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, 2003

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from to .

Commission file number 001-14256

Westport Resources Corporation

(Exact name of registrant as specified in its charter)


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

1670 Broadway Street, Suite 2800

Denver, Colorado 80202-4800

(Address of principal executive offices)

(Zip Code)

(303) 573-5404

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o

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

TABLE OF CONTENTS


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

WESTPORT RESOURCES CORPORATION

TABLE OF CONTENTS


		Page

PART I — FINANCIAL INFORMATION			1
Item 1.	Financial Statements		1
	Consolidated Balance Sheets as of June 30, 2003 (unaudited) and December 31, 2002		1
	Consolidated Statements of Operations for the three months and six months ended June 30, 2003 and 2002 (unaudited)		2
	Consolidated Statements of Cash Flows for the six months ended June 30, 2003 and 2002 (unaudited)		3
	Notes to Consolidated Financial Statements (unaudited)		4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		37
Item 4.	Controls and Procedures		37
PART II — OTHER INFORMATION			38
Item 1.	Legal Proceedings		38
Item 2.	Changes in Securities and Use of Proceeds		38
Item 3.	Defaults Upon Senior Securities		39
Item 4.	Submission of Matters to a Vote of Security Holders		39
Item 5.	Other Information		39
Item 6.	Exhibits and Reports on Form 8-K		39
Signatures			41

PART I — FINANCIAL INFORMATION


Item 1.	*Financial Statements*

WESTPORT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS


				June 30,			December 31,
				2003			2002

				(Unaudited)

				(In thousands,
				except share data)
ASSETS
Current Assets:
	Cash and cash equivalents			$	65,865		$	42,761
	Accounts receivable, net				81,520			73,549
	Derivative assets				8,401			14,861
	Prepaid expenses				14,771			13,358

			Total current assets		170,557			144,529

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties			2,269,540			2,138,471
		Unproved properties			94,944			104,430

					2,364,484			2,242,901
	Less accumulated depletion, depreciation and amortization				(592,905	)		(481,396	)

		Net oil and gas properties			1,771,579			1,761,505

	Field services assets				39,198			39,185
	Less accumulated depreciation				(560	)		—

		Net field services assets			38,638			39,185

	Building and other office furniture and equipment				10,274			9,686
	Less accumulated depreciation				(4,246	)		(3,933	)

		Net building and other office furniture and equipment			6,028			5,753

Other assets:
	Long-term derivative assets				17,792			14,824
	Goodwill				244,647			246,712
	Other assets				19,697			21,033

			Total other assets		282,136			282,569

			Total assets	$	2,268,938		$	2,233,541


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities Accounts payable				$	48,572		$	51,158
	Accrued expenses				41,484			39,209
	Ad valorem taxes payable				15,217			8,988
	Derivative liabilities				98,173			56,156
	Income taxes payable				83			86
	Current asset retirement obligation				7,960			—

			Total current liabilities		211,489			155,597
Long-term debt					731,879			799,358
Deferred income taxes					114,672			124,530
Long term derivative liabilities					42,632			21,305
Long term asset retirement obligation					50,143			745

			Total liabilities		1,150,815			1,101,535

Stockholders’ equity:
	6 1/2% convertible preferred stock, $.01 par value; 10,000,000 shares authorized; 2,930,000 issued and outstanding at June 30, 2003 and December 31, 2002, respectively				29			29
	Common stock, $0.01 par value; 100,000,000 authorized; 67,237,667 and 66,823,830 shares issued and outstanding at June 30, 2003 and December 31, 2002, respectively				672			668
	Additional paid-in capital				1,156,031			1,150,345
	Treasury stock-at cost; 35,681 and 33,617 shares at June 30, 2003 and December 31, 2002, respectively				(512	)		(469	)
	Retained earnings				32,469			2
	Accumulated other comprehensive income
		Deferred hedge loss, net			(70,405	)		(18,408	)
		Cumulative translation adjustment			(161	)		(161	)

		Total stockholders’ equity			1,118,123			1,132,006

	Total liabilities and stockholders’ equity			$	2,268,938		$	2,233,541

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

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS



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

				2003			2002			2003			2002


				(In thousands, except per share amounts)
				(Unaudited)
Operating revenues:
	Oil and natural gas sales			$	195,584		$	113,007		$	414,003		$	190,019
	Hedge settlements				(23,439	)		(577	)		(63,885	)		3,358
	Gathering income				783			—			1,992			—
	Commodity price risk management activities:
		Non-hedge settlements			723			(262	)		723			822
		Non-hedge change in fair value of derivatives			902			1,031			3,222			(8,222	)
	Gain (loss) on sale of operating assets, net				6,074			(1,868	)		6,466			(1,868	)

