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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


(Mark One)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the quarterly period ended March 31, 2004
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)

(Registrant’s telephone number, including area code)

(303) 573-5404

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

67,906,552 shares of the issuer’s common stock, par value $0.01 per share, were outstanding as of May 3, 2004.

WESTPORT RESOURCES CORPORATION

TABLE OF CONTENTS


		Page

PART I — FINANCIAL INFORMATION			1
Item 1.	Financial Statements		1
	Consolidated Balance Sheets as of March 31, 2004 (unaudited) and December 31, 2003		1
	Consolidated Statements of Operations for the three months ended March 31, 2004 and 2003 (unaudited)		2
	Consolidated Statements of Cash Flows for the three months ended March 31, 2004 and 2003 (unaudited)		3
	Notes to Consolidated Financial Statements (unaudited)		4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		34
Item 4.	Controls and Procedures		34
PART II — OTHER INFORMATION			35
Item 1.	Legal Proceedings		35
Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		35
Item 3.	Defaults Upon Senior Securities		36
Item 4.	Submission of Matters to a Vote of Security Holders		36
Item 5.	Other Information		36
Item 6.	Exhibits and Reports on Form 8-K		36
Signatures			38
Third Amended and Restated Bylaws
Termination Agreement
Certification Pursuant to Section 302 - CEO
Certification Pursuant to Section 302 - CFO
Certification Pursuant to Section 906 - CEO
Certification Pursuant to Section 906 - CFO

PART I — FINANCIAL INFORMATION


Item 1.	*Financial Statements*

WESTPORT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEET


					March 31,			December 31,
					2004			2003

					(Unaudited)

					(In thousands,
					except share data)
ASSETS
Current Assets:
	Cash and cash equivalents				$	98,278		$	73,658
	Accounts receivable, net					97,771			86,934
	Derivative assets					4,082			3,728
	Prepaid expenses					22,071			17,202

			Total current assets			222,202			181,522

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
			Proved properties			2,796,232			2,707,228
			Unproved properties			124,426			119,331

						2,920,658			2,826,559
	Less accumulated depletion, depreciation and amortization					(794,584	)		(721,631	)

			Net oil and gas properties			2,126,074			2,104,928

	Field services assets					41,291			40,226
	Less accumulated depreciation					(1,445	)		(1,135	)

			Net field services assets			39,846			39,091

	Building and other office furniture and equipment					11,427			10,926
	Less accumulated depreciation					(5,723	)		(5,380	)

			Net building and other office furniture and equipment			5,704			5,546

Other assets:
	Long-term derivative assets					21,319			23,105
	Goodwill					244,640			244,640
	Other assets					17,702			18,431

			Total other assets			283,661			286,176

			Total assets		$	2,677,487		$	2,617,263

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
	Accounts payable				$	66,857		$	79,697
	Accrued expenses					64,418			45,136
	Ad valorem taxes payable					18,322			13,847
	Derivative liabilities					140,152			107,529
	Income taxes payable					10,410			2,499
	Current asset retirement obligation					8,020			8,017

			Total current liabilities			308,179			256,725
Long-term debt						964,376			980,885
Deferred income taxes						119,120			118,024
Long term derivative liabilities						40,294			38,022
Long term asset retirement obligation						63,743			62,709

			Total liabilities			1,495,712			1,456,365

Stockholders’ equity:
		6 1/2% convertible preferred stock, $.01 par value; 10,000,000 shares authorized; 2,930,000 issued and outstanding at March 31, 2004 and December 31, 2003, respectively				29			29
	Common stock, $0.01 par value; 70,000,000 authorized; 67,905,350 and 67,571,525 shares issued and outstanding at March 31, 2004 and December 31, 2003, respectively					679			675
	Additional paid-in capital					1,173,510			1,167,008
	Treasury stock-at cost; 39,418 and 38,610 shares at March 31, 2004 and December 31, 2003, respectively					(608	)		(583	)
	Retained earnings					109,128			64,346
	Accumulated other comprehensive income:
				Deferred hedge loss, net		(101,162	)		(70,776	)
				Cumulative translation adjustment		199			199

				Total stockholders’ equity		1,181,775			1,160,898

				Total liabilities and stockholders’ equity	$	2,677,487		$	2,617,263

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

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS



				For the Three Months
				Ended March 31,

				2004			2003


				(Unaudited)

				(In thousands, except
				per share amounts)
Operating revenues:
	Oil and natural gas sales			$	271,361		$	218,419
	Hedge settlements				(34,713	)		(40,446	)
	Gathering income				(154	)		1,209
	Non-hedge change in fair value of derivatives				3,924			2,320
	Gain on sale of operating assets, net				67			392

			Net revenues		240,485			181,894

Operating costs and expenses:
	Lease operating expenses				27,214			26,336
	Production taxes				15,336			13,058
	Transportation costs				3,539			4,024
	Gathering expenses				950			1,096
	Exploration				12,837			12,047
	Depletion, depreciation and amortization				74,954			61,065
	Impairment of unproved properties				2,999			3,480
	Stock compensation expense, net				2,693			(3	)
	General and administrative				10,172			7,228

			Total operating expenses		150,694			128,331

			Operating income		89,791			53,563
Other income (expense):
	Interest expense				(17,346	)		(16,342	)
	Interest income				133			201
	Other				(180	)		145

Income before income taxes					72,398			37,567

Provision for income taxes:
	Current				(7,863	)		—
	Deferred				(18,562	)		(13,712	)

			Total provision for income taxes		(26,425	)		(13,712	)

Net income before cumulative effect of change in accounting principle					45,973			23,855
Cumulative effect of change in accounting principle (net of tax effect of $1,962)					—			(3,414	)

Net income					45,973			20,441
Preferred stock dividends					(1,191	)		(1,191	)

Net income available to common stockholders				$	44,782		$	19,250

Weighted average number of common shares outstanding:
	Basic				67,686			66,817

	Diluted				69,163			67,631

Net income per common share:
	Basic:
		Net income before cumulative effect of change in accounting principle		$	0.66		$	0.34
		Cumulative effect of change in accounting principle			—			(0.05	)

		Net income available to common stockholders		$	0.66		$	0.29

	Diluted:
		Net income before cumulative effect of change in accounting principle		$	0.65		$	0.34
		Cumulative effect of change in accounting principle			—			(0.05	)

		Net income available to common stockholders		$	0.65		$	0.29

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

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



				For the Three Months
				Ended March 31,

				2004			2003


				(Unaudited)

				(In thousands)
Cash flows from operating activities:
	Net income			$	45,973		$	20,441
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depletion, depreciation and amortization			74,954			61,065
		Exploratory dry hole costs			3,900			4,892
		Impairment of unproved properties			2,999			3,480
		Deferred income taxes			18,562			13,712
		Stock compensation expense, net			2,693			(3	)
		Change in fair value of derivatives			(3,924	)		(2,320	)
		Amortization of deferred financing fees			371			282
		Gain on sale of operating assets, net			(67	)		(392	)
		Cumulative change in accounting principle, net of tax			—			3,414
		Changes in assets and liabilities, net of effects of acquisitions:
			Increase in accounts receivable		(10,837	)		(26,403	)
			Increase in prepaid expenses		(4,869	)		(1,002	)
			Increase in net derivative liabilities		1,342			137
			Increase (decrease) in accounts payable		(9,213	)		325
			Increase in ad valorem taxes payable		4,475			2,998
			Increase in income taxes payable		7,911			—
			Increase in accrued expenses		12,554			14,877
			Decrease in other liabilities		(530	)		(217	)

Net cash provided by operating activities					146,294			95,286

Cash flows from investing activities:
	Additions to property and equipment				(99,200	)		(50,731	)
	Proceeds from sales of assets				24			3,563
	Acquisitions of oil and gas properties and purchase price adjustments				—			4,911

Net cash used in investing activities					(99,176	)		(42,257	)

Cash flows from financing activities:
	Proceeds from issuance of common stock				3,812			143
	Repayment of long term debt				(25,000	)		(30,000	)
	Preferred stock dividends paid				(1,191	)		(1,191	)
	Repurchase of common stock				(25	)		(43	)
	Financing fees				(94	)		—

Net cash used in financing activities					(22,498	)		(31,091	)

Net increase in cash and cash equivalents					24,620			21,938
Cash and cash equivalents, beginning of period					73,658			42,761

Cash and cash equivalents, end of period				$	98,278		$	64,699

Supplemental cash flow information:
	Cash paid for interest			$	3,160		$	6,283

	Cash paid for income taxes			$	—		$	—

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 as a result of the Merger, the Merger was accounted for as a reverse acquisition in which Old Westport is the purchaser of Belco. Business activities of the Company include the exploration for and production of oil and natural gas primarily in the Gulf of Mexico, the Rocky Mountains, the Gulf Coast and the West Texas/ Mid-Continent area.

2. Unaudited Consolidated Financial Statements

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments (consisting only of normal recurring items) necessary to present fairly the financial position of the Company as of March 31, 2004 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, 2003 audited financial statements set forth in the Company’s Form 10-K.

3. Debt

Long-term debt consisted of:


	March 31,			December 31,
	2004			2003


	(In thousands)
8 1/4% Senior Subordinated Notes Due 2011	$	727,376	(1)	$	718,885	(2)
Revolving Credit Facility due on December 16, 2006		237,000			262,000

		964,376			980,885
Less current portion		—			—

	$	964,376		$	980,885

(1) The balance of the 8 1/4% Senior Subordinated Notes Due 2011 as of March 31, 2004 reflects the aggregate face amount of $700 million plus $13.7 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 $13.7 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.

