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 September 30, 2002

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

52,145,942 shares of the issuer’s common stock, par value $0.01 per share, were outstanding as of November 1, 2002.

TABLE OF CONTENTS


TABLE OF CONTENTS
PART I -- FINANCIAL INFORMATION
	Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF OPERATIONS
CONSOLIDATED STATEMENTS OF CASH FLOWS
		CONDENSED CONSOLIDATING BALANCE SHEET
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
		CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures about Market Risk
	Item 4. Controls and Procedures
PART II -- OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 2. Changes in Securities and Use of Proceeds
	Item 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
CERTIFICATION
INDEX TO EXHIBITS
EX-99.1 Certification Pursuant to 18 U.S.C.
EX-99.2 Certification Pursuant to 18 U.S.C.

WESTPORT RESOURCES CORPORATION

TABLE OF CONTENTS


		Page

PART I
FINANCIAL INFORMATION			1
Item 1.	Financial Statements		1
	Consolidated Balance Sheets as of September 30, 2002 (unaudited) and December 31, 2001		1
	Consolidated Statements of Operations for the three months and nine months ended September 30, 2002 and 2001 (unaudited)		2
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2002 and 2001 (unaudited)		3
	Notes to Consolidated Financial Statements (unaudited)		4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		29
Item 4.	Controls and Procedures		29
PART II
OTHER INFORMATION			30
Item 1.	Legal Proceedings		30
Item 2.	Changes in Securities and Use of Proceeds		30
Item 3.	Defaults Upon Senior Securities		30
Item 4.	Submission of Matters to a Vote of Security Holders		30
Item 5.	Other Information		30
Item 6.	Exhibits and Reports on Form 8-K		30
Signatures			32

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

WESTPORT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS


					September 30,			December 31,
					2002			2001

					(Unaudited)

					(In thousands,
					except share data)
ASSETS
Current Assets:
	Cash and cash equivalents				$	35,273		$	27,584
	Accounts receivable, net					47,511			61,808
	Derivative assets					4,992			7,832
	Prepaid expenses					10,574			5,474

				Total current assets		98,350			102,698

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties				1,660,442			1,446,331
		Unproved properties				97,450			105,539

						1,757,892			1,551,870
	Less accumulated depletion, depreciation and amortization					(425,592	)		(280,737	)

				Net oil and gas properties		1,332,300			1,271,133

	Building and other office furniture and equipment					9,390			8,099
	Less accumulated depreciation					(3,710	)		(3,028	)

				Net building and other office furniture and equipment		5,680			5,071

Other assets:
	Long-term derivative assets					8,881			612
	Goodwill					246,712			214,844
	Other assets					9,202			9,858

				Total other assets		264,795			225,314

				Total assets	$	1,701,125		$	1,604,216


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
	Accounts payable				$	37,744		$	47,901
	Accrued expenses					36,568			30,294
	Ad valorem taxes payable					11,979			6,930
	Derivative liabilities					21,652			3,289
	Income taxes payable					519			550
	Other current liabilities					—			369

				Total current liabilities		108,462			89,333
Long-term debt						556,331			429,224
Deferred income taxes						141,090			158,005
Long term derivative liabilities						4,026			5,956
Other liabilities						814			1,402

				Total liabilities		810,723			683,920

Stockholders’ equity:
	6 1/2% convertible preferred stock, $.01 par value; 10,000,000 shares authorized; 2,930,000 issued and outstanding at September 30, 2002 and December 31, 2001, respectively					29			29
	Common stock, $0.01 par value; 70,000,000 authorized; 52,177,753 and 52,092,691 shares issued and outstanding at September 30, 2002 and, December 31, 2001, respectively					522			521
	Additional paid-in capital					881,124			877,960
	Treasury stock-at cost; 33,617 and 30,000 shares at September 30, 2002 and December 31, 2001, respectively					(469	)		(408	)
	Retained earnings					14,860			33,330
	Accumulated other comprehensive income					(5,664	)		8,864

			Total stockholders’ equity			890,402			920,296

				Total liabilities and stockholders’ equity	$	1,701,125		$	1,604,216

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

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS



				For the Three Months						For the Nine Months
				Ended September 30,						Ended September 30,

				2002			2001			2002			2001


				(In thousands, except per share amounts)

				(Unaudited)
Operating revenues:
	Oil and natural gas sales			$	105,423		$	70,157		$	295,442		$	234,405
	Hedge settlements				(1,849	)		(307	)		1,509			(1,824	)
	Commodity price risk management activities:
		Non-hedge settlements			—			(1,025	)		822			(558	)
		Non-hedge change in fair value of derivatives			(663	)		17,720			(8,885	)		24,486
	Gain (loss) on sale of operating assets, net				137			—			(1,731	)		—

			Net revenues		103,048			86,545			287,157			256,509

Operating costs and expenses:
	Lease operating expenses				23,477			14,775			67,381			34,770
	Production taxes				5,209			3,009			16,845			8,942
	Transportation costs				2,179			1,236			6,782			3,921
	Exploration				3,596			13,463			21,638			24,333
	Depletion, depreciation and amortization				47,686			31,222			147,066			72,251
	Impairment of unproved properties				2,788			1,366			9,078			3,114
	Stock compensation expense				1,860			(2,331	)		1,954			(1,060	)
	General and administrative				5,650			4,122			17,079			10,832

			Total operating expenses		92,445			66,862			287,823			157,103

			Operating income (loss)		10,603			19,683			(666	)		99,406

Other income (expense):
	Interest expense				(7,542	)		(3,892	)		(23,891	)		(4,483	)
	Interest income				172			456			373			1,522
	Change in fair value of interest rate swap				—			2,249			226			1,877
	Other				176			23			497			20

					(7,194	)		(1,164	)		(22,795	)		(1,064	)

Income (loss) before income taxes					3,409			18,519			(23,461	)		98,342
Benefit (provision) for income taxes:
	Current				—			—			—			(2,006	)
	Deferred				(1,244	)		(6,759	)		8,563			(33,889	)

			Total benefit (provision) for income taxes		(1,244	)		(6,759	)		8,563			(35,895	)

	Net income (loss)			$	2,165		$	11,760		$	(14,898	)	$	62,447

Preferred stock dividends					1,191			397			3,572			397

Net income (loss) available to common stockholders				$	974		$	11,363		$	(18,470	)	$	62,050

Weighted average number of common shares outstanding:
	Basic				52,144			44,527			52,118			40,496

