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 March 31, 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 May 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.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements — See Pages 3 through 21

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SOUTH JERSEY GAS COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
(In Thousands)
	Three Months Ended
		March 31,
		2006			2005
Operating Revenues	$	277,081		$	214,537
Operating Expenses:
Cost of Sales		208,621			144,345
Operations		13,831			15,289
Maintenance		1,405			1,493
Depreciation		5,758			5,358
Energy and Other Taxes		4,286			4,893
Total Operating Expenses		233,901			171,378
Operating Income		43,180			43,159
Other Income and Expense		(20	)		(30	)
Interest Charges		(5,152	)		(4,440	)
Income Before Income Taxes		38,008			38,689
Income Taxes		(15,530	)		(16,125	)
Net Income	$	22,478		$	22,564
The accompanying notes are an integral part of the condensed financial statements.

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SOUTH JERSEY GAS COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(In Thousands)
		Three Months Ended
		March 31,
		2006		2005
Net Income	$	22,478	$	22,564
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Investments		557		(44	)
Change in Fair Value of Derivatives		157		(103	)
Other Comprehensive Income (Loss) - Net of Tax		714		(147	)
Comprehensive Income	$	23,192	$	22,417
The accompanying notes are an integral part of the condensed financial statements.

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SOUTH JERSEY GAS COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In Thousands)
		Three Months Ended
		March 31,
		2006			2005
Cash Flows from Operating Activities:
Net Income	$	22,478		$	22,564
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation and Amortization		6,329			6,069
Provision for Losses on Accounts Receivable		1,056			1,212
Revenues and Fuel Costs Deferred - Net		15,606			442
Deferred and Noncurrent Income Taxes and Credits - Net		977			4,197
Environmental Remediation Costs - Net		(956	)		(363	)
Gas Plant Cost of Removal		(304	)		(165	)
Changes in:
Accounts Receivable		(38,070	)		(40,223	)
Inventories		44,426			58,888
Other Prepayments and Current Assets		329			(388	)
Prepaid and Accrued Taxes - Net		21,765			20,984
Accounts Payable and Other Accrued Liabilities		(40,769	)		3,327
Other Assets		2,473			3,371
Other Liabilities		(295	)		(1,132	)
Net Cash Provided by Operating Activities		35,045			78,783
Cash Flows from Investing Activities:
Capital Expenditures		(17,409	)		(14,135	)
Net Cash Used in Investing Activities		(17,409	)		(14,135	)
Cash Flows from Financing Activities:
Net Repayments of Lines of Credit		(12,200	)		(43,000	)
Principal Repayments of Long-Term Debt		(15	)		(10,500	)
Payments for Issuance of Long-Term Debt		(88	)		(51	)
Premium for Early Retirement of Debt		-			(184	)
Net Cash Used in Financing Activities		(12,303	)		(53,735	)
Net Increase in Cash and Cash Equivalents		5,333			10,913
Cash and Cash Equivalents at Beginning of Period		2,551			3,310
Cash and Cash Equivalents at End of Period	$	7,884		$	14,223
The accompanying notes are an integral part of the condensed financial statements.

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SOUTH JERSEY GAS COMPANY
CONDENSED BALANCE SHEETS
(In Thousands)
		(Unaudited)
		March 31,			December 31,
		2006			2005
Assets
Property, Plant and Equipment:
Utility Plant, at original cost	$	1,042,046		$	1,030,029
Accumulated Depreciation		(245,811	)		(241,242	)
Property, Plant and Equipment - Net		796,235			788,787
Investments:
Available-for-Sale Securities		5,893			5,628
Current Assets:
Cash and Cash Equivalents		7,884			2,551
Accounts Receivable		95,452			42,407
Unbilled Revenues		38,171			53,648
Provision for Uncollectibles		(4,015	)		(3,461	)
Natural Gas in Storage, average cost		45,981			89,957
Materials and Supplies, average cost		3,416			3,866
Prepaid Taxes		1,416			12,972
Derivatives - Energy Related Assets		2,621			6,496
Other Prepayments and Current Assets		2,528			2,858
Total Current Assets		193,454			211,294
Regulatory Assets:
Environmental Remediation Costs:
Expended - Net		10,305			9,350
Liability for Future Expenditures		54,189			56,717
Gross Receipts and Franchise Taxes		370			480
Income Taxes - Flowthrough Depreciation		5,419			5,663
Deferred Asset Retirement Obligation Costs		20,255			19,986
Deferred Fuel Costs - Net		17,958			21,237
Deferred Postretirement Benefit Costs		2,551			2,646
Societal Benefit Costs		2,160			2,691
Premium for Early Retirment of Debt		1,654			1,694
Other Regulatory Assets		1,003			1,019
Total Regulatory Assets		115,864			121,483
Other Noncurrent Assets:
Unamortized Debt Issuance Costs		6,228			6,251
Prepaid Pension		24,048			26,202
Accounts Receivable - Merchandise		6,325			6,472
Derivatives - Energy Related Assets		39			271
Derivatives - Other		624			-
Other		1,711			1,765
Total Other Noncurrent Assets		38,975			40,961
Total Assets	$	1,150,421		$	1,168,153
The accompanying notes are an integral part of the condensed financial statements.

