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 June 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

52,143,930 shares of the issuer’s common stock, par value $0.01 per share, were outstanding as of August 1, 2002.

WESTPORT RESOURCES CORPORATION

TABLE OF CONTENTS


		Page

PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Consolidated Balance Sheets as of June 30, 2002 (unaudited) and December 31, 2001	2
	Consolidated Statements of Operations for the three months and six months ended June 30, 2002 and 2001 (unaudited)	3
	Consolidated Statements of Cash Flows for the six months ended June 30, 2002 and 2001 (unaudited)	4
	Notes to Consolidated Financial Statements (unaudited)	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	28
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	29
Item 2.	Changes in Securities and Use of Proceeds	29
Item 3.	Defaults Upon Senior Securities	29
Item 4.	Submission of Matters to a Vote of Security Holders	29
Item 5.	Other Information	29
Item 6.	Exhibits and Reports on Form 8-K	30
Signatures		31

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

WESTPORT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS


					June 30,			December 31,
					2002			2001

					(Unaudited)

					(In thousands,
					except share data)
ASSETS
Current Assets:
	Cash and cash equivalents				$	55,439		$	27,584
	Accounts receivable, net					58,253			61,808
	Derivative assets					4,334			7,832
	Prepaid expenses					8,412			5,474

			Total current assets			126,438			102,698

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties				1,520,594			1,446,331
		Unproved properties				88,111			105,539

						1,608,705			1,551,870
	Less accumulated depletion, depreciation and amortization					(378,483	)		(280,737	)

			Net oil and gas properties			1,230,222			1,271,133

	Building and other office furniture and equipment					9,145			8,099
	Less accumulated depreciation					(3,492	)		(3,028	)

			Net building and other office furniture and equipment			5,653			5,071

Other assets:
	Long-term derivative assets					3,822			612
	Goodwill					246,712			214,844
	Other assets					9,476			9,858

			Total other assets			260,010			225,314

			Total assets		$	1,622,323		$	1,604,216


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable				$	33,396		$	47,901
	Accrued expenses					31,119			30,294
	Ad valorem taxes payable					9,817			6,930
	Derivative liabilities					14,319			3,289
	Income taxes payable					519			550
	Other current liabilities					—			369

				Total current liabilities		89,170			89,333

Long-term debt						491,355			429,224
Deferred income taxes						143,229			158,005
Long term derivative liabilities						3,934			5,956
Other liabilities						1,185			1,402

				Total liabilities		728,873			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 June 30, 2002 and December 31, 2001, respectively					29			29
	Common stock, $0.01 par value; 70,000,000 authorized; 52,177,547 and 52,092,691 shares issued and outstanding at June 30, 2002, December 31, 2001, respectively					522			521
	Additional paid-in capital					879,261			877,960
	Treasury stock — at cost; 33,617 shares at June 30, 2002 and December 31, 2001, respectively					(469	)		(408	)
	Retained earnings					13,886			33,330
	Accumulated other comprehensive income					221			8,864

			Total stockholders’ equity			893,450			920,296

				Total liabilities and stockholders’ equity	$	1,622,323		$	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 Six Months
				Ended June 30,						Ended June 30,

				2002			2001			2002			2001


				(In thousands,
				except per share amounts)
				(Unaudited)
Operating revenues:
	Oil and natural gas sales			$	113,007		$	67,595		$	190,019		$	164,249
	Hedge settlements				(577	)		208			3,358			(1,517	)
	Commodity price risk management activities:
		Non-hedge settlements			(262	)		390			822			467
		Non-hedge change in fair value of derivatives			1,031			4,669			(8,222	)		6,766
	Loss on sale of operating assets, net				(1,868	)		—			(1,868	)		—

			Net revenues		111,331			72,862			184,109			169,965

Operating costs and expenses:
	Lease operating expenses				24,229			9,522			43,904			19,995
	Production taxes				5,771			2,415			11,636			5,933
	Transportation costs				1,951			1,290			4,603			2,685
	Exploration				7,700			8,259			18,042			10,870
	Depletion, depreciation and amortization				51,791			20,788			99,380			41,029
	Impairment of unproved properties				5,331			743			6,290			1,748
	Stock compensation expense				(1,787	)		727			94			1,271
	General and administrative				5,495			3,188			11,429			6,710

			Total operating expenses		100,481			46,932			195,378			90,241

			Operating income (loss)		10,850			25,930			(11,269	)		79,724

Other income (expense):
	Interest expense				(7,978	)		(302	)		(16,349	)		(591	)
	Interest income				121			704			201			1,066
	Change in fair value of interest rate swap				—			(50	)		226			(372	)
	Other				803			(50	)		321			(3	)

					(7,054	)		302			(15,601	)		100

Income (loss) before income taxes					3,796			26,232			(26,870	)		79,824
Benefit (provision) for income taxes:
	Current				—			(729	)		—			(2,006	)
	Deferred				(1,386	)		(8,846	)		9,807			(27,130	)

			Total benefit (provision) for income taxes		(1,386	)		(9,575	)		9,807			(29,136	)

	Net income (loss)			$	2,410		$	16,657		$	(17,063	)	$	50,688

Preferred stock dividends					1,191			—			2,381			—

Net income (loss) available to common stockholders				$	1,219		$	16,657		$	(19,444	)	$	50,688

Weighted average number of common shares outstanding:
	Basic				52,128			38,458			52,104			38,477

