WESTPORT RESOURCES CORP /NV/ - 10-Q Quarterly Report

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 March 31, 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 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

66,958,939 shares of the issuer’s common stock, par value $0.01 per share, were outstanding as of May 1, 2003.

TABLE OF CONTENTS


PART I -- FINANCIAL INFORMATION
	Item 1. Financial Statements
	CONSOLIDATED STATEMENTS OF OPERATIONS
	CONSOLIDATED STATEMENTS 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 3. Defaults Upon Senior Securities
	Item 4. Submission of Matters to a Vote of Security Holders
	Item 5. Other Information
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
CERTIFICATION
INDEX TO EXHIBITS
EX-3.2 Certificate of Amendment to Articles of Inc
EX-99.1 Certification Pursuant to 18 USC Sec. 1350
EX-99.2 Certification Pursuant to 18 USC Sec. 1350

WESTPORT RESOURCES CORPORATION

TABLE OF CONTENTS


		Page

PART I — FINANCIAL INFORMATION			1
Item 1.	Financial Statements		1
	Consolidated Balance Sheets as of March 31, 2003 (unaudited) and December 31, 2002		1
	Consolidated Statements of Operations for the three months ended March 31, 2003 and 2002 (unaudited)		2
	Consolidated Statements of Cash Flows for the three months ended March 31, 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		22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		32
Item 4.	Controls and Procedures		32
PART II — OTHER INFORMATION			32
Item 1.	Legal Proceedings		32
Item 2.	Changes in Securities and Use of Proceeds		33
Item 3.	Defaults Upon Senior Securities		34
Item 4.	Submission of Matters to a Vote of Security Holders		34
Item 5.	Other Information		34
Item 6.	Exhibits and Reports on Form 8-K		34
Signatures			36

PART I — FINANCIAL INFORMATION


Item 1.	*Financial Statements*

WESTPORT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS


				March 31,			December 31,
				2003			2002

				(Unaudited)

				(In thousands, except share
				data)
ASSETS
Current Assets:
	Cash and cash equivalents			$	64,699		$	42,761
	Accounts receivable, net				92,501			73,549
	Derivative assets				10,668			14,861
	Prepaid expenses				14,735			13,358

			Total current assets		182,603			144,529

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties			2,222,349			2,138,471
		Unproved properties			103,312			104,430

					2,325,661			2,242,901
	Less accumulated depletion, depreciation and amortization				(536,795	)		(481,396	)

		Net oil and gas properties			1,788,866			1,761,505

	Field services assets				39,229			39,185
	Less accumulated depreciation				(280	)		—

		Net field services assets			38,949			39,185

	Building and other office furniture and equipment				9,886			9,686
	Less accumulated depreciation				(4,084	)		(3,933	)

		Net building and other office furniture and equipment			5,802			5,753

Other assets:
	Long-term derivative assets				16,326			14,824
	Goodwill				245,944			246,712
	Other assets				20,231			21,033

			Total other assets		282,501			282,569

			Total assets	$	2,298,721		$	2,233,541


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
	Accounts payable			$	51,476		$	51,158
	Accrued expenses				46,642			39,209
	Ad valorem taxes payable				11,308			8,988
	Derivative liabilities				80,902			56,156
	Income taxes payable				86			86
	Current asset retirement obligation				10,072			—

			Total current liabilities		200,486			155,597
Long-term debt					773,154			799,358
Deferred income taxes					119,807			124,530
Long term derivative liabilities					32,500			21,305
Long term asset retirement obligation					50,077			745

			Total liabilities		1,176,024			1,101,535

Stockholders’ equity:
	6 1/2% convertible preferred stock, $.01 par value; 10,000,000 shares authorized; 2,930,000 issued and outstanding at March 31, 2003 and December 31, 2002, respectively				29			29
	Common stock, $0.01 par value; 100,000,000 authorized; 66,943,970 and 66,823,830 shares issued and outstanding at March 31, 2003 and, December 31, 2002, respectively				670			668
	Additional paid-in capital				1,150,483			1,150,345
	Treasury stock-at cost; 35,681 and 33,617 shares at March 31, 2003 and December 31, 2002, respectively				(512	)		(469	)
	Retained earnings				19,252			2
	Accumulated other comprehensive income
		Deferred hedge loss, net			(47,064	)		(18,408	)
		Cumulative translation adjustment			(161	)		(161	)

		Total stockholders’ equity			1,122,697			1,132,006

	Total liabilities and stockholders’ equity			$	2,298,721		$	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
				Ended March 31,

				2003			2002


				(In thousands, except
				per share amounts)
				(Unaudited)
Operating revenues:
	Oil and natural gas sales			$	218,419		$	77,012
	Hedge settlements				(40,446	)		3,935
	Gathering income				1,209			—
	Commodity price risk management activities:
		Non-hedge settlements			—			1,084
		Non-hedge change in fair value of derivatives			2,320			(9,253	)
	Gain on sale of operating assets, net				392			—

			Net revenues		181,894			72,778

Operating costs and expenses:
	Lease operating expenses				26,336			19,675
	Production taxes				13,058			5,865
	Transportation costs				4,024			2,652
	Gathering expenses				1,096			—
	Exploration				12,047			10,342
	Depletion, depreciation and amortization				61,065			47,589
	Impairment of unproved properties				3,480			959
	Stock compensation expense, net				(3	)		1,881
	General and administrative				7,228			5,934

			Total operating expenses		128,331			94,897

			Operating income (loss)		53,563			(22,119	)
Other income (expense):
	Interest expense				(16,342	)		(8,371	)
	Interest income				201			80
	Change in fair value of interest rate swap				—			226
	Other				145			(482	)

Income (loss) before income taxes					37,567			(30,666	)

Benefit (provision) for income taxes:
	Current				—			—
	Deferred				(13,712	)		11,193

			Total benefit (provision) for income taxes		(13,712	)		11,193

	Net income (loss) before cumulative effect of change in accounting principle				23,855			(19,473	)
Cumulative effect of change in accounting principle (net of tax effect of $1,962)					(3,414	)		—

Net income (loss)					20,441			(19,473	)
Preferred stock dividends					(1,191	)		(1,190	)

Net income (loss) available to common stockholders				$	19,250		$	(20,663	)

Weighted average number of common shares outstanding:
	Basic				66,817			52,081

	Diluted				67,631			52,081

Net income (loss) per common share:
Basic:
	Net income (loss) before cumulative effect of change in accounting principle			$	.34		$	(.40	)
	Cumulative effect of change in accounting principle				(.05	)		—

			Net income (loss) available to common stockholders	$	.29		$	(.40	)

Diluted:
	Net income (loss) before cumulative effect of change in accounting principle			$	.34		$	(.40	)
	Cumulative effect of change in accounting principle				(.05	)		—

			Net income (loss) available to common stockholders	$	.29		$	(.40	)

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

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



				For the Three Months
				Ended March 31,

				2003			2002


				(In thousands)
				(Unaudited)
Cash flows from operating activities:
	Net income (loss)			$	20,441		$	(19,473	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Depletion, depreciation and amortization			61,065			47,589
		Exploratory dry hole costs			4,892			4,781
		Impairment of unproved properties			3,480			959
		Deferred income taxes			13,712			(11,193	)
		Stock compensation expense			(3	)		1,881
		Change in fair value of derivatives			981			9,027
		Amortization of derivative liabilities			(3,164	)		(2,668	)
		Amortization of deferred financing fees			282			262
		Gain on sale of operating assets, net			(392	)		—
		Cumulative change in accounting principle, net of tax			3,414			—
		Changes in assets and liabilities, net of effects of acquisitions:
			Decrease (increase) in accounts receivable		(26,403	)		21,705
			Increase in prepaid expenses		(1,002	)		(2,554	)
			Increase (decrease) in accounts payable		325			(13,851	)
			Increase in ad valorem taxes payable		2,998			816
			Decrease in income taxes payable		—			(44	)
			Increase in accrued expenses		14,877			3,928
			Decrease in other liabilities		(217	)		(65	)

