for post-retirement benefit plan assets are 48 percent U.S. equity securities, 15 percent international equity securities, and 37 percent fixed income investments. Equity securities include investments in large-cap, mid-cap and small-cap companies. Fixed income securities include both investment grade and strategic bond mutual funds.

The fair values of SJG’s other postretirement benefit plan assets at December 31, 2009 by asset category are as follows (in thousands):

Asset Category	Total		Level 1		Level 2		Level 3
Equity Securities:
U.S. Large-Cap	$	9,341	$	9,341	$	-	$	-
U.S. Mid & Small-Cap		3,231		3,231		-		-
International		3,882		3,882		-		-
Fixed Income:
Corporate Bonds		9,396		9,396		-		-
Total	$	25,850	$	25,850	$	-	$	-

All investments above are holdings in mutual funds and actively traded on major stock exchanges.

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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):

			Other
	Pension Benefits		Postretirement Benefits

2010	$	6,691	$	3,443
2011	$	6,800	$	3,656
2012	$	6,915	$	3,580
2013	$	7,105	$	3,603
2014	$	7,342	$	3,620
2015 -2019	$	42,357	$	18,671

Contributions - We made a contribution of $8.2 million to our qualified employee pension plans in 2009. SJG has no obligation to make a contribution in 2010. Payments related to the unfunded SERP plan are expected to approximate $1.0 million in 2010. 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. We match 50% of participants’ contributions up to 6% of base compensation. For employees who are not eligible for participation in SJI’s defined benefit plan, we match 50% of participants’ contributions up to 8% of base compensation. Employees not eligible for the pension plans also receive a year-end contribution of $1,000 if 10 or fewer years of service, or $1,500 if more than 10 years of service. The amount expensed and contributed for the matching provision of the Savings Plan approximated $0.7 million in each of the years ended December 31, 2009 and 2008, and 2007.

11. COMMITMENTS AND CONTINGENCIES:

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 Note6. This letter of credit expires in August 2010.

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 that any of these contracts expires is March 2010. However, discussions are taking place to extend the referenced agreement. The transportation and storage service agreements between us and our interstate pipeline suppliers were made under FERC approved tariffs. Our cumulative obligation for demand charges and reservation fees paid to suppliers for these services is approximately $4.0 million per month and is recovered on a current basis through the BGSS.

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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. Management does not currently anticipate the disposition of any known claims to have a material adverse effect on our financial position, results of operations or liquidity.

Collective Bargaining Agreements - Unionized personnel represent 64% of our workforce at December 31, 2009. 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 2013 and the International Association of Machinists and Aerospace Workers (“IAM”) that operates under a collective bargaining agreement that runs through August 2014.

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

We successfully entered into settlements with all of our historic comprehensive general liability carriers regarding the environmental remediation expenditures at our sites. Also, we have purchased a Cleanup Cost Cap Insurance Policy limiting the amount of remediation expenditures that we will be required to make at 11 of our sites. This policy will be in force until 2024 at 10 sites and until 2029 at one site. The future cost estimates discussed hereafter are not reduced by projected insurance recoveries from the Cleanup Cost Cap Insurance Policy. The policy is limited to an aggregate payment amount of $50.0 million, of which we have recovered $36.6 million through December 31, 2009. As discussed in Note 2, the BPU allows SJG to recover environmental remediation costs through the RAC.

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Since the early 1980s, we accrued environmental remediation costs of $228.7 million, of which $159.6 million has been spent as of December 31, 2009. The following table details the amounts accrued and expended for environmental remediation at December 31 (in thousands):

	2009			2008

Beginning of Year	$	64,093		$	73,880
Accruals		16,501			14,622
Expenditures		(11,538	)		(24,409	)

End of Year	$	69,056		$	64,093

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 $69.1 million to $248.6 million. We recorded the lower end of this range, $69.1 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, ranging from a low of $57.3 million to a high of $202.3 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 - A remedial action work plan has been approved by the New Jersey Department of Environmental Protection (NJDEP). Remaining steps to remediate include regulatory permitting and approval and remedy implementation for impacted soil, groundwater, and river sediments as well as acceptance of access agreements by affected property owners.

Site 2 - Various remedial investigation and action activities, such as completed and approved interim remedial measures and conceptual remedy selection, are ongoing at this site. Remaining steps to remediate include remedy selection, regulatory approval, and implementation for the remaining impacted soil and groundwater.