			Net revenues		180,627			111,331			362,521			184,109

Operating costs and expenses:
	Lease operating expenses				26,032			24,229			52,368			43,904
	Production taxes				11,364			5,771			24,422			11,636
	Transportation costs				3,354			1,951			7,378			4,603
	Gathering expenses				552			—			1,648			—
	Exploration				13,624			7,700			25,671			18,042
	Depletion, depreciation and amortization				67,036			51,791			128,101			99,380
	Impairment of proved properties				977			—			977			—
	Impairment of unproved properties				11,693			5,331			15,173			6,290
	Stock compensation expense, net				2,153			(1,787	)		2,150			94
	General and administrative				7,543			5,495			14,771			11,429

			Total operating expenses		144,328			100,481			272,659			195,378

			Operating income (loss)		36,299			10,850			89,862			(11,269	)
Other income (expense):
	Interest expense				(13,058	)		(7,978	)		(29,400	)		(16,349	)
	Interest income				180			121			381			201
	Change in fair value of interest rate swap				—			—			—			226
	Loss on debt retirement				(920	)		—			(920	)		—
	Other				188			803			333			321

Income (loss) before income taxes					22,689			3,796			60,256			(26,870	)

Benefit (provision) for income taxes:
		Current			—			—			—			—
		Deferred			(8,281	)		(1,386	)		(21,993	)		9,807

			Total benefit (provision) for income taxes		(8,281	)		(1,386	)		(21,993	)		9,807

		Net income (loss) before cumulative effect of change in accounting principle			14,408			2,410			38,263			(17,063	)
Cumulative effect of change in accounting principle (net of tax effect of $1,962)					—			—			(3,414	)		—

Net income (loss)					14,408			2,410			34,849			(17,063	)
Preferred stock dividends					(1,191	)		(1,191	)		(2,382	)		(2,381	)

Net income (loss) available to common stockholders				$	13,217		$	1,219		$	32,467		$	(19,444	)

Weighted average number of common shares outstanding:
		Basic			67,052			52,128			66,935			52,104

		Diluted			67,942			52,760			67,787			52,104

Net income (loss) per common share:
Basic:
	Net income (loss) before cumulative effect of change in accounting principle			$	.20		$	.02		$	.54		$	(.37	)
	Cumulative effect of change in accounting principle				—			—			(.05	)		—

			Net income (loss) available to common stockholders	$	.20		$	.02		$	.49		$	(.37	)

Diluted:
	Net income (loss) before cumulative effect of change in accounting principle			$	.19		$	.02		$	.53		$	(.37	)
	Cumulative effect of change in accounting principle				—			—			(.05	)		—

			Net income (loss) available to common stockholders	$	.19		$	.02		$	.48		$	(.37	)

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

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



				For the Six Months
				Ended June 30,

				2003			2002


				(In thousands)
				(Unaudited)
Cash flows from operating activities:
	Net income (loss)			$	34,849		$	(17,063	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Depletion, depreciation and amortization			128,101			99,380
		Exploratory dry hole costs			14,928			9,795
		Impairment of proved properties			977			—
		Impairment of unproved properties			15,173			6,290
		Deferred income taxes			21,993			(9,807	)
		Director retainers settled for stock			11			20
		Stock compensation expense			2,150			94
		Change in fair value of derivatives			3,514			7,996
		Amortization of derivative liabilities			(9,625	)		(5,018	)
		Amortization of deferred financing fees			548			540
		Gain on sale of operating assets, net			(6,466	)		1,868
		Cumulative change in accounting principle, net of tax			3,414			—
		Changes in assets and liabilities, net of effects of acquisitions:
			Decrease (increase) in accounts receivable		(15,423	)		5,023
			Increase in prepaid expenses		(1,039	)		(2,992	)
			Decrease in accounts payable		(2,511	)		(17,889	)
			Increase in ad valorem taxes payable		6,228			502
			Decrease in income taxes payable		(3	)		(44	)
			Increase in accrued expenses		59			2,582
			Decrease in other liabilities		(462	)		(446	)

Net cash provided by operating activities					196,416			80,831

Cash flows from investing activities:
	Additions to property and equipment				(115,626	)		(71,769	)
	Proceeds from sales of assets				13,281			7,790
	Acquisitions of oil and gas properties and purchase price adjustments				3,557			(42,303	)
	Other				—			(52	)

Net cash used in investing activities					(98,788	)		(106,334	)

Cash flows from financing activities:
	Proceeds from issuance of common stock				3,530			1,071
	Proceeds from issuance of long-term debt				151,875			55,000
	Repayment of long term debt				(226,311	)		—
	Preferred stock dividends paid				(2,381	)		(2,381	)
	Repurchase of common stock				(43	)		(61	)
	Loss on retirement of debt							(920	)
	Financing fees				(274	)		(271	)

Net cash provided by (used in) financing activities					(74,524	)		53,358

Net increase in cash and cash equivalents					23,104			27,855
Cash and cash equivalents, beginning of period					42,761			27,584

Cash and cash equivalents, end of period				$	65,865		$	55,439

Supplemental cash flow information:
	Cash paid for interest			$	33,182		$	17,664

	Cash paid for income taxes			$	3		$	44

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Organization and Nature of Business