Net cash provided by operating activities					95,286			41,100

Cash flows from investing activities:
	Additions to property and equipment				(50,731	)		(37,024	)
	Proceeds from sales of assets				3,563			147
	Acquisitions of oil and gas properties and purchase price adjustments				4,911			(37,981	)
	Other				—			(27	)

Net cash used in investing activities					(42,257	)		(74,885	)

Cash flows from financing activities:
	Proceeds from issuance of common stock				143			393
	Proceeds from issuance of long-term debt				—			45,000
	Repayment of long term debt				(30,000	)		—
	Preferred stock dividends paid				(1,191	)		(1,190	)
	Repurchase of common stock				(43	)		—
	Financing fees				—			(35	)

Net cash provided by (used in) financing activities					(31,091	)		44,168

Net increase in cash and cash equivalents					21,938			10,383
Cash and cash equivalents, beginning of period					42,761			27,584

Cash and cash equivalents, end of period				$	64,699		$	37,967

Supplemental cash flow information:
	Cash paid for interest			$	6,283		$	5,830

	Cash paid for income taxes			$	—		$	44

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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 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 was accounted for as a reverse acquisition in which Old Westport is the purchaser of Belco. Westport began consolidating the results of Belco with its results as of August 21, 2001 closing date. Business activities of the Company include oil and natural gas exploitation, acquisition and exploration activities, primarily in the Rocky Mountains, the Gulf Coast, 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 March 31, 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, 2002 audited financial statements set forth in the Company’s Form 10-K.


3.	Debt

Long-term debt consisted of:


	March 31,			December 31,
	2003			2002


	(In thousands)
8 1/4% Senior Subordinated Notes Due 2011	$	595,834	(1)	$	591,771	(2)
8 7/8% Senior Subordinated Notes due 2007		127,320	(3)		127,587	(3)
Revolving Credit Facility due on December 16, 2006		50,000			80,000

		773,154			799,358
Less current portion		—			—

	$	773,154		$	799,358

(1) The balance of the 8 1/4% Senior Subordinated Notes Due 2011, noted above as of March 31, 2003, reflects an increase of $8.7 million related to the premium recorded in connection with the issuance of the additional 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 $12.2 million related to fair market value adjustments recorded as a result of the Company’s interest rate swaps accounted for as fair value

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

hedges. The face amount of the notes at March 31, 2003 was $575.0 million. See Interest Rate Swaps — Hedges below.

(2) The balance of the 8 1/4% Senior Subordinated Notes Due 2011, noted above 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) The balances of the 8 7/8% Senior Subordinated Notes due 2007, noted above as of March 31, 2003 and December 31, 2002, respectively, reflect increases of $3.3 million and $3.5 million, respectively, 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 notes at March 31, 2003 and December 31, 2002, respectively, was $122.7 million. See Note 9 — Subsequent Events regarding the redemption of the Company’s outstanding 8 7/8% Senior Subordinated Notes due 2007 on May 5, 2003.


	*Revolving Credit Facility*

On December 17, 2002, the Company entered into a new credit facility (the “Revolving Credit Facility”) with JPMorgan Chase Bank, Credit Suisse First Boston Corporation and certain other lenders party thereto to replace the Company’s previous revolving credit facility. The Revolving Credit Facility provides for a maximum committed amount of $600 million and an initial borrowing base of approximately $470 million. The facility matures on December 16, 2006 and contains covenants and default provisions customary for similar credit facilities. The Company made borrowings under the Revolving Credit Facility to refinance all its outstanding indebtedness under the previous revolving credit facility and to pay general corporate expenses.

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:

• the rate of interest announced by JP Morgan Chase Bank, formerly known as The Chase Manhattan 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%:

in each case plus a margin of 0% to 0.625% based upon the ratio of total debt to EBITDAX, as defined in the New Revolving Credit Facility, and the ratings of the Company’s senior unsecured debt as issued by Standard and Poor’s Rating Group and Moody’s Investors Service, Inc.

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 the Company’s senior unsecured debt as issued by Standard and Poor’s Rating Group and Moody’s Investors Service, Inc.

As of March 31, 2003, the Company had borrowings of $50 million at an interest rate of 2.9% and letters of credit of approximately $64.1 million outstanding under the Revolving Credit Facility. Available unused borrowing capacity was approximately $355.9 million. The letters of credit were issued primarily in connection with the margin requirements of the Company’s oil and natural gas derivative contracts. The

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Revolving Credit Facility currently limits the outstanding letters of credit to $200 million. See also Note 9 — Subsequent Events.


	*8 7/8% Senior Subordinated Notes due 2007*

In connection with the Merger, the 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 Company 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 October 29, 2001. Including the premium and accrued interest, the total amount paid 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 the 8 7/8% Senior Subordinated Notes recorded in connection with the Merger equaled the redemption cost. See also Note 9 — Subsequent Events.


	*8 1/4% Senior Subordinated Notes Due 2011*

On December 17, 2002, the Company issued $300 million in additional principal amount of the 8 1/4% Senior Subordinated Notes Due 2011 pursuant to Rule 144A and Regulation S under the Securities Act of 1933 (the “Securities Act”) at a price of 103% of the principal amount, with accrued interest from November 1, 2002. The 2002 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. All of the 2001 and 2002 notes were subsequently exchanged on March 14, 2002 and March 12, 2003, respectively, for equal principal amounts of notes having substantially identical terms and registered under the Securities Act. See also Note 9 — Subsequent Events.

The notes are senior subordinated unsecured obligations of the Company and are guaranteed on a senior subordinated basis by some of its existing and future restricted subsidiaries. The notes mature on November 1, 2011. The Company pays interest on the notes semi-annually on May 1 and November 1. The Company is entitled to redeem the notes in whole or in part on or after November 1, 2006 for the redemption price set forth in the notes. Prior to November 1, 2006, the Company is entitled to redeem the 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 the notes.


	*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.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of March 31, 2003, the Company recorded a derivative asset of $12.2 million related to the interest rate swap designated as a fair value hedge, with a corresponding debt increase.

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 will be amortized over the remaining life of the notes. See also Note 9 — Subsequent Events.


4.	Commodity Derivative Instruments and Hedging Activities

The 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 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.

For the three months ended March 31, 2003 and 2002, the Company reclassified approximately $40.4 million of hedging losses and $3.9 million of hedging gains, respectively, out of accumulated other comprehensive income into oil and gas sales revenues. The hedging losses and gains reclassified to revenues include cash losses of $41.7 million and cash gains of $1.5 million for the three months ended March 31, 2003 and 2002, respectively.

The Company recorded no non-hedge CPRM settlements and a $1.1 million gain for the three months ended March 31, 2003 and 2002, respectively. The Company also recorded unrealized change in fair value of non-hedge derivatives of $2.3 million, which included $0.6 million ineffectiveness loss, and ($9.3) million with no ineffectiveness for the three months ended March 31, 2003 and 2002, respectively. The non-hedge CPRM settlements include cash settlements of ($1.1) million and $0.9 million for the three months ended March 31, 2003 and 2002, respectively.

As of March 31, 2003, the Company had the following CPRM transactions in place covering hedge and non-hedge positions:

• 3.8 Mmbbls of oil and 56.1 Bcf of natural gas subject to CPRM contracts for the remainder of 2003. Of these contracts, all of the oil and 47.9 Bcf of the natural gas contracts are subject to weighted average NYMEX floor prices of $23.12 per barrel and $3.78 per Mmbtu and weighted average NYMEX ceiling prices of $25.16 per barrel and $4.20 per Mmbtu, respectively, excluding the effect, if any, of the three-way floor price. Of the remaining 2003 gas CPRM contract settlements 5.5 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 2.8 Bcf are calculated based on the Colorado Interstate Gas Rocky Mountain Index (“CIGRM”) at a weighted average swap price of $3.59. In addition, included in the 47.9 Bcf of natural gas contracts are basis swaps covering 10.1 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, 2.8 Bcf of natural gas for 2003 that lock in the pricing differential between NYMEX and CIGRM at a weighted average price differential of $0.95 per Mmbtu and 6.4 Bcf for

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2003 that lock in the pricing differential between CIGRM and NWPRM at a weighted average price differential of $0.43 per Mmbtu.

