10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended September 30, 2006

OR

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

For the transition period from ________________ to ________________

Commission File Number 000-22211

SOUTH JERSEY GAS COMPANY

(Exact name of registrant as specified in its charter)

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

1 South Jersey Plaza, Folsom, NJ 08037

(Address of principal executive offices, including zip code)

(609) 561-9000

(Registrant's telephone number, including area code) 

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 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 [ ]

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 [ ] Accelerated filer [ ] Non-accelerated filer [X]

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

 As of November 1, 2006 there were 2,339,139 shares of the registrant’s common stock outstanding. All common shares are owned by South Jersey Industries, Inc., the parent company of South Jersey Gas Company.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements — See Pages 2 through 21

SJG - 1

SOUTH JERSEY GAS COMPANY
STATEMENTS OF INCOME (UNAUDITED)
(In Thousands)
		Three Months Ended
		September 30,
		2006			2005
Operating Revenues	$	87,715		$	89,702
Operating Expenses:
Cost of Sales		65,014			67,076
Operations		11,088			10,474
Maintenance		1,454			1,456
Depreciation		5,916			5,512
Energy and Other Taxes		1,336			1,580
Total Operating Expenses		84,808			86,098
Operating Income		2,907			3,604
Other Income and Expense		232			11
Interest Charges		(5,736	)		(4,720	)
Loss Before Income Taxes		(2,597	)		(1,105	)
Income Tax Benefit		1,062			334
Net Loss	$	(1,535	)	$	(771	)
The accompanying notes are an integral part of the financial statements.

SJG - 2

SOUTH JERSEY GAS COMPANY
STATEMENTS OF INCOME (UNAUDITED)
(In Thousands)
		Nine Months Ended
		September 30,
		2006			2005
Operating Revenues	$	469,802		$	390,322
Operating Expenses:
Cost of Sales		349,675			266,532
Operations		35,439			37,702
Maintenance		4,224			4,460
Depreciation		17,522			16,307
Energy and Other Taxes		7,295			8,425
Total Operating Expenses		414,155			333,426
Operating Income		55,647			56,896
Other Income and Expense		370			(27	)
Interest Charges		(16,069	)		(13,353	)
Loss Before Income Taxes		39,948			43,516
Income Taxes		(16,406	)		(18,368	)
Net Income	$	23,542		$	25,148
The accompanying notes are an integral part of the financial statements.

SJG - 3

SOUTH JERSEY GAS COMPANY
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(In Thousands)
	Three Months Ended
	September 30,
		2006			2005
Net Loss	$	(1,535	)	$	(771	)
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Investments		110			100
Change in Fair Value of Derivatives		(674	)		102
Other Comprehensive Income (Loss) - Net of Tax		(564	)		202
Comprehensive Loss	$	(2,099	)	$	(569	)
	Nine Months Ended
	September 30,
		2006			2005
Net Income	$	23,542		$	25,148
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Investments		279			178
Change in Fair Value of Derivatives		199			(616	)
Other Comprehensive Income (Loss) - Net of Tax		478			(438	)
Comprehensive Income	$	24,020		$	24,710
The accompanying notes are an integral part of the financial statements.

SJG - 4

SOUTH JERSEY GAS COMPANY
STATEMENTS OF CASH FLOWS (UNAUDITED)
(In Thousands)
		Nine Months Ended
		September 30,
		2006			2005
Cash Flows from Operating Activities:
Net Income	$	23,542		$	25,148
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation and Amortization		18,905			18,577
Provision for Losses on Accounts Receivable		399			167
Revenues and Fuel Costs Deferred - Net		12,254			(8,003	)
Deferred and Noncurrent Income Taxes and Credits - Net		(498	)		19,555
Environmental Remediation Costs - Net		(5,483	)		(2,117	)
Gas Plant Cost of Removal		(1,096	)		(679	)
Changes in:
Accounts Receivable		39,961			41,127
Inventories		3,979			(32,894	)
Other Prepayments and Current Assets		(404	)		(1,357	)
Prepaid and Accrued Taxes - Net		(6,271	)		(13,472	)
Accounts Payable and Other Accrued Liabilities		(44,797	)		17,120
Other Assets		(7,555	)		5,572
Other Liabilities		1,209			(2,317	)
Net Cash Provided by Operating Activities		34,145			66,427
Cash Flows from Investing Activities:
Capital Expenditures		(47,326	)		(50,040	)
Net (Purchase of) Proceeds from Sale of Restricted Investments		(14,486	)		-
Net Cash Used in Investing Activities		(61,812	)		(50,040	)
Cash Flows from Financing Activities:
Net Borrowings from Lines of Credit		17,100			8,500
Proceeds from Issuance of Long-Term Debt		25,000			10,000
Principal Repayments of Long-Term Debt		(2,335	)		(22,773	)
Redemption of Preferred Stock		-			(1,690	)
Dividends on Common Stock		(9,951	)		(11,251	)
Payments for Issuance of Long-Term Debt		(971	)		(289	)
Premium for Early Retirement of Debt		-			(184	)
Net Cash Provided by (Used in) Financing Activities		28,843			(17,687	)
Net Increase (Decrease) in Cash and Cash Equivalents		1,176			(1,300	)
Cash and Cash Equivalents at Beginning of Period		2,551			3,310
Cash and Cash Equivalents at End of Period	$	3,727		$	2,010
Supplemental Disclosures of Noncash Investing Activities:
Capital property and equipment acquired on account but
not paid as of September 30	$	4,201		$	6,351
The accompanying notes are an integral part of the financial statements.

SJG - 5

SOUTH JERSEY GAS COMPANY
BALANCE SHEETS
(In Thousands)
		(Unaudited)
		September 30,			December 31,
		2006			2005
Assets
Property, Plant and Equipment:
Utility Plant, at original cost	$	1,067,675		$	1,030,029
Accumulated Depreciation		(253,021	)		(241,242	)
Property, Plant and Equipment - Net		814,654			788,787
Investments:
Available-for-Sale Securities		6,016			5,628
Restricted Investments		14,486			-
Total Investments		20,502			5,628
Current Assets:
Cash and Cash Equivalents		3,727			2,551
Accounts Receivable		29,919			41,040
Accounts Receivable - Related Parties		16,964			3,186
Unbilled Revenues		10,120			53,648
Provision for Uncollectibles		(2,950	)		(3,461	)
Natural Gas in Storage, average cost		87,921			89,957
Materials and Supplies, average cost		1,923			3,866
Prepaid Taxes		18,506			12,972
Derivatives - Energy Related Assets		11,386			6,496
Other Prepayments and Current Assets		3,262			2,858
Total Current Assets		180,778			213,113
Regulatory Assets:
Environmental Remediation Costs:
Expended - Net		14,833			9,350
Liability for Future Expenditures		58,216			56,717
Income Taxes - Flowthrough Depreciation		4,930			5,663
Deferred Asset Retirement Obligation Costs		20,743			19,986
Deferred Fuel Costs - Net		23,445			21,237
Deferred Postretirement Benefit Costs		2,362			2,646
Temperature Adjustment Clause Receivable		9,269			1,003
Societal Benefit Costs		5,682			2,691
Premium for Early Retirement of Debt		1,573			1,694
Other Regulatory Assets		1,372			1,499
Total Regulatory Assets		142,425			122,486
Other Noncurrent Assets:
Unamortized Debt Issuance Costs		6,875			6,251
Prepaid Pension		23,465			26,202
Accounts Receivable - Merchandise		5,555			6,472
Derivatives - Energy Related Assets		25			271
Derivatives - Other		131			-
Other		2,011			1,765
Total Other Noncurrent Assets		38,062			40,961
Total Assets	$	1,196,421		$	1,170,975
The accompanying notes are an integral part of the financial statements.

