Consolidated Financial Statistics
(Thousands, except per share data)

Fiscal Years Ended September 30,		2003			2002			2001			2000			1999			1998
Selected Financial Data
Operating Revenues		$	2,544,379		$	1,831,504		$	2,048,408		$	1,164,549		$	904,268		$	710,342
Operating Expenses
	Gas purchases		2,238,394			1,566,467			1,782,840			919,903			669,835			483,715
	Operation and maintenance		106,030			91,646			89,348			84,890			80,919			77,980
	Depreciation and amortization		31,965			31,844			32,530			30,997			29,455			27,835
	Energy and other taxes		46,639			36,792			43,770			34,842			36,071			36,758
Total operating expenses			2,423,028			1,726,749			1,948,488			1,070,632			816,280			626,288
Operating Income			121,351			104,755			99,920			93,917			87,988			84,054
Other income			515			4,569			6,339			1,916			3,630			2,024
Interest charges, net			13,992			16,556			19,705			18,750			19,977			19,633
Income before Income Taxes			107,874			92,768			86,554			77,083			71,641			66,445
Income tax provision			42,462			35,924			32,891			29,147			26,835			24,688
Income before Accounting Change			65,412			56,844			53,663			47,936			44,806			41,757
Cumulative effect of a change in accounting, net			—			—			(1,347	)		—			—			—
Income from Continuing Operations			65,412			56,844			52,316			47,936			44,806			41,757
Income from discontinued operations, net			—			—			—			828			—			—
Net Income		$	65,412		$	56,844		$	52,316		$	48,764		$	44,806		$	41,757
Capitalization
	Common stock equity	$	418,941		$	361,453		$	352,069		$	328,128		$	302,169		$	290,804
	Redeemable preferred stock		—			295			298			400			520			20,640
	Long-term debt		257,899			370,628			353,799			291,528			287,723			326,741
Total Capitalization		$	676,840		$	732,376		$	706,166		$	620,056		$	590,412		$	638,185
Property, Plant and Equipment
	Utility plant	$	1,097,591		$	1,053,086		$	1,016,911		$	981,601		$	941,490		$	895,321
	Accumulated depreciation		(270,673	)(c)		(248,980	)		(230,373	)		(214,158	)		(198,695	)		(178,556	)
	Real estate properties and other		30,999			25,144			26,759			28,016			26,326			25,838
	Accumulated depreciation		(5,313	)		(5,075	)		(4,647	)		(4,069	)		(3,706	)		(3,535	)
Property, Plant and Equipment, Net		$	852,604		$	824,175		$	808,650		$	791,390		$	765,415		$	739,068
Capital Expenditures
	Utility plant	$	46,653		$	42,314		$	44,176		$	48,826		$	48,196		$	42,847
	Real estate properties and other		6,614			924			5,872			2,067			676			1,830
	Investments available for sale		—			—			1,669			250			—			9,498
	Cost of removal		4,308			4,715			5,629			5,401			5,362			3,691
Total Capital Expenditures		$	57,575		$	47,953		$	57,346		$	56,544		$	54,234		$	57,866
Total Assets		$	1,570,979		$	1,455,589		$	1,328,618		$	1,172,511		$	1,030,510		$	1,001,612
Common Stock Data
Earnings per share from continuing operations – Basic		$	2.41		$	2.12		$	1.97		$	1.81		$	1.67		$	1.56
Earnings per share from continuing operations – Diluted		$	2.38		$	2.09		$	1.95		$	1.79		$	1.67		$	1.56
Earnings per share – Basic		$	2.41		$	2.12		$	1.97		$	1.84		$	1.67		$	1.56
Earnings per share – Diluted		$	2.38		$	2.09		$	1.95		$	1.82		$	1.67		$	1.56
Dividends declared per share		$	1.24		$	1.20		$	1.17		$	1.15		$	1.13		$	1.09
Payout ratio(a)			51	%		57	%		59	%		64	%		68	%		70	%
Market price at year-end		$	36.04		$	32.90		$	29.47		$	27.09		$	26.67		$	23.75
Dividend yield at year-end			3.4	%		3.6	%		4.0	%		4.2	%		4.2	%		4.6	%
Price-earnings ratio			15			16			15			15			16			15
Book value per share		$	15.38		$	13.43		$	13.20		$	12.43		$	11.35		$	10.88
Market-to-book ratio at year-end			2.3			2.5			2.2			2.2			2.3			2.2
Shares outstanding at year-end			27,233			26,917			26,664			26,391			26,612			26,717
Average shares outstanding – Basic			27,095			26,860			26,598			26,547			26,778			26,697
Average shares outstanding – Diluted			27,532			27,168			26,801			26,733			26,976			26,841
Return on average equity(a) (b)			15.9	%		15.3	%		15.3	%		14.8	%		14.5	%		14.2	%

(a)	Continuing operations
(b)	Excluding accumulated other comprehensive income
(c)	Reclassified $71.5 million in 2003 to Regulatory liability in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.”

All common share and earnings-per-share data have been restated for a 3-for-2 stock split, which became effective in March 2002.

Consolidated Statements of Income
(Thousands, except per share data)

Fiscal Years Ended September 30,		2003		2002		2001
Operating Revenues		$	2,544,379	$	1,831,504	$	2,048,408
Operating Expenses
	Gas purchases		2,238,394		1,566,467		1,782,840
	Operation and maintenance		106,030		91,646		89,348
	Depreciation and amortization		31,965		31,844		32,530
	Energy and other taxes		46,639		36,792		43,770
Total operating expenses			2,423,028		1,726,749		1,948,488
Operating Income			121,351		104,755		99,920
Other income			515		4,569		6,339
Interest Charges, Net
	Long-term debt		9,643		14,095		15,314
	Short-term debt and other		4,349		2,461		4,391
Total interest charges, net			13,992		16,556		19,705
Income before Income Taxes			107,874		92,768		86,554
Income tax provision			42,462		35,924		32,891
Income before Cumulative Effect of a Change in Accounting			65,412		56,844		53,663
Cumulative effect of a change in accounting for derivatives, net of tax of $930			—		—		(1,347	)
Net Income		$	65,412	$	56,844	$	52,316
Earnings per Share – Basic
	Income before Accounting Change	$	2.41	$	2.12	$	2.02
	Net Income	$	2.41	$	2.12	$	1.97
Earnings per Share – Diluted
	Income before Accounting Change	$	2.38	$	2.09	$	2.00
	Net Income	$	2.38	$	2.09	$	1.95
Dividends per Common Share		$	1.24	$	1.20	$	1.17
Average Shares Outstanding – Basic			27,095		26,860		26,598
Average Shares Outstanding – Diluted			27,532		27,168		26,801

The accompanying notes are an integral part of these statements.

All common share and earnings-per-share data have been restated for a 3-for-2 stock split, which became effective in March 2002.

Consolidated Statements of Cash Flows
(Thousands)

Fiscal Years Ended September 30,			2003			2002			2001
Cash Flows from Operating Activities
	Net income		$	65,412		$	56,844		$	52,316
	Adjustments to reconcile net income to cash flows
		Depreciation and amortization		31,965			31,844			32,530
		Amortization of deferred charges		4,410			3,893			4,158
		Deferred income taxes		15,221			18,759			(2,397	)
		Manufactured gas plant remediation costs		(21,322	)		(23,363	)		(15,145	)
		Changes in working capital		(17,547	)		(23,769	)		(107,191	)
		Prepaid demand fees		—			(10,000	)		(5,000	)
		Other non-current assets		18,839			(2,202	)		11,025
		Other non-current liabilities		(4,842	)		(2,241	)		(481	)
Net cash flows from operating activities				92,136			49,765			(30,185	)
Cash Flows from Financing Activities
	Proceeds from long-term debt			—			49,375			12,800
	Proceeds from common stock			11,325			11,729			11,620
	Proceeds from sale-leaseback transactions			5,294			20,631			2,395
	Payments of long-term debt			(132,517	)		(1,764	)		(495	)
	Redemption of preferred stock			(295	)		(3	)		(102	)
	Purchases of treasury stock			(1,512	)		(6,135	)		(5,366	)
	Payments of common stock dividends			(33,245	)		(32,012	)		(30,989	)
	Net change in short-term debt			115,900			(50,900	)		92,500
Net cash flows from financing activities				(35,050	)		(9,079	)		82,363
Cash Flows from Investing Activities
	Expenditures for
		Utility plant		(46,653	)		(42,314	)		(44,176	)
		Real estate properties and other		(6,614	)		(924	)		(5,872	)
		Purchase of investments available for sale		—			—			(1,669	)
		Cost of removal		(4,308	)		(4,715	)		(5,629	)
	Proceeds from sale of investments available for sale			1,046			1,205			966
	Proceeds from asset sales			—			3,300			6,342
Net cash flows from investing activities				(56,529	)		(43,448	)		(50,038	)
Net change in cash and temporary investments				557			(2,762	)		2,140
Cash and temporary investments at beginning of the year				1,282			4,044			1,904
Cash and temporary investments at end of the year			$	1,839		$	1,282		$	4,044
Changes in Components of Working Capital
	Construction fund			—		$	3,600		$	4,000
	Receivables		$	33,926			(85,715	)		21,136
	Inventories			(41,449	)		(16,100	)		(5,674	)
	Underrecovered gas costs			(46,330	)		(689	)		(35,637	)
	Purchased gas			(29,014	)		83,456			(68,133	)
	Accrued and prepaid taxes, net			15,409			(8,006	)		23,016
	Accounts payable and other current liabilities			6,365			1,518			(2,245	)
	Broker margin accounts			32,343			(10,045	)		(42,703	)
	Other current assets			13,876			(1,440	)		800
	Other current liabilities			(2,673	)		9,652			(1,751	)
Total			$	(17,547	)	$	(23,769	)	$	(107,191	)
Supplemental Disclosures of Cash Flows Information
Cash paid during the year for
	Interest (net of amounts capitalized)		$	12,191		$	14,516		$	19,031
	Income taxes		$	12,365		$	31,410		$	10,033

The accompanying notes are an integral part of these statements.