• 2.2 Mmbbls of oil and 49.3 Bcf of natural gas subject to CPRM contracts for 2004. Of these contracts, all of the oil and 38.3 Bcf of the natural gas contracts are subject to weighted average floor prices of $23.93 per barrel and $3.83 per Mmbtu and weighted average NYMEX ceiling prices of $25.47 per barrel and $4.06 per Mmbtu, respectively, excluding the effect, if any, of the three-way floor price. The remaining 2004 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 38.3 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 CIGRM at a weighted average price differential of $0.81.

• 9.1 Bcf of natural gas subject to CPRM contracts for 2005 with a weighted average NYMEX swap price of $3.96 per Mmbtu.

The tables below provide details about the volumes and prices of all open CPRM hedge and non-hedge commitments as of March 31, 2003:


					2003		2004		2005

Hedges
	Gas
		NYMEX Price Swaps Sold — receive fixed price (thousand Mmbtu)(1)				24,250		18,300		9,125
			Average price, per Mmbtu		$	4.01	$	3.92	$	3.96
		NWPRM Price Swaps Sold — receive fixed price (thousand Mmbtu)(2)				—		10,980		—
			Average price, per Mmbtu		$	—	$	3.33	$	—
		CIGRM Price Swaps Sold — receive fixed price, per Mmbtu(3)				2,750		—		—
			Average price, per Mmbtu		$	3.59	$	—	$	—
		NYMEX Collars Sold (thousand Mmbtu)(4)				17,578		16,380		—
			Average floor price, per Mmbtu		$	3.61	$	3.70	$	—
			Average ceiling price, per Mmbtu		$	4.29	$	4.00	$	—
		NWPRM Collars Sold (thousand Mmbtu)(5)				5,500		—		—
			Average floor price, per Mmbtu		$	3.00	$	—	$	—
			Average ceiling price, per Mmbtu		$	3.29	$	—	$	—
		NYMEX Three-way Collars (thousand Mmbtu)(4),(6)				6,050		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)			10,100		3,660		—
				Average differential price, per Mmbtu	$	0.67	$	0.66	$	—
			CIGRM (thousand Mmbtu)			2,750		1,830		—
				Average differential price, per Mmbtu	$	0.95	$	0.81	$	—

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


					2003		2004		2005

	Oil
		NYMEX Price Swaps Sold — receive fixed price (Mbbls)(1)				545		1,098		—
			Average price, per bbl		$	21.09	$	24.02	$	—
		NYMEX Collars Sold (Mbbls)(4)				1,485		—		—
			Average floor price, per bbl		$	24.45	$	—	$	—
			Average ceiling price, per bbl		$	26.45	$	—	$	—
		NYMEX Three-way Collars (Mbbls) (4)(6)				1,500		1,098		—
			Average floor price, per bbl		$	23.18	$	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 CIGRM (thousand Mmbtu)			6,420		—		—
				Average differential price, per Mmbtu	$	0.43	$	—	$	—
	Oil
		NYMEX Price Swaps Sold, receive fixed price (Mbbls)(1)				225		—		—
			Average price, per bbl		$	18.86	$	—	$	—

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

(3) For any particular CIGRM swap sold transaction, the counterparty is required to make a payment to Westport in the event that the CIGRM 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 CIGRM 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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 $22.28 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 CIGRM) 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 CIGRM) for any settlement period is less than the swap differential price for such hedge.

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

5. Earnings Per Share and Other Comprehensive Income (Loss)


	*Earning per Share*

Basic 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.

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.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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



			For the Three Months
			Ended March 31,

			2003			2002


			(In thousands, except
			per share amount)
Net income (loss) per share:
	Net income (loss) before cumulative effect of change in accounting principle		$	23,855		$	(19,473	)
	Cumulative change in accounting principle			(3,414	)		—

	Net income (loss)			20,441			(19,473	)
	Preferred stock dividends			(1,191	)		(1,190	)

	Net income (loss) available to common stockholders		$	19,250		$	(20,663	)

	Weighted average common shares outstanding			66,817			52,081
		Add dilutive effects of employee stock options		814			—

	Weighted average common shares outstanding including the effects of dilutive securities			67,631			52,081

	Basic earnings (loss) per share before cumulative effect of change in accounting principle		$	.34		$	(.40	)

	Basic earnings (loss) per share		$	.29		$	(.40	)

	Diluted earnings (loss) per share before cumulative effect of change in accounting principle		$	.34		$	(.40	)

	Diluted earnings (loss) per share		$	.29		$	(.40	)


	*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 three months ended March 31, 2003 and 2002 are as follows (in thousands):



		Three Months Ended
		March 31,

		2003			2002

Net income (loss) available to common stockholders		$	19,250		$	(20,663	)
Other comprehensive income
	Change in fair value of derivative hedging instruments		(54,339	)		(7,477	)
	Enron non-cash settlements reclassified to income		(452	)		(371	)
	Hedge settlements reclassified to income		26,135			(2,128	)

Comprehensive loss		$	(9,406	)	$	(30,639	)

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


6.	Stock Compensation

The Company has elected to continue following 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:



		For the Three Months
		Ended March 31,

		2003		2002


		(In thousands, except
		per share amount)
Net income (loss) available to common stockholders
	As reported	$	19,250	$	(20,663	)
	Pro forma		16,150		(22,444	)
Basic net income (loss) per common share
	As reported	$	.29	$	(.40	)
	Pro forma		.24		(.43	)
Diluted net income (loss) per common share
	As reported	$	.29	$	(.40	)
	Pro forma		.24		(.43	)


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. The following is a description of the changes to the Company’s asset retirement obligations from January 1 to March 31 of 2003:


	2003

	(In thousands)
Asset retirement obligation — January 1	$	58,735
Accretion		1,082
Additions		—
Settlements		(409	)

Asset retirement obligation — March 31		59,408
Less: Current asset retirement obligation		(10,072	)

Long-term asset retirement obligation	$	49,336

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company’s current and long-term asset retirement obligations are included in current asset retirement liabilities and long-term asset retirement liabilities, respectively, on the accompanying March 31, 2003 consolidated balance sheet.

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 Months
	Ended March 31,

	2003		2002


	(In thousands, except
	per share amount)
Net income available to common stockholders	$	22,664	$	(21,780	)
Earnings per share — basic	$	.34	$	(.42	)
— diluted	$	.34	$	(.42	)

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 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. The adoption of the provisions of SFAS No. 145 did not affect the Company’s financial position or results of operations in the first quarter of 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, Statement 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 interpretation of FASB Statements Nos. 5, 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,

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 an effect on the Company’s financial position or results of operations.

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 the Interpretation 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.


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


								Gulf of			Corporate &
	Northern		Western		Southern			Mexico			Unallocated			Consolidated


	(In thousands)

	(Unaudited)
2003
Revenues(1)	$	46,930	$	27,049	$	83,254		$	62,787		$	(38,126	)	$	181,894
DD&A		10,729		5,447		21,545			23,193			151			61,065
Profit (loss)		19,667		11,281		40,633			20,255			(38,273	)		53,563
Expenditures for assets, net		6,504		5,342		7,989			25,785			200			45,820
2002
Revenues(1)	$	25,303	$	—	$	29,838		$	21,871		$	(4,234	)	$	72,778
DD&A		11,071		—		19,773			16,637			108			47,589
Profit (loss)		1,132		—		(6,401	)		(10,627	)		(6,223	)		(22,119	)
Expenditures for assets, net		47,194		—		9,005			18,441			365			75,005

(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)


9.	Subsequent Events

On April 3, 2003 the Company issued $125 million in additional principal amount of its 8 1/4% Senior Subordinated Notes Due 2011 pursuant to Rule 144A and Regulation S under the Securities Act at a price of 106% of the principal amount, with accrued interest from November 1, 2002. Interest on these notes is paid semiannually on May 1 and November 1. The Company’s first interest payment on these notes was May 1, 2003. The Company has agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement pursuant to a registration rights agreement relating to these notes. In the event the Company fails to comply with some of its obligations under the registration rights agreement relating to such notes, the Company will pay additional interest on these notes. These notes are jointly and severely guaranteed, on a senior subordinated unsecured basis, by some of our existing and future subsidiaries.