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


2.	Unaudited Consolidated Financial Statements

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


3.	Debt

Long-term debt consisted of:


	June 30,			December 31,
	2003			2002


	(in thousands)
8 1/4% Senior Subordinated Notes Due 2011	$	731,879	(1)	$	591,771	(2)
8 7/8% Senior Subordinated Notes due 2007		—			127,587	(3)
Revolving Credit Facility due on December 16, 2006		—			80,000

					799,358
Less current portion		—			—

	$	731,879		$	799,358

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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


	*Revolving Credit Facility*

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

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

• the rate of interest announced by JP Morgan Chase Bank, as its prime rate;

• the secondary market rate for three month certificates of deposits plus 1%; or

• the Federal funds effective rate plus 0.5%

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

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

The Revolving Credit Facility contains various covenants and default provisions applicable to the Company and its restricted subsidiaries, including two financial covenants that require the Company to maintain a current ratio of not less than 1.0 to 1.0 and a ratio of EBITDAX to consolidated interest

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

expense for the preceding four consecutive fiscal quarters of not less than 3.0 to 1.0. Commitment fees under the Revolving Credit Facility range from 0.25% to 0.5% on the average daily amount of the available unused borrowing capacity based on the rating of the Company’s senior unsecured debt as issued by Standard and Poor’s Rating Group and Moody’s Investor Service, Inc.

Under the terms of the Revolving Credit Facility the Company must meet certain tests before it is able to declare or pay any dividend on (other than dividends payable solely in equity interests of the Company other than disqualified stock), or make any payment of, or set apart assets for a sinking or other analogous fund for the purchase, redemption, defeasance, retirement or other acquisition of, any shares of any class of equity interests of the Company or any of its restricted subsidiaries, whether now or hereafter outstanding, or make any other distribution in respect thereof, either directly or indirectly, whether in cash or property or in obligations of the Company or any restricted subsidiary. Other covenants include restrictions on incurring additional indebtedness, liens, and guarantee obligations; limitations on fundamental changes and sales of assets; restrictions on making certain investments, loans or advances; limitations on optional redemption of subordinated indebtedness; restrictions on transacting with affiliates, changing lines of business and entering into certain hedging agreements; and limitations on sale and leasebacks and use of proceeds.

As of June 30, 2003, the Company had no outstanding indebtedness and letters of credit of approximately $104.5 million outstanding under the Revolving Credit Facility. Available unused borrowing capacity was approximately $365.5 million. The letters of credit were issued primarily in connection with the margin requirements of the Company’s oil and natural gas derivative contracts. The Revolving Credit Facility currently limits the outstanding letters of credit to $200 million.


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

On April 3, 2003, the Company issued $125 million in additional principal amount of the 8 1/4% Senior Subordinated Notes Due 2011 pursuant to Rule 144A and Regulation S under the Securities Act of 1933 (the “Securities Act”) at a price of 106% of the principal amount, with accrued interest from November 1, 2002. The 2003 notes were issued as additional debt securities under the indenture pursuant to which, on November 5, 2001, the Company issued $275 million of 8 1/4% Senior Subordinated Notes Due 2011 and on December 17, 2002, the Company issued $300 million of 8 1/4% Senior Subordinated Notes Due 2011. All of the 2001 and 2002 notes were subsequently exchanged on March 14, 2002 and March 12, 2003, respectively, for equal principal amounts of notes having substantially identical terms and registered under the Securities Act. The proceeds from the 2003 notes were used to fund the redemption of the Company’s 8 7/8% Senior Subordinated Notes due 2007 (described below) on May 5, 2003 and to reduce the indebtedness under the Revolving Credit Facility. We have agreed to file an exchange offer registration statement, or under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2003 notes. On June 4, 2003, the Company filed the exchange offer registration statement relating to the 2003 notes. In the event the Company fails, among other things, to effect the registration statement or consummate the exchange offer relating to the 2003 notes on a timely basis, the Company will pay additional interest on such notes.

The notes are senior subordinated unsecured obligations of the Company and are guaranteed on a senior subordinated basis by some of its existing and future restricted subsidiaries. The notes mature on November 1, 2011. The Company pays interest on the notes semi-annually on May 1 and November 1. The Company is entitled to redeem the notes in whole or in part on or after November 1, 2006 for the redemption price set forth in the notes. Prior to November 1, 2006, the Company is entitled to redeem the notes, in whole but not in part, at a redemption price equal to the principal amount of the notes plus a premium. There is no sinking fund for the notes.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The indenture governing the 8 1/4% Senior Subordinated Notes Due 2011 limits the activity of the Company and its restricted subsidiaries. The provisions of such indenture limit the ability of the Company and its restricted subsidiaries to incur additional indebtedness; pay dividends on capital stock or redeem, repurchase or retire such capital stock or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company; engage in transactions with the Company’s affiliates; sell assets, including capital stock of the Company’s subsidiaries; and consolidate, merge or transfer assets. During any period that these notes have investment grade ratings from both Moody’s Investors Service, Inc. and Standard and Poor’s Ratings Group and no default has occurred and is continuing, the foregoing covenants will cease to be in effect with the exception of covenants that contain limitations on liens and on, among other things, certain consolidations, mergers and transfers of assets. The 8 1/4% Senior Subordinated Notes Due 2011 do not currently qualify as investment grade.


