UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended September 30, 2002
		For the quarterly period ended June 30, 2003
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to .

Commission file number 001-14256

Westport Resources Corporation

(Exact name of ~~Registrant~~registrant as specified in its charter)


Nevada		13-3869719
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1670 Broadway Street, Suite 2800

Denver, Colorado 80202-4800

(Address of principal executive offices)

(Zip Code)

(303) 573-5404

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

~~52,145,942 shares~~Indicate ofby ~~the~~check ~~issuer’s common~~mark ~~stock,~~whether ~~par~~the ~~value~~registrant ~~$0.01 per~~is an ~~share,~~accelerated ~~were~~filer ~~outstanding~~ (as ofdefined ~~November~~in Rule 1,12b-2 ~~2002~~of the Exchange Act). Yes þ No o

67,246,667 shares of the issuer’s common stock, par value $0.01 per share, were outstanding as of August 1, 2003.

TABLE OF CONTENTS

TABLE OF CONTENTS
PART I -- FINANCIAL INFORMATION
	Item 1. Financial Statements
~~CONSOLIDATED STATEMENTS OF OPERATIONS~~	CONSOLIDATED STATEMENTS OF OPERATIONS
~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~	CONSOLIDATED STATEMENTS OF CASH FLOWS
		CONDENSED CONSOLIDATING BALANCE SHEET
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
		CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures about Market Risk
	Item 4. Controls and Procedures
PART II -- OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 2. Changes in Securities and Use of Proceeds
	Item 2. Changes in Securities and Use of Proceeds.
	Item 3. Defaults Upon Senior Securities
	Item 3. Defaults Upon Senior Securities.
	Item 4. Submission of Matters to a Vote of Security Holders
	Item 4. Submission of Matters to a Vote of Security Holders.
	Item 5. Other Information
	Item 5. Other Information.
	Item 6. Exhibits and Reports on Form 8-K
	Item 6. Exhibits and Reports on Form 8-K.
SIGNATURES
CERTIFICATION
EXHIBIT INDEX
CERTIFICATION
EX-10.1 Change in Control Severance Agreement
INDEX TO EXHIBITS
EX-31.1 Certification Pursuant to Sec. 302, by CEO
EX-99.1 Certification Pursuant to 18 U.S.C.
EX-31.2 Certification Pursuant to Sec. 302, by CFO
EX-99.2 Certification Pursuant to 18 U.S.C.
EX-32.1 Certification Pursuant to Sec. 906, by CEO
EX-32.2 Certification Pursuant to Sec. 906, by CFO

WESTPORT RESOURCES CORPORATION

TABLE OF CONTENTS

		Page
PART I
PART I — FINANCIAL INFORMATION			1
FINANCIAL INFORMATION			1
Item 1.	Financial Statements		1
	Consolidated Balance Sheets as of September 30, 2002 (unaudited) and December 31, 2001		1
	Consolidated Balance Sheets as of June 30, 2003 (unaudited) and December 31, 2002		1
	Consolidated Statements of Operations for the three months and nine months ended September 30, 2002 and 2001 (unaudited)		2
	Consolidated Statements of Operations for the three months and six months ended June 30, 2003 and 2002 (unaudited)		2
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2002 and 2001 (unaudited)		3
	Consolidated Statements of Cash Flows for the six months ended June 30, 2003 and 2002 (unaudited)		3
	Notes to Consolidated Financial Statements (unaudited)		4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		1924
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		2937
Item 4.	Controls and Procedures		2937
PART II
PART II — OTHER INFORMATION			38
OTHER INFORMATION			30
Item 1.	Legal Proceedings		38
Item 1.	Legal Proceedings		30
Item 2.	Changes in Securities and Use of Proceeds		38
Item 2.	Changes in Securities and Use of Proceeds		30
Item 3.	Defaults Upon Senior Securities		39
Item 3.	Defaults Upon Senior Securities		30
Item 4.	Submission of Matters to a Vote of Security Holders		39
Item 4.	Submission of Matters to a Vote of Security Holders		30
Item 5.	Other Information		39
Item 5.	Other Information		30
Item 6.	Exhibits and Reports on Form 8-K		39
Item 6.	Exhibits and Reports on Form 8-K		30
Signatures			41
Signatures			32

PART I — FINANCIAL INFORMATION


Item 1.	*Financial Statements*

WESTPORT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

						September 30,				December 31,
					June 30,				December 31,
						2002				2001
					2003				2002
					(Unaudited)	~~(Unaudited)~~
					(In thousands,	~~(In thousands,~~
					except share data)	~~except share data)~~
ASSETS
Current Assets:
	Cash and cash equivalents				$	$65,865	~~35,273~~		$	$42,761	~~27,584~~
	Accounts receivable, net					81,520	~~47,511~~			73,549	~~61,808~~
	Derivative assets					8,401	~~4,992~~			14,861	~~7,832~~
	Prepaid expenses					14,771	~~10,574~~			13,358	~~5,474~~
			Total current assets	~~Total current assets~~		170,557	~~98,350~~			144,529	~~102,698~~
Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties				2,269,540	~~1,660,442~~			2,138,471	~~1,446,331~~
		Unproved properties				94,944	~~97,450~~			104,430	~~105,539~~
							1,757,892				1,551,870
						2,364,484				2,242,901
	Less accumulated depletion, depreciation and amortization					(592,905	~~(425,592~~)	)		(481,396	~~(280,737~~)	)
		Net oil and gas properties		~~Net oil and gas properties~~		1,771,579	~~1,332,300~~			1,761,505	~~1,271,133~~
	Building and other office furniture and equipment						9,390				8,099
	Field services assets					39,198				39,185
	Less accumulated depreciation					(560	~~(3,710~~)	)		—	~~(3,028~~	)
				Net building and other office furniture and equipment			5,680				5,071
		Net field services assets				38,638				39,185
Other assets:
	Building and other office furniture and equipment					10,274				9,686
	Long-term derivative assets						8,881				612
	Less accumulated depreciation					(4,246	)			(3,933	)
	Goodwill						246,712				214,844
		Net building and other office furniture and equipment				6,028				5,753
	Other assets						9,202				9,858
Other assets:
				Total other assets			264,795				225,314
	Long-term derivative assets					17,792				14,824
				Total assets		$	1,701,125			$	1,604,216
	Goodwill					244,647				246,712
LIABILITIES AND STOCKHOLDERS’ EQUITY
	Other assets					19,697				21,033
Current Liabilities:
			Total other assets			282,136				282,569
	Accounts payable					$	37,744			$	47,901
			Total assets		$	2,268,938			$	2,233,541
	Accrued expenses						36,568				30,294
LIABILITIES AND STOCKHOLDERS’ EQUITY
	Ad valorem taxes payable						11,979				6,930
Current Liabilities Accounts payable					$	48,572			$	51,158
	Derivative liabilities						21,652				3,289
	Accrued expenses					41,484				39,209
	Income taxes payable						519				550
	Ad valorem taxes payable					15,217				8,988
	Other current liabilities						—				369
	Derivative liabilities					98,173				56,156
				Total current liabilities			108,462				89,333
	Income taxes payable					83				86
Long-term debt							556,331				429,224
	Current asset retirement obligation					7,960				—
Deferred income taxes							141,090				158,005
			Total current liabilities			211,489				155,597
Long term derivative liabilities							4,026				5,956
Long-term debt						731,879				799,358
Other liabilities							814				1,402
Deferred income taxes						114,672				124,530
				Total liabilities			810,723				683,920
Long term derivative liabilities						42,632				21,305
Stockholders’ equity:
Long term asset retirement obligation						50,143				745
	6 1/2% convertible preferred stock, $.01 par value; 10,000,000 shares authorized; 2,930,000 issued and outstanding at September 30, 2002 and December 31, 2001, respectively						29				29
			Total liabilities			1,150,815				1,101,535
	Common stock, $0.01 par value; 70,000,000 authorized; 52,177,753 and 52,092,691 shares issued and outstanding at September 30, 2002 and, December 31, 2001, respectively						522				521
Stockholders’ equity:
	Additional paid-in capital						881,124				877,960
	6 1/2% convertible preferred stock, $.01 par value; 10,000,000 shares authorized; 2,930,000 issued and outstanding at June 30, 2003 and December 31, 2002, respectively					29				29
	Treasury stock-at cost; 33,617 and 30,000 shares at September 30, 2002 and December 31, 2001, respectively						(469	)			(408	)
	Common stock, $0.01 par value; 100,000,000 authorized; 67,237,667 and 66,823,830 shares issued and outstanding at June 30, 2003 and December 31, 2002, respectively					672				668
	Retained earnings						14,860				33,330
	Additional paid-in capital					1,156,031				1,150,345
	Accumulated other comprehensive income						(5,664	)			8,864
	Treasury stock-at cost; 35,681 and 33,617 shares at June 30, 2003 and December 31, 2002, respectively					(512	)			(469	)
			Total stockholders’ equity				890,402				920,296
	Retained earnings					32,469				2
				Total liabilities and stockholders’ equity		$	1,701,125			$	1,604,216
	Accumulated other comprehensive income
		Deferred hedge loss, net				(70,405	)			(18,408	)
		Cumulative translation adjustment				(161	)			(161	)
		Total stockholders’ equity				1,118,123				1,132,006
	Total liabilities and stockholders’ equity				$	2,268,938			$	2,233,541

The accompanying notes are an integral part of these consolidated financial statements.

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

				For the Three Months						For the Nine Months
				For the Three
				Ended September 30,						Ended September 30,
				Months Ended						For the Six Months
				2002			2001			2002			2001
				June 30,						Ended June 30,
				2003			2002			2003			2002
				(In thousands, except per share amounts)
				(Unaudited)
Operating revenues:
	Oil and natural gas sales			$	~~105~~195,~~423~~584		$	70113,~~157~~007		$	~~295~~414,~~442~~003		$	~~234~~190,~~405~~019
	Hedge settlements				(123,~~849~~439	)		(~~307~~577	)		1(63,~~509~~885	)		(13,~~824~~358	)
	Gathering income				783			—			1,992			—
	Commodity price risk management activities:
		Non-hedge settlements			—723			(~~1,025~~262	)		~~822~~723			~~(558~~822	)
		Non-hedge change in fair value of derivatives			~~(663~~902	)		171,~~720~~031			(83,~~885~~222	)		24(8,~~486~~222	)
	Gain (loss) on sale of operating assets, net				~~137~~6,074			—(1,868	)		(16,~~731~~466	)		—(1,868	)
			Net revenues		~~103~~180,~~048~~627			86111,~~545~~331			~~287~~362,~~157~~521			~~256~~184,~~509~~109
Operating costs and expenses:
	Lease operating expenses				2326,~~477~~032			1424,~~775~~229			6752,~~381~~368			3443,~~770~~904
	Production taxes				511,~~209~~364			35,~~009~~771			1624,~~845~~422			811,~~942~~636
	Transportation costs				23,~~179~~354			1,~~236~~951			67,~~782~~378			34,~~921~~603
	Exploration				3,596			13,463			21,638			24,333
	Gathering expenses				552			—			1,648			—
	Depletion, depreciation and amortization				47,686			31,222			147,066			72,251
	Exploration				13,624			7,700			25,671			18,042
	Impairment of unproved properties				2,788			1,366			9,078			3,114
	Depletion, depreciation and amortization				67,036			51,791			128,101			99,380
	Stock compensation expense				1,860			(2,331	)		1,954			(1,060	)
	Impairment of proved properties				977			—			977			—
	General and administrative				5,650			4,122			17,079			10,832
	Impairment of unproved properties				11,693			5,331			15,173			6,290
			Total operating expenses		92,445			66,862			287,823			157,103
	Stock compensation expense, net				2,153			(1,787	)		2,150			94
			Operating income (loss)		10,603			19,683			(666	)		99,406
	General and administrative				7,543			5,495			14,771			11,429
			Total operating expenses		144,328			100,481			272,659			195,378
			Operating income (loss)		36,299			10,850			89,862			(11,269	)
Other income (expense):
	Interest expense				(713,~~542~~058	)		(37,~~892~~978	)		(2329,~~891~~400	)		(416,~~483~~349	)
	Interest income				~~172~~180			~~456~~121			~~373~~381			~~1,522~~201
	Change in fair value of interest rate swap				—			~~2,249~~—			~~226~~—			~~1,877~~226
	Other				176			23			497			20
	Loss on debt retirement				(920	)		—			(920	)		—
					(7,194	)		(1,164	)		(22,795	)		(1,064	)
	Other				188			803			333			321
Income (loss) before income taxes					322,~~409~~689			183,~~519~~796			~~(23~~60,~~461~~256	)		98(26,~~342~~870	)
Benefit (provision) for income taxes:
	~~Current~~	Current			—			—			—			~~(2,006~~—	)
	~~Deferred~~	Deferred			(18,~~244~~281	)		(61,~~759~~386	)		8(21,~~563~~993	)		~~(33~~9,~~889~~807	)
			Total benefit (provision) for income taxes		(18,~~244~~281	)		(61,~~759~~386	)		8(21,~~563~~993	)		~~(35~~9,~~895~~807	)
	Net income (loss)			$	2,165		$	11,760		$	(14,898	)	$	62,447
		Net income (loss) before cumulative effect of change in accounting principle			14,408			2,410			38,263			(17,063	)
Preferred stock dividends					1,191			397			3,572			397
Cumulative effect of change in accounting principle (net of tax effect of $1,962)					—			—			(3,414	)		—
Net income (loss) available to common stockholders				$	974		$	11,363		$	(18,470	)	$	62,050
Net income (loss)					14,408			2,410			34,849			(17,063	)
Preferred stock dividends					(1,191	)		(1,191	)		(2,382	)		(2,381	)
Net income (loss) available to common stockholders				$	13,217		$	1,219		$	32,467		$	(19,444	)
Weighted average number of common shares outstanding:
	~~Basic~~	Basic			5267,~~144~~052			4452,~~527~~128			5266,~~118~~935			4052,~~496~~104
	~~Diluted~~	Diluted			5267,~~646~~942			4552,~~238~~760			5267,~~118~~787			4152,~~329~~104
Net income (loss) per common share:
	Basic			$	.02		$	.26		$	(.35	)	$	1.53
Basic:
	Diluted			$	.02		$	.25		$	(.35	)	$	1.50
	Net income (loss) before cumulative effect of change in accounting principle			$	.20		$	.02		$	.54		$	(.37	)
	Cumulative effect of change in accounting principle				—			—			(.05	)		—
			Net income (loss) available to common stockholders	$	.20		$	.02		$	.49		$	(.37	)
Diluted:
	Net income (loss) before cumulative effect of change in accounting principle			$	.19		$	.02		$	.53		$	(.37	)
	Cumulative effect of change in accounting principle				—			—			(.05	)		—
			Net income (loss) available to common stockholders	$	.19		$	.02		$	.48		$	(.37	)

The accompanying notes are an integral part of these consolidated financial statements.

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

				For the Nine Months Ended
				For the Six Months
				September 30,
				Ended June 30,
				2002			2001
				2003			2002
				(In thousands)
				(Unaudited)
Cash flows from operating activities:
	Net income (loss)			$	~~(14~~34,~~898~~849	)	$	62(17,~~447~~063	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Depletion, depreciation and amortization			~~147~~128,~~066~~101			7299,~~251~~380
		Exploratory dry hole costs			1214,~~359~~928			169,~~623~~795
		Impairment of unproved properties			9,078			3,114
		Impairment of proved properties			977			—
		Deferred income taxes			(8,563	)		33,889
		Impairment of unproved properties			15,173			6,290
		Director retainers settled for stock			20			—
		Deferred income taxes			21,993			(9,807	)
		Stock compensation expense			1,954			(1,060	)
		Director retainers settled for stock			11			20
		Change in fair value of derivatives			8,992			(26,363	)
		Stock compensation expense			2,150			94
		Amortization of derivative liabilities			(7,187	)		—
		Change in fair value of derivatives			3,514			7,996
		Amortization of deferred financing fees			782			633
		Amortization of derivative liabilities			(9,625	)		(5,018	)
		Loss on sale of operating assets, net			1,731			—
		Amortization of deferred financing fees			548			540
		Gain on sale of operating assets, net			(6,466	)		1,868
		Cumulative change in accounting principle, net of tax			3,414			—
		Changes in assets and liabilities, net of effects of acquisitions:
			Decrease in accounts receivable		17,893			27,001
			Decrease (increase) in accounts receivable		(15,423	)		5,023
			Decrease (increase) in prepaid expenses		(2,219	)		446
			Increase in prepaid expenses		(1,039	)		(2,992	)
			Decrease in accounts payable		(152,~~136~~511	)		(517,~~426~~889	)
			Increase in ad valorem taxes payable		26,~~161~~228			~~3,141~~502
			Increase (decrease) in income taxes payable		(44	)		306
			Decrease in income taxes payable		(3	)		(44	)
			Increase (decrease) in accrued expenses		6,669			(11,200	)
			Increase in accrued expenses		59			2,582
			Decrease in other liabilities		(~~818~~462	)		(~~107~~446	)
Net cash provided by operating activities					~~159~~196,~~840~~416			~~175~~80,~~695~~831
Cash flows from investing activities:
	Additions to property and equipment				(~~104~~115,~~918~~626	)		(~~132~~71,~~688~~769	)
	Proceeds from sales of assets				1013,~~552~~281			~~654~~7,790
	Acquisitions of oil and gas properties				(168,528	)		(6,319	)
	Acquisitions of oil and gas properties and purchase price adjustments				3,557			(42,303	)
	Other				~~(81~~—	)		(252	)
Net cash used in investing activities					(~~262~~98,~~975~~788	)		(~~138~~106,~~355~~334	)
Cash flows from financing activities:
	Proceeds from issuance of common stock				13,~~074~~530			~~264~~1,071
	Repurchase of common stock				(61	)		(408	)
	Proceeds from issuance of long-term debt				151,875			55,000
	Proceeds from issuance of long-term debt				155,000			255,000
	Repayment of long term debt				(226,311	)		—
	Repayment of long term debt				(45,000	)		(273,284	)
	Preferred stock dividends paid				(2,381	)		(2,381	)
	Preferred stock dividends paid				(3,572	)		—
	Repurchase of common stock				(43	)		(61	)
	Gain on interest rate swap cancellation				3,705			—
	Loss on retirement of debt							(920	)
	Financing fees				(~~322~~274	)		(~~2,036~~271	)
Net cash provided by financing activities					110,824			(20,464	)
Net cash provided by (used in) financing activities					(74,524	)		53,358
Net increase in cash and cash equivalents					723,~~689~~104			1627,~~876~~855
Cash and cash equivalents, beginning of period					2742,~~584~~761			2027,~~154~~584
Cash and cash equivalents, end of period				$	3565,~~273~~865		$	3755,~~030~~439
Supplemental cash flow information:
	Cash paid for interest			$	2333,~~862~~182		$	1217,~~016~~664
	Cash paid for income taxes			$	443		$	~~1,700~~44

The accompanying notes are an integral part of these consolidated financial statements.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


1.	Organization and Nature of Business

On August 21, 2001, the stockholders of each of Westport Resources Corporation, a Delaware corporation (“Old Westport”), and Belco Oil & Gas Corp., a a Nevada corporation (“Belco”), approved the Agreement and Plan of Merger dated as of June 8, 2001 (the “Merger Agreement”), between Belco and Old Westport. Pursuant to the Merger Agreement, Old Westport was merged with and into Belco (the “Merger”), with Belco surviving as the legal entity and changing its name to Westport Resources Corporation (the “Company” or “Westport”). The merger of Old Westport into Belco was accounted for as a purchase transaction for financial accounting purposes. Because former Old Westport stockholders owned a majority of the outstanding Westport common stock immediately after the Merger, the Merger iswas accounted for as a reverse acquisition in which Old Westport is the purchaser of Belco. ~~Business~~Westport ~~activities of~~began consolidating the ~~Company~~results ~~include~~of ~~the~~Belco ~~exploration~~with ~~for~~its ~~and~~results ~~production~~as of August 21, ~~oil~~2001, closing date. Business activities of the Company include oil and natural gas exploitation, ~~primarily~~acquisition and inexploration ~~the~~activities, ~~Gulf~~primarily ofin ~~Mexico,~~ the Rocky Mountains, the Gulf Coast, ~~and~~ the West Texas/ Mid-Continent area and the Gulf of Mexico.


2.	Unaudited Consolidated Financial Statements

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments (consisting only of normal recurring items) necessary to present fairly the financial position of the Company as of ~~September~~June 30, ~~2002~~2003 and the results of its operations and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the Securities and Exchange Commission’s rules and regulations. Certain amounts reported in the prior year consolidated financial statements have been reclassified to correspond to the current year presentation. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the full year. Management believes the disclosures made are adequate to ensure that the information is not misleading, and suggests that these financial statements be read in conjunction with the Company’s December 31, ~~2001~~ 2002 audited financial statements set forth in the Company’s Form 10-K.


3.	Debt

Long-term debt consisted of:

	September 30,			December 31,
	June 30,			December 31,
	2002			2001
	2003			2002
	(In thousands)
	(in thousands)
8 1/4% senior subordinated notes due 2011	$	283,474	(1)	$	272,147	(2)
8 1/4% Senior Subordinated Notes Due 2011	$	731,879	(1)	$	591,771	(2)
8 7/8% senior subordinated notes due 2007		127,857	(3)		122,077	(2)
8 7/8% Senior Subordinated Notes due 2007		—			127,587	(3)
Revolving credit facility due on July 1, 2005		145,000			35,000
Revolving Credit Facility due on December 16, 2006		—			80,000
		556,331			429,224
					799,358
Less current portion		—			—
	$	~~556~~731,~~331~~879		$	~~429~~799,~~224~~358

(1)	The balance noted above at September 30, 2002 of the 8 1/4% Senior Subordinated Notes reflects an increase of $8,474,000 related to fair market value adjustments recorded as a result of the Company’s interest rate swaps accounted for as fair value hedges. See Interest Rate Swaps — Hedges below.
(2)	The balances noted above at December 31, 2001 of the 8 1/4% Senior Subordinated Notes and the 8 7/8% Senior Subordinated Notes reflect reductions of $2,853,000 and $2,353,000, respectively, related to fair market value adjustments recorded as a result of the Company’s interest rate swaps accounted for as fair value hedges. See Interest Rate Swaps — Hedges below.

(1)

The balance of the 8 1/4% Senior Subordinated Notes Due 2011 as of June 30, 2003 reflects the aggregate face amount of $700 million plus $15.1 million related to the premium recorded in connection with the issuance of 8 1/4% Senior Subordinated Notes Due 2011 on December 17, 2002 and April 3, 2003 (see 8 1/4% Senior Subordinated Notes Due 2011 below) and an increase of $16.8 million related to fair market value adjustments recorded as a result of the Company’s interest rate swaps accounted for as fair value hedges. See Interest Rate Swaps — Hedges below.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(3) The balance noted above at September 30, 2002 of the 8 7/8% Senior Subordinated Notes reflects an increase of $3,675,000 related to the gain on the cancellation of the fair market value hedge, which will be amortized over the remaining life of the note.


(2)	The balance of the 8 1/4% Senior Subordinated Notes Due 2011 as of December 31, 2002 reflects an increase of $8.9 million related to the premium recorded in connection with the issuance of 8 1/4% Senior Subordinated Notes Due 2011 on December 17, 2002 (see 8 1/4% Senior Subordinated Notes Due 2011 below) and an increase of $7.9 million related to fair market value adjustments recorded as a result of the Company’s interest rate swaps accounted for as fair value hedges. The face amount of the notes at December 31, 2002 was $575.0 million. See Interest Rate Swaps — Hedges below.

(3)	There was no balance outstanding with respect to the 8 7/8% Senior Subordinated Notes due 2007 as of June 30, 2003, since all of these notes were redeemed on May 5, 2003. The balance of the 8 7/8% Senior Subordinated Notes due 2007 as of December 31, 2002 reflects increases of $3.5 million related to the gain on the cancellation of the fair market value hedge, which is amortized over the life of the notes. The face amount of the 8 7/8% Senior Subordinated Notes due 2007 at December 31, 2002 was $122.7 million. See 8 7/8% Senior Subordinated Notes due 2007 below.


	*Revolving Credit Facility*

~~Upon~~On ~~closing~~December 17, ~~of the Merger~~2002, the Company entered into a new credit facility (“the “Revolving Credit Facility”) with aJPMorgan ~~syndicate~~Chase ~~of banks~~Bank, ~~which~~Credit ~~was~~Suisse First ~~subsequently~~Boston ~~amended~~Corporation onand ~~November 5,~~certain ~~2001.~~other lenders party thereto to replace the Company’s previous revolving credit facility. The Revolving Credit Facility, ~~as amended,~~ provides for a maximum committed amount of $~~500~~600 million and aan initial borrowing base of approximately $~~400~~470 million ~~as of September 30, 2002~~. The facility matures on ~~July~~ December 116, ~~2005~~2006. ~~Advances~~In ~~under~~the past, the Company made borrowings under the Revolving Credit Facility ~~are~~to inrefinance its outstanding indebtedness under the ~~form~~previous ofrevolving ~~either~~credit anfacility ~~ABR~~and ~~loan~~to orpay ageneral ~~Eurodollar~~corporate ~~loan~~expenses.

~~The~~Advances ~~interest~~under ~~on an ABR loan is a fluctuating rate based upon~~ the ~~highest~~Revolving ~~of:~~Credit ~~(1) the~~Facility ~~rate of interest~~are ~~announced~~in ~~by JP Morgan Chase Bank, as its prime rate; (2)~~ the ~~secondary~~form ~~market rate for three month certificates~~ of ~~deposit~~either ~~plus~~an ~~1%;~~ABR ~~and~~loan ~~(3) the~~or ~~Federal funds effective rate plus 0.5%, plus in each case~~ a ~~margin~~Eurodollar ~~of 0% to 0~~loan.~~125%~~ ~~based~~The upon the ratio of total debt to EBITDAX. EBITDAX represents earnings before exploration; depletion, depreciation and amortization; impairment of unproved properties; stock compensation expense; non-hedge change in fair value of derivatives; interest ~~expense; change in fair value of interest rate swap; loss~~ on ~~sale~~an ofABR ~~operating assets, net amortization of deferred financing fees; and total benefit (provision) for income taxes. The interest on a Eurodollar~~ loan is a fluctuating rate based upon the ~~rate at which Eurodollar deposits in the~~ ~~London~~highest ~~interbank market are quoted plus a margin~~ of ~~1.25% to~~: ~~1.50% based upon the ratio of Total debt to EBITDAX.~~

As• ofthe ~~September 30,~~rate ~~2002,~~of ~~the~~interest ~~Company~~announced ~~had borrowings~~by ofJP ~~$145 million~~Morgan ~~outstanding~~Chase ~~with~~Bank, aas ~~weighted average~~its ~~interest~~prime rate; of• ~~4.23%,~~the ~~outstanding~~secondary ~~letters~~market ofrate ~~credit issued~~for ofthree ~~approximately~~month ~~$3.8 million~~certificates ~~and~~of ~~available~~deposits ~~unused borrowing~~plus ~~capacity~~1%; ofor ~~approximately~~• ~~$251.2 million under~~ the ~~Revolving~~Federal ~~Credit~~funds ~~Facility~~effective rate plus 0. 5%

8 in ~~7/8~~each case plus a margin of 0% ~~Senior~~to ~~Subordinated~~0.625% ~~Notes~~based upon ~~due~~the ~~2007~~ratio of total debt to EBITDAX, as defined below, and the ratings of the Company’s senior unsecured debt as issued by Standard and Poor’s Rating Group and Moody’s Investor Services, Inc. EBITDAX is a financial measure calculated on the basis of methodologies other than Generally Accepted Accounting Principles (“GAAP”). For purposes of the Revolving Credit Facility, EBITDAX is defined to mean net income of the Company and its restricted subsidiaries determined on a consolidated basis in accordance with GAAP, plus (a) to the extent deducted from revenues in determining consolidated net income, (i) the aggregate amount of consolidated interest expense, (ii) the aggregate amount of letter of credit fees paid, (iii) the aggregate amount of income tax expense and (iv) all amounts attributable to depreciation, depletion, exploration, amortization and other non-cash charges and expenses, minus (b) to the extent included in revenues in determining consolidated net income, all non-cash extraordinary income, in each case determined on a consolidated basis in accordance with GAAP and without duplication of amounts.