Consolidated Balance Sheets
(Thousands)

September 30,		2003			2002
Assets
Property, Plant and Equipment
	Utility plant, at cost	$	1,097,591		$	1,053,086
	Real estate properties and other, at cost		30,999			25,144
			1,128,590			1,078,230
	Accumulated depreciation and amortization		(275,986	)		(254,055	)
Property, plant and equipment, net			852,604			824,175
Current Assets
	Cash and temporary investments		1,839			1,282
	Customer accounts receivable		126,910			158,591
	Unbilled revenues		3,649			4,679
	Allowance for doubtful accounts		(5,635	)		(4,395	)
	Regulatory assets		75,735			43,973
	Gas in storage, at average cost		188,679			147,202
	Materials and supplies, at average cost		2,754			2,782
	Prepaid state taxes		11,056			10,973
	Derivatives		21,290			15,781
	Broker margin accounts		6,600			38,943
	Other		16,846			14,654
Total current assets			449,723			434,465
Non-Current Assets
	Equity investments		15,432			14,302
	Regulatory assets		189,140			134,537
	Derivatives		16,105			10,952
	Other		47,975			37,158
Total non-current assets			268,652			196,949
Total Assets		$	1,570,979		$	1,455,589
Capitalization and Liabilities
Capitalization
	Common stock equity	$	418,941		$	361,453
	Redeemable preferred stock		—			295
	Long-term debt		257,899			370,628
Total capitalization			676,840			732,376
Current Liabilities
	Current maturities of long-term debt		2,448			26,942
	Short-term debt		185,800			59,900
	Purchased gas		200,630			229,644
	Accounts payable and other		41,053			34,688
	Postretirement employee benefit liabilities		3,321			4,996
	Dividends payable		8,442			8,072
	Accrued taxes		36,515			15,025
	Derivatives		22,750			33,042
	Customers’ credit balances and deposits		22,644			23,642
Total current liabilities			523,603			435,951
Non-Current Liabilities
	Deferred income taxes		113,608			92,435
	Deferred investment tax credits		8,801			9,148
	Deferred revenue		13,418			15,019
	Derivatives		22,039			6,612
	Manufactured gas plant remediation		108,800			65,830
	Postretirement employee benefit liabilities		15,248			19,950
	Regulatory and cost of removal liabilities		77,433			74,079
	Other		11,189			4,189
Total non-current liabilities			370,536			287,262
Commitments and Contingent Liabilities (Note 10)
Total Capitalization and Liabilities		$	1,570,979		$	1,455,589

The accompanying notes are an integral part of these statements.

Consolidated Statements of Capitalization
(Thousands)

September 30,		2003			2002
Common Stock Equity
	Common stock, $2.50 par value, authorized 50,000,000 shares; issued shares 2003 - 27,725,394; 2002 - 27,667,001	$	69,314		$	69,168
	Premium on common stock		208,749			207,197
	Accumulated other comprehensive income, net of tax		2,553			(12,374	)
	Treasury stock at cost and other; shares 2003 - 492,322; 2002 - 750,179		(16,042	)		(25,108	)
	Retained earnings		154,367			122,570
Total common stock equity			418,941			361,453
Redeemable Preferred Stock
New Jersey Natural Gas
	$100 par value, cumulative; authorized shares
	2003 - 310,000; 2002 - 312,954; outstanding shares
	5.65% series - 2003 - none; 2002 - 2,954		—			295
Total redeemable preferred stock			—			295

Long-Term Debt
New Jersey Natural Gas
First mortgage bonds		Maturity date
7.50%	Series V	December 1, 2002		—			25,000
5.38%	Series W	August 1, 2023		10,300			10,300
6.27%	Series X	November 1, 2008		30,000			30,000
6.25%	Series Y	August 1, 2024		10,500			10,500
8.25%	Series Z	October 1, 2004		25,000			25,000
Variable	Series AA	August 1, 2030		25,000			25,000
Variable	Series BB	August 1, 2030		16,000			16,000
6.88%	Series CC	October 1, 2010		20,000			20,000
Variable	Series DD	September 1, 2027		13,500			13,500
Variable	Series EE	January 1, 2028		9,545			9,545
Variable	Series FF	January 1, 2028		15,000			15,000
Variable	Series GG	April 1, 2033		18,000			18,000
Revolving credit agreement, at variable rates		January 4, 2006		15,000			25,000
Capital lease obligation — building		June 1, 2021		29,488			30,054
Capital lease obligation — meters		October 1, 2012		23,014			19,396
Less: current maturities of long-term debt				(2,448	)		(26,942	)
Total				257,899			265,353
New Jersey Resources
Revolving credit agreement, at floating rates		January 4, 2006		-			105,275
Total long-term debt				257,899			370,628
Total Capitalization			$	676,840		$	732,376

The accompanying notes are an integral part of these statements.

Consolidated Statements of Common Stock Equity and Comprehensive Income
(Thousands)

											Accum. Other
			Number of			Common		Premium on			Comprehensive			Treasury Stock			Retained
			Shares			Stock		Common Stock			Income			and Other			Earnings			Total
Balance at September 30, 2000				17,594		$	46,249	$	223,256		$	13,514		$	(31,814	)	$	76,923		$	328,128
Net income																		52,316			52,316
Other comprehensive income (loss), net of tax:
	Cumulative effect of a change in accounting for derivatives, net of tax of $(16,722)											20,530									20,530
	Unrealized loss on equity investments, net of tax of $9,130											(13,219	)								(13,219	)
	Unrealized loss on derivatives, net of tax $6,444											(11,199	)								(11,199	)
		Other comprehensive loss																			(3,888	)
Comprehensive income																					48,428
Common stock issued under stock plans				308			277		3,849						7,472						11,598
Tax benefit from stock plans									427												427
Cash dividends declared																		(31,231	)		(31,231	)
Treasury stock and other				(126	)										(5,281	)					(5,281	)
Balance at September 30, 2001				17,776			46,526		227,532			9,626			(29,623	)		98,008			352,069
Net income																		56,844			56,844
Other comprehensive income (loss), net of tax:
	Unrealized gain on equity investments, net of tax of $(208)											296									296
	Unrealized loss on derivatives, net of tax of $11,542											(13,669	)								(13,669	)
	Minimum pension liability adjustment, net of tax of $5,958											(8,627	)								(8,627	)
		Other comprehensive loss																			(22,000	)
Comprehensive income																					34,844
Common stock issued under stock plans				374			262		1,626						10,217						12,105
Stock dividend				8,952			22,380		(22,380	)											—
Tax benefits from stock plans									419												419
Cash dividends declared																		(32,282	)		(32,282	)
Treasury stock and other				(185	)										(5,702	)					(5,702	)
Balance at September 30, 2002				26,917			69,168		207,197			(12,374	)		(25,108	)		122,570			361,453
Net income																		65,412			65,412
Other comprehensive income (loss), net of tax:
	Unrealized gain on equity investments, net of tax of $(96)											139									139
	Unrealized gain on derivatives, net of tax of $(13,153)											17,127									17,127
	Minimum pension liability adjustment, net of tax of $1,586											(2,339	)								(2,339	)
		Other comprehensive income																			14,927
Comprehensive income																					80,339
Common stock issued under stock plans				363			146		1,144						10,578						11,868
Tax benefits from stock plans									408												408
Cash dividends declared																		(33,615	)		(33,615	)
Treasury stock and other				(47	)										(1,512	)					(1,512	)
Balance at September 30, 2003				27,233		$	69,314	$	208,749		$	2,553		$	(16,042	)	$	154,367		$	418,941

The accompanying notes are an integral part of these statements.

Independent Auditors’ Report

To the Board of Directors and Shareowners of New Jersey Resources Corporation:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of New Jersey Resources Corporation and its subsidiaries (the Company) as of September 30, 2003 and 2002 and the related consolidated statements of income, common stock equity and comprehensive income and cash flows for each of the three years in the period ended September 30, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2003 and 2002 and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2003 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, on October 1, 2000, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, under which the Company records the fair value of derivatives as assets and liabilities.

We have also previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheets and consolidated statements of capitalization as of September 30, 2001, 2000, 1999 and 1998, and the related consolidated statements of income, common stock equity and cash flows for each of the years ended September 30, 2000, 1999 and 1998 (none of which are presented herein) and we expressed unqualified opinions on those consolidated financial statements.

