SOUTHWESTERN ENERGY CO - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 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 June 30, 2003

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 1-8246

SOUTHWESTERN ENERGY COMPANY
(Exact name of the registrant as specified in its charter)

Arkansas		71-0205415
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2350 N. Sam Houston Pkwy. E., Suite 300, Houston, Texas 77032
(Address of principal executive offices, including zip code)

(281) 618-4700
(Registrant's telephone number, including area code)

Not Applicable
(Former name, former address and former fiscal year: if changed since last report)

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 and Exchange Act of 1934 during the preceding twelve 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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes: X		No:

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

Class		Outstanding at July 24, 2003
Common Stock, Par Value $0.10		35,575,442

PART I

FINANCIAL INFORMATION


SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

		For the three months ended				For the six months ended
		June 30,				June 30,
		2003		2002		2003		2002
		(in thousands, except share/per share amounts)
Operating Revenues:
	Gas sales	$	49,286	$	37,606	$	126,993	$	104,592
	Gas marketing		11,667		12,228		24,273		21,930
	Oil sales		3,821		4,416		7,280		7,599
	Gas transportation and other		1,713		1,754		6,596		3,541
			66,487		56,004		165,142		137,662
Operating Costs and Expenses:
	Gas purchases - utility		2,199		3,804		29,247		28,572
	Gas purchases - marketing		10,850		11,454		22,408		20,127
	Operating expenses		9,248		9,505		18,294		19,063
	General and administrative expenses		7,663		6,034		15,546		11,824
	Depreciation, depletion and amortization		13,686		13,868		26,069		27,738
	Taxes, other than income taxes		2,895		2,439		5,958		4,599
			46,541		47,104		117,522		111,923
Operating Income			19,946		8,900		47,620		25,739

Interest Expense:
	Interest on long-term debt		4,075		5,345		9,002		10,699
	Other interest charges		337		336		722		658
	Interest capitalized		(501)		(360)		(866)		(651)
			3,911		5,321		8,858		10,706
Other Income (Expense)			(63)		(232)		1,359		(474)

Income Before Income Taxes, Minority Interest & Accounting Change			15,972		3,347		40,121		14,559
Minority Interest in Partnership			(609)		(469)		(1,374)		(762)

Income Before Income Taxes & Accounting Change			15,363		2,878		38,747		13,797
Provision for Income Taxes - Deferred			5,837		1,108		14,724		5,312

Income Before Accounting Change			9,526		1,770		24,023		8,485
Cumulative Effect of Adoption of Accounting Principle			-		-		(855)		-

Net Income		$	9,526	$	1,770	$	23,168	$	8,485

Basic Earnings Per Share:
	Income Before Accounting Change		$0.27		$0.07		$0.76		$0.34
	Cumulative Effect of Adoption of Accounting Principle		-		-		(0.03)		-
	Net Income		$0.27		$0.07		$0.73		$0.34

Diluted Earnings Per Share:
	Income Before Accounting Change		$0.26		$0.07		$0.74		$0.33
	Cumulative Effect of Adoption of Accounting Principle		-		-		(0.03)		-
	Net Income		$0.26		$0.07		$0.71		$0.33

Weighted Average Common Shares Outstanding:
	Basic		35,053,171		25,208,974		31,614,921		25,146,550
	Diluted		36,087,726		26,131,452		32,558,360		25,995,692

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

2


SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)

ASSETS

			June 30,		December 31,
			2003		2002
			(in thousands)
Current Assets
	Cash		$	2,013	$	1,690
	Accounts receivable			38,174		42,115
	Inventories, at average cost			19,837		24,735
	Hedging asset - SFAS No. 133			29		3,130
	Other			5,361		4,468
		Total current assets		65,414		76,138

Investments				14,231		15,287

Property, Plant and Equipment, at cost
	Gas and oil properties, using the full cost method			1,105,819		1,030,300
	Gas distribution systems			201,821		197,473
	Gas in underground storage			34,100		32,395
	Other			31,997		31,391
				1,373,737		1,291,559
	Less: Accumulated depreciation, depletion and amortization			680,391		659,398
				693,346		632,161

Other Assets				15,788		16,576

Total Assets			$	788,779	$	740,162

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

3

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)

LIABILITIES AND SHAREHOLDERS' EQUITY

			June 30,		December 31,
			2003		2002
			(in thousands)
Current Liabilities
	Accounts payable		$	32,401	$	29,881
	Taxes payable			2,973		5,213
	Interest payable			2,217		2,513
	Customer deposits			4,879		4,999
	Hedging liability - SFAS No. 133			29,968		20,409
	Regulatory liability - hedges			-		3,130
	Over-recovered purchased gas costs			2,032		5,697
	Other			2,982		2,715
		Total current liabilities		77,452		74,557

Long-Term Debt				247,800		342,400

Other Liabilities
	Deferred income taxes			125,486		116,591
	Other			27,654		16,671
				153,140		133,262

Commitments and Contingencies

Minority Interest in Partnership				13,298		12,455

Shareholders' Equity
	Common stock, $.10 par value; authorized 75,000,000 shares, issued 37,225,584 shares			3,723		2,774
	Additional paid-in capital			121,149		19,130
	Retained earnings			221,156		197,988
	Accumulated other comprehensive income (loss)			(26,299)		(17,358)
				319,729		202,534
	Less:	Common stock in treasury, at cost, 1,650,492 shares at June 30, 2003 and 1,793,456 shares at December 31, 2002		18,388		19,981
		Unamortized cost of 496,429 restricted shares at June 30, 2003 and 498,123 restricted shares at December 31, 2002 issued under stock incentive plans		4,252		5, 065
				297,089		177,488

Total Liabilities and Shareholders' Equity			$	788,779	$	740,162

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

4

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

			For the six months ended
			June 30,
			2003		2002
			(in thousands)
Cash Flows From Operating Activities
	Net income		$	23,168	$	8,485
	Adjustments to reconcile net income to
	net cash provided by operating activities:
		Depreciation, depletion and amortization		27,668		28,939
		Deferred income taxes		14,724		5,312
		Ineffectiveness of cash flow hedges		(556)		-
		Equity in (income) loss of NOARK partnership		(1,444)		361
		Minority interest in partnership		799		160
		Cumulative effect of adoption of accounting principle		855		-
	Change in assets and liabilities:
		Accounts receivable		3,941		13,976
		Inventories		4,898		1,172
		Over-recovered purchased gas costs		(3,664)		(1,452)
		Accounts payable		2,303		(14,196)
		Taxes payable		(2,209)		(1,594)
		Other operating assets and liabilities		(175)		1,093
	Net cash provided by operating activities			70,308		42,256

Cash Flows From Investing Activities
	Capital expenditures			(80,468)		(40,774)
	Distribution from NOARK partnership			2,500		-
	(Increase) decrease in gas stored underground			(1,705)		1,239
	Other items			(479)		1,927
	Net cash used in investing activities			(80,152)		(37,608)

Cash Flows From Financing Activities
	Issuance of common stock			103,213		-
	Payments on revolving long-term debt			(184,900)		(120,200)
	Borrowings under revolving long-term debt			90,300		114,700
	Change in bank drafts outstanding			218		-
	Proceeds from exercise of common stock options			1,292		-
	Minority interest contributions			44		-
	Net cash provided by (used in) financing activities			10,167		(5,500)

Increase (decrease) in cash				323		(852)
Cash at beginning of year				1,690		3,641
Cash at end of period			$	2,013	$	2,789

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

5


SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)

											Unamortized		Accumulated
					Additional						Restricted		Other
	Common Stock				Paid-In		Retained		Treasury		Stock		Comprehensive
	Shares		Amount		Capital		Earnings		Stock		Awards		Income (Loss)		Total
						(in thousands)
Balance at December 31, 2002	27,738	$	2,774	$	19,130	$	197,988	$	(19,981)	$	(5,065)	$	(17,358)	$	177,488
Comprehensive income:
Net Income	-		-		-		23,168		-		-		-		23,168
Change in value of derivatives	-		-		-		-		-		-		(8,941)		(8,941)
Total comprehensive income (loss)	-		-		-		-		-		-		-		14,227

Issuance of common stock	9,488		949		102,264		-		-		-		-		103,213
Exercise of stock options	-		-		(252)		-		1,544		-		-		1,292
Issuance of restricted stock	-		-		7		-		49		(56)		-		-
Amortization of restricted stock	-		-		-		-		-		869		-		869

Balance at June 30, 2003	37,226	$	3,723	$	121,149	$	221,156	$	(18,388)	$	(4,252)	$	(26,299)	$	297,089


RECONCILIATION OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

		For the three months ended				For the six months ended
		June 30,				June 30,
			2003		2002		2003		2002
			(in thousands)				(in thousands)

Balance, beginning of period		$	(21,342)	$	(7,825)	$	(17,358)	$	5,763
	Current period reclassification to earnings		5,075		2,432		16,963		656
	Current period change in derivative instruments		(10,032)		(961)		(25,904)		(12,773)
Balance, end of period		$	(26,299)	$	(6,354)	$	(26,299)	$	(6,354)

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

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southwestern Energy Company and Subsidiaries

June 30, 2003

(1) BASIS OF PRESENTATION

The financial statements included herein are unaudited;
however, such information reflects all adjustments (consisting solely of normal
recurring adjustments) which are, in the opinion of management, necessary for a
fair presentation of the results for the interim periods. The Company's
significant accounting policies are summarized in Note 1 in the Notes to
Consolidated Financial Statements included in Item 8 of the Company's Annual
Report on Form 10-K for the year ended December 31, 2002 (the "2002 Annual
Report on Form 10-K").