	Diluted				52,646			45,238			52,118			41,329

Net income (loss) per common share:
	Basic			$	.02		$	.26		$	(.35	)	$	1.53

	Diluted			$	.02		$	.25		$	(.35	)	$	1.50

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

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



				For the Nine Months Ended
				September 30,

				2002			2001


				(In thousands)

				(Unaudited)
Cash flows from operating activities:
	Net income (loss)			$	(14,898	)	$	62,447
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Depletion, depreciation and amortization			147,066			72,251
		Exploratory dry hole costs			12,359			16,623
		Impairment of unproved properties			9,078			3,114
		Deferred income taxes			(8,563	)		33,889
		Director retainers settled for stock			20			—
		Stock compensation expense			1,954			(1,060	)
		Change in fair value of derivatives			8,992			(26,363	)
		Amortization of derivative liabilities			(7,187	)		—
		Amortization of deferred financing fees			782			633
		Loss on sale of operating assets, net			1,731			—
		Changes in assets and liabilities, net of effects of acquisitions:
			Decrease in accounts receivable		17,893			27,001
			Decrease (increase) in prepaid expenses		(2,219	)		446
			Decrease in accounts payable		(15,136	)		(5,426	)
			Increase in ad valorem taxes payable		2,161			3,141
			Increase (decrease) in income taxes payable		(44	)		306
			Increase (decrease) in accrued expenses		6,669			(11,200	)
			Decrease in other liabilities		(818	)		(107	)

Net cash provided by operating activities					159,840			175,695

Cash flows from investing activities:
	Additions to property and equipment				(104,918	)		(132,688	)
	Proceeds from sales of assets				10,552			654
	Acquisitions of oil and gas properties				(168,528	)		(6,319	)
	Other				(81	)		(2	)

Net cash used in investing activities					(262,975	)		(138,355	)

Cash flows from financing activities:
	Proceeds from issuance of common stock				1,074			264
	Repurchase of common stock				(61	)		(408	)
	Proceeds from issuance of long-term debt				155,000			255,000
	Repayment of long term debt				(45,000	)		(273,284	)
	Preferred stock dividends paid				(3,572	)		—
	Gain on interest rate swap cancellation				3,705			—
	Financing fees				(322	)		(2,036	)

Net cash provided by financing activities					110,824			(20,464	)

Net increase in cash and cash equivalents					7,689			16,876
Cash and cash equivalents, beginning of period					27,584			20,154

Cash and cash equivalents, end of period				$	35,273		$	37,030

Supplemental cash flow information:
	Cash paid for interest			$	23,862		$	12,016

	Cash paid for income taxes			$	44		$	1,700

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and Nature of Business

On August 21, 2001, the stockholders of each of Westport Resources Corporation, a Delaware corporation (“Old Westport”), and Belco Oil & Gas Corp., a 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 is accounted for as a reverse acquisition in which Old Westport is the purchaser of Belco. Business activities of the Company include the exploration for and production of oil and natural gas, primarily in the Gulf of Mexico, the Rocky Mountains, the Gulf Coast and the West Texas/ Mid-Continent area.

2. Unaudited Consolidated Financial Statements

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

3. Debt

Long-term debt consisted of:


	September 30,			December 31,
	2002			2001


	(In thousands)
8 1/4% senior subordinated notes due 2011	$	283,474	(1)	$	272,147	(2)
8 7/8% senior subordinated notes due 2007		127,857	(3)		122,077	(2)
Revolving credit facility due on July 1, 2005		145,000			35,000

		556,331			429,224
Less current portion		—			—

	$	556,331		$	429,224

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

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	*Revolving Credit Facility*

Upon closing of the Merger, the Company entered into a new credit facility (the “Revolving Credit Facility”) with a syndicate of banks, which was subsequently amended on November 5, 2001. The Revolving Credit Facility, as amended, provides for a maximum committed amount of $500 million and a borrowing base of approximately $400 million as of September 30, 2002. The facility matures on July 1, 2005. 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: (1) the rate of interest announced by JP Morgan Chase Bank, as its prime rate; (2) the secondary market rate for three month certificates of deposit plus 1%; and (3) the Federal funds effective rate plus 0.5%, plus in each case a margin of 0% to 0.125% based upon the ratio of total debt to EBITDAX. EBITDAX represents earnings before exploration; depletion, depreciation and amortization; impairment of unproved properties; stock compensation expense; non-hedge change in fair value of derivatives; interest expense; change in fair value of interest rate swap; loss on sale of operating assets, net amortization of deferred financing fees; and total benefit (provision) for income taxes. The interest on a Eurodollar loan is a fluctuating rate based upon the rate at which Eurodollar deposits in the London interbank market are quoted plus a margin of 1.25% to 1.50% based upon the ratio of Total debt to EBITDAX.

As of September 30, 2002, the Company had borrowings of $145 million outstanding with a weighted average interest rate of 4.23%, outstanding letters of credit issued of approximately $3.8 million and available unused borrowing capacity of approximately $251.2 million under the Revolving Credit Facility.


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

In connection with the Merger, the Company 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 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 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 was equal to the redemption cost.


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

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


	*Interest Rate Swaps — Hedges*

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the 8 7/8% Senior Subordinated Notes had a notional amount of $122.7 million and an expiration date of September 15, 2007. Under this swap agreement, the Company paid the counterparty a variable rate (LIBOR + 3.44%) and received a fixed rate (8 7/8%). On September 16, 2002 the interest rate swap on the 8 7/8% Senior Subordinated Notes was terminated resulting in $5.8 million being paid to the Company. The Company recorded a $2.1 million reduction in interest expense and a $3.7 million fair value gain which was added to the outstanding debt balance and will be amortized over the remaining life of the note. The swap on the 8 1/4% Senior Subordinated Notes has a notional amount of $100.0 million and an expiration date of November 1, 2011. Under the swap agreement, the Company pays the counterparty a variable rate (LIBOR +2.42%) and receives a fixed rate (8 1/4%). Beginning on November 1, 2006 the counterparty has the option to terminate the swap on any date beginning on November 1, 2006, subject to an early termination fee ranging from $4.125 million at November 1, 2006 to $0 on or after November 1, 2009. The early termination dates and fees mirror the prepayment terms and prepayment penalties included in the indenture related to the 8 1/4% Senior Subordinated Notes.

The Company has documented and designated these interest rate swaps as hedges of the fair value of a portion of the 8 7/8% Senior Subordinated Notes and 8 1/4% Senior Subordinated Notes. 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, “Accounting for Derivative Instruments and Hedging Activities,” the change in the fair value of the debt is assumed to equal the change in the fair value of the interest rate swaps. As such, there is no ineffectiveness assumed to exist between the interest rate swaps and the Senior Subordinated Notes.