	Diluted				52,760			39,433			52,104			39,342

Net income (loss) per common share:
	Basic			$	.02		$	.43		$	(.37	)	$	1.32

	Diluted			$	.02		$	.42		$	(.37	)	$	1.29

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

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



				For the Six Months Ended
				June 30,

				2002			2001


				(In thousands)

				(Unaudited)
Cash flows from operating activities:
	Net income (loss)			$	(17,063	)	$	50,688
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Depletion, depreciation and amortization			99,380			41,029
		Exploratory dry hole costs			9,795			6,239
		Impairment of unproved properties			6,290			1,748
		Deferred income taxes			(9,807	)		27,130
		Director retainers settled for stock			20			—
		Stock compensation expense			94			1,271
		Change in fair value of derivatives			7,996			(6,394	)
		Amortization of derivative liabilities			(5,018	)		—
		Amortization of deferred financing fees			540			—
		Loss on sale of operating assets, net			1,868			—
		Changes in assets and liabilities, net of effects of acquisitions:
			Decrease in accounts receivable		5,023			16,951
			Decrease (increase) in prepaid expenses		(2,992	)		588
			Decrease in accounts payable		(17,889	)		(5,846	)
			Increase in ad valorem taxes payable		502			2,400
			Increase (decrease) in income taxes payable		(44	)		306
			Increase (decrease) in accrued expenses		2,582			(1,216	)
			Decrease in other liabilities		(446	)		(69	)

Net cash provided by operating activities					80,831			134,825

Cash flows from investing activities:
		Additions to property and equipment			(71,769	)		(68,458	)
		Proceeds from sales of assets			7,790			654
		Acquisitions of oil and gas properties			(42,303	)		(5,695	)
		Other			(52	)		—

Net cash used in investing activities					(106,334	)		(73,499	)

Cash flows from financing activities:
		Proceeds from issuance of common stock			1,071			247
		Repurchase of common stock			(61	)		—
		Proceeds from issuance of long-term debt			55,000			—
		Preferred stock dividends paid			(2,381	)		—
		Financing fees			(271	)		—

Net cash provided by financing activities					53,358			247

Net increase in cash and cash equivalents					27,855			61,573
Cash and cash equivalents, beginning of period					27,584			20,154

Cash and cash equivalents, end of period				$	55,439		$	81,727

Supplemental cash flow information:
		Cash paid for interest		$	17,664		$	117

		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 necessary to present fairly the financial position of the Company as of June 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. 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:


	June 30,			December 31,
	2002			2001


	(In thousands)
8 1/4% senior subordinated notes due 2011	$	275,537	(1)	$	272,147	(2)
8 7/8% senior subordinated notes due 2007		125,818	(1)		122,077	(2)
Revolving credit facility due on July 1, 2005		90,000			35,000

		491,355			429,224
Less current portion		—			—

	$	491,355		$	429,224

(1) The balances noted above at June 30, 2002 of the 8 1/4% Senior Subordinated Notes and the 8 7/8% Senior Subordinated Notes reflect increases of $537,000 and $1,553,000, 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.

(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)


	*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 June 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 June 30, 2002, the Company had borrowings of $90 million outstanding with a weighted average interest rate of 3.29%, outstanding letters of credit issued of approximately $3.8 million and available unused borrowing capacity of approximately $306.2 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 the 8 7/8% Senior Subordinated Notes has a notional amount of $122.7 million and an expiration date of September 15, 2007. Under this swap agreement, the Company pays the counterparty a variable rate (LIBOR +3.44%) and receives a fixed rate (8 7/8%). Beginning on September 15, 2002 the counterparty has the option to terminate the swap early on any date subject to an early termination fee ranging from 4.438% at

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

September 15, 2002 to 0% on or after September 15, 2005. The early termination dates and fees mirror the prepayment terms and prepayment penalties included in the indenture related to the 8 7/8% Senior Subordinated Notes. 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 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 $0.6 million hedging loss and $3.4 million hedging gain for the three and six months ended June 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 $2.8 million and $1.3 million for the three and six months ended June 30, 2002, respectively.

For the three and six months ended June 30, 2002, the Company recorded non-hedge CPRM settlements of ($0.3) million and $0.8 million, respectively, and an unrealized change in fair value of non-hedge derivatives of $1.0 million and ($8.2) million, respectively, which included a $0.2 million ineffectiveness loss. The non-hedge CPRM settlements include realized losses of $1.1 million and $0.2 million for the three and six months ended June 30, 2002, respectively.

The Company recognized decreases and increase in oil and natural gas revenues of ($0.6) million and $0.2 million from settled hedging agreements for the three months ended June 30, 2002 and 2001, respectively and $3.4 and ($1.5) million for the six months end June 30, 2002 and 2001, respectively.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of June 30, 2002, the Company had approximately 1.7 Mbbls of oil and 12.0 Bcf of natural gas subject to CPRM contracts for the remainder of 2002. The 2002 contracts have weighted average floor prices of $22.13 per barrel and $2.91 per Mmbtu, with weighted average ceiling prices of $25.03 per barrel and $3.10 per Mmbtu, respectively. The Company has approximately 3.1 Mbbls of oil and 21.2 Bcf of natural gas subject to CPRM contracts for 2003. The 2003 contracts have weighted average floor prices of $22.20 per barrel and $3.58 per Mmbtu, with weighted average ceiling prices of $24.22 per barrel and $4.61 per Mmbtu, respectively. The contracts discussed above represent both the Company’s hedge and non-hedge positions as of June 30, 2002.