(2) ISSUANCE OF COMMON STOCK

In the first quarter of 2003, the Company
completed the sale of 9,487,500 shares of its common stock under a registration
statement filed with the Securities and Exchange Commission in December 2002.
Aggregate net proceeds from the equity offering of $103.2 million
were used to pay outstanding borrowings under the Company's revolving credit
facility. The Company will reborrow the repaid amounts under the credit facility
as necessary to fund the acceleration of the development of the Company's
Overton Field in East Texas and for general corporate purposes.

(3) GAS AND OIL PROPERTIES

The Company follows the full cost method of accounting for the exploration,
development, and acquisition of gas and oil reserves. Under this method, all
such costs (productive and nonproductive) including salaries, benefits, and
other internal costs directly attributable to these activities are capitalized
and amortized on an aggregate basis over the estimated lives of the properties
using the units-of-production method. The Company excludes all costs of
unevaluated properties from immediate amortization. The Company's unamortized
costs of natural gas and oil properties are limited to the sum of the future net
revenues attributable to proved natural gas and oil reserves discounted at 10
percent plus the lower of cost or market value of any unproved properties. If
the Company's unamortized costs in natural gas and oil properties exceed this
ceiling amount, a provision for additional depreciation, depletion and
amortization is required. At June 30, 2003, the Company's net book value of
natural gas and oil properties did not exceed the ceiling amount. Decreases in
market prices from June 30, 2003 levels, as well as changes in production rates,
levels of reserves, and the evaluation of costs excluded from amortization,
could result in future ceiling test impairments.

Statement of Financial Accounting Standards No. 141, "Business Combinations" (FAS
141), and Statement of Financial Accounting Standards No. 142, "Goodwill and
Intangible Assets" (FAS 142), were issued in June 2001 and became effective for
the Company on July 1, 2001, and January 1, 2002, respectively.
The Company understands
the majority of the oil and natural gas industry did not change its accounting
and disclosures for mineral interest use rights (leasehold acquisition costs) upon the implementation of FAS
141 and 142. However, an interpretation of

FAS 141 and 142 is being deliberated
by the Securities and Exchange Commission, Financial Accounting Standards Board and others as to whether mineral interest use rights in oil and
natural gas properties are intangible assets. Under this interpretation mineral
interest use rights for both undeveloped and developed leaseholds would be
classified as an asset separate from oil and natural gas properties as
intangible assets. The classification as an intangible asset would not affect
how these items are accounted for under the full cost method of accounting with
respect to the calculation of depreciation, depletion and amortization or the
calculation of the ceiling test of oil and natural gas properties. At June
30, 2003
the Company has undeveloped leasehold of
approximately $8.3 million that would be classified as "intangible
undeveloped leasehold."
Southwestern also
has developed leasehold of
approximately $7.2 million that would be classified as "intangible developed
leasehold" if
it applied the interpretation currently being deliberated. The
portion of developed leasehold that would be reclassified represents the costs
of developed leaseholds acquired or transferred to the full cost pool subsequent
to June 30, 2001, the effective date of FAS 141.

Additionally, FAS 142 requires that certain disclosures be made for all
intangible assets.
The Company has not made the disclosures set forth under FAS 142
related to the use rights of mineral interests.
The Company has continued to make the disclosures required by
Statement of Financial Accounting Standards No. 69 "Disclosures about Oil and
Gas Producing Activities" (FAS 69).

Southwestern
will continue to classify use rights of mineral
interests in oil and gas properties until further guidance is provided that
might result from the deliberations described above.

(4)
EARNINGS PER SHARE

Basic earnings per common share is computed by
dividing net income by the weighted average number of common shares outstanding
during each period. The diluted earnings per share calculation adds to the
weighted average number of common shares outstanding the incremental shares that
would have been outstanding assuming the exercise of dilutive stock options and
the vesting of unvested restricted shares of common stock. The Company had
options for 70,984 shares of common stock with a weighted average exercise price
of $17.19 per share at June 30, 2003, and options for 538,934 shares with an
average exercise price of $14.95 per share at June 30, 2002, that were not
included in the calculation of diluted shares because they would have had an
antidilutive effect.

(5)
LONG-TERM DEBT

Debt balances as of June 30, 2003 and December 31,
2002 consisted of the following:

	June 30,		December 31,
	2003		2002
	(in thousands)
Senior notes:
6.70% Series due 2005	$	125,000	$	125,000
7.625% Series due 2027, putable at the holders' option in 2009		60,000		60,000
7.21% Series due 2017		40,000		40,000
		225,000		225,000

Other:
Variable rate (2.77% at June 30, 2003 and 2.89% at December 31, 2002) unsecured revolving credit arrangements		22,800		117,400
Total long-term debt	$	247,800	$	342,400

The Company's revolving credit facility has a capacity of $125 million and a
three-year term that expires in July 2004. The Company intends to renew or
replace its revolving credit facility prior to the July 2004 expiration date.
The interest rate on the facility is 150 basis points over the current London
Interbank Offered Rate (LIBOR). The credit facility contains covenants which
impose certain restrictions on the Company. Under the credit agreement, the
Company may not issue total debt in excess of 65% of its total capital, must
maintain a certain level of shareholders' equity, and must maintain a ratio of
earnings before interest, taxes, depreciation and amortization (EBITDA) to
interest expense of at least 4.00 or higher through December 31, 2003. These
covenants change over the term of the credit facility and generally become more
restrictive. Additionally, the Company is precluded from paying dividends on its
common stock under the revolving credit agreement. At June 30, 2003, the
Company's revolving credit facility had a balance of $22.8 million and was
classified as long-term debt in the Company's balance sheet. The Company has
also entered into interest rate swaps for calendar year 2003 that require the
Company to pay a fixed interest rate of 3.8% (based upon current rates under the
revolving credit facility) on $40.0 million of its outstanding revolving debt.
As a result of the reduced level of current and anticipated borrowings under the
revolving credit facility for the remainder of 2003, these interest rate swaps
no longer qualify as cash flow hedges and therefore $0.2 million has been
expensed in the accompanying financial statements for the first six months of
2003.

(6) DERIVATIVE
AND HEDGING ACTIVITIES

Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities" as amended
by SFAS No. 137, SFAS No. 138 and SFAS No. 149, was adopted by the Company on
January 1, 2001. SFAS No. 133 requires that all derivatives be recognized in the
balance sheet as either an asset or liability measured at its fair value.
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the income statement.

At June 30, 2003, the Company's net liability related
to its cash flow hedges was $38.1 million. Additionally, at June 30, 2003, the
Company had recorded a net of tax cumulative loss to other comprehensive income
(equity section of the balance sheet) of $22.9 million. The amount recorded in
other comprehensive income will be relieved over time and taken to the income
statement as the physical transactions being hedged occur. Additional volatility
in earnings and other comprehensive income may occur in the future as a result
of the adoption of SFAS No. 133.

(7) SEGMENT INFORMATION

The Company applies SFAS No. 131, "Disclosures about Segments of an Enterprise
and Related Information." The Company's reportable business segments have been
identified based on the differences in products or services provided. Revenues
for the exploration and production
segment are derived from the production and sale of natural gas and crude oil.
Revenues for the gas

distribution segment arise from the transportation and sale
of natural gas at retail. The marketing segment generates revenue through the
marketing of both Company and third-party produced gas volumes.

Summarized financial information for the Company's
reportable segments is shown in the following table. The "Other" column includes
items not related to the Company's reportable segments including real estate,
pipeline operations and corporate items.

	Exploration
	and		Gas
	Production		Distribution		Marketing		Other			Total
	(in thousands)
Three months ended June 30, 2003:
Revenues from external customers	$	34,211	$	20,609	$	11,667	$	--		$	66,487
Intersegment revenues		9,278		28		38,230		112			47,648
Operating income		21,476		(2,108)		536		42			19,946
Depreciation, depletion and amortization expense		12,117		1,534		12		23			13,686
Interest expense⁽¹⁾		2,549		1,092		2		268			3,911
Provision (benefit) for income taxes⁽¹⁾		6,966		(1,230)		203		(102)			5,837
Assets		583,429		150,176		17,709		37,465	⁽²⁾		788,779	⁽²⁾
Capital expenditures		46,784		3,099		2		214			50,099

Three months ended June 30, 2002:
Revenues from external customers	$	26,915	$	16,860	$	12,229	$	--		$	56,004
Intersegment revenues		4,501		23		25,784		112			30,420
Operating income		10,063		(1,718)		503		52			8,900
Depreciation, depletion and amortization expense		12,248		1,564		32		24			13,868
Interest expense⁽¹⁾		4,473		637		--		211			5,321
Provision (benefit) for income taxes⁽¹⁾		1,980		(945)		196		(123)			1,108
Assets		539,565		144,681		12,595		28,136	⁽²⁾		724,977	⁽²⁾
Capital expenditures		17,954		1,412		2		37			19,405

Six months ended June 30, 2003:
Revenues from external customers	$	62,820	$	78,049	$	24,273	$	--		$	165,142
Intersegment revenues		20,405		95		73,544		224			94,268
Operating income		40,413		5,897		1,227		83			47,620
Depreciation, depletion and amortization expense		22,931		3,068		24		46			26,069
Interest expense⁽¹⁾		6,272		2,073		2		511			8,858
Provision for income taxes⁽¹⁾		12,462		1,410		466		386			14,724
Assets		583,429		150,176		17,709		37,465	⁽²⁾		788,779	⁽²⁾
Capital expenditures		75,232		4,940		2		294			80,468

Six months ended June 30, 2002:
Revenues from external customers	$	50,479	$	65,252	$	21,931	$	--		$	137,662
Intersegment revenues		9,357		88		42,705		224			52,374
Operating income		17,393		6,945		1,284		117			25,739
Depreciation, depletion and amortization expense		24,528		3,129		34		47			27,738
Interest expense⁽¹⁾		8,726		1,541		--		439			10,706
Provision (benefit) for income taxes⁽¹⁾		3,054		2,022		503		(267)			5,312
Assets		539,565		144,681		12,595		28,136	⁽²⁾		724,977	⁽²⁾
Capital expenditures		37,835		2,760		2		177			40,774

(1) Interest expense and the provision (benefit) for income taxes by segment
are an allocation of corporate amounts as debt and income tax expense (benefit)
are incurred at the corporate level.