InThe ~~connection~~interest ~~with~~on ~~the~~a ~~Merger,~~Eurodollar ~~the~~loan ~~Company assumed~~is ~~$147 million face amount of Belco’s~~a ~~8 7/8% Senior~~fluctuating ~~Subordinated~~rate ~~Notes~~based ~~due~~upon ~~2007.~~the ~~On November 1,~~rate ~~2001,~~at ~~approximately~~which ~~$24.3 million face~~Eurodollar ~~amount~~deposits ofin the ~~notes~~London ~~was~~interbank ~~tendered~~market toare ~~the~~quoted ~~Company~~plus ~~pursuant~~a ~~to the~~margin ~~change~~ of ~~control provisions of the related indenture~~1.000% ~~The tender price was equal~~ to ~~101~~1.875% ofbased upon the ~~principal~~ratio ~~amount~~ of ~~each note plus accrued and unpaid interest as of October 29, 2001. Including the premium and accrued interest, the~~ total ~~amount~~ ~~paid~~debt ~~was $24.8 million. The Company used borrowings under its Revolving Credit Facility~~ to ~~fund the repayment. No~~ ~~gain~~EBITDAX orand ~~loss was recorded in connection with~~ the ~~redemption~~ratings ~~as the fair value~~ of the ~~8 7/8% Senior~~Company’s ~~Subordinated~~senior ~~Notes~~unsecured ~~recorded~~debt inas ~~connection~~issued ~~with~~by ~~the~~Standard ~~Merger~~and ~~was~~Poor’s ~~equal~~Rating toGroup ~~the~~and ~~redemption~~Moody’s ~~cost~~Investor Service, Inc.

8 The Revolving Credit Facility contains various covenants and default provisions applicable to the Company and its restricted subsidiaries, including two financial covenants that require the Company to maintain a current ratio of not less than 1~~/4%~~.0 ~~Senior~~to ~~Subordinated~~1.0 ~~Notes~~and ~~due~~a ~~2011~~ratio of EBITDAX to consolidated interest

On November 5, 2001, the Company completed the private placement of $275 million of 8 1/4% Senior Subordinated Notes due 2011 pursuant to Rule 144A under the Securities Act of 1933, as amended. The notes are non-callable until November 1, 2006, when the Company has the right to redeem them for 104.125% of the face value, declining thereafter to face value in 2009. Proceeds of approximately $268 million, net of underwriting discounts, were used to reduce outstanding indebtedness under the Revolving Credit Facility. On March 14, 2002, the Company completed the exchange of these notes for new notes with substantially identical terms, except that the new notes are generally freely tradeable.

Interest Rate Swaps — Hedges

On November 21, 2001, the Company entered into two separate interest rate swaps to hedge the fair value of a portion of the 8 7/8% Senior Subordinated Notes and 8 1/4% Senior Subordinated Notes. The swap on

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~the~~expense ~~8 7/8% Senior~~for ~~Subordinated~~the ~~Notes had~~preceding afour ~~notional~~consecutive ~~amount of $122.7 million and an expiration~~fiscal ~~date~~quarters of ~~September 15,~~not ~~2007.~~less ~~Under~~than ~~this swap agreement, the Company paid the counterparty a variable rate (LIBOR +~~ 3.~~44%) and~~0 ~~received~~to ~~a fixed rate (8 7/8%)~~1.0. OnCommitment ~~September 16, 2002~~fees ~~the~~under ~~interest rate swap on~~ the ~~8 7/8% Senior~~ ~~Subordinated~~Revolving ~~Notes~~Credit ~~was~~Facility ~~terminated~~range ~~resulting~~from ~~in $5~~0.~~8 million being~~25% ~~paid~~ to ~~the Company~~0.5% The Company recorded a $2.1 million reduction in interest expense and a $3.7 million fair value gain which was added to the outstanding debt balance and will be amortized over the remaining life of the note. The swap on the ~~8 1/4% Senior~~average ~~Subordinated~~daily ~~Notes has a notional~~ amount of ~~$100.0 million and an expiration date~~ of ~~November 1,~~ ~~2011. Under~~ the ~~swap~~available ~~agreement,~~unused ~~the~~borrowing ~~Company~~capacity ~~pays~~based ~~the counterparty a variable rate (LIBOR +2.42%) and receives a fixed rate (8 1/4%). Beginning~~ on ~~November 1,~~ ~~2006~~ the ~~counterparty~~rating ~~has~~of the ~~option~~Company’s ~~to terminate~~senior ~~the~~unsecured ~~swap on any date beginning on November 1,~~debt ~~2006,~~as ~~subject~~issued toby anStandard ~~early termination fee ranging from $4.125 million at November 1, 2006 to $0 on or after November 1, 2009. The early termination dates~~ and ~~fees mirror~~Poor’s ~~the~~Rating ~~prepayment~~Group ~~terms~~ and ~~prepayment penalties included in~~ ~~the~~Moody’s ~~indenture~~Investor ~~related~~Service, ~~to the 8 1/4% Senior Subordinated Notes~~Inc.

~~The~~Under the terms of the Revolving Credit Facility the Company ~~has~~must ~~documented~~meet ~~and~~certain ~~designated~~tests ~~these~~before it is able to declare ~~interest~~or ~~rate~~pay ~~swaps~~any asdividend ~~hedges~~on of(other ~~the~~than ~~fair~~dividends ~~value~~payable ofsolely ain equity ~~portion~~interests of the ~~8 7/8% Senior~~Company ~~Subordinated~~other ~~Notes~~than ~~and~~disqualified stock), ~~8 1/4% Senior~~or ~~Subordinated~~make ~~Notes.~~any ~~Because~~payment ~~these~~of, ~~swaps meet~~or ~~the~~set ~~conditions~~apart toassets ~~qualify~~for a sinking or other analogous fund for the ~~“short~~purchase, ~~cut”~~redemption, defeasance, ~~method~~retirement or other acquisition of, ~~assessing~~any ~~effectiveness~~shares ~~under~~of ~~the~~any ~~provisions~~class of ~~Statement~~equity interests of ~~Financial~~the ~~Accounting~~Company ~~Standards~~or ~~(“SFAS”)~~any of its restricted ~~No. 133~~subsidiaries, ~~“Accounting~~whether ~~for~~now ~~Derivative~~or ~~Instruments~~hereafter ~~and~~outstanding, or make any ~~Hedging~~other ~~Activities~~distribution in respect thereof,” ~~the~~either ~~change~~directly or indirectly, whether in ~~the~~cash ~~fair~~or ~~value~~property or in obligations of the ~~debt~~Company isor ~~assumed~~any torestricted ~~equal~~subsidiary. ~~the~~Other ~~change~~covenants ininclude restrictions ~~the~~on ~~fair~~incurring ~~value~~additional ofindebtedness, ~~the~~liens, and ~~interest~~guarantee ~~rate~~obligations; ~~swaps.~~limitations Ason ~~such~~fundamental changes and sales of assets; restrictions on making certain investments, loans ~~there~~or isadvances; nolimitations ~~ineffectiveness~~on optional redemption of ~~assumed~~subordinated toindebtedness; ~~exist~~restrictions ~~between~~on ~~the~~transacting ~~interest~~with affiliates, ~~rate~~changing ~~swaps~~lines of business and ~~the~~entering ~~Senior~~into certain ~~Subordinated~~hedging ~~Notes~~agreements; and limitations on sale and leasebacks and use of proceeds.

4As of June 30, 2003, the Company had no outstanding indebtedness and letters of credit of approximately $104. ~~Commodity~~5 million outstanding under the Revolving Credit ~~Derivative~~Facility. ~~Instruments~~Available unused borrowing capacity was approximately $365.5 million. The letters of credit were issued primarily in connection with the margin requirements of the Company’s oil and ~~Hedging~~natural ~~Activities~~gas derivative contracts. The Revolving Credit Facility currently limits the outstanding letters of credit to $200 million.

~~The~~8 Company periodically enters into commodity price risk management (“CPRM”) transactions to manage its exposure to oil and gas price volatility. CPRM transactions may take the form of futures contracts, swaps or options. All CPRM transactions are accounted for in accordance with the requirements of SFAS No. 133 which the Company adopted on January 1,/4% ~~2001.~~Senior ~~Accordingly,~~Subordinated ~~unrealized~~Notes ~~gains~~due and losses related to the change in fair market value of derivative contracts which qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss and such amounts are reclassified to oil and gas sales revenues as the associated production occurs. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current income or expense in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of CPRM activities. 2011

~~Upon~~On ~~adoption~~April 3, of2003, ~~SFAS~~the ~~No. 133~~Company onissued ~~January~~$125 1,million ~~2001,~~in ~~the~~additional ~~Company~~principal ~~recorded~~amount aof ~~derivative~~the ~~liability~~8 1/4% ofSenior ~~approximately~~Subordinated ~~$4.7 million~~Notes ~~for~~Due ~~the~~2011 ~~fair~~pursuant ~~market~~to ~~value~~Rule 144A ofand ~~its~~Regulation S ~~derivative~~under ~~instruments~~the ~~designated~~Securities asAct ~~cash flow~~of ~~hedges~~1933 ~~and~~(the “Securities Act”) at a ~~corresponding~~price ~~loss~~of 106% of ~~approximately~~the ~~$3.1 million~~principal ~~(net~~amount, ofwith ~~tax~~accrued ~~effect~~interest offrom $November 1, 2002.~~6 million)~~ asThe ~~a cumulative~~2003 ~~effect~~notes ofwere aissued ~~change~~as inadditional ~~accounting~~debt ~~principle~~securities under inthe ~~other comprehensive~~indenture ~~income.~~pursuant ~~The~~to ~~Company~~which, ~~reclassified~~on ~~approximately~~November 5, 2001, the Company issued $~~1.8~~275 million ~~hedging~~of ~~loss~~8 1/4% Senior Subordinated Notes Due 2011 and on December 17, 2002, the Company issued $~~1.5~~300 million ~~hedging~~of 8 1/4% Senior ~~gain~~Subordinated ~~for~~Notes Due 2011. All of the ~~three~~2001 and ~~nine~~2002 ~~months~~notes ~~ended~~were subsequently ~~September~~exchanged on March 3014, 2002 and March 12, 2003, respectively, ~~from~~for ~~accumulated~~equal ~~other~~principal ~~comprehensive~~amounts ~~income~~of notes having tosubstantially ~~oil~~identical terms and ~~gas~~registered ~~sales~~under ~~revenues~~the Securities Act. The ~~hedging~~proceeds ~~gains~~from ~~and~~the ~~losses reclassified~~2003 tonotes ~~revenues~~were ~~include~~used ~~realized~~to fund ~~losses~~the redemption of the Company’s 8 7/8% Senior ~~$3.2~~Subordinated Notes due 2007 (described below) on May ~~million~~5, 2003 and $4to reduce the indebtedness under the Revolving Credit Facility.6 We have agreed to file an exchange offer registration statement, or under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2003 notes. On June ~~million~~4, ~~for~~2003, the ~~three~~Company ~~and~~filed ~~nine~~the ~~months~~exchange ~~ended~~offer ~~September 30~~registration statement relating to the 2003 notes. In the event the Company fails, ~~2002~~among other things, ~~respectively~~to effect the registration statement or consummate the exchange offer relating to the 2003 notes on a timely basis, the Company will pay additional interest on such notes.

~~For~~The ~~the~~notes ~~three~~are ~~months~~senior ~~ended~~subordinated ~~September 30,~~unsecured ~~2002,~~obligations of the Company ~~recorded~~and noare ~~non-hedge~~guaranteed ~~CPRM~~on ~~settlements,~~a ansenior ~~unrealized~~subordinated ~~change~~basis inby ~~fair~~some ~~value~~ of ~~non-hedge~~its ~~derivatives~~existing ofand future restricted ~~($0~~subsidiaries.~~7) million~~ ~~and~~The nonotes ~~ineffectiveness~~mature ~~loss~~on November 1, 2011. ~~For~~The Company pays interest on the ~~nine months~~notes ~~ended~~semi-annually ~~September~~on May ~~30,~~1 and ~~2002~~November 1. ~~the~~The Company ~~recorded~~is entitled to redeem the notes ~~non-hedge~~in ~~CPRM~~whole ~~settlements~~or ofin ~~$0.8~~part on or after November ~~million~~1, ~~and~~2006 anfor the ~~unrealized~~redemption ~~change~~price inset ~~fair~~forth ~~value~~in ofthe ~~non-hedge~~notes. ~~derivatives~~Prior ofto ~~($8.9)~~November ~~million~~1, ~~which~~2006, ~~included~~the aCompany ~~$0.2 million~~is entitled to redeem the ~~ineffectiveness~~notes, ~~loss.~~in ~~The~~whole ~~non-hedge~~but ~~CPRM~~not ~~settlements~~in ~~include realized~~part, ~~losses~~at ofa ~~$1.1 million~~redemption ~~and~~price ~~$1.3 million~~equal ~~for~~to the ~~three~~principal ~~and~~amount ~~nine~~of ~~months~~the ~~ended~~notes ~~September 30,~~plus ~~2002,~~a premium. There is no ~~respectively~~sinking fund for the notes.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The indenture governing the 8 1/4% Senior Subordinated Notes Due 2011 limits the activity of the Company and ~~recognized~~its ~~decreases~~restricted subsidiaries. The provisions of such indenture limit the ability of the Company and ~~increases~~its restricted subsidiaries to incur additional indebtedness; pay dividends on capital stock or redeem, repurchase or retire such capital stock or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company; engage in ~~oil~~transactions ~~and~~with ~~natural~~the ~~gas~~Company’s ~~revenues~~affiliates; sell assets, including capital stock of ~~($1.8) million~~the Company’s subsidiaries; and ~~($0~~consolidate, merge or transfer assets.~~3) million~~ During any period that these notes have investment grade ratings from ~~settled~~both ~~hedging~~Moody’s Investors ~~agreements~~Service, ~~for~~Inc. ~~the~~and Standard and Poor’s Ratings ~~three~~Group ~~months~~and ~~ended~~no ~~September 30,~~default ~~2002~~has occurred and ~~2001~~is continuing, the ~~respectively~~foregoing covenants will cease to be in effect with the exception of covenants that contain limitations on liens and ~~$1.5~~on, among other things, certain consolidations, mergers and transfers ~~($1~~of assets. The 8) ~~million~~1/4% ~~for~~Senior ~~the~~Subordinated ~~nine~~Notes ~~months~~Due ~~ended~~2011 ~~September 30,~~do ~~2002~~not ~~and~~currently ~~2001,~~qualify ~~respectively~~as investment grade.

As8 of September 30, 2002, the Company had approximately 0.9 Mmbbls of oil and 3.5 Bcf of natural gas subject to CPRM contracts for the remainder of 2002. The 2002 contracts have weighted average floor prices of $22.78 per barrel and $2.85 per Mmbtu, with weighted average ceiling prices of $25.41 per barrel and $3.11 per Mmbtu, respectively. In addition for the fourth quarter of 2002, the Company had 0.92 Bcf of puts purchased at a weighted average price of $3.13 per Mmbtu. The Company has approximately 4.7/8 ~~Mmbbls~~% ofSenior ~~oil~~Subordinated ~~and~~Notes ~~30.2 Bcf~~due of natural gas subject to CPRM contracts for 2003. The 2003 contracts have weighted average floor prices of $23.08 per barrel and $3.65 per Mmbtu, with weighted average ceiling prices of $25.03 per barrel and $4.40 per Mmbtu, respectively. The contracts discussed above represent both the Company’s hedge and non-hedge positions as of September 30, 2002. 2007

~~The~~In ~~summary~~connection ~~tables~~with ~~below~~the ~~provide~~Merger, ~~details~~the ~~about~~Company assumed $147 million face amount, $149 million fair value, of Belco’s 8 7/8% Senior Subordinated Notes due 2007. On November 1, 2001, approximately $24.3 million face amount of these notes was tendered to the ~~volumes~~Company ~~and~~pursuant to ~~prices~~the change of ~~all~~control ~~open~~provisions ~~CPRM~~of the related indenture. The tender price was equal to 101% of the principal amount of each note plus accrued and unpaid interest as of October 29, ~~hedge~~2001. Including the premium and ~~non-hedge~~accrued ~~commitments~~interest, the total amount paid to repay the tendered notes was $24.8 million. The Company used borrowings under its previous revolving credit facility to fund the repayment. No gain or loss was recorded in connection with the redemption as the fair value of ~~September~~the 8 307/8% Senior Subordinated Notes recorded in connection with the Merger equaled the redemption cost. On May 5, ~~2002~~2003, the Company redeemed the remaining outstanding 8 7/8% Senior Subordinated Notes due 2007 in the aggregate principal amount of approximately $123 million. Including the premium and accrued interest, the total amount paid to redeem these notes was $129.7 million. The redemption was funded with the proceeds from the offering of $125 million aggregate principal amount of the Company’s 8 1/4% Senior Subordinated Notes Due 2011, issued on April 3, 2003. The remaining proceeds were used to reduce indebtedness under the Revolving Credit Facility. The Company recorded a $0.9 million loss in connection with the redemption of the 8 7/8% Senior Subordinated Notes due 2007.

				2002		2003
Hedges
	Gas
		Price Swaps Sold-receive fixed price (thousand Mmbtu)(1)			1,286		9,780
			Weighted average price, per Mmbtu	$	2.96	$	4.00
		Collars Sold (thousand Mmbtu)(2)			1,230		12,433
			Weighted average floor price, per Mmbtu	$	2.47	$	3.54
			Weighted average ceiling price, per Mmbtu	$	3.10	$	4.52
		Puts Purchased (thousand Mmbtu)(3)			920		—
			Weighted average price, per Mmbtu	$	3.13		—
		Three-way Collars (Mmbtu)(2)(4)			300		8,030
			Three-way average floor price, per Mmbtu	$	2.40	$	2.22
			Weighted average floor price, per Mmbtu	$	3.00	$	3.39
			Weighted average ceiling price, per Mmbtu	$	3.40	$	4.73
	Oil
		Price Swaps Sold-receive fixed price (Mbbls)(1)			225		875
			Weighted average price, per bbl	$	24.07	$	21.80
		Collars Sold (Mbbls)(2)			45		1,620
			Weighted average floor price, per bbl	$	20.00	$	24.44
			Weighted average ceiling price, per bbl	$	26.75	$	26.33
		Three-way Collars (Mbbls)(2)(4)			550		1,995
			Three-way average floor price, per bbl	$	18.92	$	18.91
			Weighted average floor price, per bbl	$	23.09	$	23.18
			Weighted average ceiling price, per bbl	$	27.02	$	26.30


	*Interest Rate Swaps-Hedges*

The following table summarizes the interest rate swap contracts the Company currently has in place:

Notional Amount

Transaction Date

Expiration Date

Current Estimated Rate

$100 million

November 2001

November 1, 2011

LIBOR + 2.42%

$ 50 million

January 2003

November 1, 2011

LIBOR + 3.37%

$ 40 million

January 2003

November 1, 2011

LIBOR + 3.55%

$ 50 million

January 2003

November 1, 2011

LIBOR + 3.42%

The Company entered into the interest rate swap contracts above to hedge the fair value of a portion of the 8 1/4% Senior Subordinated Notes Due 2011. Because these swaps meet the conditions to qualify for the “short cut” method of assessing effectiveness under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 133, the change in the fair value of the notes is assumed to equal the change in the fair value of the interest rate swap. As such, there is no ineffectiveness assumed to exist between the interest rate swap and the notes.

The interest rate swaps are fixed for floating swaps in that the Company receives the fixed rate of 8.25% and pays the floating rate. The floating rate is redetermined every six months based on the London

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

				2002		2003
Non-Hedges
	Gas
		Calls Sold (thousand Mmbtu)(3)			644		—
			Weighted average price, per Mmbtu	$	3.27		—
	Oil
		Calls Sold (Mbbls)(3)			45		—
			Weighted average price, per bbl	$	22.00		—
		Price Swaps Sold-receive fixed price (Mbbls)(1)			75		300
			Weighted average price, per bbl	$	18.86	$	18.86

Interbank Offered Rate (“LIBOR”) in effect at the contractual reset date. When LIBOR plus the applicable margin shown above is less than 8.25%, the Company receives a payment from the counterparty equal to the difference in rate times the notional amount. When LIBOR plus the applicable margin shown above is greater than 8.25%, the Company pays the counterparty the difference in rate times the notional amount. As of June 30, 2003, the Company recorded a derivative asset of $16.8 million related to the interest rate swap designated as a fair value hedge, with a corresponding debt increase. Based on the fair value of the interest rate swaps at June 30, 2003, the Company could expect to receive cash flows of approximately $2 million per year.

(1)	For any particular swap sold transaction, the counterparty is required to make a payment to Westport in the event that the NYMEX Reference Price for any settlement period is less than the swap price for such hedge, and Westport is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the swap price for such hedge.
(2)	For any particular collar transaction, the counterparty is required to make a payment to Westport if the average NYMEX Reference Price for the reference period is below the floor price for such transaction, and Westport is required to make payment to the counterparty if the average NYMEX Reference Price is above the ceiling price of such transaction.
(3)	Calls or puts are sold under written option contracts in return for a premium received by Westport upon the initiation of the contract. Westport is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the price of the call sold, or less than the price of the put sold. Conversely, calls or puts bought in return for Westport’s payment of a premium require the counterparty to make a payment to Westport in the event that the NYMEX Reference Price on any settlement period is greater than the call price or less than the put price.
(4)	Three-way collars are settled as described in footnote (2) above, with the following exception: if the NYMEX Reference Price falls below the three-way floor price, the average floor price is adjusted by the amount by which the NYMEX Reference Price is below the three-way floor price. For example, on a three-way oil collar, if the NYMEX Reference Price is $18.00 per bbl during the term of the 2002 three-way collars, then the average floor price would be $22.17 per bbl.

In September 2002, the Company terminated an interest rate swap on the 8 7/8% Senior Subordinated Notes due 2007 resulting in the receipt of a $3.7 million fair value gain, which was added to the outstanding balance of the notes and was amortized until May 5, 2003, the date of redemption of all of the Company’s outstanding 8 7/8% Senior Subordinated Notes due 2007. See 8 7/8% Senior Subordinated Notes due 2007 discussed above.

54. ~~Earnings~~ ~~Per Share~~Commodity ~~and~~Derivative ~~Other~~Instruments ~~Comprehensive~~and ~~Income~~Hedging ~~(Loss)~~ Activities

~~Earning~~ The ~~per~~Company ~~Share~~periodically enters into commodity price risk management (“CPRM”) transactions to manage its exposure to oil and gas price volatility. The Company typically hedges between 20% and 40% of its expected production, one to two years into the future. Currently, the Company has approximately 60-70% of expected production hedged in 2003 to protect cash flow and return expectations on the significant assets acquired by the Company in late 2002. CPRM transactions may take the form of futures contracts, swaps or options. All CPRM data is presented in accordance with the requirements of SFAS No. 133 which the Company adopted on January 1, 2001. Accordingly, unrealized gains and losses related to the change in fair market value of derivative contracts which qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss and such amounts are reclassified to oil and gas sales revenues as the associated production occurs. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current income or expense in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of CPRM activities.

~~Basic~~For ~~earnings~~the ~~per~~six ~~share~~months ~~are~~ended ~~computed~~June 30, by2003 ~~dividing~~and ~~net~~2002, ~~earnings~~the ~~attributable~~Company toreclassified ~~common~~approximately ~~stock~~$63.9 million of byhedging ~~the~~losses ~~weighted~~and $3.4 million of hedging gains, ~~average~~respectively, ~~number~~out of ~~common~~accumulated ~~shares~~other ~~outstanding~~comprehensive ~~during~~income ~~each~~into oil ~~period,~~and gas sales revenues. The hedging losses and gains ~~excluding~~reclassified ~~treasury~~to ~~shares~~revenues include cash losses of $66.1 million and $1.3 million for the six months ended June 30, 2003 and 2002, respectively.

The Company recorded non-hedge CPRM settlement gains of $0.7 million and $0.8 million for the six months ended June 30, 2003 and 2002, respectively. The Company also recorded unrealized change in fair value of non-hedge derivatives of $3.2 million, which included $4.2 million ineffectiveness loss, and ($8.2) million with $0.2 million ineffectiveness loss for the six months ended June 30, 2003 and 2002, respectively. The non-hedge CPRM settlements include cash losses of $2.6 million and $0.2 million for the six months ended June 30, 2003 and 2002, respectively.

As of June 30, 2003, the Company had the following CPRM transactions in place covering hedge and non-hedge positions:


	•	2.4 Mmbbls of oil and 37.5 Bcf of natural gas subject to CPRM contracts for the remainder of 2003. Of these contracts, all of the oil and 32.0 Bcf of the natural gas contracts are subject to weighted average NYMEX floor prices of $23.20 per barrel and $3.78 per Mmbtu and weighted

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Diluted earnings per share are computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock and stock options.


		average NYMEX ceiling prices of $25.29 per barrel and $4.20 per Mmbtu, respectively, excluding the effect, if any, of the three-way floor price. Of the remaining 2003 natural gas CPRM contract settlements, 3.7 Bcf are calculated based on the Northwest Pipeline Rocky Mountain Index (“NWPRM”) at weighted average NWPRM floor and ceiling prices of $3.00 and $3.29, respectively, and 1.8 Bcf are calculated based on the Colorado Interstate Gas Index (“CIG”) at a weighted average swap price of $3.59. In addition, included in the 32.0 Bcf of natural gas contracts are basis swaps covering 6.7 Bcf of natural gas for 2003 that lock in the pricing differential between NYMEX and NWPRM at a weighted average price differential of $0.67 per Mmbtu, 1.8 Bcf of natural gas for 2003 that lock in the pricing differential between NYMEX and CIG at a weighted average price differential of $0.95 per Mmbtu and 4.9 Bcf of natural gas for 2003 that lock in the pricing differential between CIG and NWPRM at a weighted average price differential of $0.42 per Mmbtu.

	•	2.9 Mmbbls of oil and 53.0 Bcf of natural gas subject to CPRM contracts for 2004. Of these contracts, all of the oil and 42.0 Bcf of the natural gas contracts are subject to weighted average floor prices of $24.13 per barrel and $3.94 per Mmbtu and weighted average NYMEX ceiling prices of $25.29 per barrel and $4.14 per Mmbtu, respectively, excluding the effect, if any, of the three-way floor price. The remaining 2004 natural gas CPRM contract settlements are calculated based on the NWPRM Index with a weighted average swap price of $3.33 per Mmbtu. In addition, included in the 42.0 Bcf of natural gas contracts are basis swaps covering 3.7 Bcf of natural gas for 2004 that lock in the pricing differential between NYMEX and NWPRM at a weighted average price differential of $0.66 per Mmbtu and 1.8 Bcf of natural gas for 2004 that lock in the pricing differential between NYMEX and CIG at a weighted average price differential of $0.81.

	•	20.1 Bcf of natural gas subject to CPRM contracts for 2005 with a weighted average NYMEX floor price of $4.29 and weighted average NYMEX ceiling price of $4.48 per Mmbtu. Included in the 20.1 Bcf of natural gas contracts are basis swaps covering 3.7 Bcf of natural gas for 2005 that lock in the pricing differential between NYMEX and NWPRM at a weighted average price differential of $0.78 Mmbtu.