On May 5, 2003, the Company redeemed all of its outstanding 8 7/8% Senior Subordinated Notes due 2007 in the aggregate principal amount of approximately $123 million at a total redemption price of approximately $129.6 million. The redemption was funded with the net proceeds from the sale of the $125 million of the Company’s 8 1/4% Senior Subordinated Notes Due 2011, issued on April 3, 2003. The remaining proceeds were used to reduce the Company’s indebtedness under the Revolving Credit Facility.


10.	Condensed Consolidated Financial Statements of Subsidiary Guarantors

On November 5, 2001 the Company issued $275 million of its 8 1/4% Senior Subordinated Notes Due 2011. On December 17, 2002, the Company issued an additional $300 million of its 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 (not reflecting transactions described in Note 9 — Subsequent Events).

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

March 31, 2003


				Parent			Subsidiary
				Company			Guarantors			Eliminations			Consolidated


				(In thousands)
ASSETS
Current Assets:
	Cash and cash equivalents			$	11,974		$	52,725		$	—		$	64,699
	Accounts receivable, net				29,067			63,434			—			92,501
	Intercompany receivable				1,402,871			—			(1,402,871	)		—
	Derivative assets				10,668			—			—			10,668
	Prepaid expenses				4,689			10,046			—			14,735

			Total current assets		1,459,269			126,205			(1,402,871	)		182,603

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties			365,541			1,856,808			—			2,222,349
		Unproved properties			27,811			75,501			—			103,312
	Field services assets				—			39,229			—			39,229
	Building and other office furniture and equipment				620			9,266			—			9,886

					393,972			1,980,804			—			2,374,776
	Less accumulated depletion, depreciation and amortization				(144,747	)		(396,412	)		—			(541,159	)

			Net property and equipment		249,225			1,584,392			—			1,833,617

Other assets:
	Long-term derivative assets				16,326			—			—			16,326
	Goodwill				—			245,944			—			245,944
	Other assets				20,231			—			—			20,231

			Total other assets		36,557			245,944			—			282,501

			Total assets	$	1,745,051		$	1,956,541		$	(1,402,871	)	$	2,298,721


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable			$	15,758		$	35,718		$	—		$	51,476
	Accrued expenses				24,391			22,251			—			46,642
	Ad valorem taxes payable				(1	)		11,309			—			11,308
	Intercompany payable				—			1,402,871			(1,402,871	)		—
	Derivative liabilities				80,902			—			—			80,902
	Income taxes payable				—			86			—			86
	Other current liabilities				3,901			6,171			—			10,072

			Total current liabilities		124,951			1,478,406			(1,402,871	)		200,486
Long-term debt					773,154			—			—			773,154
Deferred income taxes					(45,004	)		164,811			—			119,807
Long-term derivative liabilities					32,500			—			—			32,500
Other liabilities					15,339			34,738			—			50,077

			Total liabilities		900,940			1,677,955			(1,402,871	)		1,176,024

Stockholders’ equity:
	Preferred stock				29			—			—			29
	Common stock				670			3			(3	)		670
	Additional paid-in capital				951,326			199,154			3			1,150,483
	Treasury stock				(512	)		—			—			(512	)
	Retained earnings				(60,338	)		79,590			—			19,252
	Accumulated other comprehensive income				(47,064	)		(161	)		—			(47,225	)

			Total stockholders’ equity		844,111			278,586			—			1,122,697

			Total liabilities and stockholders’ equity	$	1,745,051		$	1,956,541		$	(1,402,871	)	$	2,298,721

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Three Months Ended March 31, 2003


			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


			(In thousands)
Operating revenues:
	Oil and natural gas sales		$	45,428		$	172,991		$	—	$	218,419
	Hedge settlements			(40,446	)		—			—		(40,446	)
	Gathering and marketing income			—			1,209			—		1,209
	Non-hedge settlements			—			—			—		—
	Non-hedge change in fair value of derivatives			2,320			—			—		2,320
	Loss on sale of operating assets, net			—			392			—		392

		Net revenues		7,302			174,592			—		181,894

Operating costs and expenses:
	Lease operating expense			3,219			23,117			—		26,336
	Production taxes			1			13,057			—		13,058
	Transportation costs			81			3,943			—		4,024
	Gathering and marketing expense			—			1,096			—		1,096
	Exploration			9,883			2,164			—		12,047
	Depletion, depreciation and amortization			18,191			42,874			—		61,065
	Impairment of unproved properties			2,091			1,389			—		3,480
	Stock compensation expense			(3	)		—			—		(3	)
	General and administrative			1,951			5,277			—		7,228

Total operating expenses				35,414			92,917			—		128,331

		Operating income (loss)		(28,112	)		81,675			—		53,563
Other income (expense):
	Interest expense			(16,342	)		—			—		(16,342	)
	Interest income			73			128			—		201
	Other			36			109			—		145

Income (loss) before income taxes				(44,345	)		81,912			—		37,567
Provision for income taxes:
	Deferred			16,186			(29,898	)		—		(13,712	)

		Total provision for income taxes		16,186			(29,898	)		—		(13,712	)
Net income before cumulative change in accounting principle				(28,159	)		52,014			—		23,855

Preferred stock dividends				1,191			—			—		1,191
Cumulative effect of change in accounting principle				1,765			(5,179	)		—		(3,414	)

Net income available to common stockholders			$	(27,585	)	$	46,835		$	—	$	19,250

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Three Months Ended March 31, 2003


					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)
Cash flows from operating activities:
	Net income				$	(28,159	)	$	52,014		$	—		$	23,855
	Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
		Depletion, depreciation and amortization				18,191			42,874			—			61,065
		Exploration dry hole costs				3,462			1,430			—			4,892
		Impairment of unproved properties				2,091			1,389			—			3,480
		Deferred income taxes				(16,186	)		29,898			—			13,712
		Stock compensation expense				(3	)		—			—			(3	)
		Change in fair value of derivatives				981			—			—			981
		Amortization of derivative liabilities				(3,164	)		—			—			(3,164	)
		Amortization of deferred financing fees				282			—			—			282
		Loss on sale of operating assets, net				—			(392	)		—			(392	)
		Changes in asset and liabilities, net of effects of acquisitions:
			Decrease (increase) in accounts receivable			(1,186	)		(25,217	)		—			(26,403	)
			Decrease in prepaid expenses			3,233			(4,235	)		—			(1,002	)
			Decrease in accounts payable			457			(132	)		—			325
			Increase in ad valorem taxes payable			—			2,998			—			2,998
			Increase in accrued expenses			11,989			2,888			—			14,877
			Decrease in other liabilities			—			(217	)		—			(217	)

				Net cash provided by (used in) operating activities		(8,012	)		103,298			—			95,286

Cash flows from investing activities:
	Additions to property and equipment					(24,026	)		(26,705	)		—			(50,731	)
	Proceeds from sales of assets					—			3,563			—			3,563
	Increase in intercompany receivable					—			(72,522	)		72,522			—
	Acquisitions of oil and gas properties					—			4,911			—			4,911
	Other					—			—			—			—

				Net cash provided by (used in) investing activities		(24,026	)		(90,753	)		72,522			(42,257	)