(2) Other assets include the Company's equity investment in the operations of
the NOARK Pipeline System, Limited Partnership, corporate assets not allocated
to segments, and assets for non-reportable segments.

Intersegment sales by the exploration and production segment and marketing
segment to the gas distribution segment are priced in accordance with terms of
existing contracts and current market conditions. Parent company assets include
furniture and fixtures, prepaid debt costs and prepaid and intangible pension
related costs. Parent company general and administrative costs, depreciation
expense and taxes other than income are allocated to segments. All of the
Company's operations are located within the United States.

(8)
INTEREST AND INCOME TAXES PAID

The following table provides interest and income taxes
paid during each period presented. Interest payments include amounts paid or
received for the settlement of interest rate hedges.

	For the six months ended
	June 30,
	2003		2002
	(in thousands)

Interest payments	$	8,038	$	10,973
Income tax payments	$	--	$	--

(9) MINORITY INTEREST IN PARTNERSHIP

In 2001, the Company's subsidiary, Southwestern
Energy Production Company (SEPCO) formed a limited partnership, Overton
Partners, L.P., with an investor to drill and complete 14 development wells in
SEPCO's Overton Field located in Smith County, Texas. Because SEPCO is the sole
general partner and owns a majority interest in the partnership, the operating
and financial results are consolidated with the Company's exploration and
production results and the investor's share of the partnership activity is
reported as a minority interest item in the financial statements.

(10) CONTINGENCIES AND COMMITMENTS

The Company
and the other general partner of NOARK have severally guaranteed the principal
and interest payments on NOARK's 7.15% Notes due 2018. At June 30, 2003 and
December 31, 2002, the principal outstanding for these notes was $70.0 million and $71.0
million, respectively. The Company's share of the several guarantee is 60%. The
notes were issued in June 1998 and require semi-annual principal payments of
$1.0 million. Under the several guarantee, the Company is required to fund its
share of NOARK's debt service which is not funded by operations of the pipeline.
As a result of the integration of NOARK Pipeline with the Ozark Gas Transmission
System, management of the Company believes that it will realize its investment
in NOARK over the life of the system. Therefore, no provision for any loss has
been made in the accompanying financial statements. Additionally, the Company's
gas distribution subsidiary has transportation contracts for firm capacity of
66.9 MMcfd on NOARK's integrated pipeline system. These contracts expire in
2003, and are renewable year-to-year thereafter until terminated by 180 days'
notice.

The Company
is subject to laws and regulations relating to the protection of the
environment. The Company's policy is to accrue environmental and cleanup related
costs of a non-capital nature when it is both probable that a liability has been
incurred and when the amount can be reasonably estimated. Management believes
any future remediation or other compliance related costs will not have a
material effect on the financial position or reported results of operations of
the Company.

The Company is subject to litigation and claims that
have arisen in the ordinary course of business. The Company accrues for such
items when a liability is both probable and the amount can be reasonably
estimated. In the opinion of management, the results of such litigation and
claims will not have a material effect on the results of operations or the
financial position of the Company.

(11) ASSET
RETIREMENT OBLIGATIONS

Statement of Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations" (SFAS No. 143) was adopted by the
Company on January 1, 2003. SFAS No. 143 addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs and amends FASB Statement No.
19, "Financial Accounting and Reporting by Oil and Gas Producing Companies."
SFAS No. 143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made, and that the associated asset retirement
costs be capitalized as part of the carrying amount of the long-lived asset.
Associated with the adoption of the standard, the Company increased current and
long-term liabilities by $1.2 million and $5.5 million, respectively, net
property and equipment by $5.3 million, net deferred tax assets by $0.5 million,
and recorded an expense of $0.9 million constituting the cumulative effect of
adoption. As of June 30, 2003, the Company had $0.7 million of current
liabilities and $6.4 million of long-term liabilities associated with its asset
retirement obligations. The new standard had no material impact on income
before the cumulative effect of adoption in the second quarter of 2003, nor
would it have had a material impact in the second quarter of 2002 assuming an
adoption of this accounting standard on a proforma basis.

(12) ACCOUNTING FOR
STOCK-BASED COMPENSATION

The Company's stock-based employee compensation
plan is accounted for under the recognition and measurement principles of APB
Opinion No. 25, "Accounting for Stock Issued to Employees," and related
Interpretations. No stock-based employee compensation cost related to stock
options is reflected in net income, as all options granted under the plan had an
exercise price equal to the market value of the underlying common stock on the
date of grant. The Company does record compensation cost for the amortization of
restricted stock shares issued to employees. The following table illustrates the
effect on net income and earnings per share if the company had applied the fair
value recognition provisions of FASB Statement No. 123, "Accounting for
Stock-Based Compensation," to stock-based employee compensation.


		For the three months			For the six months
		ended June 30,			ended June 30,
		2003		2002	2003	2002
			(in thousands, except per share)

Net income, as reported		$9,526		$1,770	$23,168	$8,485
Add back: Amortization of restricted stock		435		312	869	625
Deduct: Total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effects		(716)		(566)	(1,431)	(1,133)

Pro forma net income		$9,245		$1,516	$22,606	$7,977

Earnings per share:
	Basic-as reported	$0.27		$0.07	$0.73	$0.34
	Basic-pro forma	0.26		0.06	0.72	0.32
	Diluted-as reported	0.26		0.07	0.71	0.33
	Diluted-pro forma	0.26		0.06	0.69	0.31

The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted-average
assumptions for all periods presented: no dividend yield; expected volatility of
45.6%; risk-free interest rate of 3.4%; and expected lives of 6 years for all
option grants. There were no options granted in the first six months of 2003.
The fair value of the options granted in the first six months of 2002 was $0.2
million.

ITEM 2. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The
following updates information as to the Company's financial condition provided
in our 2002 Annual Report on Form 10-K, and analyzes the changes in the results
of operations between the three- and six- month periods ended June 30, 2003, and
the comparable periods of 2002. For definitions of commonly used gas and oil
terms as used in this Form 10-Q, please refer to the "Glossary of Certain
Industry Terms" provided in our 2002 Annual Report on Form 10-K.

OVERVIEW

We operate
in three segments: Exploration and Production, Natural Gas Distribution and
Marketing, Transportation and Other. Our financial results depend on a number of
factors, in particular natural gas and oil prices, the seasonality of our
customers' need for natural gas and our ability to market natural gas and oil on
economically attractive terms to our customers. There has been significant price
volatility in the natural gas and crude oil market in recent years. The
volatility was attributable to a variety of factors impacting supply and demand,
including weather conditions, political events and economic events we cannot
control or predict.

We reported net income of $9.5 million, or $0.26 per
share on a fully diluted basis, on revenues of $66.5 million for the three
months ended June 30, 2003, compared to net income of $1.8 million, or $0.07 per
share, on revenues of $56.0 million for the same period in 2002. Net income for
the six months ended June 30, 2003 was $23.2 million, or $0.71 per share on a
diluted basis, on revenues of $165.1 million, compared to net income of $8.5
million, or $0.33 per share, on revenues of $137.7 million for the same period
in 2002. The increase in
revenues and earnings primarily resulted from higher natural gas
prices experienced by our exploration and production segment, partially offset
by a decrease in production volumes.

RESULTS
OF OPERATIONS

Exploration and Production

Our exploration and production segment's revenue, profitability and future rate
of growth are substantially dependent upon prevailing prices for natural gas and
oil, which are dependent upon numerous factors beyond our control, such as
economic, political and regulatory developments and competition from other
sources of energy. The energy markets have historically been very volatile, and
there can be no assurance that gas and oil prices will not be subject to wide
fluctuations in the future. Gas and oil prices affect the amount of cash flow
available for capital expenditures, our ability to borrow and raise additional
capital and the amount of gas and oil we can economically produce. We use
hedging transactions with respect to a portion of our gas and oil production to
achieve more predictable cash flows and to reduce our exposure to price
fluctuations. Our future success depends on our ability to find, develop and
acquire gas and oil reserves that are economically recoverable.


		For the three months		For the six months
		ended June 30,		ended June 30,
		2003	2002	2003	2002

Revenues (in thousands)		$43,489	$31,416	$83,225	$59,836
Operating income (in thousands)		$21,476	$10,063	$40,413	$17,393

Gas production (MMcf)		9,259	9,128	17,360	18,359
Oil production (MBbls)		139	195	264	378
	Total production (MMcfe)	10,093	10,298	18,944	20,627

Average gas price per Mcf		$4.28	$2.96	$4.22	$2.86
Average oil price per Bbl		$27.40	$22.62	$27.54	$20.10
Average unit costs per Mcfe
	Lease operating expenses	$0.36	$0.42	$0.39	$0.43
	General & administrative expenses	0.40	0.28	0.42	0.28
	Taxes other than income taxes	0.23	0.18	0.25	0.16
	Full cost pool amortization	1.17	1.16	1.17	1.16

Revenues, Operating
Income and Production

Revenues.
Revenues for our exploration and production segment were up 38% and 39% for the
three- and six- month periods ended June 30, 2003, respectively, both as
compared to the same periods in 2002. The increases were primarily due to higher
gas and oil prices received for our production.