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 transactions are accounted for 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.

Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded a derivative liability of approximately $4.7 million for the fair market value of its derivative instruments designated as cash flow hedges and a corresponding loss of approximately $3.1 million (net of tax effect of $1.6 million) as a cumulative effect of a change in accounting principle in other comprehensive income. The Company reclassified approximately $1.8 million hedging loss and $1.5 million hedging gain for the three and nine months ended September 30, 2002, respectively, from accumulated other comprehensive income to oil and gas sales revenues. The hedging gains and losses reclassified to revenues include realized losses of $3.2 million and $4.6 million for the three and nine months ended September 30, 2002, respectively.

For the three months ended September 30, 2002, the Company recorded no non-hedge CPRM settlements, an unrealized change in fair value of non-hedge derivatives of ($0.7) million and no ineffectiveness loss. For the nine months ended September 30, 2002 the Company recorded non-hedge CPRM settlements of $0.8 million and an unrealized change in fair value of non-hedge derivatives of ($8.9) million, which included a $0.2 million ineffectiveness loss. The non-hedge CPRM settlements include realized losses of $1.1 million and $1.3 million for the three and nine months ended September 30, 2002, respectively.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company recognized decreases and increases in oil and natural gas revenues of ($1.8) million and ($0.3) million from settled hedging agreements for the three months ended September 30, 2002 and 2001, respectively and $1.5 and ($1.8) million for the nine months ended September 30, 2002 and 2001, respectively.

As of September 30, 2002, the Company had approximately 0.9 Mmbbls of oil and 3.5 Bcf of natural gas subject to CPRM contracts for the remainder of 2002. The 2002 contracts have weighted average floor prices of $22.78 per barrel and $2.85 per Mmbtu, with weighted average ceiling prices of $25.41 per barrel and $3.11 per Mmbtu, respectively. In addition for the fourth quarter of 2002, the Company had 0.92 Bcf of puts purchased at a weighted average price of $3.13 per Mmbtu. The Company has approximately 4.8 Mmbbls of oil and 30.2 Bcf of natural gas subject to CPRM contracts for 2003. The 2003 contracts have weighted average floor prices of $23.08 per barrel and $3.65 per Mmbtu, with weighted average ceiling prices of $25.03 per barrel and $4.40 per Mmbtu, respectively. The contracts discussed above represent both the Company’s hedge and non-hedge positions as of September 30, 2002.

The summary tables below provide details about the volumes and prices of all open CPRM, hedge and non-hedge commitments, as of September 30, 2002.


				2002		2003

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


				2002		2003

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

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

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

(3) Calls or puts are sold under written option contracts in return for a premium received by Westport upon the initiation of the contract. Westport is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the price of the call sold, or less than the price of the put sold. Conversely, calls or puts bought in return for Westport’s payment of a premium require the counterparty to make a payment to Westport in the event that the NYMEX Reference Price on any settlement period is greater than the call price or less than the put price.

(4) Three-way collars are settled as described in footnote (2) above, with the following exception: if the NYMEX Reference Price falls below the three-way floor price, the average floor price is adjusted by the amount by which the NYMEX Reference Price is below the three-way floor price. For example, on a three-way oil collar, if the NYMEX Reference Price is $18.00 per bbl during the term of the 2002 three-way collars, then the average floor price would be $22.17 per bbl.

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


	*Earning per Share*

Basic earnings per share are computed by dividing net earnings attributable to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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



		For the Three Months				For the Nine Months
		Ended September 30,				Ended September 30,

		2002		2001		2002			2001


		(In thousands except per share amount)
Net income (loss) available to common stockholders		$	974	$	11,363	$	(18,470	)	$	62,050

Weighted average common shares outstanding			52,144		44,527		52,118			40,496
	Add dilutive effects of employee stock options		502		711		—			833

Weighted average common shares outstanding including the effects of dilutive securities			52,646		45,238		52,118			41,329

Basic earnings per share		$	.02	$	.26	$	(.35	)	$	1.53

Diluted earning per share		$	.02	$	.25	$	(.35	)	$	1.50


	*Comprehensive Income (Loss)*

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


			Nine Months Ended			Nine Months Ended
			September 30,			September 30,
			2002			2001

Net income (loss) available to common stockholders			$	(18,470	)	$	62,050
Other comprehensive income
	Cumulative effect of change in accounting principle			—			(3,100	)
	Change in fair value of derivative hedging instruments			(13,569	)		11,608
	Enron non-cash settlements reclassified to income			(897	)		—
	Hedge settlements reclassified to income			(62	)		(1,158	)

		Other comprehensive income		(14,528	)		7,350

Comprehensive income (loss)			$	(32,998	)	$	69,400

6. Acquisitions

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7. Recent Accounting Pronouncements

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

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

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

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

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


	Northern		Southern
	Division		Division
	Segment		Segment		Total

Goodwill Acquired (August 21, 2001)	$	33,416	$	181,428	$	214,844
Adjustments confirmed by information received subsequent to the Merger that existed at the date of the Merger		—		31,868		31,868

Balance as of June 30, 2002	$	33,416	$	213,296	$	246,712

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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, generally accepted accounting principles (“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 will adopt the provisions of SFAS No. 145 on January 1, 2003. The adoption of the provisions of SFAS No. 145 is not expected to affect the Company’s financial position or results of operations.

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 adoption of SFAS No. 146 is not expected to have an effect on the Company’s financial position or results of operations.

8. Segment Information

The Company operates in three geographic divisions: Northern, which manages properties in the Rocky Mountain region; Southern, which manages properties in the West Texas/ Mid-Continent area and the onshore Gulf Coast regions; and Gulf of Mexico, which manages the offshore properties. All three 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 three geographic divisions. Consolidated and segment financial information is as follows:



	For the Nine Months Ended September 30,

					Gulf of			Corporate &
	Northern		Southern		Mexico			Unallocated			Consolidated


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

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	For the Three Months Ended September 30,

					Gulf of			Corporate &
	Northern		Southern		Mexico			Unallocated			Consolidated


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

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

9. Subsequent Event

On November 6, 2002 the Company agreed to purchase from El Paso Corporation and certain of its affiliated companies natural gas properties and midstream gathering and compression assets located in Utah for a purchase price of approximately $502 million, subject to certain purchase price adjustments. The Company expects to close the transaction in December of 2002. The Company estimates that in total the assets would add approximately 600 Bcfe of proved reserves to the Company’s reserve base. Currently these assets are producing approximately 80 Mmcfe/d. The Company plans to fund the transaction initially with debt and is currently pursuing additional financing options, including issuance of equity, the sale of assets, securing a partner for a portion of the acquisition or other capital markets transactions.