SJG - 6

SOUTH JERSEY GAS COMPANY
BALANCE SHEETS
(In Thousands, except per share amounts)
		(Unaudited)
		September 30,			December 31,
		2006			2005
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		200,317			200,317
Accumulated Other Comprehensive Loss		(3,858	)		(4,337	)
Retained Earnings		151,356			142,740
Total Common Equity		353,663			344,568
Long-Term Debt		294,903			272,235
Total Capitalization		648,566			616,803
Current Liabilities:
Notes Payable		104,100			87,000
Current Maturities of Long-Term Debt		2,270			2,273
Accounts Payable - Commodity		18,960			83,957
Accounts Payable - Other		8,686			17,236
Accounts Payable - Related Parties		10,751			7,879
Derivatives - Energy Related Liabilities		24,192			6,197
Deferred Income Taxes - Net		3,070			2,295
Customer Deposits and Credit Balances		37,387			12,145
Environmental Remediation Costs		18,877			17,873
Taxes Accrued		1,425			2,162
Dividends Payable		4,975			-
Interest Accrued		4,611			6,032
Other Current Liabilities		3,313			6,045
Total Current Liabilities		242,617			251,094
Deferred Credits and Other Noncurrent Liabilities:
Deferred Income Taxes - Net		163,890			162,542
Environmental Remediation Costs		39,339			38,844
Regulatory Liabilities		55,230			54,002
Asset Retirement Obligations		23,450			22,505
Pension and Other Postretirement Benefits		15,570			16,633
Investment Tax Credits		2,551			2,795
Derivatives - Energy Related Liabilities		1,195			84
Derivatives - Other		-			306
Other		4,013			5,367
Total Deferred Credits and Other Noncurrent Liabilities		305,238			303,078
Commitments and Contingencies (Note 9)
Total Capitalization and Liabilities	$	1,196,421		$	1,170,975
The accompanying notes are an integral part of the financial statements.

SJG - 7

NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

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. Our business is subject to seasonal fluctuations and, accordingly, this interim financial information should not be the basis for estimating the full year’s operating results. These financial statements should be read in conjunction with our 2005 Form 10-K.

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). We maintain our accounts according to the BPU’s prescribed Uniform System of Accounts. We follow the accounting for regulated enterprises prescribed by the Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation.” In general, Statement No. 71 allows deferral of certain costs and creation of certain obligations when it is probable that such items will be recovered from or refunded to customers in future periods.

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.

The BPU allows us to recover all prudently incurred gas costs through the Basic Gas Supply Service clause (BGSS). We collect these costs on a forecasted basis pursuant to BPU order. We defer over/under-recoveries of gas costs and include them in the following year's BGSS. We pay interest on the net overcollected BGSS balance at the rate of return on rate base utilized by the BPU to set rates in our last base rate proceeding.

Our tariff also includes a Temperature Adjustment Clause (TAC) and a Societal Benefits Clause (SBC). 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), which was terminated in April 2006. The TAC provides stability to our earnings and our customers’ bills by normalizing the impact of extreme winter temperatures (See Note 10 - Subsequent Events). The RAC recovers environmental remediation costs of former gas manufacturing plants and the NJCEP recovers costs associated with our energy efficiency and renewable energy programs. The USF is a statewide customer assistance program that utilizes utilities as a collection agent. The CEP recovered costs associated with providing education to the public concerning customer choice. TAC adjustments affect revenue, earnings and cash flows since colder-than-normal weather can generate credits to customers, while warmer-than-normal weather can result in additional billings.  RAC adjustments affect revenue and cash flows but do not directly affect earnings because we defer and recover related costs through rates over 7-year amortization periods. NJCEP, CEP and USF adjustments also affect revenue and cash flows but do not directly affect earnings, as related costs are deferred and customer credits are recovered through rates on an ongoing basis.

SJG - 8

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

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.

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 2.4% in 2005 and 2.3% for the first nine months of 2006. 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. Capitalized interest is included in Utility Plant on the balance sheets. Interest Charges are presented net of capitalized interest on the statements of income. As of September 30, we capitalized interest as follows (in thousands):

	September 30, 2006		September 30, 2005
Quarter Ended	$	102	$	258
Nine Months Ended		310		800

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 nine months ended September 30, 2006 and for the year ended December 31, 2005, no significant impairments were identified.

Derivative Instruments - We account for derivative instruments in accordance with FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. 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 Other Comprehensive Income (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. Due to the application of regulatory accounting principles under FASB Statement No. 71, derivatives related to gas purchases are recorded through our BGSS.

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. We also 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, if we 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 the 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 previously included in Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings when the forecasted transaction occurs, or when it is not probable that it will occur.

SJG - 9

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 and futures contracts on our behalf. The costs or benefits of these contracts are included in our BGSS, subject to BPU approval. As of September 30, 2006 and December 31, 2005 we had $14.0 million and $(0.5) million of costs (benefits), respectively, included in our BGSS related to open financial contracts (See Regulatory Assets & Liabilities).

The vast majority of our contracts relate to physical transactions that qualify for the normal purchase and sale exception. Therefore, we are not required to mark these contracts to market.

From time to time we enter into interest rate derivatives and similar agreements to hedge exposure to increasing interest rates and the impact of those rates on our cash flows, with respect to our variable-rate debt. We have designated and account for these interest rate derivatives as cash flow hedges. For the three and nine months ended September 30, 2006, and 2005, the ineffective portions of the derivatives designated as cash flow hedges were not material. On October 21, 2005, we entered into two long-term forward-starting interest rate swaps which effectively fixed the interest rate at 3.43%, commencing December 1, 2006 through January 2036, on $25.0 million of variable-rate, tax-exempt debt which was issued in April 2006. Beginning December 1, 2006, the differential to be paid or received as a result of these swap agreements will be accrued as interest rates change and will be recognized as an adjustment to interest expense.

As of September 30, 2006, the market value of these agreements was $0.1 million and is included on the balance sheet under the caption Other Noncurrent Assets - Derivatives - Other. The recorded balance as of September 30, 2006 represents the amount we would have received from the counterparties if the contracts had been terminated on that date. As of December 31, 2005, the market value of these agreements was $(0.3) million and is included on the balance sheet under the caption Deferred Credits and Other Noncurrent Liabilities - Derivatives - Other. The recorded balance as of December 31, 2005 represents the amount we would have had to pay to the counterparties if the contracts had been terminated on that date. As of September 30, 2006 and December 31, 2005, we calculated the swaps to be highly effective; therefore, we recorded the change in fair value of the swaps, net of taxes, in Accumulated Other Comprehensive Loss.

We determined the fair value of derivative instruments by reference to quoted market prices of listed contracts, published quotations or quotations from unrelated third parties.

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.

Stock-Based Compensation Plans - On January 1, 2006, SJI adopted FASB Statement No. 123(R), “Share-Based Payment”, which revised FASB Statement No. 123, and superseded Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” Since officers of SJG participate in the Stock Option, Stock Appreciation Rights and Restricted Stock Award Plan (“Plan”) of SJI, changes in accounting for share-based payments also impact SJG. Statement No. 123(R) requires SJI to measure and recognize stock-based compensation expense in its financial statements based on the fair value at the date of grant for its share-based awards, which currently include restricted stock awards containing market and service conditions. In accordance with Statement No. 123(R), SJI is recognizing compensation expense over the requisite service period for: (i) awards granted on, or after, January 1, 2006 and (ii) unvested awards previously granted and outstanding as of January 1, 2006. In addition, SJI is estimating forfeitures over the requisite service period when recognizing compensation expense. These estimates can be adjusted to the extent to which actual forfeitures differ, or are expected to materially differ, from such estimates.

As permitted by Statement No. 123(R), SJI chose the modified prospective method of adoption; accordingly, financial results for the prior period presented were not retroactively adjusted to reflect the effects of this Statement. Under the modified prospective application, this Statement applies to new awards and to awards modified, repurchased, or cancelled after the required effective date. Compensation costs for the portion of awards for which the requisite service has not been rendered that are outstanding as of the required effective date shall be recognized as the requisite service is rendered based on the grant-date fair value.