In our opinion, the information set forth in the consolidated financial statistics for each of the six years in the period ended September 30, 2003 for the Company is fairly stated in all material respects, in relation to the consolidated financial statements from which it has been derived.

Parsippany, New Jersey
October 28, 2003
(March 19, 2004 as to Notes 1 and 13)

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Nature of the Business

New Jersey Resources (NJR or the Company) is an energy services holding company providing retail and wholesale natural gas and related energy services to customers from the Gulf Coast to New England and Canada. Its principal subsidiary, New Jersey Natural Gas (NJNG), provides regulated natural gas service in central and northern New Jersey and participates in the off-system sales and capacity release markets. Other operating subsidiaries include NJR Energy Services (NJRES), which provides unregulated fuel and capacity management and wholesale marketing services; NJR Home Services (NJRHS), which provides service, sales and installation of appliances; NJR Energy, an investor in energy-related ventures; Commercial Realty and Resources (CR&R), a commercial real estate developer; NJR Service, which provides shared administrative services; and NJR Investment, which makes energy-related equity investments.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries. Significant intercompany accounts and transactions have been eliminated.

Regulatory Accounting

The Company’s largest subsidiary, NJNG, maintains its accounts in accordance with the Uniform System of Accounts as prescribed by the New Jersey Board of Public Utilities (BPU). As a result of the ratemaking process, NJNG is required to follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71) and as a result, the accounting principles applied by NJNG differ in certain respects from those applied by unregulated businesses.

Utility Plant and Depreciation

Depreciation is computed on a straight-line basis for financial statement purposes, using rates based on the estimated average lives of the various classes of depreciable property. The composite rate of depreciation was 3.13 percent of average depreciable property in 2003, 3.21 percent in 2002 and 3.37 percent in 2001. When depreciable properties are retired, the original cost thereof, plus cost of removal less salvage, is charged to accumulated depreciation.

Impairment of Long-Lived Assets

The Company reviews the carrying amount of an asset for possible impairment whenever events or changes in circumstances indicate that such amount may not be recoverable. For the years ended September 30, 2003, 2002 and 2001, no such circumstances were identified.

Utility Revenue

Customers are billed through monthly cycle billings on the basis of actual or estimated usage. NJNG accrues estimated revenue for natural gas delivered to the end of the accounting period but not billed to customers.

Gas Purchases

NJNG’s tariff includes a Basic Gas Supply Service (BGSS ) which is normally revised on an annual basis. Under the BGSS, NJNG projects its cost of natural gas, net of supplier refunds, the impact of hedging activities and credits from non-firm sales and transportation activities, and recovers or refunds the difference, if any, of such projected costs compared with those included in prices through levelized charges to customers. Any under- or over-recoveries are deferred and reflected in the BGSS in subsequent years.

Income Taxes

Deferred income taxes are calculated in conformance with SFAS No. 109, “Accounting for Income Taxes.” (See Note 6: Income Taxes.)

Investment tax credits have been deferred and are being amortized as a reduction to the tax provision over the average lives of the related property.

Capitalized and Deferred Interest

The Company’s capitalized interest totaled $278,000 in 2003, $367,000 in 2002 and $875,000 in 2001, with average interest rates of 1.48 percent, 2.23 percent and 5.92 percent, respectively. These amounts are included in Utility plant on the Consolidated Balance Sheets and are reflected on the Consolidated Statements of Income as a reduction to Interest charges, net. NJNG does not capitalize a cost of equity for its utility plant construction activities.

Pursuant to a BPU order, NJNG is permited to recover carrying costs on uncollected balances related to underrecovered natural gas costs incurred through October 31, 2001, and its manufactured gas plant (MGP) remediation expenditures. (See Note 7: Regulatory Issues.) Accordingly, Other income included $1.7 million, $3 million and $4.5 million of deferred interest related to remediation and underrecovered gas costs in 2003, 2002 and 2001, respectively.

Equity Investments

Equity investments purchased as long-term investments are classified as available for sale and are carried at their estimated fair value, with any changes in unrealized gains or losses included in Accumulated other comprehensive income, a component of Common Stock Equity. Joint ventures and investments in which the Company can exercise a significant influence over operations and management are accounted for under the equity method. For investments in which significant influence does not exist, the cost method of accounting is applied.

Regulatory Assets

At September 30, 2003 and 2002, respectively, the Company had the following regulatory assets on the Consolidated Balance Sheets:

(Thousands)			2003			2002		Recovery Period
Regulatory assets — current
	Underrecovered gas costs		$	80,242		$	33,912	Less than one year (1)
	Weather-normalization clause (WNC)			(4,507	)		10,061	Less than one year (4)
Total			$	75,735		$	43,973
Regulatory assets — non-current
	Remediation costs (Note 10)
		Expended, net	$	44,117		$	42,187	(2)
		Liability for future expenditures		108,800			65,830	(3)
	Underrecovered gas costs			2,827			15,118	Through Nov. 2004 (1)
	Derivatives (Note 1)			28,870			2,562	Through Oct. 2010 (5)
	Postretirement benefit costs (Note 8)			3,021			3,322	Through Sept. 2013(4)
	WNC			—			4,858	(4)
	Societal Benefit Charges (SBC)			1,505			660	Various (2) (4)
Total			$	189,140		$	134,537

(1)	Recoverable without interest except for $13.9 million that is recoverable with interest.
(2)	Recoverable with interest. See Note 10: Commitments and Contingent Liabilities for status of recovery period for remediation costs.
(3)	Estimated future expenditures not yet recovered through a rate order.
(4)	Recoverable/refundable through a specific rate order.
(5)	Recoverable through BGSS.

Sales Tax Accounting

Sales tax and Transitional Energy Facilities Assessment (TEFA) are collected from customers and presented gross on the Consolidated Statements of Income. For the years ended September 30, 2003, 2002, and 2001, sales tax and TEFA totaled $42.6 million, $32.9 million and $39.4 million, respectively.

Statements of Cash Flows

For purposes of reporting cash flows, all temporary investments with maturities of three months or less are considered cash equivalents.

Derivative Activities

Effective October 1, 2000, the Company adopted SFAS No.133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133) under which the Company records the fair value of derivatives held as assets and liabilities. The changes in the fair value of the effective portion of derivatives qualifying as cash flow hedges are recorded, net of tax, in Accumulated other comprehensive income, a component of Common Stock Equity. Under SFAS 133, the Company also has certain derivative instruments that do not qualify as cash flow hedges. The changes in the fair value of these derivatives are recorded in Net income. In addition, the changes in the fair value of the ineffective portion of derivatives qualifying for hedge accounting are recorded as an increase or decrease in natural gas costs or interest expense, as applicable, based on the nature of the derivatives. The derivatives that NJNG utilizes to hedge its natural gas-purchasing activities are recoverable through its BGSS. Accordingly, the offset to the changes in fair value of these derivatives is recorded as a regulatory asset or liability. The Company has not designated any derivatives as fair value hedges.

The fair value of derivative investments is determined by reference to quoted market prices of listed contracts, published quotations or quotations from independent parties. In the absence thereof, the Company utilizes mathematical models based on current and historical data. (See Note 9: Financial Instruments and Risk Management.)

New Accounting Standards

In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS 150). The statement requires an issuer to classify a financial instrument as a liability (or an asset in some circumstances) because that financial instrument embodies an obligation of the issuer. These obligations include, but are not limited to, mandatorily redeemable stock, obligations to repurchase company shares and other obligations payable in company stock. The Company has completed its assessment of the effect of the pronouncement and has determined that it will not have an impact on its financial condition, results of operations or cash flows.

In April 2003, the FASB issued SFAS No.149, “Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities” (SFAS 149). SFAS 149 is generally effective for contracts entered into or modified after June 30, 2003. This amendment, among other things, further clarifies several implementation issues related to SFAS 133, as amended. The adoption of SFAS 149 did not have an impact on the Company’s financial condition, results of operations or cash flows.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), which clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” This interpretation provides guidance on the identification and consolidation of variable interest entities (VIEs), whereby consolidation is achieved through means other than through control. FIN 46 did not have an impact on the Company’s financial condition, results of operations or cash flows.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure” (SFAS 148), an amendment of FASB Statement No. 123. SFAS 148 provides implementation guidance for the adoption of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS 123), which the Company adopted as of October 1, 2002. The Company has complied with the guidelines of SFAS 148 with respect to the adoption and disclosure of SFAS 123. (See Note 2: Common Stock.)

In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). FIN 45 clarifies the requirements of SFAS No. 5, “Accounting for Contingencies” (SFAS 5), related to a guarantor’s accounting for, and disclosures of, the issuance of certain types of guarantees. (See Note 10: Commitments and Contingent Liabilities.) The Company

has completed an analysis of FIN 45 and has determined that there were no guarantees for unrelated third parties. NJR has issued parent guarantees for certain transactions entered into by NJRES. As of September 30, 2003, there were parent guarantees covering approximately $201 million of natural gas purchase and demand fee commitments not yet reflected in Accounts payable on the Consolidated Balance Sheet.

The Company completed its assessment of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143), which became effective October 1, 2002. SFAS 143 addresses the accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset removal costs. Based on its analysis, the Company determined that it has no such legal obligations. At September 30, 2003, and 2002, NJNG has asset removal costs recovered through prices in excess of actual costs incurred totaling $71.5 million, and $67.8 million, respectively, which, in accordance with SFAS 143, has been reclassified from Accumulated depreciation to non-current liabilities and is included in Regulatory and cost of removal liabilities on the Consolidated Balance Sheet.