The ~~following~~tables ~~sets~~below ~~forth~~provide details about the volumes ~~calculation~~and prices of ~~basic~~ all open CPRM hedge and ~~diluted~~non-hedge commitments ~~earnings~~as ~~per~~of ~~share~~June 30, 2003:

			For the Three Months								For the Nine Months
					2003				2004				2005
			Ended September 30,								Ended September 30,
Hedges
			2002				2001				2002				2001
	Gas
			(In thousands except per share amount)
		NYMEX Price Swaps Sold — receive fixed price (thousand Mmbtu)(1)				16,196				21,960				16,425
Net income (loss) available to common stockholders			$	974			$	11,363			$	(18,470	)		$	62,050
			Average price, per Mmbtu		$	4.01			$	4.11			$	4.35
Weighted average common shares outstanding				52,144				44,527				52,118				40,496
		NWPRM Price Swaps Sold — receive fixed price (thousand Mmbtu)(2)				—				10,980				—
	Add dilutive effects of employee stock options			502				711				—				833
			Average price, per Mmbtu		$	—			$	3.33			$	—
Weighted average common shares outstanding including the effects of dilutive securities				52,646				45,238				52,118				41,329
		CIG Price Swaps Sold — receive fixed price, per Mmbtu(3)				1,840				—				—
Basic earnings per share			$	.02			$	.26			$	(.35	)		$	1.53
			Average price, per Mmbtu		$	3.59			$	—			$	—
Diluted earning per share			$	.02			$	.25			$	(.35	)		$	1.50
		NYMEX Collars Sold (thousand Mmbtu)(4)				11,740				16,380				3,650
			Average floor price, per Mmbtu		$	3.61			$	3.70			$	4.00
			Average ceiling price, per Mmbtu		$	4.29			$	4.00			$	5.07

Comprehensive Income (Loss)

The Company follows SFAS No. 130, “Reporting Comprehensive Income,” which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to the owners of the Company. The components of other comprehensive income for the nine months ended September 30, 2002 and 2001 are as follows (in thousands):

			Nine Months Ended			Nine Months Ended
			September 30,			September 30,
			2002			2001
Net income (loss) available to common stockholders			$	(18,470	)	$	62,050
Other comprehensive income
	Cumulative effect of change in accounting principle			—			(3,100	)
	Change in fair value of derivative hedging instruments			(13,569	)		11,608
	Enron non-cash settlements reclassified to income			(897	)		—
	Hedge settlements reclassified to income			(62	)		(1,158	)
		Other comprehensive income		(14,528	)		7,350
Comprehensive income (loss)			$	(32,998	)	$	69,400

6. Acquisitions

On September 30, 2002 the Company acquired southeast Texas oil and gas properties for a total cash purchase price of approximately $120 million, subject to certain purchase price adjustments. The Company estimates the total proved reserves in the acquired properties to be approximately 76 Bcfe, of which 82% is natural gas. The Company will operate essentially all of the properties. The purchase also includes 10,000 net undeveloped acres and an interest in 300 square miles of 3-D seismic data. The Company used funds drawn under its revolving credit facility and cash flow from operations to pay for the acquisition. The purchase price allocation is subject to change resulting from, among other things, actual changes in working capital. We expect to be able to finalize the purchase price allocation by December 2002.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7. Recent Accounting Pronouncements


					2003			2004			2005

		NWPRM Collars Sold (thousand Mmbtu)(5)				3,680			—			—
			Average ceiling price, per Mmbtu		$	3.29		$	—		$	—
		NYMEX Three-way Collars (thousand Mmbtu)(4),(6)				4,048			3,660			—
			Average floor price, per Mmbtu		$	3.39		$	4.00		$	—
			Average ceiling price, per Mmbtu		$	4.73		$	5.00		$	—
			Three-way average floor price, per Mmbtu		$	2.22		$	3.15		$	—
		Basis Swaps versus NYMEX(7) NWPRM (thousand Mmbtu)				6,748			3,660			3,650
			Average differential price, per Mmbtu		$	0.67		$	0.66		$	0.78
			CIG (thousand Mmbtu)			1,840			1,830			—
			Average differential price, per Mmbtu		$	0.95		$	0.81		$	—
	Oil
		NYMEX Price Swaps Sold — receive fixed price (Mbbls)(1)				304			1,830			—
			Average price, per bbl		$	21.39		$	24.31		$	—
		NYMEX Collars Sold (Mbbls)(4)				990			—			—
			Average floor price, per bbl		$	24.45		$	—		$	—
			Average ceiling price, per bbl		$	26.45		$	—		$	—
		NYMEX Three-way Collars (Mbbls)(4)(6)				1,002			1,098			—
			Average floor price, per bbl		$	23.17		$	23.83		$	—
			Average ceiling price, per bbl		$	26.30		$	26.92		$	—
			Three-way average floor price, per bbl		$	18.90		$	19.00		$	—
Non-Hedges
	Gas
		Basis Swaps, Index versus Index(8)
			NWPRM versus CIG (thousand Mmbtu)			4,920			—			—
				Average differential price, per Mmbtu	$	0.42		$	—		$	—
	Oil
		NYMEX Price Swaps Sold, receive fixed price (Mbbls)(1)				150			—			—
			Average price, per bbl		$	18.86		$	—		$	—
Estimated fair value of oil and gas derivatives as of June 30, 2003 (in thousands)					$	(89,772	)	$	(15,521	)	$	(9,319	)

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which addresses, among other things, the financial accounting and reporting for goodwill subsequent to an acquisition. The new standard eliminates the requirement to amortize acquired goodwill; instead, such goodwill is to be reviewed at least annually for impairment. We recorded goodwill in connection with the Belco Merger for our cost or investment in excess of the fair value of the net acquired assets as of August 21, 2001. In accordance with the provisions of SFAS No. 142 no goodwill amortization has been recorded. We adopted SFAS No. 142 effective January 1, 2002.


(1)	For any particular NYMEX swap sold transaction, the counterparty is required to make a payment to Westport in the event that the NYMEX Reference Price for any settlement period is less than the swap price for such hedge, and Westport is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the swap price for such hedge.

(2)	For any particular NWPRM swap sold transaction, the counterparty is required to make a payment to Westport in the event that the NWPRM Index Price for any settlement period is less than the swap price for such hedge, and Westport is required to make a payment to the counterparty in the event

In accordance with SFAS No. 142, we were required to perform an initial impairment review of our goodwill as of January 1, 2002 and will perform an annual impairment review hereafter. We completed the initial step of the transitional goodwill impairment test during the second quarter of fiscal 2002 in accordance with the provisions of SFAS No. 142, which requires that this step be completed within six months from the date of adoption. This step of the goodwill impairment test compares the fair value of a reporting unit with its carrying amount, including goodwill. Based on results of these comparisons, goodwill in each of our reporting units has not been impaired.

During the second quarter ended June 30, 2002, the Company completed the final evaluation of the purchase price allocation in connection with the Merger. Reclassifications were made from unproved and proved oil and natural gas properties totaling $19.7 and $10.3 million, respectively, to goodwill. In addition, goodwill was increased by $1.9 million as a result of additional merger costs and other miscellaneous adjustments.

The total adjustment to unproved properties was comprised of two components. The first component resulted from the determination that, as of the date of the Merger, certain acreage positions had expired. The second component resulted from a difference in the way acreage was allocated to proved properties. Prior to the Merger, Belco allocated only net well acreage to a specific spacing tract, while Westport had a policy of allocating acreage to proved properties based on an assumption that a producing well holds all the acreage on a lease. The application of Westport’s policy to Belco properties resulted in a reduced acreage position.

The adjustment to proved properties was made as a result of the final evaluation by an outside consulting firm of the fair value of certain non-core properties in the lower 15% of the value of Belco properties acquired in the Merger. The final evaluation determined that the value of these properties included unsupportable estimates of certain undeveloped reserves. This final evaluation was done as part of a Company wide divestiture program that began subsequent to the Merger. The following table summarizes the goodwill allocation to the reporting units as of June 30, 2002. There have been no changes to the goodwill allocation since June 30, 2002.

	Northern		Southern
	Division		Division
	Segment		Segment		Total
Goodwill Acquired (August 21, 2001)	$	33,416	$	181,428	$	214,844
Adjustments confirmed by information received subsequent to the Merger that existed at the date of the Merger		—		31,868		31,868
Balance as of June 30, 2002	$	33,416	$	213,296	$	246,712

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of liabilities for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company will adopt SFAS No. 143 on January 1, 2003, and is in the process of determining the effects of adopting SFAS No. 143 on its financial position or results of operations.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale and requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The Company adopted SFAS No. 144 on January 1, 2002. The adoption of SFAS No. 144 did not have an effect on the Company’s financial position or results of operations.


	that the NWPRM Index Price for any settlement period is greater than the swap price for such hedge.

(3)	For any particular CIG swap sold transaction, the counterparty is required to make a payment to Westport in the event that the CIG Index Price for any settlement period is less than the swap price for such hedge, and Westport is required to make a payment to the counterparty in the event that the CIG Index Price for any settlement period is greater than the swap price for such hedge.

(4)	For any particular NYMEX collar transaction, the counterparty is required to make a payment to Westport if the average NYMEX Reference Price for the reference period is below the floor price for such transaction, and Westport is required to make payment to the counterparty if the average NYMEX Reference Price is above the ceiling price of such transaction.

(5)	For any particular NWPRM collar transaction, the counterparty is required to make a payment to Westport if the average NWPRM Index Price for the reference period is below the floor price for such transaction, and Westport is required to make payment to the counterparty if the average NWPRM Index Price is above the ceiling price of such transaction.

(6)	Three way collars are settled as described in footnote (4) above, with the following exception: if the NYMEX Reference Price falls below the three-way floor price, the average floor price is reduced by the amount the NYMEX Reference Price is below the three-way floor price. For example, if the NYMEX Reference Price is $18.00 per bbl during the term of the 2003 three-way collars, then the effective average floor price would be $22.27 per bbl.

(7)	For any particular basis swap versus NYMEX, the counterparty is required to make a payment to Westport in the event that the difference between the NYMEX Reference Price and the applicable published index (NWPRM or CIG) for any settlement period is greater than the swap differential price for such hedge, and Westport is required to make a payment to the counterparty in the event that the difference between the NYMEX Reference Price and the applicable published index (NWPRM or CIG) for any settlement period is less than the swap differential price for such hedge.

(8)	These basis swaps are based on the difference between CIG and NWPRM indices. The counterparty is required to make a payment to Westport in the event that CIG plus the swap differential price exceeds NWPRM for any settlement period, and Westport is required to make a payment to the counterparty in the event that the CIG price plus the swap differential price is less than NWPRM for any settlement period.

~~In April 2002, the FASB issued SFAS No~~5. ~~145, “Rescission~~ Earnings ~~of FASB Statements No. 4, 44 and 64,~~Per ~~Amendment~~Share ~~of FASB Statement No. 13~~ and ~~Technical Corrections.”~~Other ~~Prior~~Comprehensive toIncome ~~the adoption of the provisions of SFAS No. 145, generally accepted accounting principles~~ (~~“GAAP”~~Loss) ~~required gains or losses on the early~~ ~~extinguishment of debt be classified in a company’s~~ periodic consolidated statements of operations as extraordinary gains or losses, net of associated income taxes, below the determination of income or loss from continuing operations. SFAS No. 145 changes GAAP to require, except in the case of events or transactions of a highly unusual and infrequent nature, gains or losses from the early extinguishment of debt be classified as components of a company’s income or loss from continuing operations. The Company will adopt the provisions of SFAS No. 145 on January 1, 2003. The adoption of the provisions of SFAS No. 145 is not expected to affect the Company’s financial position or results of operations.

InEarnings ~~June~~per 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of SFAS No. 146 is not expected to have an effect on the Company’s financial position or results of operations. Share

8Basic earnings per share are computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding during each period, excluding treasury shares. ~~Segment~~ ~~Information~~

~~The~~Diluted ~~Company~~earnings ~~operates~~per inshare ~~three~~are ~~geographic divisions:~~computed ~~Northern, which manages properties in the Rocky~~by ~~Mountain~~adjusting ~~region; Southern, which manages properties in~~ the ~~West Texas/~~average ~~Mid-Continent~~number ~~area and the onshore Gulf Coast regions; and Gulf~~ of ~~Mexico,~~common ~~which~~shares ~~manages~~outstanding ~~the offshore properties. All~~for ~~three areas are engaged in~~ the ~~production,~~dilutive ~~development~~effect, ~~acquisition~~ ~~and~~if ~~exploration~~any, of ~~oil~~convertible ~~and~~preferred ~~natural~~stock ~~gas properties. The Company evaluates segment performance based on the profit or loss from operations before income taxes. Corporate general~~ and ~~administrative~~stock ~~expenses are allocated to the three geographic divisions~~options. ~~Consolidated and segment financial information is as~~ ~~follows:~~

	For the Nine Months Ended September 30,
					Gulf of			Corporate &
	Northern		Southern		Mexico			Unallocated			Consolidated
	(In thousands)
2002
Revenues(1)	$	91,316	$	108,737	$	93,658		$	(6,554	)	$	287,157
DD&A		34,100		55,893		56,744			329			147,066
Profit (loss)		13,944		1,398		(7,056	)		(8,952	)		(666	)
Expenditures for assets, net		62,657		150,261		59,236			1,292			273,446
2001
Revenues(1)		68,525		39,305		126,575			22,104			256,509
DD&A		14,239		11,561		46,320			131			72,251
Profit (loss)		26,380		15,975		38,981			18,070			99,406
Expenditures for assets, net		13,850		6,992		53,008			303			74,153

(1) Corporate and unallocated revenues consist of non-hedge and hedge settlements, and non-hedge change in fair value of derivatives.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	For the Three Months Ended September 30,
					Gulf of			Corporate &
	Northern		Southern		Mexico			Unallocated			Consolidated
	(In thousands)
2002
Revenues(1)	$	33,005	$	38,789	$	33,766		$	(2,512	)	$	103,048
DD&A		11,597		17,600		18,386			103			47,686
Profit (loss)		7,492		5,405		2,181			(4,475	)		10,603
Expenditures for assets, net		5,372		136,537		17,220			245			159,374
2001
Revenues(1)		20,954		17,103		32,100			16,388			86,545
DD&A		6,266		6,825		18,087			44			31,222
Profit (loss)		5,527		3,749		(6,456	)		16,863			19,683
Expenditures for assets, net		11,098		4,260		37,932			56			53,346

The following sets forth the calculation of basic and diluted earnings per share:

(1) Corporate and unallocated revenues consist of non-hedge and hedge settlements, and non-hedge change in fair value of derivatives.



			For the Six Months
			Ended June 30,

			2003			2002


			(In thousands, except
			per share amounts)
Net income (loss) per share:
	Net income (loss) before cumulative effect of change in accounting principle		$	38,263		$	(17,063	)
	Cumulative change in accounting principle			(3,414	)		—

	Net income (loss)			34,849			(17,063	)
	Preferred stock dividends			(2,382	)		(2,381	)

	Net income (loss) available to common stockholders		$	32,467		$	(19,444	)
	Weighted average common shares outstanding			66,935			52,104
		Add dilutive effects of employee stock options		852			—

	Weighted average common shares outstanding including the effects of dilutive securities			67,787			52,104

	Basic earnings (loss) per share common before cumulative effect of change in accounting principle		$	.54		$	(.37	)

	Basic earnings (loss) per common share		$	.49		$	(.37	)

	Diluted earnings (loss) per common share before cumulative effect of change in accounting principle		$	.53		$	(.37	)

	Diluted earnings (loss) per common share		$	.48		$	(.37	)

~~9. Subsequent Event~~ Comprehensive Income (Loss)

OnThe ~~November 6, 2002 the~~ Company ~~agreed~~follows ~~to purchase~~SFAS ~~from El~~No. ~~Paso Corporation and certain of its~~130, ~~affiliated~~“Reporting ~~companies~~Comprehensive ~~natural~~Income,” ~~gas~~which ~~properties and midstream~~establishes ~~gathering~~standards ~~and compression assets located in Utah~~ for areporting ~~purchase price~~comprehensive ofincome. ~~approximately~~In ~~$502 million,~~addition ~~subject~~ to ~~certain~~net ~~purchase~~income, ~~price~~comprehensive ~~adjustments.~~income ~~The~~includes ~~Company~~all ~~expects~~changes toin ~~close the~~equity ~~transaction~~during ina ~~December~~period, ofexcept ~~2002.~~those ~~The~~resulting ~~Company~~from ~~estimates~~investments ~~that in~~and ~~total~~distributions to the ~~assets~~owners ~~would add approximately 600 Bcfe~~ of ~~proved reserves to~~ the Company~~’s reserve base~~. ~~Currently these assets are producing approximately 80 Mmcfe/d.~~ The ~~Company~~components of ~~plans~~other tocomprehensive ~~fund~~income for the ~~transaction~~six ~~initially~~months ~~with debt and is~~ended ~~currently pursuing additional financing options~~June 30, ~~including issuance~~2003 ofand ~~equity~~2002, ~~the sale of assets~~respectively, ~~securing~~are aas ~~partner for a~~follows: ~~portion of the acquisition or other capital markets transactions.~~

10. Condensed Consolidated Financial Statements of Subsidiary Guarantors



		For the Six Months Ended									For the Six Months Ended
		June 30, 2003									June 30, 2002

		Gross			Tax Effect			Net			Gross			Tax Effect		Net


		(In thousands)
Net income (loss) available to common stockholders		$	54,460		$	(21,993	)	$	32,467		$	(29,251	)	$	9,807	$	(19,444	)
Other comprehensive income
	Change in fair value of derivative hedging instruments		(145,770	)		53,206			(92,564	)		(10,252	)		3,742		(6,510	)
	Enron non-cash settlements reclassified to income		(1,154	)		421			(733	)		(1,060	)		387		(673	)
	Hedge settlements reclassified to income		65,039			(23,739	)		41,300			(2,299	)		839		(1,460	)

Comprehensive income (loss)		$	(27,425	)	$	7,895		$	(19,530	)	$	(42,862	)	$	14,775	$	(28,087	)

On November 5, 2001 the Company completed a private placement of the 8 1/4% Senior Subordinated Notes due 2011, which were subsequently exchanged on March 14, 2002 for new notes with substantially identical terms (see Note 3). The 8 1/4% Senior Subordinated Notes are fully and unconditionally guaranteed, jointly and severally, on a senior subordinated unsecured basis by the following wholly-owned subsidiaries of Westport: Westport Finance Co., Jerry Chambers Exploration Company, Westport Argentina LLC, Westport Canada LLC, Westport Oil and Gas Company, L.P., Westport Overriding Royalty LLC, WHG, Inc. and WHL, Inc. (collectively, the “Subsidiary Guarantors”). The guarantees of the Subsidiary Guarantors are subordinated to senior debt of the Subsidiary Guarantors. The only existing subsidiary of Westport that has not guaranteed the 8 1/4% Senior Subordinated Notes is Horse Creek Trading and Compression LLC, which is minor for purposes of the Securities and Exchange Commission’s rules regarding presentation of the condensed consolidating financial statements below. As such, the financial position, results of operations, and related cash flow information of Horse Creek have been included in the Subsidiary Guarantor column.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~Presented below are condensed consolidating financial statements for Westport and the Subsidiary Guarantors~~6. Stock Compensation

~~CONDENSED~~The ~~CONSOLIDATING~~Company ~~BALANCE~~has elected to continue following ~~SHEET~~Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and has elected to adopt the disclosure provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” Had compensation costs for the Company’s options been determined based on the fair value at the grant dates consistent with SFAS No. 123, the Company’s net income would have been decreased and the net loss would have been increased to the pro forma amounts indicated below:

				September 30, 2002
			For the Three Months								For the Six Months
				Parent				Subsidiary
			Ended June 30,								Ended June 30
				Company				Guarantors				Eliminations				Consolidated
			2003				2002				2003				2002
				(In thousands)
			(In thousands, except per share amounts)
ASSETS
Net income (loss) available to common stockholders
Current Assets:
	As reported		$	13,217			$	1,219			$	32,467			$	(19,444	)
	Cash and cash equivalents			$	10,934			$	24,339			$	—			$	35,273
	Pro forma			12,545				(1,240	)			28,695				(23,685	)
	Accounts receivable, net				19,388				28,123				—				47,511
Basic net income (loss) per common share
	Intercompany receivable				994,904				—				(994,904	)			—
	As reported		$	.20			$	.02			$	.49			$	(.37	)
	Derivative assets				4,992				—				—				4,992
	Pro forma			.19				(.02	)			.43				(.45	)
	Prepaid expenses				3,490				7,084				—				10,574
Diluted net income (loss) per common share
		Total current assets			1,033,708				59,546				(994,904	)			98,350
	As reported		$	.19			$	.02			$	.48			$	(.37	)
Property and equipment, at cost:
	Pro forma			.18				(.02	)			.42				(.45	)
	Oil and natural gas properties, successful efforts method:
		Proved properties			325,535				1,334,907				—				1,660,442
		Unproved properties			28,617				68,833				—				97,450
	Building and other office furniture and equipment				594				8,796				—				9,390
					354,746				1,412,536				—				1,767,282
	Less accumulated depletion, depreciation and amortization				(115,114	)			(314,188	)			—				(429,302	)
		Net property and equipment			239,632				1,098,348				—				1,337,980
Other assets:
	Long-term derivative assets				8,881				—				—				8,881
	Goodwill				—				246,712				—				246,712
	Other assets				9,093				109				—				9,202
		Total other assets			17,974				246,821				—				264,795
		Total assets		$	1,291,314			$	1,404,715			$	(994,904	)		$	1,701,125
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable			$	13,628			$	24,116			$	—			$	37,744
	Accrued expenses				24,040				12,528				—				36,568
	Ad valorem taxes payable				—				11,979				—				11,979
	Intercompany payable				—				994,904				(994,904	)			—
	Derivative liabilities				21,652				—				—				21,652
	Income taxes payable				(248	)			767				—				519
		Total current liabilities			59,072				1,044,294				(994,904	)			108,462
Long-term debt					556,331				—				—				556,331
Deferred income taxes					6,098				134,992				—				141,090
Long-term derivative liabilities					4,026				—				—				4,026
Other liabilities					—				814				—				814
		Total liabilities			625,527				1,180,100				(994,904	)			810,723
Stockholders’ equity:
	Preferred stock				29				—				—				29
	Common stock				522				3				(3	)			522
	Additional paid-in capital				681,967				199,154				3				881,124
	Treasury stock				(469	)			—				—				(469	)
	Retained earnings				(10,598	)			25,458				—				14,860
	Accumulated other comprehensive income				(5,664	)			—				—				(5,664	)
		Total stockholders’ equity			665,787				224,615				—				890,402
		Total liabilities and stockholders’ equity		$	1,291,314			$	1,404,715			$	(994,904	)		$	1,701,125


7.	Recent Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of liabilities for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on January 1, 2003 and recorded a cumulative effect of a change in accounting principle on prior years of $3.4 million, net of tax effects, related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred. The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells and offshore platform facilities. On January 1, 2003 the Company also recorded $58.7 million of asset retirement obligations (using a 7.6% discount rate), an increase in the carrying amount of its oil and gas properties of $49.6 million and a decrease to accumulated depreciation of $3.8 million. Changes to the Company’s asset retirement obligations from January 1 to June 30 of 2003 are presented below:


	2003

	(In thousands)
Asset retirement obligation — January 1	$	58,735
Accretion		2,114
Additions		438
Settlements		(3,184	)

Asset retirement obligation — June 30		58,103
Less: Current asset retirement obligation		(7,960	)

Long-term asset retirement obligation	$	50,143

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~CONDENSED~~The ~~CONSOLIDATING~~Company’s ~~STATEMENT~~current OFand long-term asset ~~OPERATIONS~~retirement obligations are included in current asset retirement liabilities and long-term asset retirement liabilities, respectively, on the accompanying June 30, 2003 consolidated balance sheet.

			For the Nine Months Ended September 30, 2002
			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated
			(In thousands)
Operating revenues:
	Oil and natural gas sales		$	52,007		$	243,435		$	—	$	295,442
	Hedge settlements			1,509			—			—		1,509
	Non-hedge settlements			822			—			—		822
	Non-hedge change in fair value of derivatives			(8,885	)		—			—		(8,885	)
	Loss on sale of operating assets, net			—			(1,731	)		—		(1,731	)
		Net revenues		45,453			241,704			—		287,157
Operating costs and expenses:
	Lease operating expense			10,306			57,075			—		67,381
	Production taxes			4			16,841			—		16,845
	Transportation costs			202			6,580			—		6,782
	Exploration			14,264			7,374			—		21,638
	Depletion, depreciation and amortization			32,014			115,052			—		147,066
	Impairment of unproved properties			2,182			6,896			—		9,078
	Stock compensation expense			1,954			—			—		1,954
	General and administrative			4,501			12,578			—		17,079
		Total operating expenses		65,427			222,396			—		287,823
		Operating income (loss)		(19,974	)		19,308			—		(666	)
Other income (expense):
	Interest expense			(23,663	)		(228	)		—		(23,891	)
	Interest income			100			273			—		373
	Change in fair value of interest rate swap			—			226			—		226
	Other			462			35			—		497
Income (loss) before income taxes				(43,075	)		19,614			—		(23,461	)
Provision for income taxes:
	Deferred			15,722			(7,159	)		—		8,563
		Total provision for income taxes		15,722			(7,159	)		—		8,563
Net loss				(27,353	)		12,455			—		(14,898	)
Preferred stock dividends				3,572			—			—		3,572
Net loss available to common stock			$	(30,925	)	$	12,455		$	—	$	(18,470	)

The pro forma effects of the application of SFAS No. 143, as if the Statement had been adopted net of tax on January 1, 2002 (rather than January 1, 2003), are presented below:



		Pro Forma
		For the Three				Pro Forma
		Months				For the Six Months
		Ended June 30,				Ended June 30

		2003		2002		2003		2002


		(In thousands, except per share amounts)
Net income (loss) available to common stockholders
	As reported	$	13,217	$	1,219	$	32,467	$	(19,444	)
	Pro forma		13,217		1,723		32,467		(20,057	)
Basic net income (loss) per common share
	As reported	$	.20	$	.02	$	.49	$	(.37	)
	Pro forma		.20		.03		.49		(.38	)
Diluted net income (loss) per common share
	As reported	$	.19	$	.02	$	.48	$	(.37	)
	Pro forma		.19		.03		.48		(.38	)

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections.” Prior to the adoption of the provisions of SFAS No. 145, GAAP required that gains or losses on the early extinguishment of debt be classified in a company’s periodic consolidated statements of operations as extraordinary gains or losses, net of associated income taxes, below the determination of income or loss from continuing operations. SFAS No. 145 changes GAAP to require, except in the case of events or transactions of a highly unusual and infrequent nature, gains or losses from the early extinguishment of debt be classified as components of a company’s income or loss from continuing operations. The Company adopted the provisions of SFAS No. 145 on January 1, 2003. In May 2003, the Company recorded a $0.9 million loss in connection with the early extinguishment of debt in 2003.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The Company adopted SFAS No. 146 on January 1, 2003. The adoption of SFAS No. 146 has not had an effect on the Company’s financial position or results of operations.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-based Compensation-Transition and Disclosure.” SFAS No. 148 amends FASB No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair-value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS No. 148 has no material impact on the Company, as the Company does not plan to adopt the fair-value method of accounting for stock options at the current time.

In November 2002, the FASB issued Financial Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others — an

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~CONDENSED~~interpretation ~~CONSOLIDATING~~of ~~STATEMENT~~FASB OFStatements ~~CASH~~Nos. 5, ~~FLOWS~~57, and 107 and rescission of FASB Interpretation No. 34” (“FIN 45”). FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The adoption of FIN 45 has not had any effect on the Company’s financial position or results of operations.

					For the Nine Months Ended September 30, 2002
					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated
					(In thousands)
Cash flows from operating activities:
	Net loss				$	(27,353	)	$	12,455		$	—		$	(14,898	)
	Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
		Depletion, depreciation and amortization				32,014			115,052			—			147,066
		Exploration dry hole costs				7,102			5,257			—			12,359
		Impairment of unproved properties				2,182			6,896			—			9,078
		Deferred income taxes				(15,722	)		7,159			—			(8,563	)
		Director retainers settled for stock				20			—			—			20
		Stock compensation expense				1,954			—			—			1,954
		Change in fair value of derivatives				8,992			—			—			8,992
		Amortization of derivative liabilities				(7,187	)		—			—			(7,187	)
		Amortization of deferred financing fees				782			—			—			782
		Loss on sale of operating assets, net				—			1,731			—			1,731
		Changes in asset and liabilities, net of effects of acquisitions:
			Decrease (increase) in accounts receivable			(701	)		18,594			—			17,893
			Decrease in prepaid expenses			(1,145	)		(1,074	)		—			(2,219	)
			Decrease in accounts payable			(626	)		(14,510	)		—			(15,136	)
			Increase in ad valorem taxes payable			(1	)		2,162			—			2,161
			Decrease in income taxes payable			—			(44	)		—			(44	)
			Increase in accrued expenses			1,798			4,871			—			6,669
			Decrease in other liabilities			—			(818	)		—			(818	)
				Net cash provided by (used in) operating activities		2,109			157,731			—			159,840
Cash flows from investing activities:
	Additions to property and equipment					(48,491	)		(56,427	)		—			(104,918	)
	Proceeds from sales of assets					—			10,552			—			10,552
	Increase in intercompany receivable					(66,984	)		—			66,984			—
	Acquisitions of oil and gas properties					(328	)		(168,200	)		—			(168,528	)
	Other					—			(81	)		—			(81	)
				Net cash provided by (used in) investing activities		(115,803	)		(214,156	)		66,984			(262,975	)
Cash flows from financing activities:
	Proceeds from issuance of common stock					1,074			—			—			1,074
	Repurchase of common stock					(61	)		—			—			(61	)
	Proceeds from issuance of long-term debt					155,000			—			—			155,000
	Repayment of long term debt					(45,000	)		—			—			(45,000	)
	Preferred stock dividends paid					(3,572	)		—			—			(3,572	)
	Gain on interest rate swap cancellation					3,705			—			—			3,705
	Financing fees					(322	)		—			—			(322	)
	Increase in intercompany payable					—			66,984			(66,984	)		—
				Net cash provided by (used in) financing activities		110,824			66,984			(66,984	)		110,824
Net increase (decrease) in cash and cash equivalents						(2,870	)		10,559			—			7,689
Cash and cash equivalents, beginning of period						13,804			13,780			—			27,584
Cash and cash equivalents, end of period					$	10,934		$	24,339		$	—		$	35,273

In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities — an interpretation of ARB No. 51” (“FIN 46”). FIN 46 is an interpretation of Accounting Research Bulletin 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (“VIE’s”). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights. Such entities are known as VIE’s. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. At this time, the Company does not have a VIE.