(2) The balance of the 8 1/4% Senior Subordinated Notes Due 2011 as of December 31, 2003 reflects the aggregate face amount of $700 million plus $14.2 million related to the premium recorded in connection with the issuance of 8 1/4% Senior Subordinated Notes Due 2011 on December 17, 2002

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and April 3, 2003 (see 8 1/4% Senior Subordinated Notes Due 2011 below) and an increase of $4.7 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.


	*Revolving Credit Facility*

On December 17, 2002, the Company entered into a new credit facility (as amended from time to time, the “Revolving Credit Facility”) with JPMorgan Chase Bank, Credit Suisse First Boston Corporation and certain 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 Company made borrowings under the Revolving Credit Facility to refinance all outstanding indebtedness under its previous revolving credit facility and to pay general corporate expenses.

On October 15, 2003, the Revolving Credit Facility was amended, to increase the borrowing base from $470 million to $500 million. The amendment also eliminated the limit on the outstanding letters of credit, provided that the amount of letters of credit outstanding on any date does not exceed the lesser of the aggregate commitments under the Revolving Credit Facility and the borrowing base then in effect, or if the borrowing base is not in effect on such date, the aggregate commitments under the Revolving Credit Facility. The amendment also increased the basket allowed for purposes of providing cash collateral from $10 million to $20 million and deleted the requirement to file liens on properties if not rated BB+ and Ba1 at December 31, 2003.

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 JPMorgan 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%

plus a margin of 0% to 0.625%, in each case, 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 defined as net income plus interest expense, income tax expense, and amounts attributable to depreciation, depletion, exploration, amortization and other non-cash charges and expenses, but excluding changes in value of certain hedging instruments and extraordinary or nonrecurring gains or losses, subject to certain other specified adjustments.

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 facility matures on December 16, 2006 and contains covenants and default provisions customary for similar credit facilities, including two financial covenants that require the Company to maintain a current ratio, as defined therein, 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 the Company’s senior unsecured debt as issued by Standard and Poor’s Rating Group and Moody’s Investor Service, Inc. The Company was in compliance with such covenants at March 31, 2004.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

As of March 31, 2004, the Company had $237.0 million outstanding indebtedness and had letters of credit of approximately $89.2 million outstanding under the Revolving Credit Facility. Available unused borrowing capacity was approximately $173.8 million. The letters of credit were issued primarily in connection with the margin requirements of the Company’s oil and natural gas derivative contracts.


	*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, 2002 and 2003 notes were subsequently exchanged by the Company on March 14, 2002, March 12, 2003 and March 17, 2004, respectively, for equal principal amounts of notes having substantially identical terms and registered under the Securities Act of 1933, as amended (the “Securities Act”).

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 interest payment due on May 1, 2004 will include additional interest of 0.5% per annum payable on the exchange notes issued on March 17, 2004 and accruing from November 1, 2003 to March 17, 2004, the date the Company consummated the exchange offer with respect to the 2003 notes. 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.

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.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*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 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 March 31, 2004, the Company recorded a derivative asset of $13.7 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 March 31, 2004, the Company could expect to receive approximately $1.8 million per year through 2011.

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. CPRM transactions may take the form of futures contracts, swaps or options. All CPRM data is presented in accordance with the requirements of SFAS No. 133 which the Company adopted on January 1, 2001. Accordingly, unrealized gains and losses related to the change in fair market value of derivative contracts which qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss and such amounts are reclassified to oil and gas sales revenues as the associated production occurs. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current income or expense in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of CPRM activities.

For the three months ended March 31, 2004 and 2003, the Company reclassified approximately $34.7 million and $40.4 million of hedging losses, respectively, out of accumulated other comprehensive income into oil and gas sales revenues. The hedging losses reclassified to revenues include cash losses of $34.7 million and $41.7 million for the three months ended March 31 2004 and 2003, respectively.

The Company also recorded unrealized gain in fair value of non-hedge derivatives of $3.9 million, which included $0.2 million ineffectiveness loss, and $2.3 million, which included $0.6 million ineffectiveness loss, for the three months ended March 31, 2004 and 2003, respectively.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of March 31, 2004, the Company had:

• 3.6 Mmbbls of oil and 53.6 Bcf of natural gas subject to CPRM contracts for the remainder of 2004. Of these contracts, all of the oil and 45.3 Bcf of the natural gas contracts are subject to weighted average New York Mercantile Exchange (“NYMEX”) floor prices of $25.41 per barrel and $4.20 per Mmbtu and weighted average NYMEX ceiling prices of $26.44 per barrel and $4.34 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 Northwest Pipeline Rocky Mountain Index (“NWPRM”) at a weighted average swap price of $3.33 per Mmbtu. In addition, included in the 53.6 Bcf of natural gas contracts are basis swaps covering 2.8 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 6.9 Bcf of natural gas for 2004 that lock in the pricing differential between NYMEX and Colorado Interstate Gas Index (“CIG”) at a weighted average price differential of $0.76 per Mmbtu.

• 2.9 Mmbbls of oil and 42.0 Bcf of natural gas subject to CPRM contracts for 2005, with weighted average NYMEX floor prices of $26.59 per barrel and $4.25 per Mmbtu and weighted average NYMEX ceiling prices of $28.61 per barrel and $5.02 per Mmbtu, respectively. In addition, included in the 42.0 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 per Mmbtu.

• 0.7 Mmbbls of oil and 7.3 Bcf of natural gas subject to CPRM contracts for 2006 with weighted average NYMEX floor prices of $25.00 per barrel and $4.00 per Mmbtu and weighted average NYMEX ceiling price of $28.65 per barrel and $6.00 per Mmbtu, respectively.

The tables below provide details about the volumes and prices of all open CPRM hedge and non-hedge commitments as of March 31, 2004:


					2004		2005		2006

Hedges
	Gas
		NYMEX Price Swaps Sold — receive fixed price (thousand Mmbtu)(1)				30,250		20,075		—
			Average price, per Mmbtu		$	4.42	$	4.42	$	—
		NWPRM Price Swaps Sold — receive fixed price (thousand Mmbtu)(2)				8,250		—		—
			Average price, per Mmbtu		$	3.33	$	—	$	—
		NYMEX Collars Sold (thousand Mmbtu)(3)				12,300		21,900		—
			Average floor price, per Mmbtu		$	3.70	$	4.09	$	—
			Average ceiling price, per Mmbtu		$	4.00	$	5.57	$	—
		NYMEX Three-way Collars (thousand Mmbtu)(3),(4)				2,750		—		7,300
			Average floor price, per Mmbtu		$	4.00	$	—	$	4.00
			Average ceiling price, per Mmbtu		$	5.00	$	—	$	6.00
			Three-way average floor price, per Mmbtu		$	3.15	$	—	$	3.04
		Basis Swaps versus NYMEX(5)
			NWPRM (thousand Mmbtu)			2,750		3,650		—
				Average differential price, per Mmbtu	$	0.66	$	0.78	$	—
			CIG (thousand Mmbtu)			6,875		—		—
			Average differential price, per Mmbtu		$	0.76	$	—	$	—

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


				2004		2005		2006

	Oil
		NYMEX Price Swaps Sold — receive fixed price (Mbbls)(1)			2,475		1,095		—
			Average price, per bbl	$	25.87	$	29.23	$	—
		NYMEX Three-way Collars (Mbbls)(3)(4)			1,100		1,825		730
			Average floor price, per bbl	$	24.38	$	25.00	$	25.00
			Average ceiling price, per bbl	$	27.71	$	28.23	$	28.65
			Three-way average floor price, per bbl	$	19.25	$	20.93	$	20.88
Estimated fair value of oil and gas derivatives as of March 31, 2004 (in thousands)				$	115,582	$	45,069	$	3,898

(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 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.

(4) Three way collars are settled as described in footnote (3) 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 2004 three-way collars, then the effective average floor price would be $23.13 per bbl.

(5) 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.

See also Note 10 — Subsequent Events below for information with respect to certain financial derivative transactions entered into by Kerr-McGee Corporation and Westport’s obligation with respect thereto.

5. Asset Retirement Obligations

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,

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 are presented below:


	Three Months			Twelve Months
	Ended			Ended
	March 31,			December 31,
	2004			2003


	(In thousands)
Balance, beginning of period	$	70,726		$	58,735
Accretion		1,237			4,201
Additions		312			10,303
Revisions		—			2,260
Settlements		(512	)		(4,773	)

Balance, end of period		71,763			70,726
Less: Current asset retirement obligation		(8,020	)		(8,017	)

Long-term asset retirement obligation	$	63,743		$	62,709

The Company’s current and long-term asset retirement obligations are included in current asset retirement liabilities and long-term asset retirement liabilities, respectively, on the accompanying March 31, 2004 and December 31, 2003 consolidated balance sheets.