Stock Options

Effective with options granted in fiscal 2003, the Company expenses the cost of stock options over the life of the stock option vesting period in accordance with SFAS 123.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year reporting.

Use of Estimates

The consolidated financial statements of the Company include estimates and assumptions of certain assets, liabilities, revenues and expenses and the disclosure of certain contingent assets and liabilities. Actual results in the future may differ from such estimates.

2. Common Stock

On January 22, 2002, the Board of Directors declared a 3-for-2 split of the Company’s outstanding shares of common stock, which was distributed on March 4, 2002, to all owners of record as of February 8, 2002. Accordingly, all prior year common share information has been restated to reflect the retroactive effect of this split.

At September 30, 2003, there were 1,117,997 shares reserved for issuance under the Company’s Automatic Dividend Reinvestment and Retirement Savings Plans.

The Company currently offers an Employee and Outside Director Long-Term Incentive Compensation Plan (the Plan) with 2.9 million shares of common stock authorized for awards. Under the Plan, the Company can issue stock options, performance units, dividend equivalent rights and service awards. At September 30, 2003, there were 868,127 shares remaining for issuance or grant under the Plan.

The Company issued 75,795, 4,389 and 28,950 performance units in 2003, 2002 and 2001, respectively. The performance units vest over 3-year periods and are subject to the Company achieving certain performance targets. The annual expense associated with these issuances was $1.2 million, $299,000 and $625,000 in 2003, 2002 and 2001, respectively.

All options granted under the Plan have been non-qualified stock options. They give the holder a right to purchase the Company’s common stock at prices no less than the closing price on the date of the grant. Generally, no option can be exercised before one year or more than 10 years from the date of each grant.

Under the Plan, each outside director receives an award of 200 shares of restricted stock that vests over four years, is granted 5,000 options upon joining the Board and receives an annual grant of 1,500 options. In 2003, 400 shares were issued and 3,000 shares were forfeited.

In October 2002, the Company adopted the fair value method of recording stock-based compensation under SFAS 123. The Company adopted the prospective application of SFAS 123 for options granted after October 1, 2002, the cost of which will be expensed through the income statement based on the fair value of the award at the grant date. In December 2002, the FASB issued SFAS 148, which provides implementation guidance for the adoption of SFAS 123. The Company has complied with the guidelines of SFAS 148 with respect to the adoption and disclosure of SFAS 123. The following is a reconciliation of the As Reported and Pro Forma net income for options granted prior to October 1, 2002, which are accounted for under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.”

(Thousands)	2003			2002			2001
Net Income, as reported	$	65,412		$	56,844		$	52,316
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		93			—			—
Deduct: Total stock-based employee compensation expense determined under the fair value-based method for all awards, net of related tax effects		(589	)		(623	)		(358	)
Pro forma Net Income	$	64,916		$	56,221		$	51,958

	2003		2002		2001
Earnings Per Share:
Basic — as reported	$	2.41	$	2.12	$	1.97
Basic — pro forma	$	2.40	$	2.09	$	1.95
Diluted — as reported	$	2.38	$	2.09	$	1.95
Diluted — pro forma	$	2.36	$	2.07	$	1.93

The following table summarizes the assumptions used in the Black-Scholes option-pricing model and the resulting weighted average fair value of the stock options for the past three years:

	2003			2002			2001
Dividend yield		3.4	%		3.6	%		4.0	%
Volatility		13.8	%		16.47	%		18.82	%
Expected life (years)		7.7			7.9			8.0
Weighted average fair value	$	3.83		$	3.52		$	3.03

The following table summarizes the stock option activity for the past three years:

				Weighted
				Average
	Shares			Exercise Price
Outstanding at September 30, 2000		1,198,676		$	22.55
Granted		641,034		$	27.35
Exercised		(176,450	)	$	20.51
Forfeited		(2,067	)	$	26.44
Outstanding at September 30, 2001		1,661,193		$	22.55
Granted		47,964		$	30.22
Exercised		(123,157	)	$	20.75
Forfeited		(1,859	)	$	27.30
Outstanding at September 30, 2002		1,584,141		$	25.06
Granted		284,000		$	31.52
Exercised		(64,424	)	$	21.78
Forfeited		(3,988	)	$	27.82
Outstanding at September 30, 2003		1,799,729		$	26.20
Exercisable at September 30, 2003		1,022,992		$	24.35

The following table summarizes stock options outstanding and exercisable at September 30, 2003:

	Outstanding						Exercisable
					Average				Average
Exercise			Average		Exercise				Exercise
Price Range	Options		Life (a)		Price		Options		Price
$13.36 — $16.71		44,904		1.6	$	15.62		44,904	$	15.62
$16.71 — $20.05		158,557		2.2	$	18.57		158,557	$	18.57
$20.02 — $23.39		16,500		4.6	$	22.44		16,500	$	22.44
$23.39 — $26.73		613,318		5.6	$	25.09		449,377	$	24.78
$26.73 — $30.07		641,695		7.2	$	27.36		334,415	$	27.39
$30.07 — $35.00		324,755		9.2	$	31.39		19,239	$	30.90
Total		1,799,729		6.4	$	26.20		1,022,992	$	24.35

(a) Average contractual life remaining in years

In accordance with SFAS No. 128, “Earnings Per Share,” which established standards for computing and presenting basic and diluted earnings per share (EPS), the incremental shares required for inclusion in the denominator for the diluted EPS calculation were 436,496 in 2003, 307,883 in 2002 and 202,599 in 2001. These shares relate to stock options and restricted stock and were calculated using the treasury stock method. The numerator for each applicable basic and diluted EPS calculation was net income.

In 1996, the Board of Directors authorized the repurchase of up to 1 million of the Company’s common shares. In 1999 and 2002, the repurchase plan was expanded to 1.5 million shares and 2 million shares, respectively. As of September 30, 2003, the Company has repurchased 1,578,053 shares of its common stock at a cost of $56 million.

3. Shareholder Rights Plan

In July 1996, the Board of Directors adopted a shareholder rights plan that provides for the distribution of one right for each share of common stock outstanding on or after August 15, 1996. Each right entitles its holder to purchase 1/1500 of one share of the Series A Stock, as defined below, at an exercise price of $36.67.

The shareholder rights plan provides that, after a person or group acquires 10 percent or more of the Company’s common stock, each of the rights, except for those held by the 10 percent holder (which become void once the holder reaches the 10 percent threshold) becomes the right to acquire shares of the Company’s common stock having a market value equal to twice the exercise price. If a person or group acquires at least 10 percent, but less than 50 percent, the Board of Directors may exchange each right for one share of the Company’s common stock. The rights may be redeemed for $.01 per right at any time prior to the first public announcement or communication to the Company that a person or group has crossed the 10 percent threshold.

The Company has 400,000 shares of authorized and unissued $100 par value preferred stock. The Company has created and reserved for issuance 50,000 shares of Series A Junior Participating Cumulative Preferred Stock (Series A Stock) in connection with the adoption of the shareholder rights plan.

4. Long-Term Debt, Dividends and Retained Earnings Restrictions

Annual Long-term debt redemption requirements for the next five years are as follows: 2004, $2.4 million; 2005, $27.5 million; 2006, $2.6 million; 2007, $2.8 million; and 2008, $3 million.

NJNG’s mortgage secures its First Mortgage Bonds and represents a lien on substantially all of its property, including natural gas supply contracts. Certain indentures supplemental to the mortgage include restrictions as to cash dividends and other distributions on NJNG’s common stock, which restrictions apply so long as certain series of First Mortgage Bonds are outstanding. Under the most restrictive provision, approximately $133.7 million of NJNG’s retained earnings was available for such purposes at September 30, 2003.

NJNG enters into loan agreements with the New Jersey Economic Development Authority (EDA) whereby the EDA issues bonds to the public. To secure its loans from the EDA, NJNG issues First Mortgage Bonds with interest rates and maturity dates identical to the EDA Bonds. In July 2002, the EDA approved $12 million of new funds to finance construction in NJNG’s northern division over three years. In September 2003, the BPU approved NJNG’s petition to issue up to $112 million of First Mortgage Bonds, Private Placement Bonds, EDA loan agreements, or Medium Term Notes over the next three years. NJNG expects to enter into a loan agreement whereby the EDA would loan NJNG the proceeds from its $12 million Natural Gas Facilities

Revenue Bonds, which NJNG would deposit into a construction fund. NJNG expects to then immediately draw down $4 million from the construction fund.

At September 30, 2003 and 2002, NJNG had total long-term variable-rate debt outstanding of $112 million and $122 million, respectively.

In July 2002, NJNG entered into $97 million of interest rate caps with several banks at a rate of 3.25 percent, expiring in July 2004. These caps are designed to limit NJNG’s variable rate debt exposure for all of its outstanding tax-exempt EDA Bonds. The Company accounts for the interest rate caps as a cash flow hedge with changes in fair value accounted for in Other comprehensive income.

At September 30, 2003 and 2002, the weighted average interest rate on NJNG’s variable rate EDA Bonds was .9 percent and 1.5 percent, respectively.