Operating Income.
Operating income for the exploration and production segment was up $11.4 million
for the three months ended June 30, 2003, and up $23.0 million for the first six
months of 2003, both as compared to the same periods in 2002. The increases in
operating income resulted from the increases in revenues.

Production.
Gas and oil production during the second quarter of 2003 was 10.1 billion cubic
feet (Bcf) equivalent, compared to 10.3 Bcf equivalent in the second quarter of
2002. Gas and oil production was 18.9 Bcf equivalent for the first six months of
2003, compared to 20.6 Bcf equivalent for the
first six months of 2002. The comparative decreases in production resulted from
declines experienced in our South Louisiana properties beginning in the last
half of 2002, combined with the loss of production resulting from the November
2002 sale of our Mid-Continent properties, partially offset by increased
production from the Overton Field in East Texas. Gas production was 9.3
Bcf for the second quarter of 2003 compared to 9.1 Bcf for the second quarter of
2002. Gas production was 17.4 Bcf for the first six months of 2003 compared to
18.4 Bcf for the same period of 2002. We sold 3.5 Bcf to our gas distribution
systems during the six months ended June 30, 2003, compared to 3.2 Bcf for the
same period in 2002. Our oil production was 139 thousand barrels (MBbls) during
the second quarter of 2003 and 264 MBbls for the first six months of 2003, down
from 195 MBbls and 378 MBbls for the same periods of 2002, respectively.

Commodity Prices

We received an average price of $4.28 per thousand cubic feet (Mcf) for our gas
production for the three months ended June 30, 2003, up from $2.96 per Mcf for
the same period of 2002. For the first six months of 2003, we received an
average gas price of $4.22 compared to $2.86 for the same period of 2002. We
hedged 15.2 Bcf of gas production in the first six months of 2003 through
fixed-price swaps and zero-cost collars which had the effect of decreasing our
average gas price realized during the period by $1.51 per Mcf. On a comparative
basis, the average price realized during the first six months of 2002 included
the effect of hedges that increased our average price by $0.04 per Mcf.

For the remainder of 2003, we have 9.0 Bcf of gas production hedged with collars
having an average NYMEX floor price of $3.30 per Mcf and an average NYMEX
ceiling price of $5.07 per Mcf. We also have 6.1 Bcf of gas production for the
remainder of 2003 hedged with fixed-price swaps at an average NYMEX price of
$3.42 per Mcf. For 2004, we have 29.2 Bcf hedged under zero-cost collars and
fixed-price swaps. See Part I, Item 3 of this Form 10-Q for additional
information regarding the Company's commodity price risk hedging activities.

We received an average price of $27.54 per barrel for
our oil production during the six months ended June 30, 2003, up from $20.10 per
barrel for the same period of 2002. The average price we received for our oil
production in the first half of 2003 and 2002 was reduced by $2.80 per barrel
and $1.96 per barrel, respectively, due to the effects of fixed-price swaps. For
the remainder of 2003, we have a hedge on 180,000 barrels at an average NYMEX
price of $26.73 per barrel.

Operating
Costs and Expenses

Lease operating expenses per Mcfe for this business
segment were $0.36 for the second quarter of 2003, compared to $0.42 for the
same period in 2002. Lease operating expenses per unit have decreased in 2003 as
a larger portion of our production is being provided from the Overton Field
which has lower operating costs. Taxes other than income taxes per Mcfe were
$0.23 for the second quarter of 2003, compared to $0.18 for the same period in
2002. Severance taxes per Mcfe increased during the quarter due to higher
average prices received for our production. General and administrative expenses
per Mcfe were $0.40 and $0.42 for the second quarter and first six months of
2003, respectively, compared to $0.28 for the same two comparable periods of
2002. The increase in general and administrative expenses in 2003 was due
primarily to increased pension costs and the accrual of incentive compensation
costs.

The Company utilizes the full cost method of
accounting for costs related to its natural gas and oil properties. Under this
method, all such costs (productive and nonproductive) are capitalized and
amortized on an aggregate basis over the estimated lives of the properties using
the units-of-production method. These capitalized costs are subject to a ceiling
test, however, which limits such pooled costs to the aggregate of the present
value of future net revenues attributable to proved gas and oil reserves
discounted at 10 percent plus the lower of cost or market value of unproved
properties. Any costs in excess of this ceiling are written off as a non-cash
expense. The

expense may not be reversed in future periods, even though higher
gas and oil prices may subsequently
increase the ceiling. Our full cost ceiling is evaluated at the end of each
quarter. At June 30, 2003, our unamortized costs of gas and oil properties did
not exceed this ceiling amount. A decline in gas and oil prices from current
levels, or other factors, without other mitigating circumstances, could cause a
future write-down of capitalized costs and a non-cash charge against future
earnings.

Natural Gas Distribution

The
operating results of our gas distribution segment are highly seasonal. This
segment typically realizes operating income during the winter heating season in
the first and fourth quarters and operating losses in the second and third
quarters of the year. The extent and duration of heating weather also impacts
the profitability of this segment, although there is a weather normalization
clause in our rates intended to lessen the impact of revenue increases and
decreases which might result from weather variations during the winter heating
season. The gas distribution segment's profitability is also dependent upon the
timing and amount of regulatory rate increases that are filed with and approved
by the Arkansas Public Service Commission (APSC). For periods subsequent to
allowed rate increases, our profitability is impacted by our ability to manage
and control this segment's operating costs and expenses.


		For the three months		For the six months
		ended June 30,		ended June 30,
		2003	2002	2003	2002

Revenues (in thousands)		$20,637	$16,883	$78,144	$65,340
Gas purchases (in thousands)		11,467	8,300	49,634	37,918
Operating costs and expenses (in thousands)		11,278	10,301	22,613	20,477
Operating income (loss) (in thousands)		(2,108)	(1,718)	5,897	6,945

Deliveries (Bcf)
	Sales and end-use transportation	3.8	3.9	14.5	14.0
	Off-system transportation	0.1	0.7	0.1	0.7

Average number of customers		138,671	136,488	139,611	137,280
Average sales rate per Mcf		$9.74	$7.66	$7.34	$6.32
Heating weather - degree days		279	228	2,554	2,277
- percent of normal		90%	74%	104%	92%

Revenues and Operating
Income

Revenues. Gas distribution revenues
fluctuate due to the pass-through of gas supply cost changes and the effects of
weather. Because of the corresponding changes in purchased gas costs, the
revenue effect of the pass-through of gas cost changes has not materially
affected net income. Revenues for the three- and six-month periods ended June
30, 2003 increased 22% and 20%, respectively, from the comparable periods of
2002 due primarily to increases in the cost of gas supplies that were caused by
higher gas prices.

Operating Income.
Operating income of our gas distribution segment decreased $0.4 million in the
second quarter of 2003 and decreased $1.0 million in the first six months of
2003, as compared to the same periods of 2002. The decreases were primarily due
to increased operating costs and expenses. Weather during the first half of
2003 was 4% colder than normal and 12% colder than the same period of 2002. The
weather normalization clause in the utility's rates is intended to lessen the
impacts of revenue increases and decreases that might result from weather
variations during the winter heating season.

We filed an application with the APSC on November 8,
2002, for a rate increase of $11.0 million annually. On July 17, 2003 the
Company's gas distribution subsidiary, Arkansas Western Gas Company (AWG),
executed a Joint Stipulation and Settlement Agreement (Settlement Agreement) with the Staff of the APSC and various other consumer groups that
would resolve all outstanding issues relating to AWG's rate increase request.
Under the terms of the Settlement Agreement, AWG would receive a rate increase
of $4.2 million annually, exclusive of costs to be recovered through its
purchase gas adjustment clause. AWG would also be entitled to recover certain
additional costs totaling $2.9 million through its purchase gas adjustment clause
over a two-year period. The difference between the $11.0 million rate
adjustment requested by AWG and the rate adjustment contained in the Settlement
Agreement primarily results from a reduction in AWG's requested return on equity
and a change in AWG's assumed capital structure. In the rate increase request
that was filed with the APSC, AWG assumed an allowed return on equity of 12.9%
and a capital structure of 48% debt and 52% equity. The Settlement Agreement
provides for an allowed return on equity of 9.9% and an assumed capital
structure of 52% debt and 48% equity. The 9.9% equity return is in line with
the equity return approved in recent settlements that have been approved for the
other two Arkansas local gas distribution
companies.

The proposed Settlement Agreement is subject to the approval of
the APSC. A scheduled hearing was held at the APSC on July 22^nd
and 23^rd to hear testimony of AWG, the Staff of the APSC and the
various other intervening parties that support the Settlement Agreement as well
as testimony of the Office of the Attorney General of the State of Arkansas who
opposes the Settlement Agreement. The APSC has requested the various parties
file post-hearing briefs addressing the proposed Stipulation and Settlement
Agreement by August 8th and the effective date of any rate increase has been
extended until the first of October. AWG's last rate increase was approved in
December 1996 for its Northwest region and in December 1997 for its Northeast
region.