In April 2003, FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Company adopted SFAS No. 149 on July 1, 2003 and does not expect a material impact on its financial condition and results of operations.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS No. 150 changes the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity. FASB No. 150 requires that those instruments be classified as liabilities in statements of financial position. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company is currently assessing the impact of SFAS No. 150 on its financial condition and results of operations.


8.	Segment Information

The Company operates in four geographic divisions: Northern (Rocky Mountains); Western (Uinta Basin); Southern (Permian Basin, Mid-Continent and Gulf Coast) and Gulf of Mexico (offshore). The Western division was formed on December 17, 2002 as a result of the acquisition of certain natural gas properties and midstream gathering and compression assets located in the Uinta Basin from certain affiliates of El Paso Corporation. All four areas are engaged in the production, development, acquisition and exploration of oil and natural gas properties. The Company evaluates segment performance based on

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~CONDENSED~~the ~~CONSOLIDATING~~profit ~~BALANCE~~or loss from operations before income ~~SHEET~~taxes. Corporate general and administrative expenses are allocated to the four geographic divisions. Consolidated and segment financial information are as follows:

				December 31, 2001
		For the Six Months Ended June 30,
				Parent			Subsidiary
												Gulf of				Corporate &
				Company			Guarantors				Eliminations				Consolidated
		Northern			Western			Southern				Mexico				Unallocated			Consolidated
		(In thousands)		~~(In thousands)~~
ASSETS
2003
Current Assets:
Revenues		$	92,988		$	59,312		$	153,286			$	117,598			$	(60,663	)(1)	$	362,521
	Cash and cash equivalents			$	13,812		$	13,772			$	—			$	27,584
DD&A			20,722			11,791			45,402				49,873				313			128,101
	Accounts receivable, net				18,687			43,121				—				61,808
Impairment of proved properties			106			—			188				683				—			977
	Intercompany receivable				919,727			—				(919,727	)			—
Impairment of unproved properties			2,062			—			1,400				11,711				—			15,173
	Derivative assets				—			7,832				—				7,832
Profit (loss)			39,483			28,485			64,463				20,559				(63,128	)		89,862
	Prepaid expenses				2,345			3,129				—				5,474
Expenditures for assets, net			14,371			25,728			24,082				47,299				589			112,069
			Total current assets		954,571			67,854				(919,727	)			102,698
2002
Property and equipment, at cost:
Revenues		$	58,310		$	—		$	69,949			$	59,892			$	(4,042	)(1)	$	184,109
	Oil and natural gas properties, successful efforts method:
DD&A			22,503			—			38,293				38,358				226			99,380
		Proved properties			281,868			1,164,463				—				1,446,331
Impairment of unproved properties			3,002			—			2,093				1,195				—			6,290
		Unproved properties			23,978			81,561				—				105,539
Profit (loss)			6,452			—			(2,990	)			(10,254	)			(4,477	)		(11,269	)
	Building and other office furniture and equipment				487			7,612				—				8,099
Expenditures for assets, net			57,285			—			13,724				42,016				1,047			114,072
					306,333			1,253,636				—				1,559,969
	Less accumulated depletion, depreciation and amortization				(83,016	)		(200,749	)			—				(283,765	)
			Net property and equipment		223,317			1,052,887				—				1,276,204
Other assets:
	Long-term derivative assets				—			612				—				612
	Goodwill				—			214,844				—				214,844
	Other assets				9,830			28				—				9,858
			Total other assets		9,830			215,484				—				225,314
			Total assets	$	1,187,718		$	1,336,225			$	(919,727	)		$	1,604,216
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable			$	14,254		$	33,647			$	—			$	47,901
	Accrued expenses				8,840			21,454				—				30,294
	Ad valorem taxes payable				—			6,930				—				6,930
	Intercompany payable				—			919,727				(919,727	)			—
	Derivative liabilities				—			3,289				—				3,289
	Income taxes payable				(131	)		681				—				550
	Other current liabilities				—			369				—				369
			Total current liabilities		22,963			986,097				(919,727	)			89,333
Long-term debt					429,224			—				—				429,224
Deferred income taxes					31,053			126,952				—				158,005
Long-term derivative liabilities					5,205			751				—				5,956
Other liabilities					—			1,402				—				1,402
			Total liabilities		488,445			1,115,202				(919,727	)			683,920
Stockholders’ equity:
	Preferred stock				29			—				—				29
	Common stock				521			3				(3	)			521
	Additional paid-in capital				678,804			199,153				3				877,960
	Treasury stock				(408	)		—				—				(408	)
	Retained earnings				20,327			13,003				—				33,330
	Accumulated other comprehensive income				—			8,864				—				8,864
			Total stockholders’ equity		699,273			221,023				—				920,296
			Total liabilities and stockholders’ equity	$	1,187,718		$	1,336,225			$	(919,727	)		$	1,604,216


(1)	Corporate and unallocated revenues consist of non-hedge and hedge settlements, and non-hedge change in fair value of derivatives.



	For the Three Months Ended June 30,

							Gulf of		Corporate &
	Northern		Western		Southern		Mexico		Unallocated			Consolidated


	(In thousands)
2003
Revenues	$	46,058	$	32,263	$	70,032	$	54,811	$	(22,537	)(1)	$	180,627
DD&A		9,993		6,344		23,857		26,680		162			67,036
Impairment of proved properties		106		—		188		683		—			977
Impairment of unproved properties		1,380		—		693		9,620		—			11,693
Profit (loss)		19,816		17,204		23,830		304		(24,855	)		36,299
Expenditures for assets, net		7,867		20,386		16,093		21,514		389			66,249
2002
Revenues	$	33,007	$	—	$	40,112	$	38,021	$	191	(1)	$	111,331
DD&A		11,432		—		18,519		21,722		118			51,791
Impairment of unproved properties		3,002		—		2,093		236		—			5,331
Profit		5,514		—		3,233		357		1,746			10,850
Expenditures for assets, net		10,091		—		4,719		23,575		682			39,067


(1)	Corporate and unallocated revenues consist of non-hedge and hedge settlements, and non-hedge change in fair value of derivatives

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~CONDENSED~~9. ~~CONSOLIDATING~~Condensed ~~STATEMENT~~Consolidated ~~OF OPERATIONS~~ Financial Statements of Subsidiary Guarantors

			For the Nine Months Ended September 30, 2001
			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated
			(In thousands)
Operating revenues:
	Oil and natural gas sales		$	76,524		$	157,881		$	—	$	234,405
	Hedge settlements			—			(1,824	)		—		(1,824	)
	Non-hedge settlements			—			(558	)		—		(558	)
	Non-hedge change in fair value of derivatives			—			24,486			—		24,486
		Net revenues		76,524			179,985			—		256,509
Operating costs and expenses:
	Lease operating expense			5,390			29,380			—		34,770
	Production taxes			6			8,936			—		8,942
	Transportation costs			410			3,511			—		3,921
	Exploration			17,885			6,448			—		24,333
	Depletion, depreciation and amortization			32,154			40,097			—		72,251
	Impairment of unproved properties			2,297			817			—		3,114
	Stock compensation expense			(1,060	)		—			—		(1,060	)
	General and administrative			4,817			6,015			—		10,832
		Total operating expenses		61,899			95,204			—		157,103
		Operating income		14,625			84,781			—		99,406
Other income (expense):
	Interest expense			(3,166	)		(1,317	)		—		(4,483	)
	Interest income			1,120			402			—		1,522
	Change in fair value of interest rate swap			—			1,877			—		1,877
	Other			63			(43	)		—		20
Income before income taxes				12,642			85,700			—		98,342
Provision for income taxes:
	Current			—			(2,006	)		—		(2,006	)
	Deferred			(4,614	)		(29,275	)		—		(33,889	)
		Total provision for income taxes		(4,614	)		(31,281	)		—		(35,895	)
Net income				8,028			54,419			—		62,447
Preferred stock dividends				397			—			—		397
Net loss available to common stock			$	7,631		$	54,419		$	—	$	62,050

On April 3, 2003 the Company issued $125 million of its 8 1/4% Senior Subordinated Notes Due 2011. These notes were issued as additional debt securities under an indenture, pursuant to which, on November 5, 2001 the Company issued $275 million of 8 1/4% Senior Subordinated Notes Due 2011 and on December 17, 2002, the Company issued $300 million of 8 1/4% Senior Subordinated Notes Due 2011. All of the 8 1/4% Senior Subordinated Notes Due 2011 are jointly and severally guaranteed, on a senior subordinated unsecured basis, by the following wholly-owned subsidiaries of Westport: Westport Finance Co., Jerry Chambers Exploration Company, Westport Argentina LLC, Westport Canada LLC, Westport Oil and Gas Company, L.P., Horse Creek Trading & Compression Company LLC, Westport Field Services, LLC, Westport Overriding Royalty LLC, WHG, Inc. and WHL, Inc. (collectively, the “Subsidiary Guarantors”). The guarantees of the Subsidiary Guarantors are subordinated to senior debt of the Subsidiary Guarantors.

Presented below are condensed consolidating financial statements for Westport and the Subsidiary Guarantors for the periods indicated therein.

WESTPORT RESOURCES CORPORATION

~~NOTES~~CONDENSED TOCONSOLIDATING ~~CONSOLIDATED FINANCIAL~~BALANCE ~~STATEMENTS — (Continued)~~SHEET

~~CONDENSED~~June 30, ~~CONSOLIDATING STATEMENT OF CASH~~2003 ~~FLOWS~~

						For the Nine Months Ended September 30, 2001
					Parent				Subsidiary
						Parent				Subsidiary
					Company				Guarantors				Eliminations				Consolidated
						Company				Guarantors				Eliminations				Consolidated
					(In thousands)
						(In thousands)
					(Unaudited)
Cash flows from operating activities:
ASSETS
	Net income					$	8,028			$	54,419			$	—			$	62,447
Current Assets:
	Adjustments to reconcile net income to net cash provided by operating activities:
	Cash and cash equivalents				$	12,400			$	53,465			$	—			$	65,865
		Depletion, depreciation and amortization					32,154				40,097				—				72,251
	Accounts receivable, net					17,447				64,073				—				81,520
		Exploration dry hole costs					11,310				5,313				—				16,623
	Intercompany receivable					1,331,639				—				(1,331,639	)			—
		Impairment of unproved properties					2,297				817				—				3,114
	Derivative assets					8,401				—				—				8,401
		Deferred income taxes					4,614				29,275				—				33,889
	Prepaid expenses					5,312				9,459				—				14,771
		Stock compensation expense					(1,060	)			—				—				(1,060	)
			Total current assets			1,375,199				126,997				(1,331,639	)			170,557
		Change in fair value of derivatives					—				(26,363	)			—				(26,363	)
Property and equipment, at cost:
		Amortization of financing fees					633				—				—				633
	Oil and natural gas properties, successful efforts method:
		Changes in asset and liabilities, net of effects of Acquisitions:
		Proved properties				382,988				1,886,552				—				2,269,540
			Decrease in accounts receivable				5,048				21,953				—				27,001
		Unproved properties				22,291				72,653				—				94,944
			Decrease (increase) in prepaid expenses				283				163				—				446
	Field services assets					—				39,198				—				39,198
			Decrease in accounts payable				(815	)			(4,611	)			—				(5,426	)
	Building and other office furniture and equipment					673				9,601				—				10,274
			Increase in ad valorem taxes payable				—				3,141				—				3,141
						405,952				2,008,004				—				2,413,956
			Increase in income taxes payable				—				306				—				306
	Less accumulated depletion, depreciation and amortization					(166,279	)			(431,432	)			—				(597,711	)
			Increase (decrease) in accrued expenses				(10,972	)			(228	)			—				(11,200	)
			Net property and equipment			239,673				1,576,572				—				1,816,245
			Decrease in other liabilities				—				(107	)			—				(107	)
Other assets:
				Net cash provided by operating activities			51,520				124,175				—				175,695
	Long-term derivative assets					17,792				—				—				17,792
Cash flows from investing activities:
	Goodwill					—				244,647				—				244,647
	Additions to property and equipment						(65,485	)			(67,203	)			—				(132,688	)
	Other assets					19,697				—				—				19,697
	Proceeds from sale of assets						—				654				—				654
			Total other assets			37,489				244,647				—				282,136
	Increase in intercompany receivable						31,006				—				(31,006	)			—
			Total assets		$	1,652,361			$	1,948,216			$	(1,331,639	)		$	2,268,938
	Acquisitions of oil and gas properties						—				(6,319	)			—				(6,319	)
LIABILITIES AND STOCKHOLDERS’ EQUITY
	Other						—				(2	)			—				(2	)
Current Liabilities:
				Net cash used in investing activities			(34,479	)			(72,870	)			(31,006	)			(138,355	)
	Accounts payable				$	8,809			$	39,763			$	—			$	48,572
Cash flows from financing activities:
	Accrued expenses					19,544				21,940				—				41,484
	Proceeds from issuance of common stock						264				—				—				264
	Ad valorem taxes payable					18				15,199				—				15,217
	Repurchase of common stock						(408	)			—				—				(408	)
	Intercompany payable					—				1,331,639				(1,331,639	)			—
	Proceeds from long-term debt						255,000				—				—				255,000
	Derivative liabilities					98,173				—				—				98,173
	Repayment of long-term debt						(273,122	)			(162	)			—				(273,284	)
	Income taxes payable					—				83				—				83
	Financing fees						(2,036	)			—				—				(2,036	)
	Other current liabilities					3,974				3,986				—				7,960
	Increase in intercompany payable						—				(31,006	)			31,006				—
			Total current liabilities			130,518				1,412,610				(1,331,639	)			211,489
				Net cash provided by (used in) financing activities			(20,302	)			(31,168	)			31,006				(20,464	)
Long-term debt						731,879				—				—				731,879
	Net increase in cash and cash equivalents						(3,261	)			20,137				—				16,876
Deferred income taxes						(71,196	)			185,868				—				114,672
	Cash and cash equivalents, beginning of period						12,458				7,696				—				20,154
Long-term derivative liabilities						42,632				—				—				42,632
	Cash and cash equivalents, end of period					$	9,197			$	27,833			$	—			$	37,030
Other liabilities						15,622				34,521				—				50,143
			Total liabilities			849,455				1,632,999				(1,331,639	)			1,150,815
Stockholders’ equity:
	Preferred stock					29				—				—				29
	Common stock					672				3				(3	)			672
	Additional paid-in capital					956,875				199,153				3				1,156,031
	Treasury stock					(512	)			—				—				(512	)
	Retained earnings					(83,753	)			116,222				—				32,469
	Accumulated other comprehensive income					(70,405	)			(161	)			—				(70,566	)
			Total stockholders’ equity			802,906				315,217				—				1,118,123
			Total liabilities and stockholders’ equity		$	1,652,361			$	1,948,216			$	(1,331,639	)		$	2,268,938

~~Item~~ WESTPORT 2.RESOURCES ~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~CORPORATION

~~General~~CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

~~Critical~~ For ~~Accounting~~the ~~Policies~~Six ~~And~~Months ~~Estimates~~Ended June 30, 2003

Our discussion and analysis of our financial condition and results of operation are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our consolidated financial statements as set forth in our Annual Report on Form 10-K for the year ended December 31, 2001. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and gas revenues, oil and gas properties, fair value of derivative instruments, income taxes and contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:


			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


			(In thousands)

			(Unaudited)
Operating revenues:
	Oil and natural gas sales		$	87,740		$	326,263		$	—	$	414,003
	Hedge settlements			(63,885	)		—			—		(63,885	)
	Gathering and marketing income			—			1,992			—		1,992
	Non-hedge settlements			723			—			—		723
	Non-hedge change in fair value of derivatives			3,222			—			—		3,222
	Loss on sale of operating assets, net			3			6,463			—		6,466

		Net revenues		27,803			334,718			—		362,521

Operating costs and expenses:
	Lease operating expense			6,315			46,053			—		52,368
	Production taxes			1			24,421			—		24,422
	Transportation costs			211			7,167			—		7,378
	Gathering and marketing expense			—			1,648			—		1,648
	Exploration			14,988			10,683			—		25,671
	Depletion, depreciation and amortization			40,083			88,018			—		128,101
	Impairment of proved properties			—			977			—		977
	Impairment of unproved properties			9,508			5,665			—		15,173
	Stock compensation expense			2,150			—			—		2,150
	General and administrative			3,775			10,996			—		14,771

Total operating expenses				77,031			195,628			—		272,659

		Operating income (loss)		(49,228	)		139,090			—		89,862

Other income (expense):
	Interest expense			(29,399	)		(1	)		—		(29,400	)
	Interest income			162			219			—		381
	Loss on debt retirement			(920	)		—			—		(920	)
	Other			41			292			—		333

Income (loss) before income taxes				(79,344	)		139,600			—		60,256

Provision for income taxes:
	Deferred			28,961			(50,954	)		—		(21,993	)

		Total provision for income taxes		28,961			(50,954	)		—		(21,993	)

Net income before cumulative change in accounting principle				(50,383	)		88,646			—		38,263

Preferred stock dividends				(2,382	)		—			—		(2,382	)

Cumulative effect of change in accounting principle				1,765			(5,179	)		—		(3,414	)

Net income available to common stockholders			$	(51,000	)	$	83,467		$	—	$	32,467

• Revenue Recognition. We follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. • Successful Efforts Accounting. We account for our oil and natural gas operations using the successful efforts method of accounting. Under this method, all costs associated with property acquisition, successful exploratory wells and all development wells are capitalized. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and natural gas production costs. All of our oil and natural gas properties are located within the continental United States, the Gulf of Mexico and Canada. • Proved Reserve Estimates. Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:19

•Table the quality and quantity of available data; • the interpretation of that data; • the accuracy of various mandated economic assumptions; and • the judgment of the persons preparing the estimate.Contents

~~Our~~ WESTPORT ~~proved~~RESOURCES reserve information included in this report is based on estimates we prepared. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. Our stockholders should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Our estimates of proved reserves directly impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense increases, reducing net income. Such a declineCORPORATION

19 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

~~Table~~ For ofthe ~~Contents~~Six Months Ended June 30, 2003

may result from lower market prices or increases in costs, which may make it uneconomic to drill for and produce higher cost fields, or property performance. In addition, the decline in proved reserve estimates may impact the outcome of our assessment of our oil and gas producing properties for impairment.


					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)

					(Unaudited)
Cash flows from operating activities:
	Net income (loss)				$	(48,618	)	$	83,467		$	—		$	34,849
	Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
		Depletion, depreciation and amortization				40,083			88,018			—			128,101
		Exploration dry hole costs				8,243			6,685			—			14,928
		Impairment of proved properties				—			977			—			977
		Impairment of unproved properties				9,508			5,665			—			15,173
		Deferred income taxes				(28,961	)		50,954			—			21,993
		Director retainers settled for stock				11			—			—			11
		Stock compensation expense				2,150			—			—			2,150
		Change in fair value of derivatives				3,514			—			—			3,514
		Amortization of derivative liabilities				(9,625	)		—			—			(9,625	)
		Amortization of deferred financing fees				548			—			—			548
		Loss on sale of operating assets, net				(3	)		(6,463	)		—			(6,466	)
		Cumulative change in accounting principal, net of tax				(1,765	)		5,179			—			3,414
		Changes in asset and liabilities, net of effects of acquisitions:
			Decrease (increase) in accounts receivable			10,434			(25,857	)		—			(15,423	)
			Decrease (increase) in prepaid expenses			2,608			(3,647	)		—			(1,039	)
			Increase (decrease) in accounts payable			(6,492	)		3,981			—			(2,511	)
			Increase in ad valorem taxes payable			20			6,208			—			6,228
			Decrease in income taxes payable			—			(3	)		—			(3	)
			Increase (decrease) in accrued expenses			2,255			(2,196	)		—			59
			Decrease in other liabilities			(9	)		(453	)		—			(462	)

				Net cash provided by (used in) operating activities		(16,099	)		212,515			—			196,416

Cash flows from investing activities:
	Additions to property and equipment					(43,315	)		(72,311	)		—			(115,626	)
	Proceeds from sales of assets					3			13,278			—			13,281
	Increase in intercompany receivable					—			(143,754	)		143,754			—
	Acquisitions of oil and gas properties					—			3,557			—			3,557
	Other					—			—			—			—

				Net cash provided by (used in) investing activities		(43,312	)		(199,230	)		143,754			(98,788	)

Cash flows from financing activities:
	Proceeds from issuance of common stock					3,530			—			—			3,530
	Repurchase of common stock					(43	)		—			—			(43	)
	Proceeds from issuance of long-term debt					151,875			—			—			151,875
	Repayment of long term debt					(226,311	)		—			—			(226,311	)
	Preferred stock dividends paid					(2,381	)		—			—			(2,381	)
	Loss on retirement of debt					(920	)		—			—			(920	)
	Financing fees					(274	)		—			—			(274	)
	Increase in intercompany payable					143,754			—			(143,754	)		—

				Net cash provided by (used in) financing activities		69,230			—			(143,754	)		(74,524	)

Net increase in cash and cash equivalents						9,819			13,285			—			23,104
Cash and cash equivalents, beginning of period						2,581			40,180			—			42,761

Cash and cash equivalents, end of period					$	12,400		$	53,465		$	—		$	65,865

• Impairment of Proved Oil and Gas Properties. We review our long-lived proved properties whenever management judges that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon management’s outlook of future commodity prices and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment on a field-by-field basis, which is the lowest level at which depletion of proved properties is calculated. • Impairment of Goodwill. Goodwill of a reporting unit is tested for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Management assesses whether or not an impairment provision is necessary based upon comparing the fair value of a reporting unit with its carrying value including goodwill. • Impairment of Unproved Oil and Gas Properties. Management periodically assesses individually significant unproved oil and gas properties for impairment, on a project-by-project basis. Management’s assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects impact the amount and timing of impairment provisions. • Commodity Derivative Instruments and Hedging Activities. We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize price swaps, futures contracts or collars, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures which have a high degree of historical correlation with actual prices we receive. On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of CPRM activities.20

Overview Table of Contents

WeWESTPORT ~~are~~RESOURCES ~~an independent energy company engaged in~~CORPORATION ~~oil and natural gas exploitation, acquisition and exploration~~ activities primarily in the United States. Our reserves and production operations are concentrated in the following diversified divisions: Northern (Rocky Mountains); Southern (Permian Basin, Mid-Continent and Gulf Coast); and Gulf of Mexico (offshore). We focus on maintaining a balanced portfolio of lower-risk, long-life onshore reserves and higher-margin offshore reserves to provide a diversified cash flow foundation for our exploitation, acquisition and exploration activities.

~~Our~~CONDENSED ~~results~~CONSOLIDATING ~~of operations are significantly~~BALANCE ~~impacted by the prices of oil and natural gas, which are~~SHEET ~~volatile. The prices we receive for our oil vary from NYMEX~~ ~~prices based on the location and quality of the crude oil.~~

20 December 31, 2002


				Parent			Subsidiary
				Company			Guarantors			Eliminations			Consolidated


				(In thousands)
ASSETS
Current Assets:
	Cash and cash equivalents			$	2,581		$	40,180		$	—		$	42,761
	Accounts receivable, net				27,880			45,669			—			73,549
	Intercompany receivable				1,475,393			—			(1,475,393	)		—
	Derivative assets				14,861			—			—			14,861
	Prepaid expenses				7,922			5,436			—			13,358

			Total current assets		1,528,637			91,285			(1,475,393	)		144,529

	Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties			339,947			1,798,524			—			2,138,471
		Unproved properties			29,252			75,178			—			104,430
	Field services assets				—			39,185			—			39,185
	Building and other office furniture and equipment				620			9,066			—			9,686

					369,819			1,921,953			—			2,291,772
Less accumulated depletion, depreciation and amortization					(131,946	)		(353,383	)		—			(485,329	)

	Net property and equipment				237,873			1,568,570			—			1,806,443

Other assets:
	Long-term derivative assets				14,824			—			—			14,824
	Goodwill				—			246,712			—			246,712
	Other assets				21,033			—			—			21,033

	Total other assets				35,857			246,712			—			282,569

	Total assets			$	1,802,367		$	1,906,567		$	(1,475,393	)	$	2,233,541


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable			$	15,301		$	35,857		$	—		$	51,158
	Accrued expenses				23,354			15,855			—			39,209
	Ad valorem taxes payable				(2	)		8,990			—			8,988
	Intercompany payable				—			1,475,393			(1,475,393	)		—
	Derivative liabilities				56,156			—			—			56,156
	Income taxes payable				—			86			—			86
	Other current liabilities				—			—			—			—

			Total current liabilities		94,809			1,536,181			(1,475,393	)		155,597
	Long-term debt				799,358			—			—			799,358
	Deferred income taxes				(13,361	)		137,891			—			124,530
	Long-term derivative liabilities				21,305			—			—			21,305
	Other liabilities				—			745			—			745

			Total liabilities		902,111			1,674,817			(1,475,393	)		1,101,535

Stockholders’ equity:
	Preferred stock				29			—			—			29
	Common stock				668			3			(3	)		668
	Additional paid-in capital				951,189			199,153			3			1,150,345
	Treasury stock				(469	)		—			—			(469	)
	Retained earnings				(32,753	)		32,755			—			2
	Accumulated other comprehensive income				(18,408	)		(161	)		—			(18,569	)

			Total stockholders’ equity		900,256			231,750			—			1,132,006

			Total liabilities and stockholders’ equity	$	1,802,367		$	1,906,567		$	(1,475,393	)	$	2,233,541

21 ~~The prices we receive for our natural gas are~~ ~~based on Henry Hub prices reduced by transportation and~~ ~~processing fees.~~

OilTable and natural gas production costs are composed of lease operating expense and production taxes. Lease operating expense consists of pumpers’ salaries, utilities, maintenance and other costs necessary to operate our producing properties. In general, lease operating expense per unit of production is lower on our offshore properties and does not fluctuate proportionately with our production. Production taxes are assessed by applicable taxing authorities as a percentage of revenues. However, properties located in Federal waters offshore are generally not subject to production taxes. Transportation costs are comprised of costs paid to a carrier to deliver oil or natural gas to a specified delivery point. In some cases we receive a payment from the purchasers of our oil and natural gas which is net of gas transportation costs and in other instances we pay the costs of transportation. Contents

~~Exploration~~WESTPORT ~~expense~~RESOURCES ~~consists of geological and~~CORPORATION ~~geophysical costs, delay rentals and the cost of unsuccessful~~ exploratory wells. Delay rentals are typically fixed in nature in the short term. However, other exploration costs are generally discretionary and exploration activity levels are determined by a number of factors, including oil and natural gas prices, availability of funds, quantity and character of investment projects, availability of service providers and competition.

~~Depletion~~CONDENSED ofCONSOLIDATING ~~capitalized~~STATEMENT ~~costs of producing oil~~OF ~~and natural gas properties is computed using the~~OPERATIONS ~~units-of-production method based upon proved reserves. For~~ purposes of computing depletion, proved reserves are redetermined twice each year. Because the economic life of each producing well depends upon the assumed price for production, fluctuations in oil and natural gas prices impact the level of proved reserves. Higher prices generally have the effect of increasing reserves, which reduces depletion, while lower prices generally have the effect of decreasing reserves, which increases depletion.

WeFor ~~assess our proved properties on a field-by-field basis for impairment, in accordance with~~ the ~~provisions~~ ofSix ~~Statement~~Months ofEnded ~~Financial Accounting Standards No.~~June ~~144~~30, ~~“Accounting for the Impairment of Long Lived~~ ~~Assets and for Long Lived Assets to be Disposed of,”~~2002 whenever events or circumstances indicate that the capitalized costs of oil and natural gas properties may not be recoverable. When making such assessments, we compare the expected undiscounted future net revenues on a field-by-field basis with the related net capitalized costs at the end of each year. When the net capitalized costs exceed the undiscounted future net revenues, the cost of the property is written down to “fair value,” which is determined using discounted future net revenues based on escalated prices. Reserve categories used in the impairment analysis for all periods considered are categories of proven reserves and probable and possible reserves, which were risk adjusted based on our drilling plans and history of successfully developing those types of reserves. We periodically assess our unproved properties to determine if any such properties have been impaired. Such assessment is based on, among other things, the fair value of properties located in the same area as the unproved property and our intent to pursue additional exploration opportunities on such property.

Stock compensation expense consists of noncash charges resulting from the application of the provisions of FASB Interpretation No. 44 to certain stock options granted to employees and issuance of restricted stock to certain employees. Under Interpretation No. 44 we are required to measure compensation cost on stock options that are considered to be variable awards until the date of exercise, forfeiture or expiration of such options. Compensation cost is measured for the amount of any increases in our stock price and recognized over the remaining vesting period of the options. Any decrease in our stock price will be recognized as a decrease in compensation cost limited to the amount of compensation cost previously recognized as a result of an increase in our stock price.