10. Condensed Consolidated Financial Statements of Subsidiary Guarantors

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

CONDENSED CONSOLIDATING BALANCE SHEET



			September 30, 2002

			Parent			Subsidiary
			Company			Guarantors			Eliminations			Consolidated


			(In thousands)
ASSETS
Current Assets:
	Cash and cash equivalents		$	10,934		$	24,339		$	—		$	35,273
	Accounts receivable, net			19,388			28,123			—			47,511
	Intercompany receivable			994,904			—			(994,904	)		—
	Derivative assets			4,992			—			—			4,992
	Prepaid expenses			3,490			7,084			—			10,574

		Total current assets		1,033,708			59,546			(994,904	)		98,350

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties		325,535			1,334,907			—			1,660,442
		Unproved properties		28,617			68,833			—			97,450
	Building and other office furniture and equipment			594			8,796			—			9,390

				354,746			1,412,536			—			1,767,282
	Less accumulated depletion, depreciation and amortization			(115,114	)		(314,188	)		—			(429,302	)

		Net property and equipment		239,632			1,098,348			—			1,337,980

Other assets:
	Long-term derivative assets			8,881			—			—			8,881
	Goodwill			—			246,712			—			246,712
	Other assets			9,093			109			—			9,202

		Total other assets		17,974			246,821			—			264,795

		Total assets	$	1,291,314		$	1,404,715		$	(994,904	)	$	1,701,125


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
	Accounts payable		$	13,628		$	24,116		$	—		$	37,744
	Accrued expenses			24,040			12,528			—			36,568
	Ad valorem taxes payable			—			11,979			—			11,979
	Intercompany payable			—			994,904			(994,904	)		—
	Derivative liabilities			21,652			—			—			21,652
	Income taxes payable			(248	)		767			—			519

		Total current liabilities		59,072			1,044,294			(994,904	)		108,462
Long-term debt				556,331			—			—			556,331
Deferred income taxes				6,098			134,992			—			141,090
Long-term derivative liabilities				4,026			—			—			4,026
Other liabilities				—			814			—			814

		Total liabilities		625,527			1,180,100			(994,904	)		810,723

Stockholders’ equity:
	Preferred stock			29			—			—			29
	Common stock			522			3			(3	)		522
	Additional paid-in capital			681,967			199,154			3			881,124
	Treasury stock			(469	)		—			—			(469	)
	Retained earnings			(10,598	)		25,458			—			14,860
	Accumulated other comprehensive income			(5,664	)		—			—			(5,664	)

		Total stockholders’ equity		665,787			224,615			—			890,402

		Total liabilities and stockholders’ equity	$	1,291,314		$	1,404,715		$	(994,904	)	$	1,701,125

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS



			For the Nine Months Ended September 30, 2002

			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


			(In thousands)
Operating revenues:
	Oil and natural gas sales		$	52,007		$	243,435		$	—	$	295,442
	Hedge settlements			1,509			—			—		1,509
	Non-hedge settlements			822			—			—		822
	Non-hedge change in fair value of derivatives			(8,885	)		—			—		(8,885	)
	Loss on sale of operating assets, net			—			(1,731	)		—		(1,731	)

		Net revenues		45,453			241,704			—		287,157

Operating costs and expenses:
	Lease operating expense			10,306			57,075			—		67,381
	Production taxes			4			16,841			—		16,845
	Transportation costs			202			6,580			—		6,782
	Exploration			14,264			7,374			—		21,638
	Depletion, depreciation and amortization			32,014			115,052			—		147,066
	Impairment of unproved properties			2,182			6,896			—		9,078
	Stock compensation expense			1,954			—			—		1,954
	General and administrative			4,501			12,578			—		17,079

		Total operating expenses		65,427			222,396			—		287,823

		Operating income (loss)		(19,974	)		19,308			—		(666	)

Other income (expense):
	Interest expense			(23,663	)		(228	)		—		(23,891	)
	Interest income			100			273			—		373
	Change in fair value of interest rate swap			—			226			—		226
	Other			462			35			—		497

Income (loss) before income taxes				(43,075	)		19,614			—		(23,461	)

Provision for income taxes:
	Deferred			15,722			(7,159	)		—		8,563

		Total provision for income taxes		15,722			(7,159	)		—		8,563
Net loss				(27,353	)		12,455			—		(14,898	)

Preferred stock dividends				3,572			—			—		3,572

Net loss available to common stock			$	(30,925	)	$	12,455		$	—	$	(18,470	)

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS



					For the Nine Months Ended September 30, 2002

					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)
Cash flows from operating activities:
	Net loss				$	(27,353	)	$	12,455		$	—		$	(14,898	)
	Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
		Depletion, depreciation and amortization				32,014			115,052			—			147,066
		Exploration dry hole costs				7,102			5,257			—			12,359
		Impairment of unproved properties				2,182			6,896			—			9,078
		Deferred income taxes				(15,722	)		7,159			—			(8,563	)
		Director retainers settled for stock				20			—			—			20
		Stock compensation expense				1,954			—			—			1,954
		Change in fair value of derivatives				8,992			—			—			8,992
		Amortization of derivative liabilities				(7,187	)		—			—			(7,187	)
		Amortization of deferred financing fees				782			—			—			782
		Loss on sale of operating assets, net				—			1,731			—			1,731
		Changes in asset and liabilities, net of effects of acquisitions:
			Decrease (increase) in accounts receivable			(701	)		18,594			—			17,893
			Decrease in prepaid expenses			(1,145	)		(1,074	)		—			(2,219	)
			Decrease in accounts payable			(626	)		(14,510	)		—			(15,136	)
			Increase in ad valorem taxes payable			(1	)		2,162			—			2,161
			Decrease in income taxes payable			—			(44	)		—			(44	)
			Increase in accrued expenses			1,798			4,871			—			6,669
			Decrease in other liabilities			—			(818	)		—			(818	)

				Net cash provided by (used in) operating activities		2,109			157,731			—			159,840

Cash flows from investing activities:
	Additions to property and equipment					(48,491	)		(56,427	)		—			(104,918	)
	Proceeds from sales of assets					—			10,552			—			10,552
	Increase in intercompany receivable					(66,984	)		—			66,984			—
	Acquisitions of oil and gas properties					(328	)		(168,200	)		—			(168,528	)
	Other					—			(81	)		—			(81	)