6. 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 Three Months
			Ended March 31,

			2004			2003


			(In thousands, except
			per share amounts)
Net income per share:
	Net income before cumulative effect of change in accounting principle		$	45,973		$	23,855
	Cumulative change in accounting principle			—			(3,414	)

	Net income			45,973			20,441
	Preferred stock dividends			(1,191	)		(1,191	)

	Net income available to common stockholders		$	44,782		$	19,250

	Weighted average common shares outstanding			67,686			66,817
		Add dilutive effects of employee stock options		1,477			814

	Weighted average common shares outstanding including the effects of dilutive securities			69,163			67,631

	Basic earnings per common share before cumulative effect of change in accounting principle		$	0.66		$	0.34

	Basic earnings per common share		$	0.66		$	0.29

	Diluted earnings per common share before cumulative effect of change in accounting principle		$	0.65		$	0.34

	Diluted earnings per common share		$	0.65		$	0.29


	*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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

owners of the Company. The components of other comprehensive income for the three months ended March 31, 2004 and 2003 are as follows:



		For the Three Months Ended


		March 31, 2004									March 31, 2003

		Gross			Tax Effect			Net			Gross			Tax Effect			Net


		(In thousands)
Net income available to common stockholders		$	71,207		$	(26,425	)	$	44,782		$	32,962		$	(13,712	)	$	19,250
Add preferred stock dividends			1,191			—			1,191			1,191			—			1,191

Net income available to common stockholders before preferred dividends			72,398			(26,425	)		45,973			34,153			(13,712	)		20,441
Other comprehensive income
	Change in fair value of derivative hedging instruments		(82,565	)		30,136			(52,429	)		(85,574	)		31,235			(54,339	)
	Enron non-cash settlements reclassified to income		—			—			—			(712	)		260			(452	)
	Hedge settlements reclassified to income		34,713			(12,670	)		22,043			41,158			(15,023	)		26,135

Comprehensive income (loss)		$	24,546		$	(8,959	)	$	15,587		$	(10,975	)	$	2,760		$	(8,215	)

7. 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. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure”. 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 to the pro forma amounts indicated below:



		For the Three Months
		Ended March 31,

		2004		2003


		(In thousands, except
		per share amounts)
Net income available to common stockholders
	As reported	$	44,782	$	19,250
	Pro forma		42,062		17,281
Basic net income per common share
	As reported	$	0.66	$	0.29
	Pro forma		0.62		0.26
Diluted net income per common share
	As reported	$	0.65	$	0.29
	Pro forma		0.61		0.26

8. Recent Accounting Pronouncements

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

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 it has not had a material impact on the Company’s 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 adoption of SFAS No. 150 has not had any effect on the Company’s financial position or results of operations.

9. 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). All four areas are engaged in the production, development, acquisition and exploration of oil and natural gas properties. The Company evaluates segment performance based on the profit or loss from operations before income taxes. Consolidated and segment financial information is as follows:



	For the Three Months Ended March 31,

							Gulf of		Corporate &
	Northern		Western		Southern		Mexico		Unallocated			Consolidated


	(In thousands)
2004(1)
Revenues	$	48,691	$	39,052	$	106,933	$	75,947	$	(30,138	)	$	240,485
DD&A		10,545		8,879		33,929		20,949		652			74,954
Impairment of unproved properties		1,218		161		891		729		—			2,999
Profit (loss)		21,086		19,447		43,877		37,600		(32,219	)		89,791
Expenditures for assets, net		7,099		35,115		25,703		29,681		1,602			99,200

2003(2)
Revenues	$	46,930	$	27,049	$	83,254	$	62,787	$	(38,126	)	$	181,894
DD&A		10,729		5,447		21,545		23,193		151			61,065
Impairment of unproved properties		728		—		533		2,219		—			3,480
Profit (loss)		19,667		11,281		40,633		20,255		(38,273	)		53,563
Expenditures for assets, net		6,504		5,342		7,989		25,785		200			45,820

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

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

10. Subsequent Event

On April 6, 2004, Westport and Kerr-McGee Corporation (“KMG”) entered into an agreement and plan of merger among Westport, KMG and Kerr-McGee (Nevada), LLC, a wholly-owned subsidiary of KMG (“KMG Nevada”), which was previously approved by the respective boards of directors of each company. Pursuant to the merger agreement, KMG agreed to acquire Westport through the merger of

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Westport with and into KMG Nevada. The KMG merger is contingent upon the approval by the stockholders of both companies, as well as other customary closing conditions. Under the terms of the merger agreement, Westport’s stockholders will receive 0.71 (the “Exchange Ratio”) shares of KMG common stock for each share of Westport common stock they own at the effective time of the KMG merger. Each option to purchase Westport common stock and each award of Westport restricted stock outstanding immediately prior to the effective time of the KMG merger will be assumed by KMG and converted into an option to purchase shares of common stock and an award of restricted stock, respectively, of KMG determined by the Exchange Ratio. The exercise price of the assumed options will also be adjusted accordingly. Prior to the consummation of the KMG merger, Westport is obligated to redeem all of its 6 1/2% convertible preferred stock. The merger agreement also contains restrictions on the Company’s ability to enter into additional hedging transactions and exceed its budget for capital expenditures without KMG’s consent.

Upon completion of the transaction, KMG’s executive management team will continue as the management of the combined company and one of the current members of the Westport board of directors will join the KMG board of directors. The KMG merger is expected to be submitted for approval by stockholders of Westport and KMG during the third quarter of 2004. For more information regarding the KMG merger please refer to the joint proxy statement/ prospectus of Westport and KMG that is included in the registration statement on Form S-4 filed by KMG with the Securities and Exchange Commission (the “SEC”) on April 27, 2004, and other relevant materials that may be filed by Westport or KMG with the SEC, including any amendments to such registration statement.


	*Hedging Transactions*

Prior to entering into the merger agreement with Westport, KMG entered into certain financial derivative transactions relating to specified amounts of projected 2004, 2005 and 2006 hydrocarbon production volumes (the “2004-6 edges”). Together with KMG’s and Westport’s existing derivative transactions, these derivative transaction equate to approximately 80% of the combined company’s projected oil and gas production for the last six months of 2004, 24% for 2005 and 22% for 2006. In the event the merger agreement is terminated by Westport under certain circumstances, the 2004-6 hedges will be either terminated, continued by KMG, or assumed by Westport, as more specifically set forth in the merger agreement and the joint proxy statement/ prospectus of Westport and KMG that is included in the registration statement on Form S-4 filed by KMG with the SEC on April 27, 2004.

11. 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 2001, 2002 and 2003 notes were subsequently exchanged by the Company on March 14, 2002, March 12, 2003 and March 17, 2004, respectively, for equal principal amounts of notes having substantially identical terms and registered under the Securities Act. 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

March 31, 2004


							Subsidiary
				Parent Company			Guarantors			Eliminations			Consolidated


				(Unaudited)

				(In thousands)
ASSETS
Current Assets:
	Cash and cash equivalents			$	13,780		$	84,498		$	—		$	98,278
	Accounts receivable, net				23,334			74,437			—			97,771
	Intercompany receivable				1,526,880			—			(1,526,880	)		—
	Derivative assets				4,082			—			—			4,082
	Prepaid expenses				5,591			16,480			—			22,071

			Total current assets		1,573,667			175,415			(1,526,880	)		222,202

Property and equipment, at cost:
	Oil and natural gas properties, successful efforts method:
		Proved properties			430,385			2,365,847			—			2,796,232
		Unproved properties			18,712			105,714			—			124,426
	Field services assets				—			41,291			—			41,291
	Building and other office furniture and equipment				743			10,684			—			11,427

					449,840			2,523,536			—			2,973,376
	Less accumulated depletion, depreciation and amortization				(220,878	)		(580,874	)		—			(801,752	)

			Net property and equipment		228,962			1,942,662			—			2,171,624

Other assets:
	Long-term derivative assets				21,319			—			—			21,319
	Goodwill				—			244,640			—			244,640
	Other assets				17,702			—			—			17,702

			Total other assets		39,021			244,640			—			283,661

			Total assets	$	1,841,650		$	2,362,717		$	(1,526,880	)	$	2,677,487

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable			$	9,222		$	57,635		$	—		$	66,857
	Accrued expenses				37,664			26,754			—			64,418
	Ad valorem taxes payable				68			18,254			—			18,322
	Intercompany payable				—			1,526,880			(1,526,880	)		—
	Derivative liabilities				140,152			—			—			140,152
	Income taxes payable				—			10,410			—			10,410
	Other current liabilities				4,469			3,551			—			8,020

			Total current liabilities		191,575			1,643,484			(1,526,880	)		308,179
Long-term debt					964,376			—			—			964,376
Deferred income taxes					(113,690	)		232,810			—			119,120
Long-term derivative liabilities					40,294			—			—			40,294
Other liabilities					16,301			47,442			—			63,743

			Total liabilities		1,098,856			1,923,736			(1,526,880	)		1,495,712

Stockholders’ equity:
	Preferred stock				29			—			—			29
	Common stock				679			3			(3	)		679
	Additional paid-in capital				974,354			199,153			3			1,173,510
	Treasury stock				(608	)		—			—			(608	)
	Retained earnings				(130,498	)		239,626			—			109,128
	Accumulated other comprehensive income				(101,162	)		199			—			(100,963	)

			Total stockholders’ equity		742,794			438,981			—			1,181,775

			Total liabilities and stockholders’ equity	$	1,841,650		$	2,362,717		$	(1,526,880	)	$	2,677,487

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Three Months Ended March 31, 2004


					Parent			Subsidiary
					Company			Guarantors			Eliminations		Consolidated


					(Unaudited)
					(In thousands)
Operating revenues:
	Oil and natural gas sales				$	63,849		$	207,512		$	—	$	271,361
	Hedge settlements					(34,713	)		—			—		(34,713	)
	Gathering income					—			(154	)		—		(154	)
	Non-hedge change in fair value of derivatives					3,924			—			—		3,924
	Gain on sale of operating assets, net					—			67			—		67