SJG - 10

SJG purchases shares of common stock from SJI to satisfy its obligations under this Plan. This cash payment is equal to the amounts accrued as compensation cost during the service period. For shares granted on, or after, January 1, 2006, the accrued liability and payment shall be based on the grant date fair value of the restricted stock award earned by the employee at the date of vesting. As a result of this policy, SJG accrues a liability and records compensation cost on a straight-line basis over the requisite three-year service period based on the grant date fair value. For unvested awards previously granted and outstanding as of January 1, 2006, the payment shall be based on the sum of (i) amounts previously accrued as liabilities for such awards as of December 31, 2005, and (ii) the grant date fair value of the remaining services as of January 1, 2006 on such awards, as determined on a basis consistent with those awards granted on, or after, January 1, 2006. Since the inception of the Plan, SJG’s expense recognition policy has been consistent with the expense recognition policy at SJI. Further, compensation expense is recognized for awards that ultimately vest, and 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.

The following table summarizes the nonvested officers’ restricted stock awards outstanding at September 30, 2006 and the assumptions used to estimate the fair value of the awards (adjusted for a June 2005 two-for-one stock split):

Grant	Shares	Fair Value	Expected	Risk-Free
Date	Outstanding	Per Share	Volatility	Interest Rate
Jan. 2004	10,352	$ 20.105	16.4%	2.4%
Jan. 2005	8,342	$ 25.155	15.5%	3.4%
Jan. 2006	8,044	$ 27.950	16.9%	4.5%

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 three-year term of the officers’ restricted shares. As notional dividend equivalents are credited to the holders, which are reinvested during the three-year service period, no reduction to the fair value of the award is required.

For the nine months ended September 30, 2006 and 2005, the cost of officers’ restricted stock awards was $149,475 and $1,044,612, respectively. Of these costs, $85,710 and $366,756, respectively, were capitalized to Utility Plant.

As of September 30, 2006, 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 1.3 years.

Prior to the adoption of Statement No. 123 (R), SJI applied Statement No. 123, as amended, which permitted the application of APB No. 25. In accordance with APB No. 25, SJI and SJG recorded compensation expense over the requisite service period for restricted stock based on the probable number of shares expected to be issued and the market value of SJI’s common stock at the end of each reporting period. As a result of this previous accounting treatment, there have been no excess tax benefits recognized since the inception of the Plan.

The adoption of Statement No. 123(R) resulted in a reduction in stock-based compensation expense of $35,958 for the nine months ended September 30, 2006. This decrease in expense would have had an immaterial impact on our cash flows for the period presented.

SJG - 11

The following table summarizes information regarding restricted stock award activity during the nine months ended September 30, 2006:

	Officers *
Nonvested Shares Outstanding, January 1, 2006	49,816
Granted	10,991
Vested**	(27,924)
Cancelled/Forfeited	(6,145)
Nonvested Shares Outstanding, September 30, 2006	26,738
*   Excludes accrued dividend equivalents.
** Actual shares awarded upon vesting, including dividend equivalents and adjustments for performance measures, totaled 44,575 shares.

During the nine months ended September 30, 2006, SJG awarded 44,575 shares to its officers at a market value of $1.3 million. As a result of an SJI corporate restructuring, SJG was also obligated to settle a liability for services previously rendered by officers that are currently employed by affiliates totaling $1.0 million. During the nine months ended September 30, 2005, SJG awarded 62,058 shares at a market value of $1.6 million. As discussed earlier, SJG has a policy of purchasing shares from SJI to satisfy its obligations under these plans. Cash payments for shares of SJI common stock during the nine months ended September 30, 2006 and 2005 were approximately $2.1 million and $1.6 million, respectively. There were no awards granted during the three month periods ended September 30, 2006 and 2005. Additionally, a change in control could result in the nonvested shares becoming nonforfeitable or immediately payable in cash.

Regulatory Assets & Liabilities - All significant regulatory assets are separately identified on the balance sheets. Each item that is separately identified is or will be recovered through utility rate charges. We are currently permitted to recover interest on our Environmental Remediation Costs and Societal Benefit Costs while the other assets are being recovered without a return on investment over the following periods:

	Years Remaining
Regulatory Asset	As of September 30, 2006
Environmental Remediation Costs:
Expended - Net		Various
Liability for Future Expenditures		Not Applicable
Income Taxes - Flowthrough Depreciation		5
Deferred Asset Retirement Obligation Costs		Not Applicable
Deferred Fuel Costs - Net		Various
Deferred Postretirement Benefit Costs		6
Temperature Adjustment Clause Receivable		Various
Societal Benefit Costs		Various
Premium for Early Retirement of Debt		Various

SJG - 12

Some of the assets included in the caption 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.

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 included in the BGSS, subject to BPU approval. The offset to the change in fair value of these contracts is recorded as a component of the regulatory asset, Deferred Fuel Costs - Net, if we are in a net undercollected position, or as a component of the regulatory liability, Deferred Gas Revenues - Net, if we are in a net overcollected position. As of September 30, 2006, costs related to derivative contracts increased Deferred Fuel Costs - Net by $14.0 million. As of December 31, 2005, benefits related to derivative contracts reduced Deferred Fuel Costs - Net by $0.5 million.

Regulatory Liabilities at September 30, 2006 and December 31, 2005 consisted of the following items (in thousands):

	September 30, 2006		December 31, 2005
Excess Plant Removal Costs	$	48,286	$	48,071
Overcollected State Taxes		4,151		4,025
Other		2,793		1,906
Total Regulatory Liabilities	$	55,230	$	54,002

Excess Plant Removal Costs represent 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. The Overcollected State Taxes will be credited to the BGSS clause and returned to customers as a condition of a recent settlement (See Note 10 - Subsequent Event). All other regulatory liabilities are subject to being returned to ratepayers in future rate proceedings.

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- In July 2006, the FASB issued Interpretation No. 48 “Uncertainty in Income Taxes” (FIN 48). This Interpretation provides guidance on the recognition and measurement of uncertain tax positions in the financial statements. The effective date of FIN 48 is January 1, 2007. Management is currently evaluating the impact that the adoption of this interpretation will have on our financial statements.

In September 2006, the FASB issued its Staff Position (FSP) on “Accounting for Planned Major Maintenance Activities.” This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. This FSP is effective the first fiscal year beginning after December 15, 2006. However, as we do not currently accrue in advance for such costs, this FSP will have no affect on our financial statements.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. This statement is effective in fiscal years beginning after November 15, 2007.  Management is currently evaluating the impact that the adoption of this statement will have on our financial statements.

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In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” The new statement requires a calendar year-end company with publicly traded equity securities that sponsors a postretirement benefit plan to fully recognize, as an asset or liability, the overfunded or underfunded status of its benefit plans in its 2006 year-end balance sheet and recognize changes in the funded status in the year in which the changes occur (reported in other Comprehensive Income (Loss)). The new standard will also require a company to measure its plan assets and benefit obligations as of its year-end balance sheet date, effective for fiscal years ending after December 15, 2008.  Management is currently evaluating the impact that the adoption of this statement will have on our financial statements; however, this statement does not have an impact on the computation of benefit expense recognized in the income statement.

Reclassifications - We reclassified some previously reported amounts to conform with current period classifications. These amounts are considered immaterial to the overall presentation of our financial statements.

2.REGULATORY ACTIONS:

Base Rates - On July 7, 2004, the BPU granted us a base rate increase of $20.0 million effective July 8, 2004, which was predicated in part upon 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 reduce our composite depreciation rate from 2.9% to 2.4%.

BPU Audit - In 2004, the BPU commenced a competitive services audit and a management audit that included a focused review of our gas supply and purchasing practices. The BPU is mandated by statute to conduct such audits at predetermined intervals. In February 2006, the audit reports were released by the BPU for comments. The final BPU order accepting the recommendations of the auditor, with some minor revisions, was signed in August 2006. The recommendations contained in these audits have no material effect on our financial statements.

Other Regulatory Matters - In December 2004, the BPU approved the statewide funding of the NJCEP of $745.0 million for the years 2005 through 2008. Of this amount, we will be responsible for approximately $25.4 million over the 4-year period. Amounts not yet expended have been included in our Contractual Cash Obligations table included in Note 9.

In February 2005, we filed notice with the BPU to provide for an $11.4 million bill credit to customers. The bill credit was implemented in March 2005. In June 2005, we made our annual BGSS filing with the BPU requesting a $17.1 million, or 6.3% increase in gas cost recoveries in response to increasing wholesale gas costs. In August 2005, the BPU approved our requested increase, effective September 1, 2005, on an interim basis.