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


Hedges				2002		2003

	Gas
		Price Swaps Sold — receive fixed price (thousand Mmbtu)(1)			4,578		4,380
			Average price, per Mmbtu	$	2.96	$	4.00
		Collars Sold (thousand Mmbtu)(2)			3,070		8,833
			Average floor price, per Mmbtu	$	2.53	$	3.55
			Average ceiling price, per Mmbtu	$	3.10	$	4.81
		Puts Purchased (thousand Mmbtu)(3)			1,840		—
			Average price, per Mmbtu	$	3.13		—
	Oil
		Price Swaps Sold — receive fixed price (Mbbls)(1)			270		785
			Average price, per bbl	$	20.78	$	20.98
		Collars Sold (Mbbls)(2)			90		—
			Average floor price, per bbl	$	20.00		—
			Average ceiling price, per bbl	$	26.75		—
Non-Hedges
	Gas
		Calls Sold (thousand Mmbtu)(3)			1,288		—
			Average price, per Mmbtu	$	3.27		—
		Three-way Collars (Mmbtu)(2)(4)			1,200		8,030
			Three-way average floor price, per Mmbtu	$	2.40	$	2.22
			Average floor price, per Mmbtu	$	3.00	$	3.39
			Average ceiling price, per Mmbtu	$	3.40	$	4.73
	Oil
		Calls Sold (Mbbls)(3)			90		—
			Average price, per bbl	$	22.00		—
		Price Swaps Sold — receive fixed price (Mbbls)(1)			150		300
			Average price, per bbl	$	18.86	$	18.86
		Three-way Collars (Mbbls)(2)(4)			1,100		1,995
			Three-way average floor price, per bbl	$	18.92	$	18.91
			Average floor price, per bbl	$	23.09	$	23.18
			Average ceiling price, per bbl	$	27.02	$	26.30

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(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. Accumulated Other Comprehensive Income

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 six months ended June 30, 2002 and 2001 are as follows (in thousands):


			Six Months Ended			Six Months Ended
			June 30, 2002			June 30, 2001

Net income (loss)			$	(19,444	)	$	50,688
Other comprehensive income
	Cumulative effect of change in accounting principle			(3,100	)		(3,100	)
	Change in fair value of derivative hedging instruments			6,782			5,744
	Enron non-cash settlements reclassified to income			67			—
	Hedge settlements reclassified to income			(3,528	)		(963	)

		Other comprehensive income		221			1,681
Comprehensive income (loss)			$	(19,223	)	$	52,369

6. 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.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.


	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.

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.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7. 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 Six Months Ended June 30,

						Gulf of			Corporate &
	Northern		Southern			Mexico			Unallocated			Consolidated


	(In thousands)
2002
Revenues(1)	$	58,310	$	69,949		$	59,892		$	(4,042	)	$	184,109
DD&A		22,503		38,293			38,358			226			99,380
Profit (loss)		6,452		(2,990	)		(10,254	)		(4,477	)		(11,269	)
Expenditures for assets, net		57,285		13,724			42,016			1,047			114,072

2001
Revenues(1)		47,508		22,265			94,476			5,716			169,965
DD&A		7,889		4,737			28,233			170			41,029
Profit (loss)		21,047		11,703			45,774			1,200			79,724
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.



	For the Three Months Ended June 30,

					Gulf of		Corporate &
	Northern		Southern		Mexico		Unallocated		Consolidated


	(In thousands)
2002
Revenues(1)	$	33,007	$	40,112	$	38,021	$	191	$	111,331
DD&A		11,432		18,519		21,722		118		51,791
Profit (loss)		5,514		3,233		357		1,746		10,850
Expenditures for assets, net		10,091		4,719		23,575		682		39,067

2001
Revenues(1)		20,283		8,687		38,624		5,268		72,862
DD&A		4,024		2,518		14,161		85		20,788
Profit (loss)		7,395		3,566		11,973		2,996		25,930
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.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8. 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.

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

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

June 30, 2002


				Parent			Subsidiary
				Company			Guarantors			Eliminations			Consolidated


				(In thousands)
ASSETS
Current Assets:
	Cash and cash equivalents			$	12,135		$	43,304		$	—		$	55,439
	Accounts receivable, net				19,269			38,984			—			58,253
	Intercompany receivable				419,054			—			(419,054	)		—
	Derivative assets				4,081			253			—			4,334
	Prepaid expenses				2,912			5,500			—			8,412

			Total current assets		457,451			88,041			(419,054	)		126,438

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties			305,687			1,214,907			—			1,520,594
		Unproved properties			30,812			57,299			—			88,111
	Building and other office furniture and equipment				594			8,551			—			9,145

					337,093			1,280,757			—			1,617,850
	Less accumulated depletion, depreciation and amortization				(104,019	)		(277,956	)		—			(381,975	)

			Net property and equipment		233,074			1,002,801			—			1,235,875

Other assets:
	Long-term derivative assets				2,522			1,300			—			3,822
	Goodwill				—			246,712			—			246,712
	Other assets				9,396			80			—			9,476

			Total other assets		11,918			248,092			—			260,010

			Total assets	$	702,443		$	1,338,934		$	(419,054	)	$	1,622,323

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable			$	9,659		$	23,737		$	—		$	33,396
	Accrued expenses				12,073			19,046			—			31,119
	Ad valorem taxes payable				—			9,817			—			9,817
	Intercompany payable				—			419,054			(419,054	)		—
	Derivative liabilities				14,319			—			—			14,319
	Income taxes payable				(248	)		767			—			519
	Other current liabilities				—			—			—			—