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SOUTH JERSEY GAS COMPANY
CONDENSED BALANCE SHEETS
(In Thousands, except per share amounts)
		(Unaudited)
		March 31,			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		(3,623	)		(4,337	)
Retained Earnings		159,592			142,740
Total Common Equity		362,134			344,568
Long-Term Debt		272,220			272,235
Total Capitalization		634,354			616,803
Current Liabilities:
Notes Payable		74,800			87,000
Current Maturities of Long-Term Debt		2,273			2,273
Accounts Payable - Commodity		46,648			87,620
Accounts Payable - Other		16,891			21,452
Derivatives - Energy Related Liabilities		14,649			6,197
Deferred Income Taxes - Net		2,791			2,295
Customer Deposits		9,748			9,323
Environmental Remediation Costs		20,489			17,873
Taxes Accrued		12,371			2,162
Dividends Declared		5,626			-
Interest Accrued		4,638			6,032
Other Current Liabilities		7,362			6,045
Total Current Liabilities		218,286			248,272
Deferred Credits and Other Noncurrent Liabilities:
Deferred Income Taxes - Net		163,219			162,542
Environmental Remediation Costs		33,699			38,844
Regulatory Liabilities		55,437			54,002
Asset Retirement Obligations		22,848			22,505
Pension and Other Postretirement Benefits		15,663			16,633
Investment Tax Credits		2,714			2,795
Derivatives - Energy Related Liabilities		171			84
Derivatives - Other		-			306
Other		4,030			5,367
Total Deferred Credits and Other Noncurrent Liabilities		297,781			303,078
Commitments and Contingencies (Note 7)
Total Capitalization and Liabilities	$	1,150,421		$	1,168,153
The accompanying notes are an integral part of the condensed financial statements.

SJG - 7

NOTES TO CONDENSED 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 condensed financial statements reflect all normal and recurring adjustments needed to fairly present our financial position and operating results at the dates and for the periods presented. 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 condensed financial statements should be read in conjunction with our 2005 Form 10-K.

Equity Investments - We classify marketable equity investments purchased as long-term investments as Available-for-Sale Securities on our condensed balance sheets and carry them at their fair value. Any unrealized gains or losses are included in Accumulated Other Comprehensive Loss.

Estimates and Assumptions - We prepare our condensed financial statements to conform with accounting principles generally accepted in the United States of America. Management makes estimates and assumptions that affect the amounts reported in the condensed 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 and customers are billed monthly. For retail customers not billed at the end of each month, we record an estimate to recognize unbilled revenues for gas delivered from the date of the last meter reading to the end of the month.

The BPU allows us to recover all prudently incurred gas costs through the Basic Gas Supply Service (BGSS) clause. We collect these costs on a forecasted basis upon 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 balances 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), a Remediation Adjustment Clause (RAC), a New Jersey Clean Energy Program (NJCEP) and a Universal Service Fund (USF) program. The TAC provides stability to our earnings and our customers’ bills by normalizing the impact of extreme winter temperatures. 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. 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 do not directly affect earnings because we defer and recover related costs through rates over 7-year amortization periods. NJCEP and USF adjustments are also deferred and do not affect earnings, as related costs and customer credits are recovered through rates on an ongoing basis.

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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. 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 condensed balance sheets. Interest Charges are presented net of capitalized interest on the condensed statements of income. SJG capitalized interest of $0.1 million and $0.3 million for the three months ended March 31, 2006 and 2005, respectively.

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 three months ended March 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 as hedging relationships or not, on the condensed 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. However, due to the application of regulatory accounting principles under FASB Statement No. 71, derivatives related to gas purchases are recorded through our BGSS rather than Other Comprehensive Income (Loss). We recognize ineffective portions of changes in the fair value of cash flow hedges immediately in earnings.

As part of our gas purchasing strategy, we occasionally use financial contracts to hedge against forward price risk. The costs or benefits of these short-term contracts are included in our BGSS, subject to BPU approval. As of March 31, 2006 and December 31, 2005 we had $12.2 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 with respect to our variable-rate debt. On October 21, 2005, we entered into two long-term forward-starting interest rate swaps which effectively fixed the interest rate at 3.43% for 30 years on $25 million of variable-rate, tax-exempt debt which was issued in April 2006. We have designated and account for these interest rate derivatives as cash flow hedges. When the debt is issued, 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.