				Net cash provided by (used in) investing activities		(115,803	)		(214,156	)		66,984			(262,975	)

Cash flows from financing activities:
	Proceeds from issuance of common stock					1,074			—			—			1,074
	Repurchase of common stock					(61	)		—			—			(61	)
	Proceeds from issuance of long-term debt					155,000			—			—			155,000
	Repayment of long term debt					(45,000	)		—			—			(45,000	)
	Preferred stock dividends paid					(3,572	)		—			—			(3,572	)
	Gain on interest rate swap cancellation					3,705			—			—			3,705
	Financing fees					(322	)		—			—			(322	)
	Increase in intercompany payable					—			66,984			(66,984	)		—

				Net cash provided by (used in) financing activities		110,824			66,984			(66,984	)		110,824

Net increase (decrease) in cash and cash equivalents						(2,870	)		10,559			—			7,689
Cash and cash equivalents, beginning of period						13,804			13,780			—			27,584

Cash and cash equivalents, end of period					$	10,934		$	24,339		$	—		$	35,273

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET



				December 31, 2001

				Parent			Subsidiary
				Company			Guarantors			Eliminations			Consolidated


				(In thousands)
ASSETS
Current Assets:
	Cash and cash equivalents			$	13,812		$	13,772		$	—		$	27,584
	Accounts receivable, net				18,687			43,121			—			61,808
	Intercompany receivable				919,727			—			(919,727	)		—
	Derivative assets				—			7,832			—			7,832
	Prepaid expenses				2,345			3,129			—			5,474

			Total current assets		954,571			67,854			(919,727	)		102,698

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties			281,868			1,164,463			—			1,446,331
		Unproved properties			23,978			81,561			—			105,539
	Building and other office furniture and equipment				487			7,612			—			8,099

					306,333			1,253,636			—			1,559,969
	Less accumulated depletion, depreciation and amortization				(83,016	)		(200,749	)		—			(283,765	)

			Net property and equipment		223,317			1,052,887			—			1,276,204

Other assets:
	Long-term derivative assets				—			612			—			612
	Goodwill				—			214,844			—			214,844
	Other assets				9,830			28			—			9,858

			Total other assets		9,830			215,484			—			225,314

			Total assets	$	1,187,718		$	1,336,225		$	(919,727	)	$	1,604,216


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
	Accounts payable			$	14,254		$	33,647		$	—		$	47,901
	Accrued expenses				8,840			21,454			—			30,294
	Ad valorem taxes payable				—			6,930			—			6,930
	Intercompany payable				—			919,727			(919,727	)		—
	Derivative liabilities				—			3,289			—			3,289
	Income taxes payable				(131	)		681			—			550
	Other current liabilities				—			369			—			369

			Total current liabilities		22,963			986,097			(919,727	)		89,333

Long-term debt					429,224			—			—			429,224
Deferred income taxes					31,053			126,952			—			158,005
Long-term derivative liabilities					5,205			751			—			5,956
Other liabilities					—			1,402			—			1,402

			Total liabilities		488,445			1,115,202			(919,727	)		683,920

Stockholders’ equity:
	Preferred stock				29			—			—			29
	Common stock				521			3			(3	)		521
	Additional paid-in capital				678,804			199,153			3			877,960
	Treasury stock				(408	)		—			—			(408	)
	Retained earnings				20,327			13,003			—			33,330
	Accumulated other comprehensive income				—			8,864			—			8,864

			Total stockholders’ equity		699,273			221,023			—			920,296

			Total liabilities and stockholders’ equity	$	1,187,718		$	1,336,225		$	(919,727	)	$	1,604,216

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS



			For the Nine Months Ended September 30, 2001

			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


			(In thousands)
Operating revenues:
	Oil and natural gas sales		$	76,524		$	157,881		$	—	$	234,405
	Hedge settlements			—			(1,824	)		—		(1,824	)
	Non-hedge settlements			—			(558	)		—		(558	)
	Non-hedge change in fair value of derivatives			—			24,486			—		24,486

		Net revenues		76,524			179,985			—		256,509

Operating costs and expenses:
	Lease operating expense			5,390			29,380			—		34,770
	Production taxes			6			8,936			—		8,942
	Transportation costs			410			3,511			—		3,921
	Exploration			17,885			6,448			—		24,333
	Depletion, depreciation and amortization			32,154			40,097			—		72,251
	Impairment of unproved properties			2,297			817			—		3,114
	Stock compensation expense			(1,060	)		—			—		(1,060	)
	General and administrative			4,817			6,015			—		10,832

		Total operating expenses		61,899			95,204			—		157,103

		Operating income		14,625			84,781			—		99,406

Other income (expense):
	Interest expense			(3,166	)		(1,317	)		—		(4,483	)
	Interest income			1,120			402			—		1,522
	Change in fair value of interest rate swap			—			1,877			—		1,877
	Other			63			(43	)		—		20

Income before income taxes				12,642			85,700			—		98,342

Provision for income taxes:
	Current			—			(2,006	)		—		(2,006	)
	Deferred			(4,614	)		(29,275	)		—		(33,889	)

		Total provision for income taxes		(4,614	)		(31,281	)		—		(35,895	)

Net income				8,028			54,419			—		62,447

Preferred stock dividends				397			—			—		397

Net loss available to common stock			$	7,631		$	54,419		$	—	$	62,050

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS



					For the Nine Months Ended September 30, 2001

					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)
Cash flows from operating activities:
	Net income				$	8,028		$	54,419		$	—		$	62,447
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depletion, depreciation and amortization				32,154			40,097			—			72,251
		Exploration dry hole costs				11,310			5,313			—			16,623
		Impairment of unproved properties				2,297			817			—			3,114
		Deferred income taxes				4,614			29,275			—			33,889
		Stock compensation expense				(1,060	)		—			—			(1,060	)
		Change in fair value of derivatives				—			(26,363	)		—			(26,363	)
		Amortization of financing fees				633			—			—			633
		Changes in asset and liabilities, net of effects of Acquisitions:
			Decrease in accounts receivable			5,048			21,953			—			27,001
			Decrease (increase) in prepaid expenses			283			163			—			446
			Decrease in accounts payable			(815	)		(4,611	)		—			(5,426	)
			Increase in ad valorem taxes payable			—			3,141			—			3,141
			Increase in income taxes payable			—			306			—			306
			Increase (decrease) in accrued expenses			(10,972	)		(228	)		—			(11,200	)
			Decrease in other liabilities			—			(107	)		—			(107	)