				Net revenues		33,060			207,425			—		240,485

Operating costs and expenses:
	Lease operating expense					3,445			23,769			—		27,214
	Production taxes					1			15,335			—		15,336
	Transportation costs					330			3,209			—		3,539
	Gathering expense					—			950			—		950
	Exploration					9,376			3,461			—		12,837
	Depletion, depreciation and amortization					17,624			57,330			—		74,954
	Impairment of unproved properties					729			2,270			—		2,999
	Stock compensation expense					2,693			—			—		2,693
	General and administrative					2,259			7,913			—		10,172

Total operating expenses						36,457			114,237			—		150,694

				Operating income (loss)		(3,397	)		93,188			—		89,791
Other income (expense):
		Interest expense				(17,344	)		(2	)		—		(17,346	)
		Interest income				24			109			—		133
		Other				40			(220	)		—		(180	)

Income (loss) before income taxes						(20,677	)		93,075			—		72,398

Benefit (provision) for income taxes:
		Current				—			(7,863	)		—		(7,863	)
		Deferred				7,547			(26,109	)		—		(18,562	)

			Total benefit (provision) for income taxes			7,547			(33,972	)		—		(26,425	)

	Net income (loss)					(13,130	)		59,103			—		45,973
	Preferred stock dividends					(1,191	)		—			—		(1,191	)

	Net income (loss) available to common stockholders				$	(14,321	)	$	59,103		$	—	$	44,782

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Three Months Ended March 31, 2004


					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)
					(Unaudited)
Cash flows from operating activities:
	Net income (loss)				$	(13,130	)	$	59,103		$	—		$	45,973
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Depletion, depreciation and amortization					17,624			57,330			—			74,954
	Exploration dry hole costs					1,792			2,108			—			3,900
	Impairment of unproved properties					729			2,270			—			2,999
	Deferred income taxes					(7,547	)		26,109			—			18,562
	Stock compensation expense					2,693			—			—			2,693
	Change in fair value of derivatives					(3,924	)		—			—			(3,924	)
	Amortization of deferred financing fees					371			—			—			371
	Gain on sale of operating assets, net					—			(67	)		—			(67	)
	Changes in asset and liabilities, net of effects of acquisitions:
		Decrease (increase) in accounts receivable				935			(11,772	)		—			(10,837	)
		Decrease (increase) in prepaid expenses				397			(5,266	)		—			(4,869	)
		Increase in net derivative liabilities				1,342			—			—			1,342
		Decrease in accounts payable				(2,630	)		(6,583	)		—			(9,213	)
		Increase in ad valorem taxes payable				49			4,426			—			4,475
		Increase in income taxes payable				—			7,911			—			7,911
		Increase (decrease) in accrued expenses				14,611			(2,057	)		—			12,554
		Decrease in other liabilities				(9	)		(521	)		—			(530	)

			Net cash provided by operating activities			13,303			132,991			—			146,294

Cash flows from investing activities:
	Additions to property and equipment					(28,979	)		(70,221	)		—			(99,200	)
	Proceeds from sales of assets					—			24			—			24
	Decrease in intercompany receivable					6,445			—			(6,445	)		—

				Net cash used in investing activities		(22,534	)		(70,197	)		(6,445	)		(99,176	)

Cash flows from financing activities:
	Proceeds from issuance of common stock					3,812			—			—			3,812
	Repurchase of common stock					(25	)		—			—			(25	)
	Repayment of long term debt					(25,000	)		—			—			(25,000	)
	Preferred stock dividends paid					(1,191	)		—			—			(1,191	)
	Financing fees					(94	)		—			—			(94	)
	Decrease in intercompany payable					—			(6,445	)		6,445			—

			Net cash provided by (used in) financing activities			(22,498	)		(6,445	)		6,445			(22,498	)

Net increase (decrease) in cash and cash equivalents						(31,729	)		56,349			—			24,620
Cash and cash equivalents, beginning of period						45,509			28,149			—			73,658

Cash and cash equivalents, end of period					$	13,780		$	84,498		$	—		$	98,278

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2003


					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(In thousands)
ASSETS
Current Assets:
		Cash and cash equivalents			$	45,509		$	28,149		$	—		$	73,658
		Accounts receivable, net				24,269			62,665			—			86,934
		Intercompany receivable				1,533,325			—			(1,533,325	)		—
		Derivative assets				3,728			—			—			3,728
		Prepaid expenses				5,988			11,214			—			17,202

			Total current assets			1,612,819			102,028			(1,533,325	)		181,522

		Property and equipment, at cost:
		Oil and natural gas properties, successful efforts method:
			Proved properties			403,927			2,303,301			—			2,707,228
			Unproved properties			18,421			100,910			—			119,331
		Field services assets				—			40,226			—			40,226
		Building and other office furniture and equipment				711			10,215			—			10,926

						423,059			2,454,652			—			2,877,711
	Less accumulated depletion, depreciation and amortization					(203,563	)		(524,583	)		—			(728,146	)

		Net property and equipment				219,496			1,930,069			—			2,149,565

Other assets:
		Long-term derivative assets				23,105			—			—			23,105
		Goodwill				—			244,640			—			244,640
		Other assets				18,431			—			—			18,431

		Total other assets				41,536			244,640			—			286,176

		Total assets			$	1,873,851		$	2,276,737		$	(1,533,325	)	$	2,617,263


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
		Accounts payable			$	15,511		$	64,186		$	—		$	79,697
		Accrued expenses				19,101			26,035			—			45,136
		Ad valorem taxes payable				20			13,827			—			13,847
		Intercompany payable				—			1,533,325			(1,533,325	)		—
		Derivative liabilities				107,529			—			—			107,529
		Income taxes payable				—			2,499			—			2,499
		Current asset retirement obligation				4,479			3,538			—			8,017

				Total current liabilities		146,640			1,643,410			(1,533,325	)		256,725
		Long-term debt				980,885			—			—			980,885
		Deferred income taxes				(88,677	)		206,701			—			118,024
		Long-term derivative liabilities				38,022			—			—			38,022
		Other liabilities				15,962			46,747			—			62,709

				Total liabilities		1,092,832			1,896,858						1,456,365

Stockholders’ equity:
		Preferred stock				29			—			—			29
		Common stock				675			3			(3	)		675
		Additional paid-in capital				967,851			199,154			3			1,167,008
		Treasury stock				(583	)		—			—			(583	)
		Retained earnings				(116,177	)		180,523			—			64,346
		Accumulated other comprehensive income				(70,776	)		199			—			(70,577	)

				Total stockholders’ equity		781,019			379,879			—			1,160,898

				Total liabilities and stockholders’ equity	$	1,873,851		$	2,276,737		$	(1,533,325	)	$	2,617,263

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Three Months Ended March 31, 2003


			Parent			Subsidiary
			Company			Guarantors			Eliminations		Consolidated


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

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

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

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

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

Income (loss) before income taxes				(44,345	)		81,912			—		37,567

Benefit (provision) for income taxes:
	Current			—			—			—		—
	Deferred			16,186			(29,898	)		—		(13,712	)

		Total benefit (provision) for income taxes		16,186			(29,898	)		—		(13,712	)

Net income (loss) before cumulative change in accounting principle				(28,159	)		52,014			—		23,855
Preferred stock dividends				(1,191	)		—			—		(1,191	)
Cumulative effect of change in accounting principle				1,765			(5,179	)		—		(3,414	)

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

WESTPORT RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Three Months Ended March 31, 2003


					Parent			Subsidiary
					Company			Guarantors			Eliminations			Consolidated


					(Unaudited)
					(In thousands)
Cash flows from operating activities:
	Net income (loss)				$	(26,394	)	$	46,835		$	—		$	20,441
	Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
		Depletion, depreciation and amortization				18,191			42,874			—			61,065
		Exploration dry hole costs				3,462			1,430			—			4,892
		Impairment of unproved properties				2,091			1,389			—			3,480
		Deferred income taxes				(16,186	)		29,898			—			13,712
		Stock compensation expense				(3	)		—			—			(3	)
		Change in fair value of derivatives				(2,320	)		—			—			(2,320	)
		Amortization of financing fees				282			—			—			282
		Gain on sale of operating assets, net				—			(392	)		—			(392	)
		Cumulative change in accounting principle, net of tax				(1,765	)		5,179			—			3,414
		Changes in asset and liabilities, net of effects of acquisitions:
			Increase in accounts receivable			(1,186	)		(25,217	)		—			(26,403	)
			Decrease (increase) in prepaid expenses			3,233			(4,235	)		—			(1,002	)
			Increase in derivative liabilities			137			—			—			137
			Increase (decrease in) accounts payable			457			(132	)		—			325
			Increase in ad valorem taxes payable			—			2,998			—			2,998
			Increase in accrued expenses			11,989			2,888			—			14,877
			Decrease in other liabilities			—			(217	)		—			(217	)

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

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

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

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

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

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

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


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.

Executive Summary


	*Overview*

We are an independent energy company engaged in oil and natural gas production, exploitation, acquisition, and exploration activities primarily in the United States. We focus on maintaining a balanced portfolio of lower-risk, long-lived onshore reserves and higher-margin shorter-lived Gulf Coast and Gulf of Mexico reserves to provide a diversified cash flow foundation for our exploitation, acquisition and exploration activities. We are gas-weighted, with natural gas and natural gas liquids comprising approximately 76% of our total reserves, and we operate about 77% of our reserve value, giving us the ability to control the development of the majority of our properties. On a reserve volume basis, approximately 56% of our reserves are located in Rocky Mountain properties managed by our Northern and Western Divisions, approximately 36% are in Permian Basin/ Mid-Continent and Gulf Coast properties managed by our Southern Division and the remaining 8% are in offshore properties in the Gulf of Mexico managed by our Gulf of Mexico Division.