In October 2005, we filed a petition with the BPU to implement a Pipeline Integrity Management Tracker (Tracker) along with the three other natural gas distribution companies in New Jersey. The purpose of the Tracker is to recover 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. The New Jersey utilities are requesting approval of the Tracker since the new regulations will result in ongoing incremental costs. Costs incurred to date are not considered significant. We anticipate that a large portion of the incremental cost is dependent upon overall assessment results, and therefore cannot be specifically predicted at this time.

In November 2005, we made our annual SBC filing, requesting a $6.1 million reduction in annual recoveries.

In November 2005, we filed a BGSS Motion for Emergent Rate Relief in conjunction with the other natural gas utilities in New Jersey. This filing was necessary due to substantial increases in wholesale natural gas prices across the country. In December 2005, the BPU approved an $85.7 million increase to our rates, effective December 15, 2005, on an interim basis.

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In December 2005, we made a filing proposing to implement a Conservation and Usage Adjustment (CUA) Clause, on a five-year pilot basis. The primary purpose of the CUA is to promote conservation and to base our profit margin on the number of customers rather than the amount of natural gas distributed to customers. This structure will allow us to aggressively promote conservation programs without negatively impacting our financial stability. In October 2006, the BPU approved the CUA as a three year pilot program and renamed it the Conservation Incentive Program (CIP) (See Note 10 - Subsequent Event).

In March 2006, the BPU approved a global settlement, effective April 1, 2006, fully resolving our September 2004 SBC filing, 2003-2004 TAC filing, 2004-2005 BGSS filing and certain issues in the 2005-2006 BGSS filing. The net impact is a $4.4 million reduction to annual revenues; however, this reduction has no impact on net income as there will be a dollar-for-dollar reduction in expense. In addition, a pilot storage incentive program was approved. This program began during the second quarter of 2006 and will continue for three summer injection periods through 2008. It is designed to provide us with the opportunity to achieve BGSS price reductions and additional price stability. It will also provide us with an opportunity to share in the storage-related gains and losses, with 20% being retained by us, and 80% being credited to customers. Total storage-related gains for the three and nine months ended September 30, 2006, were $0.8 million and $1.6 million, respectively.

In June 2006, we made our annual BGSS filing with the BPU requesting a $19.7 million, or 4.6%, decrease in gas cost recoveries in response to decreasing wholesale gas costs and an $11.5 million benefit derived from the release of a storage facility and the liquidation of our low-cost base gas made available during the second quarter. Due to the continuing decrease in wholesale gas costs subsequent to our June 2006 filing, an agreement to utilize gas from a released storage facility for this upcoming winter, and a credit to gas costs for previously overcollected state taxes (See Notes 1 and 10), the BPU approved a $38.7 million, or 8.6%, annual decrease in gas cost recoveries in September 2006.

In July 2006, we made our annual USF filing, along with the state’s other electric and gas utilities, proposing to increase annual statewide gas revenues to $115.3 million, an increase of $68.5 million. Under the proposal, our annual USF revenues will increase to $13.0 million, which represents a $7.7 million increase in annual USF revenues.

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

3.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 established on January 1, 2006, that provides services to SJI and its other subsidiaries, including SJG, such as information technology, human resources, government relations, corporate communications, materials purchasing, fleet management and insurance.

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 sell 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.

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·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 price 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. In addition to our normal gas purchases and sales with SJRG, during the second quarter of 2006, we sold 1,710,903 decatherms of gas to SJRG for $13.1 million. This sale was conducted in compliance with all applicable regulatory requirements. The proceeds from the sale were credited to the BGSS clause and did not impact earnings during the quarter. The remaining amount due from SJRG for this transaction, $9.7 million, is to be paid to us during the fourth quarter of 2006.

·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 also provide billing services to SJESP.

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

Measurement Solutions International - Northeast LLC (MSI) - a metering and measurement services company in which SJI holds a minority interest. MSI provides us with meter services including procurement, warehousing and maintenance.

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

In addition to the above, we provide various administrative and professional services to SJI, SJE, SJRG, SJESP and Marina. Likewise, SJI provides substantial administrative services on our behalf. Beginning in January 2006, SJIS began to provide a majority of the aforementioned administrative services to SJI and its subsidiaries; therefore, administrative support from us to affiliates will generally decrease from 2005 to 2006. 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, were as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Sales and Services Provided to:
SJIS	$	91	$	-	$	272	$	-
SJI		92		298		726		1,038
SJES		21		-		71		-
SJE		26		184		117		581
SJRG		14,138		628		44,129		4,250
Marina		42		53		192		205
SJESP		68		198		282		582

Sales and Services Received from:
SJRG	$	11,521	$	80	$	40,809	$	2,807
SJI		1,227		1,020		5,906		4,449
SJIS		1,190		-		3,909		-
Millennium		690		659		2,046		1,955

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As of September 30, 2006 and December 31, 2005, amounts due to and from related parties, including pass-through items, were as follows (in thousands):

	September 30,		December 31,
	2006		2005
Amounts due to:
SJIS	$	1,370	$	-
SJI		795		1,470
SJE		6,283		1,691
SJRG		727		3,242
SJESP		1,274		993
Millennium		234		220
MSI		68		263
	$	10,751	$	7,879
Amounts due from:
SJIS	$	149	$	-
SJI		94		631
SJES		37		-
SJE		42		35
SJRG		16,391		2,184
SJESP		175		242
Marina		11		20
Millennium		65		74
	$	16,964	$	3,186

4.LONG-TERM DEBT:

In April 20, 2006, we issued $25.0 million of secured tax-exempt, auction-rate debt through the New Jersey Economic Development Authority (NJEDA). The auction rate, which resets weekly, was set at 3.40% as of September 30, 2006. Of the proceeds from the issue, $14.3 million was invested in interest-bearing securities pending the incurrence of capital costs that qualify for tax-exempt financing. In anticipation of this transaction, we previously entered into forward-starting interest rate swap agreements that effectively fixed the interest rate on this debt at 3.43%, commencing December 1, 2006 through January 2036. The debt was issued under our medium-term note program. An additional $115.0 million of medium-term notes remains available for issuance under that program.

5.RESTRICTED INVESTMENTS:

In accordance with the terms of our loan agreements, we were required to escrow unused proceeds pending approved construction expenditures. As of September 30, 2006, the escrowed proceeds, including interest earned, totaled $14.5 million.

6.UNUSED LINES OF CREDIT:

Bank credit available to us totaled $151.0 million at September 30, 2006, of which $104.1 million was used. Those bank facilities consist of a $100.0 million credit facility that expires in August 2011, and $51.0 million of uncommitted bank lines. The revolving credit facility contains one financial covenant regarding the ratio of total debt to total capitalization, measured on a quarterly basis. We were in compliance with this covenant as of September 30, 2006. Borrowings under these credit facilities are at market rates. The weighted-average borrowing cost, which changes daily, was 5.74% and 4.42% on September 30, 2006 and 2005, respectively. We maintain demand deposits with lending banks on an informal basis and they do not constitute compensating balances.

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7. RETAINED EARNINGS:

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 $353.7 million at September 30, 2006.

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 September 30, 2006, these restrictions did not affect the amount that may be distributed from our retained earnings.

We received an equity infusion of $30.0 million from SJI during 2005. There were no equity infusions during the first three quarters of 2006. Contributions of capital are credited to Other Paid-In Capital and Premium on Common Stock. Future equity contributions will occur on an as needed basis.

8.PENSIONS & OTHER POSTRETIRMENT BENEFIT PLANS:

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. Newly hired employees do not qualify for participation in the defined benefit pension plans. New hires 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.

The BPU authorized us to recover costs related to postretirement benefits other than pensions under the accrual method of accounting consistent with FASB Statement No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." We deferred amounts accrued prior to that authorization and are amortizing them as allowed by the BPU. The unamortized balance of $2.4 million at September 30, 2006 is recoverable in rates. We are amortizing this amount over 15 years, which started January 1998.

