Use these links to rapidly review the document
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on August 3, 2004

Registration No. 333-103027

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

POST-EFFECTIVE AMENDMENT NO. 3
TO
FORM S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

Abraxas Petroleum Corporation
Grey Wolf Exploration Inc.
Sandia Oil & Gas Corporation
Sandia Operating Corp.
Wamsutter Holdings, Inc.
Western Associated Energy Corporation
Eastside Coal Company, Inc.
(Exact Name of Registrants as Specified in their Charters)

Nevada	1331	74-2584033
Alberta	1331	N/A
Texas	1331	74-2368968
Texas	1331	74-2468708
Wyoming	1331	74-2897013
Texas	1331	74-1937878
Colorado	1331	74-2275407
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)
500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232, (210) 490-4788 (Address, including zip code, and telephone number, including area code, of registrants' principal executive offices)
Robert L. G. Watson President and Chief Executive Officer Abraxas Petroleum Corporation 500 North Loop 1604 East, Suite 100 San Antonio, Texas 78232 (210) 490-4788 (Name, address, including zip code, and telephone number, including area code, of agent for service)

With a copy to:

Cox & Smith Incorporated
112 East Pecan, Suite 1800
San Antonio, Texas 78205
Attn: Steven R. Jacobs
Carlos R. Peña
(210) 554-5500

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC:
As soon as practicable after this Registration Statement becomes effective.

        If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box. ý

        If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

        If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

        If delivery of the prospectus is expected to be made pursuant to Rule 434, check the following box. o

THE REGISTRANTS HEREBY AMEND THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANTS SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.

PROSPECTUS

ABRAXAS PETROLEUM CORPORATION

11¹/2% Secured Notes due 2007, Series A

6,592,699 Shares of Abraxas Common Stock

        This prospectus relates to the offering for resale of Abraxas Petroleum Corporation's 11¹/2% Secured Notes due 2007, Series A, and 6,592,699 shares of common stock of Abraxas Petroleum Corporation. The notes and 5,642,699 shares of common stock were issued in connection with an overall financial restructuring through a private exchange offer exempt from, or not subject to, the registration requirements of the Securities Act of 1933, as amended. The remaining 950,000 shares of common stock represent shares issuable upon exercise of outstanding warrants. This prospectus will be used by selling security holders to resell the notes and shares of common stock. We will not receive any of the proceeds from the sale of notes or common stock by the selling security holders.

The notes

•

accrue interest from the date of issuance, at a fixed annual rate of 11¹/2%, payable in cash semi-annually on each May 1 and November 1, commencing May 1, 2003, provided that, if we fail, or are not permitted pursuant to our new senior credit agreement or the intercreditor agreement between the trustee under the indenture for the notes and the lenders under the new senior credit agreement, to make such cash interest payments in full, we will pay such unpaid interest in kind by the issuance of additional notes with a principal amount equal to the amount of accrued and unpaid cash interest on the notes plus an additional 1% accrued interest for the applicable period;



•

will, upon an event of default, accrue interest at an annual rate of 16.5%;



•

are guaranteed by all of Abraxas' current subsidiaries, Sandia Oil & Gas Corp., Sandia Operating Corp., Wamsutter Holdings, Inc., Western Associated Energy Corporation, Eastside Coal Company, Inc., and our newly-formed, wholly-owned Canadian subsidiary, Grey Wolf Exploration Inc., or New Grey Wolf, and will be guaranteed by all of Abraxas' future subsidiaries;



•

are secured by a second lien or charge on all of our current and future assets, including, but not limited to, our crude oil and natural gas properties; and



•

are not listed on any national securities exchange.

The Abraxas common stock

•

is currently traded on the American Stock Exchange under the symbol "ABP." On July 27, 2004, the closing sale price of Abraxas common stock was $1.28 per share.

        You should carefully consider the risk factors beginning on page 9 of this prospectus in evaluating an investment in the notes or common stock.

Neither the SEC nor any state securities commission has approved or disapproved of the notes or the Abraxas common stock or determined if this prospectus is accurate or complete. Any representation to the contrary is a criminal offense.

August 3, 2004

TABLE OF CONTENTS

        You should rely only on the information contained in this prospectus or a document that we have referred you to. We have not authorized anyone to provide you with information that is different. The delivery of this prospectus shall not, under any circumstances, create any implication that the information herein is correct as of any time subsequent to the date hereof.

The distribution of this prospectus and the sale of the notes or shares of Abraxas common stock may be restricted by law in certain jurisdictions. Persons who receive this prospectus or any of the notes or shares of Abraxas common stock must inform themselves about, and observe, any such restrictions.

ii

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

        We make forward-looking statements throughout this prospectus. Whenever you read a statement that is not simply a statement of historical fact (such as when we describe what we "believe," "expect" or "anticipate" will occur or what we "intend" to do, and other similar statements), you must remember that our expectations may not be correct, even though we believe they are reasonable. The forward-looking information contained in this prospectus is generally located in the material set forth under the headings "Summary," "Risk Factors," "Business," and "Management's Discussion and Analysis of Financial Condition and Results of Operations" but may be found in other locations as well. These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management's reasonable estimates of future results or trends. The factors that may affect our expectations regarding our operations include, among others, the following:

•

our high debt level;



•

our ability to raise capital;



•

our limited liquidity;



•

economic and business conditions;



•

price and availability of alternative fuels;



•

political and economic conditions in oil producing countries, especially those in the Middle East;



•

our success in development, exploitation and exploration activities;



•

planned capital expenditures;



•

prices for crude oil and natural gas;



•

declines in our production of crude oil and natural gas;



•

our acquisition and divestiture activities;



•

results of our hedging activities; and



•

other factors discussed elsewhere in this prospectus.

iii

SUMMARY

The following summarizes the more detailed information appearing elsewhere in this prospectus. As used in this prospectus, "Abraxas" refers to Abraxas Petroleum Corporation and not to any of its subsidiaries, and "we," "our" and "us" refer to Abraxas and all of its subsidiaries. Except as otherwise noted, (i) the reserve data reported in this prospectus is based on the reserve estimates of our independent petroleum engineers and (ii) all dollar amounts referenced in this prospectus are references to U.S. dollars. See "Glossary of Terms" for definitions of some technical terms used in this prospectus.

About Abraxas

        We are an independent energy company engaged primarily in the acquisition, exploration, exploitation, development and production of crude oil and natural gas. Our principal means of growth has been through the acquisition and subsequent development and exploitation of producing properties. As a result of our historical acquisition activities, we believe we have a substantial inventory of low risk exploration and development opportunities, the development of which is critical to the maintenance and growth of our current production levels. We seek to complement our acquisition and development activities by selectively participating in exploration projects with experienced industry partners.

        Our principal areas of operation are Texas and western Canada. At December 31, 2003, we owned interests in 263,730 gross acres (183,354 net acres), and operated properties accounting for approximately 88% of our PV-10, affording us substantial control over the timing and incurrence of operating and capital expenditures. At December 31, 2003 estimated total proved reserves were 121.1 Bcfe with an aggregate PV-10 of $216.8 million. During 2003, we continued exploitation activities on our U.S. and Canadian properties. We participated in the drilling of 24 gross (11.8 net) wells with 23 gross (11.3 net) being successful, representing a total investment of $18.3 million in capital spending during 2003. At the end of 2003, as a result of these activities, our average daily production was approximately 24 MMcfe per day which represented a 26% increase from the daily production rate at the beginning of the year (excluding production from the Canadian properties we sold in January 2003).

        Our principal offices are located at 500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232 and the telephone number is (210) 490-4788.

Financial Restructuring

        In January 2003, we completed the following restructuring transactions:

•

The closing of the sale of the capital stock of our wholly-owned subsidiaries, Canadian Abraxas Petroleum Limited, referred to herein as Canadian Abraxas, and Grey Wolf Exploration Inc., referred to herein as Old Grey Wolf, to a Canadian royalty trust for approximately $138 million.



•

The closing of a new senior credit agreement consisting of a term loan facility of $4.2 million and a revolving credit facility of up to $50 million with an initial borrowing base of $49.9 million, of which $42.5 million was used to fund the exchange offer described below and the remaining availability funded the continued development of our existing crude oil and natural gas properties.



•

The closing of an exchange offer, pursuant to which Abraxas paid $264 in cash and issued $610 principal amount of new 11¹/2% Secured Notes due 2007, Series A, referred to herein as new notes or notes, and 31.36 shares of Abraxas common stock for each $1,000 in principal amount of the outstanding 11¹/2% Senior Secured Notes due 2004, Series A, and 11¹/2% Senior Notes due 2004, Series D, issued by Abraxas and Canadian Abraxas, which were tendered and accepted in the exchange offer. An aggregate of approximately $179.9 million in principal

1

amount of the notes were tendered in the exchange offer and the remaining $11.1 million of notes not tendered were redeemed.

•

The repayment of Abraxas' 12⁷/8% Senior Secured Notes due 2003, principal amount of $63.5 million, plus accrued interest.



•

The repayment of Old Grey Wolf's senior secured credit facility with Mirant Canada Energy Capital Ltd. in the amount of approximately $46.3 million.

        As a result of these transactions, we reduced the principal amount of our total outstanding long-term debt from approximately $300 million at December 31, 2002 to approximately $156.4 million at January 23, 2003 ($170.2 million at March 31, 2004) and reduced our annual cash interest payment from approximately $34 million to approximately $4 million, assuming that, as required under the senior credit agreement, Abraxas continues to issue additional notes in lieu of cash interest payments on the new notes.

Exchange Offer

        On January 23, 2003, Abraxas completed an exchange offer, pursuant to which it offered to exchange cash and securities for all of the outstanding 11¹/2% Senior Secured Notes due 2004, Series A, or second lien notes, and 11¹/2% Senior Notes due 2004, Series D, or old notes, issued by Abraxas and Canadian Abraxas. In exchange for each $1,000 principal amount of notes tendered in the exchange offer, tendering noteholders received:

•

cash in the amount of $264;



•

an 11¹/2% Secured Note due 2007, Series A, with a principal amount equal to $610; and



•

31.36 shares of Abraxas common stock.

        At the time the exchange offer was made, there were approximately $190.2 million of the second lien notes and $801,000 of the old notes outstanding. Holders of approximately 94% of the aggregate outstanding principal amount of the second lien notes and old notes tendered their notes for exchange in the offer. Pursuant to the procedures for redemption under the applicable indenture provisions, the remaining 6% of the aggregate outstanding principal amount of the second lien notes and old notes were redeemed at 100% of the principal amount plus accrued and unpaid interest, for approximately $11.5 million ($11.1 million in principal and $0.4 million in interest). The indentures for the second lien notes and old notes were duly discharged. In connection with the exchange offer, Abraxas made cash payments of approximately $47.5 million and issued approximately $109.7 million in principal amount of new notes and 5,642,699 shares of Abraxas common stock, each of which are being offered for resale under this prospectus. Fees and expenses incurred in connection with the exchange offer were approximately $3.8 million.

        The accounting treatment for this exchange is such that the carrying value of the new exchange notes is calculated by reducing the carrying value of the existing notes, $191.0 million, by the amount of cash paid in the exchange, $47.5 million, by the market value of the stock issued in the exchange, $3.8 million, and by the balance of the notes which were redeemed, $11.1 million. This results in a carrying value of $128.6 million. The expenses related to the exchange offer are expensed as incurred.

        The selling security holders identified in this prospectus are the holders of the notes and shares of Abraxas common stock issued in the exchange offer. The exchange offer was conducted pursuant to an exemption from the registration requirements of the Securities Act of 1933, and as such, the notes and shares of Abraxas common stock issued in the exchange offer are restricted securities. Pursuant to a registration rights agreement with the dealer manager for the exchange offer on behalf of the tendering noteholders, we agreed to file a registration statement with the SEC with respect to the notes and Abraxas common stock, of which this prospectus forms a part, and to use our reasonable best efforts to

2

keep the registration statement effective until two years after its effective date. Upon effectiveness of the registration statement, the notes and shares of Abraxas common stock will be freely tradable by the selling security holders and any subsequent purchasers.

Sale of Stock of Canadian Abraxas and Old Grey Wolf

        Contemporaneously with the closing of the exchange offer, on January 23, 2003, Abraxas completed the sale to a wholly-owned subsidiary of PrimeWest Energy Inc. of all of the outstanding capital stock of two of Abraxas' former wholly-owned subsidiaries, Canadian Abraxas and Old Grey Wolf, for approximately $138 million before net adjustments of $3.4 million. Under the terms of the agreement with PrimeWest, we have retained certain assets formerly held by Canadian Abraxas and Old Grey Wolf, including all of Canadian Abraxas' and Old Grey Wolf's undeveloped acreage existing at the time of the sale, which includes all of our interests in the Ladyfern area. These assets have been contributed to New Grey Wolf. Portions of this undeveloped acreage will be developed by PrimeWest and New Grey Wolf under a farmout arrangement.

        Abraxas used the proceeds from the sale of the capital stock of Canadian Abraxas and Old Grey Wolf for the following purposes:

•

to pay fees and expenses of the sale of Canadian Abraxas and Old Grey Wolf of approximately $2.5 million;



•

to redeem our outstanding 12⁷/8% Senior Secured Notes, Series B, or first lien notes, at 100% of their principal amount, plus accrued and unpaid interest, for approximately $66.4 million; and



•

to pay approximately $19.4 million of the cash portion of the exchange offer.

        In addition, upon the closing of the sale, Old Grey Wolf repaid all of its outstanding indebtedness of approximately $46.3 million.

Redemption of First Lien Notes

        On January 24, 2003, we completed the redemption of 100% of our outstanding 12⁷/8% Senior Secured Notes, Series B, or first lien notes, with approximately $66.4 million of the proceeds from the sale of Canadian Abraxas and Old Grey Wolf. Prior to the redemption, we had $63.5 million of our first lien notes outstanding. Under the terms of the indenture for the first lien notes, as of March 15, 2002, we had the right to redeem the first lien notes at 100% of the outstanding principal amount of the notes, plus accrued and unpaid interest to the date of redemption, and to discharge the indenture upon call of the first lien notes for redemption and deposit of the redemption funds with the trustee. We exercised these rights on January 23, 2003 and upon the discharge of the indenture, the trustee released the collateral securing our obligations under the first lien notes.

Senior Credit Agreement

        Contemporaneously with the closing of the exchange offer and the sale of Abraxas' Canadian subsidiaries, Abraxas entered into a senior credit agreement providing a term loan facility and a revolving credit facility as described below. On February 23, 2004, we entered into an amendment to our senior credit agreement providing for two revolving credit facilities and a new non-revolving credit facility. Subject to earlier termination on the occurrence of events of default or other events, the stated maturity date for these credit facilities is February 1, 2007.

3

Summary of the Offering

        The selling security holders are offering to sell up to 6,592,699 shares of Abraxas common stock and $128,062,054 principal amount in currently outstanding notes, in addition to any notes issued in lieu of cash interest payments thereon. We will not receive any proceeds from the sale of the notes or common stock. You should read the discussions under the headings "Description of the Notes" beginning on page 77 and "Description of Capital Stock" beginning on page 129 for further information regarding the notes and common stock.

Summary of the Notes

Notes	Up to $184 million in principal amount of 111/2% Secured Notes due 2007, which includes approximately $128.0 million principal amount in currently outstanding notes, and any notes issued in lieu of cash interest payments thereon.
Issuer	Abraxas Petroleum Corporation
Maturity Date	May 1, 2007
Interest Rate and Payment Dates	The notes accrue interest from the date of issuance, at a fixed annual rate of 111/2%, payable in cash semi-annually on each May 1 and November 1, commencing May 1, 2003, provided that, if we fail, or are not permitted pursuant to our new senior credit agreement or the intercreditor agreement between the trustee under the indenture for the notes and the lenders under the new senior credit agreement, to make such cash interest payments in full, we will pay such unpaid interest in kind by the issuance of additional notes with a principal amount equal to the amount of accrued and unpaid cash interest on the notes plus an additional 1% accrued interest for the applicable period. The notes will, upon an event of default, accrue interest at an annual rate of 16.5%.
Guarantees	All of Abraxas' current subsidiaries, Sandia Oil & Gas, Sandia Operating (a wholly-owned subsidiary of Sandia Oil & Gas), Wamsutter, New Grey Wolf, Western Associated Energy and Eastside Coal, are guarantors of the notes, and all of Abraxas' future subsidiaries will guarantee the notes. If Abraxas cannot make payments on the notes when they are due, the guarantors must make them instead.

4

Ranking	The notes and related guarantees
	•	are subordinated to the indebtedness under the new senior credit agreement;
	•	rank equally with all of Abraxas' current and future senior indebtedness; and
	•	rank senior to all of Abraxas' current and future subordinated indebtedness, in each case, if any.
	As of March 31, 2004, the amount outstanding under the senior credit agreement was approximately $49.7 million.
Intercreditor Agreement	The notes are subordinated to amounts outstanding under the senior credit agreement both in right of payment and with respect to lien priority and are subject to an intercreditor agreement. For more information on the intercreditor agreement, see the section entitled "Description of the Notes—Intercreditor Agreement" beginning on page 81 of this prospectus.
Collateral	The notes are secured by a second lien or charge on all of our current and future assets, including, but not limited to, all of our crude oil and natural gas properties.
Optional Redemption	Abraxas may redeem some or all of the notes at any time at the redemption prices described in the section entitled "Description of the Notes—Redemption—Optional Redemption" on page 79 of this prospectus.
Mandatory Offer to Repurchase	If Abraxas sells certain assets or experiences specific kinds of changes of control, Abraxas must offer to repurchase the notes, subject to certain limitations in the case of asset sales, at the prices described in the sections "Description of the Notes—Change of Control" and "—Certain Covenants—Limitation on Asset Sales" on pages 80 and 86, respectively, of this prospectus.

5

Basic Covenants of Indenture	Abraxas issued the notes under an indenture with U.S. Bank, N.A. The indenture, among other things, restricts our ability to:
	•	borrow money or issue preferred stock;
	•	pay dividends on stock or purchase stock;
	•	make other asset transfers;
	•	transact business with affiliates;
	•	sell stock of subsidiaries;
	•	engage in any new line of business;
	•	impair the security interest in any collateral for the notes;
	•	use assets as security in other transactions; and
	•	sell certain assets or merge with or into other companies.
	The indenture for the notes also includes certain financial covenants including covenants limiting Abraxas' selling, general and administrative expenses and capital expenditures, a covenant requiring Abraxas to maintain a specified ratio of consolidated EBITDA to cash interest and a covenant requiring Abraxas to permanently, to the extent permitted, pay down debt under the new senior credit agreement and, to the extent permitted by the new senior credit agreement, the notes or, if not permitted, paying indebtedness under the new senior credit agreement.

The Common Stock

        Of the 6,592,699 shares of common stock being offered under this prospectus, 5,642,699 shares were issued in connection with the financial restructuring exchange offer and 950,000 shares are issuable upon exercise of currently outstanding warrants to purchase common stock. Abraxas is currently authorized to issue a total of 200,000,000 shares of common stock, par value $.01 per share, and 1,000,000 shares of preferred stock, par value $.01 per share. As of July 27, 2004, there were 36,252,077 shares of Abraxas common stock outstanding and no shares of preferred stock outstanding. For a more complete description of the common stock, see the section entitled "Description of Capital Stock—Common Stock" beginning on page 129 of this prospectus.

6

Summary Historical Financial Data

        The summary historical financial information, presented below for each of the three years ended December 31, 2001, 2002 and 2003 and for each of the three months ended March 31, 2003 and 2004 has been derived from our consolidated financial statements included in this prospectus. Information for the years ended December 31 represents audited data. Information for the three months ended March 31, 2003 and 2004 is unaudited. It is important that you read this information along with "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Selected Historical Financial Data," our Consolidated Financial Statements and the notes thereto included elsewhere in this prospectus. As discussed in Note 19 to the consolidated financial statements, our financial statements have been restated.

		Years Ended December 31,								Three Months Ended March 31,
		2001*			2002*			2003*		2003*		2004
		(dollars in thousands)
Total operating revenue(1)		$	77,243		$	54,320		$	39,019	$	13,111	$	10,935
Lease and other operating expenses(2)			19,318			15,807			10,208		2,892		3,512
Depreciation, depletion and amortization expense			32,484			26,539			10,803		3,142		3,035
Proved property impairment			2,638			115,993			—		—		—
General and administrative expense			6,455			6,884			5,360		1,395		1,342
Interest expense, net of interest income(3)			31,445			34,058			16,925		5,154		5,113
Amortization of deferred financing fee			2,268			2,095			1,678		377		445
Financing cost			—			967			4,406		3,601		971
Gain on sale of foreign subsidiaries			—			—			68,933		66,960		—
Gain (loss) on sale of equity investment			(845	)		—			—		—		—
Other			207			201			774		—		11
Income (loss)		$	(19,718	)	$	(118,527	)	$	55,920	$	62,702	$	(5,557	)
Income (loss) per common share:
	Basic	$	(0.76	)	$	(3.95	)	$	1.58	$	1.83	$	(0.15	)
	Diluted	$	(0.76	)	$	(3.95	)	$	1.55	$	1.82	$	(0.15	)
Other Data:
	Capital expenditures (including acquisitions)	$	57,056		$	38,912		$	18,349	$	4,589	$	4,230
	Ratio of earnings to fixed charges(4)		n/a			n/a			4.0x		12.5x		n/a

	March 31, 2004
	(dollars in thousands)
Consolidated Balance Sheet Data:
Total assets	$	126,041
Total other liabilities		14,898
Total debt		186,971
Stockholders' deficit		(75,828	)

(1)

Consists of crude oil and natural gas production sales, revenue from rig operations and other miscellaneous revenue.

(2)

Consists of lease operating expenses, production taxes and rig operating expenses.

(3)

Interest expense on our indebtedness includes cash interest expense on the new revolving credit facility and non-cash (additional notes) interest expense on the term loan and the new notes. Non-cash interest expense is calculated at 9% on the term loan and at an imputed rate of 8.6% on the new notes based on the carrying value of the exchanged notes of $128.6 million.

7

(4)

Earnings consist of income (loss) from before income taxes plus fixed charges. Fixed charges consist of interest expense, amortization of deferred financing fees and premium on the old notes. Our earnings were inadequate to cover fixed charges in 2001 and 2002 by $15.6 million and $148.2 million, respectively. In 2003, we had earnings of $74.9 million and fixed charges of $18.6 million. Our ratio of earnings to fixed charges was 4.0x. For the quarter ended March 31, 2003 we had earnings of $69.0 million and fixed charges of $5.5 million. Our ratio of earnings to fixed charges for March 31, 2003 was 12.5x. For the quarter ended March 31, 2004, our earnings were inadequate to cover fixed charges by $5.6 million.

*

Data includes Canadian Abraxas and Old Grey Wolf for 2001, 2002 and the first 23 days of 2003 which were sold in January 2003.

Summary Historical Operating Data

		Years Ended December 31,						Three Months Ended March 31,
		2001*		2002*		2003*		2003*		2004
		(dollars in thousands, except per unit data)
Production:
	Crude oil (MBbls)		454		292		252		65		64
	NGLs (MBbls)		278		242		37		20		13
	Natural gas (MMcf)		17,496		15,453		6,189		1,965		1,687
	MMcfe		21,888		18,658		7,923		4,825		2,475
Average Sales Price:(1)
	Crude oil (per Bbl)	$	24.63	$	24.34	$	30.32	$	33.22	$	34.19
	NGLs (per Bbl)		21.51		17.94	$	24,47		25.29		29.52
	Natural gas (per Mcf)		3.20		2.55		4.78		5.13		4.83
	Per Mcfe		3.35		2.72		4.80		2.64		5.16
Average cost of production (per Mcfe)		$	0.85	$	0.82	$	1.21	$	0.65	$	1.11

(1)

Average sales prices include effects of hedging activities.

*

Data includes Canadian Abraxas and Old Grey Wolf for 2001, 2002 and the first 23 days of 2003 which were sold in January 2003.

Summary Historical Reserves Data

        The following table sets forth summary information with respect to our estimated proved crude oil, NGLs and natural gas reserves as of the dates indicated.

		As of December 31,
		2001			2002			2003
		(dollars in thousands, except per unit data)
Estimated Proved Reserves:
Crude oil and NGLs (MBbls)			6,802			4,605			4,134
Natural gas (MMcf)			188,757			138,832			96,284
Natural gas equivalents (MMcfe)			229,569			166,462			121,088
	% Proved developed		62	%		65	%		55	%
Estimated future net revenue before income taxes		$	386,762		$	460,989		$	416,756
PV-10			209,666			254,853			216,823
	% Proved developed		82	%		81	%		67	%

8

RISK FACTORS

You should carefully consider the following risk factors in addition to the other information in this prospectus before making an investment in the notes or Abraxas common stock offered by the selling security holders.

Risks Related to the Offering

        The security for the notes may be inadequate to satisfy all amounts due and owing to the holders of our notes.     Currently, the notes are secured by a second lien or charge on all of our current and future assets, including, but not limited to, our crude oil and natural gas assets. There can be no assurance that, following an acceleration after an event of default under the indenture for the notes, the proceeds from the sale of the collateral and allocable to the notes would be sufficient to satisfy all amounts due on such notes. The ability of the holders of the notes to realize upon the collateral will also be subject to certain limitations in the indenture for the notes, the accompanying mortgage and the pledge agreement, including a prohibition on foreclosing on the collateral for 180 days after an event of default under the notes, as applicable. In addition, if we become a debtor in a case under the bankruptcy code, the automatic stay imposed by the bankruptcy code would prevent the trustee from selling or otherwise disposing of the collateral without bankruptcy court authorization. In that case, the foreclosure might be delayed indefinitely. See "Description of the Notes—Security" on page 80 of this prospectus.

        The guarantees may not be enforceable in bankruptcy.    Abraxas' obligations under the notes (and any additional notes issued in lieu of cash interest payments), are guaranteed by Sandia Oil & Gas, Sandia Operating, Wamsutter, New Grey Wolf, Western Associated Energy, Eastside Coal and any other future subsidiaries. Various fraudulent conveyance laws have been enacted for the protection of creditors and may be utilized by courts to subordinate or void such guarantees. It is also possible that under certain circumstances a court could hold that the direct obligations of a guarantor could be superior to the obligations under its guarantee.

        To the extent that a court were to find that at the time a guarantor entered into a guarantee either:

(1)

the guarantee was incurred by the guarantor with the intent to hinder, delay or defraud any present or future creditor or that the guarantor contemplated insolvency with a design to favor one or more creditors to the exclusion in whole or in part of others; or



(2)

the guarantor did not receive fair consideration or reasonably equivalent value for issuing the guarantee and, at the time it issued the guarantee, the guarantor



•

was insolvent or rendered insolvent by reason of the issuance of the guarantee;



•

was engaged or about to engage in a business or transaction for which the remaining assets of the guarantor constituted unreasonably small capital; or



•

intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured;

the court could void or subordinate the guarantee in favor of the guarantor's other creditors. Among other things, a legal challenge of a guarantee issued by a guarantor on fraudulent conveyance grounds may focus on the benefits, if any, realized by the guarantor as a result of our issuance of the notes or any additional notes issued in lieu of cash interest payments. A court might find that the guarantors did not benefit from incurrence of the indebtedness represented by such notes.