Cash flows from financing activities:
	Proceeds from issuance of common stock					143			—			—			143
	Repurchase of common stock					(43	)		—			—			(43	)
	Proceeds from issuance of long-term debt					—			—			—			—
	Repayment of long term debt					(30,000	)		—			—			(30,000	)
	Preferred stock dividends paid					(1,191	)		—			—			(1,191	)
	Increase in intercompany payable					72,522			—			(72,522	)		—

				Net cash provided by (used in) financing activities		41,431			—			(72,522	)		(31,091	)

Net increase (decrease) in cash and cash equivalents						9,393			12,545			—			21,938
Cash and cash equivalents, beginning of period						2,581			40,180			—			42,761

Cash and cash equivalents, end of period					$	11,974		$	52,725		$	—		$	64,699

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

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

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Three Months Ended March 31, 2002


			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


			(In thousands)
Operating revenues:
	Oil and natural gas sales		$	10,577		$	66,435		$	—	$	77,012
	Hedge settlements			3,935			—			—		3,935
	Non-hedge settlements			1,084			—			—		1,084
	Non-hedge change in fair value of derivatives			(9,253	)		—			—		(9,253	)

		Net revenues		6,343			66,435			—		72,778

Operating costs and expenses:
	Lease operating expense			2,301			17,374			—		19,675
	Production taxes			2			5,863			—		5,865
	Transportation costs			(28	)		2,680			—		2,652
	Exploration			5,143			5,199			—		10,342
	Depletion, depreciation and amortization			8,671			38,918			—		47,589
	Impairment of unproved properties			—			959			—		959
	Stock compensation expense			1,881			—			—		1,881
	General and administrative			1,586			4,348			—		5,934

		Total operating expenses		19,556			75,341			—		94,897

		Operating income		(13,213	)		(8,906	)		—		(22,119	)

Other income (expense):
	Interest expense			(8,144	)		(227	)		—		(8,371	)
	Interest income			35			45			—		80
	Change in fair value of interest rate swap			—			226			—		226
	Other			(769	)		287			—		(482	)

Income before income taxes				(22,091	)		(8,575	)		—		(30,666	)

Provision for income taxes:
	Current			—			—			—		—
	Deferred			8,063			3,130			—		11,193

Total provision for income taxes				8,063			3,130			—		11,193

Net income				(14,028	)		(5,445	)		—		(19,473	)

Preferred stock dividends				1,190			—			—		1,190

Net loss available to common stock			$	(15,218	)	$	(5,445	)	$	—	$	(20,663	)

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Three Months Ended March 31, 2002


					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)
Cash flows from operating activities:
	Net income				$	(14,028	)	$	(5,445	)	$	—		$	(19,473	)
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depletion, depreciation and amortization				8,670			38,919			—			47,589
		Exploration dry hole costs				14			4,767			—			4,781
		Impairment of unproved properties				—			959			—			959
		Deferred income taxes				(8,063	)		(3,130	)		—			(11,193	)
		Stock compensation expense				1,881			—			—			1,881
		Change in fair value of derivatives				9,027			—			—			9,027
		Amortization of derivative liabilities				(2,668	)		—			—			2,668
		Amortization of financing fees				262			—			—			262
		Changes in asset and liabilities, net of effects of Acquisitions:
			Decrease in accounts receivable			5,783			15,922			—			21,705
			Decrease (increase) in prepaid expenses			237			(2,791	)		—			(2,554	)
			Decrease in accounts payable			(7,856	)		(5,995	)		—			(13,851	)
			Increase in ad valorem taxes payable			47			769			—			816
			Increase in income taxes payable			—			(44	)		—			(44	)
			Increase (decrease) in accrued expenses			3,264			664			—			3,928
			Decrease in other liabilities			—			(65	)		—			(65	)

				Net cash provided by operating activities		(3,430	)		44,530			—			41,100

Cash flows from investing activities:
	Additions to property and equipment					(10,298	)		(26,726	)		—			(37,024	)
	Proceeds from sale of assets					—			147			—			147
	Increase in intercompany receivable					(33,545	)		—			33,545			—
	Acquisitions of oil and gas properties					—			(37,981	)		—			(37,981	)
	Other					—			(27	)		—			(27	)

				Net cash used in investing activities		(43,843	)		(64,587	)		33,545			(74,885	)

Cash flows from financing activities:
	Proceeds from issuance of common stock					393			—			—			393
	Proceeds from long-term debt					45,000			—			—			45,000
	Preferred stock dividend					(1,190	)		—			—			(1,190	)
	Financing fees					(35	)		—			—			(35	)
	Increase in intercompany payable					—			33,545			(33,545	)		—

				Net cash provided by (used in) financing activities		44,168			33,545			(33,545	)		44,168

Net increase in cash and cash equivalents						(3,105	)		13,488			—			10,383
Cash and cash equivalents, beginning of period						13,804			13,780			—			27,584

Cash and cash equivalents, end of period					$	10,699		$	27,268		$	—		$	37,967


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

General

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.

Critical Accounting Policies and Estimates

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:

• 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. 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 GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

• 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.

Our proved reserve information included in this report is based on estimates prepared by Ryder Scott Company L.P. and our engineering staff. 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 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 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.

• Impairment of 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.

• 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.

Overview

We are an independent energy company engaged in 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); Western (Uinta Basin); 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 results of operations are significantly impacted by the prices of oil and natural gas, which are volatile. The prices we receive for our oil vary from NYMEX prices based on the location and quality of the crude oil. The prices we receive for our natural gas are based on Henry Hub prices reduced by transportation expenses, regional basis differentials and processing fees.

Oil and natural gas production costs are composed of lease operating expense, production taxes and transportation costs. Lease operating expense consists of pumpers’ salaries, utilities, maintenance, workovers 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.

Exploration expense consists of geological and 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 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.

We assess our proved properties on a field-by-field basis for impairment, in accordance with the provisions of 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 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 require any impairment. 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 non-cash charges resulting from the application of the provisions of FASB Interpretation No. 44 (“FIN 44”) to certain stock options granted to employees and issuance of restricted stock to certain employees. Under FIN 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.

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, Houston and other offices. While we expect such costs to increase with our growth, we expect such increases to be proportionately smaller than our production growth.

Basis of Presentation

On August 21, 2001, the stockholders of Belco approved an agreement and plan of merger, dated as of June 8, 2001, between Belco and Old Westport. Pursuant to this agreement, Old Westport was merged with and into Belco, with Belco surviving and changing its name to Westport Resources Corporation. The merger was accounted for as a purchase transaction for financial accounting purposes with Westport as the surviving accounting entity. Westport began consolidating the results of Belco with its results as of August 21, 2001 closing date.

On March 1, 2002 we purchased producing oil and gas properties located in the Williston Basin in North Dakota and Montana for approximately $39 million. We operate over 70% of these properties. Operations from the properties were included in our results starting on March 1, 2002.

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.

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 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.

Results of Operations

The following table sets forth certain operational data for the periods presented:

Summary Data



		For the Three Months
		Ended March 31,

		2003			2002


		(In thousands)
Production
	Oil (Mbbls)		2,046			1,805
	Natural gas (Mmcf)		27,319			20,078
	Mmcfe		39,595			30,907
Average Daily Production
	Oil (Mbbls/d)		22.7			20.1
	Natural gas (Mmcf/d)		303.5			223.1
	Mmcfe/d		439.9			343.4
Average Prices
	Oil (per bbl)	$	31.63		$	18.32
	Natural gas (per Mcf)		5.63			2.19
Hedging effect (per bbl)			(5.03	)		0.97
Hedging effect (per Mcf)			(1.11	)		0.11
Hedging effect (per Mcfe)			(1.02	)		0.13
Oil and natural gas sales		$	218,419		$	77,012
Lease operating expense			26,336			19,675
	Per Mcfe		0.67			0.64
General and administrative costs			7,228			5,934
	Per Mcfe		0.18			0.19
Depletion, depreciation and amortization			61,065			47,589
	Per Mcfe		1.54			1.54

The discussion below includes a comparison of our results of operations for the three months ended March 31, 2003 and 2002.