In fiscal 2002, NJNG entered into an agreement with a financing company whereby NJNG received $20.6 million related to the sale-leaseback of a portion of its meters. In December 2002, NJNG received $5.3 million under this agreement in connection with the sale-leaseback of its vintage 2001 meters. NJNG has the ability to continue the sale-leaseback meter program on an annual basis.

In December 2002, NJNG’s $25 million, 7.5% Series V First Mortgage Bonds matured.

In December 1995, the BPU approved NJNG’s petition to enter into a master lease agreement for its headquarters building for a 25.5-year term with two 5-year renewal options. The present value of the agreement’s minimum lease payments is reflected as both a capital lease asset and a capital lease obligation, which are included in Utility plant and Long-term debt, respectively, on the Consolidated Balance Sheets. In accordance with its ratemaking treatment, NJNG records rent expense as if the lease was an operating lease. Minimum annual lease payments are $2.6 million in 2004, $2.7 million in 2005, $2.9 million in 2006, 2007 and 2008, with $44.1 million over the remaining term of the lease. Approximately 24 percent of the building, representing approximately $651,000 of lease payments in 2003, is presently subleased to other tenants.

In December 2002, the Company entered into $380 million of committed credit facilities with several banks. The NJR portion of the facility consists of $100 million with a 364-day term and an $80 million revolving credit facility with a 3-year term expiring January 2006. The NJNG portion of the facility consists of $150 million with a 364-day term and a $50 million revolving credit facility with a 3-year term expiring January 2006. The NJR facilities are used to finance unregulated operations. NJNG’s facilities are used to support its commercial paper borrowings. Consistent with NJNG’s intent to maintain a portion of its commercial paper borrowings on a long-term basis, and as supported by its long-term revolving credit facility, $15 million and $25 million of commercial paper borrowings are included in Long-term debt on the Consolidated Balance Sheets at September 30, 2003 and 2002, respectively.

At September 30, 2003, NJR had no long-term variable rate debt outstanding. At September 30, 2002, NJR had $105.3 million of long-term variable rate debt outstanding, with a weighted average interest rate of 2.2 percent.

5. Short-Term Debt and Credit Facilities

A summary of NJR’s and NJNG’s committed credit facilities which require commitment fees on the unused amounts are as follows:

(Thousands)	2003			2002
NJR
Bank credit facilities	$	180,000		$	135,000
Amount outstanding at year-end Notes payable to banks	$	42,300			—
Weighted average interest rate at year-end Notes payable to banks		1.80	%		—
NJNG
Bank credit facilities	$	200,000		$	200,000
Amount outstanding at year-end Commercial paper	$	158,500		$	74,900
Weighted average interest rate at year-end Commercial paper		1.11	%		1.80	%

6. Income Taxes

The Company’s federal income tax returns through 1999 have either been examined by the Internal Revenue Service (IRS) or the related statute of limitations has expired and all matters have been settled. The 2000 and 2001 federal income tax returns have been reviewed by audit survey, with no changes noted. The 2002 federal income tax return is currently under IRS review.

Income tax expense differs from the amount computed by applying the statutory federal income tax rate of 35 percent to pretax income for the following reasons:

(Thousands)		2003			2002			2001
Statutory income tax expense		$	37,756		$	32,469		$	29,497
Change resulting from State income taxes			6,647			5,597			5,052
	Depreciation and cost of removal		(1,192	)		(1,362	)		(1,728	)
	Investment tax credits		(348	)		(348	)		(348	)
	Other		(401	)		(432	)		(512	)
Income tax provision		$	42,462		$	35,924		$	31,961

The Income tax provision was composed of the following:

(Thousands)		2003			2002			2001
Current
	Federal	$	16,358		$	9,339		$	13,694
	State		7,848			3,811			10,838
Deferred
	Federal		16,225			18,321			10,844
	State		2,379			4,801			(3,067	)
Investment tax credits			(348	)		(348	)		(348	)
Income tax provision		$	42,462		$	35,924		$	31,961
Charged to
	Income tax provision	$	42,462		$	35,924		$	32,891
	Cumulative effect of a change in accounting		—			—			(930	)
Total provision		$	42,462		$	35,924		$	31,961

The tax effects of significant temporary differences comprising the Company’s net deferred income tax liability at September 30, 2003 and 2002,were as follows:

(Thousands)		2003			2002
Current
	Underrecovered gas costs	$	28,070		$	11,858
	WNC		(1,841	)		3,521
	Other		(2,434	)		(2,090	)
Current deferred tax liability, net		$	23,795		$	13,289
Non-current
	Property-related items	$	95,108		$	83,127
	Customer contributions		(4,169	)		(4,189	)
	Capitalized overhead and interest		(6,120	)		(4,740	)
	Underrecovered gas costs		988			5,287
	Unamortized investment tax credits		(2,558	)		(2,906	)
	Remediation costs		26,242			21,752
	WNC and other		4,117			(5,896	)
Non-current deferred tax liability, net		$	113,608		$	92,435

7. Regulatory Issues

Energy Deregulation Legislation

In February 1999, the Electric Discount and Energy Competition Act (EDECA), which provides the framework for the restructuring of New Jersey’s energy market, became law. In March 2001, the BPU issued a written order that approved a stipulation among various parties to fully open NJNG’s residential markets to competition, restructure its rates and expand an incentive for residential and small commercial customers to switch to transportation service. As required by EDECA, NJNG restructured its rates to segregate its BGSS, the component of rates whereby NJNG provides the commodity to the customer, and delivery (i.e., transportation) prices.

In June 2001, the BPU initiated a proceeding regarding the provision of BGSS. In July 2001, NJNG submitted a BGSS proposal that provides for additional customer choices, including various pricing options. In January 2002, the BPU issued an order, which stated that BGSS could be provided by suppliers other than the state’s natural gas utilities, but BGSS should be provided by the state’s natural gas utilities until further BPU action. On October 22, 2003, the BPU approved a stipulation whereby the parties agreed to develop a commodity pooling program, which is related to NJNG’s proposal.

In December 2000, the BPU issued a written order which resolved a customer account service proceeding and approved the transfer of NJNG’s existing appliance service business to NJRHS, an unregulated subsidiary of the Company. During the customer account services proceedings, the BPU noted that issues relating to the provision of such services as metering and competitive billing would be reviewed in the future. Based on the belief that there is little interest among third-party suppliers in competitive customer account services, the BPU staff recommended that a further review be deferred until the competitive energy market develops further.

The BPU is required to audit the state’s energy utilities’ competitive services business every two years. The primary purpose of the audit is to ensure that utilities and their affiliates offering unregulated retail services do not have any unfair competitive advantage over nonaffiliated providers of similar retail services. In June 2002, the BPU initiated a compliance audit of NJNG. In March 2003, an independent consulting firm, engaged by the BPU, completed its audit of NJNG. The audit report found that NJNG and its affiliates do not have an unfair competitive advantage over other competitive service providers. It also confirmed that NJNG has established and maintained effective accounting, functional and management separation between itself and its affiliates. The audit has been submitted to the BPU for approval.

BGSS

On January 6, 2003, the BPU approved a statewide BGSS agreement requiring all New Jersey natural gas utilities to make an annual filing by June 1 for review of BGSS and a potential price change to be effective October 1. After proper notice and BPU action on the June filing, the agreement allows natural gas utilities to increase residential and small commercial customer BGSS prices up to 5 percent on a self-implementing basis on December 1 and February 1.

On February 6, 2003, NJNG received approval for a 6 percent price increase effective immediately and on August 18, 2003, NJNG received approval for an 8.7 percent price increase effective September 1, 2003. These increases reflected higher wholesale natural gas costs and are subject to refund with interest.

During fiscal 2002, NJNG received a 10.8 percent price decrease effective December 1, 2001 and a 3 percent price decrease effective February 6, 2002, reflecting lower projected wholesale natural gas costs.

NJNG is eligible to receive incentives for reducing BGSS costs through a series of margin-sharing programs that include off-system sales, capacity release, portfolio-enhancing and financial risk management programs. On October 22, 2003, the BPU approved an agreement whereby the existing margin sharing between customers and shareowners for off-system sales, capacity release and financial risk management transactions was extended through October 31, 2006. As part of this agreement, the portfolio-enhancing programs, which include an incentive for the permanent reduction of the cost of capacity, continued to receive sharing treatment between customers and shareowners through April 30, 2004, for transactions entered into on or before December 31, 2002. This BPU action also provided for the parties to evaluate the appropriateness of a new capacity reliability incentive for the BPU’s consideration by October 1, 2004. NJNG believes that the elimination of the portfolio-enhancing program will not have a material effect on its financial position, results of operations or cash flows.

The BPU also approved a new storage incentive program that will share gains and losses on an 80/20 percent basis between customers and shareowners, respectively. The 1-year pilot program, will measure the difference between the actual cost of natural gas in storage and a benchmark applicable to the April-through-October injection season.

Other Adjustment Clauses

On October 22, 2003, the BPU also approved NJNG’s request to update factors used in its WNC, which is designed to stabilize year-to-year fluctuations that may result from changing weather patterns on both NJNG’s gross margin and customers’ bills. Consumption factors had not been adjusted to reflect NJNG’s growth and actual customer base since the settlement of its last base rate case nearly a decade ago. Updating the consumption factors will make the resulting calculations from the WNC more reflective of the actual impact of weather.