			Total current liabilities		35,803			472,421			(419,054	)		89,170

Long-term debt					365,538			125,817			—			491,355
Deferred income taxes					17,998			125,231			—			143,229
Long-term derivative liabilities					3,934			—			—			3,934
Other liabilities					—			1,185			—			1,185

			Total liabilities		423,273			724,654			(419,054	)		728,873

Stockholders’ equity:
	Preferred stock				—			29			—			29
	Common stock				386			139			(3	)		522
	Additional paid-in capital				276,851			602,407			3			879,261
	Treasury stock				(469	)		—			—			(469	)
	Retained earnings				2,181			11,705			—			13,886
	Accumulated other comprehensive income				221			—			—			221

			Total stockholders’ equity		279,170			614,280			—			893,450

			Total liabilities and stockholders’ equity	$	702,443		$	1,338,934		$	(419,054	)	$	1,622,323

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Six Months Ended June 30, 2002


			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


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

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

Operating costs and expenses:
	Lease operating expense			6,134			37,770			—		43,904
	Production taxes			3			11,633			—		11,636
	Transportation costs			22			4,581			—		4,603
	Exploration			11,428			6,614			—		18,042
	Depletion, depreciation and amortization			20,920			78,460			—		99,380
	Impairment of unproved properties			236			6054			—		6,290
	Stock compensation expense			94			—			—		94
	General and administrative			3,132			8,297			—		11,429

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

		Operating income (loss)		(14,869	)		3,600			—		(11,269	)

Other income (expense):
	Interest expense			(10,841	)		(5,508	)		—		(16,349	)
	Interest income			66			135			—		201
	Change in fair value of interest rate swap			—			226			—		226
	Other			466			(145	)				321

Income (loss) before income taxes				(25,178	)		(1,692	)		—		(26,870	)

Provision for income taxes:
	Current			—			—			—		—
	Deferred			9,189			618			—		9,807

		Total provision for income taxes		9,189			618			—		9,807
Net loss				(15,989	)		(1,074	)		—		(17,063	)

Preferred stock dividends				2,381			—			—		2,381

Net loss available to common stock			$	(18,370	)	$	(1,074	)	$	—	$	(19,444	)

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Six Months Ended June 30, 2002


					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)
Cash flows from operating activities:
	Net loss				$	(15,989	)	$	(1,074	)	$	—		$	(17,063	)
	Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
		Depletion, depreciation and amortization				20,920			78,460			—			99,380
		Exploration dry hole costs				4,613			5,182			—			9,795
		Impairment of unproved properties				236			6,054			—			6,290
		Deferred income taxes				(9,189	)		(618	)		—			(9,807	)
		Director retainers settled for stock				20			—			—			20
		Stock compensation expense				94			—			—			94
		Change in fair value of derivatives				7,996			—			—			7,996
		Amortization of derivative liabilities				(5,018	)		—			—			(5,018	)
		Amortization of deferred financing fees				705			(165	)		—			540
		Loss on sale of operating assets, net				—			1,868			—			1,868
		Changes in asset and liabilities, net of effects of acquisitions:
			Decrease (increase) in accounts receivable			(582	)		5,605			—			5,023
			Decrease in prepaid expenses			(802	)		(2,190	)		—			(2,992	)
			Decrease in accounts payable			(4,594	)		(13,295	)		—			(17,889	)
			Increase in ad valorem taxes payable			1			501			—			502
			Decrease in income taxes payable			—			(44	)		—			(44	)
			Increase in accrued expenses			685			1,897			—			2,582
			Decrease in other liabilities			—			(446	)		—			(446	)

				Net cash provided by (used in) operating activities		(904	)		81,735			—			80,831

Cash flows from investing activities:
	Additions to property and equipment					(31,459	)		(40,310	)		—			(71,769	)
	Proceeds from sales of assets					—			7,790			—			7,790
	Increase in intercompany receivable					(22,336	)		—			22,336			—
	Acquisitions of oil and gas properties					(328	)		(41,975	)		—			(42,303	)
	Other								(52	)		—			(52	)

				Net cash provided by (used in) investing activities		(54,123	)		(74,547	)		22,336			(106,334	)

Cash flows from financing activities:
	Proceeds from issuance of common stock					1,071			—			—			1,071
	Repurchase of common stock					(61	)		—			—			(61	)
	Proceeds from issuance of long-term debt					55,000			—			—			55,000
	Preferred stock dividends paid					(2,381	)		—			—			(2,381	)
	Financing fees					(271	)		—			—			(271	)
	Increase in intercompany payable					—			22,336			(22,336	)		—

				Net cash provided by (used in) financing activities		53,358			22,336			(22,336	)		53,358

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

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

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2001


				Parent			Subsidiary
				Company			Guarantors			Eliminations			Consolidated


				(In thousands)
ASSETS
Current Assets:
	Cash and cash equivalents			$	13,804		$	13,780		$	—		$	27,584
	Accounts receivable, net				18,687			43,121			—			61,808
	Intercompany receivable				387,164			—			(387,164	)		—
	Derivative assets				—			7,832			—			7,832
	Prepaid expenses				2,110			3,364			—			5,474

			Total current assets		421,765			68,097			(387,164	)		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	$	654,912		$	1,336,468		$	(387,164	)	$	1,604,216

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable			$	14,254		$	33,647		$	—		$	47,901
	Accrued expenses				7,648			22,646			—			30,294
	Ad valorem taxes payable				—			6,930			—			6,930
	Intercompany payable				—			387,164			(387,164	)		—
	Derivative liabilities				—			3,289			—			3,289
	Income taxes payable				(131	)		681			—			550
	Other current liabilities				—			369			—			369