Deliveries
and Rates

The utility systems delivered 3.8 Bcf and 14.5 Bcf to
sales and end-use transportation customers during the three- and six-month
periods ended June 30, 2003, compared to 3.9 Bcf and 14.0 Bcf for the same
periods in 2002. The increase in deliveries during the first half of 2003 was
primarily due to the effects of colder weather. The increase in gas costs in the
first half of 2003 was reflected in the utility segment's average rate for its
sales which increased to $7.34 per Mcf, up from $6.32 per Mcf for the same
period in 2002. Costs paid for purchases of natural gas are passed through to
customers under automatic adjustment clauses. Our utility segment hedged 2.7 Bcf
of gas purchases in the first six months of 2003 decreasing its total gas supply
cost by $6.7

million. In the first half of 2002, 3.3 Bcf of gas purchase hedges
increased the total gas supply cost by $5.8 million. We currently have hedges in
place on 1.7 Bcf of future gas supply purchases for the months of November 2003
through March 2004 at an average fixed cost of $5.91 per Mcf.

Operating
Costs and Expenses

The changes in purchased gas costs for our gas distribution segment reflect
volumes purchased, prices paid for supplies and the mix of purchases from intercompany versus third-party sources. Other operating costs and expenses for
this segment during the second quarter and six months ended June 30, 2003 were
higher than the comparable periods of the prior year due primarily to increased
general and administrative expenses that primarily resulted from increased
pension costs and the accrual of incentive compensation costs, and from
increased transmission costs that resulted from higher fuel costs.

Marketing,
Transportation and Other

Operating income from the marketing,
transportation and other segment, which includes income from real property held
by our subsidiary, A.W. Realty Company, was $0.6 million for the second quarter
of 2003 and $1.3 million for the first six months of 2003, compared to $0.6
million and $1.4 million, respectively, for the same periods of 2002.

Marketing

	For the three months		For the six months
	ended June 30,		ended June 30,
	2003	2002	2003	2002

Marketing revenues (in thousands)	$49,897	$38,013	$97,817	$64,636
Marketing operating income (in thousands)	536	503	1,227	1,284

Gas volumes marketed (Bcf)	10.2	12.4	18.7	24.6

The increase in our gas marketing revenues for the three- and six-month periods
ended June 30, 2003 relates to a significant increase in natural gas commodity
prices from the prior year and was offset by a comparable increase in purchased
gas costs. Operating income for this segment was $0.5 million and $1.2 million
for the three- and six-month periods ended June 30 2003, compared to $0.5
million and $1.3 million, respectively, for the same periods in 2002. We
marketed 10.2 Bcf of gas in the second quarter and 18.7 Bcf in the first six
months of 2003, compared to 12.4 Bcf and 24.6 Bcf for the same periods in 2002.
The decrease in volumes marketed primarily resulted from lower volumes marketed
for third parties due to our continuing effort to reduce credit risk.

Transportation

Our share of the NOARK Pipeline System Limited
Partnership (NOARK) pretax results of operations included in other income was a
gain of $1.4 million for the first six months of 2003, compared to a loss of
$0.4 million for the same period in 2002. The gain in the first half of 2003

resulted primarily from a gain of $1.3 million recognized by the Company on the
sale of a 28-mile portion of NOARK's pipeline located in Oklahoma that had
limited strategic value to the overall system. Sales proceeds to NOARK were
$10.0 million and our share of the proceeds was $2.5 million.

Interest Expense

Interest expense decreased 26%
for the second quarter of 2003 and 17% for the first six months of 2003, both as
compared to the same periods in 2002, due to lower average borrowings, a lower
average interest rate, and increased capitalized interest. Our average
borrowings decreased as net proceeds of $103.2 million from the Company's equity
offering in the first quarter of 2003 were initially used to pay down the
Company's revolving credit facility. The Company will reborrow the repaid
amounts under the credit facility as necessary to fund the acceleration of the
development of the Company's Overton Field in East Texas and for general
corporate purposes. Interest is capitalized in the exploration and production
segment on costs that are unevaluated and excluded from amortization.

Income
Taxes

The effective tax rate for the six months ended
June 30, 2003 was 38.0% compared to 38.5% for the same period in 2002. The
changes in the provision for deferred income taxes recorded in the six months
ended June 30, 2003, as compared to the same period in 2002, resulted primarily
from the increase in the level of pre-tax income in 2003. Also
impacting deferred taxes is the deduction of intangible drilling costs in the
year incurred for tax purposes, netted against the turnaround of intangible
drilling costs deducted for tax purposes in prior years. Intangible drilling
costs are capitalized and amortized over future years for financial reporting
purposes under the full cost method of accounting.

Adoption
of Accounting Principle

Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" (SFAS No. 143) was adopted by
the Company on January 1, 2003. SFAS No. 143 addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs and amends FASB Statement No.
19, "Financial Accounting and Reporting by Oil and Gas Producing Companies."
SFAS No. 143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made, and that the associated asset retirement
costs be capitalized as part of the carrying amount of the long-lived asset. The
effect of this standard on the Company's results of operations and financial
condition at adoption was an increase in current and long-term liabilities of
$1.2 million and $5.5 million, respectively; a net increase in property, plant
and equipment of $5.3 million; a cumulative effect of adoption expense of $0.9
million and a deferred tax asset of $0.5 million. As of June 30, 2003, the
Company has $0.7 million of current liabilities and $6.4 million of long-term
liabilities associated with its asset retirement obligations. Subsequent to
adoption, the Company does not expect this standard to have a material impact on
the Company's financial position or its results of operations.

LIQUIDITY AND CAPITAL
RESOURCES

We depend on internally-generated funds and our revolving line of credit
(discussed below under "Financing Requirements") as our primary sources of
liquidity. We may borrow up to
$125.0 million under our revolving credit facility from time to time. During the
first quarter of 2003, we completed the sale of 9,487,500 shares of our common
stock under a registration statement filed with the Securities and Exchange
Commission in December 2002. Aggregate net proceeds from the equity offering of
$103.2 million were used to repay borrowings under our credit facility. We
intend to reborrow the repaid amounts as necessary to fund the acceleration of
the development of our Overton Field in East Texas and for general corporate
purposes. As of June 30, 2003, the Company's revolving credit facility had a
balance of $22.8 million and was classified as long-term debt in the Company's
balance sheet. We expect our capital expenditures (discussed below under
"Capital Expenditures") for 2003 to be funded by the cash flow generated by our
operations and the funds that may be available under our credit facility.

Net cash provided by operating activities was $70.3
million in the first six months of 2003, compared to $42.3 million for the same
period of 2002. The primary components of cash generated from operations are net
income, depreciation, depletion and amortization, the provision for deferred
income taxes and changes in operating assets and liabilities. Historically, our
capital expenditures have predominantly been funded through cash provided by
operations. For the first six months of 2003, cash provided by operating
activities provided 87% of these requirements. For the same period of 2002, cash
provided by operating activities exceeded these requirements.

Our cash flow from operating activities is highly dependent upon market prices
that we receive for our gas and oil production. The price received for our
production is also influenced by our commodity hedging activities, as more fully
discussed in "Quantitative and Qualitative Disclosure About Market Risks" and
Note 6 to the financial statements. Natural gas and oil prices are subject to
wide fluctuations. As a result, we are unable to forecast with certainty our
future level of cash flow from operations. We adjust our discretionary uses of
cash dependent upon cash flow available.

Capital
Expenditures

Our capital expenditures for the first six months
of 2003 were $80.5 million, compared to $40.8 million for the same period in
2002. Capital investments during calendar year 2003 are currently expected to be
approximately $173.6 million compared to $92.1 million in 2002. Our 2003 capital
investment program is expected to be funded through cash flow from operations
and borrowings under our revolving credit facility. We may adjust our level of
future capital investments dependent upon the level of cash flow generated from
operations.

Off-Balance Sheet Arrangements

We hold a 25% general partnership interest in NOARK
and account for our investment under the equity method of accounting. We and the
other general partner of NOARK have severally guaranteed the principal and
interest payments on NOARK's 7.15% Notes due 2018. This debt

financed a portion
of the original cost to construct the NOARK Pipeline. Our share of the guarantee
is 60%. At June 30, 2003, the outstanding principal amount of these notes was
$70.0 million and our share of the guarantee was $42.0 million. The notes were
issued in June 1998 and require semi-annual principal payments of $1.0 million.
Under the several guarantee, we are required to fund our share of NOARK's debt
service which is not funded by operations of the pipeline. We were not required
to advance any funds to NOARK in the first half of 2003 and do not expect to advance any funds during the remainder of
2003.

Our share of the results of
operations included in other income related to our NOARK investment was a gain
of $1.4 million for the first six months of 2003, compared to a loss of $0.4
million for the same period in 2002. The gain in the first half of 2003 resulted
primarily from NOARK's sale of a 28-mile portion of its pipeline located in
Oklahoma that had limited strategic value to the overall system. Sales proceeds
to NOARK were $10.0 million and our share of the proceeds was $2.5 million. In
addition to the gain recognized on the sale, the improvements experienced
recently in operating results of NOARK result primarily from the ability to
collect higher transportation rates on interruptible volumes. We believe that we
will be able to continue to reduce the losses we have experienced on the NOARK
project and expect our investment in NOARK to be realized over the life of the
system.

Contractual
Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal
course of our operations and financing activities. Significant contractual
obligations at June 30, 2003 are as follows:

Contractual Obligations

Payments Due by
Period

Less than

1 to 3

3 to 5

More than

Total

1 Year

Years

Years

5 Years

(in
thousands)

Long-term debt $ 247,800 $ -- $ 147,800 $ -- $ 100,000

Operating leases⁽¹⁾ 6,340 1,149 2,218 1,045 1,928

Unconditional purchase obligations⁽²⁾ -- -- -- -- --

Demand charges⁽³⁾ 20,829 6,056 6,599 3,439 4,735

Other obligations⁽⁴⁾
1,960
1,960 -- -- --

$
276,929 $
9,165 $
156,617 $
4,484 $
106,663

(1)   We lease certain office
space and equipment under operating leases expiring through 2013.