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

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


	*Interest Rate Swaps-Hedges*

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

Notional Amount

Transaction Date

Expiration Date

Current Estimated Rate

$100 million

November 2001

November 1, 2011

LIBOR + 2.42%

$ 50 million

January 2003

November 1, 2011

LIBOR + 3.37%

$ 40 million

January 2003

November 1, 2011

LIBOR + 3.55%

$ 50 million

January 2003

November 1, 2011

LIBOR + 3.42%

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

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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


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

For the six months ended June 30, 2003 and 2002, the Company reclassified approximately $63.9 million of hedging losses and $3.4 million of hedging gains, respectively, out of accumulated other comprehensive income into oil and gas sales revenues. The hedging losses and gains reclassified to revenues include cash losses of $66.1 million and $1.3 million for the six months ended June 30, 2003 and 2002, respectively.

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

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

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

The tables below provide details about the volumes and prices of all open CPRM hedge and non-hedge commitments as of June 30, 2003:


				2003		2004		2005

Hedges
	Gas
		NYMEX Price Swaps Sold — receive fixed price (thousand Mmbtu)(1)			16,196		21,960		16,425
			Average price, per Mmbtu	$	4.01	$	4.11	$	4.35
		NWPRM Price Swaps Sold — receive fixed price (thousand Mmbtu)(2)			—		10,980		—
			Average price, per Mmbtu	$	—	$	3.33	$	—
		CIG Price Swaps Sold — receive fixed price, per Mmbtu(3)			1,840		—		—
			Average price, per Mmbtu	$	3.59	$	—	$	—
		NYMEX Collars Sold (thousand Mmbtu)(4)			11,740		16,380		3,650
			Average floor price, per Mmbtu	$	3.61	$	3.70	$	4.00
			Average ceiling price, per Mmbtu	$	4.29	$	4.00	$	5.07

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


					2003			2004			2005

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

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

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

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

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

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

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

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


	*Earnings per Share*

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

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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



			For the Six Months
			Ended June 30,

			2003			2002


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

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

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

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

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

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

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

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


	*Comprehensive Income (Loss)*

The Company follows SFAS No. 130, “Reporting Comprehensive Income,” which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to the owners of the Company. The components of other comprehensive income for the six months ended June 30, 2003 and 2002, respectively, are as follows:



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

		Gross			Tax Effect			Net			Gross			Tax Effect		Net


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

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

6. Stock Compensation

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



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

		2003		2002			2003		2002


		(In thousands, except per share amounts)
Net income (loss) available to common stockholders
	As reported	$	13,217	$	1,219		$	32,467	$	(19,444	)
	Pro forma		12,545		(1,240	)		28,695		(23,685	)
Basic net income (loss) per common share
	As reported	$	.20	$	.02		$	.49	$	(.37	)
	Pro forma		.19		(.02	)		.43		(.45	)
Diluted net income (loss) per common share
	As reported	$	.19	$	.02		$	.48	$	(.37	)
	Pro forma		.18		(.02	)		.42		(.45	)


7.	Recent Accounting Pronouncements

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


	2003

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

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

Long-term asset retirement obligation	$	50,143

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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



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

		2003		2002		2003		2002


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

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

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

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

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

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


8.	Segment Information

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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



	For the Six Months Ended June 30,

								Gulf of			Corporate &
	Northern		Western		Southern			Mexico			Unallocated			Consolidated


	(In thousands)
2003
Revenues	$	92,988	$	59,312	$	153,286		$	117,598		$	(60,663	)(1)	$	362,521
DD&A		20,722		11,791		45,402			49,873			313			128,101
Impairment of proved properties		106		—		188			683			—			977
Impairment of unproved properties		2,062		—		1,400			11,711			—			15,173
Profit (loss)		39,483		28,485		64,463			20,559			(63,128	)		89,862
Expenditures for assets, net		14,371		25,728		24,082			47,299			589			112,069
2002
Revenues	$	58,310	$	—	$	69,949		$	59,892		$	(4,042	)(1)	$	184,109
DD&A		22,503		—		38,293			38,358			226			99,380
Impairment of unproved properties		3,002		—		2,093			1,195			—			6,290
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

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



	For the Three Months Ended June 30,

							Gulf of		Corporate &
	Northern		Western		Southern		Mexico		Unallocated			Consolidated


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

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


9.	Condensed Consolidated Financial Statements of Subsidiary Guarantors

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

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

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

June 30, 2003


				Parent			Subsidiary
				Company			Guarantors			Eliminations			Consolidated


				(In thousands)