        To the extent that a guarantee is voided as a fraudulent conveyance or found unenforceable for any other reason, holders of the notes or any additional notes issued in lieu of cash interest payments

9

would cease to have any claim in respect of the applicable guarantor. In such event, the claims of the holders of the notes against such guarantor would be subject to the prior payment of all liabilities and preferred stock claims of such guarantor. There can be no assurance that, after providing for all claims and preferred stock interests, if any, there would be sufficient assets to satisfy the claims of the holders of the notes relating to any voided portion of such guarantee.

        Under applicable provisions of Canadian federal bankruptcy law or comparable provisions of provincial fraudulent preference laws, if a court in an action brought by an unpaid creditor of New Grey Wolf or by a bankruptcy trustee thereof were to find that the liens granted by New Grey Wolf over its assets were intended to prefer the holders of the notes over other creditors, such liens could be set aside. This would become an issue if New Grey Wolf became insolvent or bankrupt within a certain period after granting the liens.

        Under certain circumstances a bankruptcy court could order the repayment of interest payments made under the notes.    The bankruptcy code allows the bankruptcy trustee (or us, acting as debtor-in-possession) to avoid certain transfers of a debtor's property as a "preference." Under the bankruptcy code a preference is:

•

a transfer of the debtor's property;



•

to or for the benefit of a creditor on account of an existing debt;



•

made while the debtor was insolvent (presumed in the 90 days before a bankruptcy filing);



•

if the creditor receives more than it would have received in a bankruptcy liquidation if the transfer had not been made; and



•

if the transfer/payment was made in the 90 days before the bankruptcy filing, or, if the creditor was an "insider" within one year before the bankruptcy filing (a creditor that is also a director, officer or controlling stockholder of a debtor may be deemed to be an insider).

        Our payment of principal and/or accrued interest, or our grant of a lien or security interest, including payments made or liens or security interests granted pursuant to the exchange offer, may be deemed to be a preference if all of the factors discussed above are present. If such transfers were deemed to be preferential transfers, the payments could be recovered from the noteholders and the lien or security interest could be avoided.

        If the notes (and any additional notes issued in lieu of cash interest payments), are fully secured (i.e., the value of collateral exceeds the amount it secures), payments on such notes would not constitute preferential transfers. However, if, or to the extent, the notes are undersecured (i.e., the value of the collateral is less than the amount which it secures), payments would be deemed to have been applied, first, to the unsecured portion of the notes and, second, to the secured portion of the notes and the payments attributable to the unsecured portion could be considered preferential transfers. Therefore, if we are involved in a bankruptcy proceeding, holders of our notes or any additional notes issued in lieu of cash interest payments may be required to disgorge payments made on such notes to the extent the notes are undersecured.

        Additionally, due to Abraxas' and the guarantors' being domiciled in the United States and in Canada, Abraxas and the guarantors could be subject to multi-jurisdictional insolvency proceedings in the United States and Canada. If multi-jurisdictional insolvency proceedings were to occur, this could result in additional delay in payment of the notes or any additional notes issued in lieu of cash interest payments, as well as delay in or prevention from enforcing remedies under such notes, any guarantee thereunder and the liens securing such notes and the guarantees. Likewise, our notes could be subject to different treatment inasmuch as the multiple insolvency proceedings would be conducted by different courts applying different laws.

10

        In bankruptcy, the payment of cash and the issuance of the notes and Abraxas common stock in the exchange offer could be avoided as a preferential transfer.    If we were to become subject to a petition for relief under the bankruptcy code within 90 days after the consummation of the exchange offer (or, with respect to any insiders specified in the bankruptcy code, within one year after consummation of the exchange offer) and certain other conditions are met, the consideration paid to noteholders in the exchange offer, absent the presence of one of the bankruptcy code defenses to avoidance, could be avoided as a preferential transfer and, to the extent avoided, the value of such consideration could be recovered from the noteholder and possibly from subsequent transferees.

        Original issue discount will be included in your gross income for U.S. federal income tax purposes before you receive any cash payments on the notes.    The notes have been deemed to be issued at a substantial discount from their stated principal amount at maturity because the issue price of the notes will be determined by reference to the fair market value of the second lien notes and old notes in exchange for which the notes subject to this prospectus were issued on January 23, 2003, the closing date of the private exchange offer in which the notes were issued. Furthermore, periodic interest payments on the notes will be payable in cash or by the issuance of additional notes and, as such, will be treated as if all interest payments are made in the form of additional notes, thereby creating additional original issue discount on the notes. Consequently, prior to receiving any cash interest payments on the notes, a holder of notes will be required to include significant original issue discount in the gross income of such holder for U.S. federal income tax purposes. For a more detailed discussion of the tax consequences applicable to holders of the notes, see the section entitled "Certain U.S. Federal Income Tax Considerations" beginning on page 134 of this prospectus.

        The amount of any claim made by a note holder in a bankruptcy action may be limited as a result of the notes being issued with original issue discount.    If a bankruptcy petition is filed by or against us under the U.S. Bankruptcy Code while the notes are outstanding, the claim of a holder of the notes with respect to the accreted value of the notes may be limited to an amount equal to the sum of:

•

the initial issue price for the notes; and



•

that portion of the original issue discount that is not deemed to constitute "unmatured interest" within the meaning of the United States Bankruptcy Code.

        Any original issue discount that was not amortized as of the date of any such bankruptcy filing would constitute "unmatured interest." Accordingly, holders of the notes under such circumstances may receive a lesser amount than they would be entitled to under the express terms of the indenture for the notes, even if sufficient funds are available. In addition, to the extent that the U.S. Bankruptcy Code differs from the Internal Revenue Code of 1986, as amended, in determining the method of amortization of original issue discount, a holder of the notes may realize taxable gain or loss upon payment of that holder's claim in bankruptcy.

        We may not be able to repurchase the notes upon a change of control.    Upon the occurrence of certain change of control events, holders of the notes may require us to offer to repurchase all or any part of their notes. We may not have sufficient funds at the time of the change of control to make the required repurchases of such notes.

        The source of funds for any repurchase required as a result of any change of control will be our available cash or cash generated from crude oil and natural gas operations or other sources, including borrowings, sales of assets, sales of equity or funds provided by a new controlling entity. We cannot assure you, however, that sufficient funds would be available at the time of any change of control to make any required repurchases of the notes tendered. Furthermore, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future. In addition, the new senior credit agreement restricts our ability to repurchase the notes.

11

Any future credit agreements or other agreements relating to debt to which we may become a party will most likely contain similar restrictions and provisions.

        An active market may not develop for the notes or Abraxas common stock.    The notes were originally issued on January 23, 2003 and no assurance can be given that an active market will develop, or, if such a market develops, that such market will be liquid. The notes will not be listed on any national securities exchange. Accordingly, no assurance can be given that a holder of the notes will be able to sell such notes in the future or as to the price at which such sale may occur. The liquidity of the market for the notes and the prices at which such notes trade will depend upon the amount outstanding, the number of holders thereof, the interest of securities dealers in maintaining a market in such notes and other factors beyond our control. The liquidity of, and trading market for, the notes also may be adversely affected by general declines in the market for high yield securities. Such declines may adversely affect the liquidity and trading markets for the notes.

        The Abraxas common stock is quoted on the American Stock Exchange. While there is currently one specialist in the Abraxas common stock, this specialist is not obligated to continue to make a market in the Abraxas common stock. In this event, the liquidity of the Abraxas common stock could be adversely impacted and a stockholder could have difficulty obtaining accurate stock quotes.

        Compound interest on the notes may be restricted by applicable law.    Interest on the notes will compound semi-annually to the extent permitted by applicable law. Although applicable law provides for enforceability of compound interest in certain loans and agreements, it may not be enforceable in a loan with a principal amount of $250,000 or less. It is unclear whether compound interest is enforceable in a loan with a principal amount of $250,000 or less when the aggregate amount of the debt incurred under the financing agreement governing that loan is over $250,000. Accordingly, the ability of the holder of any note with a principal amount of $250,000 or less to collect compounded interest may be restricted by applicable law. In any event, Abraxas intends to pay compound interest in accordance with the terms of the indenture for the notes.

        Abraxas does not pay dividends on common stock.    Abraxas has never paid a cash dividend on its common stock and the terms of the new senior credit agreement and the indenture relating to the notes limit the ability of Abraxas to pay dividends on its common stock.

        Shares eligible for future sale may depress our stock price.    At July 27, 2004 we had 36,252,077 shares of common stock outstanding of which 3,993,761 shares were held by affiliates, 3,068,819 shares of common stock were subject to outstanding options granted under certain stock option plans (of which 2,254,145 shares were vested at July 27, 2004) and 950,000 shares were issuable upon exercise of warrants.

        All of the shares of common stock held by affiliates are restricted or control securities under Rule 144 promulgated under the Securities Act. The shares of the common stock issuable upon exercise of the stock options have been registered under the Securities Act. The shares of the common stock issuable upon exercise of the warrants are subject to certain registration rights and, therefore, will be eligible for resale in the public market after a registration statement covering such shares has been declared effective. Sales of shares of common stock under Rule 144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of the common stock and could impair our ability to raise additional capital through the sale of equity securities.

        The price of Abraxas' common stock has been volatile and could continue to fluctuate substantially.    Abraxas' common stock is traded on the American Stock Exchange. The market price of Abraxas'

12

common stock has been volatile and could fluctuate substantially based on a variety of factors, including the following:

•

Fluctuations in commodity prices;



•

Variations in results of operations;



•

Legislative or regulator changes;



•

General trends in the industry;



•

Market conditions; and



•

Analysts' estimates and other events in the crude oil and natural gas industry.

        We may issue shares of preferred stock with greater rights than our common stock.    Subject to the rules of the American Stock Exchange, our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from holders of our common stock. Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, priority and liquidation premiums and may have greater voting rights than our common stock.

        Anti-takeover provisions could make a third party acquisition of Abraxas difficult.    Abraxas' articles of incorporation and by-laws provide for a classified board of directors, with each member serving a three-year term, and eliminate the ability of stockholders to call special meetings or take action by written consent. Abraxas also has adopted a stockholder rights plan. Each of the provisions in the articles of incorporation and by-laws and the stockholder rights plan could make it more difficult for a third party to acquire Abraxas without the approval of Abraxas' board. In addition, the Nevada corporate statute also contains certain provisions that could make an acquisition by a third party more difficult.

Risks Related to Our Business

        Our reduced operating cash flow resulting from the sale of Canadian Abraxas and Old Grey Wolf may put significant strain on our liquidity and cash position.    Our reduced operating cash flow and resulting limited liquidity has caused us, and the limitations imposed by the senior credit agreement and the notes will cause us, to reduce capital expenditures, including exploration, exploitation and development projects. These reductions will limit our ability to replenish our depleting reserves, which could negatively impact our cash flow from operations and results of operations in the future. In addition, under the terms of the notes, we are required, to the extent permitted, to permanently pay down debt under the senior credit agreement and, if permitted, the notes, with our cash flow which is not required to pay our capital expenditures or make cash interest and tax payments.

        The effects of our reduced operating cash flow will be exacerbated by our high level of debt, which will affect our operations in several important ways, including:

•

A substantial amount of our cash flow from operations could be required to make principal and interest payments on our outstanding indebtedness and may not be available for other purposes, including developing our properties;



•

The covenants contained in the indenture governing the notes and in the senior credit agreement will limit our ability to borrow additional funds or to dispose of assets or use the proceeds of any asset sales and may affect our flexibility in planning for, and reacting to, changes in our business; and

13

•

Our debt level may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, interest payments, scheduled principal payments, general corporate purposes or other purposes.

        Our limited liquidity and restrictions on uses of cash dictated by both the senior credit agreement and the notes, combined with our high debt levels may hinder our ability to satisfy the substantial capital requirements related to our operations.    The success of our future operations will require us to make substantial capital expenditures for the exploitation, development, exploration and production of crude oil and natural gas. Volatile commodity prices could negatively impact our cash flow from operations as well as any future sales of producing properties.

        Under the terms of the senior credit agreement, we are required to establish deposit accounts at financial institutions acceptable to the lenders and we are required to direct our customers to make all payments into these accounts. The amounts in these accounts will be transferred to the lenders upon the occurrence and during the continuance of an event of default under the senior credit agreement. We will also be required to make mandatory repayments of the outstanding amounts owing under the senior credit agreement if the outstanding amounts exceed the borrowing base. In addition, under the terms of the notes, Abraxas is subject to cash and expenditures covenants including those set forth in the sections entitled "Description of the Notes—Certain Covenants—Excess Cash Flow and Excess Cash," "—Limitations on Expenditures for Selling, General and Administrative Expenses," "—Limitations on Capital Expenditures" and "—Limitation on Uses of Cash" beginning on page 93 of this prospectus.

        These limitations imposed on Abraxas by the senior credit agreement and the notes may have the effect of limiting our ability to develop our crude oil and natural gas properties because much of our cash flow may be used for debt service. As a result, our ability to replace production may be limited. You should read the discussion under "—Our ability to replace production with new reserves is highly dependent on acquisitions or successful development and exploration activities" for more information regarding the risks associated with limitations on our ability to develop our crude oil and natural gas properties.

        Hedging transactions may limit our potential gains.    Under the terms of the senior credit agreement, we are required to maintain commodity price hedging positions on not less than 40% and not more than 75% of our estimated production for a rolling six-month period.

        The following table sets forth the Company's current hedge position:

Time Period	Notional Quantities	Price
July 2004	2,000 MMBtu of production per day 4,500 Mmbtu of production per day 500 Bbls of crude oil production per day	Floor of $4.00 Floor of $4.25 Floor of $22.00
August 2004	5,000 MMBtu of production per day 2,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $4.25 Floor of $24.00
September 2004	7,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $24.00
October 2004	7,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $24.00
November 2004	7,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $24.00

14

December 2004	7,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.50 Floor of $25.00
January 2005	7,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.50 Floor of $25.00

        For a more detailed description of the senior credit agreement and our hedging sensitivity, see the section entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 23.

        We cannot assure you that our hedging transactions will reduce risk or minimize the effect of any decline in crude oil or natural gas prices. Any substantial or extended decline in crude oil or natural gas prices would have a material adverse effect on our business and financial results. Hedging activities may limit the risk of declines in prices, but such arrangements may also limit, and have in the past limited, additional revenues from price increases. In addition, such transactions may expose us to risks of financial loss under certain circumstances, such as:

•

production being less than expected; or



•

price differences between delivery points for our production and those in our hedging agreements increasing.

        In 2001, 2002 and 2003, we experienced hedging losses of $12.1 million, $3.2 million and $ 842,000, respectively.

        Our ability to replace production with new reserves is highly dependent on acquisitions or successful development and exploration activities.    The rate of production from crude oil and natural gas properties declines as reserves are depleted. Our proved reserves will decline as reserves are produced unless we acquire additional properties containing proved reserves, conduct successful exploration, exploitation and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. Our future crude oil and natural gas production is therefore highly dependent upon our level of success in acquiring or finding additional reserves. While we have had some success in pursuing these activities, we have not been able to fully replace the production volumes lost from natural field declines and property sales. We have implemented a number of measures to conserve our cash resources, including postponement of exploration and development projects. However, while these measures will conserve our cash resources in the near term, they will also limit our ability to replenish our depleting reserves, which could negatively impact our cash flow from operations in the future. The terms of the senior credit agreement and the notes limit our capital expenditures which will further limit our ability to replenish our reserves and replace production. Further, in addition to the effects of our limited liquidity, our operations may be curtailed, delayed or cancelled by other factors, such as title problems, weather, compliance with governmental regulations, mechanical problems or shortages or delays in the delivery of equipment. We cannot assure you that our exploration and development activities will result in increases in reserves.

        Use of our net operating loss carryforwards may be limited.    At December 31, 2003, Abraxas had, subject to the limitation discussed below, $100.6 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire from 2003 through 2022 if not utilized. In connection with the financial restructuring, certain of the loss carryforwards were utilized.

        As to a portion of the U.S. net operating loss carryforwards, the amount of such carryforwards that we can use annually is limited under U.S. tax law. Additionally, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, Abraxas has established a valuation allowance of $99.1 million and $76.1 million for deferred tax assets at December 31, 2002 and 2003, respectively.

15

        Crude oil and natural gas prices and their volatility could adversely affect our revenue, cash flows, profitability and growth.    Our revenue, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for crude oil and natural gas. Natural gas prices affect us more than crude oil prices because most of our production and reserves are natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may have ceiling limitation write-downs when prices decline. During the second quarter of 2002, we had a ceiling limitation write-down of approximately $116.0 million. Lower prices may also reduce the amount of crude oil and natural gas that we can produce economically.

        We cannot predict future crude oil and natural gas prices. Factors that can cause price fluctuations include:

•

changes in supply and demand for crude oil and natural gas;



•

weather conditions;



•

the price and availability of alternative fuels;



•

political and economic conditions in oil producing countries, especially those in the Middle East; and



•

overall economic conditions.

        In addition to decreasing our revenue and cash flow from operations, low or declining crude oil and natural gas prices could have additional material adverse effects on us, such as:

•

reducing the overall volumes of crude oil and natural gas that we can produce economically;



•

causing a ceiling limitation write-down;



•

increasing our dependence on external sources of capital to meet our liquidity requirements; and



•

impairing our ability to obtain needed equity capital.

        Lower crude oil and natural gas prices increase the risk of ceiling limitation write-downs.    We use the full cost method to account for our crude oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties. Under full cost accounting rules, the net capitalized cost of crude oil and natural gas properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling limitation write-down." This charge does not impact cash flow from operating activities, but does reduce our stockholders' equity and earnings. The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period.

        We have incurred ceiling limitation writedowns in the past. At June 30, 2002, for example, we recorded a ceiling limitation writedown of $116 million. We cannot assure you that we will not experience additional ceiling limitation writedowns in the future.

        Estimates of our proved reserves and future net revenue are uncertain and inherently imprecise.    This prospectus contains estimates of our proved crude oil and natural gas reserves and the estimated future net revenue from such reserves. The process of estimating crude oil and natural gas reserves is complex

16

and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are imprecise.

        Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control.

        You should not assume that the present value of future net revenues referred to in this prospectus is the current market value of our estimated crude oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the end of the period of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the end of the year of the estimate. Any changes in consumption by natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with us or the crude oil and natural gas industry in general will affect the accuracy of the 10% discount factor.

        The estimates of our reserves are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of crude oil and natural gas reserves, future net revenue from proved reserves and the PV-10 thereof for the crude oil and natural gas properties described in this prospectus are based on the assumption that future crude oil and natural gas prices remain the same as crude oil and natural gas prices at December 31, 2003. The sales prices as of such date used for purposes of such estimates were $ 31.03 per Bbl of crude oil, $27.19 per Bbl of NGLs and $ 5.05 per Mcf of natural gas. This compares with $29.69 per Bbl of crude oil, $18.89 per Bbl of NGLs and $3.79 per Mcf of natural gas as of December 31, 2002. These estimates also assume that we will make future capital expenditures of approximately $50.4 million in the aggregate through 2019, which are necessary to develop and realize the value of proved undeveloped reserves on our properties. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of reserves set forth herein.

        We have experienced recurring net losses.    The following table shows the losses we had in 1998, 1999, 2001, and 2002:

	Years Ended December 31,
	1998			1999			2001			2002
Net (loss)	$	(84.0	)	$	(36.7	)	$	(19.7	)	$	(118.5	)

While we had net income in 2000 of $8.4 million, if the significant gain on the sale of an interest in a partnership were excluded, we would have experienced a net loss for the year of $(25.5) million. Similarly, while we had net income of $55.9 million in 2003, if the gain on the sale of Canadian Abraxas and Old Grey Wolf were excluded, we would have experienced a net loss for the year of ($13.0) million. We cannot assure you that we will become profitable in the future.

        The marketability of our production depends largely upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities.    The marketability of our production depends in part upon processing facilities. Transportation space on such gathering systems and pipelines

17

is occasionally limited and at times unavailable due to repairs or improvements being made to such facilities or due to such space being utilized by other companies with priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and state and Canadian regulation of crude oil and natural gas production and transportation, general economic conditions, and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the financial impact on us could be substantial and adversely affect our ability to produce and market crude oil and natural gas.

        Our Canadian operations are subject to the risks of currency fluctuations and in some instances economic and political developments.    We conduct operations in Canada. The expenses of such operations are payable in Canadian dollars while most of the revenue from crude oil and natural gas sales is based upon U.S. dollar price indices. As a result, Canadian operations are subject to the risk of fluctuations in the relative values of the Canadian and U.S. dollars. We are also required to recognize foreign currency translation gains or losses related to any debt issued by our Canadian subsidiary because the debt is denominated in U.S. dollars and the functional currency of such subsidiary is the Canadian dollar. Our foreign operations may also be adversely affected by local political and economic developments, royalty and tax increases and other foreign laws or policies, as well as U.S. policies affecting trade, taxation and investment in other countries.

        We depend on our key personnel.    We depend to a large extent on Robert L.G. Watson, our Chairman of the Board, President and Chief Executive Officer, for our management and business and financial contacts. The unavailability of Mr. Watson could have a materially adverse effect on our business. Mr. Watson has a three-year employment contract with Abraxas commencing on December 21, 1999, which automatically renews thereafter for successive one-year periods unless Abraxas gives 120 days notice prior to the expiration of the original term or any extension thereof of its intention not to renew the employment agreement. Our success is also dependent upon our ability to employ and retain skilled technical personnel. While we have not experienced difficulties in employing or retaining such personnel, our failure to do so in the future could adversely affect our business.

Risks Related to Our Industry

        Our operations are subject to numerous risks of crude oil and natural gas drilling and production activities.     Our crude oil and natural gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the following:

•

that no commercially productive crude oil or natural gas reservoirs will be found;



•

that crude oil and natural gas drilling and production activities may be shortened, delayed or canceled; and



•

that our ability to develop, produce and market our reserves may be limited by:



•

title problems,



•

weather conditions,



•

compliance with governmental requirements, and



•

mechanical difficulties or shortages or delays in the delivery of drilling rigs, work boats and other equipment.

        In the past, we have had difficulty securing drilling equipment in certain of our core areas. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for crude oil and natural gas may be unprofitable. Dry holes and wells that are productive but do not produce sufficient net revenues after drilling, operating and other

18

costs are unprofitable. In addition, our properties may be susceptible to hydrocarbon draining from production by other operations on adjacent properties.

        Our industry also experiences numerous operating risks. These operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.

        We operate in a highly competitive industry which may adversely affect our operations.    We operate in a highly competitive environment. Competition is particularly intense with respect to the acquisition of desirable undeveloped crude oil and natural gas properties. The principal competitive factors in the acquisition of such undeveloped crude oil and natural gas properties include the staff and data necessary to identify, investigate and purchase such properties, and the financial resources necessary to acquire and develop such properties. We compete with major and independent crude oil and natural gas companies for properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.

        The principal resources necessary for the exploration and production of crude oil and natural gas are leasehold prospects under which crude oil and natural gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of crude oil and natural gas operations. We must compete for such resources with both major crude oil and natural gas companies and independent operators. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations in the immediate future, we cannot assure you that such materials and resources will be available to us.

        We face significant competition for obtaining additional natural gas supplies for gathering and processing operations, for marketing NGLs, residue gas, helium, condensate and sulfur, and for transporting natural gas and liquids. Our principal competitors include major integrated oil companies and their marketing affiliates and national and local gas gatherers, brokers, marketers and distributors of varying sizes, financial resources and experience. Certain competitors, such as major crude oil and natural gas companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.

        Our crude oil and natural gas operations are subject to various U.S. federal, state and local and Canadian federal and provincial governmental regulations that materially affect our operations.    Matters regulated include discharge permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of crude oil and natural gas, these agencies have restricted the rates of flow of crude oil and natural gas wells below actual production capacity. Federal, state, provincial and local laws regulate production, handling, storage, transportation and disposal of crude oil and natural gas, by-products from crude oil and natural gas and other substances and materials produced or used in connection with crude oil and natural gas operations. To date, our expenditures related to complying with these laws and for remediation of existing environmental contamination have not been significant. We believe that we are in substantial compliance with all applicable laws and regulations. However, the requirements of such laws and regulations are frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

19

USE OF PROCEEDS

        We will not receive any proceeds from the sale of the notes or the Abraxas common stock by the selling security holders pursuant to this prospectus.

RATIO OF EARNINGS TO FIXED CHARGES

        Earnings consist of income before income taxes plus fixed charges. Fixed charges consist of interest expense, amortization of deferred financing fees and premium on the old notes. Our earnings were inadequate to cover fixed charges in 2001 and 2002 by $15.6 million and $148.2 million, respectively. In 2003, we had earnings of $74.9 million and fixed charges of $18.6 million. Our ratio of earnings to fixed charges during 2003 was 4.0x. For the quarter ended March 31, 2003 we had earnings of $69.0 million and fixed charges of $5.5 million. For the quarter ended March 31, 2004, our earnings were inadequate to cover fixed charges by $5.6 million.

CAPITALIZATION

        The following table sets forth our cash position and total consolidated capitalization at December 31, 2003 on a historical basis and March 31, 2004.

			December 31, 2003			March 31, 2004
			(dollars in thousands)
Cash			$	493			1,393
Total debt, including current maturities:
	Senior Credit Agreement			47,391			49,713
	111/2% Secured Notes due 2007 (new notes)(1)			137,258			137,258
		Total debt		184,649			186,971
Stockholders' equity (deficit)				(72,203	)		(75,828	)
	Total capitalization		$	112,446		$	111,143

(1)

For financial reporting purposes, the new notes are reflected at the carrying value of the second lien notes and old notes prior to the exchange of $191.0 million, net of the cash offered in the exchange of $47.5 million and net of the fair market value related to equity of $3.8 million offered in the exchange. In conjunction with the financial restructuring transaction, Abraxas paid cash of $11.5 million ($11.1 million in principal and $0.4 million in interest) to redeem certain of the outstanding old notes and second lien notes and accrued interest. The result of all of these items will be a remaining carrying value of the new notes of $128.6 million. At March 31, 2004, the face amount of the new notes was $120.5 million.

20

PRICE RANGE OF ABRAXAS COMMON STOCK

        Abraxas common stock began trading on the American Stock Exchange on August 18, 2000 under the symbol "ABP." The following table sets forth certain information as to the high and low bid quotations quoted for Abraxas' common stock on the American Stock Exchange.

Period		High		Low
2002
	First Quarter	$	1.70	$	0.89
	Second Quarter		1.41		0.52
	Third Quarter		0.98		0.42
	Fourth Quarter		0.80		0.52
2003
	First Quarter	$	0.95	$	0.55
	Second Quarter		1.30		0.61
	Third Quarter		1.11		0.82
	Fourth Quarter		1.32		0.88
2004
	First Quarter	$	3.64	$	1.29
	Second Quarter		2.89		1.57
	Third Quarter (through July 27, 2004)		1.69		1,09

Dividends

        Abraxas has not paid any cash dividends on its common stock and it is not presently determinable when, if ever, Abraxas will pay cash dividends in the future. In addition, the senior credit facility and the indenture governing the notes prohibit the payment of cash dividends and stock dividends on Abraxas' common stock. You should read the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—" beginning on page 31 for more information regarding the restrictions on Abraxas' ability to pay dividends.