			Total current liabilities		21,771			454,726			(387,164	)		89,333

Long-term debt					307,147			122,077			—			429,224
Deferred income taxes					27,063			130,942			—			158,005
Long-term derivative liabilities					2,853			3,103			—			5,956
Other liabilities					—			1,402			—			1,402

			Total liabilities		358,834			712,250			(387,164	)		683,920

Stockholders’ equity:
	Preferred stock				—			29			—			29
	Common stock				385			139			(3	)		521
	Additional paid-in capital				275,550			602,407			3			877,960
	Treasury stock				(408	)		—			—			(408	)
	Retained earnings				20,551			12,779			—			33,330
	Accumulated other comprehensive income				—			8,864			—			8,864

			Total stockholders’ equity		296,078			624,218			—			920,296

			Total liabilities and stockholders’ equity	$	654,912		$	1,336,468		$	(387,164	)	$	1,604,216

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Six Months Ended June 30, 2001


			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


			(In thousands)
Operating revenues:
	Oil and natural gas sales		$	58,699		$	105,550		$	—	$	164,249
	Hedge settlements			—			(1,517	)		—		(1,517	)
	Non-hedge settlements			—			467			—		467
	Non-hedge change in fair value of derivatives			—			6,766			—		6,766

		Net revenues		58,699			111,266			—		169,965

Operating costs and expenses:
	Lease operating expense			2,938			17,057			—		19,995
	Production taxes			6			5,927			—		5,933
	Transportation costs			384			2,301			—		2,685
	Exploration			5,014			5,856			—		10,870
	Depletion, depreciation and amortization			20,162			20,867			—		41,029
	Impairment of unproved properties			933			815			—		1,748
	Stock compensation expense			1,271			—			—		1,271
	General and administrative			3,471			3,239			—		6,710

		Total operating expenses		34,179			56,062			—		90,241

		Operating income		24,520			55,204			—		79,724

Other income (expense):
	Interest expense			—			(591	)		—		(591	)
	Interest income			770			296			—		1,066
	Change in fair value of interest rate swap			—			(372	)		—		(372	)
	Other			58			(61	)		—		(3	)

	Income before income taxes			25,348			54,476			—		79,824

Provision for income taxes:
	Current			—			(2,006	)		—		(2,006	)
	Deferred			(9,252	)		(17,878	)		—		(27,130	)

		Total provision for income taxes		(9,252	)		(19,884	)		—		(29,136	)

Net income			$	16,096		$	34,592		$	—	$	50,688

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Six Months Ended June 30, 2001


					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)
Cash flows from operating activities:
	Net income				$	16,096		$	34,592		$	—		$	50,688
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depletion, depreciation and amortization				20,162			20,867			—			41,029
		Exploration dry hole costs				1,153			5,086			—			6,239
		Impairment of unproved properties				932			816			—			1,748
		Deferred income taxes				9,252			17,878			—			27,130
		Stock compensation expense				1,271			—			—			1,271
		Change in fair value of derivatives				—			(6,394	)		—			(6,394	)
		Changes in asset and liabilities, net of effects of Acquisitions:
			Decrease in accounts receivable			4,249			12,702			—			16,951
			Decrease in prepaid expenses			518			70			—			588
			Increase (decrease) in accounts payable			1,878			(7,724	)		—			(5,846	)
			Increase in ad valorem taxes payable			3			2,397			—			2,400
			Increase in income taxes payable			—			306			—			306
			Increase (decrease) in accrued expenses			250			(1,466	)		—			(1,216	)
			Decrease in other liabilities			—			(69	)		—			(69	)

				Net cash provided by operating activities		55,764			79,061			—			134,825

Cash flows from investing activities:
	Additions to property and equipment					(33,534	)		(34,924	)		—			(68,458	)
	Proceeds from sale of assets					—			654			—			654
	Decrease in intercompany receivable					25,429			—			(25,429	)		—
	Acquisitions of oil and gas properties					—			(5,695	)		—			(5,695	)
	Other					—			—			—			—

				Net cash used in investing activities		(8,105	)		(39,965	)		(25,429	)		(73,499	)

Cash flows from financing activities:
	Proceeds from issuance of common stock					247			—			—			247
	Decrease in intercompany payable					—			(25,429	)		25,429			—

				Net cash provided by (used in) financing activities		247			(25,429	)		25,429			247

Net increase in cash and cash equivalents						47,906			13,667			—			61,573
Cash and cash equivalents, beginning of period						12,458			7,696			—			20,154

Cash and cash equivalents, end of period					$	60,364		$	21,363		$	—		$	81,727


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 purchases 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 Six Months
		Ended June 30,					Ended June 30,

		2002			2001		2002		2001


					(In thousands)
Production
	Oil (Mbbls)		2,092			912		3,897		1,838
	Natural gas (Mmcf)		20,551			10,746		40,628		21,275
	Mmcfe		33,103			16,218		64,010		32,303
Average Daily Production
	Oil (Mbbls/d)		23.0			10.0		21.5		10.2
	Natural gas (Mmcf/d)		225.8			118.1		224.5		117.5
	Mmcfe/d		363.8			178.2		353.6		178.5
Average Prices
	Oil (per bbl)	$	23.88		$	23.97	$	21.30	$	24.78
	Natural gas (per Mcf)		3.07			4.26		2.64		5.58
Hedging effect (per Mcfe)			(0.02	)		0.01		0.05		(0.04	)
Oil and natural gas sales		$	113,007		$	67,595	$	190,019	$	164,249
Lease operating expense			24,229			9,522		43,904		19,995
	Per Mcfe		0.73			0.59		0.69		0.62
General and administrative costs			5,495			3,188		11,429		6,710
	Per Mcfe		0.17			0.20		0.18		0.21
Depletion, depreciation and amortization			51,791			20,788		99,380		41,029
	Per Mcfe		1.56			1.28		1.55		1.27