				(Unaudited)
ASSETS
Current Assets:
	Cash and cash equivalents			$	12,400		$	53,465		$	—		$	65,865
	Accounts receivable, net				17,447			64,073			—			81,520
	Intercompany receivable				1,331,639			—			(1,331,639	)		—
	Derivative assets				8,401			—			—			8,401
	Prepaid expenses				5,312			9,459			—			14,771

			Total current assets		1,375,199			126,997			(1,331,639	)		170,557

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties			382,988			1,886,552			—			2,269,540
		Unproved properties			22,291			72,653			—			94,944
	Field services assets				—			39,198			—			39,198
	Building and other office furniture and equipment				673			9,601			—			10,274

					405,952			2,008,004			—			2,413,956
	Less accumulated depletion, depreciation and amortization				(166,279	)		(431,432	)		—			(597,711	)

			Net property and equipment		239,673			1,576,572			—			1,816,245

Other assets:
	Long-term derivative assets				17,792			—			—			17,792
	Goodwill				—			244,647			—			244,647
	Other assets				19,697			—			—			19,697

			Total other assets		37,489			244,647			—			282,136

			Total assets	$	1,652,361		$	1,948,216		$	(1,331,639	)	$	2,268,938


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable			$	8,809		$	39,763		$	—		$	48,572
	Accrued expenses				19,544			21,940			—			41,484
	Ad valorem taxes payable				18			15,199			—			15,217
	Intercompany payable				—			1,331,639			(1,331,639	)		—
	Derivative liabilities				98,173			—			—			98,173
	Income taxes payable				—			83			—			83
	Other current liabilities				3,974			3,986			—			7,960

			Total current liabilities		130,518			1,412,610			(1,331,639	)		211,489
Long-term debt					731,879			—			—			731,879
Deferred income taxes					(71,196	)		185,868			—			114,672
Long-term derivative liabilities					42,632			—			—			42,632
Other liabilities					15,622			34,521			—			50,143

			Total liabilities		849,455			1,632,999			(1,331,639	)		1,150,815

Stockholders’ equity:
	Preferred stock				29			—			—			29
	Common stock				672			3			(3	)		672
	Additional paid-in capital				956,875			199,153			3			1,156,031
	Treasury stock				(512	)		—			—			(512	)
	Retained earnings				(83,753	)		116,222			—			32,469
	Accumulated other comprehensive income				(70,405	)		(161	)		—			(70,566	)

			Total stockholders’ equity		802,906			315,217			—			1,118,123

			Total liabilities and stockholders’ equity	$	1,652,361		$	1,948,216		$	(1,331,639	)	$	2,268,938

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Six Months Ended June 30, 2003


			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


			(In thousands)

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

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

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

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

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

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

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

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

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

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

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

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

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

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Six Months Ended June 30, 2003


					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)

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

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

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

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

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

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

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

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

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2002


				Parent			Subsidiary
				Company			Guarantors			Eliminations			Consolidated


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

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

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

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

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

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

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

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


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

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

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

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

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

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

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Six Months Ended June 30, 2002


			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


			(In thousands)

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

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

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

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

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

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

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

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

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

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

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

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)

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

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

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

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

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

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

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

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


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

General

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

Critical Accounting Policies And Estimates

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

• Revenue Recognition. We follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. No receivables, payables or unearned revenue are recorded unless a working interest owner’s aggregate sales from the property exceed its share of the total reserves-in-place. If such a situation arises, the parties would likely cash balance.

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

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

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

Our proved reserve information included in this report is based on estimates prepared by Ryder Scott Company L.P. and our engineering staff. Estimates prepared by others may be higher or lower than our estimates.

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

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

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

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

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

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

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

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

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

Overview

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

Our results of operations are significantly impacted by the prices of oil and natural gas, which are volatile. The prices we receive for our oil vary from NYMEX prices based on the location and quality of the crude oil. The prices we receive for our natural gas are based on Henry Hub prices reduced by transportation expenses, regional basis differentials and processing fees.

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

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

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

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

natural gas properties may not be recoverable. We estimate the expected future cash flows of our oil and gas properties on a field-by-field basis and compare such future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include estimates of proved reserves, future commodity prices, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected future cash flows. Reserve categories used in the impairment analysis for all periods considered are categories of proven reserves and probable and possible reserves, which were risk adjusted based on our drilling plans and history of successfully developing those types of reserves. We periodically assess our unproved properties to determine if any such properties require any impairment. Factors leading to recording unproved impairments include lease expirations and an assessment of the lack of exploration opportunities existing on a lease. 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. We expect to record unproved property impairments in future periods.

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

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

Basis of Presentation

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

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

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

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

Results of Operations

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

Summary Data



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

			2003			2002			2003			2002


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

The discussion below includes a comparison of our results of operations for the three months and six months ended June 30, 2003 and 2002, respectively.

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

Mcfe, for the three months ended June 30, 2002. We typically hedge between 20% and 40% of our expected production one to two years into the future. We currently have approximately 60-70% of our expected 2003 production hedged to protect cash flow and return expectations on significant assets we acquired in late 2002.