			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


			(In thousands)

			(Unaudited)
Operating revenues:
	Oil and natural gas sales		$	31,142		$	158,877		$	—	$	190,019
	Hedge settlements			3,358			—			—		3,358
	Non-hedge settlements			822			—			—		822
	Non-hedge change in fair value of derivatives			(8,222	)		—			—		(8,222	)
	Loss on sale of operating assets, net			—			(1,868	)		—		(1,868	)

		Net revenues		27,100			157,009			—		184,109

Operating costs and expenses:
	Lease operating expense			6,134			37,770			—		43,904
	Production taxes			3			11,633			—		11,636
	Transportation costs			22			4,581			—		4,603
	Exploration			11,428			6,614			—		18,042
	Depletion, depreciation and amortization			20,920			78,460			—		99,380
	Impairment of unproved properties			236			6,054			—		6,290
	Stock compensation expense			94			—			—		94
	General and administrative			3,132			8,297			—		11,429

		Total operating expenses		41,969			153,409			—		195,378

		Operating income		(14,869	)		3,600			—		(11,269	)
Other income (expense):
	Interest expense			(16,121	)		(228	)		—		(16,349	)
	Interest income			66			135			—		201
	Change in fair value of interest rate swap			—			226			—		226
	Other			466			(145	)		—		321

Income before income taxes				(30,458	)		3,588			—		(26,870	)

Provision for income taxes:
	Current			—			—			—		—
	Deferred			11,117			(1,310	)		—		9,807

Total provision for income taxes				11,117			(1,310	)		—		9,807

Net income				(19,341	)		2,278			—		(17,063	)

Preferred stock dividends				(2,381	)		—			—		(2,381	)

Net loss available to common stock			$	(21,722	)	$	2,278		$	—	$	(19,444	)

22 ~~General and administrative expenses consist~~ ~~primarily of salaries and related benefits, office rent, legal~~ ~~fees, consultants, systems costs and other administrative costs~~ ~~incurred in our Denver, Dallas and Houston offices. While we expect such costs to increase with our growth, we expect such increases to be proportionately smaller than our production growth.~~

21 Table of Contents

~~Table~~ WESTPORT ofRESOURCES ~~Contents~~CORPORATION

~~Mergers~~CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

OnFor ~~August 21, 2001,~~ the ~~stockholders~~Six ~~of Belco~~Months ~~approved~~Ended ~~the Agreement and Plan of Merger, dated as of~~ June 830, ~~2001, between Belco and Westport. Pursuant to the~~ ~~Merger Agreement, Old Westport was merged with and into Belco,~~2002 with Belco surviving and changing its name to Westport Resources Corporation. The Merger was accounted for as a purchase transaction for financial accounting purposes. Because former Old Westport stockholders owned a majority of the outstanding Westport common stock immediately after the Merger, the Merger is accounted for as a reverse acquisition in which Old Westport is the purchaser of Belco.

Old Westport was formed by the merger on April 7, 2000 of Westport Oil and Gas with Equitable Production Gulf Company (“EPGC”). As a result of the merger, Westport Oil and Gas became a wholly-owned subsidiary of EPGC, which subsequently changed its name to Westport Resources Corporation, and the stockholders of Westport Oil and Gas became the majority stockholders of EPGC. The senior management team of Westport Oil and Gas became the management team for the combined company, complemented by certain key managers from EPGC.


					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)

					(Unaudited)
Cash flows from operating activities:
	Net income (loss)				$	(19,341	)	$	2,278		$	—		$	(17,063	)
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depletion, depreciation and amortization				20,920			78,460			—			99,380
		Exploration dry hole costs				4,613			5,182			—			9,795
		Impairment of unproved properties				236			6,054			—			6,290
		Deferred income taxes				(11,117	)		1,310			—			(9,807	)
		Director retainers settled for stock				20			—			—			20
		Stock compensation expense				94			—			—			94
		Change in fair value of derivatives				7,996			—			—			7,996
		Amortization of derivative liabilities				(5,018	)		—			—			(5,018	)
		Amortization of financing fees				540			—			—			540
		Loss on sale of operating assets, net				—			1,868			—			1,868
		Changes in asset and liabilities, net of effects of Acquisitions:
			Decrease (increase) in accounts receivable			(582	)		5,605			—			5,023
			Increase in prepaid expenses			(802	)		(2,190	)		—			(2,992	)
			Decrease in accounts payable			(4,594	)		(13,295	)		—			(17,889	)
			Increase in ad valorem taxes payable			1			501			—			502
			Decrease in income taxes payable			—			(44	)		—			(44	)
			Increase in accrued expenses			685			1,897			—			2,582
			Decrease in other liabilities			—			(446	)		—			(446	)

				Net cash provided by (used in) operating activities		(6,349	)		87,180			—			80,831

Cash flows from investing activities:
	Additions to property and equipment					(31,459	)		(40,310	)		—			(71,769	)
	Proceeds from sale of assets					—			7,790			—			7,790
	Increase in intercompany receivable					(16,891	)		—			16,891			—
	Acquisitions of oil and gas properties					(328	)		(41,975	)		—			(42,303	)
	Other					—			(52	)		—			(52	)

				Net cash used in investing activities		(48,678	)		(74,547	)		16,891			(106,334	)

Cash flows from financing activities:
	Proceeds from issuance of common stock					1,071			—			—			1,071
	Repurchase of common stock					(61	)		—			—			(61	)
	Proceeds from long-term debt					55,000			—			—			55,000
	Preferred stock dividend					(2,381	)		—			—			(2,381	)
	Financing fees					(271	)		—			—			(271	)
	Increase in intercompany payable					—			16,891			(16,891	)		—

				Net cash provided by (used in) financing activities		53,358			16,891			(16,891	)		53,358

Net increase in cash and cash equivalents						(1,669	)		29,524			—			27,855
Cash and cash equivalents, beginning of period						13,804			13,780			—			27,584

Cash and cash equivalents, end of period					$	12,135		$	43,304		$	—		$	55,439

23 ~~Results of Operations~~

AsTable indicated above, the Merger was accounted for using purchase accounting with Old Westport as the surviving accounting entity. We began consolidating the results of Belco with the results of Old Westport as of the August 21, 2001 closing date. Contents

~~The~~Item ~~following~~2. ~~table~~Management’s ~~sets~~Discussion ~~forth~~and ~~certain operational~~Analysis ~~data~~of ~~for~~Financial ~~the~~Condition ~~periods~~and ~~presented:~~ Results of Operations

~~Summary Data~~General

		For the Three Months						For the Nine Months
		Ended September 30,						Ended September 30,
		2002			2001			2002		2001
		(In thousands)
Production
	Oil (Mbbls)		2,002			1,236			5,899		3,075
	Natural gas (Mmcf)		19,244			15,905			59,873		37,177
	Mmcfe		31,256			23,321			95,267		55,627
Average Daily Production
	Oil (Mbbls/d)		21.8			13.4			21.6		11.3
	Natural gas (Mmcf/d)		209.2			172.9			219.3		136.2
	Mmcfe/d		339.7			253.5			349.0		203.8
Average Prices
	Oil (per bbl)	$	26.06		$	23.13		$	22.92	$	24.12
	Natural gas (per Mcf)		2.77			2.61			2.68		4.31
Hedging effect (per Mcfe)			(0.06	)		(0.01	)		0.02		(0.03	)
Oil and natural gas sales		$	105,423		$	70,157		$	295,442	$	234,405
Lease operating expense			23,477			14,775			67,381		34,770
	Per Mcfe		0.75			0.63			0.71		0.63
General and administrative costs			5,650			4,122			17,079		10,832
	Per Mcfe		0.18			0.18			0.18		0.19
Depletion, depreciation and amortization			47,686			31,222			147,066		72,251
	Per Mcfe		1.53			1.34			1.54		1.30

The following information should be read in conjunction with our historical consolidated financial statements and related notes and other financial information included elsewhere in this report.

~~The~~Critical ~~discussion~~Accounting ~~below~~Policies ~~includes a comparison of our~~And ~~results of operations for the three months and nine months ended~~Estimates ~~September 30, 2002 and 2001.~~

22 Our discussion and analysis of our financial condition and results of operation is based upon consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our consolidated financial statements as set forth in our Annual Report on Form 10-K for the year ended December 31, 2002. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and gas revenues, oil and gas properties, fair value of derivative instruments, income taxes and contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies reflect our more significant judgments and estimates used in the preparation of our consolidated financial statements:

~~Table~~• Revenue Recognition. We follow the sales method of ~~Contents~~accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. No receivables, payables or unearned revenue are recorded unless a working interest owner’s aggregate sales from the property exceed its share of the total reserves-in-place. If such a situation arises, the parties would likely cash balance. • Successful Efforts Accounting. We account for our oil and natural gas operations using the successful efforts method of accounting. Under this method, all costs associated with property acquisition, successful exploratory wells and all development wells are capitalized. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and natural gas production costs. All of our oil and natural gas properties are located within the continental United States, the Gulf of Mexico and Canada. • Proved Reserve Estimates. Estimates of our proved reserves are prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:

~~Revenues.~~• ~~Oil and natural gas revenues for~~ the ~~three~~quality ~~months~~and ~~ended September 30,~~quantity ~~2002~~of ~~increased~~available bydata; ~~$35.3 million,~~• ~~or 50%, from $70.2 million to $105.4 million, compared to~~ the ~~three~~ ~~months~~interpretation ~~ended September 30, 2001. Production from the acquired Belco properties accounted for $28.1 million~~ of ~~the~~ ~~increase.~~that ~~Production~~data; ~~volumes~~• ~~increased by 7.9 Bcfe, or 34%, from 23.3 Bcfe to 31.3 Bcfe. Acquired Belco properties accounted for 7.3 Bcfe of~~ the ~~increase. Production~~accuracy ~~volumes also increased 1.4 Bcfe from recent discoveries in the Gulf~~ of ~~Mexico~~various ~~and~~mandated ~~0.9 Bcfe~~economic ~~due~~assumptions; ~~to an acquisition of properties in the Williston Basin in March 2002. The increases in production volumes were partially offset by oil~~ and ~~natural~~• ~~gas production declines in~~ the ~~Gulf~~judgment of ~~Mexico developed properties. The increase in oil and natural gas revenues was also due to increases of 6% and 13% in realized natural gas prices and oil prices, respectively, excluding~~ the ~~effects~~ ofpersons ~~hedging.~~preparing ~~Hedging transactions had~~ the ~~effect of decreasing oil and natural gas revenues by $1~~estimate.~~8 million, or $0.6 per Mcfe, and $0.3 million, or $0.1 per Mcfe, for the three months ended September 30, 2002 and 2001, respectively.~~

~~Oil~~Our ~~and~~proved ~~natural~~reserve ~~gas~~information ~~revenues~~included ~~for the nine months ended September 30, 2002 increased by $61.0 million, or 26%, from $234.4 million to $295.4 million, over the comparable period~~ in ~~2001. Production from the acquired~~this ~~Belco~~report ~~properties~~is ~~accounted~~based ~~for~~on anestimates ~~increase~~prepared ~~of $106.0 million. The increase in production volumes, including production attributable to Belco properties, was partially offset~~ by ~~decreases~~Ryder ofScott ~~38% and 5% in realized natural~~Company ~~gas prices and oil prices, respectively, excluding the effects of hedging~~L. ~~Production volumes increased 39~~P.~~6 Bcfe~~ from 55.6 Bcfe in 2001 to 95.3 Bcfe in 2002 (acquired Belco properties accounted for 34.0 Bcfe of the increase). Production volumes also increased 5.4 Bcfe from recent discoveries in the Gulf of Mexico and ~~2.1 Bcfe~~our ~~due~~engineering ~~to an acquisition of properties in the Williston Basin in March 2002~~staff. ~~The~~ ~~increases~~Estimates inprepared ~~production volumes were partially offset~~ by ~~oil and~~others ~~natural gas production declines in the Gulf of Mexico~~may ~~developed~~be ~~properties.~~higher ~~Hedging transactions had the effect of increasing oil and natural gas revenues by $1.5 million,~~ or ~~$0.02 per~~ ~~Mcfe,~~lower ~~and~~than ~~reducing~~our ~~oil and natural gas revenues by $1~~estimates.~~8 million, or $0.03 per Mcfe, for the nine~~ ~~months ended September 30, 2002 and 2001, respectively.~~

~~Commodity~~Because ~~Price~~these ~~Risk~~estimates ~~Management Activities.~~depend ~~The~~on ~~Company recorded a~~many ~~loss~~assumptions, ofall ~~$0.7 million in the non-hedge change in fair value~~ of ~~derivatives~~which ~~for~~may ~~the~~substantially ~~three~~differ ~~months~~from ~~ended September 30,~~actual ~~2002~~results, ~~compared~~reserve toestimates amay ~~$17.7 million~~be ~~gain~~different ~~for~~from the ~~three months~~quantities ~~ended~~of ~~September 30,~~oil ~~2001.~~and ~~There~~gas ~~were~~that noare ~~non-hedge settlements~~ultimately ofrecovered. ~~derivatives~~In ~~recorded for the three months ended September 30~~addition, results ~~2002 as compared to a loss~~ of ~~$1.0 million~~ ~~for~~drilling, ~~the~~testing ~~same period in 2001. The gains~~ and ~~losses~~ ~~relate~~production toafter ~~settlements~~the date of ~~derivatives and changes in fair~~an ~~value~~estimate onmay ~~derivatives~~justify ~~that~~material ~~under~~revisions ~~SFAS~~to ~~No. 133~~the ~~do not qualify for hedge accounting~~estimate.

~~For the nine months ended September 30, 2002, the Company recorded a loss of $8.9 million in the non-hedge change in fair value of derivatives, compared to a gain of $~~24~~.5 million for the same period in 2001.~~ ~~Non-hedge settlements of derivatives for the nine months ended~~ ~~September 30, 2002 resulted in a gain of $0.8 million~~ ~~compared to a loss of $0.6 million for the nine months~~ ~~ended September 30, 2001. The gains and losses relate to settlements of derivatives and changes in fair value on derivatives that under SFAS No. 133 do not qualify for hedge accounting.~~

GainTable (Loss) on Sale of Operating Assets, Net. For the three and nine months ended September 30, 2002, we recorded a net gain of $0.1 million and a net loss of $1.7 million, respectively, on sales of non-core onshore operating assets (gain (loss) was calculated as the difference between the sales proceeds and the carrying value of the properties as of the date of the sale). For the three and nine months ended September 30, 2001 there were no dispositions of operating assets. Contents

~~Lease~~Our ~~Operating Expense.~~stockholders ~~Lease~~should ~~operating~~not ~~expense~~assume ~~for the~~that ~~three months ended September 30, 2002 increased by~~the ~~$8.7 million,~~present orvalue ~~59%,~~of ~~from~~future ~~$14.8 million~~net ~~to $23.5 million,~~cash ~~compared~~flows tois the ~~same~~current ~~period in 2001. Lease~~market ~~operating~~value ~~expenses~~of ~~from~~our ~~the~~estimated ~~acquired~~proved ~~Belco properties accounted for $6~~reserves.~~7 million~~ ofIn ~~the~~accordance ~~increase.~~with ~~The remaining increase~~SEC ~~was~~requirements, ~~primarily~~we abase ~~result~~the ofestimated ~~increased~~discounted ~~production~~future ~~from~~net ~~recent~~cash ~~offshore~~flows ~~discoveries,~~from ~~nonrecurring~~proved ~~workover~~reserves ~~expense~~on inprices ~~the Gulf of Mexico~~ and ~~the~~costs ~~acquisition~~as inof the ~~Williston~~date ~~Basin in March~~of ~~2002~~the estimate. OnActual afuture ~~per~~prices ~~Mcfe~~and ~~basis,~~costs ~~lease~~may ~~operating~~be ~~expense increased~~materially ~~from~~higher ~~$0.63~~or tolower ~~$0.75~~than in the ~~2001~~prices and ~~2002 periods, respectively.~~costs ~~The~~as ~~increase~~of ~~on a per Mcfe basis was primarily due to nonrecurring workover expense performed in~~ the ~~three~~date ~~months ended September 30, 2002 at a rate~~ of $0the estimate.~~09 per Mcfe.~~

23 Our estimates of proved reserves directly impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense increases, reducing net income. Such a decline may result from lower market prices or increases in costs, which may make it uneconomic to drill for and produce higher cost fields, or from poor property performance. In addition, the decline in proved reserve estimates may impact the outcome of our assessment of our oil and gas producing properties for impairment.

~~Table~~• Impairment of ~~Contents~~Proved Oil and Gas Properties. We review our long-lived proved properties to be held and used whenever management judges that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon management’s outlook of future commodity prices and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment on a field-by-field basis, which is the lowest level at which depletion of proved properties is calculated. • Impairment of Goodwill. Goodwill of a reporting unit is tested for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Management assesses whether or not an impairment provision is necessary based upon comparing the fair value of a reporting unit with its carrying value including goodwill. • Impairment of Unproved Oil and Gas Properties. Management periodically assesses individually significant unproved oil and gas properties for impairment, on a project-by-project basis. Management’s assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects impact the amount and timing of impairment provisions. • Commodity Derivative Instruments and Hedging Activities. We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize basis swaps, price swaps, futures contracts or collars, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices we receive. On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of CPRM activities.

25 ~~Lease operating expense for the nine months ended~~ ~~September 30, 2002 increased by $32.6 million, or 94%,~~ ~~from $34.8 million to $67.4 million, compared to the~~ same period in 2001. Lease operating expenses from the acquired Belco properties accounted for $26.1 million of the increase. The remaining increase was primarily a result of increased production from recent offshore discoveries, nonrecurring workover expense in the Gulf of Mexico and the acquisition in the Williston Basin in March 2002. On a per Mcfe basis, lease operating expense increased from $0.63 to $0.71 in the 2001 and 2002 periods, respectively. The increase on a per Mcfe basis was primarily due to nonrecurring workover expense performed in the nine months ended September 30, 2002 at a rate of $0.07 per Mcfe.

ProductionTable Taxes. Production taxes for the three months ended September 30, 2002 increased by $2.2 million, or 73%, from $3.0 million to $5.2 million, compared to the same period in 2001. Production taxes on the acquired Belco properties accounted for $1.6 million of the increase and the acquisition in the Williston Basin in March 2002 caused an increase of $0.4 million. As a percent of oil and natural gas revenues (excluding the effects of hedges), production taxes increased from 4.3% to 4.9%. The increase in production taxes as a percent of revenue is primarily the result of the Belco and the Williston Basin acquisition in August 2001 and March 2002, respectively, which increased the number of onshore properties that are subject to production taxes. Contents

Production taxes for the nine months ended September 30, 2002 increased by $7.9 million, or 88%, from $8.9 million to $16.8 million, compared to the same period in 2001. Production taxes on the acquired Belco properties caused an increase of $8.9 million and the acquisition in the Williston Basin in March 2002 caused an increase of $0.8 million. The increases were partially offset by the decreases in oil and natural gas prices. As a percent of oil and natural gas revenues (excluding the effects of hedges), production taxes increased from 3.8% to 5.7%. The increase in production taxes as a percent of revenue is primarily the result of the Belco and the Williston Basin acquisition in August 2001 and March 2002, respectively, which increased the number of onshore properties that are subject to production taxes.


	•	Asset Retirement Obligations. We computed the asset retirement obligation in accordance with SFAS No. 143, “Accounting of Asset Retirement Obligations.” SFAS No. 143 requires us to record the fair value of liabilities for retirement obligations of long-lived assets. Our asset retirement obligations arise from the plugging and abandonment liabilities for our oil and gas wells and offshore platform facilities. We estimated our liability based on the best information available to us at this time. Revisions to the liability could occur due to changes in actual plugging and abandonment costs.

	•	Valuation of Deferred Tax Assets. We computed income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires an asset liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of those assets and liabilities. SFAS No. 109 also requires the recording of a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized.

~~Transportation~~Overview ~~Costs. Transportation costs for the~~ three months ended September 30, 2002 increased by $0.9 million, or 76%, from $1.2 million to $2.2 million, compared to the same period in 2001. The acquired Belco properties accounted for an increase of $0.8 million.

~~Transportation~~We ~~costs~~are ~~for~~an ~~the~~independent ~~nine~~energy ~~months~~company ~~ended~~engaged in ~~September 30,~~oil ~~2002~~and ~~increased~~natural bygas ~~$2.9 million~~exploitation, oracquisition ~~73%,~~and exploration ~~from~~activities ~~$3.9 million~~primarily toin $6the United States.~~8 million,~~ ~~compared~~Our toreserves ~~the~~and ~~same~~production ~~period~~operations are concentrated in ~~2001.~~the ~~Transportation~~following diversified ~~costs~~divisions: ~~from~~Northern ~~the~~(Rocky ~~acquired~~Mountains); Western ~~Belco~~(Uinta ~~properties~~Basin); ~~accounted~~Southern ~~for~~(Permian ~~$2.2 million~~Basin, ofMid-Continent ~~the~~and Gulf ~~increase~~Coast) and Gulf of Mexico (offshore). ~~The~~We ~~remaining~~focus ~~increase~~on ~~was~~maintaining ~~primarily~~a balanced ~~due~~portfolio of lower-risk, long-life onshore reserves and higher-margin offshore reserves to provide a ~~one~~diversified ~~time~~cash ~~adjustment~~flow ~~related~~foundation tofor ~~certain~~our ~~coalbed~~exploitation, ~~methane~~acquisition ~~wells~~and exploration activities.

~~Exploration~~Our ~~Costs. Exploration~~results ~~costs~~of ~~for~~operations ~~the~~are ~~three months ended September 30,~~significantly ~~2002~~impacted ~~decreased~~ by ~~$9.9 million, or 73%, from $13.5 million to $3.6 million, compared to~~ the ~~same period~~prices inof ~~2001.~~oil ~~Dry~~and ~~hole~~natural ~~costs for the three months ended September 30~~gas, ~~2002~~which ~~decreased $7~~are volatile.~~7 million,~~ ~~compared~~The ~~to the~~prices ~~same~~we ~~period~~receive infor ~~2001.~~our ~~One~~oil ~~unsuccessful~~vary ~~exploratory~~from ~~well was~~NYMEX ~~drilled~~prices inbased ~~the~~on ~~Gulf of Mexico in~~ the ~~three~~location ~~months~~and ~~ended September 30,~~quality ~~2002, compared to two higher cost unsuccessful exploratory wells drilled in the Gulf~~ of ~~Mexico in~~ the ~~three~~crude ~~months ended September 30, 2001~~oil. The ~~remaining~~ ~~decrease~~prices inwe ~~exploration~~receive ~~costs~~for ofour ~~$2.4 million~~natural ~~was~~gas ~~primarily attributable~~are tobased ~~the~~on ~~timing~~Henry ~~of purchases of Gulf of Mexico 3-D~~Hub ~~seismic~~prices ~~data~~reduced ~~during~~by ~~the~~transportation ~~three~~expenses, ~~months~~regional ~~ended September 30,~~basis ~~2002,~~differentials ~~compared~~and toprocessing ~~the same period in 2001~~fees.

~~Exploration~~Oil ~~costs~~and ~~for~~natural ~~the~~gas ~~nine~~production ~~months~~costs ~~ended~~are composed ~~September 30,~~of ~~2002~~lease ~~decreased~~operating ~~by $2.7 million~~expense, orproduction ~~11%, from~~taxes ~~$24~~and transportation costs.~~3 million~~ toLease ~~$21.6 million,~~operating ~~compared~~expense toconsists ~~the~~of pumpers’ ~~same~~salaries, ~~period~~utilities, inmaintenance, ~~2001.~~workovers ~~Dry~~and ~~hole~~other costs necessary ~~for~~to ~~the~~operate ~~nine~~our ~~months~~producing ~~ended September 30,~~properties. ~~2002~~In ~~decreased $4.1 million~~general, ~~compared to~~lease ~~the~~operating ~~same~~expense ~~period~~per inunit ~~2001.~~of ~~For~~production ~~the~~is ~~nine~~lower ~~months~~on ~~ended~~our ~~September 30,~~offshore ~~2002,~~properties ~~five~~and ~~unsuccessful~~does ~~exploratory~~not ~~wells~~fluctuate proportionately with ~~were~~our ~~drilled~~production. inProduction ~~the~~taxes ~~Gulf~~are ofassessed ~~Mexico~~by ~~and~~applicable taxing ~~two~~authorities ~~unsuccessful~~as ~~onshore exploratory~~a ~~wells~~percentage ~~were~~of ~~drilled~~revenues. ~~For~~However, properties ~~the~~located ~~nine~~in ~~months~~Federal ~~ended~~waters offshore are generally not ~~September 30,~~subject ~~2001,~~to ~~five~~production ~~unsuccessful~~taxes. ~~exploratory~~Transportation ~~wells~~costs are comprised ~~were~~of ~~drilled~~costs atpaid ~~higher~~to ~~costs~~a incarrier ~~the~~to ~~Gulf~~deliver ofoil ~~Mexico.~~or ~~The~~natural ~~decrease in~~gas ~~dry~~to ~~hole~~a specified ~~costs~~delivery ~~was~~point. ~~partially~~In ~~offset~~some bycases ~~increases~~we inreceive ~~purchases~~a payment offrom ~~Gulf~~the purchasers of ~~Mexico~~our ~~3-D~~oil ~~seismic~~and ~~data~~natural ~~and~~gas, ~~delay~~which ~~rentals~~is ~~during~~net ~~the~~of ~~nine~~gas ~~months~~transportation ~~ended~~costs ~~September 30,~~and ~~2002,~~in ~~compared~~other toinstances we pay the ~~same~~costs ~~period~~of ~~in 2001~~transportation.

~~Depletion~~Exploration expense consists of geological and geophysical costs, ~~Depreciation~~delay rentals and ~~Amortization~~the cost of unsuccessful ~~(DD&A)~~exploratory ~~Expense~~wells. ~~DD&A~~Delay ~~expense~~rentals are typically fixed in nature ~~increased~~in ~~$16~~the short term.~~5 million~~ ~~during~~However, ~~the~~other ~~three~~exploration ~~months~~costs ~~ended~~are ~~September 30~~generally discretionary and exploration activity levels are determined by a number of factors, ~~2002~~including oil and natural gas prices, ~~from~~availability ~~$31.2 million~~of tofunds, quantity and character of ~~$47.7 million~~investment projects, ~~compared~~availability toof ~~the~~service providers and competition.

24 Depletion of capitalized costs of producing oil and natural gas properties is computed using the units-of-production method based upon proved reserves. For purposes of computing depletion, proved reserves are redetermined twice each year. Because the economic life of each producing well depends upon the assumed price for production, fluctuations in oil and natural gas prices impact the level of proved reserves. Higher prices generally have the effect of increasing reserves, which reduces depletion, while lower prices generally have the effect of decreasing reserves, which increases depletion.

~~Table~~ We assess our proved properties on a field-by-field basis for impairment, in accordance with the provisions of ~~Contents~~SFAS No. 144, “Accounting for the Impairment of Long Lived Assets and for Long Lived Assets to be Disposed of,” whenever events or circumstances indicate that the capitalized costs of oil and

26 ~~same period in 2001. Depletion related to the~~ ~~acquired Belco properties caused DD&A expense to increase~~ ~~$15.6 million. An increase of $3.8 million is related~~ to recent discoveries in the Gulf of Mexico and an increase of $0.7 million was related to the acquired properties in the Williston Basin in March 2002. The remaining increase was due to additions and acquisitions of oil and natural gas properties since September 30, 2001. The increases were partially offset by a decrease in DD&A related to developed Gulf of Mexico properties due to a natural decline in production. On a per Mcfe basis, DD&A expense increased from $1.34 to $1.53 primarily due to recent discoveries in the Gulf of Mexico and acquired Belco properties, which have higher DD&A expense per Mcfe.