21

SELECTED HISTORICAL FINANCIAL DATA

        The following historical selected consolidated financial data are derived from our Consolidated Financial Statements and the notes thereto. The Statement of Operations Data for the three months ended March 31, 2004, is not necessarily indicative of results of a full year. The consolidated financial data for the three months ended March 31, 2003 and March 31, 2004 are derived from our unaudited financial statements and, in the opinion of management, include all adjustments that are of a normal and a recurring nature and necessary for a full presentation. The selected historical consolidated financial information should be read in conjunction with our Consolidated Financial Statements and the notes thereto and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this prospectus. As discussed in Note 19 to the consolidated financial statements, our financial statements have been restated.

			Year Ended December 31,															Three Months Ended March 31,
			1999*			2000*			2001*			2002*			2003*			2003*			2004
			(in thousands, except per share data)
Consolidated Statements of Operations Data:
Operating revenue:
	Oil and gas production revenues		$	59,025		$	72,973		$	73,201		$	50,862		$	38,105		$	12,772		$	10,732
	Gas processing revenue			4,244			2,717			2,438			2,420			133			132			—
	Rig and other revenue			3,501			910			1,604			1,038			781			207			203
		Total operating revenue		66,770			76,600			77,243			54,320			39,019			13,111			10,935
Operating costs and expenses:
	Lease operating and production taxes			17,938			18,783			18,616			15,240			9,599			2,726			3,367
	Depreciation, depletion and amortization expense			34,811			35,857			32,484			26,539			10,803			3,142			3,035
	General and administrative expense			5,269			6,533			6,445			6,884			5,360			1,395			1,342
	General and administrative (Stock-based compensation)			—			2,767			(2,767	)		—			1,106			36			2,063
	Other			624			717			702			567			609			166			145
	Proved property impairment			19,100			—			2,638			115,993			—			—			—
		Total operating expenses		77,742			64,657			58,118			165,223			27,477			7,465			9,952
Operating income (loss)				(10,972	)		11,943			19,125			(110,903	)		11,542			5,646			983
Net interest expense				36,149			30,610			31,445			34,058			16,925			5,154			5,113
Amortization of deferred financing Fees				1,915			2,091			2,268			2,095			1,678			377			445
Financing cost				—			—			—			967			4,406			3,601			971
Gain on debt extinguishment				—			(1,773	)		—			—			—			—			—
(Gain) loss on sale of equity investment				—			(33,983	)		845			—			—			—			—
Gain on sale of foreign subsidiaries				—			—			—			—			(68,933	)		(66,960	)		—
Other (income) expense				—			1,563			207			201			774			—			11
Income (loss) before taxes and cumulative effect of accounting change				(49,036	)		13,435			(15,640	)		(148,224	)		56,692			63,474			(5,557	)
Cumulative effect of accounting change				—			—			—			—			(395	)		(395	)		—
Income tax (expense) benefit				12,625			(3,705	)		(2,402	)		29,697			(377	)		(377	)		—
Minority interest in (income) loss of consolidated foreign subsidiaries				(269	)		(1,281	)		(1,676	)		—			—			—			—
Income (loss)			$	(36,680	)	$	8,449		$	(19,718	)	$	(118,527	)	$	55,920		$	62,702		$	(5,557	)
Income (loss) from per common share:
	Basic		$	(5.41	)	$	0.37		$	(0.76	)	$	(3.95	)	$	1.58		$	1.83		$	(0.15	)
	Diluted			(5.41	)		0.26			(0.76	)		(3.95	)	$	1.55			1.82		$	(0.15	)
Consolidated Balance Sheet Data:
Total assets			$	322,284		$	335,560		$	303,616		$	181,425		$	126,437		$	117,647		$	126,041
Long-term debt—excluding current maturities				273,421			266,441			262,240			236,943			184,649			173,735			186,971
Stockholder's equity (deficit)				(9,505	)		(6,503	)		(28,585	)		(142,254	)		(72,203	)		(70,201	)		(75,828	)

*

Data includes Canadian Abraxas and Old Grey Wolf for 1999-2002 and the first 23 days of 2003 which were sold in January 2003.

22

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following is a discussion of our consolidated financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto.

        As discussed in Note 19 to the consolidated financial statements, our financial statements have been restated. The following management's discussion and analysis gives effect to that restatement.

General

        We are an independent energy company engaged primarily in the acquisition, exploration, exploitation and production of crude oil and natural gas. Our principal means of growth has been through the acquisition and subsequent development and exploitation of producing properties. As a result of our historical acquisition activities, we believe that we have a substantial inventory of low risk exploitation and development opportunities, the successful completion of which is critical to the maintenance and growth of our current production levels.

        We have incurred net losses in three of the last five years, and there can be no assurance that operating income and net earnings will be achieved in future periods. Our financial results depend upon many factors, particularly the following factors which most significantly affect our results of operations:

•

the sales prices of crude oil, natural gas liquids and natural gas;



•

the level of total sales volumes of crude oil, natural gas liquids and natural gas;



•

the availability of, and our ability to raise additional, capital resources and provide liquidity to meet cash flow needs;



•

the level of and interest rates on borrowings; and



•

the level and success of exploitation and development activity.

        Commodity Prices and Hedging Activities.    Our results of operations are significantly affected by fluctuations in commodity prices. Price volatility in the natural gas market has remained prevalent in the last few years. In January 2001, the market price of natural gas was at its highest level in our operating history and the price of crude oil was also at a high level. However, over the course of 2001 and the beginning of the first quarter of 2002, prices again became depressed, primarily due to the economic downturn. Beginning in March 2002, commodity prices began to increase and continued higher through December 2003. Prices have remained strong during the first part of 2004.

        The table below illustrates how natural gas prices fluctuated over the course of 2002 and 2003. The table below contains the last three day average of NYMEX traded contracts price and the prices we realized during each quarter for 2002 and 2003 and the first quarter of 2004, including the impact of our hedging activities.

Natural Gas Prices by Quarter
(in $ per Mcf)

	Quarter Ended
	March 31, 2002		June 30, 2002		Sept. 30, 2002		Dec. 31, 2002		March 31, 2003		June 30, 2003		Sept. 30, 2003		Dec. 31, 2003		March 31, 2004
Index	$	2.38	$	3.36	$	3.28	$	3.99	$	6.61	$	5.51	$	5.10	$	4.60	$	5.69
Realized	$	2.21	$	2.44	$	2.08	$	3.47	$	5.13	$	5.11	$	4.50	$	4.30	$	4.83

23

        The NYMEX natural gas price on July 27, 2004 was $5.99 per Mcf.

        The table below contains the last three day average of NYMEX traded contracts price and the prices we realized during each quarter for 2002 and 2003 and the first quarter of 2004.

Crude Oil Prices by Quarter
(in $ per Bbl)

	Quarter Ended
	March 31, 2002		June 30, 2002		Sept. 30, 2002		Dec. 31, 2002		March 31, 2003		June 30, 2003		Sept. 30, 2003		Dec. 31, 2003		March 31, 2004
Index	$	19.48	$	26.40	$	27.50	$	28.29	$	33.71	$	29.87	$	30.85	$	29.64	$	34.76
Realized	$	16.64	$	23.47	$	23.47	$	24.83	$	33.22	$	28.53	$	29.52	$	29.73	$	34.19

        The NYMEX crude oil price on July 27, 2004 was $41.84 per Bbl.

        We seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. In 2001 and 2002, we experienced hedging losses of $12.1 million and $3.2 million, respectively. In October 2002, all of these hedge agreements expired. We made total payments over the term of these arrangements to various counterparties in the amount of $35.1 million.

        Under the terms of our senior credit agreement, we are required to maintain hedging positions with respect to not less than 40% nor more than 75% of our crude oil and natural gas production, on an equivalent basis, for a rolling six month period. As of June 30, 2004, we had the following hedges in place:

Time Period	Notional Quantities	Price
July 2004	2,000 MMBtu of production per day 4,500 Mmbtu of production per day 500 Bbls of crude oil production per day	Floor of $4.00 Floor of $4.25 Floor of $22.00
August 2004	5,000 MMBtu of production per day 2,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $4.25 Floor of $24.00
September 2004	7,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $24.00
October 2004	7,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $24.00
November 2004	7,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $24.00
December 2004	7,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.50 Floor of $25.00
January 2005	7,100 Mmbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.50 Floor of $25.00

24

        Production Volumes.    Because our proved reserves will decline as crude oil, natural gas and natural gas liquids are produced, unless we acquire additional properties containing proved reserves or conduct successful exploration and development activities, our reserves and production will decrease. Our ability to acquire or find additional reserves in the near future will be dependent, in part, upon the amount of available funds for acquisition, exploitation and development projects. For more information on the volumes of crude oil, natural gas liquids and natural gas we have produced during 2001, 2002 and 2003, please refer to the information under the caption "Results of Operations" below.

        We have budgeted $10 million for drilling expenditures in 2004. Under the terms of our senior credit agreement and our new notes, we are subject to limitations on capital expenditures. As a result, we will be limited in our ability to replace existing production with new production and might suffer a decrease in the volume of crude oil and natural gas we produce. If crude oil and natural gas prices return to depressed levels or if our production levels continue to decrease, our revenues, cash flow from operations and financial condition will be materially adversely affected. For more information, see "Liquidity and Capital Resources—Current Liquidity Requirements" and "Future Capital Resources."

        Availability of Capital.    As described more fully under "Liquidity and Capital Resources" below, our sources of capital are primarily cash on hand, cash from operating activities, funding under our senior credit agreement and the sale of properties. At July 27, 2004, we had approximately $15.0 million of availability under our senior credit agreement. Our capital expenditures are limited to $10 million per year under the terms of the indenture for the notes. We may also attempt to raise additional capital or refinance our existing indebtedness through the issuance of debt or equity securities although we cannot assure you that we will be successful in any such efforts.

        Borrowings and Interest.    As a result of the financial restructuring we completed in January 2003, we reduced our indebtedness from approximately $300.4 million at December 31, 2002 to approximately $184.6 million at December 31, 2003 ($187.0 at March 31, 2004). In addition, we decreased our cash interest expense from $34.2 million during 2002 to $4.3 million during 2003. By decreasing the amount of our indebtedness and required cash interest payments, we reduced the amount of our cash flow from operations needed to pay interest on our indebtedness so that more of our capital resources could be utilized for drilling activities and paying other expenses.

        Exploitation and Development Activity.    During 2003, we continued exploitation activities on our U.S. properties. We participated in the drilling of 24 gross (11.8 net) wells with 23 gross (11.3 net) being successful. The Company invested $18.3 million in capital spending on these activities during 2003. At the end of 2003, as a result of these activities, our average daily production was approximately 24 MMcfepd, a 26% increase from the daily production rate at the beginning of the year (excluding production from the Canadian properties sold in January 2003).

        Outlook for 2004.    As a result of final 2003 financial results and current market conditions, Abraxas has updated its operating and financial guidance for year 2004 as follows:

Production:
	BCFE (approximately 80% gas)	8-9
Price Differentials (Pre Hedge):
	$ Per Bbl	0.86
	$ Per Mcf	0.64
Lifting Costs, $ Per Mcfe		1.29
G&A, $ Per Mcfe		0.60
Capital Expenditures ($ Millions)		10.00

25

        Actual results could materially differ and will depend on, among other things, our ability to successfully increase our production of crude oil, natural gas liquids and natural gas through our drilling activities. We undertake no duty to update these forward-looking statements.

        Selected Operating Data.    The following table sets forth certain of our operating data for the periods presented.

	Years Ended December 31,							Three Months Ended March 31,
	2001(1)		2002(1)			2003(1)		2003		2004
								(unaudited)
	(dollars in thousands, except per unit data)
Operating revenue:
Crude oil sales*	$	11,184	$	7,114		$	7,627	$	2,174	$	2,187
NGLs sales		5,979		4,343			911		511		393
Natural gas sales*		56,038		39,405			29,567		10,087		8,152
Gas processing revenue		2,438		2,420			133		132		—
Rig and other		1,604		1,038			781		207		203
Total operating revenues	$	77,243	$	54,320		$	39,019	$	13,111	$	10,935
Operating income (loss)	$	19,125	$	(110,903	)		11,542	$	5,646	$	983
Crude oil production (MBbls)		454.1		292.3			251.6		65.4		64.0
NGLs production (MBbls)		278.0		242.0			37.3		20.2		13.3
Natural gas production (MMcf)		17,495.6		15,452.7			6,189.4		1,965.3		1,687.4
Average crude oil sales price (per Bbl)*	$	24.63	$	24.34		$	30.32	$	33.22	$	34.19
Average NGLs sales price (per Bbl)	$	21.51	$	17.94		$	24.47	$	25.29	$	29.52
Average natural gas sales price (per Mcf)*	$	3.20	$	2.55		$	4.78	$	5.13	$	4.83

(1)

Data for 2001, 2002 and the first 23 days of 2003 includes Canadian Abraxas and Old Grey Wolf which were sold in January 2003.

*

Revenue and average sales prices are net hedging activities.

Comparison of Three Months Ended March 31, 2004 to Three Months Ended March 31, 2003

        Operating Revenue.    During the three months ended March 31, 2004, operating revenue from crude oil, natural gas and natural gas liquid sales decreased to $10.7 million from $12.8 for the first quarter of 2003. The decrease in revenue was primarily due to a decrease in production volumes and a decrease in the realized price for natural gas. The decrease in production volumes was due to the sale of our Canadian properties on January 23, 2003. A decline in our realized price for natural gas had a negative impact on revenue of approximately $508,000 which was partially offset by slightly higher realized prices for crude oil and natural gas liquids.

        Average sales prices net of hedging losses for the quarter ended March 31, 2004 were:

•

$34.19 per Bbl of crude oil,



•

$29.52 per Bbl of natural gas liquid, and



•

$4.83 per Mcf of natural gas

        Average sales prices net of hedging losses for the quarter ended March 31, 2003 were:

•

$33.22 per Bbl of crude oil,



•

$25.29 per Bbl of natural gas liquid, and

26

•

$5.13 per Mcf of natural gas

        Crude oil production volumes declined from 65.4 MBbls during the quarter ended March 31, 2003 to 64.0 MBbls for the same period of 2004. The decline in crude oil production was due to the sale of our Canadian subsidiaries on January 23, 2003. These properties contributed 2.4 MBbbls of crude oil in the first quarter of 2003 (through January 23). Excluding production related to the properties sold, crude oil production increased by approximately 919 Bbls. Natural gas production volumes declined from 1,965.3 MMcf for the three months ended March 31, 2003 to 1,687.4 MMcf for the same period of 2004. This decline was due to the sale of Canadian properties in January 2003. The Canadian properties contributed 558.9 MMcf in the first quarter of 2003 (through January 23, 2003). Excluding production related to these properties, we had an increase in natural gas production of 281.0 MMcf for the quarter ended March 31, 2004 as compared to 2003.

        Lease Operating Expenses.    Lease operating expenses ("LOE") for the three months ended March 31, 2004 increased to $3.4 million from $2.7 million for the same period in 2003. The increase in LOE was primarily due to pipeline charges in Canada related to startup costs associated with previously stranded gas. LOE on a per Mcfe basis for the three months ended March 31, 2004 was $1.57 per Mcfe compared to $1.10 for the same period of 2003.

        General and Administrative ("G&A") Expenses.    G&A expenses decreased slightly to $1.3 million during the quarter ended March 31, 2004 from $1.4 million for the first three months of 2003. G&A expense on a per Mcfe basis was $0.62 for the first quarter of 2004 compared to $0.56 for the same period of 2003. The increase in G&A expense on a per Mcfe basis was due to a decline in production volumes during the first quarter of 2004 compared to the same period in 2003.

        G&A Stock-based Compensation.    Effective July 1, 2000, the Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions Involving Stock Compensation", an interpretation of Accounting Principles Board Opinion No. ("APB") 25. Under the interpretation, certain modifications to fixed stock option awards which were made subsequent to December 15, 1998, and not exercised prior to July 1, 2000, require that the awards be accounted for as variable until they are exercised, forfeited, or expired. In January 2003, we amended the exercise price to $0.66 per share on certain options with an existing exercise price greater than $0.66 per share. The price of our common stock increased during the quarter ended March 31, 2004 resulting in the recognition of approximately $2.1 million as stock-based compensation expense for the quarter then ended. We recognized approximately $36,000 as stock-based compensation expense during the quarter ended March 31, 2003 related to these repricings.

        Depreciation, Depletion and Amortization Expenses.    Depreciation, depletion and amortization ("DD&A") expense decreased to $3.0 million for the three months ended March 31, 2004 from $3.1 million for the same period of 2003. The decline in DD&A was primarily due to the sale of Canadian properties in January 2003. Our DD&A on a per Mcfe basis for the three months ended March 31, 2004 was $1.41 per Mcfe compared to $1.27 per Mcfe in 2003.

        Interest Expense.    Interest expense decreased from $5.2 million for the first three months of 2003 to $5.1 million in 2004. The decrease in interest expense was due to the restructuring of our long-term debt in January 2003, resulting in a reduction of the overall interest rate.

Comparison of Year Ended December 31, 2003 to Year Ended December 31, 2002.

        Operating Revenue.    During the year ended December 31, 2003, operating revenue from crude oil, natural gas and natural gas liquids sales decreased by $12.8 million from $50.9 million in 2002 to $38.1 million in 2003. The decrease in revenue was primarily due to decreased production volumes, primarily due to the sale of our Canadian subsidiaries in January 2003, which was partially offset by higher commodity prices realized during the period. Higher commodity prices contributed $16.5 million

27

to crude oil and natural gas revenue while reduced production volumes had a $29.3 million negative impact on revenue. The Canadian properties which were sold in January 2003 contributed $29.3 million to revenues from crude oil and natural gas for the year ended December 31, 2002, compared to $3.1 million in 2003 through the date of sale (January 23, 2003).

        Natural gas liquids volumes declined from 242.0 MBbls in 2002 to 37.3 MBbls in 2003 The decline in natural gas liquids volumes was due almost entirely to the sale of our Canadian subsidiaries in January 2003. These properties contributed 232.5 MBbls of natural gas liquids in 2002 compared to 11.7 MBbls during 2003. Crude oil sales volumes declined from 292.3 MBbls in 2002 to 251.6 MBbls during 2003. The Canadian properties which were sold in January 2003 contributed 27.7 MBbls of crude oil production in 2002 compared to 2.4 MBbls in 2003 through the date of the sale. Crude oil production volumes relating to the Canadian properties which were retained and current drilling activities in Canada resulted in an increase to 29.0 MBbls in 2003 compared to 9.5 MBbls in 2002. Crude oil production from U.S. operations decreased due primarily to natural field declines. Natural gas sales volumes decreased from 15.5 Bcf in 2002 to 6.2 Bcf in 2003. This decrease is primarily due to the sale of our Canadian subsidiaries in January 2003. The Canadian properties sold contributed 9.8 Bcf in 2002 compared to .558 MMcf in 2003 through the date of sale.

        Average sales prices in 2003 net of hedging costs were:

•

30.32 per Bbl of crude oil,



•

24.47 per Bbl of natural gas liquids, and



•

4.78 per Mcf of natural gas.

        Average sales prices in 2002 net of hedging costs were:

•

24.34 per Bbl of crude oil,



•

17.94 per Bbl of natural gas liquids, and



•

2.55 per Mcf of natural gas.

        Lease Operating Expense.    Lease operating expense, or LOE, decreased from $15.2 million in 2002 to $9.6 million in 2003 The decrease in LOE is primarily due the sale of Canadian Abraxas and Old Grey Wolf in January 2003. LOE related to the properties owned by Canadian Abraxas and Old Grey Wolf was $7.3 million for the year ended December 31, 2002. Excluding the properties sold, LOE attributable to on going operations increased, primarily due to higher production taxes associated with higher commodity prices in 2003 as compared to 2002. Our LOE on a per Mcfe basis for the year ended December 31, 2003 was $1.21 per Mcfe compared to $0.82 for 2002, primarily due to the decrease in production volumes.

        G&A Expense.    General and administrative, or G&A, expense decreased from $6.9 million in 2002 to $5.4 million in 2003 The decrease in G&A expense was primarily due to a reduction in personnel in connection with the sale of Canadian Abraxas and Old Grey Wolf on January 23, 2003. Our G&A expense on a per Mcfe basis increased from $0.37 in 2002 to $0.67 in 2003. The increase in the per Mcfe cost was due primarily to lower production volumes in 2003 as compared to 2002.

        G&A—Stock-based Compensation Expense.    Effective July 1, 2000, the Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions Involving Stock Compensation", an interpretation of Accounting Principles Board Opinion No. ("APB") 25. Under the interpretation, certain modifications to fixed stock option awards which were made subsequent to December 15, 1998, and not exercised prior to July 1, 2000, require that the awards be subject to variable accounting until they are exercised, forfeited, or expired. In March 1999, we amended the exercise price to $2.06 on all options with an existing exercise price greater than $2.06. In January 2003,

28

we amended the exercise price to $0.66 per share on certain options with an existing exercise price greater than $0.66 per share which resulted in variable accounting. We charged approximately $1.1 million to stock based compensation expense in 2003 related to these repricings. During 2002, we did not recognize any stock—based compensation due to the decline in the price of our common stock.

        DD&A Expense.    Depreciation, depletion and amortization, or DD&A, expense decreased by $15.7 million from $26.5 million in 2002 to $10.8 million in 2003. The decrease in DD&A was primarily due to the sale of our Canadian subsidiaries in January 2003 as well as ceiling limitation write-downs in the second quarter of 2002. Our DD&A expense on a per Mcfe basis for 2003 was $1.33 per Mcfe as compared to $1.42 per Mcfe in 2002.

        Interest Expense.    Interest expense decreased from $34.1 million to $17.0 million for 2003 compared to 2002. The decrease in interest expense was due to the reduction in debt in 2003. Total debt was reduced as a result of the transactions which occurred on January 23, 2003. Total debt was $300.4 million as of December 31, 2002 compared to $184.6 million at December 31, 2003.

        Ceiling Limitation Write-down.    We record the carrying value of our crude oil and natural gas properties using the full cost method of accounting. For more information on the full cost method of accounting, you should read the description under "Critical Accounting Policies—Full Cost Method of Accounting for Crude Oil and Natural Gas Activities". At June 30, 2002, our net capitalized costs of crude oil and natural gas properties exceeded the present value of our estimated proved reserves by $138.7 million ($28.2 million on the U.S. properties and $110.5 million on the Canadian properties). These amounts were calculated considering June 30, 2002 prices of $26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. Subsequent to June 30, 2002, commodity prices increased in Canada and we utilized these increased prices in calculating the ceiling limitation write-down. The total write-down was approximately $116.0 million. At December 31, 2003 our net capitalized cost of crude oil and natural gas properties did not exceed the present value of our estimated reserves, due to increased commodity prices during 2003 and, as such, no write-down was recorded in 2003. We cannot assure you that we will not experience additional ceiling limitation write-downs in the future.

        The risk that we will be required to write-down the carrying value of our crude oil and natural gas assets increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long-term contracts for our natural gas. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved resources are revised downward, a further write-down of the carrying value of our crude oil and natural gas properties may be required.

        Income taxes.    Income tax expense increased from a benefit of $29.7 million for the year ended December 31, 2002 to an expense of $377,000 for the year ended December 31, 2003. The expense in 2003 was related to the operations of the Canadian properties prior to their sale on January 23, 2003. There is no current or deferred income tax expense for 2003 related to on-going operations due to the valuation allowance which has been recorded against the deferred tax asset.

Comparison of Year Ended December 31, 2002 to Year Ended December 31, 2001

        Operating Revenue.    During the year ended December 31, 2002, operating revenue from crude oil, natural gas and natural gas liquids sales decreased by $22.3 million from $73.2 million in 2001 to $50.9 million in 2002. This decrease was primarily attributable to a decrease in production volumes and lower commodity prices in 2002 as compared to 2001. Crude oil and natural gas revenue was impacted by $11.5 million from a decline in commodity prices and $10.8 million from reduced production. The

29

decline in production was due to the disposition of certain properties in south Texas and natural field declines.

        Natural gas liquids volumes declined from 278.0 MBbls in 2001 to 242.0 MBbls in 2002. Crude oil sales volumes declined from 454.1 MBbls in 2001 to 292.3 MBbls during 2002. Natural gas sales volumes decreased from 17.5 Bcf in 2001 to 15.5 Bcf in 2002. Production declines were primarily attributable to our disposition of assets during 2002 and natural field declines.

        Average sales prices in 2002 net of hedging losses were:

•

$24.34 per Bbl of crude oil,



•

$17.94 per Bbl of natural gas liquids, and



•

$2.55 per Mcf of natural gas.

        Average sales prices in 2001 net of hedging losses were:

•

$24.63 per Bbl of crude oil,



•

$21.51 per Bbl of natural gas liquids, and



•

$3.20 per Mcf of natural gas.

        Lease Operating Expense.    Lease operating expense ("LOE") decreased from $18.6 million in 2001 to $15.2 million in 2002. LOE on a per Mcfe basis for 2002 was $0.82 per Mcfe as compared to $0.83 per Mcfe in 2001. The decrease in the per Mcfe cost is due to a reduced operating cost offset by the decline in production volumes.

        G&A Expense.    General and administrative ("G&A") expense increased slightly from $6.4 million in 2001 to $6.9 million in 2002. This increase was due primarily to increased legal expenses related to ongoing litigation in 2002. Our G&A expense on a per Mcfe basis increased from $0.30 in 2001 to $0.37 in 2002. The increase in the per Mcfe cost was due primarily to lower production volumes in 2002 as compared to 2001.

        G&A—Stock-based Compensation Expense.    Effective July 1, 2000, the Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions Involving Stock Compensation", an interpretation of Accounting Principles Board Opinion No. ("APB") 25. Under the interpretation, certain modifications to fixed stock option awards which were made subsequent to December 15, 1998, and not exercised prior to July 1, 2000, require that the awards be subject to variable accounting until they are exercised, forfeited, or expired. In March 1999, we amended the exercise price to $2.06 on all options with an existing exercise price greater than $2.06. We charged approximately $2.8 million to stock-based compensation expense in 2000 compared to crediting approximately $2.8 million in 2001. This was due to the decline in the market price of our common stock during 2001. During 2002, we did not recognize any stock—based compensation due to the decline in the price of our common stock.

        DD&A Expense.    Depreciation, depletion and amortization ("DD&A") expense decreased by $5.9 million from $32.4 million in 2001 to $26.5 million in 2002. The decline in DD&A is due to reductions in our full cost pool resulting from ceiling test write-downs, as well as lower production volumes. Our DD&A expense on a per Mcfe basis for 2002 was $1.42 per Mcfe as compared to $1.74 per Mcfe in 2001.

        Interest Expense.    Interest expense increased from $31.5 million to $34.1 million for 2002 compared to 2001. The increase was the result of additional sales pursuant to our production payment arrangement with Mirant Americas as well as increased borrowings under Old Grey Wolf's credit facility in 2002. The production payment was reacquired in June 2002 for approximately $6.8 million.