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As of March 31, 2006, the market value of these agreements was $0.6 million and is included on the condensed balance sheet under the caption Other Noncurrent Assets - Derivatives - Other. The recorded balance as of March 31, 2006 represents the amount we would have received from the counterparty 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 condensed 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 counterparty if the contracts had been terminated on that date. As of March 31, 2006 and December 31, 2005, we calculated the swaps to be highly effective; therefore, we recorded the change in fair value of the swaps along with the cumulative unamortized costs 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.

New Accounting Pronouncements - 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 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 March 31, 2006 and the assumptions used to estimate the fair value of the awards (adjusted for the June 2005 two-for-one stock split):

Grant	Shares	Fair Value	Expected	Risk-Free
Date	Granted	Per Share	Volatility	Interest Rate
Jan. 2004	11,470	$                20.105	16.4%	2.4%
Jan. 2005	10,422	$                25.155	15.5%	3.4%
Jan. 2006	10,991	$                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.

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    The cost of the officers’ restricted stock awards was $0.1 million and $0.3 million for the three months ended March 31, 2006 and 2005, respectively. Of those costs, $20,000 and $89,000 were capitalized to Utility Plant for the three months ended March 31, 2006 and 2005, respectively.

    As of March 31, 2006, there was $0.4 million of total unrecognized compensation cost related to nonvested share-based compensation awards granted under the restricted stock plans. That cost is expected to be recognized over a weighted average period of 2.2 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.

    In the first quarter of 2006, the adoption of Statement No. 123(R) resulted in a reduction in stock-based compensation expense of $19,200, or $11,300 after taxes. This decrease in expense would have had no impact on SJG’s cash flows for the quarter.

    The following table summarizes information regarding restricted stock award activity during the three months ended March 31, 2006:

	Officers *
Nonvested Shares Outstanding, January 1, 2006		49,816
Granted		10,991
Vested**		(27,924	)
Cancelled/Forfeited		-
Nonvested Shares Outstanding, March 31, 2006		32,883
*   excludes accrued dividend equivalents
** actual shares awarded upon vesting, including dividend equivalents and adjustments for
performance measures, totaled 44,575 shares.

    During the three months ended March 31, 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 three months ended March 31, 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 three months ended March 31, 2006 and 2005 were approximately $2.1 million and $1.6 million, respectively. Additionally, a change in control could result in the nonvested shares becoming nonforefeitable or immediately payable in cash.

    In November 2004, the FASB issued Statement No. 151, “Inventory Costs.” This statement requires that abnormal amounts of idle facility expense, freight, handling costs and spoilage be charged to income as a current period expense rather than capitalized as inventory costs. The effective date of this statement was January 1, 2006. The adoption of this statement had no effect on our condensed financial statements.

Regulatory Assets & Liabilities - All significant regulatory assets are separately identified on the condensed balance sheets. Each item that is separately identified is being 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 :

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	Years Remaining
Regulatory Asset	As of March 31, 2006
Environmental Remediation Costs:
Expended - Net		Various
Liability for Future Expenditures		Not Applicable
Gross Receipts and Franchise Taxes		1
Income Taxes - Flowthrough Depreciation		5
Deferred Asset Retirement Obligation Costs		Not Applicable
Deferred Fuel Costs - Net		Various
Deferred Postretirement Benefit Costs		7
Societal Benefit Costs		Various
Premium for Early Retirement of Debt		Various

Some of the assets reflected under 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 March 31, 2006, costs related to derivative contracts increased Deferred Fuel Costs - Net by $12.2 million. As of December 31, 2005, benefits related to derivative contracts reduced Deferred Fuel Costs - Net by $0.5 million.

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

	March 31, 2006		December 31, 2005
Excess Plant Removal Costs	$	48,260	$	48,071
Overcollected State Taxes		4,073		4,025
Other		3,104		1,906
Total Regulatory Liabilities	$	55,437	$	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. 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.

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

2. REGULATORY ACTIONS:

Base Rates - On July 7, 2004, the BPU granted us a base rate increase of $20.0 million, which was predicated in part upon a 7.97% rate of return on rate base that included a 10.0% return on common equity. The increase was effective July 8, 2004 and designed to provide an incremental $8.5 million on an annualized basis to net income. We were also permitted recovery of regulatory assets contained in our petition and a reduction in our composite depreciation rate from 2.9% to 2.4%.

Pending Audits - 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 recommendations contained in these audits have no material effect on our financial statements.