Net periodic benefit cost for the three and nine months ended September 30, 2006 and 2005 related to the employee and officer pension and other postretirement benefit plans consisted of the following components (in thousands):

	Pension Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Service Cost	$	574		$	714		$	1,723		$	2,139
Interest Cost		1,471			1,467			4,411			4,399
Expected Return on Plan Assets		(1,880	)		(1,869	)		(5,639	)		(5,608	)
Amortization of Loss and Other		576			644			1,728			1,934
Net Periodic Benefit Cost		741			956			2,223			2,864
Capitalized Benefit Costs		(319	)		(314	)		(956	)		(943	)
Net Periodic Benefit Expense	$	422		$	642		$	1,267		$	1,921

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	Other Postretirement Benefits
	Three Months Ended							Nine Months Ended
	September 30,							September 30,
		2006			2005			2006			2005
Service Cost	$	234		$	183		$	492		$	549
Interest Cost		1,095			491			1,709			1,473
Expected Return on Plan Assets		(757	)		(371	)		(1,213	)		(1,112	)
Amortization of Loss and Other		354			52			394			156
Net Periodic Benefit Cost		926			355			1,382			1,066
Capitalized Benefit Costs		(398	)		(124	)		(594	)		(373	)
Net Periodic Benefit Expense	$	528		$	231		$	788			693

The reduction in service costs during 2006 in the tables above was the result of the transfer of employees from SJG to SJI Services, effective January 1, 2006. Capitalized benefit costs reflected in the table above relate to our construction program.

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
2006	$	5,436	$	2,147
2007		5,503		2,361
2008		5,561		2,474
2009		5,635		2,549
2010		5,707		2,688
2011-2015		31,384		13,318

Contributions - We do not expect to make any contributions to our pension plan in 2006; however, changes in future investment performance and discount rates may ultimately result in a contribution during the fourth quarter. 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.

9.COMMITMENTS AND CONTINGENCIES:

The following table summarizes our contractual cash obligations and their applicable payment due dates as of September 30, 2006 (in thousands):

			Up to		Years		Years		More than
Contractual Cash Obligations	Total		1 Year		2 & 3		4 & 5		5 Years
Long-Term Debt	$	297,173	$	2,270	$	-	$	35,000	$	259,903
Interest on Long-Term Debt		238,357		17,191		34,003		33,697		153,466
Operating Leases		232		124		89		19		-
Construction Obligations		304		304		-		-		-
Commodity Supply Purchase Obligations		218,740		49,829		82,215		26,785		59,911
New Jersey Clean Energy Program		15,557		5,807		9,750		-		-
Other Purchase Obligations		9,695		4,453		3,053		2,064		125
Total Contractual Cash Obligations	$	780,058	$	79,978	$	129,110	$	97,565	$	473,405

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Expected environmental remediation costs and asset retirement obligations are not included in the table above due to the subjective nature of such costs and timing of anticipated payments. As a result, the total obligation cannot be calculated. Additionally, future pension contributions are not included in the table as contributions vary from year-to-year based on investment performance and discount rates. Our regulatory obligation to contribute to our postretirement benefit plans’ trust, as discussed in Note 8, is also not included as its duration is indefinite.

Gas Supply Contracts - In the normal course of 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 October 2007. The transportation and storage service agreements between our interstate pipeline suppliers and us were made under Federal Energy Regulatory Commission approved tariffs. Our cumulative obligation for demand charges and reservation fees paid to suppliers for these services is approximately $4.4 million per month which are recovered on a current basis through the BGSS.

Pending Litigation - We are subject to claims arising in the ordinary course of business and other legal proceedings. We accrue liabilities related to these claims when we can 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.

Union Contract - Unionized personnel represent 70% of our workforce at September 30, 2006 and are operating under agreements that run through at least January 2008.

Environmental Remediation Costs - We incurred and recorded costs for environmental cleanup of 12 sites where our predecessors or we 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 received $8.4 million through September 30, 2006.

Since the early 1980s, we accrued environmental remediation costs of $162.5 million, of which $104.3 million has been spent as of September 30, 2006. With the assistance of consulting firms, we estimate that undiscounted future costs to clean up our sites will range from $58.2 million to $212.1 million. We recorded the lower end of this range, $58.2 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. Four of our sites comprise a significant portion of these estimates, ranging from a low of $31.9 million and a high of $125.1 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 following table details the amounts expended and accrued for environmental remediation (in thousands):

	Nine Months Ended			Year Ended
	September 30, 2006			December 31, 2005
Beginning Balance	$	56,717		$	51,046
Accruals and Adjustments		8,895			11,710
Expenditures		(6,448	)		(6,039	)
Insurance Recoveries		(948	)		-
Ending Balance	$	58,216		$	56,717

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

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

Site 1 - The remedial selection process is underway for this site. Once complete, a remedial action work plan will be submitted to the New Jersey Department of Environmental Protection (NJDEP) for approval. Remaining steps to remediate include remedy selection, regulatory approval and remedy implementation for impacted soil, groundwater, and river sediments as well as acceptance of the selected remedy 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, groundwater, and stream sediments.

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.

Site 4 - Remedial investigative activities are ongoing at this site. Remaining steps to remediate include completing the remedial investigation of impacted soil, groundwater and sediment in preparation for selecting the appropriate action and implementation and gaining regulatory and property owner approval of the selected remedy. An interim remedial measure is being planned to accommodate a third party property owner’s development needs.

We have two regulatory assets associated with environmental costs. The first asset, Environmental Remediation Cost: Expended - Net, represents what was actually spent to clean up former gas manufacturing plant sites. These costs meet the requirements of FASB Statement No. 71. The BPU allows us to recover expenditures through the RAC. The other asset, Environmental Remediation Cost: Liability for Future Expenditures, relates to estimated future expenditures determined under the guidance of FASB Statement No. 5, "Accounting for Contingencies." We recorded this amount, which relates to former manufactured gas plant sites, as a regulatory asset under Statement No. 71 with the corresponding amounts reflected on the balance sheets under the captions Current Liabilities and Deferred Credits and Other Noncurrent Liabilities. The BPU's intent, evidenced by current practice, is to allow us to recover the deferred costs over 7-year periods after they are spent.

As of September 30, 2006, we reflected the unamortized expended remediation costs of $14.8 million on the balance sheet under Regulatory Assets. Since implementing the RAC in 1992, we have recovered $45.5 million through rates.

10.SUBSEQUENT EVENT:

We received approval from the New Jersey BPU for the CIP, previously referenced as the CUA, on October 12, 2006. The CIP was approved as a three-year pilot program, commencing October 2006.  The program is designed to decouple the link between customer usage and our utility gross margin to allow us to encourage our customers to conserve energy.  Under the approval, the existing TAC will be replaced with the CIP tracking mechanism, which addresses margin variations related to both weather and customer usage. Furthermore, we are required to initiate programs to aid customer conservation efforts. Finally, we agreed to credit the BGSS for approximately $4.2 million of previously overcollected state taxes as part of this settlement. This credit will have no impact on our earnings.

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Item 2. Management’s Discussion and Analysis of Financial Condition

and Results of Operations (Unaudited)

OVERVIEW:

Organization - South Jersey Gas Company (SJG) is a regulated natural gas utility, wholly owned by South Jersey Industries, Inc. (SJI). We distributed natural gas in the seven southernmost counties of New Jersey to 325,589 customers at September 30, 2006, compared with 317,273 customers at September 30, 2005. We also:

o sell natural gas and pipeline transportation capacity (off-system sales) on a wholesale basis to various customers on the interstate pipeline system; and

o transport natural gas purchased directly from producers or suppliers for our own sales and for some of our customers.

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

A discussion of these and other risks and uncertainties may be found in our Form 10-K for the year ended December 31, 2005 and in other filings made by us with the Securities and Exchange Commission. These cautionary statements should not be construed by you to be exhaustive and they are made only as of the date of this Quarterly Report on Form 10-Q, or in any document incorporated by reference, at the date of such document. While we believe 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, we undertake no obligation to update or revise any of our forward-looking statements, whether as a result of new information, future events or otherwise.