30

        Ceiling Limitation Write-down.    We record the carrying value of our crude oil and natural gas properties using the full cost method of accounting. For more information on the full cost method of accounting, you should read the description under "—Critical Accounting Policies—Full Cost Method of Accounting for Crude Oil and Natural Gas Activities". As of December 31, 2001, our net capitalized costs of crude oil and natural gas properties exceeded the present value of its estimated proved reserves by $71.3 million. These amounts were calculated considering 2001 year-end prices of $19.84 per Bbl for crude oil and $2.57 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. We did not adjust our capitalized costs for its U.S. properties because subsequent to December 31, 2001, crude oil and natural gas prices increased such that capitalized costs for its U.S. properties did not exceed the present value of the estimated proved crude oil and natural gas reserves for its U.S. properties as determined using increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and $2.89 per Mcf for natural gas

        At June 30, 2002, our net capitalized costs of crude oil and natural gas properties exceeded the present value of our estimated proved reserves by $138.7 million ($28.2 million on the U.S. properties and $110.5 million on the Canadian properties). These amounts were calculated considering June 30, 2002 prices of $26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. Subsequent to June 30, 2002, commodity prices increased in Canada and we utilized these increased prices in calculating the ceiling limitation write-down. The total write-down was approximately $116.0 million. At December 31, 2002 our net capitalized cost of crude oil and natural gas properties did not exceed the present value of our estimated reserves, due to increased commodity prices during the fourth quarter and, as such, no further write-down was recorded. We cannot assure you that we will not experience additional ceiling limitation write-downs in the future.

        The risk that we will be required to write-down the carrying value of our crude oil and natural gas assets increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long-term contracts for our natural gas. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved resources are revised downward, a further write-down of the carrying value of our crude oil and natural gas properties may be required. See Note 18 of Notes to Consolidated Financial Statements.

        Income taxes.    Income tax expense decreased from an expense of $2.4 million for the year ended December 31, 2001 to a benefit of $29.7 million for the year ended December 31, 2002. The decrease was primarily due to the tax benefit relating to the ceiling limitation write-down related to our Canadian properties.

Liquidity and Capital Resources

        General.    The crude oil and natural gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following costs:

•

the development of existing properties, including drilling and completion costs of wells;



•

acquisition of interests in crude oil and natural gas properties; and



•

production and transportation facilities.

The amount of capital available to us will affect our ability to service our existing debt obligations and to continue to grow the business through the development of existing properties and the acquisition of new properties.

31

        Our sources of capital are primarily cash on hand, cash from operating activities, funding under the new senior credit agreement and the sale of properties. Our overall liquidity depends heavily on the prevailing prices of crude oil and natural gas and our production volumes of crude oil and natural gas. Significant downturns in commodity prices, such as that experienced in the last nine months of 2001 and the first quarter of 2002, can reduce our cash from operating activities. Although we have hedged a portion of our natural gas and crude oil production and will continue this practice as required pursuant to the new senior credit agreement, future crude oil and natural gas price declines would have a material adverse effect on our overall results, and therefore, our liquidity. Low crude oil and natural gas prices could also negatively affect our ability to raise capital on terms favorable to us.

        If the volume of crude oil and natural gas we produce decreases, our cash flow from operations will decrease. Our production volumes will decline as reserves are produced. In addition, due to sales of properties in 2002 and January 2003, we now have significantly reduced reserves and production levels. In the future we may sell additional properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful exploration, exploitation and development activities, acquire additional producing properties or identify additional behind-pipe zones or secondary recovery reserves. While we have had some success in pursuing these activities, historically, we have not been able to fully replace the production volumes lost from natural field declines and property sales.

        Working Capital.    At March 31, 2004, our current liabilities of approximately $13.3 million exceeded our current assets of $7.9 million resulting in a working capital deficit of $5.4 million. This compares to a working capital deficit of approximately $2.4 million at December 31, 2003. Current liabilities at March 31, 2004 consisted of trade payables of $4.1million, revenues due third parties of $2.4 million and accrued interest of $5.3 million related to our new notes, of which $4.9 million is non-cash and other accrued liabilities of $1.4 million. Under our senior credit agreement, we will have cash interest expense of approximately $4.5 million for 2004. We do not expect to make cash interest payments with respect to the outstanding new notes, and the issuance of additional new notes in lieu of cash interest payments thereon will not affect our working capital balance.

        Capital Expenditures.    Capital expenditures in 2001, 2002 and 2003 and for the three months ended March 31, 2004 were $57.1 million, $38.7 million, $18.3 million and $4.2 million, respectively. The table below sets forth the components of these capital expenditures for the three years ended December 31, 2003 and for the three months ended March 31, 2003 and 2004.

		Year Ended December 31,						Three Months Ended March 31,
		2001		2002		2003		2003		2004
		(dollars in thousands)
Expenditure category:
	Development		56,694		38,560		18,313	$	4,423	$	3,549
	Facilities and other		362		154		36		166		681
		$	57,056	$	38,714	$	18,349	$	4,589	$	4,230

        During the three months ended March 31, 2003 and 2004 and during, 2002 and 2003, capital expenditures were primarily for the development of existing properties. We currently have a capital expenditure budget of $10 million for 2004, of which $5.0 million is allocated to U.S. projects and $5.0 million is allocated to Canadian drilling projects. We plan to participate in the drilling or putting on production of 17 gross (13 net) wells, of which 11 gross (11 net) wells will be operated by us. Our capital expenditures could include expenditures for acquisition of producing properties if such opportunities arise, but we currently have no agreements, arrangements or undertakings regarding any material acquisitions. We have no material long-term capital commitments and are consequently able to

32

adjust the level of our expenditures as circumstances dictate. Additionally, the level of capital expenditures will vary during future periods depending on market conditions and other related economic factors. Should the prices of crude oil and natural gas decline from current levels, our cash flows will decrease which may result in a reduction of the capital expenditures budget. If we decrease our capital expenditures budget, we may not be able to offset crude oil and natural gas production volumes decreases caused by natural field declines and sales of producing properties.

        Sources of Capital.    The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:

	Year Ended December 31,									Three Months Ended March 31,
	2001			2002			2003			2003			2004
Net cash (used in) provided by operating activities	$	16,263		$	(8,336	)	$	23,850		$	2,745		$	7,083
Net cash provided by (used in) investing activities		(30,797	)		(5,036	)		67,461			81,235			(4,230	)
Net cash provided by (used in) financing activities		20,685			10,836			(95,662	)		(86,587	)		(1,899	)
Total	$	6,151		$	(2,536	)	$	(4,311	)	$	(2,607	)	$	909

        Operating activities during the three months ended March 31, 2004 provided us $7.1 million cash compared to providing $2.7 million in the same period in 2003. Net loss plus non-cash expense items during 2004 and net changes in operating assets and liabilities accounted for most of these funds. Financing activities used $1.9 million for the first three months of 2004 compared to using $86.6 million for the same period of 2003. Most of these funds were used to reduce our long-term debt and for financing fees. In 2003 funds were used to reduce our long-term debt and were generated by the sale of our Canadian subsidiaries and the exchange offer completed in January 2003. Investing activities used $4.2 million during the three months ended March 31, 2004 compared to providing $81.2 million for the quarter ended March 31, 2003. Expenditures during the quarter ended March 31, 2004 were primarily for the development of existing properties. The sale of our Canadian subsidiaries contributed $85.8 million in 2003 reduced by $4.6 million in exploration and development expenditures.

        Operating activities for the year ended December 31, 2003 provided us with $23.9 million of cash. Investing activities provided us $67.5 million during 2003. Financing activities used $95.6 million during 2003. Most of these funds were used to reduce our long-term debt and were generated by the sale of our Canadian subsidiaries and the exchange offer completed in January 2003. The sale of our Canadian subsidiaries contributed $85.8 million in 2003 reduced by $18.3 million in exploration and development expenditures. Expenditures in 2003 were primarily for the development of crude oil and natural gas properties.

        Operating activities for the year ended December 31, 2002 used $8.4 million of cash. Investing activities used $5.0 million during 2002. Our investing activities included the sale of properties which provided $33.9 million, and the use of $38.9 million primarily for the development of producing properties. Financing activities provided us with $10.8 million during 2002, relating primarily to advances on Old Grey Wolf's credit facility.

        Operating activities for the year ended December 31, 2001, provided us $16.3 million of cash. Investing activities included the sale of properties which provided $28.9 million, and the use of $57.1 million for the development of producing properties and $2.7 million for the acquisition of the minority interest in Grey Wolf. Financing activities provided $20.7 million during 2001, including the provision of additional funding of $11.7 million under our production payment arrangement with

33

Mirant Americas, and the provision of $18.3 million under Old Grey Wolf's credit facility. Payments on long term debt used $9.3 million during 2001.

        Future Capital Resources.    We will have four principal sources of liquidity going forward: (i) cash on hand, (ii) cash from operating activities, (iii) funding under the senior credit agreement, and (iv) sales of producing properties. However, covenants under the indenture for the outstanding new notes and the senior credit agreement restrict our use of cash on hand, cash from operating activities and any proceeds from asset sales. We may attempt to raise additional capital through the issuance of additional debt or equity securities, though the terms of the indenture and the new senior credit agreement substantially restrict our ability to:

•

incur additional indebtedness;



•

incur liens;



•

pay dividends or make certain other restricted payments;



•

consummate certain asset sales;



•

enter into certain transactions with affiliates;



•

merge or consolidate with any other person; or



•

sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets.

Contractual Obligations

        We are committed to making cash payments in the future on the following types of agreements:

•

Long-term debt



•

Operating leases for office facilities

We have no off-balance sheet debt or unrecorded obligations and we have not guaranteed the debt of any other party. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of March 31, 2004:

	Payments due in:
Contractual obligations	Total		Less than one year		1-3 years		3-5 years		More than 5 years
	(dollars in thousands)
Long-Term Debt(1)	$	233,957	$	—	$	49,713	$	184,244	—
Operating Leases(2)		1,269		415		734		120	—

(1)

These amounts represent the balances outstanding under the term loan facility, the revolving credit facility and the new notes. These repayments assume that interest will be capitalized under the term loan facility and that periodic interest on the revolving credit facility will be paid on a monthly basis and that we will not draw down additional funds thereunder.

(2)

Office lease obligations. Leases for office space for Abraxas and New Grey Wolf expire in April 2006 and December 2008, respectively.

        Other obligations.    We make and will continue to make substantial capital expenditures for the acquisition, exploitation, development, exploration and production of crude oil and natural gas. In the past, we have funded our operations and capital expenditures primarily through cash flow from operations, sales of properties, sales of production payments and borrowings under our bank credit facilities and other sources. Given our high degree of operating control, the timing and incurrence of operating and capital expenditures is largely within our discretion.

34

        Long-Term Indebtedness.    The financial restructuring resulted in the retirement of our first lien notes, second lien notes and old notes, together with the Old Grey Wolf credit facility. The following table sets forth our long-term indebtedness as of December 31, 2003, and March 31, 2004.

Long-Term Indebtedness

	December 31, 2003		March 31, 2004
111/2% Secured Notes due 2007 (new notes)	$	137,258	$	137,258
Senior Credit Agreement		47,391		49,713
		184,649		186,971
Less current maturities		—		—
	$	184,649	$	186,971

        11¹/2% Secured Notes.    In connection with the financial restructuring, Abraxas issued $109.7 million in principal amount of 11¹/2% Secured Notes due 2007, Series A, in exchange for the second lien notes and old notes tendered in the exchange offer. The notes were issued under an indenture with U.S. Bank, N. A. For a more complete description of the notes, see "Description of the Notes" beginning on page 77 of this prospectus.

        Senior Credit Agreement.    In connection with the financial restructuring, Abraxas entered into a new senior credit agreement providing a term loan facility and a revolving credit facility as described below. Subsequently, on February 23, 2004, Abraxas entered into an amendment to its existing senior credit agreement providing for two revolving credit facilities and a new non-revolving credit facility as described below. Subject to earlier termination on the occurrence of events of default or other events, the stated maturity date for these credit facilities is February 1, 2007. In the event of an early termination, we will be required to pay a prepayment premium, except in the limited circumstances described in the amended senior credit agreement.

        First Revolving Credit Facility.    Lenders under the amended senior credit agreement have provided a revolving credit facility to Abraxas with a maximum borrowing base of up to $20 million. Our current borrowing base under this revolving credit facility is the full $20.0 million, subject to adjustments based on periodic calculations and mandatory prepayments under the senior credit agreement. We have borrowed $6.6 million under this revolving credit facility, which was used to refinance principal and interest on advances under our preexisting revolving credit facility under the senior credit agreement, and to pay certain fees and expenses relating to the transaction. Outstanding amounts under this revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 1.125%.

        Second Revolving Credit Facility.    Lenders under the amended senior credit agreement have provided a second revolving credit facility to Abraxas, with a maximum borrowing of up to $30 million. This revolving credit facility is not subject to a borrowing base. We have borrowed $30.0 million under this revolving credit facility, which was used to refinance principal and interest on advances under our preexisting revolving credit facility, and to pay certain transaction fees and expenses. Outstanding amounts under this revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 3.00%.

        Non-Revolving Credit Facility.    Abraxas has borrowed $15.0 million pursuant to a non-revolving credit facility, which was used to repay the preexisting term loan under our senior credit agreement, to refinance principal and interest on advances under the preexisting revolving credit facility, and to pay certain transaction fees and expenses. This non-revolving credit facility is not subject to a borrowing

35

base. Outstanding amounts under this credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 8.00%.

        Covenants.    Under the amended senior credit agreement, Abraxas is subject to customary covenants and reporting requirements. Certain financial covenants require Abraxas to maintain minimum ratios of consolidated EBITDA (as defined in the amended senior credit agreement) to adjusted fixed charges (which includes certain capital expenditures), minimum ratios of consolidated EBITDA to cash interest expense, a minimum level of unrestricted cash and revolving credit availability, minimum hydrocarbon production volumes and minimum proved developed hydrocarbon reserves. In addition, if on the day before the end of each fiscal quarter the aggregate amount of our cash and cash equivalents exceeds $2.0 million, we are required to repay the loans under the amended senior credit agreement in an amount equal to such excess. The amended senior credit agreement also requires us to enter into hedging agreements on not less than 40% or more than 75% of our projected oil and gas production. We are also required to establish deposit accounts at financial institutions acceptable to the lenders and we are required to direct our customers to make all payments into these accounts. The amounts in these accounts will be transferred to the lenders upon the occurrence and during the continuance of an event of default under the amended senior credit agreement.

        In addition to the foregoing and other customary covenants, the amended senior credit agreement contains a number of covenants that, among other things, restrict our ability to:

•

incur additional indebtedness;



•

create or permit to be created liens on any of our properties;



•

enter into change of control transactions;



•

dispose of our assets;



•

change our name or the nature of our business;



•

make guarantees with respect to the obligations of third parties;



•

enter into forward sales contracts;



•

make payments in connection with distributions, dividends or redemptions relating to our outstanding securities, or



•

make investments or incur liabilities.

Security.    The obligations of Abraxas under the amended senior credit agreement continue to be secured by a first lien security interest in substantially all of Abraxas' assets, including all crude oil and natural gas properties.

        Guarantees.    The obligations of Abraxas under the amended senior credit agreement continue to be guaranteed by Abraxas' subsidiaries, Sandia Oil & Gas, Sandia Operating, Wamsutter, New Grey Wolf, Western Associated Energy and Eastside Coal. The guarantees under the amended senior credit agreement continue to be secured by a first lien security interest in substantially all of the guarantors' assets, including all crude oil and natural gas properties.

        Events of Default.    The amended senior credit agreement contains customary events of default, including nonpayment of principal or interest, violations of covenants, inaccuracy of representations or warranties in any material respect, cross default and cross acceleration to certain other indebtedness, bankruptcy, material judgments and liabilities, change of control and any material adverse change in our financial condition.

36

Hedging Activities

        Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. Under the senior credit agreement, we are required to maintain hedge positions on not less than 40% or more than 75% of our projected oil and gas production for a six month rolling period. See "—Quantitative and Qualitative Disclosures about Market Risk—Hedging Sensitivity" for further information.

Net Operating Loss Carryforwards

        At December 31, 2003 we had, subject to the limitation discussed below, $100.6 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire through 2022 if not utilized. In connection with financial restructuring transactions described in Note 2, in Notes to Consolidated Financial Statements, certain of the loss carryforwards were utilized.

        Uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, we have established a valuation allowance of $99.1 million and $76.1 million for deferred tax assets at December 31, 2002 and 2003, respectively.

Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

        As an independent crude oil and natural gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil, natural gas and natural gas liquids. Declines in commodity prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the year ended December 31, 2003 a 10% decline in crude oil, natural gas and natural gas liquids prices would have reduced our operating revenue, cash flow and net income by approximately $3.8 million for the year.

Hedging Sensitivity

        On January 1, 2001, we adopted SFAS 133 as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge or cash flow hedge. If the derivative qualifies for cash flow hedge accounting, the gain or loss on the derivative is deferred in Other Comprehensive Income (Loss), a component of Stockholders' Equity, to the extent that the hedge is effective. As of December 31, 2003, the derivatives that we have in place were not designated as hedges. Accordingly, changes in the fair market value of the derivatives are recorded in current period oil and gas revenue.

        If the derivative qualifies for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows

37

attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in accumulated Other Comprehensive Income/Loss related to a cash flow hedge that becomes ineffective, remain unchanged until the related production is delivered. If we determine that it is probable that a hedged transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.

        Gains and losses on qualified hedging instruments related to accumulated Other Comprehensive Income and adjustments to carrying amounts on hedged production are included in natural gas or crude oil production revenue in the period that the related production is delivered. For derivatives not qualifying for hedge accounting, changes in the fair market value of the instrument are changed to income in the current period.

        In 2001 and 2002, we experienced hedging losses of $12.1 million and $3.2 million, respectively. In October 2002, all of these hedge agreements expired. We made total payments to various counterparties of $35.1 million during the terms of these expired hedge agreements.

        Under the terms of the senior credit agreement, we are required to maintain hedging positions with respect to not less than 40% nor more than 75% of our crude oil and natural gas production for a rolling six month period.

        All hedge transactions are subject to our risk management policy, which has been approved by the Board of Directors. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

Interest Rate Risk

        As a result of the financial restructuring that occurred in January 2003, and the amendment to the senior credit agreement in February 2004, the debt under the senior credit agreement bears interest at the bank prime rate plus various points. As of March 31, 2004, we had $49.7 million in outstanding indebtedness under the senior credit agreement. For every percentage point that the prime rate rises, our interest expense would increase by approximately $497,000 on an annual basis. Our new notes accrue interest at fixed rates. A change in interest rates impacts the net market value of the Company's fixed rate debt but has no impact on interest incurred or cash flows on the Company's fixed rate debt.

Foreign Currency Risk

        Our Canadian operations are measured in the local currency of Canada. As a result, our financial results are affected by changes in foreign currency exchange rates or weak economic conditions in the foreign markets. Our Canadian operations reported a pre-tax income of $218,000 for the year ended December 31, 2003. It is estimated that a 5% change in the value of the U.S. dollar to the Canadian dollar would have changed our net income by approximately $10,900. We do not maintain any derivative instruments to mitigate the exposure to translation risk. However, this does not preclude the adoption of specific hedging strategies in the future.

Related Party Transactions

        Accounts receivable—Other in the consolidated balances sheets includes approximately $51,211 and $35,558 as of December 31, 2002 and 2003, respectively, representing amounts due from officers and stockholders relating to advances made to employees.

38

        Wind River Resources Corporation ("Wind River"), all of the capital stock of which is owned by the Company's President, previously owned a twin-engine airplane. The airplane was available for business use by the employees of the Company from time to time. The Company paid Wind River a total of approximately $314,000, $345,000 and $132,000 in 2001, 2002 and 2003, respectively, for Wind River's operating costs associated with the Company's use of the plane. The airplane was sold in July 2003.

Critical Accounting Policies

        The preparation of financial statements in conformity with generally accepted accounting principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.

        Full Cost Method of Accounting for Crude Oil and Natural Gas Activities.    SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and the full cost method. Abraxas has chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of crude oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the "full cost" pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher depreciation, depletion and amortization date on our crude oil and natural gas properties.

        At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. We have experienced this situation several times over the years, most recently in 2002. Our crude oil and natural gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from the full cost method of accounting.

        Under full cost accounting rules, the net capitalized cost of crude oil and natural gas properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling limitation write-down." This charge does not impact cash flow from operating activities, but does reduce our stockholders' equity and reported earnings. The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for our natural gas production. An expense

39

recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period.

        For the year ended December 31, 2002, we recorded a write-down of $116.0 million. The write-down in 2002 was due to low commodity prices. We cannot assure you that we will not experience additional write-downs in the future.

        Estimates of Proved Oil and Natural Gas Reserves.    Estimates of our proved reserves included in this prospectus are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

•

the quality and quantity of available data;



•

the interpretation of that data;



•

the accuracy of various mandated economic assumptions;



•

and the judgment of the persons preparing the estimate.

        Our proved reserve information included in this prospectus was based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

        You 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 on 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.

        The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields.

        Use of Estimates.    The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Management believes that it is reasonably possible that estimates of proved crude oil and natural gas revenues could significantly change in the future.

        Revenue Recognition.    The Company recognizes crude oil and natural gas revenue from its interest in producing wells as crude oil and natural gas is sold from those wells, net of royalties. Revenue from the processing of natural gas is recognized in the period the service is performed. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, income is recorded based on the Company's net revenue interest in production taken for delivery. The Company had no material gas imbalances.

        Asset Retirement Obligations.    The estimated costs of restoration and removal of facilities are accrued. The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the

40

capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense.

        Hedge Accounting.    From time to time, we use commodity price hedges to limit our exposure to fluctuations in crude oil and natural gas prices. Results of those hedging transactions are reflected in crude oil and natural gas sales.

        Statement of Financial Accounting Standards, ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities", was effective for us on January 1, 2001. SFAS 133, as amended and interpreted, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. Under this statement, all derivatives, whether designated in hedging relationships or not, are required to be recorded at fair value on our balance sheet. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results of the hedged item in the consolidated statement of operations. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. For derivative instruments designated as fair value hedges, changes in fair value, to the extent the hedge is effective, are recognized as an increase or decrease to the value of the hedged item until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in the fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings. Changes in fair value of contracts that do not meet the SFAS 133 definition of a cash flow or fair value hedge are also recognized in earnings through risk management income. All amounts initially recorded in this caption are ultimately reversed within the same caption and included in oil and gas sales or interest expense, as applicable, over the respective contract terms.

        One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of all derivative instruments using estimates determined by our counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

        Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at the inception and on an ongoing basis. This correlation is complicated because energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.

        Due to the volatility of crude oil and natural gas prices and, to a lesser extent, interest rates, our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2003 the net market value of our derivatives was an asset of $21,136. As of December 31, 2002, we did not have any outstanding derivatives.

41

New Accounting Pronouncements

        In March 2004, the Emerging Issues Task Force ("EITF") reached a consensus that mineral rights, as defined in EITF Issue No. 04-2, "Whether Mineral Rights are Tangible or Intangible Assets," are tangible assets and that they should be removed as examples of intangible assets in SFAS No. 141, "Business Combinations" and No. 142, "Goodwill and Other Intangible Assets". The FASB has recently ratified this consensus and directed the FASB staff to amend SFAS Nos. 141 and 142 through the issuance of FASB Staff Position FAS Nos. 141-1 and 142-1. Historically, the Company has included the costs of such mineral rights as tangible assets, which is consistent with the EITF's consensus. As such, EITF 04-02 has not affected the Company's consolidated financial statements.

        In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 was effective for us January 1, 2003. SFAS No. 143 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense in the accompanying financial statements.

        The Company adopted SFAS 143 effective January 1, 2003. For the year ended December 31, 2003 the Company recorded a charge of $395,341 for the cumulative effect of the change in accounting principal and a liability of $1.3 million. During 2003, the Company charged approximately $379,000 to expense related to the accretion of the liability. The impact on each of the prior periods was not material.

        In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). Effective January 1, 2002, the Company adopted SFAS 144. SFAS 144 retains the requirement to recognize an impairment loss only where the carrying value of a long-lived asset is not recoverable from its undiscounted cash flows and to measure such loss as the difference between the carrying amount and fair value of the asset. SFAS 144, among other things, changes the criteria that have to be met to classify an asset as held-for-sale and requires that operating losses from discontinued operations be recognized in the period that the losses are incurred rather than as of the measurement date. This new standard had no impact on the Company's consolidated financial statements for the year ended December 31, 2003.

        In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS 146). SFAS 146 requires costs associated with exit of disposal activities to be recognized when they are incurred rather than at the date of commitment to an exit or disposal plan. The Company is currently evaluating the impact the standard will have on its results of operations and financial condition. The standard is effective for exit or disposal activities initiated after December 31, 2002.

        In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 149, among other things, clarifies the circumstances under which a contract with an initial net investment meets the characteristic of a derivative and amends the definition of an "underlying" to conform it to language used in FIN 45. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. The Company adopted this statement effective

42

July 1, 2003. Implementation of this new standard did not have an effect on the Company's consolidated financial position or results of operations.

        In November 2002 the FASB issued FASB Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees that it has issued, including loan guarantees such as standby letters of credit. It also requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligations it has undertaken in issuing the guarantee. The Interpretation does not specify the subsequent measurement of the guarantor's recognized liability over the term of the related guarantee. The guidance in FIN 45 does not apply to certain guarantee contracts, such as those issued by insurance companies or for a lessee's residual value guarantee embedded in a capital lease. The provisions related to recognizing a liability at inception of the guarantee for the fair value of the guarantor's obligations would not apply to product warranties or to guarantees accounted for as derivatives. The initial recognition and initial measurement provisions apply on a prospective basis to guarantees issued or modified after December 31, 2002, regardless of the guarantor's fiscal year-end. FIN 45 specifies additional disclosures effective for financial statements of interim or annual periods ending after December 15, 2002.

        In January 2003 the FASB issued FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable-Interest Entities (VIEs"). FIN 46 establishes the definition of VIEs to encompass a broader group of entities than those previously considered special-purpose entities (SPEs). FIN 46 specifies the criteria under which it is appropriate for an investor to consolidate VIEs; in order for an investor to consolidate a VIE, the entity must fall within the definition of VIE and the investor must fall within the definition of primary beneficiary, both newly defined terms under this FIN. The revised effective date of FIN 46 for public companies with VIEs meeting certain conditions will be the end of the first interim or annual period ending after December 15, 2003. In December 2003, the FASB issued FASB Interpretation no. 46(R)m which expanded and clarified the guidelines of FIN 46.

        In May 2003, the FASB issued FAS No. 150, entitled "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity"(SFAS 150). This statement is effective for financial instruments entered into or modified after May 31, 2003, and is otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The Company has no financial instruments affected by SFAS 150, therefore adoption by the Company as of July 1, 2003 will not impact the Company's financial statements.

43

BUSINESS

General

        We are an independent energy company engaged primarily in the acquisition, exploration, exploitation, and production of crude oil and natural gas. Our principal means of growth has been through the acquisition and subsequent development and exploitation of producing properties. As a result of our historical acquisition activities, we believe that we have a substantial inventory of low risk exploration and development opportunities, the development of which is critical to the maintenance and growth of our current production levels. We seek to complement our acquisition and development activities by selectively participating in exploration projects with experienced industry partners.

        Our principal areas of operation are Texas and western Canada. At December 31, 2003, we owned interests in 263,730 gross acres (183,354 net acres), and operated properties accounting for approximately 88% of our PV-10, affording us substantial control over the timing and incurrence of operating and capital expenditures. At December 31, 2003 estimated total proved reserves were 121.1 Bcfe with an aggregate PV-10 of $216.8 million. During 2003, we continued exploitation activities on our U.S. and Canadian properties. We participated in the drilling of 24 gross (11.8 net) wells with 23 gross (11.3 net) being successful, representing a total investment of $18.3 million in capital spending during 2003. At the end of 2003, as a result of these activities, our average daily production was approximately 24 MMcfe per day which represented a 26% increase from the daily production rate at the beginning of the year (excluding production from the Canadian properties sold in January 2003).