Oil and natural gas revenues for the six months ended June 30, 2003 increased by $224.0 million, or 118%, from $190.0 million to $414.0 million, compared to the six months ended June 30, 2002. Production from the acquired El Paso, Southeast Texas and Williston Basin properties accounted for $98.9 million of the increase. The majority of the remaining increase in oil and natural gas revenues was due to increases of 38% and 99% in realized oil and natural gas prices, respectively, excluding the effects of hedging. Production volumes increased by 16.5 Bcfe, or 26%, from 64.0 Bcfe for the six months ended June 30, 2002 to 80.5 Bcfe for the six months ended June 30, 2003. Acquired El Paso, Southeast Texas and Williston Basin properties accounted for 19.5 Bcfe of the increase. Production volumes also increased due to drilling activity since June 30, 2002, which were offset by oil and natural gas production declines.Hedging transactions decreased oil and natural gas revenues by $63.9 million, or $0.79 per Mcfe, for the six months ended June 30, 2003, and increased oil and natural gas revenues by $3.4 million, or $0.05 per Mcfe, for the six months ended June 30, 2002.

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

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

Gain (Loss) on Sale of Operating Assets, Net. For the three months ended June 30, 2003 and 2002, we recorded a net gain of $6.1 million and a net loss of $1.9 million, respectively, on sales of non-core onshore operating assets.

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

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

For the six months ended June 30, 2003, we reported $2.0 million of gathering income and $1.6 million of gathering expense, or a margin of $0.4 million. The gathering income reflected in the consolidated statement of operations relates only to third-party natural gas flowing through our system. Intercompany sales of $2.9 million have been eliminated in our consolidated financial statements. In addition, for the six months ended June 30, 2003, gathering income and expense includes marketing revenue of $727,000 and marketing expense of $681,000, or a margin of $46,000 which primarily occurred in the first quarter of 2003. We do not expect to continue to engage in these marketing activities.

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

Lease operating expense for the six months ended June 30, 2003 increased by $8.5 million, or 19%, from $43.9 million to $52.4 million, compared to the six months ended June 30, 2002. Lease operating expenses from the acquired El Paso, Southeast Texas and Williston Basin properties accounted for $10.3 million of the increase. The increase in lease operating expenses was partially offset by a decrease in workovers of $1.2 million for the six months ended June 30, 2003, as compared to the six months ended June 30, 2002. On a per Mcfe basis, lease operating expense decreased from $0.69 for the six months ended June 30, 2002 to $0.65 for the same period in 2003. The decrease on a per Mcfe basis was primarily due to a $0.03 per Mcfe decrease in workovers performed in the Gulf of Mexico Division during the six months ended June 30, 2003, compared to workovers performed in the Gulf of Mexico Division during the comparable period of 2002.

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

Production taxes for the six months ended June 30, 2003 increased by $12.8 million, or 110%, from $11.6 million to $24.4 million, compared to the six months ended June 30, 2002. Production taxes from the acquired El Paso, Southeast Texas and Williston Basin properties accounted for $8.5 million of the increase. The remaining increase was primarily due to the increase in oil and natural gas prices. On a per Mcfe basis, production taxes increased from $0.18 to $0.30 in the six month periods of 2002 and 2003 respectively. The increase in production taxes on a per Mcfe basis was primarily due to the increase in oil and natural gas prices and the acquired onshore El Paso, Southeast Texas and Williston Basin properties.

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

Transportation costs for the six months ended June 30, 2003 increased by $2.8 million, or 60%, from $4.6 million to $7.4 million, compared to the six months ended June 30, 2002. The acquired El Paso properties accounted for an increase of $2.7 million.

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

2002. Exploration costs for the six months ended June 30, 2003 increased by $7.7 million, or 43%, from $18.0 million to $25.7 million, compared to the six months ended June 30, 2002.



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

	2003		2002		2003		2002


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

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

The majority of the geological and geophysical costs pertain to the purchase of 3-D seismic data in Southeast Texas for the three months ended June 30, 2003. For the three months ended June 30, 2002, the geological and geophysical costs primarily relate to 3-D seismic data purchased in South Louisiana. Dry hole costs for the three months ended June 30, 2003 resulted from two high cost unsuccessful exploratory wells drilled in the Gulf of Mexico and one in Colorado. Dry hole costs for the three months ended June 30, 2002 resulted from three unsuccessful exploratory wells drilled in the Gulf of Mexico, which included one dry hole where another partner carried us on the drilling.

For the six months ended June 30, 2003, the geological and geophysical costs represent 3-D seismic data purchased in the Gulf of Mexico and Southeast Texas. For the six months ended June 30, 2002, the geological and geophysical costs primarily relate to 3-D seismic data purchased in the Gulf of Mexico and South Louisiana. Dry hole costs for the six months ended June 30, 2003 resulted from three high cost unsuccessful exploratory wells drilled in the Gulf of Mexico, two in Texas and one each in Wyoming and Colorado. Dry hole costs for the six months ended June 30, 2002 resulted from four unsuccessful exploratory wells drilled in the Gulf of Mexico, which included one dry hole where another partner carried us on the drilling.