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

Revenues. Oil and natural gas revenues for the three months ended June 30, 2002 increased by $45.4 million, or 67%, from $67.6 million to $113.0 million, compared to the three months ended June 30, 2001. Production from the acquired Belco properties accounted for $43.8 million of the increase. Production volumes increased by 16.9 Bcfe, or 104%, from 16.2 Bcfe to 33.1 Bcfe. Acquired Belco properties accounted for 13.2 Bcfe of the increase. Production volumes also increased 2.7 Bcfe from recent discoveries in the Gulf of Mexico and production volumes increased 0.9 Bcfe due to an acquisition of properties in the Williston Basin in March 2002. The increase in production volumes was partially offset by decreases of 119% and 9% in realized natural gas prices and oil prices, respectively, excluding the effects of hedging. For the three months ended June 30, 2002, hedging transactions had the effect of decreasing oil and natural gas revenues by $0.6 million, or $0.02 per Mcfe, and for the three months ended June 30, 2001 had the effect of increasing oil and natural gas revenues by $0.2 million, or $0.01 per Mcfe.

Oil and natural gas revenues for the six months ended June 30, 2002 increased by $25.8 million, or 16%, from $164.2 million to $190.0 million, over the comparable period in 2001. Production from the acquired Belco properties accounted for an increase of $77.9 million. The increase in production volumes, including production attributable to Belco properties, was partially offset by decreases of 53% and 14% in realized natural gas prices and oil prices, respectively, excluding the effects of hedging. Production volumes increased 31.7 Bcfe from 32.3 Bcfe in 2001 to 64.0 Bcfe in 2002 (acquired Belco properties accounted for 26.7 Bcfe of the increase). Production volumes also increased 3.9 Bcfe from recent discoveries in the Gulf of Mexico and production volumes increased 1.2 Bcfe due to an acquisition of properties in the Williston Basin in March 2002. Hedging transactions had the effect of increasing oil and natural gas revenues by $3.4 million, or $0.05 per Mcfe, and reducing oil and natural gas revenues by $1.5 million, or $0.04 per Mcfe, for the six months ended June 30, 2002 and 2001, respectively.

Commodity Price Risk Management Activities. The Company recorded a gain of $1.0 million in the non-hedge change in fair value of derivatives for the three months ended June 30, 2002, compared to a $4.7 million gain for the three months ended June 30, 2001. Non-hedge settlements of derivatives for the three months ended June 30, 2002 resulted in a loss of $0.3 million, compared to a gain of $0.4 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 six months ended June 30, 2002, the Company recorded a loss of $8.2 million in the non-hedge change in fair value of derivatives, compared to a gain of $6.8 million for the same period in 2001. Non-hedge settlements of derivatives for the six months ended June 30, 2002 was a gain of $0.8 million compared to a gain of $0.5 million for the three months ended June 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.

Loss on Sale of Operating Assets, Net. For the three and six months ended June 30, 2002, we recorded a net loss on sales of non-core operating assets of $1.9 million related to the sales of onshore properties (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 six months ended June 30, 2001 there were no dispositions of operating assets.

Lease Operating Expense. Lease operating expense for the three months ended June 30, 2002 increased by $14.7 million, or 154%, from $9.5 million to $24.2 million, compared to the same period in 2001. Lease operating expenses from the acquired Belco properties accounted for $10.1 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 recent acquisition in the Williston Basin. On a per Mcfe basis, lease operating expense increased from $0.59 to $0.73 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 June 30, 2002 at a rate of $0.10 per Mcfe.

Lease operating expense for the six months ended June 30, 2002 increased by $23.9 million, or 120%, from $20.0 million to $43.9 million, compared to the same period in 2001. Lease operating expenses from the acquired Belco properties accounted for $19.3 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 recent acquisition in the Williston Basin. On a per Mcfe basis, lease operating expense increased from $0.62 to $0.69 in the 2001 and 2002 periods, respectively. The increase on a per Mcfe basis was primarily due to nonrecurring workover expense performed in the six months ended June 30, 2002 at a rate of $0.07 per Mcfe.

Production Taxes. Production taxes for the three months ended June 30, 2002 increased by $3.4 million, or 139%, from $2.4 million to $5.8 million, compared to the same period in 2001. Production taxes on the acquired Belco properties accounted for $3.3 million of the increase. As a percent of oil and natural gas revenues (excluding the effects of hedges), production taxes increased from 3.6% to 5.1%. The increase in production taxes as a percent of revenue is primarily the result of the Belco acquisition, which increased the number of onshore properties that are subject to production taxes.

Production taxes for the six months ended June 30, 2002 increased by $5.7 million, or 96%, from $5.9 million to $11.6 million, compared to the same period in 2001. Production taxes on the acquired Belco properties caused an increase of $7.3 million. The increase from the Belco properties was partially offset by the decrease in oil and natural gas revenues. As a percent of oil and natural gas revenues (excluding the effects of hedges), production taxes increased from 3.6% to 6.1%. The increase in production taxes as a percent of revenue is primarily the result of the Belco acquisition, which increased the number of onshore properties that are subject to production taxes.