				Net cash provided by operating activities		51,520			124,175			—			175,695

Cash flows from investing activities:
	Additions to property and equipment					(65,485	)		(67,203	)		—			(132,688	)
	Proceeds from sale of assets					—			654			—			654
	Increase in intercompany receivable					31,006			—			(31,006	)		—
	Acquisitions of oil and gas properties					—			(6,319	)		—			(6,319	)
	Other					—			(2	)		—			(2	)

				Net cash used in investing activities		(34,479	)		(72,870	)		(31,006	)		(138,355	)

Cash flows from financing activities:
	Proceeds from issuance of common stock					264			—			—			264
	Repurchase of common stock					(408	)		—			—			(408	)
	Proceeds from long-term debt					255,000			—			—			255,000
	Repayment of long-term debt					(273,122	)		(162	)		—			(273,284	)
	Financing fees					(2,036	)		—			—			(2,036	)
	Increase in intercompany payable					—			(31,006	)		31,006			—

				Net cash provided by (used in) financing activities		(20,302	)		(31,168	)		31,006			(20,464	)

	Net increase in cash and cash equivalents					(3,261	)		20,137			—			16,876
	Cash and cash equivalents, beginning of period					12,458			7,696			—			20,154

	Cash and cash equivalents, end of period				$	9,197		$	27,833		$	—		$	37,030

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

General


	*Critical Accounting Policies And Estimates*

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

• Revenue Recognition. We follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers.

• Successful Efforts Accounting. We account for our oil and natural gas operations using the successful efforts method of accounting. Under this method, all costs associated with property acquisition, successful exploratory wells and all development wells are capitalized. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and natural gas production costs. All of our oil and natural gas properties are located within the continental United States, the Gulf of Mexico and Canada.

• Proved Reserve Estimates. Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

• 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 we prepared. Estimates prepared by others may be higher or lower than our estimates.

Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

Our stockholders should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

Our estimates of proved reserves directly impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense increases, reducing net income. Such a 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 whenever management judges that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon management’s outlook of future commodity prices and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment on a field-by-field basis, which is the lowest level at which depletion of proved properties is calculated.

• Impairment of Goodwill. Goodwill of a reporting unit is tested for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Management assesses whether or not an impairment provision is necessary based upon comparing the fair value of a reporting unit with its carrying value including goodwill.

• Impairment of Unproved Oil and Gas Properties. Management periodically assesses individually significant unproved oil and gas properties for impairment, on a project-by-project basis. Management’s assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects impact the amount and timing of impairment provisions.

• Commodity Derivative Instruments and Hedging Activities. We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize price swaps, futures contracts or collars, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures which have a high degree of historical correlation with actual prices we receive. On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of CPRM activities.

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); 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 and processing fees.

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

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 Statement of Financial Accounting Standards 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 have been impaired. Such assessment is based on, among other things, the fair value of properties located in the same area as the unproved property and our intent to pursue additional exploration opportunities on such property.

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

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

Mergers

On August 21, 2001, the stockholders of Belco approved the Agreement and Plan of Merger, dated as of June 8, 2001, between Belco and Westport. Pursuant to the Merger 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. Because former Old Westport stockholders owned a majority of the outstanding Westport common stock immediately after the Merger, the Merger is accounted for as a reverse acquisition in which Old Westport is the purchaser of Belco.

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

Results of Operations

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

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

Summary Data



		For the Three Months						For the Nine Months
		Ended September 30,						Ended September 30,

		2002			2001			2002		2001


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

The discussion below includes a comparison of our results of operations for the three months and nine months ended September 30, 2002 and 2001.

Revenues. Oil and natural gas revenues for the three months ended September 30, 2002 increased by $35.3 million, or 50%, from $70.2 million to $105.4 million, compared to the three months ended September 30, 2001. Production from the acquired Belco properties accounted for $28.1 million of the increase. Production volumes increased by 7.9 Bcfe, or 34%, from 23.3 Bcfe to 31.3 Bcfe. Acquired Belco properties accounted for 7.3 Bcfe of the increase. Production volumes also increased 1.4 Bcfe from recent discoveries in the Gulf of Mexico and 0.9 Bcfe due to an acquisition of properties in the Williston Basin in March 2002. The increases in production volumes were partially offset by oil and natural gas production declines in the Gulf of Mexico developed properties. The increase in oil and natural gas revenues was also due to increases of 6% and 13% in realized natural gas prices and oil prices, respectively, excluding the effects of hedging. Hedging transactions had the effect of decreasing oil and natural gas revenues by $1.8 million, or $0.6 per Mcfe, and $0.3 million, or $0.1 per Mcfe, for the three months ended September 30, 2002 and 2001, respectively.

Oil and natural gas revenues for the nine months ended September 30, 2002 increased by $61.0 million, or 26%, from $234.4 million to $295.4 million, over the comparable period in 2001. Production from the acquired Belco properties accounted for an increase of $106.0 million. The increase in production volumes, including production attributable to Belco properties, was partially offset by decreases of 38% and 5% in realized natural gas prices and oil prices, respectively, excluding the effects of hedging. Production volumes increased 39.6 Bcfe from 55.6 Bcfe in 2001 to 95.3 Bcfe in 2002 (acquired Belco properties accounted for 34.0 Bcfe of the increase). Production volumes also increased 5.4 Bcfe from recent discoveries in the Gulf of Mexico and 2.1 Bcfe due to an acquisition of properties in the Williston Basin in March 2002. The increases in production volumes were partially offset by oil and natural gas production declines in the Gulf of Mexico developed properties. Hedging transactions had the effect of increasing oil and natural gas revenues by $1.5 million, or $0.02 per Mcfe, and reducing oil and natural gas revenues by $1.8 million, or $0.03 per Mcfe, for the nine months ended September 30, 2002 and 2001, respectively.

Commodity Price Risk Management Activities. The Company recorded a loss of $0.7 million in the non-hedge change in fair value of derivatives for the three months ended September 30, 2002, compared to a $17.7 million gain for the three months ended September 30, 2001. There were no non-hedge settlements of derivatives recorded for the three months ended September 30, 2002 as compared to a loss of $1.0 million for the same period in 2001. The gains and losses relate to settlements of derivatives and changes in fair value on derivatives that under SFAS No. 133 do not qualify for hedge accounting.