Other Regulatory Matters - In September 2004, we filed for a $2.6 million reduction to our annual Societal Benefits Clause (SBC) recovery level. The SBC recovers costs related to BPU-mandated programs, including environmental remediation costs that are recovered through the RAC; energy efficiency and renewable energy program costs that are recovered through the NJCEP; consumer education program costs; and low income program costs that are recovered through the USF. This matter was resolved as part of the global settlement (See “global settlement” discussion that follows), which was approved by the BPU in March 2006.

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 7.

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.

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In October 2005, we, along with the three other natural gas distribution companies in New Jersey, filed a petition with the BPU to implement a Pipeline Integrity Management Tracker (Tracker). 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. 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.

Also, 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. We requested a $103.2 million increase. In December 2005, the BPU approved an $85.7 million increase to our rates, effective December 15, 2005.

In November 2005, we made our annual TAC filing, requesting a $1.0 million increase in annual revenues. The increase will recover the cash related to the net TAC deficiency resulting from warmer-than-normal weather for the 2003-2004 winter, partially offset by colder-than-normal weather for the 2004-2005 winter. The 2003-2004 TAC was resolved as part of the global settlement, which was approved by the BPU in March 2006.

In December 2005, we made a filing proposing to implement a Conservation and Usage Adjustment (CUA) Clause, on a 5-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. The proposed CUA would replace our existing TAC, but would continue to protect customers and the Company from significant variations in degree days.

In March 2006, the BPU approved a global settlement, effective April 1, 2006, fully resolving our September 2004 SBC filing, 2003-2004 TAC, 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 storage incentive program was approved. This program will be implemented as a pilot for three summer injection periods, beginning in 2006, and 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 the Company, and 80% being credited to customers.

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

3.RELATED PARTY TRANSACTIONS:

We conducted business with our parent, SJI, and several of SJI’s other wholly owned subsidiaries. A description of each of these affiliates is as follows:

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     · SJI Services, LLC (SJIS) - established on January 1, 2006, SJIS 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) - serves as a holding company for all of SJI’s nonutility businesses.

·  South Jersey Energy Company (SJE) - a third party energy marketer supplying natural gas to customers within our territory.

·  South Jersey Resources Group (SJRG) - a wholesale gas and risk management business that supplies natural gas to retail marketers, utility 

           businesses and electricity generators in the mid-Atlantic and southern regions.

·  Marina Energy LLC (Marina) - an owner and operator of energy production facilities for the commercial and industrial markets.

·  South Jersey Energy Service Plus (SJESP) - an appliance service and installation company.

We sold natural gas for resale to both SJE and SJRG. These sales comply with Section 284.02 of the Regulations of the Federal Energy Regulatory Commission (FERC). Additionally, we met some of our gas purchasing requirements by purchasing natural gas for resale from SJRG. For SJE and SJESP, we also provided billing services. For SJE’s residential customers, for which we performed billing services, we purchased the related accounts receivable at book value less a factor for potential uncollectible accounts and assumed all risk associated with the collection of such amounts. Finally, we provided natural gas transportation services to Marina under BPU-approved utility tariffs.

In addition to the above, we provided various administrative and professional services for SJI, SJE, SJRG, SJESP and Marina. These services included administrative support, information system and data management support, and office space rental. Likewise, SJI provided substantial administrative services on our behalf including such items as public and governmental relations, cash management and consulting services. 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.

A summary of these related party transactions were as follows as of March 31 (in thousands):

	2006		2005
Sales and Services Provided to:
SJI	$	547	$	567
SJE		56		205
SJIS		91		-
SJRG		7,507		2,319
Marina		74		140
SJESP		124		133
Sales and Services Received from:
SJRG	$	18,435	$	1,626
SJI		3,326		2,527
SJIS		1,458		-

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     Amounts due to related parties are included in Accounts Payable and amounts due from related parties are included in Accounts Receivable on the condensed balance sheets. As of March 31, 2006 and December 31, 2005, these related party balances were as follows (in thousands):

	March 31, 2006		December 31, 2005
Amounts due to:
SJI	$	2,547	$	699
SJE		1,273		1,270
SJESP		1,085		993
SJRG		3,600		2,293
SJIS		604		-
Amounts due from:
SJI	$	34	$	507
SJE		9		32
SJRG		2,513		-
Marina		7		25
SJESP		22		69
SJIS		29		-

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 condensed financial statements as a whole and are not included in the amounts disclosed above.

Lastly we purchased meter reading services from 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. Fees incurred by us related to such services were $672,000 and $629,000 for the three month period ending March 31, 2006 and 2005, respectively. Amounts due, included in Accounts Payable on the balance sheets, were $226,000 and $220,000 as of March 31, 2006 and December 31, 2005, respectively.