DD&ATable expense increased $74.8 million during the nine months ended September 30, 2002, from $72.3 million to $147.1 million, compared to the same period in 2001. Depletion related to the acquired Belco properties caused DD&A expense to increase $59.4 million. Recent discoveries in the Gulf of Mexico caused DD&A expense to increase $13.1 million and an increase of $1.7 million was related to the acquired properties in the Williston Basin in March 2002. The remaining increase was primarily due to additions and acquisitions of oil and natural gas properties since September 30, 2001. The increases were partially offset by a decrease in DD&A related to developed Gulf of Mexico properties due to a natural decline in production. On a per Mcfe basis, DD&A expense increased from $1.30 to $1.54 primarily due to recent discoveries in the Gulf of Mexico and acquired Belco properties, which have higher DD&A expense per Mcfe. Contents

~~Impairment~~natural gas properties may not be recoverable. We estimate the expected future cash flows of ~~Unproved~~our oil and gas ~~Properties.~~properties ~~During~~on a field-by-field basis and compare such future cash flows to the ~~three~~carrying ~~months~~amount of the oil and gas properties ~~ended~~to ~~September 30,~~determine ~~2002~~if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we ~~recognized~~will ~~unproved~~adjust ~~property impairments~~the carrying amount of $2the oil and gas properties to fair value.~~8 million.~~ The ~~impairments~~factors ~~consisted~~used to determine fair value include estimates of proved reserves, future commodity $0prices, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected future cash flows.~~8 million~~ Reserve categories used in the impairment analysis for ~~expired~~all periods ~~leases~~considered ~~held~~are incategories ~~Wyoming~~of proven reserves and probable and possible reserves, which were risk adjusted based ~~acquired~~on ~~from~~our ~~Belco~~drilling plans and ~~$2.0 million~~history onof ~~offshore~~successfully ~~leases~~developing those types of reserves. We periodically assess our unproved ~~The~~properties ~~offshore~~to ~~impairments~~determine ~~were~~if ~~recognized~~any assuch aproperties ~~result~~require ofany impairment. anFactors leading to recording unproved impairments include lease expirations and an assessment of the lack of exploration opportunities existing on ~~such properties~~a lease. ~~During~~Such ~~the~~assessment is ~~three~~based ~~months~~on, ~~ended~~among ~~September 30~~other things, the fair value of properties ~~2001,~~located wein ~~recognized~~the same area as the unproved property ~~impairments~~and ofour intent ~~$1.4 million~~to pursue additional exploration opportunities on ~~offshore~~such ~~leases~~property. We expect to record unproved property impairments in future periods.

~~During~~Stock ~~the~~compensation ~~nine~~expense ~~months~~consists ~~ended~~of ~~September 30,~~non-cash ~~2002,~~charges weresulting ~~recognized~~from ~~unproved~~the ~~property~~application ~~impairments~~of the provisions of FASB $9Interpretation No.1 ~~million.~~44 ~~The~~(“FIN ~~impairments~~44”) ~~consisted~~to ofcertain stock ~~$3.4 million~~options ~~for~~granted ~~expired~~to ~~leases~~employees ~~held~~and inissuance ~~Wyoming,~~of restricted stock to $1certain employees.~~6 million~~ ~~for~~Under ~~expired~~FIN ~~leases~~44 ~~held~~we inare ~~Texas,~~required to measure ~~$3.1 million~~compensation ~~for~~cost ~~offshore~~on ~~leases~~stock ~~and~~options ~~$1.0 million~~that ~~for expired~~are ~~leases~~considered ~~held~~to inbe variable ~~North~~awards ~~Dakota,~~until ~~Louisiana~~the ~~and~~date ~~various~~of ~~other~~exercise, forfeiture or ~~states.~~expiration ~~Unproved~~of ~~properties~~such ~~acquired~~options. ~~from~~Compensation ~~Belco~~cost ~~accounted~~is measured for ~~$5.8 million~~the amount of ~~the~~any ~~impairments~~increases ~~related~~in toour ~~expired~~stock ~~leases.~~price and recognized ~~The~~over ~~offshore~~the ~~impairments~~remaining ~~were~~vesting ~~recognized~~period asof athe ~~result~~options. ofAny andecrease ~~assessment~~in ofour ~~the~~stock ~~exploration~~price ~~opportunities~~will ~~existing~~be onrecognized ~~such~~as a decrease in ~~properties.~~compensation ~~During~~cost limited to the ~~nine~~amount ~~months~~of ~~ended~~compensation ~~September 30,~~cost ~~2001,~~previously we recognized ~~unproved~~as ~~property~~a ~~impairments~~result of ~~$3.1 million~~ onan ~~offshore~~increase ~~leases~~in our stock price.

~~Stock~~General ~~Compensation Expense.~~and ~~During~~administrative ~~the~~expenses ~~three months ended~~consist ~~September 30,~~primarily ~~2002, we recorded $1.8 million~~ of ~~stock compensation~~salaries ~~expense~~and related tobenefits, ~~certain~~office ~~stock~~rent, ~~options as a~~legal ~~result~~fees, ofconsultants, ~~applying~~systems ~~FASB~~costs ~~Interpretation~~and ~~No. 44~~other ~~and~~administrative ~~recorded~~costs ~~$0.1 million~~incurred in ~~expense~~our ~~related~~Denver, toDallas, ~~the~~Houston ~~issuance~~and ~~of restricted~~other ~~stock~~offices. ~~During the three months ended~~While ~~September 30, 2001,~~ we ~~reduced~~expect ~~stock~~such ~~compensation~~costs ~~expense related~~ to ~~certain~~increase ~~stock~~with ~~options~~our ~~previously~~growth, ~~recognized~~we inexpect ~~prior~~such ~~periods~~increases byto ~~$2.4 million~~be asproportionately asmaller ~~result~~than ofour ~~applying FASB~~production ~~Interpretation No~~growth. ~~44 and recorded $0.1 million in~~ ~~expense related to the issuance of restricted stock.~~

~~During~~Basis ~~the nine months ended September 30, 2002, we recorded $1.8 million~~ of ~~stock compensation~~Presentation ~~expense as a result of applying FASB Interpretation No. 44~~ and recorded $0.2 million in expense related to the issuance of restricted stock. During the nine months ended September 30, 2001, we reduced stock compensation expense related to certain stock options previously recognized in prior periods by $1.4 million as a result of applying FASB Interpretation No. 44 and recorded $0.3 million in expense related to the issuance of restricted stock.

~~General~~On ~~and~~August 21, ~~Administrative~~2001, ~~(G&A)~~the stockholders of ~~Expense.~~Belco ~~G&A~~approved ~~expense~~an ~~increased $1.6 million,~~agreement orand ~~37%,~~plan ~~during~~of ~~the~~merger, ~~three~~dated ~~months~~as ~~ended~~of ~~September~~June 308, ~~2002~~2001, ~~from~~between $4Belco and Old Westport.~~1 million~~ Pursuant to ~~$5.7 million~~this agreement, ~~compared~~Old toWestport ~~the~~was ~~same~~merged ~~period~~with inand ~~2001.~~into ~~The~~Belco, ~~Merger~~with ~~accounted~~Belco ~~for~~surviving ~~$1.1 million~~and ofchanging ~~the~~its ~~increase~~name to Westport Resources Corporation. The ~~remaining~~ ~~increase~~merger was ~~primarily~~accounted ~~related~~for toas ~~payroll~~a ~~costs such~~purchase astransaction ~~salaries~~for ~~and~~financial ~~benefits,~~accounting ~~resulting~~purposes ~~from~~with anWestport ~~increase in staff.~~as ~~G&A~~the ~~expense~~surviving ~~per~~accounting ~~Mcfe~~entity. ofWestport ~~production~~began ~~remained~~ consolidating the ~~same~~results ~~at $0.18~~of inBelco ~~the~~with ~~third~~its ~~quarter~~results as of ~~2002~~August 21, ~~and~~ 2001, closing ~~respectively~~date.

~~G&A~~On ~~expense increased $6.3~~March ~~million~~1, or2002 we purchased producing oil ~~58%,~~and ~~during~~gas ~~the~~properties ~~nine~~located ~~months~~in ~~ended~~the ~~September 30,~~Williston ~~2002,~~Basin ~~from~~in North Dakota and Montana for approximately $~~10.8~~39 million. toWe operate ~~$17~~over 70% of these properties.~~1 million,~~ ~~compared~~Operations tofrom the ~~same~~ ~~period~~properties inwere ~~2001.~~included ~~The~~in ~~Merger~~our ~~accounted~~results ~~for~~starting ~~$4.8~~on March ~~million~~1, of2002.

25 On September 30, 2002, we acquired oil and natural gas properties located in Southeast Texas for a total cash purchase price of approximately $122 million. We operate substantially all of the properties. Operations from the properties were included in our results starting on October 1, 2002.

~~Table~~ On December 17, 2002, we acquired producing properties, undeveloped leasehold, gathering and compression facilities and other related assets in the Greater Natural Buttes area of ~~Contents~~Uintah County, Utah from certain affiliates of El Paso Corporation for approximately $507 million, subject to certain purchase price adjustments (the “El Paso Acquisition”). The Western Division is comprised substantially of these properties. Operations from these properties were included in our results starting on December 17, 2002.

27 ~~the increase. A majority of the remaining~~ ~~increase was related to payroll costs such as salaries and~~ ~~benefits, resulting from an increase in staff, and due to~~ additional legal fee expense related to general corporate matters. G&A expense per Mcfe of production decreased during the nine months ended September 30, 2002 from $0.19 to $0.18, compared to the same period in 2001.

OtherTable Income (Expense). Other income (expense) for the three months ended September 30, 2002 was ($7.2) million compared to ($1.2) million for the three months ended September 30, 2001. Interest expense increased $3.7 million during the three months ended September 30, 2002, compared to the same period in 2001, as a result of the increase in the debt balances relating to the Merger. For the three months ended September 30, 2001, we recorded income of $2.2 million related to the changes in fair values on interest rate swap contracts that were not designated as hedges for accounting purposes. For the three months ended September 30, 2002, we did not have any interest rate swap contracts that did not qualify for hedge accounting, because the contracts in existence at September 30, 2001 have been terminated or expired. Contents

~~Other~~Results income (expense) for the nine months ended September 30, 2002 was ($22.8) million compared to ($1.1) million for the nine months ended September 30, 2001. Interest expense increased $19.4 million during the nine months ended September 30, 2002, compared to the same period in 2001, as a result of ~~the increase in the debt balances relating to the~~Operations ~~Merger. For the nine months ended September 30, 2002 and~~ 2001, we recorded income of $0.2 million and $1.9 million respectively, related to the changes in fair values on interest rate swap contracts that were not designated as hedges for accounting purposes.

~~Income~~The ~~Taxes.~~following ~~We recorded~~table asets ~~deferred~~forth ~~income tax expense of $1.2 million and~~certain ~~$6.8 million~~operational data for the ~~three~~periods ~~months ended September 30,~~presented: ~~2002 and 2001, respectively.~~

WeSummary ~~recorded a deferred income tax benefit of~~Data ~~$8.6 million for the nine months ended September 30,~~ ~~2002 due to a net loss. For the nine months ended September 30, 2001, we recorded income tax expense of $35.9 million ($33.9 million deferred and $2.0 million current).~~

Net Income. Net income for the three months ended September 30, 2002 was $2.2 million compared to net income of $11.8 million for the three months ended September 30, 2001. The variance was primarily attributable to increases in net revenues of $16.5 million and decrease in income tax expense of $5.5 million offset by increases of $25.6 million in operating expenses and other expense of $6.0 million.



			For the Three Months						For the Six Months
			Ended June 30,						Ended June 30,

			2003			2002			2003			2002


			(In thousands)
Production
	Oil (Mbbls)			1,941			2,092			3,987			3,897
	Natural gas (Mmcf)			29,235			20,551			56,554			40,628
	Mmcfe			40,881			33,103			80,476			64,010
Average Daily Production
	Oil (Mbbls/d)			21.3			23.0			22.0			21.5
	Natural gas (Mmcf/d)			321.3			225.8			312.5			224.5
	Mmcfe/d			449.2			363.8			444.6			353.6
Average Prices
	Oil (per bbl)		$	26.90		$	23.88		$	29.33		$	21.30
	Natural gas (per Mcf)			4.90			3.07			5.25			2.64
	Price (per Mcfe)			4.78			3.41			5.14			2.97
	Hedging effect (per bbl)			(1.95	)		0.05			(3.54	)		0.47
	Hedging effect (per Mcf)			(0.67	)		(0.03	)		(0.88	)		0.04
	Hedging effect (per Mcfe)			(0.57	)		(0.02	)		(0.79	)		0.05
Oil and natural gas sales			$	195,584		$	113,007		$	414,003		$	190,019
Lease operating expense				26,032			24,229			52,368			43,904
	Per Mcfe			0.64			0.73			0.65			0.69
Production taxes				11,364			5,771			24,422			11,636
		Per Mcfe		.28			.17			.30			.18
Transportation costs				3,354			1,951			7,378			4,603
		Per Mcfe		.08			.06			.09			.07
General and administrative costs				7,543			5,495			14,771			11,429
	Per Mcfe			0.18			0.17			0.18			0.18
Depletion, depreciation and amortization				67,036			51,791			128,101			99,380
	Per Mcfe			1.64			1.56			1.59			1.55

~~Net~~The ~~loss~~discussion ~~for~~below ~~the~~includes ~~nine~~a ~~months~~comparison ~~ended September 30,~~of ~~2002 was $14.9 million compared to net~~our ~~income~~results of ~~$62.4 million~~operations for the ~~nine~~three months ~~ended September 30, 2001. The variance was primarily attributable to increases in net revenues of $30.6 million~~ and ~~income tax~~six ~~benefit~~months ~~of $44.5 million offset by increases of~~ended ~~$130.7~~June ~~million~~30, in2003 ~~operating expenses~~ and ~~other~~2002, ~~expense of $21~~respectively.~~7 million.~~

~~Liquidity~~Revenues. Oil and ~~Capital~~natural ~~Resources~~gas revenues for the three months ended June 30, 2003 increased by $82.6 million, or 73%, from $113.0 million to $195.6 million, compared to the three months ended June 30, 2002. Production from the acquired El Paso and Southeast Texas properties accounted for $49.9 million of the increase. The majority of the remaining increase in oil and natural gas revenues was due to increases of 13% and 60% in realized oil and natural gas prices, respectively, excluding the effects of hedging. Production volumes increased by 7.8 Bcfe, or 24%, from 33.1 Bcfe for the three months ended June 30, 2002 to 40.9 Bcfe for the three months ended June 30, 2003. Acquired El Paso and Southeast Texas properties accounted for 10.2 Bcfe of the increase. Production volumes also increased due to drilling activity since June 30, 2002, which were offset by oil and natural gas production declines. Hedging transactions decreased oil and natural gas revenues by $23.4 million, or $0.57 per Mcfe, for the three months ended June 30, 2003, and decreased oil and natural gas revenues by $0.6 million, or $0.02 per

28 ~~Our principal uses of capital have been for the~~ ~~exploitation, acquisition and exploration of oil and natural gas~~ ~~properties.~~

NetTable cashof provided by operating activities was $159.8 million for the nine months ended September 30, 2002 compared to $175.7 million for the nine months ended September 30, 2001. Operating cash flow in the nine month period decreased compared to the prior period due to decreased oil and natural gas prices, and higher operating and other expenses. Contents

~~Net~~Mcfe, ~~cash used in investing activities was $263.0 million~~ for the ~~nine~~three months ended ~~September~~June 30, 2002 ~~compared to $138~~.~~4 million~~ ~~for~~We ~~the~~typically ~~nine~~hedge ~~months~~between ~~ended September 30,~~20% ~~2001.~~and Of40% ~~this~~of ~~total~~our ~~for the nine months ended~~expected ~~September 30,~~production ~~2002,~~one ~~$104.9 million~~to ~~was~~two ~~used~~years ~~for exploitation~~into ~~and~~the ~~exploration~~future. ~~activities~~We ~~and~~currently ~~$168.5 million~~have ~~was~~approximately ~~used~~60-70% ~~for acquisitions, offset by proceeds from sales~~ of ~~properties~~ ofour ~~$10.5 million.~~expected ~~Investing~~2003 ~~activities~~production ~~for~~hedged ~~the~~to ~~nine~~protect ~~months~~cash ~~ended~~flow ~~September 30, 2001 included $132.7 million for exploitation~~ and ~~exploration~~return ~~activities and~~expectations ~~$6.3 million~~on ~~for~~significant ~~acquisitions, offset by proceeds from~~assets ~~sales~~we ofacquired ~~properties~~in oflate $02002.~~7 million.~~

~~Net~~Oil ~~cash~~and ~~provided~~natural bygas ~~financing~~revenues ~~activities~~for ~~was~~the six months ended June 30, 2003 increased by $~~110~~224.80 million, ~~for~~or 118%, from $190.0 million to $414.0 million, compared to the ~~nine~~six months ended ~~September~~June 30, 2002. ~~compared~~Production tofrom (the acquired El Paso, Southeast Texas and Williston Basin properties accounted for $2098.5)9 million of the increase. The majority of the remaining increase in oil and natural gas revenues was due to increases of 38% and 99% in realized oil and natural gas prices, respectively, excluding the effects of hedging. Production volumes increased by 16.5 Bcfe, or 26%, from 64.0 Bcfe for the ~~nine~~six months ended June 30, 2002 to 80.5 Bcfe ~~September~~for the six months ended June 30, ~~2001~~2003. ~~Financing~~Acquired ~~activities~~El Paso, Southeast Texas and Williston Basin properties accounted for 19.5 Bcfe of the ~~nine~~increase. Production volumes also increased due ~~months~~to ~~ended~~drilling ~~September~~activity since June 30, 2002, ~~consisted~~which ofwere offset by oil and natural gas production declines.Hedging transactions decreased oil and natural gas revenues by $~~155~~63.9 million, or $0.79 per Mcfe, for the six months ended June 30, 2003, and increased oil and natural gas revenues by $3.4 million, inor ~~borrowings~~$0.05 ~~utilized~~per Mcfe, for the ~~acquisition~~six months ended June 30, 2002.

26 Commodity Price Risk Management Activities. We recorded a gain of $0.9 million in the non-hedge change in fair value of derivatives for the three months ended June 30, 2003, compared to a $1.0 million gain for the three months ended June 30, 2002. We recorded a gain of $0.7 million in non-hedge settlements of derivatives for the three months ended June 30, 2003, as compared to a loss of $0.3 million for the three months ended June 30, 2002. The gains and losses relate to settlements of derivatives and changes in fair value of derivatives that under SFAS No. 133 do not qualify for hedge accounting or were not originally designated as hedges and any ineffectiveness related to our hedges.

~~Table~~ We recorded a gain of ~~Contents~~$3.2 million in the non-hedge change in fair value of derivatives for the six months ended June 30, 2003, compared to an $8.2 million loss for the six months ended June 30, 2002. We recorded a gain of $0.7 million in non-hedge settlements of derivatives for the six months ended June 30, 2003,as compared to a gain of $0.8 million for the six months ended June 30, 2002. The gains and losses relate to settlements of derivatives and changes in fair value of derivatives that under SFAS No. 133 do not qualify for hedge accounting or were not originally designated as hedges and any ineffectiveness related to our hedges.

~~and~~Gain ~~development~~(Loss) ofon ~~oil~~Sale ~~and natural gas properties, $1.1 million from issuance~~ of ~~common~~Operating ~~stock and~~Assets, $3Net.~~7 million~~ ~~from~~For the ~~gain~~three onmonths ~~the cancellation of the~~ended 8June ~~7/8%~~30, ~~fair~~2003 ~~value~~and ~~interest~~2002, ~~rate~~we ~~swap~~recorded ~~offset~~a bynet gain of $456.01 million ~~debt repayment~~ and a net loss of $31.69 million, ~~preferred~~respectively, ~~stock~~on ~~dividend~~sales ~~payment~~of non-core onshore operating assets.

~~Financing~~For ~~Activity~~the six months ended June 30, 2003 and 2002, we recorded a net gain of $6.5 million and a net loss of $1.9 million, respectively, on sales of non-core onshore operating assets.

~~Revolving~~ Gathering ~~Credit~~Income/ Expense. ~~Facility~~On December 17, 2002, as part of the El Paso Acquisition, we purchased gathering and compression facilities in the Greater Natural Buttes area in Utah. For the quarter ended June 30, 2003, we reported $0.8 million of gathering income and $0.6 million of gathering expense, or a margin of $0.2 million. The gathering income reflected in the consolidated statement of operations relates only to third-party natural gas flowing through our system. Intercompany sales of $1.5 million have been eliminated in our consolidated financial statements.

~~The~~For ~~Company~~the ~~entered~~six ~~into~~months ~~the~~ended ~~Revolving~~June 30, ~~Credit~~2003, we ~~Facility~~reported ~~with~~$2.0 million ~~a syndicate~~ of ~~banks~~gathering ~~upon~~income ~~closing~~and $1.6 million of ~~the~~gathering ~~Merger~~expense, ~~which~~ ~~was~~or ~~subsequently~~a ~~amended~~margin ~~on November~~of $0.4 ~~5, 2001~~million. The ~~Revolving~~ ~~Credit~~gathering ~~Facility,~~income asreflected ~~amended,~~in ~~provides~~the consolidated ~~for~~statement aof ~~maximum~~operations relates only to third-party ~~committed~~natural ~~amount~~gas offlowing ~~$500 million~~through ~~and~~our asystem. ~~borrowing~~Intercompany ~~base~~sales of ~~approximately~~ $~~400~~2.9 million ashave ofbeen ~~September~~eliminated in our consolidated financial statements. In addition, for the six months ended June 30, ~~2002. The~~2003, ~~facility~~gathering ~~matures~~income onand ~~July 1~~expense includes marketing revenue of $727,000 ~~2005.~~and ~~Advances~~marketing ~~under~~expense ~~the~~of $681,000, ~~Revolving~~or ~~Credit~~a ~~Facility~~margin ~~are~~of $46,000 which primarily occurred in the ~~form~~first quarter of ~~either~~2003. anWe ~~ABR~~do ~~loan or~~not aexpect ~~Eurodollar~~to ~~loan~~continue to engage in these marketing activities.

29 ~~The interest on an ABR loan is a fluctuating rate~~ ~~based upon the highest of: (1) the rate of interest~~ ~~announced by JP Morgan Chase Bank, as its prime rate;~~ (2) the secondary market rate for three month certificates of deposits plus 1%; and (3) the Federal funds effective rate plus 0.5% plus in each case a margin of 0% to 0.125% based upon the ratio of total debt to EBITDAX. EBITDAX represents earnings before exploration; depletion, depreciation and amortization; impairment of unproved properties; stock compensation expense; non-hedge change in fair value of derivatives; interest expense; change in fair value of interest rate swap; loss on sale of operating assets, net amortization of deferred financing fees; and total benefit (provision) for income taxes. The interest on a Eurodollar loan is a fluctuating rate based upon the rate at which Eurodollar deposits in the London interbank market are quoted plus a margin of 1.25% to 1.50% based upon the ratio of total debt to EBITDAX.

AsTable of September 30, 2002, we had borrowings and letters of credit issued of approximately $148.8 million outstanding under the Revolving Credit Facility with a weighted average interest rate of 4.23% and available unused borrowing capacity of approximately $251.2 million. All loans were Eurodollar loans. Contents

Lease Operating Expense. Lease operating expense for the three months ended June 30, 2003 increased by $1.8 million, or 7/8%, ~~Senior~~from ~~Subordinated~~$24.2 million ~~Notes~~to $26.0 million, compared to the three months ended June 30, 2002. Lease operating expenses from the acquired El Paso and Southeast Texas properties accounted for $4.1 million of the increase. The increase in lease operating expenses was partially offset by a decrease in workovers of $1.9 million for the three months ended June 30, 2003, as compared to the three months ended June 30, 2002. On a per Mcfe basis, lease operating expense decreased from $0.73 to $0.64 in the 2002 and 2003 periods, respectively. The decrease on a per Mcfe basis was primarily due to ~~2007~~a $0.06 per Mcfe decrease in workover activity in the Gulf of Mexico, Southern and Northern Divisions, compared to workovers performed during the comparable period of 2002. The remaining decrease on a per Mcfe basis was partially attributable to the lower per Mcfe costs on the natural gas properties located in the Western Division.

InLease ~~connection~~operating ~~with~~expense for the ~~Merger,~~six wemonths ~~assumed~~ended ~~$147~~June ~~million~~30, ~~face~~2003 ~~amount~~increased ofby ~~Belco’s~~ $8.5 ~~7/8% Senior~~million, ~~Subordinated~~or ~~Notes~~19%, ~~due 2007. On~~from ~~November~~$43.9 1,million ~~2001,~~to ~~approximately~~ $2452.34 million, ~~face amount~~compared ofto the ~~notes~~six months ~~was~~ended ~~tendered~~June 30, to2002. usLease ~~pursuant~~operating toexpenses from the ~~change~~acquired ofEl Paso, Southeast Texas and Williston Basin ~~control~~properties ~~provisions~~accounted for $10.3 million of the ~~related indenture~~increase. The increase ~~tender~~in ~~price was~~lease ~~equal~~operating toexpenses ~~101%~~was ofpartially ~~the~~offset ~~principal~~by ~~amount~~a decrease in workovers of ~~each~~$1.2 million ~~note~~for ~~plus accrued~~the ~~and~~six ~~unpaid~~months ended ~~interest~~June 30, 2003, as ofcompared ~~October~~to the six months ended June 2930, ~~2001~~2002. ~~Including~~ ~~the~~On ~~premium~~a ~~and~~per ~~accrued~~Mcfe ~~interest~~basis, ~~the~~lease ~~total~~operating ~~amount~~expense ~~paid~~decreased ~~was~~from $240.~~8 million.~~69 Wefor ~~used~~the ~~borrowings~~six ~~under~~months ~~our Revolving~~ended ~~Credit~~June 30, ~~Facility~~ 2002 to ~~fund~~$0.65 for the ~~repayment~~same period in 2003. NoThe ~~gain~~decrease oron ~~loss~~a per Mcfe basis was ~~recorded~~primarily indue ~~connection~~to ~~with~~a ~~the~~$0.03 ~~redemption~~per asMcfe decrease in workovers performed in the ~~fair~~Gulf ~~value~~ of Mexico Division during the six 8months ended June ~~7/8% Senior~~30, ~~Subordinated~~2003, ~~Notes~~compared ~~recorded~~to inworkovers ~~connection~~performed ~~with~~in the ~~Merger~~Gulf ~~equaled~~of Mexico Division during the ~~redemption~~comparable period ~~cost~~of 2002.

Production Taxes. Production taxes for the three months ended June 30, 2003 increased by $5.6 million, or 97%, from $5.8 million 1/to $11.4% million, ~~Senior~~compared ~~Subordinated~~to ~~Notes~~the three months ended June 30, 2002. Production taxes from the acquired El Paso and Southeast Texas properties accounted for $4.2 million of the increase. The remaining increase was primarily due ~~2011~~to the increase in oil and natural gas prices. On a per Mcfe basis, production taxes increased from $0.17 to $0.28 in the three month periods of 2002 and 2003 respectively. The increase in production taxes on a per Mcfe basis was primarily due to the increase in oil and natural gas prices and the acquired onshore El Paso and Southeast Texas properties.

OnProduction ~~November 5,~~taxes ~~2001,~~for wethe ~~completed~~six ~~the~~months ended ~~private~~June 30, ~~placement~~2003 ofincreased by $~~275~~12.8 million, ofor 110%, 8from $11.6 1/million to $24.4% ~~Senior~~million, ~~Subordinated~~compared ~~Notes due 2011 pursuant~~ to ~~Rule 144A~~ ~~under~~ the six ~~Securities~~months ~~Act~~ended ~~of 1933~~June 30, ~~as amended~~2002. ~~The notes~~Production ~~are~~taxes ~~non-callable~~from ~~until~~the acquired ~~November 1,~~El ~~2006~~Paso, ~~when~~Southeast weTexas ~~have the~~and ~~right~~Williston toBasin ~~redeem~~properties accounted ~~them~~ for ~~104~~$8.~~125%~~5 million of the ~~face~~increase. ~~value,~~The remaining ~~declining~~increase ~~thereafter~~was primarily due to ~~face~~the ~~value~~increase in ~~2009.~~oil ~~Proceeds~~and ofnatural ~~approximately~~gas ~~$268 million,~~prices. ~~net~~On ofa ~~underwriting~~per ~~discounts~~Mcfe basis, ~~were~~ ~~used~~production totaxes ~~reduce~~increased ~~outstanding~~from $0.18 ~~indebtedness~~to ~~under~~$0.30 in the ~~Revolving Credit~~six ~~Facility.~~month Onperiods ~~March 14,~~of 2002, weand ~~completed the~~2003 ~~exchange~~respectively. ofThe ~~these~~increase ~~notes~~in ~~for~~production ~~new~~taxes ~~notes~~on ~~with~~a ~~substantially~~per Mcfe ~~identical~~basis ~~terms,~~was ~~except~~primarily ~~that~~due to the ~~new~~increase ~~notes~~in ~~are~~oil ~~generally~~and ~~freely~~natural gas ~~tradeable~~prices and the acquired onshore El Paso, Southeast Texas and Williston Basin properties.

~~Acquisitions~~ Transportation Costs. ofTransportation ~~Certain~~costs ~~Oil~~for the ~~and~~three ~~Gas~~months ~~Properties~~ended June 30, 2003 increased by $1.4 million, or 72%, from $2.0 million to $3.4 million, compared to the three months ended June 30, 2002. The acquired El Paso properties accounted for an increase of $1.2 million.