In March 2003, the BPU approved a permanent statewide Universal Service Fund (USF) program, effective July 1, 2003. The USF program was established for all natural gas and electric utilities in New Jersey for the benefit of limited-income customers. Eligible customers will receive a credit toward their utility bill. The credits applied to eligible customers will be recovered through a USF rider. NJNG will recover carrying costs on deferred USF balances.

NJNG has proposed a Smart Growth pilot program for Asbury Park and Long Branch, New Jersey, that would invest new capital in the infrastructure of these cities. NJNG’s proposal features a recovery mechanism referred to as the Targeted Revitalization Infrastructure Program (TRIP), which would provide a current return on and return of any capital invested in this program. NJNG estimates that it would invest approximately $14 million under this program. The BPU is currently reviewing this proposal.

In June 2003, the BPU approved a 10-year transportation agreement between NJNG and Ocean Peaking Power, LLC, to provide transportation service to a new natural gas-fired electric generation plant in Lakewood, New Jersey. NJNG’s transportation agreement became effective on June 1, 2003, and will benefit customers by providing additional credits against natural gas costs, with sales principally made during nonpeak times. Gross margin from these sales over the first four years will be shared with customers and shareowners on a 50/50 percent basis.

NJNG is also involved in various proceedings associated with several other adjustment clauses, which in NJNG’s opinion will not have a material adverse impact on its financial condition or results of operations.

8. Employee Benefit Plans

Pension Plans

The Company has two trusteed, noncontributory defined benefit retirement plans covering regular represented and nonrepresented employees with more than one year of service. All represented employees of NJRHS hired on or after October 1, 2000, are covered by an enhanced defined contribution plan instead of the defined benefit plan.

Defined benefit plan benefits are based on years of service and average compensation during the highest 60 consecutive months of employment.

The components of the qualified plans net pension cost were as follows:

(Thousands)	2003			2002			2001
Service cost	$	2,394		$	1,957		$	1,622
Interest cost		5,100			4,813			4,365
Expected return on plan assets		(5,863	)		(6,065	)		(5,996	)
Amortization of prior service cost		87			87			87
Recognized actuarial (gain) loss		220			—			(356	)
Recognized net initial obligation		(287	)		(306	)		(306	)
Recognized actuarial loss due to special termination		—			—			574
Net periodic pension cost	$	1,651		$	486		$	(10	)

A reconciliation of the funded status of the plans to the amounts recognized on the Consolidated Balance Sheets is presented below:

(Thousands)		2003			2002
Change in Projected Benefit Obligation (PBO)
PBO at beginning of year		$	77,125		$	65,407
Service cost			2,394			1,957
Interest cost			5,100			4,813
Plan participants’ contributions			64			62
Actuarial loss			2,324			8,068
Benefits paid			(3,380	)		(3,182	)
PBO at end of year		$	83,627		$	77,125
Change in plan assets
Fair value of plan assets at beginning of year		$	44,109		$	51,830
Actual return on plan assets			7,907			(4,601	)
Employer contributions			13,700			—
Plan participants’ contributions			64			62
Benefits paid			(3,380	)		(3,182	)
Fair value of plan assets at end of year		$	62,400		$	44,109
Funded status		$	(21,227	)	$	(33,016	)
Unrecognized actuarial loss			29,284			29,225
Unrecognized prior service cost			403			489
Unrecognized net initial obligation			(238	)		(526	)
Net amount recognized		$	8,222		$	(3,828	)
Amounts recognized on Consolidated Balance Sheets
Accrued benefit liability included in:
	Postretirement employee benefit liability — current		—		$	(2,417	)
	Postretirement employee benefit liability	$	(10,673	)		(16,211	)
Intangible asset			473			215
Accumulated other comprehensive income			18,422			14,585
Net amount recognized		$	8,222		$	(3,828	)

The accumulated benefit obligation (ABO) at September 30, 2003 and 2002, was $73.1 million and $62.7 million, respectively.

Pursuant to SFAS No. 87, “Employers Accounting for Pensions” (SFAS 87), the Company was required to record a $4.1 million additional minimum pension liability in 2003, which is included in Postretirement employee benefit liability on the Consolidated Balance Sheets. In 2002, the Company recorded a $14.8 million additional minimum pension liability that resulted from a decrease in the fair value of plan assets, which was due primarily to declining stock market values and a decrease in the discount rate.

The Company’s funding policy is to contribute at least the minimum amount required by the Employment Retirement Income Security Act of 1974, as amended. In 2003, the Company contributed $13.7 million to its pension plans, of which $2.4 million represented the required minimum funding. The Company elected to make the additional tax deductible contributions to improve the funded status of the plans. In 2004, the Company has no minimum funding requirements and currently does not anticipate making any discretionary contributions. The Company was not required to, and did not, make contributions to its pension plans in 2002 and 2001.

The weighted average assumptions are as follows:

	2003			2002			2001
Discount rate		6.00	%		6.75	%		7.50	%
Expected asset return		9.00	%		9.25	%		9.50	%
Compensation increase		3.75	%		4.00	%		4.00	%

The mix and targeted allocation of the pension plans’ assets are as follows:

										Weighted
	2004			Assets						Avg. Expected
	Target			at Sept. 30,						Long-term
Asset Allocation	Allocation			2003			2002			Rate of Return
U.S. equity securities		52	%		53	%		50	%		9.6	%
International equity securities		18	%		17	%		17	%		10.4	%
Fixed income		30	%		30	%		33	%		7.1	%
Total		100	%		100	%		100	%		9.0	%

The Company maintains an unfunded nonqualified pension equalization plan (PEP) that was established to provide employees with the full level of benefits as stated in the qualified plan without reductions due to various limitations imposed by the provisions of federal income tax laws and regulations. There were no plan assets in the nonqualified plan due to the nature of the plan. The Company recorded a $73,000 and $63,000 net periodic PEP cost in 2003 and 2002, respectively. The PEP weighted averaged assumptions are identical to the qualified pension plan assumptions.

The PBO and ABO for the Company’s nonfunded PEP were $423,000 and $325,000, respectively, as of September 30, 2003, and $446,000 and $213,000, respectively, as of September 30, 2002.

Other Postretirement Benefit Plans (OPEB)

The Company provides postretirement medical and life insurance benefits to employees who meet the eligibility requirements. The Company’s transition obligation associated with these benefits of $8.6 million is being amortized over 20 years.

Effective October 1, 1998, the BPU approved the recovery of $4.9 million of deferred costs over 15 years, which is included in Regulatory assets on the Consolidated Balance Sheets.

The components of the net OPEB cost are as follows:

(Thousands)		2003			2002			2001
Service cost		$	922		$	799		$	615
Interest cost			1,862			1,777			1,519
Expected return on plan assets			(577	)		(520	)		(555	)
Amortization of
	Transition obligation		357			357			372
	Prior service cost		74			74			84
	Loss		486			335			65
Special termination benefit			—			—			168
Net periodic OPEB cost		$	3,124		$	2,822		$	2,268

A reconciliation of the funded status of the plans to the amounts recognized on the Consolidated Balance Sheets at September 30, 2003 and 2002, is presented below:

(Thousands)	2003			2002
Change in PBO
PBO at beginning of year	$	27,306		$	23,656
Service cost		922			799
Interest cost		1,862			1,777
Actuarial loss		4,420			2,063
Benefits paid		(1,006	)		(989	)
PBO at end of year	$	33,504		$	27,306
Change in plan assets
Fair value of plan assets at beginning of year	$	6,266		$	5,458
Actual return on plan assets		1,097			(445	)
Employer contributions		2,001			2,242
Benefits paid		(1,006	)		(989	)
Fair value of plan assets at end of year		8,358			6,266
Funded status		(25,146	)		(21,040	)
Unrecognized transition obligation		3,598			3,955
Unrecognized prior service cost		612			686
Unrecognized net loss		13,708			10,294
Net amount recognized	$	(7,228	)	$	(6,105	)
Amounts recognized on Consolidated Balance Sheets
Postretirement employee benefit liability — current	$	(3,308	)	$	(2,579	)
Postretirement employee benefit liability		(3,920	)		(3,526	)
Net amount recognized	$	(7,228	)	$	(6,105	)

Based upon certain regulatory and actuarial assumptions, the Company anticipates making contributions of approximately $3.3 million in 2004.

Effect of a 1 percentage point increase in the health care cost trend rate (HCCTR) on:

(Thousands)	2003		2002
Year-end benefit obligation	$	5,527	$	4,474
Total service and interest cost	$	566	$	485

Effect of a 1 percentage point decrease in the HCCTR on:

(Thousands)	2003			2002
Year-end benefit obligation	$	(4,425	)	$	(3,585	)
Total service and interest cost	$	(439	)	$	(375	)

The assumed HCCTR used in measuring the PBO as of September 30, 2003, was 9.5 percent, gradually declining to 4.5 percent in 2008, and then remaining constant thereafter.