4.UNUSED LINES OF CREDIT AND COMPENSATING BALANCES:

Bank credit available to us totaled $176.0 million at March 31, 2006, of which $74.8 million was used. Those bank facilities consist of a $100.0 million credit facility that expires in August 2006, and $76.0 million of uncommitted bank lines. We are presently working with all of our banks to extend the existing revolving credit facilities through 2011. The revolving credit facilities contain certain financial covenants measured on a quarterly basis. We were in compliance with these covenants as of March 31, 2006. Borrowings under these lines of credit are at market rates. The weighted-average borrowing cost, which changes daily, was 5.42% and 3.03% at March 31, 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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5. 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 $362.1 million at March 31, 2006.

Restrictions also exist under various loan agreements regarding the amount of cash dividends or other distributions that we may pay on our common stock. As of March 31, 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 was no equity infusion during the first quarter 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.

6.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 a 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 $2.6 million at March 31, 2006 is recoverable in rates. We are amortizing this amount over 15 years, which started January 1998.

Net periodic benefit cost for the three months ended March 31, 2006 and 2005 related to the employee and officer pension and other postretirement benefit plans consisted of the following components (in thousands):

							Other
	Pension Benefits						Postretirement Benefits
		2006			2005			2006			2005
Service Cost	$	678		$	720		$	129		$	347
Interest Cost		1,416			1,488			307			597
Expected Return on Plan Assets		(1,795	)		1,679			(228	)		(347	)
Amortization of Loss and Other		629			574			20			33
Net Periodic
Benefit Cost		928			1,103			228			630
Capitalized Benefit Costs		(399	)		(386	)		(98	)		(221	)
Net Periodic Benefit Expense	$	529		$	717		$	130		$	409

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

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

			Other
	Pension Benefits		Postretirement Benefits
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 expect to make no contributions to our pension plan in 2006; however, changes in future investment performance and discount rates may ultimately result in a contribution. 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.

7.COMMITMENTS AND CONTINGENCIES:

The following table summarizes our contractual cash obligations and their applicable payment due dates as of March 31, 2006 (in thousands):

			Up to		Years		Years		More than
Contractual Cash Obligations	Total		1 Year		2 & 3		4 & 5		5 Years
Long-Term Debt	$	274,493	$	2,273	$	2,270	$	10,000	$	259,950
Interest on Long-Term Debt		220,660		16,426		32,380		32,287		139,567
Operating Leases		386		181		174		31		-
Construction Obligations		104,388		34,560		69,828		-		-
Commodity Supply Purchase Obligations		236,348		34,772		83,795		46,901		70,880
New Jersey Clean Energy Program		18,383		5,133		13,250		-		-
Other Purchase Obligations		18,676		9,693		8,083		900		-
Total Contractual
Cash Obligations	$	873,334	$	103,038	$	209,780	$	90,119	$	470,397

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. As discussed in Note 6, we currently do not expect to make a pension contribution in 2006; however, changes in future investment performance and discount rates may ultimately result in a contribution. Furthermore, future pension contributions beyond 2006 cannot be determined at this time. Our regulatory obligation to contribute approximately $3.6 million annually to our postretirement benefit plans’ trusts, less costs incurred directly by us, is not included as the duration is indefinite.

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Gas Supply Contracts - In the normal course of conducting business, we have entered into long-term contracts for natural gas supplies, firm transportation and gas storage service. The earliest that any of these contracts expires is October 2007. The transportation and storage service agreements between us and our interstate pipeline suppliers 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.

Environmental Remediation Costs - We incurred and recorded costs for environmental cleanup of 12 sites where we or our predecessors operated manufactured gas 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 $7.9 million through March 31, 2006.

Since the early 1980s, we accrued environmental remediation costs of $154.0 million, of which $99.8 million has been spent as of March 31, 2006. With the assistance of consulting firms, we estimate that undiscounted future costs to clean up our sites will range from $54.2 million to $203.0 million. Four of our sites comprise a significant portion of these estimates, ranging from a low of $32.8 million and a high of $124.4 million. We recorded the lower end of this range, $54.2 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. 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.

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

	Three Months Ended March 31, 2006			Year Ended December 31, 2005
Beginning Balance	$	56,717		$	51,046
Accruals and Adjustments		(76	)		11,710
Expenditures		(1,979	)		(6,039	)
Insurance Recoveries		(473	)		-
Ending Balance	$	54,189		$	56,717

The balances are segregated between current and non-current on the condensed 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 gaining regulatory and property owner approval of the selected remedy.

Site 4 - The NJDEP has approved the selected remedy to address impacted soil and groundwater at this site. Remaining steps to remediate include bidding, implementation, and ongoing operation and maintenance of the selected remedy.