Revenues. Oil and natural gas revenues for the three months ended March 31, 2003 increased by $141.4 million, or 184%, from $77.0 million to $218.4 million, compared to the three months ended March 31, 2002. Production from the acquired El Paso, Southeast Texas and Williston Basin properties accounted for $50.5 million of the increase. The majority of the remaining increase in oil and natural gas revenues was due to increases of 73% and 157%, respectively, in realized oil and natural gas prices, excluding the effects of hedging. Production volumes increased by 8.7 Bcfe, or 28%, from 30.9 Bcfe for the three months ended March 31, 2002 to 39.6 Bcfe for the three months ended March 31, 2003. Acquired El Paso, Southeast Texas and Williston Basin properties accounted for 9.4 Bcfe of the increase. Production volumes also increased due to drilling activity since March 31, 2002, which were offset by oil and natural gas production declines. Hedging transactions decreased oil and natural gas revenues by $40.4 million, or $1.02 per Mcfe, for the three months ended March 31, 2003, and increased oil and natural gas revenues by $3.9 million, or $0.13 per Mcfe, for the three months ended March 31, 2002.

Commodity Price Risk Management Activities. The Company recorded a gain of $2.3 million in the non-hedge change in fair value of derivatives for the three months ended March 31, 2003, compared to a $9.3 million loss for the three months ended March 31, 2002. There were no non-hedge settlements of

derivatives recorded for the three months ended March 31, 2003 as compared to a gain of $1.1 million for the three months ended March 31, 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.

Gain (Loss) on Sale of Operating Assets, Net. For the three months ended March 31, 2003, we recorded a net gain of $0.4 million on sales of non-core onshore operating assets. For the three months ended March 31, 2002 there were no dispositions of operating assets.

Gathering Income/ Expense. 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 March 31, 2003, we reported $502,000 of gathering income and $416,000 of gathering expense, or a margin of $86,000. The gathering income reflected in the consolidated statement of operations relates only to third-party natural gas flowing through our system. Intercompany sales of $1.4 million have been eliminated in our consolidated financial statements. In addition, for the quarter ended March 31, 2003, gathering income and expense includes marketing revenue of $707,000 and marketing expense of $680,000, or a margin of $27,000. We do not expect to continue to engage in these marketing activities after March 31, 2003.

Lease Operating Expense. Lease operating expense for the three months ended March 31, 2003 increased by $6.6 million, or 34%, from $19.7 million to $26.3 million, compared to the three months ended March 31, 2002. Lease operating expenses from the acquired El Paso, Southeast Texas and Williston Basin properties accounted for $6.4 million of the increase. On a per Mcfe basis, lease operating expense increased from $0.64 to $0.67 in the 2002 and 2003 periods, respectively. The increase on a per Mcfe basis was primarily due to a $0.03 per Mcfe increase in workovers performed in the Northern and Western Divisions, compared to workovers performed in the Northern Division in 2002.

Production Taxes. Production taxes for the three months ended March 31, 2003 increased by $7.2 million, or 123%, from $5.9 million to $13.1 million, compared to the three months ended March 31, 2002. Production taxes from the acquired El Paso, Southeast Texas and Williston Basin properties accounted for $4.3 million of the increase. The remaining increase was primarily due to the increase in oil and natural gas prices. On a per Mcfe basis, production taxes increased from $0.19 to $0.33 in the 2002 and 2003 periods, 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, Southeast Texas and Williston Basin properties.

Transportation Costs. Transportation costs for the three months ended March 31, 2003 increased by $1.4 million, or 52%, from $2.6 million to $4.0 million, compared to the three months ended March 31, 2002. The acquired El Paso properties accounted for an increase of $1.5 million, which was partially offset by a reduction in other areas.

Exploration Costs. Exploration costs for the three months ended March 31, 2003 increased by $1.7 million, or 16%, from $10.3 million to $12.0 million, compared to the three months ended March 31, 2002.



	Three Months Ended
	March 31,

	2003		2002


	(In thousands)
Geological and geophysical costs	$	6,613	$	5,047
Unsuccessful property acquisitions		—		94
Delay rentals		543		420
Exploratory dry holes costs		4,892		4,781

	$	12,047	$	10,342

The majority of the geological and geophysical costs pertain to the purchase of 3-D seismic data for the Gulf of Mexico for both the three months ended March 31, 2003 and 2002. Dry hole costs for the three months ended March 31, 2003 resulted from four unsuccessful exploratory wells, two in Texas, one in

Wyoming and one in the Gulf of Mexico. Dry hole costs for the three months ended March 31, 2002 resulted from two unsuccessful exploratory wells, one in the Gulf of Mexico and one in Wyoming.

Depletion, Depreciation and Amortization (DD&A) Expense. DD&A expense increased $13.5 million for the three months ended March 31, 2003, from $47.6 million to $61.1 million, compared to the three months ended March 31, 2002. Depletion related to the acquired El Paso, Southeast Texas and Williston Basin properties caused DD&A expense to increase $11.6 million. On a per Mcfe basis, DD&A expense remained constant at a $1.54 for the three months ended March 31, 2003 and 2002, respectively.

Impairment of Unproved Properties. During the three months ended March 31, 2003, we recognized unproved property impairments of $3.5 million. The impairments consisted of $1.4 million for expired onshore leases and $2.1 million for offshore leases as a result of an assessment of the lack of exploration opportunities existing on such properties. During the three months ended March 31, 2002, we recognized unproved property impairments of $1.0 million for offshore leases.

Stock Compensation Expense. During the three months ended March 31, 2003, we reduced stock compensation expense by $3,000. Restricted stock expense was reduced by $22,000 as a result of expenses recognized in prior periods offset by $19,000 of stock compensation expense related to certain stock options as a result of applying FIN 44. During the three months ended March 31, 2002, we recognized $1.8 million of stock compensation expense related to certain stock options as a result of applying FIN 44 and recorded $0.1 million in expense related to the issuance of restricted stock.

General and Administrative (G&A) Expense. G&A expense increased $1.3 million, or 22%, for the three months ended March 31, 2003, from $5.9 million to $7.2 million, compared to the three months ended March 31, 2002. The majority of the increase was due to additional staff required for the El Paso Acquisition causing an increase in payroll costs such as salaries and benefits. G&A expense per Mcfe of production decreased to $0.18 in the first quarter of 2003 from $0.19 for the first quarter of 2002.

Other Income (Expense). Other income (expense) for the three months ended March 31, 2003 was ($16.0) million compared to ($8.5) million for the three months ended March 31, 2002. Interest expense increased $8.0 million for the three months ended March 31, 2003, compared to the three months ended March 31, 2002, as a result of the increase in the debt balances relating to the El Paso and Southeast Texas acquisitions.

Income Taxes. We recorded a deferred income tax expense of $13.7 million for the three months ended March 31, 2003 and a deferred income tax benefit of $11.2 million due to a net loss for the three months ended March 31, 2002.

Net Income. Net income for the three months ended March 31, 2003 was $23.9 million compared to net loss of $19.5 million for the three months ended March 31, 2002. The variance was primarily attributable to increases in net revenues of $109.1 million, which were offset by increases in income tax expense of $24.9 million, $33.4 million in operating expenses and other expense of $7.4 million.

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.

Liquidity and Capital Resources

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

Net cash provided by operating activities was $95.3 million for the three months ended March 31, 2003, compared to $41.1 million for the three months ended March 31, 2002. Operating cash flow in the three month period increased compared to the prior period due to increased oil and natural gas prices and production.