(2)   Our utility segment has
volumetric commitments for the purchase of gas under competitive bid packages
and wellhead contracts. Volumetric purchase commitments at June 30, 2003 totaled
2.6 Bcf, comprised of 1.0 Bcf in less than one year, 0.9 Bcf in one to three
years, 0.5 Bcf in three to five years and 0.2 Bcf in more than five years. Our
volumetric purchase commitments are priced at regional gas indices set at the
first of each future month. These costs are recoverable from the utility's
end-use customers.

(3)   Our utility segment has
commitments for $13.8 million of demand charges on firm gas purchase and firm
transportation agreements. These costs are recoverable from the utility's
end-use customers. Our E&P segment has a commitment for $7.0 million of demand
transportation charges.

22

(4) Our significant other
obligations include approximately $0.4 million of land leases, approximately
$0.8 million for drilling rig commitments and approximately $0.8 million of
various information technology support and data subscription agreements.

We refer you to "Financing Requirements" below for a
discussion of the terms of our long-term debt.

Contingent Liabilities or Commitments

        We have the following commitments and contingencies
that could create, increase or accelerate our liabilities. Substantially all of
our employees are covered by defined benefit and postretirement benefit plans.
Our return on the assets of these plans in 2002 was negative which, combined
with other factors,
has resulted in an increase in pension expense and our required
funding of the plans for 2003. As a result of actuarial data, we expect to
record pension expense of approximately $3.4 million in 2003, of which $1.7
million has been recorded in the first half of 2003.

        As discussed above in "Off-Balance Sheet
Arrangements," we have guaranteed 60% of the principal and interest payments on
NOARK's 7.15% Notes due 2018. At June 30, 2003 the principal outstanding for
these notes was $70.0 million. The notes require semi-annual principal payments
of $1.0 million.

Financing Requirements

        Our total debt outstanding was $247.8 million at June
30, 2003 and $342.4 million at December 31, 2002. In July 2001, we arranged an
unsecured revolving credit facility with a group of banks to replace a
short-term credit facility that was put in place in July 2000. The revolving
credit facility has a current capacity of $125 million and expires in July 2004.
The Company intends to renew or replace its revolving credit facility prior to
the July 2004 expiration date. The interest rate on the current facility is 150
basis points over the current LIBOR. The credit facility contains covenants
which impose certain restrictions on us. Under the credit agreement, we may not
issue total debt in excess of 65% of our total capital, we must maintain a
certain level of shareholders' equity, and we must maintain a ratio of earnings
before interest, taxes, depreciation and amortization (EBITDA) to interest
expense of at least 4.00 or higher through December 31, 2003. These covenants change over the term of the credit facility and
generally become more restrictive. Additionally, we are precluded from paying
dividends on our common stock under the revolving credit agreement. At June 30, 2003, the Company's revolving credit facility
had a balance of $22.8 million and was classified as long-term debt in the
Company's balance sheet. We have also entered into interest rate swaps for
calendar year 2003 that require us to pay a fixed interest rate of 3.8% (based
upon current rates under the revolving credit facility) on $40.0 million of our
outstanding revolving debt. As a result of the reduced level of current and
anticipated borrowings under the revolving credit facility for the remainder of
2003, these interest rate swaps no longer qualify as cash flow hedges and
therefore $0.2 million has been expensed in the accompanying financial
statements.

        During the first six months of 2003, our total debt
decreased by $94.6 million primarily due to the initial use of the net proceeds
from the issuance of common stock to pay off the balance of our revolving debt.
We intend to reborrow the repaid amounts as necessary to fund the acceleration
of

23

the development drilling of our Overton Field properties in East Texas and
for general corporate purposes as these costs are incurred. Total debt at June
30, 2003, accounted for 45% of our total capitalization.


At June 30, 2003, the NOARK partnership had outstanding debt totaling $70.0
million. We and the other general partner of NOARK have severally guaranteed the
principal and interest payments on the NOARK debt. Our share of the several
guarantee is 60%.

Working Capital

        We maintain access to funds that may be needed to meet
seasonal requirements through our credit facility described above. We had
negative working capital of $12.0 million at June 30, 2003, compared to positive
working capital of $1.6 million at December 31, 2002. Current assets decreased
by
14% in the first half of 2003 while current liabilities
increased 4%. The decrease in current assets during the first six
months of 2003 was due primarily to a $5.0 million decrease in current gas stored underground due to withdrawals to
meet sales requirements, a
$3.9
million decrease in accounts receivable caused by seasonal deliveries of our gas
distribution segment, and a $3.1 million decrease in our current hedging asset
recorded under the provisions of SFAS No. 133. Increases in current liabilities
during the first six months of 2003 related to our hedging activities and asset
retirement obligations recorded under the provisions of SFAS No. 143 were
partially offset by
a decrease
in our regulatory liability and a reduction in over-recovered gas
purchase costs. Over-recovered purchased gas costs for the Company's gas
distribution segment were $2.0 million at June 30, 2003, compared to $5.7
million at December 31, 2002. Purchased gas costs are recovered from our utility customers in
subsequent months through automatic cost of gas adjustment clauses included in
the utility's filed rate tariffs.
Changes in other current assets and current liabilities are primarily due to the
timing of expenditures and receipts. At June 30, 2003, we had a current hedging liability of
$30.0 million recorded as a result of the provisions of SFAS No. 133.

CRITICAL ACCOUNTING POLICIES

Natural Gas and Oil Properties

        We utilize the full cost method of accounting for
costs related to our natural gas and oil properties. We review the carrying
value of our natural gas and oil properties under the full cost accounting rules
of the SEC on a quarterly basis. Under these rules, all such costs (productive
and nonproductive) are capitalized and amortized on an aggregate basis over the
estimated lives of the properties using the units-of-production method. These
capitalized costs are subject to a ceiling test, however, which limits such
pooled costs to the aggregate of the present value of future net revenues
attributable to proved gas and oil reserves discounted at 10 percent plus the
lower of cost or market value of unproved properties. If the net capitalized
costs of natural gas and oil properties exceed the ceiling, we will record a
ceiling test write-down to the extent of such excess. A ceiling test write-down
is a non-cash charge to earnings. If required, it reduces earnings and impacts
shareholders' equity in the period of occurrence and results in lower
depreciation, depletion and amortization expense in future periods. The
write-down may not be reversed in future periods, even though higher natural gas
and oil prices may subsequently increase the ceiling.

24

        The risk
that we will be required to write-down the carrying value of our natural gas and
oil properties increases when natural gas and oil prices are depressed or if
there are substantial downward revisions in estimated proved reserves.
Application of these rules during periods of relatively low natural gas or oil
prices, even if temporary, increases the probability of a ceiling test
write-down. Based on natural gas and oil prices in effect on June 30, 2003, the
unamortized cost of our natural gas and oil properties did not exceed the
ceiling of proved natural gas and oil reserves. Natural gas pricing has
historically been unpredictable and any significant declines could result in a
ceiling test write-down in subsequent quarterly or annual reporting periods.

        Natural gas and oil reserves used in the full cost
method of accounting cannot be measured exactly. Our estimate of natural gas and
oil reserves requires extensive judgments of reservoir engineering data and is
generally less precise than other estimates made in connection with financial
disclosures. Assigning monetary values to such estimates does not reduce the
subjectivity and changing nature of such reserve estimates. The uncertainties
inherent in the disclosure are compounded by applying additional estimates of
the rates and timing of production and the costs that will be incurred in
developing and producing the reserves. We engage the services of an independent
petroleum consulting firm to review reserves as prepared by our reservoir
engineers.


Statement of Financial Accounting Standards No. 141, "Business Combinations" (FAS
141), and Statement of Financial Accounting Standards No. 142, "Goodwill and
Intangible Assets" ( FAS 142), were issued in June 2001 and became effective for
us on July 1, 2001, and January 1, 2002, respectively. We understand the
majority of the oil and natural gas industry did not change its accounting and
disclosures for mineral interest use rights (leasehold acquisition costs) upon
the implementation of FAS 141 and 142. However, an interpretation of FAS 141
and 142 is being deliberated by the Securities and Exchange Commission,
Financial Accounting Standards Board and others as to whether mineral
interest use rights in oil and natural gas properties are intangible assets.
Under this interpretation, mineral interest use rights for both undeveloped and
developed leaseholds would be classified as an asset separate from oil and
natural gas properties as intangible assets. The classification as an
intangible asset would not affect how these items are accounted for under the
full cost method of accounting with respect to the calculation of depreciation,
depletion and amortization or the calculation of the ceiling test of our oil and
natural gas properties. At June 30, 2003 we have undeveloped leasehold
of approximately $8.3 million that would be classified as
"intangible undeveloped leasehold." We also have developed leasehold of
approximately $7.2
million that would be classified as "intangible developed
leasehold" if we applied the interpretation currently being deliberated. The
portion of developed leasehold that would be reclassified represents the costs
of developed leaseholds acquired or transferred to the full cost pool subsequent
to June 30, 2001, the effective date of FAS 141.


Additionally, FAS 142 requires that certain disclosures be made for all
intangible assets. We have not made the disclosures set forth under FAS 142
related to the use rights of mineral interests. We have continued to make the
disclosures required by Statement of Financial Accounting Standards No. 69
"Disclosures about Oil and Gas Producing Activities" (FAS 69).