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 condensed 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.

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As of March 31, 2006, we reflected the unamortized expended remediation costs of $10.3 million on the condensed balance sheet under Regulatory Assets. Since implementing the RAC in 1992, we have recovered $46.1 million through rates.

8.SUBSEQUENT EVENT:

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 initially set at 3.55%. Of the proceeds from the issue, $14.2 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% 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.

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

and Results of Operations (Unaudited)

Overview

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 324,964 customers at March 31, 2006, compared with 316,094 customers at March 31, 2005. We also:

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

· transport natural gas purchased directly from producers or suppliers 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; 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.

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Critical Accounting Policies

Estimates and Assumptions - As described in the notes to our condensed financial statements, management must make estimates and assumptions that affect the amounts reported in the condensed financial statements and related disclosures. Actual results could differ from those estimates. Five types of transactions presented in our condensed financial statements require a significant amount of judgment and estimation. These relate to regulatory accounting, 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 condensed financial statements.

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 $3.6 million and $(0.9) million for the three months ended March 31, 2006 and 2005, respectively. Weather during the first three months of 2006 was 17.2% warmer than the same period last year, and 12.6% warmer than the 20-year TAC average. Weather during the first three months of 2005 was 5.6% colder than the 20-year TAC average.

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

Environmental Remediation - See detailed discussion concerning Environmental Remediation in Note 7 to the condensed financial statements.

Customer Choice Legislation - All residential natural gas customers in New Jersey can choose their gas supplier under the terms of the “Electric Discount and Energy Competition Act of 1999.” As of March 31, 2006, approximately 8,900 of our residential customers chose a natural gas commodity supplier other than us. The number of such customers fell from approximately 85,200 at March 31, 2005, as marketers were unable to offer natural gas at prices competitive with those available under regulated utility tariffs during the later part of 2005 and the first quarter of 2006, due to changing market conditions. Customers purchasing natural gas from providers other than us are charged for gas costs by the marketer. While customer choice can significantly affect utility revenues and gas costs, it does not affect our earnings or financial condition (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.

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Results of Operations

Operating Revenues:

Revenues increased $62.5 million during the first quarter of 2006 compared with same period in the prior year primarily due to three factors. First, we added 8,870 customers during the 12-month period ended March 31, 2006, which represents a 2.8% increase in total customers. Second, 90% of the residential customers and 21% of the commercial customers purchasing their gas from sources other than us migrated back to utility sales service during the 12-month period ended March 31, 2006. The total number of transportation customers decreased from 87,132 at March 31, 2005, to only 10,411 at March 31, 2006, as third party marketers found it difficult to compete with our BGSS rates under current market conditions. 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 Off-System Sales and lower customer utilization rates experienced during the three months ended March 31, 2006, compared with the same period in 2005.

Total gas throughput decreased 17.6% for the first three months of 2006, compared with the same period in 2005. Such throughput dropped from 47.0 billion cubic feet (Bcf) during the first quarter of 2005 to 38.7 Bcf during the first quarter of 2006. The lower throughput was primarily due to significantly warmer weather during 2006, as previously discussed under the TAC.

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The following table is a comparison of operating revenue and throughput for the three months ended March 31:

	2006		2005
Operating Revenues (Thousands):
Firm Sales -
Residential	$	166,436	$	97,171
Commercial		51,409		35,204
Industrial		2,014		2,055
Cogeneration & Electric Generation		1,057		849
Firm Transportation -
Residential		1,362		15,486
Commercial		4,221		5,908
Industrial		3,270		3,318
Cogeneration & Electric Generation		-		45
Total Firm Revenues		229,769		160,036
Interruptible		399		415
Interruptible Transportation		634		599
Off-System		41,643		48,905
Capacity Release & Storage		4,302		4,192
Other		334		390
Total Operating Revenues	$	277,081	$	214,537
Throughput (MMcf):
Firm Sales -
Residential		9,774		8,304
Commercial		3,279		3,353
Industrial		100		100
Cogeneration & Electric Generation		29		65
Firm Transportation -
Residential		312		3,804
Commercial		1,594		2,279
Industrial		3,360		4,139
Cogeneration & Electric Generation		2		11
Total Firm Throughput		18,450		22,055
Interruptible		31		38
Interruptible Transportation		972		855
Off-System		4,118		6,663
Capacity Release & Storage		15,105		17,354
Total Throughput		38,676		46,965

Cost of Sales:

Cost of sales increased $64.3 million during the first quarter of 2006 compared with the same period in 2005 due to the increase 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. 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 2005and into 2006.