Business Strategy

        Our primary business objectives are to increase reserves, production and cash flow through the following:

•

Low Cost Operations. We seek to maintain low lease operating and G&A expenses per Mcfe by operating a majority of our producing properties and by maintaining a high rate of production on a per well basis. As a result of this strategy, we have achieved per unit lease operating and G&A expenses that compare favorably with our peer companies.



•

Exploitation of Existing Properties. We will continue to allocate a portion of our operating cash flow to the exploitation of our proved oil and natural gas properties. We believe that the proximity of our undeveloped reserves to existing production makes development of these properties less risky and more cost-effective than other drilling opportunities available to us. Given our high degree of operating control, the timing and incurrence of operating and capital expenditures is largely within our discretion. Abraxas' inventory of development opportunities is considerable and growing, but our ability to exploit that inventory will depend on our ability to raise additional capital and on our discretionary cash flow, which in turn is highly dependent on future crude oil and natural gas prices.

Recent Developments

Financial Restructuring

        In January 2003, we completed a series of transactions designed to reduce our indebtedness, improve our ability to meet our debt service obligations and provide us with working capital necessary to develop our existing crude oil and natural gas properties. As a result of these transactions, which we sometimes refer to in this prospectus as the financial restructuring, we have reduced the principal amount of our overall outstanding long-term debt from approximately $300 million at December 31, 2002 to approximately $156.4 million in principal amount at January 23, 2003 ($187 million at March 31, 2004), and reduced our annual cash interest payments from approximately $34 million, to approximately $4 million, assuming that, as required under the senior credit agreement, Abraxas issues

44

additional notes in lieu of cash interest payments. Due to the accounting treatment under accounting principles generally accepted in the United States of America for financial restructurings, the reported carrying value of such total indebtedness was approximately $175 million ($128.6 million as of January 23, 2003 and $142.2 million at March 31, 2004 related to the outstanding notes). The transactions comprising the financial restructuring are summarized below.

        Exchange Offer.    On January 23, 2003 Abraxas completed an exchange offer, pursuant to which it offered to exchange cash and securities for all of the outstanding 11¹/2% Senior Secured Notes due 2004, Series A, or second lien notes, and 11¹/2% Senior Notes due 2004, Series D, or old notes, issued by Abraxas and Canadian Abraxas. In exchange for each $1,000 principal amount of notes tendered in the exchange offer, tendering note holders received:

•

cash in the amount of $264;



•

an 11¹/2% Secured Note due 2007, Series A, with a principal amount equal to $610; and



•

31.36 shares of Abraxas common stock.

        At the time the exchange offer was made, there were approximately $190.2 million of the second lien notes and $801,000 of the old notes outstanding. Holders of approximately 94% of the aggregate outstanding principal amount of the second lien notes and old notes tendered their notes for exchange in the offer. Pursuant to the procedures for redemption under the applicable historical indenture provisions, the remaining 6% of the aggregate outstanding principal amount of the second lien notes and old notes were redeemed at 100% of the principal amount plus accrued and unpaid interest, for approximately $11.5 million ($11.1 million in principal and $0.4 million in interest). The indentures for the second lien notes and old notes were duly discharged. In connection with the exchange offer, Abraxas made cash payments of approximately $47.5 million and issued approximately $109.7 million in principal amount of notes and 5,642,699 shares of Abraxas common stock, each of which are being offered for resale under this prospectus. Fees and expenses incurred in connection with the exchange offer were approximately $3.8 million.

        Sale of Stock of Canadian Abraxas and Old Grey Wolf.    Contemporaneously with the closing of the exchange offer, on January 23, 2003, Abraxas completed the sale to a wholly-owned subsidiary of PrimeWest Energy Inc. of all of the outstanding capital stock of two of Abraxas' former wholly owned subsidiaries, Canadian Abraxas and Old Grey Wolf for approximately $138 million before net adjustments of $3.4 million. The aggregate sales price for the shares of capital stock of Canadian Abraxas and Old Grey Wolf was as follows:

	Number of Shares	Sales Price
Canadian Abraxas	5,751 common shares	$	68 million
Old Grey Wolf	12,804,628 common shares	$	70 million
	Total Sales Price:	$	138 million

        After sales price adjustments and related costs and expenses of approximately $5.9 million were made, the sales price realized for the sale of Canadian Abraxas and Old Grey Wolf was $132.1 million. Upon consummation of the sale, Old Grey Wolf repaid the outstanding indebtedness under its credit agreement with Mirant Canada Energy Capital, Ltd. in the amount of $46.3 million, which reduced the net proceeds from the sale by a corresponding amount. The net cash proceeds from the sale were $85.8 million, all of which has been utilized in connection with the financial restructuring.

        The properties transferred in conjunction with the sale of Canadian Abraxas and Old Grey Wolf amounted to approximately 35% of our total proved reserves at June 30, 2002 and approximately 60% of our production for the quarter ended September 30, 2002. Under the terms of the agreement with

45

PrimeWest, Abraxas has retained certain assets formerly held by Canadian Abraxas and Old Grey Wolf, including all of Canadian Abraxas' and Old Grey Wolf's undeveloped acreage existing at the time of the sale, which includes all of our interests in the Ladyfern area. These assets have been contributed to New Grey Wolf, a new wholly-owned Canadian subsidiary of Abraxas. Portions of this undeveloped acreage will be developed by PrimeWest and New Grey Wolf under a farmout arrangement. Under the farmout arrangements, PrimeWest has agreed to participate in the development of certain lands of New Grey Wolf in the Caroline and Pouce Coupe areas of Alberta. PrimeWest has the right to obtain a 60% interest in certain wells if it bears 100% of the expense of drilling such wells. In addition, New Grey Wolf and PrimeWest will have an area of mutual interest in respect of the lands surrounding the Caroline area where each party will be entitled to participate in the acquisitions of the other, with New Grey Wolf participating with a 40% interest and PrimeWest participating with a 60% interest.

        Redemption of First Lien Notes.    On January 24, 2003, we completed the redemption of 100% of our outstanding 12⁷/8% Senior Secured Notes, Series A, or first lien notes, with approximately $66.4 million of the proceeds from the sale of Canadian Abraxas and Old Grey Wolf. Prior to the redemption, we had $63.5 million of our first lien notes outstanding. Under the terms of the indenture for the first lien notes, as of March 15, 2002, we had the right to redeem the first lien notes at 100% of the outstanding principal amount of the notes, plus accrued and unpaid interest to the date of redemption, and to discharge the indenture upon call of the first lien notes for redemption and deposit of the redemption funds with the trustee. We exercised these rights on January 23, 2003 and upon the discharge of the indenture, the trustee released the collateral securing our obligations under the first lien notes.

        Senior Credit Agreement.    Contemporaneously with the closing of the exchange offer and the sale of Canadian Abraxas and Old Grey Wolf, on January 23, 2003, Abraxas entered into a new senior credit agreement providing a term loan facility of $4.2 million and a revolving credit facility with a maximum borrowing base of up to $50 million. This facility was amended in February 2004. For a detailed description of the credit facilities under the new senior credit agreement, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Indebtedness" beginning on page 35.

Sources and Uses of Funds in Financial Restructuring

        The following table illustrates the sources and uses of funds for the financial restructuring.

Sources of Funds			Uses of Funds
(US dollars in millions)
Sale of Canadian Abraxas and Old Grey Wolf(1)	$	132.1	Redemption of First Lien Notes(3)	$	66.4
New Senior Credit Agreement(2)		46.7	Exchange Offer Cash Payments(4)		59.0
			Repayment of Old Grey Wolf Credit Facility(5)		46.3
			Fees and Expenses		7.1
Total Sources	$	178.8	Total Uses	$	178.8

(1)

Represents CDN $205.9 million converted to US $134.6 million at an exchange rate of US $0.6538 per CDN $1.00, less fees and expenses of $2.5 million.

(2)

Included term loan facility of $4.2 million and outstanding amounts under the revolving credit facility of $42.5 million at the time of the financial restructuring.

46

(3)

Represents $63.5 million in principal amount of the first lien notes and accrued interest of $2.9 million.

(4)

Represents payments of $47.5 million for the cash portion of the exchange offer consideration and payments of $11.5 million for the redemption of the second lien notes and old notes remaining outstanding upon closing of the exchange offer.

(5)

Represents CDN $70.8 million converted to US $46.3 million at an exchange rate of US $0.6538 per CDN $1.00.

2003 Drilling Results

        In the Peace River Arch area of western Alberta, New Grey Wolf successfully completed a well drilled during the first quarter of 2003 which is currently producing an average of 1.2 MMcfe per day. Two additional wells were drilled in the area during the second quarter. One well has casing set and is awaiting completion. The other well is currently drilling. In the Lady Fern area of northeastern British Columbia, current combined production is approximately an average of 7.5 MMcfe per day from three wells with a 16.7% working interest. New Grey Wolf is currently adding compression to reduce the line pressure, currently 1200 psi, to approximately 450 psi to increase production from these wells. In the Caroline area of southwestern Alberta, a well has been drilled and logged pursuant to a farmout agreement with Prime West and is awaiting completion. In west Texas, under a joint participation agreement with EOG Resources, the sixth horizontal well in the Montoya formation was completed with an initial rate of 16 MMcfe per day. The well is currently producing an average of 8 MMcfe per day. We hold a 20% working interest in the well

Markets and Customers

        The revenue generated by our operations is highly dependent upon the prices of, and demand for, crude oil and natural gas. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our crude oil and natural gas production and the level of such production are subject to wide fluctuations and depend on numerous factors beyond our control including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other crude oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic regulation, legislation and policies. Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenue, profitability and cash flow from operations. You should read the discussion under "Risk Factors—Risks Relating to Our Business—Crude oil and natural gas prices and their volatility could adversely affect our revenues, cash flows and profitability" and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies" for more information relating to the effects on us of decreases in crude oil and natural gas prices.

        In order to manage our exposure to price risks in the marketing of our crude oil and natural gas, from time to time we have entered into fixed price delivery contracts, financial swaps and crude oil and natural gas futures contracts as hedging devices. To ensure a fixed price for future production, we may sell a futures contract and thereafter either (i) make physical delivery of crude oil or natural gas to comply with such contract or (ii) buy a matching futures contract to unwind our futures position and sell our production to a customer. These contracts may expose us to the risk of financial loss in certain circumstances, including instances where production is less than expected, our customers fail to purchase or deliver the contracted quantities of crude oil or natural gas, or a sudden, unexpected event materially impacts crude oil or natural gas prices. These contracts may also restrict our ability to benefit from unexpected increases in crude oil and natural gas prices. You should read the discussion

47

under "Management's Discussion and Analysis of Financial Condition And Results of Operations—Liquidity and Capital Resources," and "Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk" for more information regarding our historical hedging activities.

        Substantially all of our crude oil and natural gas is sold at current market prices under short-term arrangements, as is customary in the industry. During the year ended December 31, 2003, three purchasers accounted for approximately 80% of our United States crude oil and natural gas sales and three customers accounted for approximately 91% of our crude oil and natural gas sales in Canada. We believe that there are numerous other companies available to purchase our crude oil and natural gas and that the loss of one or more of these purchasers would not materially affect our ability to sell crude oil and natural gas. The prices we realize for the sale of our crude oil and natural gas are subject to our hedging activities. You should read the discussion under "Management's Discussion and Analysis of Financial Condition And Results of Operations—Liquidity and Capital Resources" and "Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk" for more historical information regarding our hedging activities.

Primary Operating Areas

Texas

        Our U.S. operations are concentrated in South and West Texas with over 99% of the PV-10 of our U.S. crude oil and natural gas properties at December 31, 2003 located in those two regions. We operate 94% of our wells in Texas. During 2003, we drilled a total of six wells (3.73 net) in Texas with a 100% success rate.

        Operations in South Texas are concentrated along the Edwards trend in Live Oak and Dewitt Counties, the Frio/Vicksburg trend in San Patricio County and the Wilcox trend in Goliad County. In total in South Texas we own an average 93% working interest in 43 wells with average daily production of 239 net Bbls of crude oil and NGLs and 6,210 net Mcf of natural gas per day for the year ended December 31, 2003. As of December 31, 2003 we had estimated net proved reserves in South Texas of 28.6 Bcfe (82% natural gas) with a PV-10 of $57.7 million, 70% of which was attributable to proved developed reserves.

        Our West Texas operations are concentrated along the deep Devonian/Ellenberger formations and shallow Cherry Canyon sandstones in Ward County and in the Sharon Ridge Clearfork Field in Scurry County. In September 2000, Abraxas entered into a farmout agreement with EOG Resources Inc. whereby EOG earned a 75% working interest in Abraxas' then existing Montoya acreage by paying Abraxas $2.5 million and paying 100% of the cost of the first five wells, the last of which came on line in December 2002. Two wells were drilled in 2003 for which Abraxas was responsible for its pro rata share of drilling and development cost. The farmout agreement terminated in January 2004 and EOG is obligated to reassign all unearned acreage to Abraxas. In total in West Texas we own an average 74% working interest in 158 wells with average daily production of 338 net Bbls of crude oil and NGLs and 6,887 net Mcf of natural gas per day for the year ended December 31, 2003. As of December 31, 2003, we had estimated net proved reserves in West Texas of 71.1 Bcfe (80% natural gas) with a PV-10 of $103.6million, 60% of which was attributable to proved developed reserves.

Wyoming

        We currently hold over 60,000 contiguous acres in the Powder River Basin in east central Wyoming. We have drilled and operate five wells in Converse and Niobrara counties that were completed in the Turner and Niobrara formations. We own a 100% working interest in these wells that produced an average of 31 net barrels of crude oil per day in 2003. As of December 31, 2003, we had estimated net proved producing reserves in Wyoming of 68,669 barrels of crude oil with a PV-10 of $ 280,343.

48

Western Canada

        We own properties in western Canada, consisting primarily of natural gas reserves and undeveloped acreage in the provinces of Alberta and British Columbia. Our Alberta properties are in two concentrated areas: the Caroline field, 60 miles northwest of Calgary, and the Peace River Arch area in northwestern Alberta. We have entered into a farmout agreement with PrimeWest in connection with the sale of Canadian Abraxas and Old Grey Wolf to jointly develop these areas in the future. Our other Canadian operations are located in the Ladyfern area of northeast British Columbia.

        As of December 31, 2003 New Grey Wolf had estimated net proved reserves of 21.0 Bcfe (77% natural gas) with a PV-10 of $55.2 million of which 76% was attributable to proved developed reserves. For the year ended December 31, 2003, the Canadian properties produced an average of approximately 111 net Bbls of crude oil and NGLs per day and 2,328 net Mcf of natural gas per day.

Exploratory and Developmental Acreage

        Our principal crude oil and natural gas properties consist of non-producing and producing crude oil and natural gas leases, including reserves of crude oil and natural gas in place. The following table indicates our interest in developed and undeveloped acreage as of December 31, 2003:

		Developed and Undeveloped Acreage
		As of December 31, 2003
		Developed Acreage		Undeveloped Acreage
		Gross Acres	Net Acres	Gross Acres	Net Acres
Canada		18,238	9,075	155,246	93,866
Texas		23,671	18,978	5,864	4,692
Wyoming		3,200	3,200	57,431	53,519
N. Dakota		—	—	80	24
	Total	45,109	31,253	218,621	152,101

Productive Wells

        The following table sets forth our total gross and net productive wells expressed separately for crude oil and natural gas, as of December 31, 2003:

		Productive Wells
		As of December 31, 2003
		Crude Oil		Natural Gas
State/Country
		Gross	Net	Gross	Net
Canada		29.0	5.1	205.0	17.0
Texas		140.5	112.6	60.5	44.7
Wyoming		5.0	5.0	18.0	—
N. Dakota		1.0	—	—	—
	Total	175.5	122.7	283.5	61.7

Reserves Information

        The crude oil and natural gas reserves of the U.S. operations only have been estimated as of January 1, 2004, January 1, 2003, and January 1, 2002, by DeGolyer and MacNaughton, of Dallas, Texas. The reserves of the Canadian operations as of January 1, 2004 and January 1, 2002 have been estimated by DeGolyer and MacNaughton and the terms as of January 1, 2002 were estimated by McDaniel and Associates Consultants Ltd. of Calgary, Alberta. The January 1, 2003 reserves

49

attributable to the Canadian operations were estimated internally. The January 1, 2004 reserves related to an override which was retained by New Grey Wolf were estimated internally. Crude oil and natural gas reserves, and the estimates of the present value of future net revenues therefrom, were determined based on then current prices and costs. Reserve calculations involve the estimate of future net recoverable reserves of crude oil and natural gas and the timing and amount of future net revenues to be received there from. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain.

        The following table sets forth certain information regarding estimates of our crude oil, natural gas liquids and natural gas reserves as of January 1, 2002, January 1, 2003 and January 1, 2004:

		Estimated Proved Reserves
		Proved Developed	Proved Undeveloped	Total Proved
As of January 1, 2004
	Crude oil (MBbls)	2,051	1,578	3,629
	NGLs (MBbls)	263	242	505
	Natural gas (MMcf)	52,398	43,885	96,284
As of January 1, 2003(1)
	Crude oil (MBbls)	1,782	1,317	3,099
	NGLs (MBbls)	1,222	284	1,506
	Natural gas (MMcf)	90,374	48,458	138,832
As of January 1, 2002
	Crude oil (MBbls)	1,980	1,170	3,150
	NGLs (MBbls)	3,067	585	3,652
	Natural gas (MMcf)	111,243	77,514	188,757

(1)

Reserves as of January 1, 2003 include 67 MBbls of crude oil, 1,079 MBbls of NGLs, and 47,066 MMcf of natural gas that were sold in connection with the sale of Canadian Abraxas and Old Grey Wolf in January 2003. See "Business—Recent Events".

(2)

Reserves as of January 1, 2002 include 158 MBbls of crude oil, 2,257 MBbls of NGLs, and 80,289 MMcf of natural gas that were sold in connection with the sale of Canadian Abraxas and Old Grey Wolf in January 2003.

        The process of estimating crude oil and natural gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are imprecise.

        Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control.

        You should not assume that the present value of future net revenues referred to in this prospectus is the current market value of our estimated crude oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the end of the year of the estimate, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of our financial statements. Because we use the full cost method to account for our crude oil and natural gas operations, we are susceptible to significant non-cash charges during times of volatile commodity prices because the full

50

cost pool may be impaired when prices are low. At June 30, 2002, we incurred a ceiling test writedown of approximately $116.0 million. A ceiling test writedown does not impact cash flow from operating activities but does reduce our stockholders' equity and reported earnings. We cannot assure you that we will not experience additional ceiling limitation write-downs in the future. For more information regarding the full cost method of accounting, you should read the information under "Management's Discussion and Analysis of Financial Condition and Results of Operation—Critical Accounting Policies."

        Actual future prices and costs may be materially higher or lower than the prices and costs as of the end of the year of the estimate. Any changes in consumption by natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with us or the crude oil and natural gas industry in general will affect the accuracy of the 10% discount factor.

        The estimates of our reserves are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of crude oil and natural gas reserves, future net revenue from proved reserves and the PV-10 thereof for the crude oil and natural gas properties described in this prospectus are based on the assumption that future crude oil and natural gas prices remain the same as crude oil and natural gas prices at December 31, 2003. The average sales prices as of such date used for purposes of such estimates were $31.03 per Bbl of crude oil, $27.19 per Bbl of NGLs and $5.05 per Mcf of natural gas. It is also assumed that we will make future capital expenditures of approximately $50.4 million in the aggregate through, which are necessary to develop and realize the value of proved undeveloped reserves on our properties. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of reserves set forth herein.

        We file reports of our estimated crude oil and natural gas reserves with the Department of Energy and the Bureau of the Census. The reserves reported to these agencies are required to be reported on a gross operated basis and therefore are not comparable to the reserve data reported herein.

Crude Oil, Natural Gas Liquids, and Natural Gas Production and Sales Prices

        The following table presents our net crude oil, net natural gas liquids and net natural gas production, the average sales price per Bbl of crude oil and natural gas liquids and per Mcf of natural

51

gas produced and the average cost of production per BOE of production sold, for the three years ended December 31, 2003.

	2001(1)		2002(1)		2003(1)
Crude oil production (Bbls)		454,063		292,264		251,567
Natural gas production (Mcf)		17,495,598		15,452,721		6,189,359
Natural gas liquids production (Bbls)		277,969		242,032		37,258
MMcfe		21,888		18,658		7,922
Average sales price per Bbl of crude oil	$	24.63	$	24.34	$	30.32
Average sales price per Mcf of natural gas(2)	$	3.20	$	2.55	$	4.78
Average sales price per Bbl of natural gas liquids	$	21.51	$	17.94	$	24.47
Average sales price per Mcfe	$	3.35	$	2.72	$	4.81
Average cost of production per Mcfe produced(3)	$	0.85	$	0.82	$	1.21

(1)

Includes production for 2001, 2002 and the first 23 days of 2003 for Canadian properties sold in January 2003.

(2)

Average sales prices are net of hedging activity.

(3)

Crude oil and natural gas were combined by converting crude oil and natural gas liquids to a Mcf equivalent on the basis of 1 Bbl of crude oil and natural gas liquid equals 6 Mcf of natural gas. Production costs include direct operating costs, ad valorem taxes and gross production taxes.

Drilling Activities

        The following table sets forth our gross and net working interests in exploratory and development wells drilled during the three years ended December 31, 2003.

				2001		2002		2003
				Gross	Net	Gross	Net	Gross	Net
Exploratory
	Productive
		Crude oil		—	—	1.0	1.0	1.0	1.0
		Natural gas		2.0	1.0	3.0	0.5	—	—
		Dry holes		1.0	.5	3.0	1.5	1.0	0.5
			Total	3.0	1.5	7.0	3.0	2.0	1.5
Development
	Productive
		Crude oil		2.0	2.0	—	—	2.0	2.0
		Natural gas		13.0	11.0	14.0	11.8	20.0	8.3
		Dry holes		—	—	1.0	1.0	—	—
			Total	15.0	13.0	15.0	12.8	22.0	10.3

        As of July 27, 2004 we had one well in process of completing in Canada.

Competition

        We operate in a highly competitive environment. Competition is particularly intense with respect to the acquisition of desirable undeveloped crude oil and natural gas properties. The principal competitive factors in the acquisition of such undeveloped crude oil and natural gas properties include the staff and data necessary to identify, investigate and purchase such properties, and the financial resources necessary to acquire and develop such properties. We compete with major and independent crude oil

52

and natural gas companies for properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.

        The principal resources necessary for the exploration and production of crude oil and natural gas are leasehold prospects under which crude oil and natural gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of crude oil and natural gas operations. We must compete for such resources with both major crude oil and natural gas companies and independent operators. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations in the immediate future we cannot assure you that such materials and resources will be available to us.

        We face significant competition for obtaining additional natural gas supplies for gathering and processing operations, for marketing NGLs, residue gas, helium, condensate and sulfur, and for transporting natural gas and liquids. Our principal competitors include major integrated oil companies and their marketing affiliates and national and local gas gatherers, brokers, marketers and distributors of varying sizes, financial resources and experience. Certain competitors, such as major crude oil and natural gas companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.

        We compete against other companies in our natural gas processing business both for supplies of natural gas and for customers to which we sell our products. Competition for natural gas supplies is based primarily on location of natural gas gathering facilities and natural gas gathering plants, operating efficiency and reliability and ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price and delivery capabilities.

Regulation of Crude Oil and Natural Gas Activities

        The exploration, production and transportation of all types of hydrocarbons are subject to significant governmental regulations. Our operations are affected from time to time in varying degrees by political developments and federal, state, provincial and local laws and regulations. In particular, crude oil and natural gas production operations and economics are, or in the past have been, affected by industry specific price controls, taxes, conservation, safety, environmental, and other laws relating to the petroleum industry, by changes in such laws and by constantly changing administrative regulations.

Price Regulations

        In the past, maximum selling prices for certain categories of crude oil, natural gas, condensate and NGLs in the United States were subject to significant federal regulation. At the present time, however, all sales of our crude oil, natural gas, condensate and NGLs produced in the United States under private contracts may be sold at market prices. Congress could, however, reenact price controls in the future. If controls that limit prices to below market rates are instituted, our revenue would be adversely affected.

        Crude oil and natural gas exported from Canada is subject to regulation by the National Energy Board ("NEB") and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that export contracts in excess of two years must continue to meet certain criteria prescribed by the NEB and the government of Canada. Crude oil and natural gas exports for a term of less than two years must be made pursuant to an NEB order, or, in the case of exports for a longer duration, pursuant to an NEB license and Governor in Council approval.

        The provincial governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from these provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and marketing considerations.

53

The North American Free Trade Agreement

        On January 1, 1994, the North American Free Trade Agreement ("NAFTA") among the governments of the United States, Canada and Mexico became effective. In the context of energy resources, Canada remains free to determine whether exports to the U.S. or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of the energy resource (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.

        NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports. The Texas Railroad Commission has recently become the lead agency for Texas for coordinating permits governing Texas to Mexico cross border pipeline projects. The availability of selling natural gas into Mexico may substantially impact the interstate natural gas market on all producers in the coming years.

United States Natural Gas Regulation

        Historically, the natural gas industry as a whole has been more heavily regulated than the crude oil or other liquid hydrocarbons market. Most regulations focused on transportation practices. In the recent past interstate pipeline companies in the United States generally acted as wholesale merchants by purchasing natural gas from producers and reselling the natural gas to local distribution companies and large end users. Commencing in late 1985, the Federal Energy Regulatory Commission (the "FERC") issued a series of orders that have had a major impact on interstate natural gas pipeline operations, services, and rates, and thus have significantly altered the marketing and price of natural gas. The FERC's key rule making action, Order No. 636 ("Order 636"), issued in April 1992, required each interstate pipeline to, among other things, "unbundle" its traditional bundled sales services and create and make available on an open and nondiscriminatory basis numerous constituent services (such as gathering services, storage services, firm and interruptible transportation services, and standby sales and natural gas balancing services), and to adopt a new ratemaking methodology to determine appropriate rates for those services. To the extent the pipeline company or its sales affiliate markets natural gas as a merchant, it does so pursuant to private contracts in direct competition with all of the sellers, such as us; however, pipeline companies and their affiliates were not required to remain "merchants" of natural gas, and most of the interstate pipeline companies have become "transporters only," although many have affiliated marketers. Order 636 and related FERC orders have resulted in increased competition within all phases of the natural gas industry. We do not believe that Order 636 and the related restructuring proceedings affect us any differently than other natural gas producers and marketers with which we compete.

        Transportation pipeline availability and cost are major factors affecting the production and sale of natural gas. Our physical sales of natural gas are affected by the actual availability, terms and cost of pipeline transportation. The price and terms for access onto the pipeline transportation systems remain subject to extensive Federal regulation. Although Order 636 does not directly regulate our production and marketing activities, it does affect how buyers and sellers gain access to and use of the necessary transportation facilities and how we and our competitors sell natural gas in the marketplace. The courts have largely affirmed the significant features of Order No. 636 and the numerous related orders pertaining to individual pipelines, although some appeals remain pending and the FERC continues to review and modify its regulations regarding the transportation of natural gas. For example, the FERC has recently begun a broad review of its natural gas transportation regulations, including how its

54

regulations operate in conjunction with state proposals for natural gas marketing restructuring and in the increasingly competitive marketplace for all post-wellhead services related to natural gas.