For the nine months ended September 30, 2002, the Company recorded a loss of $8.9 million in the non-hedge change in fair value of derivatives, compared to a gain of $24.5 million for the same period in 2001. Non-hedge settlements of derivatives for the nine months ended September 30, 2002 resulted in a gain of $0.8 million compared to a loss of $0.6 million for the nine months ended September 30, 2001. The gains and losses relate to settlements of derivatives and changes in fair value on derivatives that under SFAS No. 133 do not qualify for hedge accounting.

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

Lease Operating Expense. Lease operating expense for the three months ended September 30, 2002 increased by $8.7 million, or 59%, from $14.8 million to $23.5 million, compared to the same period in 2001. Lease operating expenses from the acquired Belco properties accounted for $6.7 million of the increase. The remaining increase was primarily a result of increased production from recent offshore discoveries, nonrecurring workover expense in the Gulf of Mexico and the acquisition in the Williston Basin in March 2002. On a per Mcfe basis, lease operating expense increased from $0.63 to $0.75 in the 2001 and 2002 periods, respectively. The increase on a per Mcfe basis was primarily due to nonrecurring workover expense performed in the three months ended September 30, 2002 at a rate of $0.09 per Mcfe.

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

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

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

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

Transportation costs for the nine months ended September 30, 2002 increased by $2.9 million, or 73%, from $3.9 million to $6.8 million, compared to the same period in 2001. Transportation costs from the acquired Belco properties accounted for $2.2 million of the increase. The remaining increase was primarily due to a one time adjustment related to certain coalbed methane wells.

Exploration Costs. Exploration costs for the three months ended September 30, 2002 decreased by $9.9 million, or 73%, from $13.5 million to $3.6 million, compared to the same period in 2001. Dry hole costs for the three months ended September 30, 2002 decreased $7.7 million, compared to the same period in 2001. One unsuccessful exploratory well was drilled in the Gulf of Mexico in the three months ended September 30, 2002, compared to two higher cost unsuccessful exploratory wells drilled in the Gulf of Mexico in the three months ended September 30, 2001. The remaining decrease in exploration costs of $2.4 million was primarily attributable to the timing of purchases of Gulf of Mexico 3-D seismic data during the three months ended September 30, 2002, compared to the same period in 2001.

Exploration costs for the nine months ended September 30, 2002 decreased by $2.7 million, or 11%, from $24.3 million to $21.6 million, compared to the same period in 2001. Dry hole costs for the nine months ended September 30, 2002 decreased $4.1 million, compared to the same period in 2001. For the nine months ended September 30, 2002, five unsuccessful exploratory wells were drilled in the Gulf of Mexico and two unsuccessful onshore exploratory wells were drilled. For the nine months ended September 30, 2001, five unsuccessful exploratory wells were drilled at higher costs in the Gulf of Mexico. The decrease in dry hole costs was partially offset by increases in purchases of Gulf of Mexico 3-D seismic data and delay rentals during the nine months ended September 30, 2002, compared to the same period in 2001.

Depletion, Depreciation and Amortization (DD&A) Expense. DD&A expense increased $16.5 million during the three months ended September 30, 2002, from $31.2 million to $47.7 million, compared to the

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

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

Impairment of Unproved Properties. During the three months ended September 30, 2002, we recognized unproved property impairments of $2.8 million. The impairments consisted of $0.8 million for expired leases held in Wyoming which were acquired from Belco and $2.0 million on offshore leases. The offshore impairments were recognized as a result of an assessment of the exploration opportunities existing on such properties. During the three months ended September 30, 2001, we recognized unproved property impairments of $1.4 million on offshore leases.

During the nine months ended September 30, 2002, we recognized unproved property impairments of $9.1 million. The impairments consisted of $3.4 million for expired leases held in Wyoming, $1.6 million for expired leases held in Texas, $3.1 million for offshore leases and $1.0 million for expired leases held in North Dakota, Louisiana and various other states. Unproved properties acquired from Belco accounted for $5.8 million of the impairments related to expired leases. The offshore impairments were recognized as a result of an assessment of the exploration opportunities existing on such properties. During the nine months ended September 30, 2001, we recognized unproved property impairments of $3.1 million on offshore leases.

Stock Compensation Expense. During the three months ended September 30, 2002, we recorded $1.8 million of stock compensation expense related to certain stock options as a result of applying FASB Interpretation No. 44 and recorded $0.1 million in expense related to the issuance of restricted stock. During the three months ended September 30, 2001, we reduced stock compensation expense related to certain stock options previously recognized in prior periods by $2.4 million as a result of applying FASB Interpretation No. 44 and recorded $0.1 million in expense related to the issuance of restricted stock.

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

General and Administrative (G&A) Expense. G&A expense increased $1.6 million, or 37%, during the three months ended September 30, 2002, from $4.1 million to $5.7 million, compared to the same period in 2001. The Merger accounted for $1.1 million of the increase. The remaining increase was primarily related to payroll costs such as salaries and benefits, resulting from an increase in staff. G&A expense per Mcfe of production remained the same at $0.18 in the third quarter of 2002 and 2001, respectively.

G&A expense increased $6.3 million, or 58%, during the nine months ended September 30, 2002, from $10.8 million to $17.1 million, compared to the same period in 2001. The Merger accounted for $4.8 million of

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

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

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

Income Taxes. We recorded a deferred income tax expense of $1.2 million and $6.8 million for the three months ended September 30, 2002 and 2001, respectively.

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

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

Net loss for the nine months ended September 30, 2002 was $14.9 million compared to net income of $62.4 million for the nine months ended September 30, 2001. The variance was primarily attributable to increases in net revenues of $30.6 million and income tax benefit of $44.5 million offset by increases of $130.7 million in operating expenses and other expense of $21.7 million.

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

Net cash used in investing activities was $263.0 million for the nine months ended September 30, 2002 compared to $138.4 million for the nine months ended September 30, 2001. Of this total for the nine months ended September 30, 2002, $104.9 million was used for exploitation and exploration activities and $168.5 million was used for acquisitions, offset by proceeds from sales of properties of $10.5 million. Investing activities for the nine months ended September 30, 2001 included $132.7 million for exploitation and exploration activities and $6.3 million for acquisitions, offset by proceeds from sales of properties of $0.7 million.

Net cash provided by financing activities was $110.8 million for the nine months ended September 30, 2002 compared to ($20.5) million for the nine months ended September 30, 2001. Financing activities for the nine months ended September 30, 2002 consisted of $155.0 million in borrowings utilized for the acquisition

and development of oil and natural gas properties, $1.1 million from issuance of common stock and $3.7 million from the gain on the cancellation of the 8 7/8% fair value interest rate swap offset by $45.0 million debt repayment and a $3.6 million preferred stock dividend payment.