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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 months ended March 31 (in thousands):

	2006 vs. 2005
Operations	$	(1,458	)
Maintenance		(88	)
Depreciation		400
Energy and Other Taxes		(607	)

Operations expense decreased $1.5 million during the first quarter of 2006, compared with the same period in 2005, primarily due to a $1.0 million decrease in our costs under the New Jersey Clean Energy Programs (NJCEP). Such costs are recovered on a dollar-for-dollar basis; therefore, SJG experienced an offsetting decrease in revenues during the period. 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. We also experienced lower pension and other postretirement benefit costs during the quarter as detailed in Note 6 to the condensed financial statements. Such reductions were the result of earnings on additional contributions to both plans in addition to savings resulting from the early retirement plan offered in 2004 and 2005.

Depreciation expense increased for the three months ended March 31, 2006, compared with the same period last year due mainly to our continuing investment in utility plant.

Energy and Other Taxes decreased for the first three months of 2006, compared with the same period 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.

Interest Charges:

Interest charges increased by $0.7 million during the first three months of 2006, compared with the same period 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, which we had not yet financed with long-term debt. 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. The increase in interest charges associated with short-term debt was partially offset by lower levels of long-term debt outstanding during the three months ended March 31, 2006, compared with the same period in 2005.  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.

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Net Income Applicable to Common Stock:

Net income decreased $0.1 million, or 1.6%, to $22.5 million for the first three months of 2006, as compared with $22.6 million in the same period of 2005.

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 $35.0 million and $78.8 million for the three months ended March 31, 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 recoveries. Net cash provided by operating activities in the first quarter of 2006 was heavily impacted by these factors as collection of much higher fuel costs incurred during 2005 was deferred until the first quarter of 2006. On December 15, 2005, we were authorized by the BPU to increase the rate we charge customers by 24.3% for residential and 28.4% for commercial/industrial. The increase enables us to recover from our customers the higher cost of gas that has been and will be delivered to them during 2005 and 2006. However, since our rates are billed based upon volumes of gas sold and warm winter weather reduced demand for gas, gas cost recovery was slowed. Changes in Accounts Receivable, Inventories and Accounts Payable on the condensed statements of cash flows for the first quarter of 2006 reflected the impact of higher gas prices and warm weather experienced during the first quarter of 2006 compared to the same quarter in 2005. 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 condensed balance sheets. During the first quarter, gas is typically withdrawn from storage to meet heightened winter demand levels. Due to unseasonably warm weather experienced during the fourth quarter of 2005 and first quarter of 2006, withdrawals from inventory were lower than normal. Consequently, the cash flow benefit received from reducing inventory was less than expected. However, since we fill our gas storage during the second and third quarters, the high level of gas inventory maintained as of March 31, 2006 is expected to result in reduced cash outflows during the next two quarters. We also end each calendar year in a prepaid tax position due to mandatory prepayment requirements on all state taxes. Such prepayments are credited against amounts otherwise due during the first quarter of the subsequent year; further improving first quarter liquidity.

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Bank credit available to us totaled $176.0 million at March 31, 2006, of which $74.8 million was used. Those bank facilities consist of a $100.0 million revolving credit facility that expires in August 2006, and $76.0 million of uncommitted bank lines. We are presently working with our banks to extend the revolving credit through 2011. We anticipate the extended agreement to be in place during the second quarter of 2006. The revolving credit facilities contain certain financial covenants measured on a quarterly basis. We were in compliance with these covenants as of March 31, 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.

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 and issued a $10.0 million note under the program at a rate of 5.45%, maturing in 2035. The proceeds of the 2005 note issue were used to refinance a $10.0 million, 7.9% note issued under a previous MTN program that was called for redemption in July 2005.

On April 20, 2006, SJG 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 initially set at 3.55%. 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% through January 2036. The debt was issued under our medium-term note program. An additional $115.0 million on medium-term notes 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 quarter 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 March 31,			As of       December 31,
		2006			2005
Common Equity		51	%		53	%
Long-Term Debt		39	%		45	%
Short-Term Debt		10	%		2	%
Total		100	%		100	%

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.

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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 $362.1 million at March 31, 2006.

Capital Expenditures, Commitments and Contingencies

Capital 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 three months ended March 31, 2006 amounted to $17.4 million and $1.0 million, respectively. We estimate net cash outflows for construction and remediation projects for 2006, 2007 and 2008, to be approximately $50.7 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.