The weighted average assumptions are as follows:

(Thousands)	2003			2002			2001
Discount rate		6.00	%		6.75	%		7.50	%
Expected asset return		8.50	%		8.75	%		9.00	%
Compensation increase		3.75	%		4.00	%		4.00	%
Initial HCCTR		9.50	%		9.00	%		10.00	%
Ultimate HCCTR		4.50	%		4.50	%		5.00	%
Year ultimate HCCTR reached		2008			2007			2006

The Company’s OPEB plan assets consist of the same mix and targeted allocation as the pension plans. The weighted average long-term rate of return on plan assets in the OPEB plan is 50 basis points lower than that of the pension plan assets due to less favorable tax treatment.

Defined Contribution Plan

The Company offers an Employees’ Retirement Savings Plan (Savings Plan) to eligible employees. The Company matches 50 percent of participants’ contributions up to 6 percent of base compensation.

For represented NJRHS employees who are not eligible for participation in the defined benefit plan, the Company contributes between 2 and 3 percent of base compensation, depending on service, into the Savings Plan on their behalf.

The amount expensed for the matching provision of the Savings Plan was $978,000, $959,000 and $719,000 in 2003, 2002 and 2001, respectively.

9. Financial Instruments and Risk Management

The Company and its subsidiaries are subject to market risk due to fluctuations in the price of natural gas. To hedge against such fluctuations, the Company and its subsidiaries enter into futures contracts, option agreements and over-the-counter swap agreements. NJNG’s recovery of natural gas costs is governed by the BGSS, but to hedge against price fluctuations, NJNG utilizes futures, options and

swaps through its corporate financial risk management program. NJRES hedges purchases and sales of storage gas and transactions with wholesale customers. NJR Energy has hedged a long-term, fixed-price contract to sell natural gas. The amounts included in Other comprehensive income related to natural gas instruments, which have been designated cash flow hedges, will reduce or increase gas costs as the underlying physical transaction occurs. Based on the amount recorded in Accumulated other comprehensive income at September 30, 2003, $6.9 million is expected to be recorded as a decrease to gas costs in 2004.

The following table reflects the changes in the fair market value of commodity derivatives from September 30, 2002, to September 30, 2003:

	Balance			Increase			Less			Balance
	Sept. 30,			(Decrease) in Fair			Amounts			Sept. 30,
(Thousands)	2002			Market Value			Settled			2003
NJNG	$	(2,564	)	$	(17,289	)	$	9,017		$	(28,870	)
NJRES		(14,689	)		(11,707	)		(32,180	)		5,784
NJR Energy		3,362			17,246			5,668			14,940
Total	$	(13,891	)	$	(11,750	)	$	(17,495	)	$	(8,146	)

     There were no contracts originated and valued at fair market value and no changes in methods of valuations during the year ended September 30, 2003.

     The following is a summary of fair market value of commodity derivatives at September 30, 2003, by method of valuation and by maturity:

							After			Total
(Thousands)	2004			2005-2007			2007			Fair Value
Price based on NYMEX	$	(8,808	)	$	(11,690	)	$	(8,473	)	$	(28,971	)
Price based on over-the-counter published quotations		7,347			9,693			1,610			18,650
Price based upon models		—			525			1,650			2,175
Total	$	(1,461	)	$	(1,472	)	$	(5,213	)	$	(8,146	)

The following is a summary of commodity derivatives by type as of September 30, 2003:

		Net			Amount Included
		Volume	Price per		in Derivatives
		(Bcf)	Mmbtu		(Thousands)
NJNG
	Futures	0.5		$5.11 – $5.21	$	302
	Options	(1.7)		$3.25 – $10.00		(9,474	)
	Swaps	32.5				(19,698	)
NJRES
	Futures	(18.0)		$4.46 – $5.26		1,262
	Options	0.9		$5.22 – $5.32		89
	Swaps	38.9				4,433
NJR Energy
	Swaps	19.4				14,940
Total					$	(8,146	)

In March 1992, NJR Energy entered into long-term, fixed-price contracts to sell natural gas (Gas Sale Contracts) to an energy marketing company. In October 1994, in conjunction with a shift in capital allocation policy, NJR Energy entered into a swap agreement that hedged its risk for sales volumes under the Gas Sale Contracts that were in excess of the estimated production from natural gas reserves owned at that time. NJR Energy subsequently sold its natural gas reserves pursuant to a plan to exit the oil and natural gas production business. To hedge its risk for sales volumes under the Gas Sale Contracts, which would have otherwise been fulfilled by its producing reserve base, NJR Energy entered into a second swap agreement in June 1995. Under the terms of the swap agreements, NJR Energy pays to the counterparties the identical fixed price it receives from the natural gas marketing company in exchange for the payment by the counterparties of an index price plus a spread per Mmbtu (i.e., floating price) for the total volumes under the Gas Sale Contracts. The swap agreements were effective as of November 1995 and will expire on the same date as the underlying Gas Sale Contracts.

To secure the physical natural gas supply needed to meet the delivery requirements under its Gas Sale Contracts, NJR Energy entered into a long-term purchase contract, effective November 1995, with a second natural gas marketing company for the identical volumes that it is obligated to sell under the above-mentioned Gas Sale Contracts. NJR Energy has agreed to pay the supplier the identical floating price that it is receiving under the swap agreements.

The net result of the above swap agreements and purchase contract is that NJR Energy has hedged both its price and volume risk associated with its Gas Sale Contracts. The respective obligations of NJR Energy and the counterparties under the swap agreements are guaranteed, subject to a maximum amount, by the Company and the respective counterparties’ parent corporations. In the event of nonperformance by the counterparties and their parent corporations, NJR Energy’s financial results would be impacted by the difference, if any, between the fixed price it is receiving under the Gas Sale Contracts and the floating price that it is paying under the purchase contract. However, the Company does not anticipate nonperformance by the counterparties.

The fair value of cash and temporary investments, accounts receivable, accounts payable, commercial paper and borrowings under revolving credit facilities is estimated to equal their carrying amounts due to the short maturity of those instruments. The estimated fair value of long-term debt is based on quoted market prices for similar issues. The carrying amount of long-term debt was $207.8 million and $348.1 million, with a fair market value of $217.1 million and $357.9 million, at September 30, 2003 and 2002, respectively.

Effective October 1, 2000, the Company adopted SFAS 133. (See Note 1: Summary of Significant Accounting Policies – Derivative Activities.)

At October 1, 2000, the effect of adopting SFAS 133 was as follows:

(Thousands)
Fair value of derivative assets	$	56,963
Fair value of derivative liabilities	$	17,657
Regulatory liability	$	6,834
Cumulative effect on net income from a change in accounting, net of tax	$	(1,347	)
Accumulated other comprehensive income, net of tax	$	20,530

The cumulative effect on net income from a change in accounting resulted from derivatives that do not qualify for hedge accounting.

The amounts included in Other comprehensive income that relate to natural gas instruments will reduce or be charged to gas costs as the related transactions effects earnings. Of the amount recorded to Other comprehensive income on the October 1, 2000 transition date, $20.1 million was recorded as a reduction to gas costs in fiscal 2001. The amounts related to interest rate instruments are charged to interest expense as the forecasted transactions effects earnings.

In July 2001, the Company entered into a 5-year, zero-premium collar to hedge changes in the value of 100,000 shares of its investment in Capstone Turbine Corporation (Capstone). The collar consists of a purchased put option with a strike price of $9.97 per share and a sold call option with a strike price of $24.16 per share for 100,000 shares. The Company entered into this transaction to hedge its anticipated sale of 100,000 shares of Capstone at the settlement date in 2006 and, accordingly, accounts for the transaction as a cash flow hedge. Other comprehensive income for the year ended September 30, 2003, included a $90,000 unrealized loss related to this collar. At September 30, 2003, Accumulated other comprehensive income included a $751,000 unrealized gain related to this collar.

The ineffective portions of derivatives qualifying for hedge accounting were immaterial in 2003.

The cash flow hedges described above cover various periods of time ranging from November 2002 to October 2010.

10. Commitments and Contingent Liabilities

NJNG has entered into long-term contracts, expiring at various dates through 2022, for the supply, storage and delivery of natural gas. These contracts include fixed charges of approximately $94 million annually at current contract rates and volumes, which are recovered through the BGSS.

NJNG’s capital expenditures are estimated at $66 million and $69 million in 2004 and 2005, respectively, and consist primarily of its construction program to support customer growth, maintenance of its distribution system, upgrades in targeted areas and replacement needed under proposed pipeline safety rulemaking. In addition, CR&R expects $15.8 million of capital expenditures in 2004 to complete a 200,000-square-foot build-to-suit building.

The Company’s future minimum lease payments under various operating leases are less than $2.5 million annually for the next five years and $428,000 in the aggregate for all years thereafter.