Historically, acquisitions of producing properties and the subsequent exploitation of those properties have accounted for most of our growth. From December 31, 1997 to December 31, 2003 primarily as a result of these investments, we increased our estimated proved reserves from 197 Bcfe to 1,781 Bcfe, and our average daily production increased from 66 Mmcfe/d to 455 Mmcfe/d, yielding compounded annual growth rates of approximately 44% and 38%, respectively.

Notwithstanding our rapid growth, and as an integral part of our growth strategy, we have maintained a disciplined approach to the control of costs. Over the six-year period ending on December 31, 2003 we have reduced our per unit cost structure from $1.32 per Mcfe to $1.14 per Mcfe of our net production for the aggregate of lease operating expenses, transportation costs, production taxes and general and administrative costs. We have accomplished this while maintaining a strong balance sheet and significant financial flexibility.

We expect that our future growth will continue to depend on our ability to continue to add reserves primarily through acquisitions and subsequent exploitation and to a lesser extent exploration successes.


	*First Quarter 2004 Highlights*

• Record levels of production  — Our average daily natural gas equivalent production was approximately 551 Mmcfe/d for the first quarter of 2004, a 21% increase from 455 Mmcfe/d for the previous quarter and a 25% increase from 440 Mmcfe/d for the first quarter of last year.

• Record levels of net cash provided by operating activities  — Net cash provided by operating activities was $146.3 million for the first quarter of 2004, a 39% increase from $105.4 million for the previous quarter and a 54% increase from $95.3 million for the first quarter of last year.

• Record levels of net income available to common stockholders  — Net income available to common stockholders was $44.8 million for the first quarter of 2004 compared to $7.2 million for the previous quarter and $19.3 million for the first quarter of last year.

• Continuation of reduction of lease operating costs per Mcfe  — Lease operating costs per Mcfe were $0.54 in the first quarter of 2004, a 5% reduction from $0.57 in the previous quarter and a 19% reduction from $0.67 in the first quarter of last year.

• 74 wells drilled with a 96% success rate — We drilled 74 wells with a 96% success rate in the first quarter of 2004, compared to 87 wells with a 93% success rate in the previous quarter and 47 wells with an 89% success rate in the first quarter of last year.


	*Full Year 2004 Outlook*

On April 6, 2004, we entered into an agreement and plan of merger with Kerr-McGee Corporation, referred to as KMG, and Kerr-McGee (Nevada) LLC, a wholly-owned subsidiary of KMG and referred to as KMG Nevada, which was previously approved by the respective boards of directors of each company. Pursuant to the merger agreement, KMG agreed to acquire us through the merger of Westport with and into KMG Nevada. The KMG merger is contingent upon the approval by the stockholders of both companies, as well as other customary closing conditions. Under the terms of the merger agreement, our stockholders will receive 0.71 shares of KMG common stock for each share of Westport common stock they own at the effective time of the KMG merger, referred to as the exchange ratio. Each option to purchase Westport common stock and each award of Westport restricted stock outstanding immediately prior to the effective time of the KMG merger will be assumed by KMG and converted into an option to purchase shares of common stock and an award of restricted stock, respectively, of KMG determined by the exchange ratio. The exercise price of the assumed options will also be adjusted accordingly. Prior to the consummation of the KMG merger, Westport is obligated to redeem all of its 6 1/2% convertible preferred stock. The merger agreement also contains restrictions on our ability to enter into additional hedging transactions and exceed our budget for capital expenditures without KMG’s consent.

Upon completion of the transaction, KMG’s executive management team will continue as the management of the combined company and one of the current members of our board of directors will join the KMG board of directors. The KMG merger is expected to be submitted for approval by stockholders of Westport and KMG during the third quarter of 2004. For more information regarding the KMG merger please refer to the joint proxy statement/ prospectus of Westport and KMG that is included in the registration statement on Form S-4 filed by KMG with the SEC on April 27, 2004, and other relevant materials that may be filed by us or KMG with the SEC, including any amendments to such registration statement.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or 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. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and gas revenues, oil and gas properties, fair value of derivative instruments, income taxes and contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:

• Revenue Recognition. We follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. 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. Substantially all of our oil and natural gas properties are located within the continental United States and the Gulf of Mexico.

• Proved Reserve Estimates. Estimates of our proved reserves included in this report 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 is based on estimates prepared by Ryder Scott Company, Netherland, Sewell & Associates, Inc. and our engineering staff. Estimates prepared by different third parties may be higher or lower than the estimates represented in our reserve report.

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 natural 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 based the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

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

• Impairment of Proved Oil and Gas Properties. Because we use the successful efforts method of accounting to account for our oil and gas operations, we assess our proved properties for impairment on a field-by-field basis, in accordance with the provisions of Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” 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. 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. 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 reserves, future production, future commodity prices, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected future cash flows. Management has chosen to use the traditional present value approach to determine the fair value as opposed to the expected present value method. In the traditional present value approach, a single set of estimated cash flows and a single interest rate (commensurate with the risk) are used to estimate fair value. In the expected present value approach, multiple cash flow scenarios reflecting the range of possible outcomes and a risk-free rate are used to estimate fair value. Using the expected present value method could result

in different (and possibly higher) amounts for property impairments than those calculated using the traditional present value method.

• Impairment of Goodwill. Goodwill of a reporting unit is tested for impairment on an annual basis at year-end 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. The factors used to determine fair value include estimates of reserves, future production, future commodity prices, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected future cash flows. Management has chosen to use the traditional present value approach to determine the fair value as opposed to the expected present value method. In the traditional present value approach, a single set of estimated cash flows and a single interest rate (commensurate with the risk) are used to estimate fair value. In the expected present value approach, multiple cash flow scenarios reflecting the range of possible outcomes and a risk-free rate are used to estimate fair value. Using the expected present value method could result in different (and possibly higher) impairment charges than those calculated using the traditional present value method.

• Impairment of Unproved Oil and Gas Properties. We periodically assess our unproved properties to determine if any such properties have been impaired. Such assessment is based on, among other things, the fair value of properties located in the same area as the unproved property and our intent to pursue additional exploration opportunities on such property. Future changes in any of the above-referenced factors could result in us recording unproved property impairment charges in future periods.

• 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 future contracts, swaps or options, 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. Under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” 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 commodity price risk management, or CPRM, activities.

• Valuation of Deferred Tax Assets. The Company computes income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires an asset and 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.

Results of Operations

Our results of operations are significantly impacted by the prices of oil and natural gas, which are volatile. Approximately 71% of our volumes sold in the first quarter of 2004 were natural gas compared to approximately 69% in the first quarter of 2003. We attempt to manage commodity price volatility through our CPRM activities described above in “Critical Accounting Policies and Estimates.”

Oil and natural gas production costs are composed of lease operating expense, production taxes and transportation costs. Lease operating expense consists of pumper 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 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. We focus our efforts on reducing controllable operating costs per unit of production.

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 re-determined 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. The level of proved reserves is also impacted by assumptions regarding the performance of the oil and gas properties. See “Critical Accounting Policies and Estimates” above for more information on proved reserve estimates and how they impact depletion expense.

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.

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

Historically, we have been able to overcome natural declines in oil and natural gas production by adding, through acquisitions and drilling, more reserves than we produce. Our future growth, if any, will depend on our ability to continue to add oil and natural gas reserves in excess of production.

On December 18, 2003, we completed the acquisition of certain oil and natural gas properties located in south Texas for a total cash purchase price of approximately $342 million, referred to as the South Texas acquisition. Operations from the properties were included in our results beginning December 19, 2003.

The following table sets forth selected data for the three months ended March 31, 2004 and 2003.

Summary Data


								Change			% Change
		Three Months			Three Months			First Quarter			First Quarter
		Ended			Ended			2004 vs.			2004 vs.
		March 31,			March 31,			First Quarter			First Quarter
		2004			2003			2003			2003

Average Daily Production
	Oil (Mbbls/d)		27.0			22.7			4.3			19	%
	Natural gas (Mmcf/d)		388.7			303.5			85.2			28	%
	Mmcfe/d		551.0			439.9			111.1			25	%
Production
	Oil (Mbbls)		2,461			2,046			415			20	%
	Natural gas (Mmcf)		35,372			27,319			8,053			29	%
	Mmcfe		50,138			39,595			10,543			27	%
Average prices before hedging
	Oil (per bbl)	$	33.14		$	31.63		$	1.51			5	%
	Natural gas (per Mcf)		5.37			5.63			(0.26	)		(5	)%
	Price (per Mcfe)		5.41			5.52			(0.11	)		(2	)%
Average prices after hedging
	Oil (per bbl)		28.95			26.60			2.35			9	%
	Natural gas (per Mcf)		4.68			4.52			0.16			4	%
	Price (per Mcfe)		4.72			4.50			0.22			5	%
Oil and natural gas sales:
	Volume variance								56,956
	Price variance(1)								(4,014	)
	Total(1)		271,361			218,419			52,942			24	%
Hedge settlements			(34,713	)		(40,446	)		5,733			14	%
Lease operating expense			27,214			26,336			878			3	%
	Per Mcfe		0.54			0.67			(0.13	)		(19	)%
Production taxes			15,336			13,058			2,278			17	%
	Per Mcfe		0.31			0.33			(.02	)		(6	)%
Production taxes as a percent of sales(1)			6	%		6	%		—			—
Transportation costs			3,539			4,024			(485	)		(12	)%
	Per Mcfe		0.07			0.10			(.03	)		(30	)%
Depletion, depreciation and amortization			74,954			61,065			13,889			23	%
	Per Mcfe		1.49			1.54			(0.05	)		(3	)%
General and administrative costs			10,172			7,228			2,944			41	%
	Per Mcfe		0.20			0.18			.02			11	%

(1) Sales before hedging.