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, energy derivatives, environmental remediation costs, pension and other postretirement employee benefit costs, and revenue recognition. A discussion of these estimates and assumptions may be found in our Form 10-K for the year ended December 31, 2005.

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

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Temperature Adjustment Clause - The BPU-approved Temperature Adjustment Clause (TAC) is designed to mitigate the effect of variations in heating season temperatures from historical norms. While we record the revenue and earnings impacts of TAC adjustments as incurred, cash inflows or outflows directly attributable to TAC adjustments generally do not begin until the next clause year. Each TAC year begins October 1 and ends May 31 of the subsequent year. The TAC increased (decreased) our net income by $0.1 million and $(0.1) million for the three months and $5.0 million and $(0.2) million for the nine months ended September 30, 2006 and 2005, respectively. Weather during the nine months ended September 30, 2006 was 18.1% warmer than the same period last year, and 14.1% warmer than the 20-year TAC average. Due to significantly warmer weather during the 2005-2006 winter season, the deferred amount due from ratepayers as of September 30, 2006 for TAC adjustments was $9.3 million compared to $0.9 million as of September 30, 2005. Effective October 1, 2006, the TAC was replaced by a Conservation Incentive Program (CIP) tracking mechanism (see below). The outstanding TAC balance of $9.3 million as of September 30, 2006, will be recovered under our current TAC.

Conservation Incentive Program - The CIP is a BPU-approved pilot program that commences October 1, 2006 for a duration of three years.  The program is designed to eliminate the link between our profits and the quantity of natural gas we sell and improve conservation efforts. Going forward, our profits will be 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.  Under the approval, the existing TAC will be replaced with a CIP tracking mechanism which will adjust earnings based on weather and non-weather related factors. The CIP tracking mechanism will adjust our revenues similar to the TAC for weather variations and will also adjust our revenues where actual usage per customer experienced during an annual period varies from an established baseline usage per customer.

Just as currently occurs under the TAC, utility earnings will be 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 will run from October 1 to September 30.

The CIP is expected to contribute up to $4.5 million to earnings over the initial twelve months after implementation, depending on actual use factors realized. The incremental earnings are derived from baseline usages per customer which have been set above the average utilization rate recently experienced by our customers, and from the fact that customer usage has been consistently declining, primarily due to more energy efficient appliances and building standards.

As part of the CIP, we are required to implement additional conservation programs including customized customer communications 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.

Earnings accrued and payments received under the CIP are limited to a return on equity of no more than 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.

Regulatory Actions - See detailed discussions concerning Regulatory Actions in Note 2 to the financial statements.

Environmental Remediation - See detailed discussion concerning Environmental Remediation in Note 9 to the financial statements.

SJG - 23

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.” 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. For a period of several years, marketers had successfully attracted gas commodity customers by offering natural gas at prices competitive with those available under regulated utility tariffs. However, during the third quarter of 2005, marketers found it increasingly difficult to compete with the local utility because of changing market conditions and rising gas costs. Our affiliate, South Jersey Energy Company, responded by returning approximately 69,000 residential gas customers to us during the third quarter of 2005. As a result, the total number of customers in our service territory purchasing natural gas from a marketer fell from 82,829 to 12,372 during the third quarter of 2005. Beginning in the first quarter of 2006, marketers began to attract customers back through new offers. Although the number of transportation customers increased to 16,960 as of September 30, 2006, the average number of transportation customers was 16,606 and 55,873 for the three months ended September 30, 2006 and 2005, respectively, and 13,984 and 74,289 for the nine months ended September 30, 2006 and 2005, respectively.

While customer choice can significantly affect utility revenues and gas costs, it does not affect net income as we earn no profit margin on the commodity portion of our natural gas sales (See Results of Operations). The BPU continues to allow for full recovery of prudently incurred natural gas costs through the Basic Gas Supply Service (BGSS) Clause as well as other costs of service, including deferred costs, through tariffs.

RESULTS OF OPERATIONS:

Operating Revenues - Revenues decreased $2.0 million and increased $79.5 million for the three and nine-month periods ended September 30, 2006, respectively, compared with the same periods last year. The increase in revenues for the nine months ended September 30, 2006, was primarily due to three factors. First, we added 8,316 customers during the 12-month period ended September 30, 2006, which represents a 2.6% increase in total customers. Second, as previously discussed under Customer Choice Legislation, the average number of transportation customers decreased 81.2%, from 74,289 to 13,984, for the nine months ended September 30, 2006 as compared with the same period in 2005. The migration of customers from transportation service back to sales service has a direct impact on utility revenues as charges for gas costs are included in sales revenues and not in transportation revenues. However, since gas costs are passed on directly to customers without any profit margin added by us, the change in customer utilization of gas marketers did not impact our earnings. Third, we were granted two BGSS rate increases as a result of substantial increases in wholesale natural gas prices across the country. The first increase in September 2005, resulted in a 4.4% increase in the average residential customer’s bill and 5.0% in the average commercial/industrial customer’s bill. The second was effective in December 2005, and resulted in a 24.3% increase in the average residential customer’s bill and 28.4% in the average commercial/industrial customer’s bill. However, as previously stated, since gas costs are passed on directly to customers without any profit margin added by us, the BGSS rate increases did not impact our profitability.

Partially offsetting the positive factors noted above were lower customer utilization rates experienced during the three and nine months ended September 30, 2006, compared with the same periods in 2005, primarily due to the impact of higher natural gas prices on customer usage. Additionally, sales to an electric generation customer were substantially lower than last year as the 2006 summer season weather was not nearly as warm as the 2005 summer season.

Revenues for the third quarter of 2006 were slightly lower than the same period last year. Overall, revenue from residential and commercial customers was higher because of the three positive factors noted above for the first nine months of 2006. However, as sales volumes are at their lowest points during the third quarter, the offset in sales related to an electric generation customer resulted in a net decrease in revenues.

Total gas throughput decreased 14.6% to 32.3 billion cubic feet (Bcf) for the three months ended September 30, 2006, compared with the same period in 2005. Total gas throughput decreased 16.3% to 100.2 Bcf for the nine months ended September 30, 2006, compared with the same period in 2005. The lower throughput was primarily due to significantly warmer weather experienced during 2006, as previously discussed under the TAC, which lowered sales and opportunity for capacity release.

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The following table is a comparison of operating revenue and throughput for the three and nine months ended September 30:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
		2006		2005		2006		2005
Operating Revenues (thousands):
Firm Sales
Residential	$	28,209	$	22,307	$	241,593	$	149,421
Commercial		11,496		10,325		75,749		55,763
Industrial		665		1,279		3,627		3,423
Cogeneration & Electric Generation		6,457		10,901		9,817		16,040
Firm Transportation
Residential		647		2,962		2,790		23,888
Commercial		1,683		1,899		8,156		10,321
Industrial		3,027		3,282		9,289		9,846
Cogeneration & Electric Generation		175		115		186		220
Total Firm Revenues		52,359		53,070		351,207		268,922
Interruptible		95		340		864		1,179
Interruptible Transportation		332		361		1,324		1,476
Off-System		32,816		32,909		107,560		108,148
Capacity Release & Storage		1,796		2,608		7,797		9,214
Other		317		414		1,050		1,383
Total Operating Revenues	$	87,715	$	89,702	$	469,802	$	390,322

Throughput (MMcf):
Firm Sales -
Residential	1,362	1,176	13,575	11,767
Commercial	819	699	5,001	4,959
Industrial	14	12	142	138
Cogeneration & Electric Generation	780	1,114	1,024	1,601
Firm Transportation -
Residential	83	422	530	5,261
Commercial	546	597	2,885	3,764
Industrial	3,787	4,057	10,416	12,108
Cogeneration & Electric Generation	227	228	239	324
Total Firm Throughput	7,618	8,305	33,812	39,922
Interruptible	6	16	70	95
Interruptible Transportation	746	523	2,530	2,119
Off-System	3,961	3,463	12,597	13,593
Capacity Release & Storage	19,977	25,512	51,172	64,016
Total Throughput	32,308	37,819	100,181	119,745

SJG - 25

Cost of Sales - Cost of sales decreased $2.1 million and increased $83.1 million for the three and nine months periods ended September 30, 2006, respectively, compared with the same periods in 2005. The increase for the nine months ended September 30, 2006, resulted from growth in our total customer base, the impact of the migration of customers from transportation service back to sales service and increased gas costs now being recovered through rates.