Net cash used in investing activities was $42.3 million for the three months ended March 31, 2003, compared to $74.9 million for the three months ended March 31, 2002. Of this total for the three months ended March 31, 2003, $50.7 million was used for exploitation and exploration activities offset by $4.9 million in acquisition purchase price adjustments and proceeds from sales of properties of $3.5 million. Investing activities for the three months ended March 31, 2002 included $37.0 million for exploitation and exploration activities and $38.0 million for acquisitions, offset by proceeds from sales of properties of $0.1 million.

Net cash used in financing activities was $31.1 million for the three months ended March 31, 2003, compared to ($44.2) million for the three months ended March 31, 2002. Financing activities for the three months ended March 31, 2003 consisted of $30.0 million in repayment of long-term debt and a $1.2 million preferred stock dividend payment offset by $0.1 million from issuance of common stock. Financing activities for the three months ended March 31, 2002 consisted of $45.0 million in borrowings utilized for the acquisition and development of oil and natural gas properties and $0.4 million from issuance of common stock offset by a $1.2 million preferred stock dividend payment.

Financing Activity


	*Revolving Credit Facility*

On December 17, 2002, we entered into a new credit facility (the “Revolving Credit Facility”) with JP Morgan Chase Bank, Credit Suisse First Boston Corporation and certain other lenders party thereto to replace our previous revolving credit facility. The Revolving Credit Facility provides for a maximum committed amount of $600 million and an initial borrowing base of approximately $470 million. The facility matures of December 16, 2006 and contains covenants and default provisions customary for similar credit facilities. We made borrowing under the Revolving Credit Facility to refinance our outstanding indebtedness under our previous revolving credit facility and to pay general corporate expenses.

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 fluctuating rate based upon the highest of:

in each case plus a margin of 0% to 0.625% based upon the ratio of total debt to EBITDAX, as defined in the Revolving Credit Facility, and the ratings of the Company’s senior unsecured debt as issued by Standard and Poor’s Rating Group and Moody’s Investors Service, Inc.


	*8 7/8% Senior Subordinated Notes due 2007*

In connection with the Merger, we assumed $147 million face amount of Belco’s 8 7/8% Senior Subordinated Notes due 2007. On November 1, 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 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 at a total redemption price of approximately $129.6 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 (see below). The remaining proceeds were used to reduce our indebtedness under the Revolving Credit Facility.


	*8 1/4% Senior Subordinated Notes Due 2011*

On December 17, 2002, we issued $300 million in additional principal amount of our 8 1/4% Senior Subordinated Notes Due 2011 pursuant to Rule 144A and Regulation S under the Securities Act at a price of 103% of the principal amount, with accrued interest from November 1, 2002. The 2002 notes were issued as additional debt securities under an indenture pursuant to which, on November 5, 2001, we issued $275 million of our 8 1/4% Senior Subordinated Notes Due 2011. All of the 2001 and 2002 notes were subsequently exchanged on March 14, 2002 and March 12, 2003, respectively, for equal principal amounts of notes having substantially identical terms and registered under the Securities Act. On April 3, 2003, we issued an additional $125 million of our Senior Subordinated Notes Due 2011 under the same indenture pursuant to Rule 144A and Regulation S under the Securities Act at a price of 106% of the principal amount, with accrued interest from November 1, 2002. All of our 8 1/4% Senior Subordinated Notes Due 2011 constitute a single class of debt securities under the indenture relating to these notes. These notes are senior subordinated unsecured obligations of Westport and are jointly and severally guaranteed, on a 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. Our first interest payment on the 2003 notes was May 1, 2003. We used the proceeds from the sale of the 2003 notes to redeem all of our outstanding 8 7/8% Senior Subordinated Notes due 2007 (described above) 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. In the event we fail to comply with some of our obligations under the registration rights agreement relating to such notes, we will pay additional interest on the 2003 notes. The 2003 notes are eligible for trading in The Portal^SM Market, a subsidiary of The Nasdaq Stock Market, Inc.


	*Capital Expenditures*

We anticipate that our capital expenditures for 2003 will be approximately $230 million. We anticipate that our primary cash requirements for 2003 will include funding development projects, exploration and general working capital needs. For the first three months of 2003, we had capital expenditures of $45.8 million excluding geological and geophysical costs incurred of $6.1 million.

We will continue to seek opportunities for acquisitions of proved reserves with substantial exploitation and exploration potential. The size and timing of capital requirements for acquisitions is inherently unpredictable and we therefore do not budget for them. We expect to fund our capital expenditure activities, which include acquisition, development of and exploration on our oil and natural gas properties, through cash flow from operations and available capacity under the Revolving Credit Facility.

We believe that borrowings under the Revolving Credit Facility, projected operating cash flows and cash on hand will be sufficient to meet the requirements of our business. However, future cash flows are subject to a number of variables including the level of production and oil and natural gas prices. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. Actual levels of capital expenditures may vary significantly due to a variety of factors, including but not limited to:

• drilling results;

• product prices;

• industry conditions and outlook; and

• future acquisition of properties.

Special Note Regarding Forward-Looking Statements

Our disclosure and analysis in this report, including information incorporated by reference, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. Forward-looking statements give our current expectations and projections relating to the financial condition, results of operations, plans, objectives, future performance and business of Westport and its subsidiaries. You can identify these statements by the fact that they do not 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 terms of similar meaning in connection with any discussion of the timing or nature of future operating 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 future are forward-looking statements and include, among other things, statements relating to:

• amount, nature and timing of capital expenditures;

• projected drilling of wells;

• reserve estimates;

• timing and amount of future production of oil and natural gas;

• operating costs and other expenses;

• cash flow, anticipated liquidity and prospects for growth;

• estimates of proved reserves and exploitation and exploration opportunities; and

• marketing of oil and natural gas.

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.


Item 3.	*Quantitative and Qualitative Disclosures About Market Risk*

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.

The derivative commodity price instruments are generally put in place to limit the risk of adverse oil and natural gas price movements. However, such instruments can limit future gains resulting from upward favorable oil and natural gas price movements. Recognition of both realized and unrealized gains or losses is reported currently in our financial statements as required by existing generally accepted accounting principles.

As of March 31, 2003, we had substantial derivative financial instruments outstanding and related to our price risk management program. See “Note 4” to our consolidated financial statements in Item 1 of this Report for additional details on our oil and natural gas related transactions in effect as of March 31, 2003. For more information on our interest rate swaps in effect as of March 31, 2003, see “Note 3” to our consolidated financial statements in Item 1 of this Report.


Item 4.	*Controls and Procedures*

Our Chairman of the Board and Chief Executive Officer and our Chief Financial Officer (our principal executive officer and principal financial officer, respectively) have concluded, based on their evaluation as of a date within 90 days prior to the date of the filing of this report on Form 10-Q, that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and 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.

There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of such evaluation.

PART II — OTHER INFORMATION


Item 1.	*Legal Proceedings*

Westport Oil and Gas Company, L.P., our wholly-owned subsidiary, is a defendant in a case brought in July 2001 against its predecessor, Belco Energy 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 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 and are ongoing. 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.

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.


Item 2.	*Changes in Securities and Use of Proceeds*

(a) During the quarter ended March 31, 2003, we issued 147,100 shares of our common stock as restricted stock awards and issued 6,000 shares of our common stock in connection with the exercise of options granted pursuant to the 2000 Stock Incentive Plan. We also issued 2,721 shares of our common stock in connection with the exercise of options granted pursuant to the Belco 1996 Stock Incentive Plan.

(b) On March 12, 2003 we paid the first quarter dividend for 2003 of $0.40625 per share per quarter on our 6 1/2% convertible preferred stock.

(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.