NJNG identified 11 former MGP sites, dating back to the late 1800s and early 1900s, which contain contaminated residues from the former gas manufacturing operations. Ten of the 11 sites in question were acquired by NJNG in 1952. Gas manufacturing operations ceased at these sites at least by the mid-1950s and, in some cases, had been discontinued many years earlier. All of the former gas manufacturing facilities were subsequently dismantled by NJNG or the previous owners. Since October 1989, NJNG has entered into Administrative Consent Orders or Memoranda of Agreement with the New Jersey Department of Environmental Protection (NJDEP) covering all 11 sites. These orders and agreements establish the procedures to be followed in developing a final remedial cleanup plan for each site. NJNG is currently involved in administrative proceedings with the NJDEP with respect to the plant sites in question, and is participating in various studies and investigations by outside consultants to determine the nature and extent of any such contaminated residues and to develop appropriate programs of remedial action, where warranted. Until September 2000, most of the cost of such studies and investigations had been shared under an agreement with the former owner and operator of 10 of the MGP sites. In September 2000, a revised agreement was executed pursuant to which NJNG is responsible for two of the sites, while the former owner is responsible for the remaining eight sites. Also in September 2000, NJNG purchased a 20-year cost-containment insurance policy for its two remaining sites. NJNG continues to participate in the investigation and remedial action for the MGP site that was not subject to the original cost-sharing agreement.

In June 1992, the BPU approved a remediation rider through which NJNG recovers its remediation expenditures over a 7-year period. NJNG is currently recovering its remediation expenditures incurred through June 30, 1998. Costs incurred subsequent to June 30, 1998, including carrying costs on deferred expenditures (See Note 1: Summary of Significant Accounting Policies – Capitalized and Deferred Interest), will be recovered over rolling 7-year periods, subject to BPU approval. In September 1999 and January 2001, NJNG filed for recovery of remediation expenditures incurred in the years ended June 30, 1999 and 2000, respectively. In March 2003, NJNG filed testimony for recovery of remediation expenditures for the 2-year

period ending June 30, 2002. The BPU is currently reviewing these three filings and, while NJNG believes that all costs are probable of recovery, no assurance can be given as to the ultimate resolution of this matter. As of September 30, 2003, $44.1 million of previously incurred remediation costs, net of recoveries from customers and insurance, are included in Regulatory assets on the Consolidated Balance Sheet.

In September 2003, with the assistance of an outside consulting firm, NJNG updated an environmental review of the MGP sites, including a review of their potential liability for investigation and remedial action. Based on this review, NJNG estimates that, exclusive of any insurance recoveries, total future expenditures to remediate and monitor the three MGP sites it is responsible for will range from $108.8 million to $146.3 million. NJNG’s estimate of these liabilities is based upon currently available facts, existing technology and presently enacted laws and regulations. However, actual costs may differ from these estimates. Where available information is sufficient to estimate the amount of the liability, it is NJNG’s policy to accrue the full amount of such estimate. Where the information is sufficient only to establish a range of probable liability and no point within the range is more likely than any other, it is NJNG’s policy to accrue the lower end of the range. Accordingly, NJNG has recorded an MGP remediation liability and a corresponding Regulatory asset of $108.8 million on the Consolidated Balance Sheet. The actual costs to be incurred by NJNG are dependent upon several factors, including final determination of remedial action, changing technologies and governmental regulations, the ultimate ability of other responsible parties to pay and any insurance recoveries. NJNG will continue to seek recovery of such costs through its remediation rider. If any future regulatory position indicates that the recovery of such costs is not probable, the related cost would be charged to income.

NJRES is the marketing agent for the Stagecoach storage project. Stagecoach is a high-injection/high-withdrawal facility in New York State with 12 billion cubic feet (Bcf) of working natural gas capacity with a connection to the Tennessee Gas Pipeline.

NJRES’ marketing and management agreement ends March 31, 2012, subject to termination rights. During this period, NJRES has agreed to arrange contracts for, or purchase at fixed prices, sufficient services to provide Stagecoach with revenues of approximately $22 million annually from April 1, 2003, to March 31, 2012. Stagecoach must notify NJRES of its intent to sell services under the aforementioned contract by November 30 of the prior annual period. Stagecoach did not notify NJRES of its intent to sell services for the annual period ended March 31, 2004. Therefore, NJRES has no purchase obligation related to this period. NJRES has reached 1- to 5-year agreements with Stagecoach customers with varying expiration dates, the last of which is August 31, 2008. The value of these services totals 85 percent, 37 percent, 20 percent and 13 percent of the Company’s potential purchase obligation for the annual periods ended March 31, 2005 through 2008, respectively.

In August 2002, NJNG, in connection with its system requirements, was awarded 2-year agreements for Stagecoach storage and transportation services ending July 31, 2004. These agreements were awarded pursuant to an open bid process.

Due to the price levels of the potential purchase obligations to NJRES, as compared with current market prices, and the current and expected level of contracts, the Company does not currently believe that the potential purchase obligation in the Stagecoach agreement will result in any material future losses.

Under the Stagecoach agreement, NJRES is also required to provide and maintain 2 Bcf of firm base gas at the Stagecoach facility for the term of the agreement.

Since July 1, 2003, multiple lawsuits have been filed in the Superior Court of New Jersey, Monmouth County, Law Division, against NJNG and the Company alleging, among other things, personal injuries relating to the former MGP site in Long Branch, New Jersey. The relief sought by the plaintiffs includes compensatory damages, medical monitoring, disgorgement of profits, costs of cleanup, remediation and punitive damages.

The Company has made a demand on its insurance carriers for coverage, and one of its insurance carriers has advised that it will provide the Company legal defense coverage, subject to a reservation of rights. NJNG is also defending the former owner of the MGP site pursuant to an indemnity agreement.

The Company believes that it is not liable under the allegations of the complaints, and further believes that any liability that could possibly be assessed against it, with the exception of liability for punitive damages, would be recoverable through insurance or may be recoverable through the remediation rider. No assurance can be given as to the ultimate resolution of this matter or the impact on the Company’s financial condition, results of operations or cash flows.

The Company is a party to other various claims, legal actions, complaints and investigations arising in the ordinary course of business. In management’s opinion, the ultimate disposition of these matters will not have a material adverse effect on either the Company’s financial condition or results of operations.

11. Business Segment Data

Information related to the Company’s various business segments, excluding capital expenditures, which are presented in the Consolidated Statements of Cash Flows, is detailed below.

The Natural Gas Distribution segment consists of regulated energy and off-system and capacity management operations. The Energy Services segment consists of unregulated fuel and capacity management and wholesale marketing operations. The Retail and Other segment consists of appliance and installation services, commercial real estate development, investment and other corporate activities.

(Thousands)		2003			2002			2001
Operating Revenues
	Natural Gas Distribution	$	759,878		$	774,541		$	1,009,477
	Energy Services		1,766,265			1,037,417			1,022,734
	Retail and Other		21,927			19,711			21,474
Total before eliminations			2,548,070			1,831,669			2,053,685
	Intersegment revenues		(3,691	)		(165	)		(5,277	)
Total		$	2,544,379		$	1,831,504		$	2,048,408
Depreciation and Amortization
	Natural Gas Distribution	$	31,192		$	31,044		$	31,676
	Energy Services		189			219			250
	Retail and Other		584			581			604
Total		$	31,965		$	31,844		$	32,530
Operating Income
	Natural Gas Distribution	$	97,408		$	88,883		$	89,248
	Energy Services		19,454			11,430			5,638
	Retail and Other		4,489			4,442			5,034
Total		$	121,351		$	104,755		$	99,920

The Company’s assets for the various business segments are detailed below:

(Thousands)		2003		2002
Assets at Year-End
	Natural Gas Distribution	$	1,285,894	$	1,127,195
	Energy Services		213,253		276,471
	Retail and Other		71,832		51,923
Total		$	1,570,979	$	1,455,589

12. Selected Quarterly Data (Unaudited)

A summary of financial data for each fiscal quarter of 2003 and 2002 follows. Due to the seasonal nature of the Company’s businesses, quarterly amounts vary significantly during the year. In the opinion of management, the information furnished reflects all adjustments necessary for a fair presentation of the results of the interim periods.

(Thousands, except		First		Second		Third		Fourth
per share data)		Quarter		Quarter		Quarter		Quarter
2003
Operating revenues		$	668,779	$	1,152,851	$	369,660	$	353,089
Operating income		$	41,669	$	71,885	$	9,665	$	(1,868	)
Net income		$	23,323	$	41,244	$	4,473	$	(3,628	)
Earnings per share
	Basic	$	.86	$	1.52	$	.16	$	(.13	)
	Diluted	$	.85	$	1.50	$	.16	$	(.13	)
2002
Operating revenues		$	395,831	$	525,780	$	442,684	$	467,209
Operating income		$	34,847	$	59,425	$	9,725	$	758
Net income		$	19,681	$	34,930	$	4,764	$	(2,531	)
Earnings per share
	Basic	$	.74	$	1.30	$	.18	$	(.09	)
	Diluted	$	.73	$	1.29	$	.17	$	(.09	)

13. Subsequent Event - Asset Removal Obligations

As disclosed in Note 1 to the consolidated financial statements, the Company had asset removal costs recovered through prices in excess of actual costs incurred of $71.5 million and $67.8 million at September 30, 2003 and 2002, respectively. Based upon interpretation of SFAS 143 and related SEC guidance at the time of filing of the Company’s Annual Report on Form 10-K for its fiscal year ended September 30, 2003, the amount of asset removal costs recovered through prices in excess of actual costs at September 30, 2002 was included in Accumulated depreciation. Based on recent SEC guidance, the amount of asset removal costs recovered through prices in excess of actual costs at September 30, 2002 was reclassified on March 19, 2004, from Accumulated depreciation to non-current liabilities and is included in Regulatory and cost of removal liabilities.