        In recent years the FERC also has pursued a number of other important policy initiatives which could significantly affect the marketing of natural gas in the United States. Some of the more notable of these regulatory initiatives include:

(1)

a series of orders in individual pipeline proceedings articulating a policy of generally approving the voluntary divestiture of interstate pipeline owned gathering facilities by interstate pipelines to their affiliates (the so-called "spin down" of previously regulated gathering facilities to the pipeline's nonregulated affiliates).



(2)

Order No. 497 involving the regulation of pipelines with marketing affiliates.



(3)

various FERC orders adopting rules proposed by the Gas Industry Standards Board which are designed to further standardize pipeline transportation tariffs and business practices.



(4)

a notice of proposed rulemaking that, among other things, proposes (a) to eliminate the cost-based price cap currently imposed on natural gas transactions of less than one year in duration, (b) to establish mandatory "transparent" capacity auctions of short-term capacity on a daily basis, and (c) to permit interstate pipelines to negotiate terms and conditions of service with individual customers.



(5)

issuance of Policy Statements regarding Alternate Rates and Negotiated Terms and Conditions of Service covering (a) the pricing of long-term pipeline transportation services by alternative rate mechanism options, including the pricing of interstate pipeline capacity utilizing market-based rates, incentive rates, or indexed rates, and (b) investigating of whether FERC should permit pipelines to negotiate the terms and conditions of service, in addition to rates of service.



(6)

a notice of proposed rulemaking that proposes generic procedures to expedite the FERC's handling of complaints against interstate pipelines with the goals of encouraging and supporting consensual resolutions of complaints and organizing the complaint procedures so that all complaints are handled in a timely and fair manner.

        Several of these initiatives are intended to enhance competition in natural gas markets, although some, such as "spin downs," may have the adverse effect of increasing the cost of doing business on some in the industry, including us, as a result of the geographic monopolization of those facilities by their new, unregulated owners. As to all of these FERC initiatives, the ongoing, or, in some instances, preliminary and evolving nature of these regulatory initiatives makes it impossible at this time to predict their ultimate impact on our business. However, we do not believe that these FERC initiatives will affect us any differently than other natural gas producers and marketers with which we compete.

        Since Order 636, FERC decisions involving onshore facilities have been more liberal in their reliance upon traditional tests for determining what facilities are "gathering" and therefore exempt from federal regulatory control. In many instances, what was once classified as "transmission" may now be classified as "gathering." We ship certain of our natural gas through gathering facilities owned by others, including interstate pipelines, under existing long term contractual arrangements. Although these FERC decisions have created the potential for increasing the cost of shipping our natural gas on third party gathering facilities, our shipping activities have not been materially affected by these decisions.

        In summary, all of the FERC activities related to the transportation of natural gas have resulted in improved opportunities to market our physical production to a variety of buyers and market places, while at the same time increasing access to pipeline transportation and delivery services. Additional proposals and proceedings that might affect the natural gas industry in the United States are

55

considered from time to time by Congress, the FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their effect, if any, on our operations. The crude oil and natural gas industry historically has been very heavily regulated; thus there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future.

State and Other Regulation

        All of the jurisdictions in which we own producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions requiring permits for the drilling of wells and maintaining bonding requirements in order to drill or operate wells and provisions relating to the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units on an acreage basis and the density of wells which may be drilled and the unitization or pooling of crude oil and natural gas properties. In this regard, some states and provinces allow the forced pooling or integration of tracts to facilitate exploration while other states and provinces rely on voluntary pooling of lands and leases. In addition, state and provincial conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. Some states, such as Texas and Oklahoma, have, in recent years, reviewed and substantially revised methods previously used to make monthly determinations of allowable rates of production from fields and individual wells. The effect of all of these conservation regulations is to limit the speed, timing and amounts of crude oil and natural gas we can produce from our wells, and to limit the number of wells or the location at which we can drill.

        State and provincial regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take requirements, but does not generally entail rate regulation. In the United States, natural gas gathering has received greater regulatory scrutiny at both the state and federal levels in the wake of the interstate pipeline restructuring under Order 636. For example, the Texas Railroad Commission enacted a Natural Gas Transportation Standards and Code of Conduct to provide regulatory support for the State's more active review of rates, services and practices associated with the gathering and transportation of natural gas by an entity that provides such services to others for a fee, in order to prohibit such entities from unduly discriminating in favor of their affiliates.

        For those operations on U.S. Federal or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies. In addition, in the United States, the Minerals Management Service ("MMS") has recently issued a final rule to clarify or severely limit the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, MMS will not allow deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the MMS has been engaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculating royalties owed to the government. The crude oil and natural gas industry as a whole has resisted the proposed rules under an assumption that royalty burdens will substantially increase. We cannot predict what, if any, effect any new rule will have on our operations.

56

Canadian Royalty Matters

        In addition to Canadian federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed preference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced.

        From time to time the governments of Alberta and British Columbia, the provinces where almost all of New Grey Wolf's production is located, have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging crude oil and natural gas exploration or enhanced planning projects. All of New Grey Wolf's production is from oil and gas rights which have been granted by the Provinces.

        The Province of Alberta requires the payment from lessees of oil and gas rights of annual rental payments as well as royalty payments. Regulations made pursuant to the Mines and Minerals Act (Alberta) provide various incentives for exploring and developing crude oil reserves in Alberta. Crude oil produced from horizontal extensions commenced at least five years after the well was originally spudded may qualify for a royalty reduction. An 8,000 cubic meters exemption is available to production from a well that has not produced for a 12-month period prior to January 31, 1993 or 24 months following such date. In addition, crude oil production from eligible new field and new pool wildcat wells and deeper pool test wells spudded or deepened after September 30, 1992, is entitled to a 12-month royalty exemption (to a maximum of CDN $1 million). Crude oil produced from low productivity wells, enhanced recovery schemes (such as injection wells) and experimental projects is also subject to royalty reductions.

        The Alberta government classifies conventional crude oil into three categories, being Old Oil, New Oil and Third Tier Oil. Each have a base royalty rate of 10%. The rate caps on the categories are 25% for oil from crude oil pools discovered after September 30, 1992, being the Third Tier Oil, 30% for oil from pools or pool extensions discovered after April 1, 1974, from wells drilled or deepened after October 31, 1991 or from reactivated wells and which are not Third Tier Oil, and 35% for Old Oil.

        Effective January 1, 1994, the calculation and payment of natural gas royalties became subject to a simplified process. The royalty reserved to the Crown, subject to various incentives, is between 15% or 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying exploratory gas wells spudded or deepened after July 1, 1985 and before June 1, 1988 are eligible for a royalty exemption for a period of 12 months, or such later time that the value of the exempted royalty quantity equals a prescribed maximum amount. Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the well.

        In Alberta, a producer of crude oil or natural gas is entitled to credit against the royalties payable to the Crown by virtue of the Alberta Royalty Tax Credit ("ARTC") program. The ARTC program is based on a price-sensitive formula, and the ARTC rate currently varies between 75% for prices for crude oil at or below CDN $100 per cubic meter and 35% for prices above CDN $210 per cubic meter. The ARTC rate is currently applied to a maximum of CDN $2.0 million of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on average "par price", as determined by the Alberta Department of Energy for the previous quarterly period.

57

        Producers of crude oil and natural gas in British Columbia are also required to pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of crude oil and natural gas produced from Crown and freehold lands respectively. British Columbia also classifies conventional crude oil into the three categories of Old Oil, New Oil and Third Tier Oil. The amount payable as a royalty in respect of crude oil depends on the vintage of the crude oil (whether it was produced from a pool discovered before or after October 31, 1975) or a pool in which no well was completed on June 1, 1998), the quantity of crude oil produced in a month and the value of the crude oil. Crude oil produced from a discovery well may be exempt from the payment of a royalty for the first 36 months of production to a maximum production of 11,450 m3. The royalty payable on natural gas is determined by a sliding scale based on a classification of the gas based on whether it is conservation gas (gas associated with marketed oil production) and by drilling and land lease date and on a reference price which is the greater of the amount obtained by the producer and at prescribed minimum price. Conservation gas has a minimum royalty of 8%. The royalty rate ranges from between 9% and 27% for wells drilled on lands issued after May 31, 1998 and before January 1, 2003 and completed within 5 years of the date the lands were issued and between 12% and 27% for wells spudded after May 31, 1998 on lands where rights had been issued as of May 31, 1998.

Environmental Matters

        Our operations are subject to numerous federal, state, provincial and local laws and regulations controlling the generation, use, storage, and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences; restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling, production, and natural gas processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, and other protected areas; require remedial measures to mitigate pollution from historical and on-going operations such as use of pits and plugging of abandoned wells; restrict injection of liquids into subsurface strata that may contaminate groundwater; and impose substantial liabilities for pollution resulting from our operations. Environmental permits required for our operations may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines, and even criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on us as well as the crude oil and natural gas industry in general, and thus we are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations.

        In the United States, the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as "Superfund," and comparable state statutes impose strict, joint, and several liability on certain classes of persons who are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that generated, disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA such persons or companies may be retroactively liable for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is common for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize imposition of substantial civil and criminal penalties for failing to prevent surface and subsurface pollution, as well as to control the

58

generation, transportation, treatment, storage and disposal of hazardous waste generated by crude oil and natural gas operations. Although CERCLA currently contains a "petroleum exclusion" from the definition of "hazardous substance," state laws affecting our operations impose cleanup liability relating to petroleum and petroleum related products, including crude oil cleanups. In addition, although RCRA regulations currently classify certain oilfield wastes which are uniquely associated with field operations as "non-hazardous," such exploration, development and production wastes could be reclassified by regulation as hazardous wastes thereby administratively making such wastes subject to more stringent handling and disposal requirements.

        We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of crude oil and natural gas. Although we utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Our operations are also impacted by regulations governing the disposal of naturally occurring radioactive materials ("NORM"). We must comply with the Clean Air Act and comparable state statutes which prohibit the emissions of air contaminants, although a majority of our activities are exempted under a standard exemption. Moreover, owners, lessees and operators of crude oil and natural gas properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are usually causes of action based on negligence, trespass, nuisance, strict liability and fraud.

        United States federal regulations also require certain owners and operators of facilities that store or otherwise handle crude oil, such as us, to prepare and implement spill prevention, control and countermeasure plans and spill response plans relating to possible discharge of crude oil into surface waters. The federal Oil Pollution Act ("OPA") contains numerous requirements relating to prevention of, reporting of, and response to crude oil spills into waters of the United States. For facilities that may affect state waters, OPA requires an operator to demonstrate $10 million in financial responsibility. State laws mandate crude oil cleanup programs with respect to contaminated soil.

        Our Canadian operations are also subject to environmental regulation pursuant to local, provincial and federal legislation which generally require operations to be conducted in a safe and environmentally responsible manner. Canadian environmental legislation provides for restrictions and prohibitions relating to the discharge of air, soil and water pollutants and other substances produced in association with certain crude oil and natural gas industry operations, and environmental protection requirements, including certain conditions of approval and laws relating to storage, handling, transportation and disposal of materials or substances which may have an adverse effect on the environment. Environmental legislation can affect the location of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines or issuance of clean-up orders.

        Certain federal environmental laws that may affect us include the Canadian Environmental Assessment Act which ensures that the environmental effects of projects receive careful consideration prior to licenses or permits being issued, to ensure that projects that are to be carried out in Canada or on federal lands do not cause significant adverse environmental effects outside the jurisdictions in which they are carried out, and to ensure that there is an opportunity for public participation in the environmental assessment process; the Canadian Environmental Protection Act ("CEPA") which is the most comprehensive federal environmental statute in Canada, and which controls toxic substances

59

(broadly defined), includes standards relating to the discharge of air, soil and water pollutants, provides for broad enforcement powers and remedies and imposes significant penalties for violations; the National Energy Board Act which can impose certain environmental protection conditions on approvals issued under the Act; the Fisheries Act which prohibits the depositing of a deleterious substance of any type in water frequented by fish or in any place under any condition where such deleterious substance may enter any such water and provides for significant penalties; the Navigable Waters Protection Act which requires any work which is built in, on, over, under, through or across any navigable water to be approved by the Minister of Transportation, and which attracts severe penalties and remedies for non-compliance, including removal of the work.

        In Alberta, environmental compliance has been governed by the Alberta Environmental Protection and Enhancement Act ("AEPEA") since September 1, 1993. In addition to consolidating a variety of environmental statutes, the AEPEA also imposes certain new environmental responsibilities on crude oil and natural gas operators in Alberta. The AEPEA sets out environmental standards and compliance for releases, clean-up and reporting. The Act provides for a broad range of liabilities, enforcement actions and penalties.

        We are not currently involved in any administrative, judicial or legal proceedings arising under domestic or foreign federal, state, or local environmental protection laws and regulations, or under federal or state common law, which would have a material adverse effect on our financial position or results of operations. Moreover, we maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area.

        We believe that we have obtained and are in compliance with all material environmental permits, authorizations and approvals.

Title to Properties

        As is customary in the crude oil and natural gas industry, we make only a cursory review of title to undeveloped crude oil and natural gas leases at the time we acquire them. However, before drilling commences, we require a thorough title search to be conducted, and any material defects in title are remedied prior to the time actual drilling of a well begins. To the extent title opinions or other investigations reflect title defects, we, rather than the seller of the undeveloped property, are typically obligated to cure any title defect at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We believe that we have good title to our crude oil and natural gas properties, some of which are subject to immaterial encumbrances, easements and restrictions. The crude oil and natural gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or use of our properties.

Employees

        As of March 31, 2004, we had 46 full-time employees in the United States, including 3 executive officers, 3 non-executive officers, 1 petroleum engineer, 1 geologist, 6 managers, 1 landman, 12 secretarial and clerical personnel and 21 field personnel. Additionally, we retain contract pumpers on a month-to-month basis. We retain independent geological and engineering consultants from time to time on a limited basis and expect to continue to do so in the future.

        As of March 31, 2004, New Grey Wolf had 11 full-time employees, including 3 executive officers, 1 non-executive officers, 2 petroleum engineers, 2 geologists, 1 geophysicist and, 4 technical and clerical personnel.

60

Office Facilities

        Our executive and administrative offices are located at 500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232. We also have an office in Midland, Texas. These offices, consisting of approximately 12,650 square feet in San Antonio and 570 square feet in Midland, are leased until March 2006 at an aggregate base rate of $19,500 per month.

        New Grey Wolf leases 17,522 square feet of office space in Calgary, Alberta pursuant to a lease, which expires in April, 2008.

Other Properties

        We own 10 acres of land, an office building, workshop, warehouse and house in Sinton, Texas, 2.8 acres of land, an office building and 600 acres of fee land in Scurry County, Texas and 160 acres of land in Coke County, Texas. All three properties are used for the storage of tubulars and production equipment. We also own 19 vehicles which are used in the field by employees. We own 2 workover rigs, which are used for servicing our wells.

Litigation

        In 2001, Abraxas and Abraxas Wamsutter L.P. were named as defendants in a lawsuit filed in U.S. District Court in the District of Wyoming. The claim asserts breach of contract, fraud and negligent misrepresentation by Abraxas and Abraxas Wamsutter, L.P. related to the responsibility for year 2000 ad valorem taxes on crude oil and natural gas properties sold by Abraxas and Abraxas Wamsutter, L.P. In February 2002, a summary judgment was granted to the plaintiff in this matter and a final judgment in the amount of $1.3 million was entered. Abraxas has filed an appeal. We believe these charges are without merit. We have established a reserve in the amount of $845,000, which represents our estimated share of the judgment.

        Additionally, from time to time, we are involved in litigation relating to claims arising out of operations in the normal course of business. At December 31, 2002, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our operations.

Enforceability of Civil Liabilities Against Foreign Persons

        New Grey Wolf is an Alberta corporation, certain of its officers and directors may be residents of various jurisdictions outside the United States and its Canadian counsel, Osler, Hoskin & Harcourt, LLP, are residents of Canada. All or a substantial portion of the assets of New Grey Wolf and of such persons may be located outside the United States. As a result, it may be difficult for investors to effect service of process within the United States upon such persons or to enforce judgments obtained against such persons in United States courts and predicated upon the civil liability provisions of the Securities Act. Notwithstanding the foregoing, New Grey Wolf has irrevocably agreed that it may be served with process with respect to actions based on offers and sales of securities made hereby in the United States by serving Chris E. Williford, c/o Abraxas Petroleum Corporation, 500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232, New Grey Wolf's United States agent appointed for that purpose. New Grey Wolf has been advised by its Canadian counsel, Osler, Hoskin & Harcourt, LLP, that there is doubt as to the enforceability in Canada against New Grey Wolf Abraxas or against any of its directors, controlling persons, officers or experts who are not residents of the United States, in original actions for enforcement of judgments of United States courts, of liabilities predicated solely upon United States federal securities laws.

61

MANAGEMENT

Directors and Executive Officers

        Set forth below are the names, ages, years of service and positions of the executive officers and directors of Abraxas, as well as certain executive officers of New Grey Wolf. The term of the Class I director of Abraxas expires in 2006, the term of the Class II directors expires in 2005 and the term of the Class III directors expires in 2004 (other than Mr. Phelps, whose term expires in 2006).

Name and Municipality of Residence	Age	Office	Class
Robert L. G. Watson, San Antonio, Texas	53	Chairman of the Board, President and Chief Executive Officer	III
Chris E. Williford, San Antonio, Texas	52	Executive Vice President, Chief Financial Officer and Treasurer	—
Robert W. Carington, Jr., San Antonio, Texas	42	Executive Vice President	—
Craig S. Bartlett, Jr., Montclair, New Jersey	70	Director	II
Franklin A. Burke, Doyleston, Pennsylvania	70	Director	I
Harold D. Carter, Dallas, Texas	65	Director	III
Ralph F. Cox, Ft. Worth, Texas	71	Director	II
Barry J. Galt, Houston, Texas	70	Director	III
Dennis E. Logue Norman, Oklahoma	60	Director	II
James C. Phelps, San Antonio, Texas	81	Director	III
Joseph A. Wagda, Danville, California	60	Director	II

Robert L. G. Watson has served as Chairman of the Board, President, Chief Executive Officer and a director of Abraxas since 1977. From May 1996 to January 2003, Mr. Watson also served as Chairman of the Board and a director of Old Grey Wolf. Since January 2003, he has served as Chairman of the Board and a director of New Grey Wolf. In November 1996, Mr. Watson was elected Chairman of the Board, President and as a director of Canadian Abraxas, a former wholly owned Canadian subsidiary of Abraxas. Prior to joining Abraxas, Mr. Watson was employed in various petroleum engineering positions with Tesoro Petroleum Corporation, a crude oil and natural gas exploration and production company, from 1972 through 1977, and DeGolyer and MacNaughton, an independent petroleum engineering firm, from 1970 to 1972. Mr. Watson received a Bachelor of Science degree in Mechanical Engineering from Southern Methodist University in 1972 and a Master of Business Administration degree from the University of Texas at San Antonio in 1974.

Chris E. Williford was elected Vice President, Treasurer and Chief Financial Officer of Abraxas in January 1993, and as Executive Vice President and a director of Abraxas in May 1993. In November 1996, Mr. Williford was elected Vice President and Assistant Secretary of Canadian Abraxas. In December 1999, Mr. Williford resigned as a director of Abraxas. Prior to joining Abraxas, Mr. Williford was Chief Financial Officer of American Natural Energy Corporation, a crude oil and natural gas exploration and production company, from July 1989 to December 1992 and President of Clark Resources Corp., a crude oil and natural gas exploration and production company, from

62

January 1987 to May 1989. Mr. Williford received a Bachelor of Science degree in Business Administration from Pittsburgh State University in 1973.

        Robert W. Carington, Jr.    was elected Executive Vice President and a director of Abraxas in July 1998. In December 1999, Mr. Carington resigned as a director of Abraxas. Prior to joining Abraxas, Mr. Carington was a Managing Director with Jefferies & Company, Inc. Prior to joining Jefferies & Company, Inc. in January 1993, Mr. Carington was a Vice President at Howard, Weil, Labouisse, Friedrichs, Inc. Prior to joining Howard, Weil, Labouisse, Friedrichs, Inc., Mr. Carington was a petroleum engineer with Unocal Corporation from 1983 to 1990. Mr. Carington received a Bachelor of Science in Mechanical Engineering from Rice University in 1983 and a Masters of Business Administration from the University of Houston in 1990.

Craig S. Bartlett Jr., a director of Abraxas since December 1999, has over forty years of commercial banking experience, the most recent being with National Westminster Bank USA, rising to the position of Executive Vice President, Senior Lending Officer and Chairman of the Credit Policy Committee. Mr. Bartlett currently serves on the boards of NVR, Inc. and Janus Hotels and Resorts, Inc. and is active in securities arbitration. Mr. Bartlett attended Princeton University, and has a certificate in Advanced Management from Pennsylvania State University.

Franklin A. Burke, a director of Abraxas since June 1992, has served as President and Treasurer of Venture Securities Corporation since 1971, where he is in charge of research and portfolio management. He has also been a general partner and director of Burke, Lawton, Brewer & Burke, a securities brokerage firm, since 1964, where he is responsible for research and portfolio management. Mr. Burke also serves as a director of Suburban Community Bank in Chalfont, Pennsylvania. Mr. Burke received a Bachelor of Science degree in Finance from Kansas State University in 1955, a Master's degree in Finance from University of Colorado in 1960 and studied at the graduate level at the London School of Economics from 1962 to 1963.

Harold D. Carter has served as a director of Abraxas since October 2003. Mr. Carter has more than 30 years experience in the oil and gas industry and has been an independent consultant since 1990. Prior to consulting, Mr. Carter served as Executive Vice President of Pacific Enterprises Oil Company (USA). Before that, Mr. Carter was associated for 20 years with Sabine Corporation, ultimately serving as President and Chief Operating Officer from 1986 to 1989. Mr. Carter consults for Endowment Advisors, Inc. with respect to its EEP Partnerships and Associated Energy Managers, Inc. with respect to its Energy Income Fund, L.P. and is a director of Brigham Exploration Company, a publicly traded oil and gas company, and Energy Partners, Ltd., and Longview Production Company, both private companies. Mr. Carter was a director of Abraxas from 1996 to 1999 and served as an advisory director from 1999 to September 2003.

Ralph F. Cox, a director of Abraxas since December 1999, has over 45 years of oil and gas industry experience, over thirty of which was with Arco. Mr. Cox retired from Arco in 1985 after having become Vice Chairman. Mr. Cox then joined what was known as Union Pacific Resources prior to its acquisition by Anadarko Petroleum in July 2000, retiring in 1989 as President and Chief Operating Officer. Mr. Cox then joined Greenhill Petroleum Corporation as President until leaving in 1994 to pursue his consulting business. Mr. Cox has in the past and continues to serve on many boards including CH2M Hill Companies, and is a trustee for the Fidelity group of funds. Mr. Cox earned Petroleum and Mechanical Engineering degrees from Texas A&M University with advanced studies at Emory University.

Barry J. Galt, a director of Abraxas since October 2003, has served as a director of Ocean Energy, Inc. since his retirement in 1999 until the acquisition of Ocean by Devon Energy Corporation in April 2003. He served as Chairman and Chief Executive Officer of Seagull Energy Corporation, the predecessor to Ocean, from 1983 through 1998 and as Vice Chairman of Seagull from January 1999 until May 1999. Prior to his employment by Seagull, Mr. Galt acted as President and Chief Operating

63

Officer of The Williams Companies. Mr. Galt has also served as a director of Trinity Industries, Inc. since 1989, a director of StanCorp Financial Group, Inc. since 1989 and a director of Dynegy Inc. since September 2002.

Dennis E. Logue, a director of Abraxas since April 2003, is Dean and Fred E. Brown Chair at the Michael F. Price College of business at the University of Oklahoma. Prior to joining Price College in 2001, he was the Steven Roth Professor at the Amos Tuck School at Dartmouth Collage where he had been since 1974. He is currently a director of Sallie Mae (GSE) and Waddell & Reed Financial, Inc. He is also on the editorial boards of several scholarly journals, including the Journal of Banking and Finance, the Journal of Portfolio Management, and the Journal of Management Strategy Education. Mr. Logue holds degrees from Fordham College, Rutgers, and Cornell University.

James C. Phelps, a director of Abraxas since December 1983, has been a consultant to crude oil and natural gas exploration and production companies such as Panhandle Producing Company and Tesoro Petroleum Corporation since April 1981. Mr. Phelps served as a director of Old Grey Wolf from January 1996 to January 2003. From April 1995 to May 1996, Mr. Phelps served as Chairman of the Board and Chief Executive Officer of Old Grey Wolf, and from January 1996 to May 1996, he served as President of Old Grey Wolf. From March 1983 to September 1984, he served as President of Osborn Heirs Company, a privately owned crude oil exploration and production company based in San Antonio. Mr. Phelps was President and Chief Operating Officer of Tesoro Petroleum Corporation from 1971 to 1981 and prior to that was Senior Vice President and Assistant to the President of Continental Oil Company. He received a Bachelor of Science degree in Industrial Engineering and a Master of Science degree in Industrial Engineering from Oklahoma State University.

Joseph A. Wagda, a director of Abraxas since December 1999, has been involved in a variety of business activities over a twenty-nine year career. From 2000 to the present, Mr. Wagda has been Chief Executive Officer and a director of BrightStar Information Technology Group, Inc., an information technology company, and was named Chairman in 2001. He also is an attorney and president of Altamont Capital Management, Inc., where he was involved from 1997 to 2001 in a number of investment projects as an investor and consultant, including leadership roles as a member of Campus in 1999 to 2000 and as a managing member of AltaNet Partners, LLC from 2000. Previously, Mr. Wagda was President and Chief Executive Officer of American Heritage Group, Inc., a modular home builder, and a Senior Managing Director and co-founder of the Price Waterhouse corporate finance practice. He also served with the finance staff of Chevron Corporation and in the general counsel's office at Ford Motor Company. Mr. Wagda received an undergraduate degree from Fordham College, a Masters of Business Administration, with distinction, from the Johnson Graduate School of Management, Cornell University, and a JD, with honors, from Rutgers University.

64

EXECUTIVE COMPENSATION

Compensation Summary

        The following table sets forth a summary of compensation for the fiscal years ended December 31, 2001, 2002 and 2003 paid by Abraxas to Robert L.G. Watson, Abraxas' Chairman of the Board, President and Chief Executive Officer, Chris E. Williford, Abraxas' Executive Vice President, Chief Financial Officer and Treasurer, Robert W. Carington, Jr., Abraxas' Executive Vice President, Lee T. Billingsley, Abraxas' Vice President—Exploration, and to William H. Wallace, Abraxas' Vice President—Operations.