Cost of sales for the third quarter of 2006 was slightly lower than the same period last year. Overall, cost of sales related to residential and commercial customers was higher because of the three positive factors noted above. However, as sales to an electric generation customer were substantially lower than last year, cost of sales related to this customer was also much lower. As sales volumes are at their lowest point during the third quarter, the offset in electric generation resulted in an overall decrease in cost of sales.

Changes in the unit cost of gas sold to utility ratepayers do not always directly affect cost of sales. We defer fluctuations in gas costs to ratepayers not reflected in current rates to future periods under a BPU-approved Basic Gas Supply Service (BGSS) price structure. As a result of the two BGSS rate increases in 2005, discussed under Operating Revenues, we were able to recover and recognize some of the increase in gas costs experienced during the later part of 2005 and the first quarter of 2006.

Gas supply sources include contract and open-market purchases. We secure and maintain our own gas supplies to serve our sales customers. We do not anticipate any difficulty renewing or replacing expiring contracts under acceptable terms and conditions.

Operating Expenses - A summary of changes in other operating expenses for the three and nine months ended September 30 is as follows (in thousands):

		Three Months Ended September 30,			Nine Months Ended September 30,
		2006 vs. 2005			2006 vs. 2005
Operations	$	614		$	(2,263	)
Maintenance		(2	)		(236	)
Depreciation		404			1,215
Energy and Other Taxes		(244	)		(1,130	)

Operations expense increased $0.6 million during the third quarter of 2006 compared with the same period last year. Generally, we experience a significant decrease in our reserve for uncollectible accounts during the third quarter as customer accounts receivable are at their lowest point following the summer season. This decrease in the reserve results in a corresponding reduction in expense during the period, which totaled $0.8 million in the third quarter of 2005. However, as a result of the unusually warm 2005-2006 winter season, customer balances were reaching their low points earlier during 2006. Consequently, the corresponding benefit of a reserve reduction was also experienced earlier in 2006.

This increase to operations expense was offset primarily by a decrease in regulatory expense of $0.2 million due to previously deferred expenses related to our 2004 base rate proceeding before the BPU that had been fully amortized as of the end of 2005, and one-time consulting expenses incurred during the third quarter of 2005.

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Operations expense decreased $2.3 million during the nine months ended September 30, 2006, compared with the same period in 2005, primarily as a result of three factors. First, there was a $1.2 million decrease for the nine-month period ended September 30, 2006, in our costs under the New Jersey Clean Energy Programs (NJCEP). Such costs are recovered on a dollar-for-dollar basis; therefore, SJG experienced offsetting decreases in revenues during the periods. The BPU-approved NJCEP allows for full recovery of costs, including carrying costs when applicable. As a result, the decrease in expense had no impact on our net income. Second, our regulatory expenses decreased $0.5 million in the first nine months of 2006 primarily as a result of amortization of previously deferred expenses related to our 2004 base rate proceeding with the BPU. Such costs were fully amortized as of December 31, 2005. Finally, we also experienced lower pension costs during 2006 as detailed in Note 8 to the financial statements. Such reductions were the result of earnings on additional contributions to the plans, the transfer of employees to SJI Services, LLC effective January 1, 2006, and savings resulting from the early retirement plan offered in 2004 and 2005.

Depreciation expense increased for the three and nine months ended September 30, 2006, compared with the same periods last year due mainly to our continuing investment in utility plant.

Energy and Other Taxes decreased for the three and nine-month periods ended September 30, 2006, compared with the same periods in 2005, primarily due to lower energy-related taxes based on the decreased sales volumes in 2006. This was partially offset by a slight increase in SJG’s revenue-based taxes resulting from higher revenues, as discussed in detail under Operating Revenues.

Other Income and Expense - Other income and expense was higher for the three and nine-month periods ended September 30, 2006, compared to the same periods last year, primarily due to interest earned on our restricted investments placed in escrow in April 2006 (See Note 5 - Restricted Investments).

Interest Charges - Interest charges increased by $1.0 million and $2.7 million during the three and nine months ended September 30, 2006, respectively, compared with the same periods in 2005, due primarily to higher levels of short-term debt and higher interest rates on short-term debt. Short-term debt levels rose to support our capital expenditures that have not yet been financed with long-term debt, gas costs not yet collected from customers for gas previously consumed, and higher gas costs incurred during the 2006 summer injection period. A steep rise in short-term interest rates was driven by a series of interest rate hikes enacted by the Federal Reserve Bank over the periods covered by this report. 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.

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.

Liquidity needs are first met with net cash provided by operating activities. Net cash provided by operating activities totaled $34.1 million and $66.4 million for the nine months ended September 30, 2006 and 2005, respectively. Net cash provided by operating activities varies from year-to-year primarily due to the impact of weather on customer demand and related gas purchases, inventory utilization and gas cost recovery. Net cash provided by operating activities for the first nine months of 2006 was heavily impacted by high gas costs incurred in 2005 and 2006. Lower natural gas consumption levels due to warm weather and customer conservation experienced since the fourth quarter of 2005 further reduced recoveries of such gas costs. These conditions have resulted in an under-recovery of gas costs from consumers. Higher customer rates were put into place in mid-December 2005 in an effort to enable us to fully collect gas costs by October 2006. However, the lower customer utilization rate has slowed the collection of those costs that totaled $9.4 million at September 30, 2006, which excludes the impact of hedge accounting (See Note 1 to the financial statements). Higher gas costs than last year also increased inventory levels for 2006. Also, accounts payable are significantly reduced from last year as we are paying for gas as it is received. Some gas purchases last year contained terms that did not require payment until the first quarter of 2006.

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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. Our operations are also subject to seasonal fluctuations. Significant changes in the balances of Current Assets and Current Liabilities can occur from the end of one reporting period to another, as evidenced by the changes on the balance sheets.

Bank credit available to us totaled $151.0 million at September 30, 2006, of which $104.1 million was used. Those bank facilities consist of a $100.0 million revolving credit facility and $51.0 million of uncommitted bank lines. On August 3, 2006, we replaced the existing revolving credit with a new $100.0 million revolver that expires August 2011. The revolving credit facility contains one financial covenant that limits our total debt to total capitalization ratio to no more than 65%, measured on a quarterly basis. We were in compliance with this covenant as of September 30, 2006. Based upon the existing credit facilities and a regular dialogue with our banks, we believe that there will continue to be sufficient credit available to meet our business’ future liquidity needs. The increase in our bank credit used of $17.1 million during the first nine months of 2006 was the result of under-recovery of gas costs that have not yet been collected under the BGSS as well as capital expenditures only partially financed with long-term debt. Such cash outflows were partially offset by overcollections from our customers enrolled in our budget billing program. Such overcollections totaled $28.3 million and $2.8 million as of September 30, 2006 and December 31, 2005, respectively, and are included on the Balance Sheets in Customer Deposits and Credit Balances.

We supplement our operating cash flow and credit lines with both debt and equity capital. Over the years, we have 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 2005, we established a new $150.0 million MTN program. On April 20, 2006, we issued $25.0 million of secured tax-exempt, auction-rate debt through the New Jersey Economic Development Authority. The auction rate, which resets weekly, was 3.40% as of September 30, 2006. In anticipation of this transaction, we previously entered into forward-starting interest rate swap agreements that effectively fixed the interest rate on this debt at 3.43%, commencing December 1, 2006 through January 2036. The debt was issued under our medium-term note program. An additional $115.0 million of MTN’s remains available for issuance under that program.

SJI contributed $30.0 million of capital to SJG during 2005. There were no capital contributions during the first nine months of 2006. Contributions of capital are credited to Other Paid-in Capital and Premium on Common Stock.

Our capital structure was as follows:

	As of		As of
	September 30,		December 31,
	2006		2005
Common Equity		46.8%		49.0%
Long-Term Debt		39.4%		38.7%
Short-Term Debt		13.8%		12.4%
Total		100.0%		100.0%

Our long-term, senior secured debt is rated “A” and “Baa1” by Standard & Poor’s and Moody’s Investor Services, respectively. These ratings have not changed in the past five years.