OnTransportation ~~September 30,~~costs ~~2002~~for wethe ~~acquired~~six ~~southeast~~months ended ~~Texas~~June 30, ~~oil~~2003 ~~and~~increased ~~gas~~by ~~properties~~$2.8 million, ~~for~~or a60%, ~~total cash purchase price of~~from ~~approximately~~ $~~120~~4.6 million, ~~subject~~ to ~~certain purchase price adjustments~~$7.4 million, Wecompared ~~estimate~~to the ~~total proved reserves in the~~six ~~acquired~~months ~~properties~~ended ~~to be approximately 76~~June ~~Bcfe~~30, ~~of which 82% is natural gas~~2002. WeThe ~~will~~acquired ~~operate~~El ~~essentially~~Paso ~~all of the~~ properties. accounted ~~The~~for ~~purchase~~an ~~also~~increase ~~includes~~of ~~10,000~~$2.7 ~~net~~million. ~~undeveloped acres and an interest in~~

27 Exploration Costs. Exploration costs for the three months ended June 30, 2003 increased by $5.9 million, or 77%, from $7.7 million to $13.6 million, compared to the three months ended June 30,

~~Table of Contents~~30

300 squareTable miles of 3-D seismic data. We used funds drawn under our revolving credit facility and cash flow from operations to pay for the acquisition. Contents

~~On November 6,~~ 2002. weExploration ~~agreed~~costs tofor ~~purchase from~~the ~~El Paso~~six ~~Corporation~~months ~~and certain of its affiliated~~ended ~~companies~~June 30, ~~natural~~2003 ~~gas~~increased ~~properties~~by ~~and midstream gathering and compression assets located in Utah for a purchase price of approximately~~ $~~502~~7.7 million, ~~subject~~or to43%, ~~certain purchase~~from ~~price adjustments~~$18. ~~We expect to close the transaction in December of 2002. We estimate that in total the assets would add approximately 600~~0 ~~Bcfe~~million ~~of proved reserves~~ to ~~our reserve base~~$25. ~~Currently these assets are producing approximately 80~~7 ~~Mmcfe/d.~~million, Wecompared ~~plan~~ to ~~fund~~ the ~~transaction initially with~~six ~~debt~~months ~~and~~ended ~~are currently pursuing additional financing options~~June 30, ~~including~~ ~~issuance of equity, the sale of assets, securing a partner for a portion of the acquisition or other capital markets transactions~~2002.

Capital Expenditures



	Three Months Ended				Six Months Ended
	June 30,				June 30,

	2003		2002		2003		2002


	(In thousands)
Geological and geophysical costs	$	2,716	$	1,619	$	9,329	$	6,666
Unsuccessful property acquisitions		16		163		16		257
Delay rentals		856		904		1,398		1,324
Exploratory dry holes costs		10,036		5,014		14,928		9,795

	$	13,624	$	7,700	$	25,671	$	18,042

WeThe ~~anticipate~~majority ~~that~~of ~~our~~the ~~capital~~geological ~~expenditures~~and ~~for~~geophysical ~~2002~~costs ~~will~~pertain beto ~~approximately~~the ~~$170 million.~~purchase Weof do3-D ~~not~~seismic ~~budget for~~data ~~acquisitions~~in ~~and~~Southeast Texas infor the ~~first~~three ~~nine~~ months ofended ~~2002~~June 30, ~~we had acquisitions of $168~~2003.~~5 million.~~ WeFor ~~anticipate that our~~the ~~primary~~three ~~cash~~months ~~requirements~~ended ~~for~~June 30, 2002 ~~will include funding acquisitions~~, ~~funding~~the ~~development~~geological ~~projects~~ and ~~general working~~ ~~capital~~geophysical ~~needs.~~costs ~~For~~primarily ~~the~~relate ~~first~~to ~~nine~~3-D ~~months~~seismic ofdata ~~2002, we had capital~~purchased ~~expenditures~~in ofSouth ~~$104~~Louisiana.~~9 million~~ ~~excluding~~Dry ~~geological~~hole ~~and geophysical~~ costs ~~incurred~~for ofthe ~~$7.0 million.~~three Wemonths ~~will~~ended ~~continue~~June 30, to2003 ~~seek~~resulted ~~opportunities~~from ~~for~~two ~~acquisitions~~high ofcost ~~proved~~unsuccessful ~~reserves~~exploratory ~~with~~wells ~~substantial~~drilled ~~exploitation~~in ~~and~~the ~~exploration potential.~~Gulf ~~The~~of ~~size~~Mexico and ~~timing~~one ~~of capital requirements for~~in ~~acquisitions~~Colorado. isDry ~~inherently~~hole ~~unpredictable~~costs ~~and~~for wethe ~~therefore~~three domonths ~~not~~ended ~~budget~~June 30, ~~for~~2002 ~~them.~~resulted Wefrom ~~expect~~three tounsuccessful ~~fund our capital expenditure~~exploratory ~~activities,~~wells ~~which~~drilled ~~include~~in ~~acquisition,~~the ~~development~~Gulf of ~~and exploration~~Mexico, onwhich ~~our~~included ~~oil~~one ~~and~~dry ~~natural gas properties through cash~~hole ~~flow~~where ~~from~~another ~~operations~~partner ~~and~~carried ~~available~~us ~~capacity~~on ~~under~~ the ~~Revolving Credit Facility~~drilling.

WeFor ~~believe~~the ~~that~~six ~~borrowings~~months ~~under~~ended ~~the~~June 30, ~~Revolving Credit Facility~~2003, ~~projected~~the geological ~~operating~~and ~~cash~~geophysical ~~flows~~costs ~~and~~represent ~~cash~~3-D onseismic ~~hand~~data ~~will~~purchased bein ~~sufficient to meet~~ the ~~requirements~~Gulf of ~~our~~Mexico ~~business~~and Southeast Texas. For the six ~~However~~months ended June 30, ~~future~~2002, ~~cash~~the ~~flows~~geological ~~are~~and ~~subject~~geophysical costs primarily relate to a3-D ~~number~~seismic ofdata ~~variables including~~purchased in the ~~level~~ Gulf of ~~production~~Mexico and ~~oil~~South ~~and~~Louisiana. ~~natural~~Dry ~~gas prices.~~hole Wecosts ~~cannot~~for ~~assure~~the ~~you~~six ~~that~~months ended ~~operations~~June 30, ~~and~~2003 ~~other~~resulted ~~capital~~from three high cost ~~resources~~unsuccessful ~~will~~exploratory ~~provide~~wells ~~cash~~drilled in ~~sufficient~~the ~~amounts~~Gulf toof ~~maintain~~Mexico, ~~planned~~two ~~levels~~in ofTexas ~~capital~~and ~~expenditures~~one oreach ~~that~~in ~~increased~~Wyoming ~~capital~~and Colorado. Dry hole ~~expenditures~~costs ~~will~~for ~~not~~the besix ~~undertaken.~~months ~~Actual~~ended ~~levels~~June 30, of2002 ~~capital~~resulted from ~~expenditures~~four ~~may~~unsuccessful ~~vary~~exploratory ~~significantly~~wells ~~due~~drilled toin athe ~~variety~~Gulf of ~~factors~~ Mexico, which included one dry hole where another partner ~~including~~carried ~~but~~us ~~not~~on ~~limited~~the ~~to:~~drilling.

• Depletion, ~~drilling~~Depreciation ~~results;~~and •Amortization (DD&A) ~~product~~Expense. ~~prices;~~DD&A expense •increased ~~industry~~$15.2 million ~~conditions~~for the three months ended June 30, 2003, from $51.8 million to $67.0 million, compared to the three months ended June 30, 2002. Depletion related to the acquired El Paso and ~~outlook;~~Southeast Texas properties caused DD&A expense to increase $13.3 million. The remaining increase was primarily attributable to a loss of reserve volumes in the West Cameron 180/198 complex causing an increase in DD&A. On a per Mcfe basis, DD&A expense increased from $1.56 to $1.64 in the 2002 and •2003 ~~future~~periods, ~~acquisition~~respectively. The increase was primarily due to the loss of ~~properties~~reserve volumes in the West Cameron 180/198 complex.

~~Special~~DD&A ~~Note~~expense ~~Regarding~~increased ~~Forward-Looking~~$28.7 million for ~~Statements~~the six months ended June 30, 2003, from $99.4 million to $128.1 million, compared to the six months ended June 30, 2002. Depletion related to the acquired El Paso, Southeast Texas and Williston Basin properties caused DD&A expense to increase $24.8 million. The remaining increase was primarily attributable to a loss of reserve volumes in the West Cameron 180/198 complex causing an increase in DD&A. On a per Mcfe basis, DD&A expense increased from $1.55 to $1.59 in the 2002 and 2003 periods, respectively. The increase was primarily due to the loss of reserve volumes in the West Cameron 180/198 complex.

~~Our~~Impairment ~~disclosure~~of ~~and~~Proved Properties. ~~analysis~~During inthe ~~this~~three ~~report,~~month ~~including~~period ~~information~~ended ~~incorporated~~June 30, ~~by reference~~2003, ~~includes forward-looking~~we ~~statements~~recognized ~~within~~proved ~~the meaning of~~property ~~Section 27A~~impairments of ~~the Securities Act of 1933, as amended, or Securities Act, Section~~$1.0 ~~21E~~million. ofIn the ~~Securities~~Gulf ~~Exchange Act~~ of ~~1934~~Mexico, Southern ~~as amended, or Exchange Act,~~ and ~~the~~Northern ~~Private~~Divisions ~~Securities Litigation~~we ~~Reform~~recorded ~~Act~~impairments of ~~1995~~ $0.7 million, ~~that are subject to risks and uncertainties~~$0.2 million ~~Forward-looking statements give our current expectations~~ and ~~projections~~$0.1 million ~~relating~~as ~~to the financial~~a ~~condition,~~result ~~results~~ of ~~operations,~~declines ~~plans,~~in ~~objectives,~~oil ~~future performance~~ and ~~business~~natural ofgas ~~Westport~~reserve ~~Resources~~values ~~Corporation~~due ~~and~~to ~~its~~reserve ~~subsidiaries.~~volume ~~You~~reductions ~~can~~in ~~identify~~underperforming ~~these~~fields. ~~statements~~During by the ~~fact~~ ~~that~~respective ~~they~~three doand ~~not~~six ~~relate~~month ~~strictly~~periods toended ~~historical or current facts. These statements may include words such as “anticipate~~June 30,” ~~“estimate~~2002,” ~~“expect,”~~we ~~“project,”~~recorded ~~“intend,” “plan,”~~no ~~“believe”~~proved ~~and~~property ~~other words and terms of similar meaning in connection with any discussion of the timing or nature of future operating or financial performance or other events~~impairments. ~~All statements other than statements of historical~~ ~~facts included in this report that address activities, events or~~ ~~developments that we~~

28 Impairment of Unproved Properties. During each of the three and six month periods ended June 30, 2003, we recognized unproved property impairments of $11.7 million due to expired leases and from an assessment of the lack of exploration opportunities existing on such properties. In the Gulf of Mexico, Northern and Southern Divisions we recorded impairments of $9.6 million, $1.4 million and $0.7 million,

~~Table of Contents~~31

expect,Table believeof or anticipate will or may occur in the future are forward-looking statements and include, among other things, statements relating to: Contents

• respectively. ~~amount,~~The ~~nature~~$9.6 million ~~and~~recorded ~~timing~~in impairments offor ~~capital~~the ~~expenditures;~~Gulf ~~• drilling~~ of ~~wells;~~Mexico •included ~~reserve~~$8.6 million related ~~estimates;~~to •the ~~timing~~two ~~and~~unsuccessful ~~amount~~exploration ofwells ~~future~~drilled ~~production~~in ofthe three ~~oil~~months ~~and~~ended ~~natural~~June 30, ~~gas;~~2003. •During ~~operating~~the ~~costs~~three ~~and~~months ended ~~other~~June 30, ~~expenses;~~2002, •we ~~cash~~recognized ~~flow~~unproved ~~and~~property impairments ~~anticipated~~of ~~liquidity;~~$5.3 million. •The ~~estimates~~impairments ofconsisted ~~proved reserves~~of $3.0 million, ~~exploitation~~$2.1 million ~~potential~~and or$0.2 million recorded ~~exploration~~in ~~prospect~~the ~~size;~~Northern, Southern and •Gulf ~~marketing~~ of ~~oil~~Mexico ~~and natural gas~~Divisions, respectively.

~~These~~During ~~forward-looking~~the ~~statements~~six ~~are~~months ~~based~~ended onJune 30, ~~our~~2003, ~~expectations~~we ~~and~~recognized ~~beliefs~~unproved ~~concerning~~property ~~future~~impairments ~~events affecting us~~of ~~and~~$15.2 million ~~are~~due ~~subject~~ to ~~uncertainties~~expired ~~and~~leases ~~factors relating to our operations~~ and ~~business~~from ~~environment,~~an ~~all of which are difficult~~assessment relating to ~~predict~~the ~~and~~lack ~~many~~ of ~~which~~exploration ~~are~~opportunities ~~beyond~~existing ~~our~~on such ~~control~~properties. ~~Although~~In ~~we believe that~~ the ~~expectations~~Gulf ~~reflected~~of ~~in our forward-looking statements are reasonable~~Mexico, weNorthern doand ~~not know whether our~~Southern ~~expectations~~Divisions ~~will~~we ~~prove~~recorded ~~correct.~~impairments ~~Any or all~~ of ~~our~~$11.7 million, ~~forward-looking statements in this report may turn out to be wrong~~$2.1 million ~~They can be affected by inaccurate assumptions we might make or by known or unknown risks~~ and ~~uncertainties~~$1. ~~Many factors mentioned in our discussion in this report~~4 million, ~~including the~~respectively. ~~risks outlined under “Risk Factors” in our report~~During ~~on Form 10-K for~~ the ~~year~~six months ended ~~December~~June 3130, ~~2001~~2002, ~~will~~ bewe ~~important~~recognized ~~in determining future results. Actual future~~unproved ~~results~~property ~~may~~impairments ~~vary~~of ~~materially from those reflected in our forward-looking statements~~$6.3 million. ~~Because~~The ~~of these factors, we caution~~impairments ~~that~~consisted ~~investors should not place undue reliance on any~~ of ~~our forward-looking statements~~$3. ~~Further~~0 million, ~~any~~$2.1 million ~~forward-looking~~and ~~statement~~$1.2 million ~~speaks~~recorded ~~only~~in ~~as of~~ the ~~date on which it is made~~Northern, Southern and ~~except~~ asGulf ~~required by law we undertake no obligation to update~~of ~~any~~Mexico ~~forward-looking~~Divisions, ~~statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances~~respectively.

~~Item~~ Stock 3Compensation Expense. ~~Quantitative~~During the three months ended June 30, 2003, we recorded $2.1 million of stock compensation expense related to certain stock options as a result of applying FIN 44 and ~~Qualitative~~recorded ~~Disclosures~~$0.1 million ~~about~~in expense ~~Market~~related ~~Risk~~to the issuance of restricted stock. During the three months ended June 30, 2002, we reduced stock compensation expense related to certain stock options previously recognized in prior periods by $1.9 million as a result of applying FIN 44 and recorded $0.1 million in expense related to the issuance of restricted stock.

~~Our~~During ~~market~~the ~~risk~~six ~~exposures~~months ~~relate~~ended ~~primarily~~June 30, to2003, ~~commodity~~we ~~prices~~recorded ~~and interest rates~~$2.1 million Weof ~~enter~~stock ~~into~~compensation ~~various~~expense ~~transactions~~related ~~involving~~to ~~commodity~~certain ~~price~~stock ~~risk~~options ~~management activities~~as ~~involving~~ a ~~variety~~result of ~~derivatives~~applying FIN 44 ~~instruments~~and recorded $0.1 million in expense related to ~~hedge~~ the ~~impact~~issuance of ~~crude~~restricted ~~oil~~stock. ~~and~~During ~~natural~~the ~~gas~~six ~~price~~months ended ~~fluctuations.~~June 30, ~~In addition~~2002, we ~~enter~~recorded ~~into~~no ~~interest~~stock ~~rate~~compensation ~~swap~~expense as ~~agreements~~a toresult ~~reduce~~of ~~current~~applying ~~interest~~FIN 44 ~~burdens~~and recorded $0.1 million in expense related to ~~our fixed~~the ~~long-term~~issuance ~~debt~~of restricted stock.

~~The~~General ~~derivative~~and ~~commodity~~Administrative ~~price~~(G&A) Expense. ~~instruments~~G&A ~~are~~expense increased ~~generally~~$2.0 million, ~~put~~or in36%, ~~place~~for the three months ended June 30, 2003, from $5.5 million to ~~limit~~$7.5 million, compared to the ~~risk~~three ofmonths ~~adverse~~ended ~~oil~~June 30, ~~and~~2002. The ~~natural~~majority ~~gas~~of ~~price~~the ~~movements.~~increase ~~However,~~was ~~such~~due ~~instruments~~to ~~can~~additional ~~limit~~staff required ~~future~~for ~~gains~~the ~~resulting~~El ~~from~~Paso ~~upward~~Acquisition ~~favorable~~causing ~~oil~~an ~~and~~increase ~~natural~~in ~~gas~~payroll costs ~~price~~such ~~movements.~~as ~~Recognition~~salaries ofand ~~both~~benefits. ~~realized~~G&A ~~and~~expense ~~unrealized~~per Mcfe of ~~gains~~production orincreased ~~losses~~from ~~are~~$0.17 ~~reported~~for ~~currently~~the insecond ~~our~~quarter ~~financial~~of 2002 ~~statements~~to as$0.18 ~~required~~in bythe ~~existing~~second ~~generally~~quarter ~~accepted~~of ~~accounting principles~~2003.

AsG&A ofexpense ~~September~~increased $3.3 30million, ~~2002~~or 29%, wefor ~~had~~the ~~substantial derivative~~six ~~financial~~months ~~instruments~~ended ~~outstanding~~June 30, ~~and~~2003, ~~related to our~~from ~~price risk management program~~$11.4 million ~~See~~to ~~“Note~~$14.8 4”million, compared to the six ~~our~~months ~~consolidated~~ended ~~financial~~June 30, ~~statements~~2002. inThe ~~Item 1~~majority of ~~this~~the increase ~~Report~~was ~~for~~due to additional ~~details~~staff onrequired ~~our~~for ~~oil~~the ~~and~~El ~~natural~~Paso ~~gas related~~Acquisition ~~transactions~~causing inan ~~effect~~increase asin ofpayroll ~~September 30,~~costs ~~2002.~~such ~~For~~as ~~more~~salaries and ~~information~~benefits. onG&A ~~our~~expense ~~interest~~per ~~rate~~Mcfe ~~swaps~~of inproduction ~~effect as of~~remained ~~September 30,~~constant ~~2002,~~at ~~see~~$0.18 ~~“Note 3”~~for tothe ~~our consolidated~~respective ~~financial~~six ~~statements~~month inperiods ~~Item~~ended June 130, of2003 ~~this~~and ~~Report~~2002.

~~Item~~ Other 4Income (Expense). ~~Controls~~Other income (expense) for the three months ended June 30, 2003 was ($13.6) million, compared to ($7.1) million for the three months ended June 30, 2002. Interest expense increased $5.1 million for the three months ended June 30, 2003, compared to the three months ended June 30, 2002, as a result of the increase in the debt balances relating to the El Paso and ~~Procedures~~Southeast Texas acquisitions. We recorded a loss on debt retirement of $0.9 million related to the redemption of the 8 7/8% Senior Subordinated Notes due 2007 on May 5, 2003.

~~Our~~Other ~~Chairman~~income of(expense) for the ~~Board~~six ~~and~~months ~~Chief Executive~~ended ~~Officer~~June 30, ~~and~~2003 ~~our~~was ~~Chief Financial Officer~~ (~~our~~$29.6) million, ~~principal~~compared ~~executive~~to ~~officer~~($15.6) million ~~and~~for ~~principal~~the ~~financial~~six ~~officer,~~months ~~respectively)~~ended ~~have concluded~~June 30, 2002. ~~based~~Interest onexpense ~~their~~increased ~~evaluation~~$13.1 million asfor ofthe asix months ~~date~~ended ~~within 90~~June ~~days~~30, ~~prior~~2003, compared to the ~~date~~six ofmonths ended ~~the~~June 30, ~~filing~~2002, ofas ~~this~~a ~~report~~result ~~on Form 10-Q,~~of ~~that~~the ~~our~~increase ~~disclosure~~in ~~controls~~the debt ~~and~~balances ~~procedures~~relating ~~are effective~~ to ~~ensure~~the ~~that~~El ~~information~~Paso ~~required~~and toSoutheast beTexas acquisitions. ~~disclosed~~We ~~by us~~recorded ina ~~the~~loss ~~reports~~on ~~filed~~debt orretirement ~~submitted~~of $0.9 million byrelated itto ~~under~~the redemption of the ~~Securities~~8 7/8% ~~Exchange~~Senior ~~Act~~Subordinated ofNotes ~~1934,~~due as2007 ~~amended,~~on ~~is recorded~~May 5, ~~processed,~~2003. ~~summarized~~

29 Income Taxes. We recorded a deferred income tax expense of $8.3 million and $1.4 million for the three months ended June 30, 2003 and 2002, respectively.

~~Table of Contents~~32

andTable reported within the time periods specified in the SEC’s rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chairman of the Board and Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Contents

~~There~~We ~~were~~recorded noa ~~significant~~deferred ~~changes~~income intax ~~our~~expense ~~internal~~of ~~controls~~$22.0 million orfor inthe ~~other~~six ~~factors~~months ~~that~~ended ~~could~~June 30, ~~significantly affect~~2003 ~~these~~and ~~controls~~a ~~subsequent~~deferred income tax benefit of $9.8 million due to a net loss for the ~~date~~six ofmonths ~~such~~ended ~~evaluation~~June 30, 2002.

~~PART~~Net Income (Loss) before Cumulative Effect of Change in Accounting Principle. Net income for the three months ended June II30, 2003 was $14.4 —million, ~~OTHER~~compared to a net income of ~~INFORMATION~~$2.4 million for the three months ended June 30, 2002. The variance was primarily attributable to the increase in net revenues of $69.3 million, which was offset by increases of $6.9 million in income tax expense, $43.8 million in operating expenses and $6.6 million in other expense.

~~Item~~ Net income for the six months ended June 30, 2003 was $38.3 million, compared to net loss of $17.1 million for the six months ended June 30, 2002. The ~~Legal~~variance ~~Proceedings~~was primarily attributable to the increase in net revenues of $178.4 million, which was offset by increases of $31.8 million in income tax expense, $77.3 million in operating expenses and $13.9 million in other expense.

~~None~~Cumulative Effect of Change in Accounting Principle. We adopted SFAS No. 143 on January 1, 2003 and recorded a cumulative effect of a change in accounting principle on prior years of $3.4 million, net of tax effects, related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred.

~~Item~~ Liquidity ~~2. Changes in Securities~~ and ~~Use~~Capital ~~of Proceeds~~Resources

~~(a) During~~Our ~~the~~principal ~~quarter~~uses ~~ended September 30, 2002, we issued 206 shares~~ of ~~Common Stock~~capital inhave ~~connection~~been ~~with~~for the ~~exercise of options granted~~ ~~pursuant~~exploitation, toacquisition ~~the~~and ~~Belco~~exploration ~~1996~~of ~~Stock~~oil ~~Incentive~~and ~~Plan~~natural gas properties.

~~(b)~~Net cash provided by operating activities was $196.4 Onmillion ~~September~~for the six months ended June 1130, 2003, compared to $80.8 million for the six months ended June 30, 2002. weOperating ~~paid~~cash flow in the six month period ~~second~~increased ~~quarter~~compared ~~dividend~~to ~~for~~the ~~2002~~respective ofprior ~~$0.40625 per~~period ~~share~~due ~~per~~to ~~quarter~~increased onoil ~~our~~and ~~6 1/2% Convertible~~natural ~~Preferred~~gas ~~Stock~~prices and production.

~~Item~~ Net cash used in investing activities was $98.8 million for the six months ended June 30, 2003, compared to $106.3 million for the six months ended June 30, 2002. ~~Defaults~~Of ~~Upon~~this ~~Senior~~total ~~Securities~~for the six months ended June 30, 2003, $115.6 million was used for exploitation and exploration activities offset by $3.6 million in acquisition purchase price adjustments and proceeds from sales of properties of $13.2 million. Investing activities for the six months ended June 30, 2002 included $71.8 million for exploitation and exploration activities and $42.3 million for acquisitions, offset by proceeds from sales of properties of $7.8 million.

~~None~~Net cash used in financing activities was $74.5 million for the six months ended June 30, 2003, compared to $53.4 million provided for the six months ended June 30, 2002. Financing activities for the six months ended June 30, 2003 consisted of $226.3 million in repayment of long-term debt, a $2.4 million preferred stock dividend payment, $0.9 million loss on debt retirement and a payment of $0.3 million in financing fees, offset by $151.9 million from the issuance of senior subordinated notes and borrowing of long-term debt and $3.5 million from issuance of common stock. Financing activities for the six months ended June 30, 2002 consisted of $55.0 million in borrowings utilized for acquisition and development of oil and natural gas properties and $1.1 million from issuance of common stock, offset by a $2.4 million preferred stock dividend payment and a payment of $0.3 million in financing fees.

~~Item~~ Financing ~~4. Submission of Matters to a Vote of Security Holders~~Activity

~~None.~~ Revolving Credit Facility

~~Item~~ On 5December 17, 2002, we entered into the Revolving Credit Facility with JPMorgan Chase Bank, Credit Suisse First Boston Corporation and certain other lenders party thereto to replace our previous revolving credit facility. ~~Other~~The Revolving ~~Information~~Credit Facility provides for a maximum committed amount of $600 million and an initial borrowing base of approximately $470 million. The facility matures on

33 ~~None.~~

ItemTable 6.of Exhibits and Reports on Form 8-KContents

~~(a)~~December ~~Exhibits~~16, 2006. ~~The~~In ~~following~~the ~~exhibits~~past, we made ~~are~~borrowings ~~filed~~under asthe ~~part~~Revolving ofCredit ~~this~~Facility ~~Form 10-Q:~~to refinance our outstanding indebtedness under our previous revolving credit facility and to pay general corporate expenses.

2	.1	Agreement and Plan of Merger, dated as of March 9, 2000, by and among Westport Oil and Gas Company, Inc., Westport Energy Corporation, Equitable Production Company, Equitable Production (Gulf) Company and EPGC Merger Sub Corporation (incorporated by reference to Exhibit 2.1 to the registration statement on Form S-1, Registration No. 333-40422), filed with the Securities and Exchange Commission on June 29, 2000).
2	.2	Agreement and Plan of Merger, dated as of June 8, 2001, by and among Belco Oil & Gas Corp. and Westport Resources Corporation (incorporated by reference to Exhibit 2.1 to the registration statement on Form S-4/A, (Registration No. 333-64320), filed with the Securities and Exchange Commission on July 24, 2001).
3	.1	Amended Articles of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the registration statement on Form 8-A/A, filed with the Securities and Exchange Commission on August 31, 2001).
3	.2	Second Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the registration statement on Form 8-A/A, filed with the Securities and Exchange Commission on August 31, 2001).
4	.1	Specimen Certificate for shares of Common Stock of the Company (incorporated by reference to Exhibit 4.1 to the registration statement on Form 8-A/A, filed with the Securities and Exchange Commission on August 31, 2001).

Advances under the Revolving Credit Facility are in the form of either an ABR loan or a Eurodollar loan. The interest on an ABR loan is a fluctuating rate based upon the highest of:

30 • the rate of interest announced by JP Morgan Chase Bank, as its prime rate; • the secondary market rate for three month certificates of deposits plus 1%; or • the Federal funds effective rate plus 0.5%

~~Table~~ in each case plus a margin of ~~Contents~~0% to 0.625% based upon the ratio of total debt to EBITDAX, as defined below, and the ratings of our senior unsecured debt as issued by Standard and Poor’s Rating Group and Moody’s Investor Services, Inc. EBITDAX is a non-GAAP financial measure, which for purposes of the Revolving Credit Facility, is defined to mean net income of the Company and its restricted subsidiaries determined on a consolidated basis in accordance with GAAP, plus (a) to the extent deducted from revenues in determining consolidated net income, (i) the aggregate amount of consolidated interest expense, (ii) the aggregate amount of letter of credit fees paid, (iii) the aggregate amount of income tax expense and (iv) all amounts attributable to depreciation, depletion, exploration, amortization and other non-cash charges and expenses, minus (b) to the extent included in revenues in determining consolidated net income, all non-cash extraordinary income, in each case determined on a consolidated basis in accordance with GAAP and without duplication of amounts.

4	.2	Specimen Certificate for shares of 6 1/2% Convertible Preferred Stock of the Company (incorporated by reference to Exhibit 4 to the registration statement on Form 8-A/ A, filed with the Securities and Exchange Commission on August 31, 2001).
*99	.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Executive Officer of the Company.
*99	.2	Certification Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Financial Officer of the Company.

The interest on a Eurodollar loan is a fluctuating rate based upon the rate at which Eurodollar deposits in the London interbank market are quoted plus a margin of 1.000% to 1.875% based upon the ratio of total debt to EBITDAX and the ratings of our senior unsecured debt as issued by Standard and Poor’s Rating Group and Moody’s Investor Service, Inc.