The following table sets forth the changes in our results between the three month periods ended March 31, 2004 and 2003 for selected items along with an estimate of how much those results were impacted by the South Texas acquisition discussed above.



		Change Three Months Ended March 31,
		2004 vs. 2003

		Acquisitions(1)		All Other			Total

Average Daily Production:
	Oil (Mbbls/d)		0.7		3.6			4.3
	Natural gas (Mmcf/d)		53.1		32.1			85.2
	Mmcfe/d		57.4		53.7			111.1
Production:
	Oil (Mbbls)		65		350			415
	Natural gas (Mmcf)		4,830		3,223			8,053
	Mmcfe		5,220		5,323			10,543
Oil and natural gas sales:
	Volume variance	$	27,906	$	29,050		$	56,956
	Price variance(2)		—		(4,014	)		(4,014	)
	Total		27,906		25,036			52,942
Lease operating expense			2,490		(1,612	)		878
Production taxes			2,760		(482	)		2,278
Transportation costs			56		(541	)		(485	)
Depletion, depreciation and amortization			10,036		3,853			13,889

(1) Includes the South Texas acquisition, plus additions from successful post-closing developmental drilling on the acquired properties.

(2) Sales before hedging.


	*Comparison of Results of Operations — Three months ended March 31, 2004 and 2003*

Revenues. Oil and natural gas revenues for the three months ended March 31, 2004 increased by $52.9 million, or 24%, from $218.4 million to $271.4 million, compared to the three months ended March 31, 2003. Production from acquisitions accounted for $27.9 million of the increase and discoveries in the Gulf of Mexico accounted for $26.2 million of the increase. Additionally, increases from developmental drilling in the Western and Southern divisions and higher oil prices were partially offset by natural declines in production in other existing properties and lower gas prices. Production volumes increased 10.5 Bcfe from 39.6 Bcfe for the three months end March 31, 2003 to 50.1 Bcfe for the three months ended March 31, 2004. Production from acquisitions accounted for 5.2 Bcfe of the increase and discoveries in the Gulf of Mexico accounted for 4.6 Bcfe of the increase. Oil prices before hedging increased 5% for the three months ended March 31, 2004 compared to the three months ended March 31, 2003 and natural gas prices before hedging decreased 5% for the three months ended March 31, 2004 compared to the three months ended March 31, 2003 causing the average prices per Mcfe before hedging to decrease 2%. Hedging transactions had the effect of reducing oil and natural gas revenues by $34.7 million for the three months ended March 31, 2004, or $0.69 per Mcfe, and $40.4 million for the three months ended March 31, 2003, or $1.02 per Mcfe.

Lease Operating Expense. Lease operating expense for the three months ended March 31, 2004 increased by $0.9 million, or 3%, from $26.3 million to $27.2 million, compared to the three months ended March 31, 2003. Lease operating expenses from acquisitions accounted for $2.5 million of the increase. The increase was offset by decreases in workovers of $1.4 million, primarily in the Northern and the Western divisions. On a per Mcfe basis, lease operating expense decreased from $0.67 for the three months ended March 31, 2003 to $0.54 for the three months ended March 31, 2004. The decrease on a

per Mcfe basis was partially due to a $0.04 per Mcfe decrease in workovers. In addition, lease operating expense per Mcfe for the Western division properties, which were acquired in December 2002, decreased by $0.19 or 28%, excluding workovers.

Production Taxes. Production taxes for the three months ended March 31, 2004 increased by $2.3 million, or 17%, from $13.1 million to $15.3 million, compared to the three months ended March 31, 2003. Acquisitions accounted for $2.8 million of the increase. The increase was partially offset by a decrease in natural gas prices before hedges. As a percent of oil and natural gas revenues (excluding the effects of hedges), production taxes remained flat at 6% for the three months ended March 31, 2004 and 2003, respectively.

Transportation Costs. Transportation costs for the three months ended March 31, 2004 decreased by $0.5 million, or 12%, from $4.0 million to $3.5 million, compared to the three months ended March 31, 2003. On a per Mcfe basis, transportation costs decreased from $0.10 for the three months ended March 31, 2003 to $.07 for the three months ended March 31, 2004. The decreases were a result of transportation cost reductions in the Western division.

Depletion, Depreciation and Amortization, or DD&A, Expense. DD&A expense increased $13.9 million for the three months ended March 31, 2004, from $61.1 million to $75.0 million, compared to the three months ended March 31, 2003. DD&A expense related to acquisitions caused $10.0 million of the increase. Discoveries in the Gulf of Mexico caused DD&A expense to increase $3.4 million. The remaining increase was primarily due to the additions from drilling of oil and natural gas properties during 2004. On a per Mcfe basis, DD&A expense decreased from $1.54 for the three months ended March 31, 2003 to $1.49 for the three months ended March 31, 2004.

General and Administrative, or G&A, Expense. G&A expense increased $2.9 million for the three months ended March 31, 2004, or 41%, from $7.2 million to $10.1 million, compared to the three months ended March 31, 2003. The majority of the increase was due to additional staff required as a result of the acquisition of the Uinta Basin properties in December 2002 and the South Texas properties in December 2003, which caused an increase in salary and related benefit costs. Increases in staffing related to the Uinta Basin properties did not occur until the end of the first quarter of 2003. On a per Mcfe basis, G&A expense increased from $0.18 for the three months ended March 31, 2003 to $0.20 in 2004, primarily as a result of expenses attributable to certain shareholder relations, public filings and software costs that we do not expect to continue to incur during the remainder of the year.

Hedge Settlements and Non-hedge Change in Fair Value of Derivatives. We recorded a realized loss related to hedging settlements of $34.7 million for the three months ended March 31, 2004, compared to a realized loss of $40.4 million for the three months ended March 31, 2003. The hedging losses had the effect of reducing oil and natural gas sales by $0.69 per Mcfe for the three months ended March 31, 2004 and $1.02 per Mcfe for the three months ended March 31, 2003. We recorded an unrealized net gain of $3.9 million in the non-hedge change in fair value of derivatives for the three months ended March 31, 2004 compared to an unrealized net gain of $2.3 million for the three months ended March 31, 2003. These gains and losses were the result of changes in fair value of derivative instruments that either did not qualify for hedge accounting or were not originally designated as hedges.

Gain (Loss) on Sale of Operating Assets. For the three months ended March 31, 2004 and 2003 we recorded a net gain of $67,000 and $0.4 million, respectively, in connection with the sale of non-strategic properties. The gains and losses were calculated as the difference between the sales proceeds and the carrying value of the properties as of the date of the sale.

Exploration Costs. Exploration costs for the three months ended March 31, 2004 increased by $0.8 million, or 7%, from $12.0 million to $12.8 million, compared to the three months ended March 31, 2003. The following table sets forth the components of our exploration costs:



	Three Months Ended
	March 31,

	2004		2003


	(In thousands)
Geological and geophysical costs	$	8,154	$	6,612
Unsuccessful property acquisitions		117		—
Delay rentals		666		543
Exploratory dry holes		3,900		4,892

	$	12,837	$	12,047

Impairment of Unproved Properties. For the three months ended March 31, 2004, we recognized unproved property impairments of $3.0 million due to expired leases and from an assessment of the exploration opportunities existing on such properties. The impairments were for leases held as follows: $0.7 million in the Gulf of Mexico, $1.2 million in the Northern division, $0.9 million in the Southern division and $0.2 million in the Western division. For the three months ended March 31, 2003, we recognized unproved property impairments of $3.5 million due to expired leases and from an assessment of the exploration opportunities existing on such properties. The impairments were for leases held as follows: $2.2 million in the Gulf of Mexico, $0.7 million in Northern division and $0.6 million in the Southern division.

Stock Compensation Expense. For the three months ended March 31, 2004 and 2003 we recorded $2.6 million, and $19,000, respectively, of stock compensation expense related to certain stock options as a result of applying the provisions of FASB Interpretation No. 44 and recorded $0.1 million, and ($22,000) respectively, in expense related to the issuance of restricted stock.

Other Income (Expense). Other expense for the three months ended March 31, 2004 was ($17.4 million) compared to ($16.0 million) for the three months ended March 31, 2003. Interest expense increased $1.0 million for the three months ended March 31, 2004, as a result of the increase in the debt balance relating to acquisitions.

Income Taxes. We recorded income tax expense of $26.4 million for the three months ended March 31, 2004 ($18.6 million deferred and $7.8 million current) and deferred income tax expense of $13.7 million for the three months ended March 31, 2003. The effective tax rate was 36.5% in both periods.

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.

Recent Accounting Developments

In June 2001, the FASB issued SFAS No. 141, “Business Combinations” and SFAS No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 141 addresses accounting and reporting for business combinations and is effective for all business combinations initiated after June 30, 2001. SFAS No. 142 addresses the accounting and reporting for acquired goodwill and other intangible assets.