(d) On November 19, 2002, we completed a private equity offering of 3.125 million shares of our common stock to Spindrift Partners, L.P., Spindrift Investors (Bermuda) L.P., Global Natural Resources III and Global Natural Resources III L.P. at a net price to us of $16.00 per share for aggregate proceeds of $50 million. The net price represents a 9% discount from the closing price of our common stock on the New York Stock Exchange on November 11, 2002, the date on which the terms of the sale were negotiated. We incurred total expenses of approximately $40,000 in connection with the private equity offering. We did not pay any underwriting discounts or commissions in connection with this offering. Our aggregate net proceeds from this offering were approximately $50 million. On December 31, 2002, we filed the shelf registration statement (File No. 333-102281) registering the resale by the selling stockholders from time to time of our common stock issued in the private equity offering, which registration statement was declared effective by the SEC on January 7, 2003. The net proceeds from the private equity offering were used to reduce our indebtedness under the revolving credit facility. We did not receive any proceeds from the sale of shares of common stock by the selling stockholders. No payments constituted direct or indirect payments to any of our directors, officers or general partners or their associates, to persons owning 10% or more of any class of our equity securities or to any of our affiliates.

On December 2, 2002 we commenced, and on December 16, 2002 we completed, an offering of 11.5 million shares of common stock at a price of $19.90 per share, which included 1.5 million shares covered by an over-allotment option we granted to, and which was exercised by, the underwriters, pursuant to the Company’s Shelf Registration Statement (File No. 333-42107), which was declared effective by the SEC on December 24, 1997. The managing underwriters were Lehman Brothers Inc., Credit Suisse First Boston Corporation, J.P. Morgan Securities Inc., Petrie Parkman & Co., Inc., A.G. Edwards & Sons, Inc. and McDonald Investments. We received net proceeds of approximately $216.2 million from the sale of our common stock, all of which we used to finance our acquisition of certain natural gas properties and midstream gathering and compression assets located in Utah from certain affiliates of El Paso Corporation on December 17, 2002. In connection with the offering of 11.5 million shares of our common stock, we incurred total expenses of approximately $12.4 million, including underwriting discounts and commissions of approximately $11.5 million and approximately $0.9 million in other expenses. No payments constituted direct or indirect payments to any of our directors, officers or general partners or their associates, to persons owning 10% or more of any class of our equity securities or to any of our affiliates.


Item 3.	*Defaults Upon Senior Securities*

None.


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

The Company held its Special Meeting of Stockholders on March 5, 2003. At the Special Meeting, the Company’s stockholders approved a proposal to amend the Company’s Amended Articles of Incorporation to increase the number of authorized shares of the Company’s common stock from 70 million shares to 100 million shares the vote tabulation was as follows:


FOR		AGAINST		ABSTAIN

	57,642,973		426,917		4,316


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.
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).
10	.1	Change in Control Severance Protection Agreement, dated as of February 1, 2003, between the Company and Carter Mathies (incorporated by reference to Exhibit 10.28 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, filed on March 10, 2003).
*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.

* Filed herewith

(b) Reports on Form 8-K:

      (i) Current Report on Form 8-K (Item 5), filed on January 17, 2003;

      (ii) Current Report on Form 8-K (Item 5), filed on February 10, 2003;

      (iii) Current Report on Form 8-K/ A (Items 5 and 7), filed on February 26, 2003; and

      (iv) Current Report on Form 8-K (Item 5), filed on February 28, 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: May 8, 2003		By: /s/ DONALD D. WOLF Name: Donald D. Wolf Title: Chairman of the Board and Chief Executive Officer

Date: May 8, 2003		By: /s/ LON MCCAIN Name: Lon McCain Title: Vice President, Chief Financial Officer and Treasurer

CERTIFICATION

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

1. I have reviewed this quarterly report on Form 10-Q of Westport Resources Corporation;

2. Based on my 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;

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

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) 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;

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

a) all significant deficiencies 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; and

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.

Date: May 8, 2003

By: /s/ DONALD D. WOLF

Name: Donald D. Wolf

Title: Chairman of the Board and Chief Executive Officer

CERTIFICATION

I, Lon McCain, Vice President, Chief Financial Officer and Treasurer of Westport Resources Corporation, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Westport Resources Corporation;

Date: May 8, 2003

By: /s/ LON MCCAIN

Name: Lon McCain

Title: Vice President, Chief Financial Officer and Treasurer

INDEX TO EXHIBITS


Exhibit
Number			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.
	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).
	10	.1	Change in Control Severance Protection Agreement, dated as of February 1, 2003, between the Company and Carter Mathies (incorporated by reference to Exhibit 10.28 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, filed on March 10, 2003).
	*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.

* Filed herewith


(2)	The balance of the 8 1/4% Senior Subordinated Notes Due 2011, noted above 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)	The balances of the 8 7/8% Senior Subordinated Notes due 2007, noted above as of March 31, 2003 and December 31, 2002, respectively, reflect increases of $3.3 million and $3.5 million, respectively, 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 notes at March 31, 2003 and December 31, 2002, respectively, was $122.7 million. See Note 9 — Subsequent Events regarding the redemption of the Company’s outstanding 8 7/8% Senior Subordinated Notes due 2007 on May 5, 2003.


	•	the rate of interest announced by JP Morgan Chase Bank, formerly known as The Chase Manhattan 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%:


	•	3.8 Mmbbls of oil and 56.1 Bcf of natural gas subject to CPRM contracts for the remainder of 2003. Of these contracts, all of the oil and 47.9 Bcf of the natural gas contracts are subject to weighted average NYMEX floor prices of $23.12 per barrel and $3.78 per Mmbtu and weighted average NYMEX ceiling prices of $25.16 per barrel and $4.20 per Mmbtu, respectively, excluding the effect, if any, of the three-way floor price. Of the remaining 2003 gas CPRM contract settlements 5.5 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 2.8 Bcf are calculated based on the Colorado Interstate Gas Rocky Mountain Index (“CIGRM”) at a weighted average swap price of $3.59. In addition, included in the 47.9 Bcf of natural gas contracts are basis swaps covering 10.1 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, 2.8 Bcf of natural gas for 2003 that lock in the pricing differential between NYMEX and CIGRM at a weighted average price differential of $0.95 per Mmbtu and 6.4 Bcf for


		2003 that lock in the pricing differential between CIGRM and NWPRM at a weighted average price differential of $0.43 per Mmbtu.

	•	2.2 Mmbbls of oil and 49.3 Bcf of natural gas subject to CPRM contracts for 2004. Of these contracts, all of the oil and 38.3 Bcf of the natural gas contracts are subject to weighted average floor prices of $23.93 per barrel and $3.83 per Mmbtu and weighted average NYMEX ceiling prices of $25.47 per barrel and $4.06 per Mmbtu, respectively, excluding the effect, if any, of the three-way floor price. The remaining 2004 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 38.3 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 CIGRM at a weighted average price differential of $0.81.

	•	9.1 Bcf of natural gas subject to CPRM contracts for 2005 with a weighted average NYMEX swap price of $3.96 per Mmbtu.


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

(3)	For any particular CIGRM swap sold transaction, the counterparty is required to make a payment to Westport in the event that the CIGRM 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 CIGRM 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 $22.28 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 CIGRM) 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 CIGRM) for any settlement period is less than the swap differential price for such hedge.

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


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


	•	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. 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 GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:


	•	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.


	•	Impairment of 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.

	•	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.


	•	drilling results;

	•	product prices;

	•	industry conditions and outlook; and

	•	future acquisition of properties.


	•	amount, nature and timing of capital expenditures;

	•	projected drilling of wells;

	•	reserve estimates;

	•	timing and amount of future production of oil and natural gas;

	•	operating costs and other expenses;

	•	cash flow, anticipated liquidity and prospects for growth;

	•	estimates of proved reserves and exploitation and exploration opportunities; and

	•	marketing of oil and natural gas.


	(i) Current Report on Form 8-K (Item 5), filed on January 17, 2003;

	(ii) Current Report on Form 8-K (Item 5), filed on February 10, 2003;

	(iii) Current Report on Form 8-K/ A (Items 5 and 7), filed on February 26, 2003; and

	(iv) Current Report on Form 8-K (Item 5), filed on February 28, 2003.


	a) 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;


	a) 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; and