We will continue to classify use rights of mineral interests in oil and gas
properties until further guidance is provided that might result from the
deliberations described above.

25

Hedging

        We use
natural gas and crude oil swap agreements and options and interest rate swaps to
reduce the volatility of earnings and cash flow, as well as to manage the price
volatility of natural gas purchases in our gas distribution segment, due to
fluctuations in the prices of natural gas and oil and in interest rates. Our
policies prohibit speculation with derivatives and limit swap agreements to
counterparties with appropriate credit standings. The primary market risks
related to our derivative contracts are the volatility in market prices and
basis differentials for natural gas and crude oil. However, the market price
risk is offset by the gain or loss recognized upon the related sale or purchase
of the natural gas or sale of the oil that is hedged.

        Our derivative instruments are accounted for under
SFAS No. 133 and are recorded at fair value in our financial statements. We
utilize market-based quotes from our hedge counterparties to value these open
positions. These valuations are recognized as assets or liabilities in our
balance sheet and, to the extent an open position is an effective cash flow
hedge on equity production or interest rates, the offset is recorded in other
comprehensive income. Results of settled commodity hedging transactions are
reflected in natural gas and oil sales or in gas purchases. Results of settled
interest rate hedges are reflected in interest expense. Any ineffective hedge,
derivative not qualifying for accounting treatment as a hedge, or ineffective
portion of a hedge is recognized immediately in earnings. Future market price
volatility could create significant changes to the hedge positions recorded in
our financial statements. We refer you to "Quantitative and Qualitative
Disclosures about Market Risk" in this Form 10-Q for additional information
regarding our hedging activities.

Regulated Utility Operations

        Our utility operations are subject to the rate
regulation and accounting requirements of the APSC. Allocations of costs and
revenues to accounting periods for ratemaking and regulatory purposes may differ
from those generally applied by non-regulated operations. Such allocations to
meet regulatory accounting requirements are considered generally accepted
accounting principles for regulated utilities provided that there is a
demonstrated ability to recover any deferred costs in future rates.

        During the ratemaking process, the regulatory
commission may require a utility to defer recognition of certain costs to be
recovered through rates over time as opposed to expensing such costs as
incurred. This allows the utility to stabilize rates over time rather than
passing such costs on to the customer for immediate recovery. This causes
certain expenses to be deferred as a regulatory asset and amortized to expense
as they are recovered through rates. The regulatory commission has not required
any unbundling of services, although large industrials are free to contract for
their own gas supply. There are no regulations relating to unbundling of
services currently anticipated; however, should such regulation be proposed and
adopted, certain of these assets may no longer meet the criteria for deferred
recognition and, accordingly, a write-off of regulatory assets and stranded
costs may be required.

26

Pension Accounting

        We record our prepaid or accrued benefit cost, as well
as our periodic benefit cost, for our pension and other postretirement benefit
plans using measurement assumptions that we consider
reasonable at the time of calculation. Two of the
assumptions that affect the amounts recorded are the discount rate, which
estimates the rate at which benefits could be effectively settled, and the
expected return on plan assets, which reflects the average rate of earnings
expected on the funds invested. For 2002, the discount rate assumed was 6.8% and
the expected return assumed was 9.0%.

        Using the
assumed rates discussed above, we recorded pension expense of $0.9 million in
2002 and a pension liability of $5.6 million at December 31, 2002. Assuming a 1%
change in the 2002 rates (lower discount rate and lower rate of return), we
would have recorded pension expense of $1.7 million in 2002, and recorded an
accrued pension liability of $10.7 million at December 31, 2002.

         For 2003,
we expect our pension expense to be approximately $3.4 million using an assumed
discount rate of 6.8% and an assumed expected return of 9.0%. Accordingly,
pension expense of $1.7 million was recorded in the first half of 2003.

Gas in Underground Storage

        We record our gas stored in inventory that is owned by
the exploration and production segment at the lower of weighted average cost or
market. Gas expected to be cycled within the next 12 months is recorded in
current assets with the remaining stored gas reflected as a long-term asset. The
quantity and average cost of gas in storage was 8.5 Bcf at $3.06 at June 30,
2003 and 10.1 Bcf at $3.05 at December 31, 2002.

        The gas in inventory for the exploration and
production segment is used primarily to supplement production in meeting the
segment's contractual commitments including delivery to customers of our gas
distribution business, especially during periods of colder weather. As a result,
demand fees paid by the gas distribution segment to the exploration and
production segment, which are passed through to the utility's customers, are a
part of the realized price of the gas in storage. In determining the lower of
cost or market for storage gas, we utilize the gas futures market in assessing
the price we expect to be able to realize for our gas in inventory. Declines in
the future market price of natural gas could result in us writing down our
carrying cost of gas in storage.

FORWARD-LOOKING INFORMATION


All statements, other than historical fact or present
financial information, may be deemed to be forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended. All statements that
address activities, outcomes and other matters that should or may occur in the
future, including, without limitation, statements regarding the financial
position, business strategy, production and reserve growth and other plans and
objectives for our future operations, are

27

forward-looking statements. Although
we believe the expectations expressed in such forward-looking statements are
based on reasonable assumptions, such statements are not guarantees of future
performance. We have no obligation and make no undertaking to publicly update or
revise any forward-looking statements.


Forward-looking statements include the items identified in the preceding
paragraph, information concerning possible or assumed future results of
operations and other statements in this Form 10-Q identified by words such as
"anticipate," "project," "intend," "estimate," "expect," "believe," "predict,"
"budget," "projection," "goal," "plan," "forecast," "target" or similar
expressions.

        You should not place undue reliance on forward-looking
statements. They are subject to known and unknown risks, uncertainties and other
factors that may affect our operations, markets, products, services and prices
and cause our actual results, performance or achievements to be materially
different from any future results, performance or achievements expressed or
implied by the forward-looking statements. In addition to any assumptions and
other factors referred to specifically in connection with forward-looking
statements, risks, uncertainties and factors that could cause our actual results
to differ materially from those indicated in any forward-looking statement
include, but are not limited to:


- -     the timing and extent of changes in commodity prices for natural gas and
oil;


- -     the timing and extent of our success in discovering, developing,
producing and estimating reserves;


- -     our future property acquisition or divestiture activities;


- -     the effects of weather and regulation on our gas distribution segment;


- -     increased competition;


- -     the impact of federal, state and local government regulation;


- -     the financial impact of accounting regulations;


- -     changing market conditions and prices (including regional basis
differentials);


- -     the comparative cost of alternative fuels;


- -     the availability of oil field personnel, services, drilling rigs and
other equipment; and


- -     any other factors listed in the reports we have filed and may file with
the SEC.

        We caution
you that these forward-looking statements are subject to all of the risks and
uncertainties, many of which are beyond our control, incident to the exploration
for and

28

development, production and sale of natural gas and
oil. These risks include, but are not limited to, commodity price volatility,
third-party interruption of sales to market, inflation, lack of availability of
goods and services, environmental risks, drilling and other operating risks,
regulatory changes, the uncertainty inherent in estimating proved natural gas
and oil reserves and in projecting future rates of production and
timing of development expenditures and the other risks set forth in our 2002
Annual Report on Form 10-K which are incorporated by reference herein.

        Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact way. The accuracy of any reserve estimate depends on the
quality of available data and the interpretation of that data by geological
engineers. In addition, the results of drilling, testing and production
activities may justify revisions of estimates that were made previously. If
significant, these revisions would change the schedule of any further production
and development drilling. Accordingly, reserve estimates are generally different
from the quantities of natural gas and oil that are ultimately recovered.

        Should one or more of the risks or uncertainties
described above or incorporated by reference occur, or should underlying
assumptions prove incorrect, our actual results and

plans
could differ materially from those expressed in any forward-looking statements.
We specifically disclaim all responsibility to publicly update any information
contained in a forward-looking statement or any forward-looking statement in its
entirety and therefore disclaim any resulting liability for potentially related
damages.

        All forward-looking statements attributable to us are
expressly qualified in their entirety by this cautionary statement.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS


Market risks relating to our operations result primarily from the volatility in
commodity prices, basis differentials and interest rates, as well as credit risk
concentrations. We use natural gas and crude oil swap agreements and options and
interest rate swaps to reduce the volatility of earnings and cash flow due to
fluctuations in the prices of natural gas and oil and in interest rates. While
the use of these hedging arrangements limits the downside risk of adverse price
movements, they may also limit future revenues from favorable price movements.
The Board of Directors has approved risk management policies and procedures to
utilize financial products for the reduction of defined commodity price and
interest rate risks. These policies prohibit speculation with derivatives and
limit swap agreements to counterparties with appropriate credit standings.

Credit Risks


Our financial instruments that
are exposed to concentrations of credit risk consist primarily of trade
receivables and derivative contracts associated with commodities trading.
Concentrations of credit risk with respect to receivables are limited due to the
large number of customers and their dispersion across geographic areas. No
single customer accounts for greater than
10% of accounts receivable. See the discussion of credit risk
associated with commodities trading below.

29

Interest
Rate Risk

        Revolving debt obligations are sensitive to changes in
interest rates. Our policy is to manage interest rates through use of a
combination of fixed and floating rate debt. Interest rate swaps may be used to
adjust interest rate exposures when appropriate. We have entered into interest
rate swaps for calendar year 2003 that require us to pay an average fixed
interest rate of 3.8% (based upon current rates under the revolving credit
facility) on $40.0 million of our outstanding revolving debt. Our revolving debt
was $117.4 million at December 31, 2002, and had an average interest rate of
3.23%. At June 30, 2003, we had a balance of $22.8 million that was classified
as long-term debt in the Company's balance sheet. As a result of the reduced
level of current and anticipated borrowings under the revolving credit facility
for the remainder of 2003, these interest rate swaps no longer qualify as cash
flow hedges and therefore $0.2 million has been expensed in the accompanying
financial statements.