Site 3 - Remedial investigative activities are ongoing at this site. Remaining steps to remediate include completing the remedial investigation of impacted soil and groundwater in preparation for selecting the appropriate action and implementation and gaining regulatory and property owner approval of the selected remedy.

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Site 4 - Remedial action activities associated with groundwater are planned at this site. Remaining steps to remediate include continuing implementation of the NJDEP approved Remedial Action Work Plan of impacted groundwater.

Site 5 – Various remedial investigation and action activities are ongoing at this site. An interim remedial measure has been implemented and a remedial action work plan has been prepared and submitted to the NJDEP for an off site interim remedial measure. Remaining steps to implement the off site interim remedial measure include regulatory approval, remedial investigation of bay sediments, as well as acceptance of the selected remedy by affected property owners. Remaining steps to remediate soil and groundwater include completing the remedial investigation of impacted soil and groundwater in preparation for selecting the appropriate action and implementation and gaining regulatory and property owner approval of the selected remedy.

Site 6 – Remedial investigative activities are ongoing at this site. Remaining steps to remediate include completing the remedial investigation of impacted soil and groundwater in preparation for selecting the appropriate action and implementation and gaining regulatory and property owner approval of the selected remedy.

12. FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES:

GAAP establishes a hierarchy that prioritizes fair value measurements based on the types of inputs used for the various valuation techniques. The levels of the hierarchy are described below:

Level 1: Observable inputs such as quoted prices in active markets for identical assets or liabilities.

Level 2: Inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly; these include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.

Level 3: Unobservable inputs that reflect the reporting entity’s own assumptions.

Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of financial assets and financial liabilities and their placement within the fair value hierarchy.

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For financial assets and financial liabilities measured at fair value on a recurring basis, information about the fair value measurements for each major category as of December 31, 2009 is as follows (in thousands):

	Total		Level 1		Level 2		Level 3
Assets -

Available-for-Sale Securities (A)	$	5,941	$	5,941	$	-	$	-
Derivatives – Energy Related Assets (B)		1,130		989		141		-
	$	7,071	$	6,930	$	141	$	-

Liabilities -

Derivatives – Energy Related Liabilities (B)	$	10,303	$	8,565	$	1,738	$	-
Derivatives – Other (C)		1,956		-		1,956		-
	$	12,259	$	8,565	$	3,694	$	-

(A) Available-for-Sale Securities are valued using the quoted principal market close prices that are provided by the trustees of these securities.

(B) Derivatives – Energy Related Assets and Liabilities are traded in both exchange-based and non-exchange-based markets. Exchange-based contracts are valued using unadjusted quoted market sources in active markets and are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based contracts are valued using indicative price quotations available through brokers or over-the-counter, on-line exchanges and, are categorized in Level 2. These price quotations reflect the average of the bid-ask mid-point prices and are obtained from sources that management believes provide the most liquid market. Management reviews and corroborates the price quotations to ensure the prices are observable which includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration.

(C) Derivatives – Other, include interest rate swaps that are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

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13. AVAILABLE–FOR–SALE SECURITIES:

The Company's portfolio of investments consists of five highly diversified funds which are not used for working capital purposes. These funds are in an unrealized loss position as of December 31, 2009. Due to the nature of the underlying securities, these funds as a whole are susceptible to changes in the economy and have been adversely affected by the economic slowdown, particularly during the fourth quarter of 2008 when the Company's investments became impaired. The Company has evaluated the near-term prospects of the overall funds in relation to the severity and duration of the impairment. Based on that evaluation, the Company recorded an insignificant impairment loss during the fourth quarter of 2008. The Company does not intend to sell the remaining funds, and it is more likely than not it will not have to sell the remaining funds before recovery of its cost basis. The Company does not consider these remaining investments to be other-than-temporarily impaired at December 31, 2009.

The following table shows the gross unrealized losses and fair value of the Company's Available-for-Sale Securities with unrealized losses that are not deemed to be other-than-temporarily impaired (in thousands), aggregated by length of time that the individual funds have been in a continuous unrealized loss position at December 31, 2009 and 2008:

	Less than 12 Months				Greater Than 12 Months				Total

Marketable Equity Securities	Fair Value		Unrealized Losses		Fair Value		Unrealized Losses		Fair Value		Unrealized Losses
December 31, 2009	$	-	$	-	$	4,493	$	534	$	4,493	$	534
December 31, 2008	$	3,609	$	1,218	$	-	$	-	$	3,609	$	1,218

As of December 31, 2009 and 2008, the total losses for securities with net losses included in Accumulated Other Comprehensive Loss was $0.3 million and $0.7 million, respectively. As of December 31, 2009, securities with net gains of $0.1 million were included in Accumulated Other Comprehensive Loss. As of December 31, 2008, there were no securities with net gains included in Accumulated Other Comprehensive Loss.