Summary Compensation Table

							Long Term Compensation Awards—Securities Underlying Options (#)
	Annual Compensation
Name and Principal Position
	Year	Salary ($)		Bonus ($)
Robert L. G. Watson, Chairman of the Board, President and Chief Executive Officer	2001 2002 2003	$ $ $	259,615 271,442 291,750	$ $ $	27,388 24,592 200,200	(1)	60,000 90,000 0
Chris E. Williford, Executive Vice President, Chief Financial Officer and Treasurer	2001 2002 2003	$ $ $	155,769 163,653 175,615	$ $ $	16,433 14,848 120,400	(2)	20,000 43,000 0
Robert W. Carington, Jr., Executive Vice President	2001 2002 2003	$ $ $	207,629 215,577 225,961	$ $ $	21,910 19,488 154,000	(3)	20,000 55,000 0
Lee T. Billingsley Vice President—Exploration	2001 2002 2003	$ $ $	134,077 156,885 168,346	$ $ $	10,331 9,792 42,023	(4)	15,000 22,000 0
William H. Wallace, Vice President—Operations	2001 2002 2003	$ $ $	131,577 156,885 168,346	$ $ $	10,331 9,792 42,023	(4)	15,000 22,000 0

(1)

Of this amount, $177,719 will be paid in cash and $22,481 in restricted stock.*

(2)

Of this amount, $101,051 will be paid in cash and $19,349 in restricted stock.*

(3)

Of this amount, $121,211 will be paid in cash and $32,789 in restricted stock.*

(4)

Of this amount, $32,123 will be paid in cash and $9,900 in restricted stock.*

*

The number of shares of stock was determined based upon a price of $2.69 per share, which was the closing price of the Company's common stock on the AMEX on April 15, 2004.

Grants of Stock Options and Stock Appreciation Rights During the Fiscal Year Ended December 31,2003

        Pursuant to the Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan (the "ISO Plan"), the Abraxas Petroleum Corporation 1993 Key Contributor Stock Option Plan (the "1993 Plan"), and the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan (the "LTIP"), Abraxas grants to its employees and officers (including its directors who are also employees) incentive stock options and non-qualified stock options. The ISO Plan, the 1993 Plan, and the LTIP are administered

65

by the Compensation Committee which, based upon the recommendation of the Chief Executive Officer, determines the number of shares subject to each option.

OPTION GRANTS IN FISCAL YEAR

        No options were granted to Messers. Watson, Williford, Carington and Wallace and Dr. Billingsley during 2003.

Aggregated Option Exercises in Fiscal 2003 and Fiscal Year End Option Values

        The table below contains certain information concerning exercises of stock options during the fiscal year ended December 31, 2003, by Messrs. Watson, Williford, Carington and Wallace and Dr. Billingsley and the fiscal year end value of unexercised options held by Messrs. Watson, Williford, Carington and Wallace and Dr. Billingsley.

OPTION EXERCISES IN FISCAL YEAR

Name	Shares Acquired By Exercise (#)	Value Realized ($)	Number of Unexercised Options on December 31, 2003 (#) Exercisable/Unexercisable(1)	Value of Unexercised Options on December 31, 2003 ($) Exercisable/Unexercisable
Robert L. G. Watson	2,019	0	592,167/134,358	337,535/76,584
Chris E. Williford	20,000	0	185,750/52,250	105,878/29,783
Robert W. Carington, Jr.	0	0	373,750/61,250	213,038/34,913
Lee T. Billingsley	0	0	101,000/39,000	57,570/22,230
William H. Wallace	0	0	63,500/39,000	36,195/22,230

Employment Agreements

        Abraxas has entered into employment agreements with each of Messrs. Watson, Williford, Carington and Wallace and with Dr. Billingsley pursuant to which each of Messrs. Watson, Williford, Carington and Wallace and Dr. Billingsley will receive compensation as determined from time to time by the board in its sole discretion.

        The employment agreements for Messrs. Watson, Williford, and Carington are scheduled to terminate on December 21, 2004, and shall be automatically extended for additional one-year terms unless Abraxas gives the officer 120 days notice prior to the expiration of the original term or any extension thereof of its intention not to renew the employment agreement. If, during the term of the employment agreements for each of such officers, the officer's employment is terminated by Abraxas other than for cause or disability, by the officer other than by reason of such officer's death or retirement, or by the officer, for "good reason" (as defined in each officer's respective employment agreement), then such officer will be entitled to receive a lump sum payment equal to the greater of (a) his annual base salary for the last full year during which he was employed by Abraxas or (b) his annual base salary for the remainder of the term of each of their respective employment agreements.

        If a change of control occurs during the term of the employment agreement for Mr. Watson, Mr. Williford or Mr. Carington, and if subsequent to such change of control, such officer's employment is terminated by Abraxas other than for cause or disability, by reason of the officer's death or

66

retirement or by such officer, for good reason, then such officer will be entitled to the following, as applicable:

Mr. Watson:

(1)

if such termination occurs prior to the end of the first year of the initial term of his employment agreement, a lump sum payment equal to five times his annual base salary;



(2)

if such termination occurs after the end of the first year of the initial term of his employment agreement but prior to the end of the second year of the initial term of his employment agreement, a lump sum payment equal to four times his annual base salary;



(3)

if such termination occurs after the end of the second year of the initial term of his employment agreement but prior to the end of the third year of the initial term of his employment agreement, a lump sum payment equal to three times his annual base salary; and



(4)

if such termination occurs after the end of the third year of the initial term of his employment agreement a lump sum payment equal to 2.99 times his annual base salary.

Mr. Williford or Mr. Carington:

(1)

if such termination occurs prior to the end of the first year of the initial term of the officer's employment agreement, a lump sum payment equal to four times the officer's annual base salary;



(2)

if such termination occurs after the end of the first year of the initial term of the officer's employment agreement but prior to the end of the second year of the initial term of the employment agreement, a lump sum payment equal to three times the officer's annual base salary; and



(3)

if such termination occurs after the end of the second year of the initial term of the officer's employment agreement, a lump sum payment equal to 2.99 times the officer's annual base salary.

        Abraxas has entered into employment agreements with Mr. Wallace and Dr. Billingsley pursuant to which each of Mr. Wallace and Dr. Billingsley will receive compensation as determined from time to time by the board in its sole discretion. The employment agreements, originally scheduled to terminate on December 31, 1998 for Dr. Billingsley and December 31, 2000 for Mr. Wallace, were automatically extended and will terminate on December 31, 2004, and may be automatically extended for an additional year if by December 1 of the prior year neither Abraxas nor Mr. Wallace or Dr. Billingsley, as the case may be, has given notice to the contrary. Except in the event of a change in control, at all times during the term of the employment agreements, each of Mr. Wallace's and Dr. Billingsley's employment is at will and may be terminated by Abraxas for any reason without notice or cause. If a change in control occurs during the term of the employment agreement or any extension thereof, the expiration date of Mr. Wallace's and Dr. Billingsley's employment agreement is automatically extended to a date no earlier than three years following the effective date of such change in control. If, following a change in control, either Mr. Wallace's or Dr. Billingsley's employment is terminated other than for Cause (as defined in each of the employment agreements) or Disability (as defined in each of the Employment Agreements), by reason of Mr. Wallace's or Dr. Billingsley's death or retirement or by Mr. Wallace or Dr. Billingsley, as the case may be, for Good Reason (as defined in each of the employment agreements), then the terminated officer will be entitled to receive a lump sum payment equal to three times his annual base salary.

67

        If any lump sum payment to Messrs. Watson, Williford, Carington, Wallace or Dr. Billingsley would individually or together with any other amounts paid or payable constitute an "excess parachute payment" within the meaning of Section 280G of the Internal Revenue Code of 1986, as amended, and applicable regulations there under, the amounts to be paid will be increased so that Messrs. Watson, Williford, Carington, Wallace or Dr. Billingsley, as the case may be, will be entitled to receive the amount of compensation provided in his contract after payment of the tax imposed by Section 280G.

Compensation of Directors

        Stock Options.    In 1999, each of Messrs. Bartlett, Cox and Wagda were each granted options to purchase 75,000 shares of common stock at an exercise price of $0.98 per share. In April 2003, Mr. Burke was granted options to purchase 45,000 shares of common stock at an exercise price of $0.68 and Mr. Phelps was granted options to purchase 43,000 shares at an exercise price of $0.68. In September 2003, Mr. Carter was granted options to purchase 45,000 shares of common stock and Mr. Galt was granted options to purchase 75,000 shares of common stock each at an exercise price of $1.01.

        Other Compensation.    During 2003, each director who was not an employee of Abraxas or its affiliates, received an annual fee of $8,000 plus $1,000 for each board meeting attended and $500 for each committee meeting attended. Aggregate fees paid to directors in 2003 were $149,400. Except for the foregoing, the directors of Abraxas received no other compensation for services as directors, except for reimbursement of travel expenses to attend board meetings.

CERTAIN TRANSACTIONS

        Wind River Resources Corporation ("Wind River"), all of the capital stock of which is owned by Mr. Watson, previously owned a twin-engine airplane. The airplane was available for business use by employees of Abraxas from time to time at Wind River's cost. Abraxas paid Wind River a total of $345,000 for use of the plane during 2002. In July 2003, the airplane was sold to a third party. In connection with the sale, Abraxas acquired Wind River from Mr. Watson in consideration of the issuance of 106,977 shares of Abraxas common stock and the payment of $35,000. Wind River was subsequently dissolved.

68

PRINCIPAL STOCKHOLDERS

        Based upon information received from the persons concerned, each person known to Abraxas to be the beneficial owner of more than five percent of the outstanding shares of common stock of Abraxas, each director and nominee for director, each of the named executive officers and all directors and officers of Abraxas as a group, owned beneficially as of March 31, 2004, the number and percentage of outstanding shares of common stock of Abraxas indicated in the following table:

Name and Address of Beneficial Owner	Number of Shares(1)		Percentage (%)
Peter S. Lynch 82 Devonshire St. 58A Boston, MA 02109	3,335,440		9.24
Venture Securities Corp. 516 N. Bethlehem Pike Spring House, PA 19477	2,423,724	(2)	6.71
Robert L. G. Watson	1,127,099	(3)	3.07
Franklin A. Burke	1,717,970	(4)	4.75
James C. Phelps	543,999	(5)	1.51
Chris E. Williford	220,005	(6)	*
Lee T. Billingsley	174,925	(7)	*
Robert W. Carington, Jr.	477,090	(8)	1.31
William H. Wallace	75,986	(9)	*
C. Scott Bartlett, Jr.	87,000	(10)	*
Ralph F. Cox	335,000	(10)	*
Harold D. Carter	48,098	(4)
Joseph A. Wagda	75,000	(10)	*
All Officers and Directors as a Group (11 persons)(3)(4)(5)(6)(7)(8)(9)(10)	4,887,172		13.45

*

Less than 1%

(1)

Unless otherwise indicated, all shares are held directly with sole voting and investment power.

(2)

Includes 1,244,204 shares with sole voting power held by Venture Securities and Franklin A. Burke, a director of Abraxas, the sole owner of Venture Securities, and 1,179,520 shares managed by Venture Securities on behalf of third parties.

(3)

Includes 55,642 shares issuable upon exercise of options granted pursuant to Abraxas Petroleum Corporation 1993 Key Contributor Stock Option Plan, 551,525 shares issuable upon exercise of options granted pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan and 300 shares in a retirement account. Does not include a total of 75,880 shares owned by the Robert L. G. Watson, Jr. Trust and the Carey B. Watson Trust, the trustees of which are Mr. Watson's brothers and the beneficiaries of which are Mr. Watson's children. Mr. Watson disclaims beneficial ownership of the shares owned by these trusts.

(4)

Includes 30,000 shares issuable upon exercise of options granted pursuant to the Amended and Restated Director Stock Option Plan (the "Director Option Plan").

(5)

Includes 340,000 shares owned by Marie Phelps, Mr. Phelps' wife, 88,762 shares owned by JMRR LP, 2,000 shares issuable upon exercise of options granted pursuant to an option agreement and 25,750 shares issuable upon exercise of options granted pursuant to the Director Option Plan.

69

(6)

Includes 190,750 shares issuable upon exercise of options granted pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan.

(7)

Includes 104,750 shares issuable upon exercise of options granted pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan and 5,000 shares in a retirement account..

(8)

Includes 378,750 shares issuable upon exercise of options granted pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan.

(9)

Includes 67,250 shares issuable upon exercise of options granted pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan.

(10)

Includes 75,000 shares issuable upon exercise of certain option agreements.

70

SELLING SECURITY HOLDERS

        The notes and shares of common stock are being offered by the selling security holders listed in the table below or referred to in a prospectus supplement. The shares of common stock and $109,523,000 principal amount of notes being offered were issued in connection with an overall financial restructuring through a private exchange offer exempt from, or not subject to, the registration requirements of the Securities Act. Since the restructuring, additional notes being offered hereunder were issued to selling security holders in lieu of cash interest payments. The remaining 950,000 shares of common stock represent shares underlying outstanding warrants. The selling security holders may offer and sell, from time to time, any or all of their common stock or notes, including any notes issued in lieu of cash interest payments.

        No offer or sale under this prospectus may be made by a holder of the securities unless that holder is listed in the table in this prospectus or until that holder has notified us and a supplement to this prospectus has been filed or an amendment to the related registration statement has become effective. We will supplement or amend this prospectus to include additional selling security holders upon request and upon provision of all required information to us.

        The following table sets forth, as of July 27, 2004 (unless subsequent information has been provided to us in writing from the selling security holders), the name, principal amount of notes, and number of shares received in the exchange offer by the selling security holders eligible to sell the notes or common stock. Based on information provided to us by the selling security holders, the table also discloses whether any selling security holder selling in connection with the prospectus or prospectus supplement has held any position or office with, been employed by, or otherwise has had a material relationship with us or any of our affiliates during the three years prior to the date of the prospectus or prospectus supplement. The selling security holders may sell under this prospectus up to the number of shares and the principal amount of notes indicated below, in addition to any notes issued to the selling security holders in lieu of cash interest payments.

Name	Principal Amount of Notes that may be sold hereby ($)	Number of shares of common stock that may be sold hereby	Material Relationship
ABN Amro Inc	2,890,000	148,605	None
Ahab International Ltd	244,000	12,544	None
Ahab Partners LP	366,000	18,816	None
Basil Street Company	0	750,000	None
BBH Broad Market Fixed Fund	268,000	13,798	None
BBH High Yield Fixed Income Fund	835,000	42,963	None
Cathy A. Wichert Trustee	60,000	3,136	None
Cebron Family Trust	27,000	1,411	None
Charles Schwab & Co. Inc	21,000	1,097	None
Concordian Partners	1,830,000	94,080	None
Claire E. Fox	89,000	0	None
Credit Suisse First Boston	11,586,000	595,651	None
Craig Kaplan Irrevocable Trust David A Kaplan & Samuel Kaplan TR UA	6,000	0	None
David H. Vahlsing IRA #2 FCC as Custodian	3,000	0	None
David Hilty	55,000	2,871	None
David Stein IRA Bear Stearns Fee. Corp Cust	4,000	219	None
Dean Witter Reynolds	30,000	1,568	None
Deborah Z. Corson Family Trust	15,000	784	None

71

Delaware Charter Guar & Trust TTEE FBO Eileen P. May	7,000		376		None
Delaware Charter Guar & Trust TTEE Rhonda J. Keefer IRA	3,000		0		None
Deutsche Bank Securities	305,000		15,680		None
Doris M. Clarke IRA FCC as Custodian	7,000		0		None
Embassy & Co	1,387,000		71,344		None
EV Emerald US High Yield Fund	771,000		39,670		None
First Clearing Corp.	2,888,000		170,635			(1)
Fishingboat & Co	305,000		15,680		None
Frank Parmet & Nancy M. Parmet JTWROS	3,000		0		None
Franklin A. Burke TR UA Marion J Hill-Kelly Trust	25,000		0		None
George G. Steele III IRA FCC as Custodian	3,000		0		None
Goldman Sachs	1,169,000		60,117		None
Gryphon Hidden Values L.P.		(2)	26,335		None
Gryphon Hidden Values Ltd.		(2)	186,599		None
Gryphon Hidden Values 2000		(2)	324,507		None
Halcyon Fund, L.P. and related funds		(3)		(3)	None
Hare & Co	15,304,000		786,885		None
Harriett L. Manning	6,000		313		None
Harry John Cornbleet	15,000		784		None
Houlihan Lokey Howard Zukin Capital Inc.	523,000		26,938		None
Hugo Ciccotosto IRA FCC as Custodian	6,000		0		None
Ingalls & Snyder LLC	27,599,870		994,122		None
Irenc S. Zorensky Family Trust	15,000		784		None
Irwin Gold	156,000		8,022		None
Jacqueline Heffernen IRA FCC as Custodian	3,000		0		None
Jane Baker Macpherson Trustee Carington 2503 (C) Childrens	40,000		2,068			(4)
Janet A. Lawton IRA FCC as Custodian	6,000		0		None
Jeff Werbalowsky	156,000		8,022		None
Jesup & Lamont Holdings, TNC, Inc. and Charles K. Butler	0		200,000		None
JMB Capital Partners LP	3,050,000		156,800		None
JoAnne Tauber IRA FCC as Custodian	3,000		0		None
John L. and Dorothy F. Greenly Jr. JT Ten	6,000		0		None
John S. Ingrilli And Janc Ann Ingrilli Jt Wros	12,000		627		None
Joseph R. and Nancy C. Hafner, Jr. JT Ten	3,000		0		None
Joseph Manning Jr	9,000		470		None
Joseph O. Supper IRA FCC as Custodian	15,000		0		None
JP Morgan	1,067,000		54,880		None
Karl L. and Betty J. Henning JT Ten	5,000		0		None
Lami Trading Company	3,050,000		156,800		None
Linda Harrington IRA FCC as Custodian	6,000		0		None
Lonestar Partners LP	1,662,000		85,456		None
Margaret G. Nuttycombe IRA FCC as Custodian	3,000		0		None
Mark Grasmeder SEP IRA FCC as Custodian	3,000		0		None
Martin H. Orliner Trustee,	30,000		1,568		None

72

Mary E Edwards	30,000	1,568	None
Maryjo Simjian Garre Trustee	15,000	784	None
Merrill Lynch Professional CC	23,954,000	1,232,038	None
Merrill Lynch, Pierce, Fenner & Smith Incorporated	2,154,000	110,855	None
Merrill Lynch, Pierce, Fenner & Smith Incorporated	101,000	0	None
Milton L. Zorensky Insurance Trust #1	12,000	627	None
Morgan Stanley & Co. Inc	2,962,000	152,715	None
Morgan Stanley D W Inc	3,000	156	None
Mr. Harold D. Carter IRA	21,000	1,097	None
Mulberry Ltd	410,000	21,109	None
Murphy & Durien	5,000	344	None
Nancy S. Nettelbladt IRA FCC as Custodian	6,000	0	None
Ned K. Ryder & Ann K. Ryder, Trustees	42,000	2,195	None
NFS/FMTC IRA FBO Herbert L Eisen	15,000	784	None
NFS/FMTC IRA FBO R. Scott Williams	61,000	3,136	None
NFS/FMTC IRA FBO Samuel Garre III	15,000	784	None
Nicholas W. Iadicicco IRA FCC as Custodian	3,000	0	None
Patricia J. Silver	6,000	0	None
Peter Tyler IRA R/O FCC as Custodian	3,000	0	None
Philip Lebovitz Marilyn Lebovitz	15,000	784	None
Raymond Albert Wagner	6,000	0	None
Recap International (BVI) Ltd	796,000	40,972	None
Recap Partners LP	396,000	20,394	None
Regiment Capital Ltd	1,958,000	100,665	None
Robert W. and Joyce M. Clarke, Jr. JT Ten	8,000	0	None
Robert A. Iadicicco IRA FCC Custodian	6,000	0	None
Roger H. Nettelbladt IRA FCC as Custodian	3,000	0	None
Rosemary Jung	15,000	784	None
Salomon Smith Barney	15,702,000	807,360	None
Saltship & Co	115,000	5,958	None
Sis Segainterse TT LE AG	152,000	7,840	None
South Lake & Co	1,342,000	68,992	None
Spindrift Investors (Bermuda), LP	405,000	20,854	None
Spindrift Partners, LP	406,000	20,885	None
Stanley H. Shatz Geraloine A. Shatz	30,000	1,568	None
Sterneck Value & Opportunity LP	97,000	5,017	None
Venezuela Recovery FD NY	610,000	31,360	None
Vibration Specialty Corp.	4,000	0	None
Zurich Institutional Benchmark	240,000	12,387	None

(1)

Notes in the principal amount of $2,557,000 and 131,680 shares of common stock beneficially owned by Franklin A. Burke, a current director of Abraxas, are held of record by First Clearing Corporation.

(2)

Notes in the aggregate principal amount of $6,165,000 beneficially owned by Gryphon Hidden Values, L.P., Gryphon Hidden Values, Ltd. and Gryphon Hidden Values 2000 are held of record by Salomon Smith Barney on their behalf.

73

(3)

Notes in the aggregate principal amount of up to $27,457,000 and an aggregate number of 861,053 shares of common stock beneficially owned by Halcyon Fund, L.P. and related funds (collectively, "Halcyon") are held of record by Merrill Lynch Professional CC and Morgan Stanley & Co. Inc on Halcyon's behalf.

(4)

Securities are held in trust on behalf of the children of Robert A. Carington, Executive Vice President of Abraxas. Mr. Carington has disclaimed beneficial ownership of these securities.

        We prepared this table based on the information supplied to us by the selling security holders named in the table, and we have not sought to verify such information.

        The selling security holders listed in the above table may have sold or transferred, in transactions exempt from the registration requirements of the Securities Act, some or all of their notes or shares of common stock since the date on which the information in the above table was provided to us. Information about selling security holders may change over time.

        Because the selling security holders may offer all or some of their notes or shares of common stock from time to time, we cannot estimate the amount of notes or the number of shares of common stock that will be held by the selling security holders upon the termination of any particular offering by such selling security holder. Please refer to "Plan of Distribution" beginning on page 75 of this prospectus.

74

PLAN OF DISTRIBUTION

        This prospectus covers the resale of the notes and the shares of Abraxas common stock by the selling security holders and their donees, pledgees, transferees or other successors in interest. The selling security holders may sell their notes and shares of Abraxas common stock under this prospectus:

•

through one or more broker-dealers acting as either principal or agent;



•

through underwriters;



•

directly to investors; or



•

any combination of these methods.

        The selling security holders will fix a price or prices, and may change the price, of the notes and shares of Abraxas common stock offered based upon:

•

market prices prevailing at the time of sale;



•

prices related to those market prices; or



•

negotiated prices.

        These sales may be effected in one or more of the following transactions (which may involve crosses and block transactions):

•

on any securities exchange or U.S. inter-dealer system of a registered national securities association on which the common stock may be listed or quoted at the time of sale;



•

in the over-the-counter market;



•

in private transactions;



•

through the writing of options, whether the options are listed on an option exchange or otherwise; or



•

through the settlement of short sales.

        Broker-dealers, underwriters or agents may receive compensation in the form of discounts or concessions from the selling security holders or the purchasers. These discounts, concessions or commissions may be more than those customary for the transaction involved. If any broker-dealer purchases the notes or shares of common stock as principal, it may affect resales of the shares through other broker-dealers, and other broker-dealers may receive compensation from the purchasers for whom they act as agents.

        To comply with the securities laws of some states, if applicable, the securities may be sold in these jurisdictions only through registered or licensed brokers or dealers. In addition, in some states the securities may not be sold unless they have been registered or qualified for sale or an exemption from registration or qualification requirements is available and is complied with.

        The selling security holders and any underwriters, broker-dealers or agents that participate in the sale of the securities may be "underwriters" within the meaning of the Securities Act. Any discounts, commissions, concessions or profit they earn on any resale of the shares may be underwriting discounts and commissions under the Securities Act. Any selling security holders who are "underwriters" within the meaning of the Securities Act will be subject to the prospectus delivery requirements of the Securities Act.

        Any securities covered by this prospectus which qualify for sale under Rule 144 or Rule 144A of the Securities Act may be sold under Rule 144 or Rule 144A rather than under this prospectus. The

75

selling security holders may not sell any securities described in this prospectus and may not transfer, devise or gift these securities by other means not described in this prospectus.

        To the extent required, the specific securities to be sold, the names of the selling security holders, the respective purchase prices and public offering prices, the names of any agent, dealer or underwriter, and any applicable commissions or discounts with respect to a particular offer will be set forth in an accompanying prospectus supplement or, if appropriate, a post-effective amendment to the registration statement of which this prospectus is a part.

        Under Abraxas' registration rights agreement with the selling security holders, we have agreed to indemnify the selling security holders and each underwriter, if any, against certain liabilities, including certain liabilities under the Securities Act, or will contribute to payments the selling security holders or underwriters may be required to make in respect of those liabilities.

        We have agreed to pay substantially all of the expenses in connection with the registration, offering and sale of the securities covered by this prospectus, other than commissions, fees and discounts of underwriters, brokers, dealers and agents.

        We have agreed to keep the registration statement, of which this prospectus is a part, effective for two years from the time this registration statement becomes effective, subject to extension for any suspension or blackout periods during which securities covered by this prospectus can not be sold.

76

DESCRIPTION OF THE NOTES

        Abraxas issued an aggregate principal amount of $109,706,000 of notes on January 23, 2003 under an indenture entered into on that date among Abraxas, the subsidiary guarantors and U.S. Bank, N.A., as trustee. The indenture is governed by certain provisions contained in the Trust Indenture Act of 1939, as amended. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act.

        The indenture provides for original issuance of up to $118,250,000 of notes, plus such additional principal amounts as may be necessary for the issuance of additional notes in lieu of cash interest payments. The indenture also provides for issuance of registered exchange notes to be issued only in exchange for a like principal amount of outstanding notes issued on January 23, 2003 and any additional notes issued in lieu of cash interest payments on such outstanding notes. The term "notes" as used herein refers to all of the currently outstanding notes, the exchange notes, any additional notes issued in lieu of cash interest payments and any notes issued pursuant to the CEO Note Options (as defined below), all of which are deemed to be a single class of securities under the indenture for purposes of any waiver, consent or amendment.

        The following description is a summary of the material provisions of the notes, the indenture, the documents providing for the security interests of the holders of the notes and an intercreditor and subordination agreement to which the notes are subject. It does not restate those agreements in their entirety. You can find definitions of certain terms used in this description under the subheading "Certain Definitions" beginning on page 107 of this prospectus.

Brief Description of the Notes and the Guarantees

The Notes

        The notes:

•

provide that the Issuer will make current payments of interest in cash to the extent not prohibited by the terms of the Senior Credit Agreement or the Intercreditor Agreement;



•

provide for interest not paid in cash to be paid in the form of additional notes;



•

are general obligations of the Issuer;



•

are secured by a second Lien on all of the current and future Oil and Gas Assets of the Issuer and its Subsidiaries, and substantially all other current and future assets of the Issuer and its Subsidiaries;



•

are subordinate to Indebtedness of Issuer under the Senior Credit Agreement and Qualified Senior Affiliate Indebtedness (as described under the section below entitled "Certain Definitions"), and rank equally with all of the Issuer's other current and future senior Indebtedness, if any;



•

rank senior to all of the Issuer's current and future Subordinated Indebtedness, if any; and



•

are unconditionally guaranteed by the Subsidiary Guarantors.

The Guarantees

        The notes are jointly and severally guaranteed (the "Guarantees") by all current and future Subsidiaries of the Issuer, including (but not limited to) the following:

•

Sandia;



•

Wamsutter;

77

•

Sandia Operating;



•

Eastside Coal;



•

Western Associated; and



•

New Grey Wolf.