A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive industries, including oil and natural gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights associated with extracting oil and natural gas as intangible assets in the balance sheet, apart from other capitalized oil and

natural gas property costs, and to provide specific footnote disclosures. Historically, we have included the costs of mineral/drilling rights associated with extracting oil and natural gas as tangible assets and as a component of oil and natural gas properties. If it is ultimately determined that SFAS No. 142 requires oil and natural as companies to classify costs of mineral rights associated with extracting oil and natural gas as a separate intangible assets line item on the balance sheet, we would be required to reclassify the amounts as follows:


			March 31,			December 31,
			2004			2003

INTANGIBLE ASSETS:
	Proved leasehold acquisition costs		$	1,435,978,859		$	1,434,134,563
	Unproved leasehold acquisition costs			124,425,771			119,330,993

		Total leasehold acquisition costs		1,560,404,630			1,553,465,556
	Less accumulated depletion			(246,201,975	)		(227,819,127	)

		Net leasehold acquisition costs	$	1,314,202,655		$	1,325,646,429

Our cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with SFAS No. 144. Further, we do not believe the classification of the costs of mineral rights associated with extracting oil and natural gas as intangible assets would have any impact on our compliance with covenants under our debt agreements.

Liquidity and Capital Resources

Historically, our primary sources of funds have been cash flow from our producing oil and gas properties, the issuance of debt and equity securities, borrowings under our bank credit facilities, and to a minor extent proceeds from sales of non-strategic properties. Our ability to access any of these sources of funds can be significantly impacted by unexpected decreases in oil and natural gas prices. To mitigate the effects of dramatic commodity price fluctuations we typically hedge between 20% and 40% of our expected production over the next two years. In addition we may hedge a larger proportion of our expected production from acquired properties in order to reduce the risk of receiving significantly lower revenues than anticipated at the time of acquisition.

Our principal uses of funds have been for the exploitation, acquisition and exploration of oil and natural gas properties, operation of our business, interest payments, debt repayments and preferred stockholder dividends. Our expenditures for acquisitions are discretionary. In the event of an unexpected decrease in oil and natural gas prices, other planned capital expenditures can also be reduced, if necessary. If prices increase unexpectedly, we have more flexibility to pursue growth opportunities and to reduce our debt.

Net cash provided by operating activities was $146.3 million for the three months ended March 31, 2004, compared to $95.3 million for the three months ended March 31, 2003. Operating cash flow in the three month period increased compared to the respective prior period due to increased production.

Net cash used in investing activities was $99.2 million for the three months ended March 31, 2004, compared to $42.3 million for the three months ended March 31, 2003. For the three months ended March 31, 2004, $99.2 million was used for exploitation and exploration. Investing activities for the three months ended March 31, 2003 included $50.7 million for exploitation and exploration activities offset by $4.9 million in acquisition purchase price adjustment and by proceeds from sales of properties of $3.5 million.

Net cash used in financing activities was $22.5 million for the three months ended March 31, 2004, compared to $31.1 million for the three months ended March 31, 2003. Financing activities for the three months ended March 31, 2004 consisted of $25.0 million in repayment of long-term debt, a $1.2 million preferred stock dividend payment and a payment of $0.1 million in financing fees, offset by $3.8 million from issuance of common stock in connection with option exercises under our stock option plans.

Financing activities for the three months ended March 31, 2003 consisted of $0.1 million from issuance of common stock, offset by $30.0 million in repayment of long-term debt and a $1.2 million preferred stock dividend payment.

Financing Activity


	*Revolving Credit Facility*

On December 17, 2002, we entered into a revolving credit facility, as may be amended from time to time, with JPMorgan Chase Bank, Credit Suisse First Boston Corporation and certain other lenders party thereto to replace our previous revolving credit facility. A maximum committed amount under our revolving credit facility is $600 million. Our revolving credit facility initially provided for a borrowing base of approximately $470 million. We made borrowings under our revolving credit facility to refinance our outstanding indebtedness under our previous revolving credit facility and to pay general corporate expenses.

On October 15, 2003, our revolving credit facility was amended to increase the borrowing base from $470 million to $500 million. The amendment also eliminated limits on outstanding letters of credit, provided that the amount of letters of credit outstanding on any date does not exceed the lesser of the aggregate commitments under our revolving credit facility and the borrowing base then in effect, or if the borrowing base is not in effect on such date, the aggregate commitments under our revolving credit facility. The amendment also increased the basket allowed for purposes of providing cash collateral from $10 million to $20 million and deleted the requirement to mortgage our properties if the Company was not rated BB+ and Ba1 at December 31, 2003.

Advances under our 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:

plus a margin of 0% to 0.625%, in each case, 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 our 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 facility matures on December 16, 2006 and contains covenants and default provisions customary for similar credit facilities applicable to us and our restricted subsidiaries, including two financial covenants that require us to maintain a current ratio, as defined therein, 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 our 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 our 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 March 31, 2004, we had outstanding under our revolving credit facility borrowings of $237 million and letters of credit of approximately $89.2 million, leaving available unused borrowing capacity of approximately $173.8 million. As of May 1, 2004, we had outstanding under our revolving credit facility borrowings of $237 million and letters of credit of approximately $105.3 million, leaving available unused borrowing capacity of approximately $157.7 million. The letters of credit were issued primarily in connection with the margin requirements of our oil and natural gas derivative contracts.


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

On April 3, 2003, we issued $125 million in additional principal amount of our 8 1/4% Senior Subordinated Notes Due 2011 pursuant to Rule 144A and Regulation S under the Securities Act 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, we issued $275 million of 8 1/4% Senior Subordinated Notes Due 2011 and on December 17, 2002, we issued $300 million of 8 1/4% Senior Subordinated Notes Due 2011. All of the 2001, 2002 and 2003 notes were subsequently exchanged on March 14, 2002, March 12, 2003 and March 17, 2004 respectively, for equal principal amounts of notes having substantially identical terms and registered under the Securities Act.

The notes are senior subordinated unsecured obligations of Westport and are fully and unconditionally guaranteed on a senior subordinated basis by some of our existing and future restricted subsidiaries. The notes mature on November 1, 2011. We pay interest on the notes semiannually on May 1 and November 1. The interest payment due on May 1, 2004 will include additional interest of 0.5% per annum payable on the exchange notes issued on March 17, 2004 and accruing from November 1, 2003 to March 17, 2004, the date we consummated the exchange offer with respect to the 2003 notes. We are 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, we are 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.

The indenture governing the 8 1/4% Senior Subordinated Notes Due 2011 limits our and our restricted subsidiaries’ activities, including the ability 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 our and our restricted subsidiaries’ ability 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 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.


	*Capital Expenditures*

We have entered into a merger agreement with KMG, pursuant to which we will be acquired by KMG through the merger of Westport with and into KMG Nevada, subject to the approval by the stockholders of both companies and other customary closing conditions. The KMG merger is expected to be completed in the third quarter of this year. For more information regarding the KMG merger please refer to the section entitled “Full Year 2004 Outlook” above and the joint proxy statement/ prospectus of Westport and KMG that is included in the registration statement on Form S-4 filed by KMG with the SEC on April 27, 2004, and other relevant materials that may be filed by us or KMG with the SEC, including any amendments to such registration statement. The following discussion relates to our plans for the year without regard to the potential impact of the KMG merger.

We anticipate that our capital expenditures, excluding acquisitions, for 2004 will be approximately $370 million. Our capital expenditures for the three months ended 2004 were $99.2 million, excluding geological and geophysical costs of $8.2 million. We anticipate that our primary cash requirements for 2004 will include the funding of acquisitions, development projects and general working capital needs. 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 expenditures in 2004 through cash flow from operations and available capacity under our revolving credit facility.

We believe that borrowings under our 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 made. Actual levels of capital expenditures may vary significantly due to a variety of factors, including but not limited to:

• drilling results;

• product prices and hedging results;

• industry conditions and outlook;

• equipment availability and service sector costs; and

• property acquisitions.

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;

• marketing of oil and natural gas; and

• the proposed merger with KMG.

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, 2003 and the joint proxy statement/ prospectus of Westport and KMG that is included in the registration statement on Form S-4 filed by KMG with the SEC on April 27, 2004, including any amendments to such registration statement, will be important in determining future results. Actual future results may vary materially from those reflected in our forward-looking statements. Because of these factors, we caution that investors should not place undue reliance on any of our forward-looking statements. Further, any forward-looking statement speaks only as of the date on which it is made, and except as required by law we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.


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

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

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

As of March 31, 2004, we had substantial derivative financial instruments outstanding related to our price risk management program. See Note 4 to our consolidated financial statements in Item 1 of this report for additional details on our oil and natural gas related transactions in effect as of March 31, 2004. For more information on our interest rate swaps in effect as of March 31, 2004, see Note 3 to our consolidated financial statements in Item 1 of this report. See also Note 10 to our consolidated financial statements in Item 1 of this report for information with respect to certain financial derivative transactions entered into by KMG prior to entering into the merger agreement with Westport and Westport’s obligations with respect thereto.


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 (a) 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 (b) 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. is 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 $117.4 million 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 $517.0 million, 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, Use of Proceeds and Issuer Purchases of Equity Securities.*

(a) During the quarter ended March 31, 2004, we issued 333,825 shares of our common stock. The common stock included 122,045 shares of restricted stock and 139,044 shares of our common stock issued in connection with the exercise of options granted pursuant to the 2000 Stock Incentive Plan. We also issued 47,006 shares of our common stock in connection with the exercise of options granted pursuant to the Belco 1996 Stock Incentive Plan and issued 25,730 shares of our common stock in connection with the exercise of options granted pursuant to the EPGC 2000 Stock Option Plan.