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14. QUARTERLY RESULTS OF OPERATIONS - UNAUDITED:

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

	2009 Quarter Ended									2008 Quarter Ended

	March 31		June 30		Sept. 30			Dec. 31		March 31		June 30		Sept. 30			Dec. 31

Operating Revenues	$	243,113	$	64,835	$	56,305		$	120,123	$	237,904	$	93,571	$	64,563		$	172,008

Expenses:
Cost of Sales		165,977		29,905		31,726			66,244		162,917		60,263		41,201			119,022
Operation and Maintenance
Including Fixed Charges		30,246		28,413		27,016			29,025		28,257		26,134		25,408			28,737
Income Taxes (Benefit)		17,615		2,102		(1,666	)		9,053		17,530		2,482		(1,306	)		7,802
Energy and Other Taxes		4,621		1,746		1,416			3,044		4,357		1,711		1,356			3,203

Total Expenses		218,459		62,166		58,492			107,366		213,061		90,590		66,659			158,764

Other Income and Expense		324		358		107			513		170		457		242			(410	)

Net Income (Loss) Applicable to Common Stock	$	24,978	$	3,027	$	(2,080	)	$	13,270	$	25,013	$	3,438	$	(1,854	)	$	12,834

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

Item 9. Changes in and Disagreements with Accountants on

Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company’s management, with the participation of its chief executive officer and chief financial officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2009. Based on that evaluation, the Company’s chief executive officer and chief financial officer concluded that the disclosure controls and procedures employed at the Company are effective.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined under Exchange Act Rules 13a-15(f). The Company’s internal control system is designed to provide reasonable assurance to its management and board of directors regarding the preparation and fair presentation of published financial statements. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under that framework, management concluded that our internal control over financial reporting was effective as of December 31, 2009.

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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 temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

There has not been any change in the Company's internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, during the fiscal quarter ended December 31, 2009 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

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

Item 11. Executive Compensation

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

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Item 12. Security Ownership of Certain Beneficial Owners and Management

and Related Stockholder Matters

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

Item 13. Certain Relationships and Related Transactions,

and Director Independence

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

Item 14. Principal Accounting Fees and Services

Fees Paid to Auditors

Deloitte & Touche LLP served as the auditors of SJG and its parent, SJI, during 2009. 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 $366,000 and $356,000 in fiscal years 2009 and 2008, respectively.

Audit-Related Fees

None.

Tax Fees

None.

All Other Fees

None.

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PART IV

Item 15. Exhibits and Financial Statement Schedule

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

1 - The financial statements and notes to financial statements together with the report thereon of Deloitte & Touche LLP, February 26, 2010. See Item 8.

2 - Supplementary Financial Information

Report of the Independent Registered Public Accounting Firm on financial statement schedule. See Item 8.

Schedule II - Valuation and Qualifying Accounts. See page 91.

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).

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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 April 23, 2009 (filed herewith).

(4)(a)	Form of Stock Certificate for Common Stock.	Incorporated by reference from Exhibit (4)(a) of Form 10 filed March 7, 1997.

(4)(b)(i)	First Mortgage Indenture dated October 1, 1947.	Incorporated by reference from Exhibit (4)(b)(i) of Form 10-K of SJI for 1987 (1-6364).

(4)(b)(ii)	Nineteenth Supplemental Indenture dated as of April 1, 1992.	Incorporated by reference from Exhibit (4)(b)(xvii) of Form 10-K of SJI for 1992 (1-6364).

(4)(b)(iii)	Twenty-First Supplemental Indenture dated as of March 1, 1997.	Incorporated by reference from Exhibit (4)(b)(xviv) of Form 10-K of SJI for 1997 (1-6364).

(4)(b)(iv)	Twenty-Second Supplemental Indenture dated as of October 1, 1998.	Incorporated by reference from Exhibit (4)(b)(ix) of Form S-3 (333-62019).

(4)(b)(v)	Twenty-Third Supplemental Indenture dated as of September 1, 2002.	Incorporated by reference from Exhibit (4)(b)(x) of Form S-3 (333-98411).

(4)(b)(vi)	Twenty-Fourth Supplemental Indenture dated as of September 1, 2005.	Incorporated by reference from Exhibit (4)(b)(vi) of Form S-3 (333-126822).