Transportation Costs. Transportation costs for the three months ended June 30, 2002 increased by $0.7 million, or 51%, from $1.3 million to $2.0 million, compared to the same period in 2001. The acquired Belco properties accounted for the increase of $0.7 million.

Transportation costs for the six months ended June 30, 2002 increased by $1.9 million, or 71%, from $2.7 million to $4.6 million, compared to the same period in 2001. Transportation costs from the acquired Belco properties accounted for $1.4 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 June 30, 2002 decreased by $0.6 million, or 7%, from $8.3 million to $7.7 million, compared to the same period in 2001. Dry hole costs were $5.0 million for both periods as a result of three unsuccessful exploratory wells, which included one dry hole where another partner carried us on the drilling, drilled in the Gulf of Mexico during the three months ended June 30, 2002 and 2001. The decrease in exploration costs of $0.6 million was primarily attributable to the timing of purchases of Gulf of Mexico 3-D seismic data.

Exploration costs for the six months ended June 30, 2002 increased by $7.1 million, or 66%, from $10.9 million to $18.0 million, compared to the same period in 2001. Dry hole costs for the six months ended June 30, 2002 increased $3.6 million, compared to the same period in 2001. The increase was attributable to four unsuccessful exploratory wells, which included one dry hole where another partner carried us on the drilling, drilled in the Gulf of Mexico and two unsuccessful onshore exploratory wells drilled in 2002 compared to three unsuccessful offshore exploratory wells drilled at a lower cost in 2001. Purchases of Gulf of Mexico 3-D seismic data increased $3.3 million during the six months ended June 30, 2002 compared to the same period in 2001.

Depletion, Depreciation and Amortization (DD&A) Expense. DD&A expense increased $31.0 million during the three months ended June 30, 2002, from $20.8 million to $51.8 million, compared to the same period in 2001. Depletion related to the acquired Belco properties caused DD&A expense to increase $21.6 million. An increase of $4.7 million is related to recent discoveries in the Gulf of Mexico and the remaining increase was primarily due to additions and acquisitions of oil and natural gas properties since June 30, 2001. On a per Mcfe basis, DD&A expense increased from $1.28 to $1.56 primarily due to recent discoveries in the Gulf of Mexico and acquired Belco properties, which have higher DD&A expense per Mcfe compared to properties we owned in the same period in 2001.

DD&A expense increased $58.4 million during the six months ended June 30, 2002, from $41.0 million to $99.4 million, compared to the same period in 2001. Depletion related to the acquired Belco properties caused DD&A expense to increase $43.4 million. Recent discoveries in the Gulf of Mexico caused DD&A expense to

increase $9.2 million. The remaining increase was primarily due to additions and acquisitions of oil and natural gas properties since June 30, 2001. On a per Mcfe basis, DD&A expense increased from $1.27 to $1.55 primarily due to recent discoveries in the Gulf of Mexico and acquired Belco properties, which have higher DD&A expense per Mcfe compared to properties we owned in the same period in 2001.

Impairment of Unproved Properties. During the three months ended June 30, 2002, we recognized unproved property impairments of $5.3 million. The impairments consisted of $2.5 million for leases held in Wyoming, $1.6 million for leases held in Texas and $0.5 million for leases held in North Dakota and the remaining $0.7 million were associated with various leases held offshore, in Louisiana and in various other states. Unproved properties acquired from Belco accounted for $5.0 million of the impairments. These impairments were recognized as a result of an assessment of the exploration opportunities existing on such properties. During the three months ended June 30, 2001, we recognized unproved property impairments of $0.7 million on offshore leases.

During the six months ended June 30, 2002, we recognized unproved property impairments of $6.3 million. The impairments consisted of $2.5 million for leases held in Wyoming, $1.6 million for leases held in Texas, $1.2 million for offshore leases and $1.0 million for leases held in North Dakota, Louisiana and various other states. Unproved properties acquired from Belco accounted for $5.0 million of the impairments. These impairments were recognized as a result of an assessment of the exploration opportunities existing on such properties. During the six months ended June 30, 2001, we recognized unproved property impairments of $1.7 on offshore leases.

Stock Compensation Expense. During the three months ended June 30, 2002, we reduced stock compensation expense related to certain stock options previously recognized in prior periods by $1.9 million as a result of applying FASB Interpretation No. 44 and recorded $0.1 million in expense related to the issuance of restricted stock. During the three months ended June 30, 2001, we recorded $0.6 million of stock compensation expense related to certain stock options as a result of applying FASB Interpretation No. 44 and $0.1 million in expense related to the issuance of restricted stock.

During the six months ended June 30, 2002, we recorded no stock compensation expense 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 six months ended June 30, 2001, we recorded $1.1 million of stock compensation expense related to certain stock options as a result of applying FASB Interpretation No. 44 and $0.2 million in expense related to the issuance of restricted stock.

General and Administrative (G&A) Expense. G&A expense increased $2.3 million, or 72%, during the three months ended June 30, 2002, from $3.2 million to $5.5 million, compared to the same period in 2001. The Merger accounted for $1.7 million of the increase. The majority of the remaining increase was related to payroll costs such as salaries and benefits, resulting from an increase in staff. G&A expense per Mcfe of production decreased to $0.17 in the second quarter of 2002 from $0.20 for the second quarter of 2001.

G&A expense increased $4.7 million, or 70%, during the six months ended June 30, 2002, from $6.7 million to $11.4 million, compared to the same period in 2001. The Merger accounted for $3.6 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. G&A expense per Mcfe of production decreased to $0.18 for the six months ended June 30, 2002 from $0.21 for the comparable period in 2001.