Commodities Risk

        We use over-the-counter natural
gas and crude oil swap agreements and options to hedge sales of our production,
to hedge activity in our marketing segment, and to hedge the purchase of gas in
our utility segment against the inherent price risks of adverse price
fluctuations or locational pricing differences between a published index and the
NYMEX (New York Mercantile Exchange) futures market. These swaps and options
include (1) transactions in which one party will pay a fixed price (or variable
price) for a notional quantity in exchange for receiving a variable price (or
fixed price) based on a published index (referred to as price swaps), (2)
transactions in which parties agree to pay a price based on two different
indices (referred to as basis swaps), and (3) the purchase and sale of
index-related puts and calls (collars) that provide a "floor" price below which
the counterparty pays (production hedge) or receives (gas purchase hedge) funds
equal to the amount by which the price of the commodity is below the contracted
floor, and a "ceiling" price above which we pay to (production hedge) or receive
from (gas purchase hedge) the counterparty the amount by which the price of the
commodity is above the contracted ceiling.

        The primary market risks related
to our derivative contracts are the volatility in market prices and basis
differentials for natural gas and crude oil. However, the market price risk is
offset by the gain or loss recognized upon the related sale or purchase of the
natural gas or sale of the oil that is hedged. Credit risk relates to the risk
of loss as a result of non-performance by our counterparties. The counterparties
are primarily major investment and commercial banks which management believes
present minimal credit risks. The credit quality of each counterparty and the
level of financial exposure we have to each counterparty are periodically
reviewed to ensure limited credit risk exposure.


The following table provides information about our financial instruments that
are sensitive to changes in commodity prices. The table presents the notional
amount in Bcf (billion cubic feet) and MBbls (thousand barrels), the weighted
average contract prices, and the total dollar contract amount by expected
maturity dates. The "Carrying Amount" for the contract amounts is calculated as
the contractual payments for the quantity of gas or oil to be exchanged under
futures contracts and does not represent amounts recorded in our financial
statements. The "Fair Value" represents values for the same contracts using
comparable market prices at June 30, 2003. At June 30, 2003, the "Carrying
Amount" exceeded the "Fair Value" of these financial instruments by $37.8
million.

30

Expected Maturity Date

2003

2004

Carrying

   Fair

Carrying

Fair

Amount

  Value
Amount
Value

Natural Gas Production and Marketing:

Swaps with a fixed price receipt

   Contract volume (Bcf) 6.2 7.2

   Weighted average price per Mcf $ 3.46 $ 4.01

   Contract amount (in millions) $ 21.6 $ 8.5 $ 28.9 $ 20.4

Swaps with a fixed price payment

   Contract volume (Bcf) 0.1 -

   Weighted average price per Mcf $ 6.02 -

   Contract amount (in millions) $ 0.2 $ 0.2 - -

Price collar

   Contract volume (Bcf) 9.0 22.0

   Weighted average floor price per Mcf $ 3.30 $ 3.82

   Contract amount of floor (in millions) $ 29.9 $ 28.1 $ 84.0 $ 83.9

   Weighted average ceiling price per Mcf $ 5.07 $ 6.26

   Contract amount of ceiling (in millions) $ 45.8 $ 40.7 $ 137.8 $ 129.4

Oil Production:

Swaps with a fixed price receipt

   Contract volume (MBbls)
180 -

   Weighted average price per Bbl $ 26.73 -

    Contract amount (in millions) $ 4.8 $ 4.4 - -

Natural Gas Purchases:

Swaps with a fixed price payment

   Contract volume (Bcf)
0.6 1.1

   Weighted average price per Mcf $ 5.91 $ 5.91

    Contract amount (in millions) $ 3.4 $ 3.2 $ 6.7 $ 6.5

ITEM 4. CONTROLS AND PROCEDURES



Within the 90 days prior to the date of this report,
we carried out an evaluation under the supervision and with the participation of
our management, including our Chief Executive Officer and our Chief Financial
Officer, of the effectiveness of the design and operation of our disclosure
controls and procedures. There are inherent limitations to the effectiveness of
any system of disclosure controls and procedures, including the possibility of
human error and the circumvention or overriding of the controls and procedures.
Accordingly, even effective disclosure controls and procedures can only provide
reasonable assurance of achieving their control objectives. Based upon and as of
the date of our evaluation, our Chief Executive Officer and our Chief Financial
Officer concluded that the disclosure controls and procedures are effective in
all material respects to ensure that information required to be disclosed in the
reports we file and submit under the Exchange Act is recorded, processed,
summarized and reported as and when required.

31

PART II

OTHER INFORMATION

Items 1 - 3.

No
developments required to be reported under Items 1 - 3 occurred during the
quarter ended June 30, 2003.

Item 4. Submission of Matters to a Vote of Security Holders

The Company held its Annual
Meeting of Shareholders on May 14, 2003, for the purpose of electing Directors
of the Company for the ensuing year. Holders of 30,011,047 shares (87.5% of
total outstanding shares) voted in total.

Holders of 28,755,520 shares
voted for the election of directors and 1,255,527 shares voted as withheld. The
Directors were elected with the number of shares voted as follows:

Voted For

Withheld

Lewis E. Epley, Jr. 29,347,676 583,687

John Paul Hammerschmidt 29,528,895 402,468

Robert L. Howard 29,545,997 385,366

Harold M. Korell 29,706,568 782,583

Vello A. Kuuskraa 29,615,651 315,712

Kenneth R. Mourton 29,544,960 386,403

Charles E. Scharlau 29,383,904 547,459

Item 5.

No
developments required to be reported under Item 5 occurred during the quarter
ended June 30, 2003.

Item 6(a). Exhibits

(31.1)   Certification of CEO filed pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.

(31.2)   Certification of CFO filed pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.

(32)      Certification of CEO and CFO furnished
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.

32

Item 6(b). Reports on Form 8-K

Item

Financial Statements

Date of Report

Number

Required to be Filed

July 17, 2003

5,7 No

June 6, 2003

7,9 No

May 14, 2003

7,9 No

April 29, 2003

7,9 No

April 28, 2003

7,9 No

April 25, 2003

7,9 No

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.

SOUTHWESTERN
ENERGY COMPANY

Registrant

Date:

July 29, 2003

/s/ GREG D.
KERLEY

Greg D. Kerley

Executive Vice President

and Chief Financial Officer

33

	Payments Due by Period
			Less than			1 to 3		3 to 5		More than
	Total		1 Year			Years		Years		5 Years
					(in thousands)

Long-term debt	$	247,800	$	--		$	147,800	$	--	$	100,000
Operating leases⁽¹⁾		6,340		1,149			2,218		1,045		1,928
Unconditional purchase obligations⁽²⁾		--		--			--		--		--
Demand charges⁽³⁾		20,829		6,056			6,599		3,439		4,735
Other obligations⁽⁴⁾		1,960		1,960			--		--		--
	$	276,929	$	9,165		$	156,617	$	4,484	$	106,663

		Expected Maturity Date
		2003					2004
	Carrying		Fair		Carrying			Fair
	Amount		Value		Amount			Value

Natural Gas Production and Marketing:
Swaps with a fixed price receipt
Contract volume (Bcf)		6.2				7.2
Weighted average price per Mcf	$	3.46			$	4.01
Contract amount (in millions)	$	21.6	$	8.5	$	28.9		$	20.4

Swaps with a fixed price payment
Contract volume (Bcf)		0.1				-
Weighted average price per Mcf	$	6.02				-
Contract amount (in millions)	$	0.2	$	0.2		-			-

Price collar
Contract volume (Bcf)		9.0				22.0
Weighted average floor price per Mcf	$	3.30			$	3.82
Contract amount of floor (in millions)	$	29.9	$	28.1	$	84.0		$	83.9
Weighted average ceiling price per Mcf	$	5.07			$	6.26
Contract amount of ceiling (in millions)	$	45.8	$	40.7	$	137.8		$	129.4

Oil Production:
Swaps with a fixed price receipt
Contract volume (MBbls)		180				-
Weighted average price per Bbl	$	26.73				-
Contract amount (in millions)	$	4.8	$	4.4		-			-

Natural Gas Purchases:
Swaps with a fixed price payment
Contract volume (Bcf)		0.6				1.1
Weighted average price per Mcf	$	5.91			$	5.91
Contract amount (in millions)	$	3.4	$	3.2	$	6.7		$	6.5

	Voted For	Withheld
Lewis E. Epley, Jr.	29,347,676	583,687
John Paul Hammerschmidt	29,528,895	402,468
Robert L. Howard	29,545,997	385,366
Harold M. Korell	29,706,568	782,583
Vello A. Kuuskraa	29,615,651	315,712
Kenneth R. Mourton	29,544,960	386,403
Charles E. Scharlau	29,383,904	547,459

	Item	Financial Statements
Date of Report	Number	Required to be Filed

July 17, 2003	5,7	No
June 6, 2003	7,9	No
May 14, 2003	7,9	No
April 29, 2003	7,9	No
April 28, 2003	7,9	No
April 25, 2003	7,9	No

		SOUTHWESTERN ENERGY COMPANY
		Registrant


Date:	July 29, 2003	/s/ GREG D. KERLEY
		Greg D. Kerley Executive Vice President and Chief Financial Officer