~~(b) Reports~~The Revolving Credit Facility contains various covenants and default provisions applicable to us and our restricted subsidiaries, including two financial covenants that require us to maintain a current ratio of not less than 1.0 to 1.0 and a ratio of EBITDAX to consolidated interest expense for the preceding four consecutive fiscal quarters of not less than 3.0 to 1.0. Commitment fees under the Revolving Credit Facility range from 0.25% to 0.5% on ~~Form 8-K:~~the average daily amount of the available unused borrowing capacity based on the rating of our senior unsecured debt as issued by Standard and Poor’s Rating Group and Moody’s Investor Service, Inc.

~~None~~ Under the terms of the Revolving Credit Facility we must meet certain tests before we are able to declare or pay any dividend on (other than dividends payable solely in equity interests of the Company other than disqualified stock), or make any payment of, or set apart assets for a sinking or other analogous fund for the purchase, redemption, defeasance, retirement or other acquisition of, any shares of any class of equity interests of us or any of our restricted subsidiaries, whether now or hereafter outstanding, or make any other distribution in respect thereof, either directly or indirectly, whether in cash or property or in obligations of the Company or any restricted subsidiary. Other covenants include restrictions on incurring additional indebtedness, liens, and guarantee obligations; limitations on fundamental changes and sales of assets; restrictions on making certain investments, loans or advances; limitations on optional redemption of subordinated indebtedness; restrictions on transacting with affiliates, changing lines of business and entering into certain hedging agreements; and limitations on sale and leasebacks and use of proceeds.

* As ~~Filed~~of ~~herewith~~June 30, 2003, we had no outstanding borrowings and letters of credit of approximately $104.5 million outstanding under the Revolving Credit Facility. Available unused borrowing capacity was approximately $365.5 million. The letters of credit were issued primarily in connection with the margin requirements of our oil and natural gas derivative contracts. The Revolving Credit Facility currently limits the outstanding letters of credit to $200 million. At August 1, 2003 we had no outstanding indebtedness and letters of credit of approximately $41.2 million.

3134

~~SIGNATURES~~ 8 1/4% Senior Subordinated Notes Due 2011

~~Pursuant~~On April 3, 2003, we issued an additional $125 million of our Senior Subordinated Notes Due 2011 pursuant to Rule 144A and Regulation S under the Securities ~~requirements~~Act at a price of 106% of the ~~Securities~~principal amount, with ~~Exchange~~accrued ~~Act~~interest offrom ~~1934~~November 1, 2002. The 2003 notes were issued as ~~amended~~additional debt securities under the indenture pursuant to which on November 5, 2001, we issued $275 million of our 8 1/4% Senior Subordinated Notes Due 2011 and on December 17, 2002, we issued $300 million in additional principal amount of our 8 1/4% Senior Subordinated Notes Due 2011. All of the ~~registrant~~2001 and ~~has~~2002 ~~duly~~notes ~~caused~~were subsequently exchanged on March 14, ~~this~~2002 ~~report~~and March 12, 2003, respectively, for equal principal amounts of notes having substantially identical terms and registered under the Securities Act. All of our 8 1/4% Senior Subordinated Notes Due 2011 constitute a single class of debt securities under the indenture relating to bethese ~~signed~~notes. These notes are senior subordinated unsecured obligations of Westport and are jointly and severally guaranteed, on ~~its~~a ~~behalf~~senior subordinated basis, by some of our existing and future restricted subsidiaries. These notes mature on November 1, 2011. We pay interest on these notes semiannually on May 1 and November 1. We used the ~~undersigned~~proceeds from the sale of the ~~thereunto~~2003 ~~duly~~notes ~~authorized~~to redeem all of our outstanding 8 7/8% Senior Subordinated Notes due 2007 (described below) and to reduce our indebtedness under the Revolving Credit Facility. We are entitled to redeem our 8 1/4% Senior Subordinated Notes Due 2011 in whole or in part on or after November 1, 2006 for the redemption price set forth in these notes. Prior to November 1, 2006, we are entitled to redeem these notes, in whole but not in part, at a redemption price equal to the principal amount of the notes plus a premium. There is no sinking fund for these notes. We have agreed to file an exchange offer registration statement, or under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2003 notes. We filed an exchange offer registration statement on June 4, 2003 relating to the 2003 notes. In the event we fail, among other things, to effect the registration statement or consummate the exchange offer relating to the 2003 notes on a timely basis, we will pay additional interest on such notes.

~~WESTPORT~~ The ~~RESOURCES~~indenture ~~CORPORATION~~governing the 8 1/4% Senior Subordinated Notes Due 2011 limits what we and our restricted subsidiaries do, including:

~~By:~~• ~~/s/~~incur ~~DONALD~~additional D.indebtedness; ~~WOLF~~• ~~Name:~~pay ~~Donald~~dividends D.on ~~Wolf~~our ~~Title:~~capital ~~Chairman~~stock ofor redeem, repurchase or retire our capital stock or subordinated indebtedness; • make investments; • incur liens; • create any consensual limitation on the ~~Board~~ability of our restricted subsidiaries to pay dividends, make loans or transfer property to us; • engage in transactions with our affiliates; • sell assets, including capital stock of our subsidiaries; and ~~Chief~~• ~~Executive~~consolidate, ~~Officer~~merge or transfer assets.

~~Date: November~~ During any period that the 8 1/4% Senior Subordinated Notes Due 2011 have investment grade ratings from both Moody’s Investors Service, ~~2002~~Inc. and Standard and Poor’s Ratings Group and no default has occurred and is continuing, the foregoing covenants will cease to be in effect with the exception of covenants that contain limitations on liens and on, among other things, certain consolidations, mergers and transfers of assets. These notes do not currently qualify as investment grade.

~~By:~~8 7/s/8% ~~LON~~Senior ~~MCCAIN~~Subordinated ~~Name:~~Notes ~~Lon~~due ~~McCain Title: Vice President, Chief Financial Officer and Treasurer~~2007

~~Date:~~In connection with the Merger, we assumed $147 ~~November~~million face amount of Belco’s 8 7/8% Senior Subordinated Notes due 2007. On November 1, ~~2002~~2001, approximately $24.3 million face amount of the notes was tendered to us pursuant to the change of control provisions of the related indenture. The tender price was equal to 101% of the principal amount of each note plus accrued and unpaid interest as of

3235

~~CERTIFICATION~~October 29, 2001. Including the premium and accrued interest, the total amount paid was $24.8 million. We used borrowings under our previous revolving credit facility to fund the repayment. No gain or loss was recorded in connection with the redemption, as the fair value of the 8 7/8% Senior Subordinated Notes due 2007 recorded in connection with the Merger equaled the redemption cost. On May 5, 2003 we redeemed all of our outstanding 8 7/8% Senior Subordinated Notes due 2007 in the aggregate principal amount of approximately $123 million. Including the premium and accrued interest, the total amount paid was $129.7 million. The redemption was funded with the proceeds from the offering of $125 million of our 8 1/4% Senior Subordinated Notes Due 2011 issued on April 3, 2003. The remaining proceeds were used to reduce our indebtedness under the Revolving Credit Facility.

I,Capital ~~Donald D. Wolf, Chairman of the Board and Chief Executive Officer of Westport Resources Corporation, certify that:~~ Expenditures

~~1. I~~We ~~have~~anticipate ~~reviewed~~that ~~this~~our ~~quarterly~~capital ~~report~~expenditures onfor ~~Form~~2003 will be approximately $270 ~~10-Q~~million. We anticipate that our primary cash requirements for 2003 will include funding development projects, exploration and general working capital needs. For the first six months of ~~Westport~~2003, ~~Resources~~we ~~Corporation;~~had capital expenditures of $112.1 million excluding geological and geophysical costs incurred of $9.3 million.

~~2. Based~~We onwill mycontinue ~~knowledge,~~to ~~this~~seek ~~quarterly~~opportunities for ~~report~~acquisitions ~~does~~of ~~not~~proved ~~contain~~reserves ~~any~~with ~~untrue~~substantial ~~statement~~exploitation and exploration potential. The size and timing of acapital requirements ~~material~~for ~~fact~~acquisitions is inherently unpredictable and we ortherefore ~~omit~~do tonot ~~state~~budget afor ~~material~~them. ~~fact~~We ~~necessary~~expect to ~~make~~fund ~~the~~our capital ~~statements~~expenditure ~~made~~activities, inwhich ~~light~~include acquisition, development of ~~the~~and ~~circumstances~~exploration ~~under~~on ~~which~~our ~~such statements~~oil ~~were~~and ~~made~~natural gas properties, through ~~not~~cash ~~misleading~~flow ~~with~~from ~~respect~~operations toand ~~the~~available ~~period~~capacity under ~~covered~~the byRevolving ~~this~~Credit ~~quarterly report;~~Facility.

~~3. Based~~We onbelieve mythat ~~knowledge,~~borrowings under the ~~financial~~Revolving ~~statements~~Credit Facility, ~~and~~projected ~~other~~operating ~~financial~~cash ~~information~~flows ~~included~~and incash ~~this~~on hand ~~quarterly~~will ~~report~~be sufficient to meet the requirements of our business. However, ~~fairly~~future ~~present~~cash inflows ~~all~~are ~~material~~subject ~~respects~~to ~~the~~a number of variables ~~financial~~including ~~condition,~~the ~~results~~level of production and oil and natural gas prices. We cannot assure you that operations and other capital resources will provide cash ~~flows~~in sufficient amounts to maintain planned levels of ~~the~~capital expenditures or that increased capital ~~registrant~~expenditures aswill not be undertaken. Actual levels of, ~~and~~capital expenditures ~~for,~~may ~~the~~vary ~~periods~~significantly ~~presented~~due into ~~this~~a variety of factors, ~~quarterly~~including ~~report;~~but not limited to:

~~4. The~~• ~~registrant’s~~drilling ~~other~~results; ~~certifying officers~~• ~~and I~~product ~~are~~prices; ~~responsible~~• ~~for~~industry ~~establishing~~conditions and ~~maintaining~~ ~~disclosure~~outlook; ~~controls~~ and ~~procedures~~• ~~(as~~future ~~defined~~acquisition ~~in Exchange~~of ~~Act Rules 13a-14 and 15d-14) for the registrant and we have:~~ properties.

~~(a)~~ Special ~~designed~~Note ~~such~~Regarding disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; (b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and (c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;Forward-Looking Statements

5.Our disclosure and analysis in this report, including information incorporated by reference, includes forward-looking statements within the meaning of Section ~~The~~27A ~~registrant’s~~of ~~other~~the ~~certifying~~Securities Act of 1933, as amended, or ~~officers~~Securities ~~and~~Act, Section I21E ~~have~~of ~~disclosed~~the Securities Exchange Act of 1934, ~~based~~as onamended, ~~our~~or ~~most~~Exchange ~~recent~~Act, and the Private Securities ~~evaluation~~Litigation Reform Act of 1995, that are subject to risks and uncertainties. Forward-looking statements give our current expectations and projections relating to the ~~registrant’s~~financial condition, ~~auditors~~results of operations, plans, objectives, future performance and business of Westport and its subsidiaries. You can identify these statements by the ~~audit~~fact that they do not ~~committee~~relate strictly to historical or current facts. These statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe” and other words and expressions of ~~registrant’s~~similar ~~board~~meaning in connection with any discussion of ~~directors~~the (timing or ~~persons~~nature of future operating ~~performing~~or financial performance or other events. All statements other than statements of historical facts included in this report that address activities, events or developments that we expect, believe or anticipate will or may occur in the ~~equivalent~~future ~~function)~~are forward-looking statements and include, among other things, statements relating to:

~~(a)~~• ~~all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record~~amount, ~~process,~~nature ~~summarize~~ and ~~report~~timing ~~financial~~of ~~data~~capital ~~and have identified for the registrant’s auditors any material weaknesses in internal controls~~expenditures; ~~and~~• ~~(b)~~projected ~~any~~drilling ~~fraud,~~of ~~whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls~~wells; ~~and~~

36 ~~6. The registrant’s other certifying~~ ~~officers and I have indicated in this quarterly report~~ ~~whether or not there were significant changes in internal~~ controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

By:Table /s/ DONALD D. WOLF Name: Donald D. Wolf Title: Chairman of the Board and Chief Executive OfficerContents

~~Date: November 8~~• reserve estimates; • timing and amount of future production of oil and natural gas; • operating costs and other expenses; • cash flow, ~~2002~~ anticipated liquidity and prospects for growth; • estimates of proved reserves and exploitation and exploration opportunities; and • marketing of oil and natural gas.

33 These forward-looking statements are based on our expectations and beliefs concerning future events affecting us and are subject to uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. Although we believe that the expectations reflected in our forward-looking statements are reasonable, we do not know whether our expectations will prove correct. Any or all of our forward-looking statements in this report may turn out to be wrong. They can be affected by inaccurate assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report, including the risks outlined under “Risk Factors” in our report on Form 10-K for the year ended December 31, 2002, will be important in determining future results. Actual future results may vary materially from those reflected in our forward-looking statements. Because of these factors, we caution that investors should not place undue reliance on any of our forward-looking statements. Further, any forward-looking statement speaks only as of the date on which it is made, and except as required by law we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

~~Table~~Item of3. ~~Contents~~Quantitative and Qualitative Disclosures about Market Risk

~~CERTIFICATION~~Our market risk exposures relate primarily to commodity prices and interest rates. We enter into various transactions involving commodity price risk management activities involving a variety of derivatives instruments to hedge the impact of crude oil and natural gas price fluctuations. In addition, we enter into interest rate swap agreements to reduce current interest burdens related to our fixed long-term debt.

I,The ~~Lon~~derivative ~~McCain,~~commodity ~~Vice~~price ~~President~~instruments are generally put in place to limit the risk of adverse oil and natural gas price movements. However, ~~Chief~~such ~~Financial~~instruments can limit ~~Officer~~future gains resulting from upward favorable oil and ~~Treasurer~~natural gas price movements. Recognition of ~~Westport~~both ~~Resources~~realized ~~Corporation,~~and ~~certify~~unrealized ~~that:~~gains or losses is reported currently in our financial statements as required by existing generally accepted accounting principles.

1As of June 30, 2003, we had substantial derivative financial instruments outstanding and related to our price risk management program. See “Note I4” ~~have~~to our ~~reviewed~~consolidated financial statements in Item 1 of this Report ~~quarterly~~for ~~report~~additional details on our oil and natural gas related ~~Form~~transactions in effect as of June ~~10-Q~~30, 2003. For more information on our interest rate swaps in effect as of June 30, ~~Westport~~2003, ~~Resources~~see ~~Corporation;~~“Note 3” to our consolidated financial statements in Item 1 of this Report.

2Item 4. ~~Based~~ onControls myand knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; Procedures

~~3. Based~~Our onmanagement, mywith ~~knowledge,~~the participation of our Chairman of the ~~financial~~Board and Chief Executive Officer (our principal ~~statements,~~executive officer) and ~~other~~our Chief Financial Officer (our principal financial ~~information~~officer) ~~included~~have inconcluded, ~~this~~based on their ~~quarterly~~evaluation as of the end of the period covered by this report, that ~~fairly~~our ~~present~~disclosure controls and procedures are effective to ensure that information required to be disclosed by us in ~~all~~the reports ~~material~~filed ~~respects~~or submitted by us under the Securities Exchange ~~financial~~Act ~~condition~~of 1934, ~~results~~as ofamended, ~~operations~~is recorded, processed, summarized and reported ~~cash~~within ~~flows~~the oftime periods specified in the SEC’s ~~registrant~~rules asand offorms, and ~~for,~~include ~~the~~controls ~~periods~~and ~~presented~~procedures designed to ensure that information required to be disclosed by us in ~~this~~such ~~quarterly~~reports ~~report;~~is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

37 ~~4. The registrant’s other certifying~~ ~~officers and I are responsible for establishing and~~ ~~maintaining disclosure controls and procedures (as defined in~~ ~~Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:~~

(a)Table designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; (b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and (c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;Contents

~~5. The~~There ~~registrant’s~~were ~~other~~no ~~certifying~~changes in our internal controls ~~officers~~over ~~and I~~financial ~~have~~reporting ~~disclosed,~~during ~~based~~the onperiod ~~our~~covered ~~most~~by ~~recent~~this ~~evaluation,~~report tothat ~~the~~have ~~registrant’s~~materially ~~auditors~~affected ~~and~~or ~~the~~are ~~audit committee~~reasonably oflikely ~~registrant’s~~to materially ~~board~~affect ofour ~~directors~~internal ~~(or~~controls ~~persons performing~~over ~~the~~financial ~~equivalent function):~~reporting.

~~(a)~~ PART II — all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; andOTHER INFORMATION

6Item 1. ~~The~~ ~~registrant’s~~Legal other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Proceedings

~~By:~~ Westport ~~/s/~~Oil ~~LON~~and ~~MCCAIN~~Gas ~~Name:~~Company, ~~Lon~~L.P., ~~McCain~~our ~~Title:~~indirect wholly-owned ~~Vice~~subsidiary, ~~President~~is a defendant in a case brought in July 2001 against its predecessor, ~~Chief~~Belco ~~Financial~~Energy ~~Officer~~Corp., in the district court of Sweetwater County, Wyoming. The complaint seeks damages on behalf of a purported class of royalty owners for alleged improper deduction, valuation and ~~Treasurer~~reporting under the Wyoming Royalty Payment Act in connection with royalty payments made by Belco on production from wells it operates in the Moxa Arch area of the Green River Basin. Plaintiffs have advised us that they calculate the amount of damages allegedly owed by Belco to be approximately $1,165,000, which includes attorneys fees and litigation costs. We have denied liability for any of these damages and believe that we have valid defenses to plaintiffs’ claims. Class certification and discovery have been stayed pending the decision by the Wyoming Supreme Court in a case involving unrelated parties that may have a bearing on this case and other similar cases filed by plaintiffs against other oil and gas industry operators in the Green River Basin. Settlement discussions have occurred with plaintiffs. We believe that our potential liability with respect to this proceeding is not material in the aggregate to our financial position, results of operations or cash flows. Accordingly, we have not established a reserve for loss in connection with this proceeding.

~~Date: November 8~~Westport Oil and Gas Company, L.P. is also a party to an appeal filed by Uintah County, Utah, to the determination by the Utah State Tax Commission of the taxable value of our tangible real property in Uintah County for the 2003 tax year. This property was included in the assets we acquired in December 2002 from affiliates of El Paso Corporation. The Property Tax Division assessed a taxable value of $117,381,602 for our tangible real property in Uintah County based upon the future net value of the proved producing reserves and a value for lease and well equipment. We believe that this assessment was in accordance with applicable regulations and historic practice. Uintah County appealed that assessment, claiming that the taxable value should be $517,000,000, which it claims to be the “fair market value” of the taxable property. The County’s figure is based on the adjusted purchase price of the El Paso assets. Such adjusted purchase price included significant proved undeveloped reserves and non-proved reserves, which are not generally subject to assessment under existing regulations and practice, as well as non-operated working interests and mid-stream assets, which are generally taxed to third-party operators or otherwise subject to separate assessment. We believe that Uintah County’s position is not consistent with applicable law or existing practice and that the original assessment of the Property Tax Division will be upheld. We have not established a reserve for loss in connection with this proceeding.

34 From time to time, we may be a party to various other legal proceedings. Except as discussed herein, we are not currently party to any material pending legal proceedings.

~~Table~~Item 2. Changes in Securities and Use of ~~Contents~~Proceeds.

~~INDEX~~(a) During TOthe ~~EXHIBITS~~quarter ended June 30, 2003, we issued 264,416 shares of our common stock, including 5,000 shares of restricted stock and issued 50,387 shares of our common stock in connection with the exercise of options granted pursuant to the 2000 Stock Incentive Plan. We also issued 22,270 shares of our common stock in connection with the exercise of options granted pursuant to the Belco 1996 Stock Incentive Plan and issued 186,163 shares of our common stock in connection with the exercise of options granted pursuant to the EPGC 2000 Stock Option Plan. We also issued 596 shares of our common stock to a director in lieu of cash for director fees.

Exhibit
Number
	2	.1	Agreement and Plan of Merger, dated as of March 9, 2000, by and among Westport Oil and Gas Company, Inc., Westport Energy Corporation, Equitable Production Company, Equitable Production (Gulf) Company and EPGC Merger Sub Corporation (incorporated by reference to Exhibit 2.1 to the registration statement on Form S-1, Registration No. 333-40422), filed with the Securities and Exchange Commission on June 29, 2000).
	2	.2	Agreement and Plan of Merger, dated as of June 8, 2001, by and among Belco Oil & Gas Corp. and Westport Resources Corporation (incorporated by reference to Exhibit 2.1 to the registration statement on Form S-4/A, (Registration No. 333-64320), filed with the Securities and Exchange Commission on July 24, 2001).
	3	.1	Amended Articles of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the registration statement on Form 8-A/A, filed with the Securities and Exchange Commission on August 31, 2001).
	3	.2	Second Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the registration statement on Form 8-A/A, filed with the Securities and Exchange Commission on August 31, 2001).
	4	.1	Specimen Certificate for shares of Common Stock of the Company (incorporated by reference to Exhibit 4.1 to the registration statement on Form 8-A/A, filed with the Securities and Exchange Commission on August 31, 2001).
	4	.2	Specimen Certificate for shares of 6 1/2% Convertible Preferred Stock of the Company (incorporated by reference to Exhibit 4 to the registration statement on Form 8-A/ A, filed with the Securities and Exchange Commission on August 31, 2001).
	*99	.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Executive Officer of the Company.
	*99	.2	Certification Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Financial Officer of the Company.

(b) On June 11, 2003 we paid the second quarter dividend for 2003 of $0.40625 per share per quarter on our 6 1/2% convertible preferred stock.

* Filed herewith38

(c) No equity securities of the Company were sold by the Company during the period covered by the report that were not registered under the Securities Act.


Item 3.	*Defaults Upon Senior Securities.*

None.


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

(a) The Company held its Annual Meeting of Stockholders on May 22, 2003.

(b) Robert A. Haas, David L. Porges and Donald D. Wolf were elected to continue to serve as Class 2 directors of the Company.


	Proposal No. 1 — Election of Directors.


Director	For		Withheld

Robert A. Haas		57,273,288		1,156,877
David L. Porges		57,272,288		1,157,877
Donald D. Wolf		57,273,288		1,156,877


	Proposal No. 2 — To ratify the appointment of KPMG LLP as independent public accountant of the Company for the fiscal year ending December 31, 2003.


FOR		AGAINST		ABSTAIN

	57,919,371		494,815		15,979


Item 5.	*Other Information.*

None.


Item 6.	*Exhibits and Reports on Form 8-K.*

(a) Exhibits. The following exhibits are filed as part of this Form 10-Q with the Securities and Exchange Commission:


2	.1	Agreement and Plan of Merger, dated as of March 9, 2000, by and among Westport Oil and Gas Company, Inc., Westport Energy Corporation, Equitable Production Company, Equitable Production (Gulf) Company and EPGC Merger Sub Corporation (incorporated by reference to Exhibit 2.1 to the registration statement on Form S-1 (Registration No. 333-40422), filed on June 29, 2000).
2	.2	Agreement and Plan of Merger, dated as of June 8, 2001, by and among Belco Oil & Gas Corp. and Westport Resources Corporation (incorporated by reference to Exhibit 2.1 to the registration statement on Form S-4/A (Registration No. 333-64320), filed on July 24, 2001).
3	.1	Amended Articles of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the registration statement on Form 8-A/A, filed on August 31, 2001).
3	.2	Certificate of Amendment to Amended Articles of Incorporation of the Company, dated March 5, 2003 (incorporated by reference to Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 30, 2003, filed on May 8, 2003).
3	.3	Second Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the registration statement on Form 8-A/A, filed on August 31, 2001).
4	.1	Specimen Certificate for shares of Common Stock of the Company (incorporated by reference to Exhibit 4.1 to the registration statement on Form 8-A/A, filed on August 31, 2001).
4	.2	Specimen Certificate for shares of 6 1/2% Convertible Preferred Stock of the Company (incorporated by reference to Exhibit 4 to the registration statement on Form 8-A/A, filed on August 31, 2001).


4	.3	Certificate of Designations of 6 1/2% Convertible Preferred Stock, dated March 5, 1998 (incorporated by reference to Exhibit 4.1 to Belco’s Current Report on Form 8-K, filed on March 11, 1998).
4	.4	Third Amended and Restated Shareholders Agreement, dated as of February 14, 2003, among the Company, Equitable Resources, Inc., Medicor Foundation, Westport Energy, LLC and certain stockholders named therein (incorporated by reference to Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, filed on March 10, 2003).
4	.5	Registration Right Agreement, dated as of April 3, 2003, among the Company, subsidiary guarantors party thereto and Lehman Brothers Inc. (incorporated by reference to Exhibit 4.7 to the Company’s registration statement on Form S-4 (File No. 333-105834), filed on June 4, 2003).
4	.6	Third Supplemental Indenture, dated as of April 3, 2003, among the Company, subsidiary guarantors party thereto and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.11 to the Company’s registration statement on Form S-4 (File No. 333-105834), filed on June 4, 2003).
*10	.1	Change in Control Severance Protection Agreement, effective as of June 1, 2003, between the Company and Peter M. Mueller.
*31	.1	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of the Company.
*31	.2	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of the Company.
*32	.1	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of the Company.
*32	.2	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of the Company.


*	Filed herewith

(b) Reports on Form 8-K:


	(i) Current Report on Form 8-K (Item 9), filed on May 7, 2003;

	(ii) Current Report on Form 8-K (Item 5), filed on June 3, 2003; and

	(iii) Current Report on Form 8-K (Item 5), filed on June 10, 2003.

SIGNATURES

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


	WESTPORT RESOURCES CORPORATION


Date: August 14, 2003		By: /s/ DONALD D. WOLF Name: Donald D. Wolf Title: Chairman of the Board and Chief Executive Officer

Date: August 14, 2003		By: /s/ LON MCCAIN Name: Lon McCain Title: Vice President, Chief Financial Officer and Treasurer

EXHIBIT INDEX


No. of
Exhibit			Description

	2	.1	Agreement and Plan of Merger, dated as of March 9, 2000, by and among Westport Oil and Gas Company, Inc., Westport Energy Corporation, Equitable Production Company, Equitable Production (Gulf) Company and EPGC Merger Sub Corporation (incorporated by reference to Exhibit 2.1 to the registration statement on Form S-1 (Registration No. 333-40422), filed on June 29, 2000).
	2	.2	Agreement and Plan of Merger, dated as of June 8, 2001, by and among Belco Oil & Gas Corp. and Westport Resources Corporation (incorporated by reference to Exhibit 2.1 to the registration statement on Form S-4/A (Registration No. 333-64320), filed on July 24, 2001).
	3	.1	Amended Articles of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the registration statement on Form 8-A/A, filed on August 31, 2001).
	3	.2	Certificate of Amendment to Amended Articles of Incorporation of the Company, dated March 5, 2003 (incorporated by reference to Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 30, 2003, filed on May 8, 2003).
	3	.3	Second Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the registration statement on Form 8-A/A, filed on August 31, 2001).
	4	.1	Specimen Certificate for shares of Common Stock of the Company (incorporated by reference to Exhibit 4.1 to the registration statement on Form 8-A/A, filed on August 31, 2001).
	4	.2	Specimen Certificate for shares of 6 1/2% Convertible Preferred Stock of the Company (incorporated by reference to Exhibit 4 to the registration statement on Form 8-A/A, filed on August 31, 2001).
	4	.3	Certificate of Designations of 6 1/2% Convertible Preferred Stock, dated March 5, 1998 (incorporated by reference to Exhibit 4.1 to Belco’s Current Report on Form 8-K, filed on March 11, 1998).
	4	.4	Third Amended and Restated Shareholders Agreement, dated as of February 14, 2003, among the Company, Equitable Resources, Inc., Medicor Foundation, Westport Energy, LLC and certain stockholders named therein (incorporated by reference to Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, filed on March 10, 2003).
	4	.5	Registration Right Agreement, dated as of April 3, 2003, among the Company, subsidiary guarantors party thereto and Lehman Brothers Inc. (incorporated by reference to Exhibit 4.7 to the Company’s registration statement on Form S-4 (File No. 333-105834), filed on June 4, 2003).
	4	.6	Third Supplemental Indenture, dated as of April 3, 2003, among the Company, subsidiary guarantors party thereto and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.11 to the Company’s registration statement on Form S-4 (File No. 333-105834), filed on June 4, 2003).
	*10	.1	Change in Control Severance Protection Agreement, effective as of June 1, 2003, between the Company and Peter M. Mueller.
	*31	.1	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of the Company.
	*31	.2	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of the Company.
	*32	.1	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of the Company.
	*32	.2	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of the Company.


*	Filed herewith.

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