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

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

Impairment of Proved Properties. During the three month period ended June 30, 2003, we recognized proved property impairments of $1.0 million. In the Gulf of Mexico, Southern and Northern Divisions we recorded impairments of $0.7 million, $0.2 million and $0.1 million as a result of declines in oil and natural gas reserve values due to reserve volume reductions in underperforming fields. During the respective three and six month periods ended June 30, 2002, we recorded no proved property impairments.

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

respectively. The $9.6 million recorded in impairments for the Gulf of Mexico included $8.6 million related to the two unsuccessful exploration wells drilled in the three months ended June 30, 2003. During the three months ended June 30, 2002, we recognized unproved property impairments of $5.3 million. The impairments consisted of $3.0 million, $2.1 million and $0.2 million recorded in the Northern, Southern and Gulf of Mexico Divisions, respectively.

During the six months ended June 30, 2003, we recognized unproved property impairments of $15.2 million due to expired leases and from an assessment relating to the lack of exploration opportunities existing on such properties. In the Gulf of Mexico, Northern and Southern Divisions we recorded impairments of $11.7 million, $2.1 million and $1.4 million, respectively. During the six months ended June 30, 2002, we recognized unproved property impairments of $6.3 million. The impairments consisted of $3.0 million, $2.1 million and $1.2 million recorded in the Northern, Southern and Gulf of Mexico Divisions, respectively.

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

During the six months ended June 30, 2003, we recorded $2.1 million of stock compensation expense related to certain stock options as a result of applying FIN 44 and recorded $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 FIN 44 and recorded $0.1 million in expense related to the issuance of restricted stock.

General and Administrative (G&A) Expense. G&A expense increased $2.0 million, or 36%, for the three months ended June 30, 2003, from $5.5 million to $7.5 million, compared to the three months ended June 30, 2002. The majority of the increase was due to additional staff required for the El Paso Acquisition causing an increase in payroll costs such as salaries and benefits. G&A expense per Mcfe of production increased from $0.17 for the second quarter of 2002 to $0.18 in the second quarter of 2003.

G&A expense increased $3.3 million, or 29%, for the six months ended June 30, 2003, from $11.4 million to $14.8 million, compared to the six months ended June 30, 2002. The majority of the increase was due to additional staff required for the El Paso Acquisition causing an increase in payroll costs such as salaries and benefits. G&A expense per Mcfe of production remained constant at $0.18 for the respective six month periods ended June 30, 2003 and 2002.

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

Other income (expense) for the six months ended June 30, 2003 was ($29.6) million, compared to ($15.6) million for the six months ended June 30, 2002. Interest expense increased $13.1 million for the six months ended June 30, 2003, compared to the six months ended June 30, 2002, as a result of the increase in the debt balances relating to the El Paso and Southeast Texas acquisitions. We recorded a loss on debt retirement of $0.9 million related to the redemption of the 8 7/8% Senior Subordinated Notes due 2007 on May 5, 2003.

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

We recorded a deferred income tax expense of $22.0 million for the six months ended June 30, 2003 and a deferred income tax benefit of $9.8 million due to a net loss for the six months ended June 30, 2002.

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

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

Cumulative Effect of Change in Accounting Principle. We adopted SFAS No. 143 on January 1, 2003 and recorded a cumulative effect of a change in accounting principle on prior years of $3.4 million, net of tax effects, related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred.

Liquidity and Capital Resources

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

Net cash provided by operating activities was $196.4 million for the six months ended June 30, 2003, compared to $80.8 million for the six months ended June 30, 2002. Operating cash flow in the six month period increased compared to the respective prior period due to increased oil and natural gas prices and production.

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

Net cash used in financing activities was $74.5 million for the six months ended June 30, 2003, compared to $53.4 million provided for the six months ended June 30, 2002. Financing activities for the six months ended June 30, 2003 consisted of $226.3 million in repayment of long-term debt, a $2.4 million preferred stock dividend payment, $0.9 million loss on debt retirement and a payment of $0.3 million in financing fees, offset by $151.9 million from the issuance of senior subordinated notes and borrowing of long-term debt and $3.5 million from issuance of common stock. Financing activities for the six months ended June 30, 2002 consisted of $55.0 million in borrowings utilized for acquisition and development of oil and natural gas properties and $1.1 million from issuance of common stock, offset by a $2.4 million preferred stock dividend payment and a payment of $0.3 million in financing fees.

Financing Activity


	*Revolving Credit Facility*

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

December 16, 2006. In the past, we made borrowings under the Revolving Credit Facility to refinance our outstanding indebtedness under our previous revolving credit facility and to pay general corporate expenses.