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 $353.7 million at September 30, 2006.

SJG - 28

CAPITAL EXPENDITURES, COMMITMENTS AND CONTINGENCIES:

Commitments and Contingencies - We have certain commitments for both pipeline capacity and gas supply for which we pay fees regardless of usage. Those commitments as of September 30, 2006, average $47.5 million annually and total $251.6 million over the contracts’ lives. Approximately 53% of the financial commitment under these contracts expires 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 costs 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 September 30, 2006 (in thousands):

			Up to		Years		Years		More than
Contractual Cash Obligations	Total		1 Year		2 & 3		4 & 5		5 Years
Long-Term Debt	$	297,173	$	2,270	$	-	$	35,000	$	259,903
Interest on Long-Term Debt		238,357		17,191		34,003		33,697		153,466
Operating Leases		232		124		89		19		-
Construction Obligations		304		304		-		-		-
Commodity Supply Purchase Obligations		218,740		49,829		82,215		26,785		59,911
New Jersey Clean Energy Program		15,557		5,807		9,750		-		-
Other Purchase Obligations		9,695		4,453		3,053		2,064		125
Total Contractual Cash Obligations	$	780,058	$	79,978	$	129,110	$	97,565	$	473,405

Expected environmental remediation costs and asset retirement obligations are not included in the table above due to the subjective nature of these costs and timing of anticipated payments. As a result, the total obligation cannot be calculated. Additionally, future pension contributions are not included in the table as contributions vary from year-to-year based on investment performance and discount rates. Our regulatory obligation to contribute to our postretirement benefit plans’ trust, as discussed in Note 8, is also not included as its duration is indefinite.

Capital and Remediation Expenditures - 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 the nine months ended September 30, 2006 amounted to $47.3 million and $5.5 million, respectively. We estimate net cash outflows for construction and remediation projects for 2006, 2007 and 2008, to be approximately $57.1 million, $43.8 million and $44.2 million, respectively. Included in the 2006 estimate is $8.9 million in capital costs accrued but not paid as of December 31, 2005, primarily related to two large special projects totaling $12.1 million for pipeline installation.

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.

SJG - 29

Ratio of Earnings to Fixed Charges - Our ratio of earnings to fixed charges for each of the periods indicated is as follows:

Twelve Months Ended September 30,	Year Ended December 31,
2006	2005	2004	2003	2002	2001
3.6x	4.0x	3.9x	3.3x	2.9x	2.6x

The ratio of earnings to fixed charges represents, on a pre-tax basis, the number of times earnings covers fixed charges. Earnings consist of net income, to which has been added fixed charges and taxes based on income before discontinued operations. Fixed charges consist of interest charges and preferred securities dividend requirements and an interest factor in rentals.

Item 3. Quantitative and Qualitative Disclosures about Market Risks

MARKET RISKS:

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

We transact commodities on a physical 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. 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 September 30, 2006 is as follows (in thousands):

Assets			Maturity		Maturity
	Source of Fair Value			<1 Year		1 - 3 Years		Total
Prices Actively Quoted		NYMEX	$	10,508	$	25	$	10,533
Other External Sources		Basis		878		-		878
Total			$	11,386	$	25	$	11,411
Liabilities				Maturity		Maturity
	Source of Fair Value			<1 Year		1 - 3 Years		Total
Prices Actively Quoted		NYMEX	$	23,671	$	1,195	$	24,956
Other External Sources		Basis		431		-		431
Total			$	24,192	$	1,195	$	25,387

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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 2.6million decatherms with a weighted average settlement price of $8.72 per decatherm.

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 Asset, January 1, 2006	$	486
Contracts Settled During The Nine Months Ended September 30, 2006, Net		20,235
Other Changes in Fair Value from Continuing and New Contracts, Net		(34,697	)
Net Derivatives — Energy Related Liability, September 30, 2006	$	(13,976	)

The change in our derivative position from a $0.5 million asset at December 31, 2005 to a $14.0 million liability at September 30, 2006 is primarily due to the change in value of our financial positions held with SJRG.  As of December 31, 2005 the average future price was approximately $10.80 per decatherm vs. $6.90 per decatherm as of September 30, 2006.  The decrease in prices has resulted in a significant decline in the value of these financial contracts.  However, the purchase price of a portion of our future gas purchases is fixed, regardless of future fluctuations in the market price.

Interest Rate Risk - Our exposure to interest rate risk relates primarily to short-term, variable-rate borrowings. Short-term, variable-rate debt outstanding at September 30, 2006 was $104.1 million and averaged $82.5 million during the first nine months of 2006. A hypothetical 100 basis point (1%) increase in interest rates on our average variable-rate debt outstanding would result in a $487,000 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: 2005 - 191 b.p. increase; 2004 - 115 b.p. increase; 2003 - 31 b.p. decrease; 2002 - 74 b.p. decrease; and 2001 - 383 b.p. decrease. For September 2006, our weighted-average borrowing cost, which changes daily, was 5.71%.

We issue long-term debt either at fixed rates or use interest rate derivatives to fix interest rates on variable-rate, long-term debt. Consequently, interest expense on existing long-term debt is not significantly impacted by changes in market interest rates.

Item 4. Controls and Procedures

Management has established controls and procedures to ensure that material information relating to SJG is made known to the officers who certify its financial reports and to other members of senior management and the Board of Directors.

Based upon their evaluation as of the end of the period of this report, the principal executive officer and the principal financial officer of SJG have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) employed at SJG are effective to ensure that the information required to be disclosed by SJG in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

No change in SJG’s internal control over financial reporting occurred during SJG’s third fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

SJG - 31

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

Information required by this Item is incorporated by reference to Part I, Item 1, Note 9, beginning on page 19.

Item 1A. Risk Factors

None

SJG - 32

Item 6. Exhibits

(a) Exhibits
Exhibit No.	Description
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) of the Exchange Act.
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) of the Exchange Act.
32.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14(b) of the Exchange Act as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
32.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14(b) of the Exchange Act as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

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SIGNATURES

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

SOUTH JERSEY GAS COMPANY

(Registrant)

Dated: November 9, 2006	By:         /s/ Edward J. Graham
	Edward J. Graham
	President & Chief Executive Officer
Dated: November 9, 2006	By:         /s/ David A. Kindlick
	David A. Kindlick
	Senior Vice President & Chief Financial Officer

SJG - 34

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Edward J. Graham, certify that:

1. I have reviewed this report on Form 10-Q for the period ended September 30, 2006, of South Jersey Gas Company;

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

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

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

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

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

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

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

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

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

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

Date: November 9, 2006	/s/ Edward J. Graham
	Edward J. Graham
	President & Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, David A. Kindlick, certify that:

1. I have reviewed this report on Form 10-Q for the period ended September 30, 2006, of South Jersey Gas Company;

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

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

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

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

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

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

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

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

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

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

	SOUTH JERSEY GAS COMPANY
Date: November 9, 2006	By:	/s/ David A. Kindlick
		David A. Kindlick
		Executive Vice President & Chief Financial Officer

EX-32.1

Exhibit 32.1

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

AS ADOPTED PURSUANT TO SECTION 906 OF

THE SARBANES-OXLEY ACT OF 2002

In connection with the filing of the Quarterly Report on Form 10-Q of South Jersey Gas Company (the “Company”) for the period ended September 30, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Edward J. Graham, Chief Executive Officer of the Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

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

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

/s/ Edward J. Graham

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Name: Edward J. Graham

Title: Chief Executive Officer

November 9, 2006

EX-32.2

Exhibit 32.2

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

AS ADOPTED PURSUANT TO SECTION 906 OF

THE SARBANES-OXLEY ACT OF 2002

In connection with the filing of the Quarterly Report on Form 10-Q of South Jersey Gas Company (the “Company”) for the period ended September 30, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David A. Kindlick, Chief Financial Officer of the Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

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

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

/s/ David A. Kindlick

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Name: David A. Kindlick

Title: Chief Financial Officer

November 9, 2006