Financing Activity


	*Revolving Credit Facility*

The Company entered into the Revolving Credit Facility with a syndicate of banks upon closing of the Merger, which was subsequently amended on November 5, 2001. The Revolving Credit Facility, as amended, provides for a maximum committed amount of $500 million and a borrowing base of approximately $400 million as of September 30, 2002. The facility matures on July 1, 2005. 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: (1) the rate of interest announced by JP Morgan Chase Bank, as its prime rate; (2) the secondary market rate for three month certificates of deposits plus 1%; and (3) the Federal funds effective rate plus 0.5% plus in each case a margin of 0% to 0.125% based upon the ratio of total debt to EBITDAX. EBITDAX represents earnings before exploration; depletion, depreciation and amortization; impairment of unproved properties; stock compensation expense; non-hedge change in fair value of derivatives; interest expense; change in fair value of interest rate swap; loss on sale of operating assets, net amortization of deferred financing fees; and total benefit (provision) for income taxes. The interest on a Eurodollar loan is a fluctuating rate based upon the rate at which Eurodollar deposits in the London interbank market are quoted plus a margin of 1.25% to 1.50% based upon the ratio of total debt to EBITDAX.

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


	*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 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.


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

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


	*Acquisitions of Certain Oil and Gas Properties*

On September 30, 2002 we acquired southeast Texas oil and gas properties for a total cash purchase price of approximately $120 million, subject to certain purchase price adjustments. We estimate the total proved reserves in the acquired properties to be approximately 76 Bcfe, of which 82% is natural gas. We will operate essentially all of the properties. The purchase also includes 10,000 net undeveloped acres and an interest in

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

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


	*Capital Expenditures*

We anticipate that our capital expenditures for 2002 will be approximately $170 million. We do not budget for acquisitions and in the first nine months of 2002 we had acquisitions of $168.5 million. We anticipate that our primary cash requirements for 2002 will include funding acquisitions, funding development projects and general working capital needs. For the first nine months of 2002, we had capital expenditures of $104.9 million excluding geological and geophysical costs incurred of $7.0 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 Resources Corporation 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;

• drilling of wells;

• reserve estimates;

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

• operating costs and other expenses;

• cash flow and anticipated liquidity;

• estimates of proved reserves, exploitation potential or exploration prospect size; 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, 2001, 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 are reported currently in our financial statements as required by existing generally accepted accounting principles.

As of September 30, 2002, 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 September 30, 2002. For more information on our interest rate swaps in effect as of September 30, 2002, 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 it 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

None.

Item 2. Changes in Securities and Use of Proceeds

(a) During the quarter ended September 30, 2002, we issued 206 shares of Common Stock in connection with the exercise of options granted pursuant to the Belco 1996 Stock Incentive Plan.

(b) On September 11, 2002 we paid the second quarter dividend for 2002 of $0.40625 per share per quarter on our 6 1/2% Convertible Preferred Stock.

Item 3. Defaults Upon Senior Securities

None.

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

None.

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:


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


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

(b) Reports on Form 8-K:

None.

* Filed herewith

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

By: /s/ DONALD D. WOLF

Name: Donald D. Wolf

Title: Chairman of the Board and Chief Executive Officer

Date: November 8, 2002

By: /s/ LON MCCAIN

Name: Lon McCain

Title: Vice President, Chief Financial Officer and Treasurer

Date: November 8, 2002

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.

By: /s/ DONALD D. WOLF

Name: Donald D. Wolf

Title: Chairman of the Board and Chief Executive Officer

Date: November 8, 2002

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;

By: /s/ LON MCCAIN

Name: Lon McCain

Title: Vice President, Chief Financial Officer and Treasurer

Date: November 8, 2002

INDEX TO EXHIBITS


Exhibit
Number

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

* Filed herewith

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

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


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

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

(3)	Calls or puts are sold under written option contracts in return for a premium received by Westport upon the initiation of the contract. Westport is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the price of the call sold, or less than the price of the put sold. Conversely, calls or puts bought in return for Westport’s payment of a premium require the counterparty to make a payment to Westport in the event that the NYMEX Reference Price on any settlement period is greater than the call price or less than the put price.

(4)	Three-way collars are settled as described in footnote (2) above, with the following exception: if the NYMEX Reference Price falls below the three-way floor price, the average floor price is adjusted by the amount by which the NYMEX Reference Price is below the three-way floor price. For example, on a three-way oil collar, if the NYMEX Reference Price is $18.00 per bbl during the term of the 2002 three-way collars, then the average floor price would be $22.17 per bbl.


(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.

	•	Successful Efforts Accounting. We account for our oil and natural gas operations using the successful efforts method of accounting. Under this method, all costs associated with property acquisition, successful exploratory wells and all development wells are capitalized. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and natural gas production costs. All of our oil and natural gas properties are located within the continental United States, the Gulf of Mexico and Canada.

	•	Proved Reserve Estimates. Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:


	•	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 we prepared. Estimates prepared by others may be higher or lower than our estimates.

	Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

	Our stockholders should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

	Our estimates of proved reserves directly impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense increases, reducing net income. Such a decline


	•	Impairment of Proved Oil and Gas Properties. We review our long-lived proved properties whenever management judges that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon management’s outlook of future commodity prices and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment on a field-by-field basis, which is the lowest level at which depletion of proved properties is calculated.

	•	Impairment of Goodwill. Goodwill of a reporting unit is tested for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Management assesses whether or not an impairment provision is necessary based upon comparing the fair value of a reporting unit with its carrying value including goodwill.

	•	Impairment of Unproved Oil and Gas Properties. Management periodically assesses individually significant unproved oil and gas properties for impairment, on a project-by-project basis. Management’s assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects impact the amount and timing of impairment provisions.

	•	Commodity Derivative Instruments and Hedging Activities. We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize price swaps, futures contracts or collars, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures which have a high degree of historical correlation with actual prices we receive. On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of CPRM activities.


	•	drilling results;

	•	product prices;

	•	industry conditions and outlook; and

	•	future acquisition of properties.


	•	amount, nature and timing of capital expenditures;

	•	drilling of wells;

	•	reserve estimates;

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

	•	operating costs and other expenses;

	•	cash flow and anticipated liquidity;

	•	estimates of proved reserves, exploitation potential or exploration prospect size; and

	•	marketing of oil and natural gas.


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


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


	(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


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


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