Other Income (Expense). Other income (expense) for the three months ended June 30, 2002 was ($7.1) million compared to $0.3 million for the three months ended June 30, 2001. Interest expense increased $7.7 million during the three months ended June 30, 2002, compared to the same period in 2001, as a result of the increase in the debt balances relating to the Merger.

Other income (expense) for the six months ended June 30, 2002 was ($15.6) million compared to $0.1 million for the six months ended June 30, 2001. Interest expense increased $15.8 million during the six months ended June 30, 2002, compared to the same period in 2001, as a result of the increase in the debt balances relating to the Merger.

Income Taxes. We recorded a deferred income tax expense of $1.4 million for the three months ended June 30, 2002. For the three months ended June 30, 2001, we recorded income tax expense of $9.6 million ($8.9 million deferred and $0.7 million current).

We recorded a deferred income tax benefit of $9.8 million for the six months ended June 30, 2002 due to a net loss. For the six months ended June 30, 2001, we recorded income tax expense of $29.1 million ($27.1 million deferred and $2.0 million current).

Net Income. Net income for the three months ended June 30, 2002 was $2.4 million compared to net income of $16.7 million for the three months ended June 30, 2001. The variance was primarily attributable to increases in net revenues of $38.5 million and decrease in income tax expense of $8.2 million offset by increases of $53.6 million in operating expenses and other expense of $7.4 million.

Net loss for the six months ended June 30, 2002 was $17.1 million compared to net income of $50.7 million for the six months ended June 30, 2001. The variance was primarily attributable to increases in net revenues of $14.1 million and income tax benefit of $38.9 million offset by increases of $105.1 million in operating expenses and other expense of $15.7 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 $80.8 million for the six months ended June 30, 2002 compared to $134.8 million for the six months ended June 30, 2001. Operating cash flow in the six 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 $106.3 million for the six months ended June 30, 2002 compared to $73.5 million for the six months ended June 30, 2001. Of this total, $71.8 million was used for exploitation and exploration activities and $42.3 million was used for acquisitions, offset by proceeds from sales of properties of $7.8 million. Investing activities for the six months ended June 30, 2001 included $68.5 million for exploitation and exploration activities and $5.7 million for acquisitions, offset by proceeds from sales of properties of $0.7 million.

Net cash provided by financing activities was $53.4 million for the six months ended June 30, 2002 compared to $0.2 million for the six months ended June 30, 2001. Financing activities for the six months ended June 30, 2002 consisted of $55.0 million in borrowings utilized for the acquisition and development of oil and natural gas properties and $1.1 million from issuance of common stock offset by a $2.4 million preferred stock dividend payment.

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 June 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 June 30, 2002, we had borrowings and letters of credit issued of approximately $93.8 million outstanding under the Revolving Credit Facility with an average interest rate of 3.29% and available unused borrowing capacity of approximately $306.2 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.


	*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 six months of 2002 we had acquisitions of $42.3 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 six months of 2002, we had capital expenditures of $71.8 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 June 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 June 30, 2002. For more information on our interest rate swaps in effect as of June 30, 2002, see “Note 3” to our consolidated financial statements in Item 1 of this Report.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

None.

Item 2. Changes in Securities and Use of Proceeds

(a) During the quarter ended June 30, 2002, we issued 52,557 shares of Common Stock, including 29,276 shares issued in connection with the exercise of options granted pursuant to the EPGC 2000 Stock Option Plan and 22,206 shares issued in connection with the exercise of options granted pursuant to the Belco 1996 Stock Incentive Plan.

(b) On June 12, 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

(a) The Company held its Annual Meeting of Stockholders on May 20, 2002.

(b) Laurence D. Belfer, James M. Funk, William F. Wallace, Peter R. Hearl and Robert A. Haas were elected to continue to serve as directors of the Company.

Proposal No. 1 — Election of Directors.


Director	For		Withheld

Laurence D. Belfer		44,028,311		2,085,081
James M. Funk		44,564,839		1,421,022
William F. Wallace		45,769,536		343,856
Peter R. Hearl		45,775,476		337,916
Robert A. Haas		45,778,476		334,916

Proposal No. 2 — To ratify the appointment of KPMG LLP as independent public accountant of the Company for the fiscal year ending December 31, 2002.


For		Against		Abstain		Withheld

	45,924,885		58,759		1,217		128,531

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).
	*10.1					Form of Indemnification Agreement between the Company and its directors and officers.
	*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:

(i) A report on Form 8-K, filed with the Securities and Exchange Commission on April 15, 2002, regarding changes in the Company’s independent public accountants.

* 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: August 14, 2002

By: /s/ LON MCCAIN

    Name: Lon McCain

    Title: Vice President, Chief Financial Officer

                  and Treasurer

Date: August 14, 2002

EXHIBIT INDEX


Exhibit
Number		Description

	2.1	Agreement and Plan of Merger, dated as of March 9, 2000, by and among Westport Oil and Gas Company, Inc., Westport Energy Corporation, Equitable Production Company, Equitable Production (Gulf) Company and EPGC Merger Sub Corporation (incorporated by reference to Exhibit 2.1 to the registration statement on Form S-1, Registration No. 333-40422), filed 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).
	*10.1	Form of Indemnification Agreement between the Company and its directors and officers.
	*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.


(1)	The balances noted above at June 30, 2002 of the 8 1/4% Senior Subordinated Notes and the 8 7/8% Senior Subordinated Notes reflect increases of $537,000 and $1,553,000, 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.

(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.