(4)(b)(vii)	Amendment to Twenty-Fourth Supplemental Indenture dated as of March 31, 2006.	Incorporated by reference from Exhibit 4 of Form 8-K as filed April 26, 2006.

(4)(b)(viii)	Loan Agreement by and between New Jersey Economic Development Authority as SJGdated 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.

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Exhibit Number	Description	Reference

(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 of SJI 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-& (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)	Gas transportation service agreement (FTS-1) between South Jersey Gas Company and Columbia Gulf Transmission Company dated November 1, 1993.	Incorporated by reference from Exhibit (10)(k)(k) of Form 10-K for 1993 (1-6364).

(10)(c)(ii)	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)(iii)	NTS Service Agreement No. 39305 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993.	Incorporated by reference from Exhibit (10)(k)(o) of Form 10-K for 1993 (1-6364).

(10)(c)(iv)	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).

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Exhibit Number	Description	Reference

(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 Employment Agreement between certain officers and either South Jersey Industries, Inc. or its subsidiaries.	Incorporated by reference from Exhibit (10)(e)(iii) of Form 10-K of SJI for 2008 (1-6364).

(10)(h)(v)*	Schedule of Officer Employment Agreements.	Incorporated by reference from Exhibit (10)(e)(iv) of Form 10-K of SJI for 2008.

(10)(h)(vi)*	Officer Severance Benefit Program for all officers.	Incorporated by reference from Exhibit (10)(l)(g) of Form 10-K of SJI for 1985 (1-6364).

(10)(i)(i)	Five-year Revolving Credit Agreement for SJG.	Incorporated by reference from Exhibit 10 of Form 8-K as filed on August 8, 2006.

(10)(i)(ii)	Loan Agreement between Toronto Dominion (New York) LLC and SJG dated December 15, 2008.	Incorporated by reference from Exhibit (10)(i)(ii)of Form 10-K for 2008.

(10)(i)(iii)	Amendment No. 1 dated December 14, 2009 to the Loan Agreement between Toronto Dominion (New York) LLC and SJG.	Incorporated by reference from Exhibit (10)(g)(v)of Form 10K of SJI for 2009.

(12)	Calculation of Ratio of Earnings to Fixed Charges (Before Federal Income Taxes) (filed herewith).

(14)	Code of Ethics	Incorporated by reference from Exhibit (14) of Form 10-K of SJI as filed for 2007.

(21)	Subsidiaries of the Registrant (filed herewith).

(23)	Independent Registered Public Accounting Firm’s Consent(filed herewith).

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Exhibit Number	Description	Reference

(31.1)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

(31.2)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

(32.1)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

(32.2)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (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

	BY:	/s/ David A. Kindlick
		David A. Kindlick, Senior Vice President &
		Chief Financial Officer
		Date: March 1, 2010

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/ Edward J. Graham	Chairman of the Board, President & Chief Executive Officer	March 1, 2010
(Edward J. Graham)	(Principal Executive Officer)

/s/ David A. Kindlick	Senior Vice President & Chief Financial Officer	March 1, 2010
(David A. Kindlick)	(Principal Financial and Accounting Officer)

/s/ Gina Merritt-Epps	Corporate Counsel & Secretary	March 1, 2010
(Gina Merritt-Epps)

/s/ Shirli M. Billings	Director	March 1, 2010
(Shirli M. Billings)

/s/ Thomas A. Bracken	Director	March 1, 2010
(Thomas A. Bracken)

/s/ Sheila Hartnett-Devlin	Director	March 1, 2010
(Sheila Hartnett-Devlin)

/s/ William J. Hughes	Director	March 1, 2010
(William J. Hughes)

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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

	Balance at		Charged to		Charged to
	Beginning		Costs and		Other Accounts -		Deductions -		Balance at End
Classification	of Period		Expenses		Describe (a)		Describe (b)		of Period

Provision for Uncollectible
Accounts for the Year Ended
December 31, 2009	$	3,628	$	2,418	$	594	$	2,725	$	3,915


Provision for Uncollectible
Accounts for the Year Ended
December 31, 2008	$	3,265	$	2,281	$	279	$	2,197	$	3,628


Provision for Uncollectible
Accounts for the Year Ended
December 31, 2007	$	2,741	$	2,672	$	725	$	2,873	$	3,265


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

(b) Uncollectible accounts written off.

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Attached files

SOUTH JERSEY GAS Co Reports

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