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 March 31, 2006, average $46.6 million annually and total $236.3 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 March 31, 2006 (in thousands):

			Up to		Years		Years		More than
Contractual Cash Obligations	Total		1 Year		2 & 3		3 & 5		5 Years
Long-Term Debt	$	274,493	$	2,273	$	2,270	$	10,000	$	259,950
Interest on Long-Term Debt		220,660		16,426		32,380		32,287		139,567
Operating Leases		386		181		174		31		-
Construction Obligations		104,388		34,560		69,828		-		-
Commodity Supply
Purchase Obligations		236,348		34,772		83,795		46,901		70,880
New Jersey Clean Energy Program
Funding		18,383		5,133		13,250		-		-
Other Purchase Obligations		18,676		9,693		8,083		900		-
Total Contractual Cash Obligations	$	873,334	$	103,038	$	209,780	$	90,119	$	470,397

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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 these costs and timing of anticipated payments. As a result, the total obligation cannot be calculated. As discussed in Note 6 to the condensed financial statements, we currently do not expect to make a pension contribution in 2006; however, changes in future investment performance and discount rates may ultimately result in a contribution. Furthermore, future pension contributions beyond 2006 cannot be determined at this time. Our regulatory obligation to contribute approximately $3.6 million annually to our other postretirement benefit plans’ trusts, less costs incurred directly by us, is not included as the duration is indefinite.

Off-Balance Sheet Arrangements:

We have no off-balance sheet financing arrangements.

Pending Litigation:

We are subject to claims arising in the ordinary course of business and other legal proceedings. We accrue liabilities related to claims when we can determine the amount or range of amounts of probable settlement costs. Management does not currently anticipate the disposition of any known claims to have a material adverse effect on our financial position, results of operations or liquidity.

Union Contract:

In November 2004, our largest bargaining unit voted to ratify a new, 4-year contract. The contract covers the period from the old contract’s expiration on January 15, 2005 through January 14, 2009. Terms of the contract include annual wage increases ranging from 3.0% to 3.5% over the contract’s life, health care plan redesign, the establishment of caps on payments for postretirement medical benefits, and the implementation of separate wage and benefit packages for new hires. With this agreement, all unionized personnel, which represent 70% of our workforce at March 31, 2006, are operating under agreements that run through at least January 2008.

Market Risks

Commodity Market Risks:

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

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We transact commodities on a physical basis and typically do not enter into financial derivative positions directly. South Jersey Resources Group, LLC, an affiliate by common ownership, manages our risk by entering into the types of transactions noted above. As part of our gas purchasing strategy, we occasionally 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 under the mark-to-market method as of March 31, 2006 is as follows (in thousands):

Assets		Maturity		Maturity
	Source of Fair Value		<1 Year		1 - 3 Years		Total
Prices Actively Quoted	NYMEX	$	2,621	$	39	$	2,660
Other External Sources	Basis		-		-		-
Total		$	2,621	$	39	$	2,660
Liabilities			Maturity		Maturity
	Source of Fair Value		<1 Year		1 - 3 Years		Total
Prices Actively Quoted	NYMEX	$	14,649	$	171	$	14,820
Other External Sources	Basis		-		-		-
Total		$	14,649	$	171	$	14,820

NYMEX (New York Mercantile Exchange) is the primary national commodities exchange on which natural gas is traded. Basis represents the price of a NYMEX natural gas futures contract adjusted for the difference in price for delivering the gas at another location. Contracted volumes of our NYMEX contracts are 8.2 million decatherms with a weighted average settlement price of $8.29 per decatherms.

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 Quarter Ended March 31, 2006, Net		7,043
Other Changes in Fair Value from Continuing and New Contracts, Net		(19,689	)
Net Derivatives — Energy Related Liability, March 31, 2006	$	(12,160	)

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Interest Rate Risk:

Our exposure to interest rate risk relates primarily to short-term, variable-rate borrowings. Short-term, variable-rate debt outstanding at March 31, 2006 was $74.8 million and averaged $73.7 million during the first quarter of 2006. A hypothetical 100 basis point (1%) increase in interest rates on our average variable-rate debt outstanding would result in a $435,000 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. Our weighted-average borrowing cost, which changes daily, was 5.42% at March 31, 2006.

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. In October 2005, in anticipation of issuing long-term, variable-rate, tax-exempt debt during 2006 under the MTN Program, we executed $25.0 million of forward-starting interest rate swaps that will result in an effective fixed rate of 3.43% for 30 years. The debt, which was issued in April 2006, is being used to provide long-term financing for capital improvements to our gas transmission and distribution system serving Atlantic and Cape May Counties in southern New Jersey.

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 March 31,	Year Ended December 31,
2006	2005	2004	2003	2002	2001
3.9x	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

Information required by this item is incorporated by reference to the section entitled "Market Risks" beginning on page 30 of this report.

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 ffirst fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

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PART II — OTHER INFORMATION

Item l. Legal Proceedings

Information required by this Item is incorporated by reference to Part I, Item 1, Note 7, beginning on page 18.

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

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