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

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

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

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

Under the terms of the Revolving Credit Facility we must meet certain tests before we are able to declare or pay any dividend on (other than dividends payable solely in equity interests of the Company other than disqualified stock), or make any payment of, or set apart assets for a sinking or other analogous fund for the purchase, redemption, defeasance, retirement or other acquisition of, any shares of any class of equity interests of us or any of our restricted subsidiaries, whether now or hereafter outstanding, or make any other distribution in respect thereof, either directly or indirectly, whether in cash or property or in obligations of the Company or any restricted subsidiary. Other covenants include restrictions on incurring additional indebtedness, liens, and guarantee obligations; limitations on fundamental changes and sales of assets; restrictions on making certain investments, loans or advances; limitations on optional redemption of subordinated indebtedness; restrictions on transacting with affiliates, changing lines of business and entering into certain hedging agreements; and limitations on sale and leasebacks and use of proceeds.

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

8 1/4% Senior Subordinated Notes Due 2011

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

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

• incur additional indebtedness;

• pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

• make investments;

• incur liens;

• create any consensual limitation on the ability of our restricted subsidiaries to pay dividends, make loans or transfer property to us;

• engage in transactions with our affiliates;

• sell assets, including capital stock of our subsidiaries; and

• consolidate, merge or transfer assets.

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


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

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

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


	*Capital Expenditures*

We anticipate that our capital expenditures for 2003 will be approximately $270 million. We anticipate that our primary cash requirements for 2003 will include funding development projects, exploration and general working capital needs. For the first six months of 2003, we had capital expenditures of $112.1 million excluding geological and geophysical costs incurred of $9.3 million.

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

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

• drilling results;

• product prices;

• industry conditions and outlook; and

• future acquisition of properties.

Special Note Regarding Forward-Looking Statements

Our disclosure and analysis in this report, including information incorporated by reference, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. Forward-looking statements give our current expectations and projections relating to the financial condition, results of operations, plans, objectives, future performance and business of Westport and its subsidiaries. You can identify these statements by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe” and other words and expressions of similar meaning in connection with any discussion of the timing or nature of future operating or financial performance or other events. All statements other than statements of historical facts included in this report that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements and include, among other things, statements relating to:

• amount, nature and timing of capital expenditures;

• projected drilling of wells;

• reserve estimates;

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

• operating costs and other expenses;

• cash flow, anticipated liquidity and prospects for growth;

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

• marketing of oil and natural gas.

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


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

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

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

As of June 30, 2003, we had substantial derivative financial instruments outstanding and related to our price risk management program. See “Note 4” to our consolidated financial statements in Item 1 of this Report for additional details on our oil and natural gas related transactions in effect as of June 30, 2003. For more information on our interest rate swaps in effect as of June 30, 2003, see “Note 3” to our consolidated financial statements in Item 1 of this Report.


Item 4.	*Controls and Procedures*

Our management, with the participation of our Chairman of the Board and Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer) have concluded, based on their evaluation as of the end of the period covered by this report, that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in our internal controls over financial reporting during the period covered by this report that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

PART II — OTHER INFORMATION


Item 1.	*Legal Proceedings*

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

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

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


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

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

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

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


Item 3.	*Defaults Upon Senior Securities.*

None.


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

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

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

Proposal No. 1 — Election of Directors.


Director	For		Withheld

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

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


FOR		AGAINST		ABSTAIN

	57,919,371		494,815		15,979


Item 5.	*Other Information.*

None.


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

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


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


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

* Filed herewith

(b) Reports on Form 8-K:

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

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

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

SIGNATURES

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

WESTPORT RESOURCES CORPORATION


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

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

EXHIBIT INDEX


No. of
Exhibit			Description

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

* Filed herewith.


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

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


	•	the rate of interest announced by JP Morgan Chase Bank, as its prime rate;

	•	the secondary market rate for three month certificates of deposits plus 1%; or

	•	the Federal funds effective rate plus 0.5%


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


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

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

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


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

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


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

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

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

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

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

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

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


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


	•	Revenue Recognition. We follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. No receivables, payables or unearned revenue are recorded unless a working interest owner’s aggregate sales from the property exceed its share of the total reserves-in-place. If such a situation arises, the parties would likely cash balance.

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

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


	•	the quality and quantity of available data;

	•	the interpretation of that data;

	•	the accuracy of various mandated economic assumptions; and

	•	the judgment of the persons preparing the estimate.


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

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

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

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


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

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


	•	incur additional indebtedness;

	•	pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

	•	make investments;

	•	incur liens;

	•	create any consensual limitation on the ability of our restricted subsidiaries to pay dividends, make loans or transfer property to us;

	•	engage in transactions with our affiliates;

	•	sell assets, including capital stock of our subsidiaries; and

	•	consolidate, merge or transfer assets.


	•	drilling results;

	•	product prices;

	•	industry conditions and outlook; and

	•	future acquisition of properties.


	•	amount, nature and timing of capital expenditures;

	•	projected drilling of wells;


	•	reserve estimates;

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

	•	operating costs and other expenses;

	•	cash flow, anticipated liquidity and prospects for growth;

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

	•	marketing of oil and natural gas.


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

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

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