(b) On March 10, 2004 we paid the first quarter dividend for 2004 of $0.40625 per share per quarter on our 6 1/2% convertible preferred stock.

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

(d) No repurchases of its equity securities were made by the Company during the period covered by the report.


Item 3.	*Defaults Upon Senior Securities.*

None.


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

None.


Item 5.	*Other Information.*

None.


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

(a) Exhibits. The following exhibits are filed as part of this Form 10-Q 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).
2	.3	Agreement and Plan of Merger, dated as of April 6, 2004, by and among Westport Resources Corporation, Kerr-McGee Corporation and Kerr-McGee (Nevada) LLC (incorporated by reference to Exhibit 2.1 to the current report on Form 8-K, filed on April 7, 2004).
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*	Third Amended and Restated Bylaws of the Company, effective as of October 1, 2003, as amended on November 20, 2003.
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	Termination and Voting Agreement, dated as of October 1, 2003, among the Company, Equitable Resources, Inc., Medicor Foundation, Westport Energy LLC and certain stockholders named therein (incorporated by reference to Exhibit 4.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, filed on November 14, 2003).
4	.5	Registration Right Agreement, dated as of October 1, 2003, among the Company, Equitable Resources, Inc., Medicor Foundation, Westport Energy LLC and certain stockholders named therein (incorporated by reference to Exhibit 4.6 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, filed on November 14, 2003).


4	.6*	Termination Agreement, dated as of April 6, 2004, among the Company, EQT Investments, LLC, Medicor Foundation, Westport Energy LLC and certain stockholders party thereto.
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.

Reports on Form 8-K:

      (a) Current Report on Form 8-K/ A filed on February 5, 2004 (Items 5 and 7);

      (b) Current Report on Form 8-K filed on February 18, 2004 (Item 12);

      (c) Current Report on Form 8-K filed on February 19, 2004 (Item 9); and

      (d) Current Report on Form 8-K filed on April 7, 2004 (Item 5).

SIGNATURES

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

WESTPORT RESOURCES CORPORATION

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

Date: May 5, 2004

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

Date: May 5, 2004

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).
	2	.3	Agreement and Plan of Merger, dated as of April 6, 2004, by and among Westport Resources Corporation, Kerr-McGee Corporation and Kerr-McGee (Nevada) LLC (incorporated by reference to Exhibit 2.1 to the current report on Form 8-K, filed on April 7, 2004).
	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*	Third Amended and Restated Bylaws of the Company, effective as of October 1, 2003, as amended on November 20, 2003.
	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	Termination and Voting Agreement, dated as of October 1, 2003, among the Company, Equitable Resources, Inc., Medicor Foundation, Westport Energy LLC and certain stockholders named therein (incorporated by reference to Exhibit 4.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, filed on November 14, 2003).
	4	.5	Registration Right Agreement, dated as of October 1, 2003, among the Company, Equitable Resources, Inc., Medicor Foundation, Westport Energy LLC and certain stockholders named therein (incorporated by reference to Exhibit 4.6 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, filed on November 14, 2003).
	4	.6*	Termination Agreement, dated as of April 6, 2004, among the Company, EQT Investments, LLC, Medicor Foundation, Westport Energy LLC and certain stockholders party thereto.
	31	.1*	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of the Company.
	31	.2*	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of the Company.
	32	.1*	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of the Company.
	32	.2*	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of the Company.

* Filed herewith.

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(1)	The balance of the 8 1/4% Senior Subordinated Notes Due 2011 as of March 31, 2004 reflects the aggregate face amount of $700 million plus $13.7 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 $13.7 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.

(2)	The balance of the 8 1/4% Senior Subordinated Notes Due 2011 as of December 31, 2003 reflects the aggregate face amount of $700 million plus $14.2 million related to the premium recorded in connection with the issuance of 8 1/4% Senior Subordinated Notes Due 2011 on December 17, 2002


	•	the rate of interest announced by JPMorgan 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%


	•	3.6 Mmbbls of oil and 53.6 Bcf of natural gas subject to CPRM contracts for the remainder of 2004. Of these contracts, all of the oil and 45.3 Bcf of the natural gas contracts are subject to weighted average New York Mercantile Exchange (“NYMEX”) floor prices of $25.41 per barrel and $4.20 per Mmbtu and weighted average NYMEX ceiling prices of $26.44 per barrel and $4.34 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 Northwest Pipeline Rocky Mountain Index (“NWPRM”) at a weighted average swap price of $3.33 per Mmbtu. In addition, included in the 53.6 Bcf of natural gas contracts are basis swaps covering 2.8 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 6.9 Bcf of natural gas for 2004 that lock in the pricing differential between NYMEX and Colorado Interstate Gas Index (“CIG”) at a weighted average price differential of $0.76 per Mmbtu.

	•	2.9 Mmbbls of oil and 42.0 Bcf of natural gas subject to CPRM contracts for 2005, with weighted average NYMEX floor prices of $26.59 per barrel and $4.25 per Mmbtu and weighted average NYMEX ceiling prices of $28.61 per barrel and $5.02 per Mmbtu, respectively. In addition, included in the 42.0 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 per Mmbtu.

	•	0.7 Mmbbls of oil and 7.3 Bcf of natural gas subject to CPRM contracts for 2006 with weighted average NYMEX floor prices of $25.00 per barrel and $4.00 per Mmbtu and weighted average NYMEX ceiling price of $28.65 per barrel and $6.00 per Mmbtu, respectively.


(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 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.

(4)	Three way collars are settled as described in footnote (3) 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 2004 three-way collars, then the effective average floor price would be $23.13 per bbl.

(5)	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.


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

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


	•	Record levels of production — Our average daily natural gas equivalent production was approximately 551 Mmcfe/d for the first quarter of 2004, a 21% increase from 455 Mmcfe/d for the previous quarter and a 25% increase from 440 Mmcfe/d for the first quarter of last year.

	•	Record levels of net cash provided by operating activities — Net cash provided by operating activities was $146.3 million for the first quarter of 2004, a 39% increase from $105.4 million for the previous quarter and a 54% increase from $95.3 million for the first quarter of last year.

	•	Record levels of net income available to common stockholders — Net income available to common stockholders was $44.8 million for the first quarter of 2004 compared to $7.2 million for the previous quarter and $19.3 million for the first quarter of last year.

	•	Continuation of reduction of lease operating costs per Mcfe — Lease operating costs per Mcfe were $0.54 in the first quarter of 2004, a 5% reduction from $0.57 in the previous quarter and a 19% reduction from $0.67 in the first quarter of last year.


	•	74 wells drilled with a 96% success rate — We drilled 74 wells with a 96% success rate in the first quarter of 2004, compared to 87 wells with a 93% success rate in the previous quarter and 47 wells with an 89% success rate in the first quarter of last year.


	•	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. Substantially all of our oil and natural gas properties are located within the continental United States and the Gulf of Mexico.

	•	Proved Reserve Estimates. Estimates of our proved reserves included in this report 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. Because we use the successful efforts method of accounting to account for our oil and gas operations, we assess our proved properties for impairment on a field-by-field basis, in accordance with the provisions of Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” 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. 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. 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 reserves, future production, future commodity prices, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected future cash flows. Management has chosen to use the traditional present value approach to determine the fair value as opposed to the expected present value method. In the traditional present value approach, a single set of estimated cash flows and a single interest rate (commensurate with the risk) are used to estimate fair value. In the expected present value approach, multiple cash flow scenarios reflecting the range of possible outcomes and a risk-free rate are used to estimate fair value. Using the expected present value method could result


		in different (and possibly higher) amounts for property impairments than those calculated using the traditional present value method.

	•	Impairment of Goodwill. Goodwill of a reporting unit is tested for impairment on an annual basis at year-end 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. The factors used to determine fair value include estimates of reserves, future production, future commodity prices, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected future cash flows. Management has chosen to use the traditional present value approach to determine the fair value as opposed to the expected present value method. In the traditional present value approach, a single set of estimated cash flows and a single interest rate (commensurate with the risk) are used to estimate fair value. In the expected present value approach, multiple cash flow scenarios reflecting the range of possible outcomes and a risk-free rate are used to estimate fair value. Using the expected present value method could result in different (and possibly higher) impairment charges than those calculated using the traditional present value method.

	•	Impairment of Unproved Oil and Gas Properties. We periodically assess our unproved properties to determine if any such properties have been impaired. Such assessment is based on, among other things, the fair value of properties located in the same area as the unproved property and our intent to pursue additional exploration opportunities on such property. Future changes in any of the above-referenced factors could result in us recording unproved property impairment charges in future periods.

	•	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 future contracts, swaps or options, 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. Under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” 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 commodity price risk management, or CPRM, activities.

	•	Valuation of Deferred Tax Assets. The Company computes income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires an asset and 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.


(1)	Includes the South Texas acquisition, plus additions from successful post-closing developmental drilling on the acquired properties.

(2)	Sales before hedging.


	•	drilling results;

	•	product prices and hedging results;

	•	industry conditions and outlook;

	•	equipment availability and service sector costs; and

	•	property acquisitions.


	•	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;

	•	marketing of oil and natural gas; and

	•	the proposed merger with KMG.


	(a) Current Report on Form 8-K/ A filed on February 5, 2004 (Items 5 and 7);

	(b) Current Report on Form 8-K filed on February 18, 2004 (Item 12);

	(c) Current Report on Form 8-K filed on February 19, 2004 (Item 9); and

	(d) Current Report on Form 8-K filed on April 7, 2004 (Item 5).


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


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