        The Guarantees of the notes are:

•

general obligations of each current and future Subsidiary Guarantor;



•

senior in right of payment to all existing and future Subordinated Indebtedness, if any, of each Subsidiary Guarantor;



•

subordinate to Indebtedness of each Subsidiary Guarantor under the Senior Credit Agreement and Qualified Senior Affiliate Indebtedness (as described under the section below entitled "Certain Definitions"), and rank equally with all other existing and future senior Indebtedness of each Subsidiary Guarantor, if any;



•

secured by a second lien on all of the current and future Oil and Gas Assets of each Subsidiary Guarantor, and on substantially all other current and future assets of each Subsidiary Guarantor; and



•

limited for each Subsidiary Guarantor to the maximum amount which will result in each Guarantee not being a fraudulent conveyance or fraudulent transfer.

        Each Subsidiary Guarantor that makes a payment or distribution under its Guarantee will be entitled to a contribution from each other Subsidiary Guarantor in a prorata amount based on the net assets of each Subsidiary Guarantor.

        Each Subsidiary Guarantor may consolidate with or merge into or sell its assets to the Issuer or another Subsidiary Guarantor that is a Wholly Owned Subsidiary without limitation, or with or to other Persons upon the terms and conditions set forth in the indenture. See the description of the covenant in "Merger, Consolidation and Sale of Assets" below. In the event all of the Capital Stock of a Subsidiary Guarantor is sold by the Issuer and/or one or more of its Subsidiaries and the sale complies with the provisions set forth in "Limitation on Asset Sales," such Subsidiary Guarantor's Guarantee and any related Collateral owned by such Subsidiary Guarantor will be released.

Principal, Maturity and Interest

        The indenture provides for original issuance of up to $118,250,000 of notes, plus such additional principal amounts as may be necessary for the issuance of additional notes in lieu of cash interest payments. The notes will be issued in full registered form only, without coupons. The notes will mature on May 1, 2007. The indenture also provides for issuance of exchange notes.

        Interest on the notes accrues at the rate of 11.5% per annum and, to the extent not prohibited by the terms of the Senior Credit Agreement or the Intercreditor Agreement, is payable in cash semi-annually on each May 1 and November 1, commencing on May 1, 2003, to the Persons who are registered holders at the close of business on the April 15 and October 15 immediately preceding the applicable interest payment date. If the payment of such interest in cash is prohibited by the terms of the Senior Credit Agreement or the Intercreditor Agreement, that interest will be paid in the form of notes (the "PIK notes") in a principal amount equal to the amount of accrued and unpaid interest on the notes plus an additional 1% per annum accrued interest for the applicable period, on each May 1 and November 1, commencing on May 1, 2003, to the Persons who are registered holders at the close of business on the April 15 and October 15 immediately preceding the applicable interest payment date.

78

        Additional interest is payable on the notes, pursuant to a registration rights agreement, under the circumstances described in "Registration Rights; Liquidated Damages." All references to interest in this description include such additional interest, unless the context otherwise requires.

        Upon and during the continuation of an Event of Default, interest on the notes will accrue at the rate of 16.5% per annum, unless the terms of the registration rights agreement apply and provide for a higher rate of interest. See "Registration Rights; Liquidated Damages" for a summary of the registration rights agreement.

        Unpaid interest shall be due and payable at stated maturity or, to the extent the notes are earlier redeemed or repurchased, on the date of such early redemption or repurchase. Interest due and payable at the maturity of the notes shall be paid to the Persons to whom principal is paid. Interest shall accrue and be payable both before and after the filing of any bankruptcy petition at the rates stated above.

        Interest on the notes has been accruing from and including the issue date of the notes. Interest is computed on the basis of a 360-day year comprised of twelve 30-day months.

Paying Agent and Registrar; Transfer and Exchange

        Initially, the Trustee is acting as registrar for the notes and as paying agent. The notes may be presented for registration of transfer and exchange at the office of the registrar, which currently is the Trustee's corporate trust office at 180 East Fifth Street, Saint Paul, Minnesota 55101. The Issuer will pay principal (and premium, if any) and interest on the notes upon surrender of the notes at the office of the paying agent in the Borough of Manhattan in the City of New York, State of New York. The Issuer may change the paying agent, registrar, and the agent for service of demands and notices in connection with the notes and the guarantees without notice to the holders of the notes.

Redemption

Optional Redemption

        The Issuer may redeem the notes, at its option, in whole at any time or in part from time to time, at redemption prices expressed as percentages of the principal amount set forth below. If the Issuer redeems all or any notes, the Issuer must also pay all interest accrued and unpaid to the applicable redemption date. The redemption prices for the notes during the indicated time periods are as follows:

Period	Percentage
From January 24, 2003 to June 23, 2003	80.0429	%
From June 24, 2003 to January 23, 2004	91.4592	%
From January 24, 2004 to June 23, 2004	97.1674	%
From June 24, 2004 to January 23, 2005	98.5837	%
Thereafter	100.0000	%

        Notwithstanding the foregoing, the redemption price for notes to be redeemed will in no event be less than the then current Adjusted Issued Price.

        If the Issuer redeems less than all of the notes, selection of notes for redemption will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which the notes are listed or, if the notes are not then listed on a national securities exchange, on a pro rata basis, by lot or by such other method as the Trustee deems fair and appropriate. The Issuer will not redeem in part notes in principal amounts of less than $1,000. Except as provided above, the Issuer will mail notice of redemption at least 30 and not more than 60 days before the redemption date. The notice will describe the amount of notes being redeemed, if less than the entire principal amount. Interest will cease to accrue on notes which are redeemed on the redemption date.

79

Security

        All of the Obligations of the Issuer under the notes and the indenture and the Guarantees are secured by a second priority Lien, but subject to certain Permitted Liens, on all of the current and future Oil and Gas Assets of the Issuer and its Subsidiaries, and substantially all other current and future assets of the Issuer and the Subsidiary Guarantors (other than assets securing Acquired Indebtedness to the extent granting additional Liens would be prohibited by the terms of the instruments relating to such Acquired Indebtedness). The Oil and Gas Assets included in the assets that initially secure such Obligations represent approximately 100% of the PV-10 value at June 30, 2002 attributable to Oil and Gas Assets that remain Property of the Issuer and its Subsidiaries after the sale of stock described under the discussion above entitled "Business—Recent Developments—Financial Restructuring—Sale of Stock of Canadian Abraxas and Old Grey Wolf."

        If the notes become due and payable prior to maturity or are not paid in full at maturity, the Trustee may take all actions it deems necessary or appropriate, including, but not limited to, foreclosing upon the Collateral in accordance with the security documents and applicable law. The right to foreclose on the Collateral is, however, subject to certain limitations for the benefit of the Senior Credit Facility Lenders described below under the discussion entitled "Intercreditor Agreement." Subject to the rights of the Senior Credit Facility Lenders and the holder of any Qualified Senior Affiliate Indebtedness, the proceeds received from the sale of any Collateral that is the subject of a foreclosure or collection suit will be applied first to pay the expenses of such foreclosure or suit and amounts then payable to the Trustee, then to pay the principal of and interest on the notes. Subject to the rights of the Senior Credit Facility Lenders, the Trustee has the power to institute and maintain such suits and proceedings as it may deem expedient to prevent impairment of, or to preserve or protect its and the holders' interest in, the Collateral.

        We cannot assure you that the Trustee will be able to sell the Collateral without substantial delays or compromises in addition to delays resulting from limitations on the right to foreclose on the Collateral described below under the discussion entitled "Intercreditor Agreement," or that the proceeds obtained will be sufficient to pay all amounts owing to holders of the notes or. You should read the discussion under the heading "Risk Factors—Risks Related to the Offering—The security for the notes may be inadequate to satisfy all amounts due and owing to the holders of our notes" for a further discussion regarding the adequacy of the collateral securing the notes. Third parties that have Permitted Liens (including, without limitation, the Senior Credit Facility Lenders) may have rights and remedies with respect to the property subject to such Liens that, if exercised, could adversely affect the value of the Collateral. In addition, the ability of the holders to realize upon the Collateral may be subject to certain bankruptcy law limitations in the event of a bankruptcy. You should read the discussion under the heading "Risk Factors" for more information regarding these bankruptcy law limitations.

        The collateral release provisions of the indenture permit the release of Collateral without substitution of collateral of equal value under certain circumstances. See "Possession, Use and Release of Collateral." As described under the summary of the covenant "Limitation on Asset Sales," the Net Cash Proceeds of Asset Sales will be required to be utilized to Pay Down Debt.

Change of Control

        If a Change of Control occurs, each holder will have the right to require that the Issuer purchase all or a portion of such holder's notes pursuant to the offer described below (the "Change of Control Offer"), at a purchase price equal to the percentage of the principal amount thereof then applicable to optional redemptions by the Issuer, plus all accrued and unpaid interest to the date of purchase.

        The Issuer must mail a notice of any Change of Control to each holder and the Trustee no later than 30 days after the Change of Control occurs. The notice will state, among other things, the

80

purchase date, which must be no earlier than 30 days nor later than 45 days from the date such notice is mailed, other than as may be required by law (the "Change of Control Payment Date"). A Change of Control Offer must remain open for a period of 20 Business Days or such longer period as may be required by law. Holders electing to have a note purchased pursuant to a Change of Control Offer will be required to surrender the note, with the form entitled "Option of Holder to Elect Purchase" on the reverse of the note completed, to the paying agent for the notes at the address specified in the notice prior to the close of business on the third Business Day prior to the Change of Control Payment Date.

        The Issuer will not be required to make a Change of Control Offer if a third party makes the Change of Control Offer at the Change of Control purchase price, at the same times and otherwise in compliance with the requirements applicable to a Change of Control Offer made by the Issuer and purchases the notes validly tendered and not withdrawn under such Change of Control Offer.

        If a Change of Control Offer is made, there can be no assurance that the Issuer will have available funds sufficient to pay the Change of Control purchase price for all the notes that might be delivered by holders seeking to accept the Change of Control Offer. In addition, the Senior Credit Agreement may have similar change of control provisions as the indenture, which may further restrict the ability of the Issuer to purchase the notes. Also, the terms of the Intercreditor Agreement will limit the Issuer's ability to make a Change of Control Offer under certain circumstances. See the discussion below entitled "Intercreditor Agreement." In the event the Issuer is required to purchase notes pursuant to a Change of Control Offer, the Issuer expects that it would seek third party financing to the extent it does not have available funds to meet its purchase obligations. However, there can be no assurance that the Issuer would be able to obtain such financing.

        Neither the Board of Directors of the Issuer nor the Trustee may waive the covenant relating to the Issuer's obligation to make a Change of Control Offer. Restrictions in the indenture described in this Description of the notes on the ability of the Issuer and its Subsidiaries to incur additional Indebtedness, to grant liens on their property, to make Restricted Payments and to make Asset Sales may also make more difficult or discourage a takeover of the Issuer, whether favored or opposed by the management of the Issuer. Consummation of any such transaction in certain circumstances may require repurchase of the notes, and there can be no assurance that the Issuer or the acquiring party will have sufficient financial resources to effect such repurchase. Such restrictions and the restrictions on transactions with Affiliates may, in certain circumstances, make more difficult or discourage any leveraged buyout of the Issuer by the management of the Issuer. While such restrictions cover a wide variety of arrangements which have traditionally been used to effect highly leveraged transactions, the indenture may not afford the holders of notes protection in all circumstances from the adverse aspects of a highly leveraged transaction, reorganization, restructuring, merger or similar transaction.

        The Issuer will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with the repurchase of notes pursuant to a Change of Control Offer. These rules require that the Issuer keep the offer open for 20 Business Days. They also require that the Issuer notify holders of notes of changes in the offer and extend the offer for specified time periods if the Issuer amends the offer. If the provisions of any securities laws or regulations conflict with the "Change of Control" provisions in the indenture, the Issuer will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the "Change of Control" provisions of the indenture.

Intercreditor Agreement

        The notes are subject to an intercreditor and subordination agreement. In general, the Junior Indebtedness will be subordinated to the Senior Indebtedness. The liens securing the Junior Indebtedness will also be subordinated to the liens securing the Senior Indebtedness. The following

81

description is a summary of the material provisions of the intercreditor and subordination agreement. It does not restate that agreement in its entirety. The description is qualified in its entirety by the terms of the intercreditor and subordination agreement.

        The intercreditor and subordination agreement has the following material terms:

•

Upon a payment default under the Senior Credit Agreement, the holders of the notes will not be entitled to be paid until all Senior Indebtedness is paid in full in cash.



•

Upon a default (other than a payment default) under the Senior Credit Agreement, for a period of 180 days commencing upon receipt by the Trustee of written notice of such non-payment default (each a "Payment Blockage Period"), the holders of the notes will not be entitled to be paid. There will be at least 180 consecutive days during which no Payment Blockage Period is in effect during any period of 365 consecutive days.



•

Upon any acceleration of the Junior Indebtedness or any payment or distribution of assets of the Issuer or any of its Subsidiaries following a bankruptcy or insolvency proceeding, all amounts due or to become due upon the Senior Indebtedness shall be first paid in full in cash before any payment is made on account of any of the Junior Indebtedness. Following the commencement of a bankruptcy or insolvency proceeding, any payment or distribution of assets of the Issuer or any of its Subsidiaries to which the holders of the notes would be entitled (excluding securities that are subordinated to the Senior Indebtedness to the same extent as, or more deeply than, the Junior Indebtedness is subordinated to the Senior Indebtedness pursuant to the intercreditor and subordination agreement), will be paid by the Issuer or its Subsidiaries, or by the holders of the notes or the Trustee if received by them or it, directly to the Senior Credit Facility Lenders until the Senior Indebtedness is paid in full in cash.



•

During a bankruptcy or insolvency proceeding, (a) the Senior Credit Facility Lenders will be permitted to file claims and proofs of claims in respect of the Junior Indebtedness if there shall remain not more than 30 days before such action is barred, prohibited or otherwise cannot be taken and (b) the holders of the notes and the Trustee will use commercially reasonable best efforts to take such actions as the Senior Credit Facility Lenders may reasonably request (at the Senior Credit Facility Lenders' expense) to collect the Junior Indebtedness for the account of the Senior Credit Facility Lenders and file claims or proof of claims with respect thereto, to execute such documents or instruments to enable the Senior Credit Facility Lenders to enforce any and all claims and the liens and security interests securing payment of the Junior Indebtedness and to collect and receive for the account of the Senior Credit Facility Lenders any and all payments or distributions which may be payable or deliverable upon or with respect to the Junior Indebtedness.



•

Any payment or other distribution of assets of the Issuer or any of its Subsidiaries received by the holders of the notes or the Trustee prior to the payment in full of the Senior Indebtedness will be held by the holders of the notes or the Trustee, as the case may be, in trust and paid over to the Senior Credit Facility Lenders.



•

As between the Senior Credit Facility Lenders and the holders of the notes, the liens and security interests of the Senior Credit Facility Lenders securing the Senior Indebtedness will be a first priority lien on and security interest in all of the property and assets on the Issuer and its Subsidiaries (the "Collateral") and the liens and security interests of the holders of the notes securing the Junior Indebtedness will be a second priority lien on and security interest in the Collateral. Neither the holders of the notes nor the Trustee will challenge or contest the validity, legality, perfection, priority, availability or enforceability of the security interests and liens of the Senior Credit Facility Lenders upon the Collateral or seek to have the same avoided, disallowed, set aside, or otherwise invalidated in any judicial proceeding or otherwise.

82

•

Until the payment in full in cash of the Senior Indebtedness, the Senior Credit Facility Lenders shall have the exclusive right to exercise and enforce all privileges and rights to the Collateral and to manage the disposition of the Collateral and neither the holders of the notes nor the Trustee will exercise any Secured Creditor Remedies or commence a bankruptcy, insolvency or other proceeding against the Issuer or any of its Subsidiaries; provided, however, that, upon the occurrence and during an event of default with respect to the Junior Indebtedness, commencing 180 days after receipt by the Senior Credit Facility Lenders of written notice of such default and intention to exercise remedies, the holders of the notes or the Trustee may commence a bankruptcy, insolvency or other proceeding against the Issuer or any of its Subsidiaries or exercise any Secured Creditor Remedies unless, in the case of any exercise of Secured Creditor Remedies, only so long as the Senior Credit Facility Lenders are not diligently pursuing in good faith the exercise of their Secured Creditor Remedies, or attempting to vacate any stay of enforcement of their liens on a material portion of the Collateral. The holders of the notes and the Trustee will waive any and all rights to affect the method or challenge the appropriateness of any action by the Senior Credit Facility Lenders with respect to the Collateral. Upon an event of default with respect to the Senior Indebtedness, the holders of the notes and the Trustee will, immediately upon the request of the Senior Credit Facility Lenders, release or otherwise terminate their liens and security interests upon the Collateral, to permit the Senior Credit Facility Lenders or the Issuer or its Subsidiaries (with the consent of the Senior Credit Facility Lenders) to sell or otherwise dispose of the Collateral to the extent the proceeds of such sale or other disposition is used to repay in full and in cash the Senior Indebtedness. If such sale or other disposition of the Collateral by the Senior Credit Facility Lenders or the Issuer or its Subsidiaries (with the consent of the Senior Credit Facility Lenders) result in a surplus after the payment in full of the Senior Indebtedness, such surplus will be paid to the holders of the notes or the Trustee.



•

The intercreditor and subordination agreement will remain applicable if the Issuer or any of its Subsidiaries is subject to a bankruptcy or insolvency proceeding.



•

If, during a bankruptcy or insolvency proceeding of the Issuer or any of its Subsidiaries, the Senior Credit Facility Lenders decide to permit the use of cash collateral or provide post-petition financing to the Issuer or any of its Subsidiaries, the holders of the notes and the Trustee will not object to the use of such cash collateral or post-petition financing by the Senior Credit Facility Lenders (or their agent), provided that (i) the holders of the notes or the Trustee are granted the same liens and security interests on the post-petition Collateral that may be granted to or for the benefit of the Senior Credit Facility Lenders (or their agent), junior only to the liens and security interests of the Senior Credit Facility Lenders (or their agent) and (ii) the aggregate principal amount of pre-petition secured indebtedness together with the aggregate principal amount of financing in such bankruptcy or insolvency proceeding will not exceed, at the time of determination, the sum of (a) $50 million less the aggregate amount applied from time to time to repay the principal amount of the Senior Indebtedness which is accompanied by a corresponding permanent reduction of the Revolver Commitment under the Senior Credit Agreement plus (b) (x) $15 million, if the then applicable Revolver Commitment under the Senior Credit Agreement is $25 million or greater, (y) $10 million, if the then applicable Revolver Commitment under the Senior Credit Agreement is less than $25 million and greater than or equal to $15 million or (z) $5 million, if the then applicable Revolver Commitment under the Senior Credit Agreement is less than $15 million (the sum of the immediately preceding clauses (a) and (b), the "Maximum Senior Indebtedness"); provided, however, that in no event shall Indebtedness constituting Bank Product Obligations or Related Senior Indebtedness (as such terms are defined in the Intercreditor Agreement) be included in the calculation of Maximum Senior Indebtedness. Neither the holders of the notes nor the Trustee

83

will object to a motion for relief from the automatic stay in any proceeding to foreclose on and sell the Collateral.

•

The Senior Credit Facility Lenders will have absolute power and discretion, without notice to the holders of the notes or the Trustee, to deal in any manner with the Senior Indebtedness including, without limitation, amendments, modifications, supplements, refinancings, renewals, refundings, extensions or terminations of the documents related to the Senior Indebtedness, provided that the Senior Credit Facility Lenders may not (i) increase the principal amount of the Senior Indebtedness (excluding any Related Senior Indebtedness and Senior Indebtedness under any Bank Product Agreement) to a principal amount in excess of the Maximum Senior Indebtedness, less the outstanding Term Loan under the Senior Credit Agreement or (ii) extend the final maturity of the Senior Indebtedness beyond January 23, 2008. Neither the holders of the notes nor the Trustee will amend, modify or supplement any terms of the documents related to such notes in a manner adverse to the Senior Credit Facility Lenders without the prior written consent of the Senior Credit Facility Lenders.



•

Until the payment in full of the Senior Secured Obligations, neither the holders of the notes nor the Trustee will cancel or otherwise discharge any of the indebtedness evidenced by the notes or subordinate such indebtedness to any other indebtedness of the Issuer or any of its Subsidiaries, other than the Senior Indebtedness.

Certain Definitions with Respect to the Intercreditor Agreement

        "Bank Product Agreement" means any agreement for any service or facility extended to the Issuer or any of its Subsidiaries by the Senior Credit Facility Representative or any Senior Credit Facility Lender or any Affiliate of the Senior Credit Facility Representative or any such lender including: (a) credit cards, (b) credit card processing services, (c) debit cards, (d) purchase cards, (e) cash management or related services (including the Automated Clearing House processing of electronic funds transfers through the direct Federal Reserve Fedline system), (f) cash management, including controlled disbursement, accounts or services, or (g) Hedging Agreements.

        "Hedging Agreement" means any Currency Protection Agreement (a currency swap, cap or collar agreement or similar arrangement entered into with the intent of protecting against fluctuations in currency values, either generally or under specific contingencies), any Interest Rate Protection Agreement (an interest rate swap, cap or collar agreement or similar arrangement entered into with the intent of protecting against fluctuations in interest rates or the exchange of notional interest obligations, either generally or under specific contingencies), or Commodity Hedging Agreement (a commodity hedging or purchase agreement or similar arrangement entered into with the intent of protecting against fluctuations in commodity prices or the exchange of notional commodity obligations, either generally or under specific contingencies).

        "Junior Indebtedness" means any and all presently existing or hereafter arising Indebtedness, claims, debts, liabilities, obligations (including, without limitation, any prepayment premium), fees, expenses or indemnities of the Issuer or any of its Subsidiaries owing to the holders of the notes (or their agents or trustees) under the indenture, the notes and any other agreement, instrument or document related thereto, whether direct or indirect, whether contingent (including in respect of any guaranty or the registration rights agreement) or of any other nature, character, or description (including all interest and other amounts accruing after commencement of any bankruptcy or insolvency proceeding, and any interest and other amounts that, but for the provisions of the bankruptcy code, would have accrued and become due or otherwise would have been allowed), and any refinancings, renewals, refundings, or extensions of such amounts to the extent permitted under the Intercreditor Agreement.

84

        "Secured Creditor Remedies" means any action by the Senior Credit Facility Representative, the Senior Credit Facility Lenders, the holders of the notes or their trustee (each a "Secured Creditor") in furtherance of the sale, foreclosure, realization upon, or the repossession or liquidation of any of the Collateral, including, without limitation: (i) the exercise of any remedies or rights of a "Secured Creditor" under Article 9 of the applicable Uniform Commercial Code, such as, without limitation, the notification of account debtors; (ii) the exercise of any remedies or rights as a mortgagee or beneficiary (or by the trustee on behalf of the beneficiary), including, without limitation, the appointment of a receiver, or the commencement of any foreclosure proceedings or the exercise of any power of sale, including, without limitation, the placing of any advertisement for the sale of any Collateral; (iii) the exercise of any remedies available to a judgment creditor; (iv) the exercise of any rights of forfeiture, recession or repossession of any assets, or (v) any other remedy available in respect of the Collateral available to such Secured Creditor under any agreement, instrument or other document to which it is a party or under applicable law, provided that Secured Creditor Remedies shall not include any action taken by a Secured Creditor solely to (A) correct any mistake or ambiguity in any agreement, instrument or other document or (B) remedy or cure any defect in or lapse of perfection of the lien of a Secured Creditor in the Collateral.

        "Senior Indebtedness" means any and all presently existing or hereafter arising indebtedness, reimbursement obligations, claims, debts, liabilities, obligations (including, without limitation, any prepayment premium), expenses, fees or indemnities of the Issuer or any of its Subsidiaries owing to the Senior Credit Facility Lenders (or their agents) under the Senior Credit Agreement or any other agreement, instrument or document related thereto (including under any Bank Product Agreement), whether direct or indirect, whether contingent (including in respect of any guaranty) or of any other nature, character, or description (including all interest and other amounts accruing after commencement of any bankruptcy or insolvency proceeding, and all interest and other amounts that, but for the provisions of the bankruptcy code, would have accrued and become due or otherwise would have been allowed), and any refinancings, renewals, refundings, or, to the extent permitted in the intercreditor and subordination agreement, extensions of such amounts.

Certain Covenants

        The indenture contains, among others, the following covenants:

Limitation on Incurrence of Additional Indebtedness

        Other than Permitted Indebtedness, the Issuer may not, and may not cause or permit any of its Subsidiaries to, directly or indirectly, create, incur, assume, guarantee, acquire, become liable, contingently or otherwise, with respect to, or otherwise become responsible for payment of (collectively, "incur") any Indebtedness.

        Indebtedness of a Person existing at the time such Person becomes a Subsidiary (whether by merger, consolidation, acquisition of Capital Stock or otherwise) or is merged with or into the Issuer or any Subsidiary or which is secured by a Lien on an asset acquired by the Issuer or a Subsidiary (whether or not such Indebtedness is assumed by the acquiring Person) shall be deemed incurred at the time the Person becomes a Subsidiary or at the time of the asset acquisition.

        The Issuer will not, and will not permit any Subsidiary Guarantor, to incur any Indebtedness which by its terms (or by the terms of any agreement governing such Indebtedness) is subordinated in right of payment to any other Indebtedness (other than to senior Indebtedness under the Senior Credit Agreement and Qualified Senior Affiliate Indebtedness) of the Issuer or such Subsidiary Guarantor unless such Indebtedness is also by its terms (or by the terms of any agreement governing such Indebtedness) made expressly subordinate in right of payment to the notes or the Guarantee of such Subsidiary Guarantor, as the case may be, pursuant to subordination provisions that are substantively

85

identical to the subordination provisions of such Indebtedness (or such agreement) that are most favorable to the holders of any other Indebtedness (other than to senior Indebtedness under the Senior Credit Agreement and Qualified Senior Affiliate Indebtedness) of the Issuer or such Subsidiary Guarantor, as the case may be. Notwithstanding the foregoing, the provisions of this paragraph do not prohibit tranches of Indebtedness under the Senior Credit Agreement being subordinated to other tranches of Indebtedness under the Senior Credit Agreement. The Issuer will not, and will not permit any Subsidiary to, incur or suffer to exist Indebtedness that is senior in right of payment to the notes or any Guarantee, as the case may be, and expressly contractually subordinate in right of payment to any other Indebtedness of the Issuer or such Subsidiary, as the case may be.

Limitation on Restricted Payments

        The indenture defines and prohibits the following as Restricted Payments if done by the Issuer or any of its Subsidiaries:

•

declare or pay any dividend or make any distribution (other than dividends or distributions payable solely in Qualified Capital Stock of the Issuer) on or in respect of shares of the Issuer's Capital Stock to holders of such Capital Stock;



•

purchase, redeem or otherwise acquire or retire for value any Capital Stock of the Issuer or any warrants, rights or options to purchase or acquire shares of any class of such Capital Stock other than through the exchange therefore solely of Qualified Capital Stock of the Issuer or warrants, rights or options to purchase or acquire shares of Qualified Capital Stock of the Issuer;



•

make any principal payment on, purchase, defease, redeem, prepay, decrease or otherwise acquire or retire for value, prior to any scheduled final maturity, scheduled repayment or scheduled sinking fund payment, any Subordinated Indebtedness of the Issuer or a Subsidiary Guarantor; or



•

make any Investment (other than a Permitted Investment).

        However, the Issuer may take the following actions:

•

if no Default or Event of Default shall have occurred and be continuing, the acquisition of any shares of Capital Stock of the Issuer solely in exchange for shares of Qualified Capital Stock of the Issuer, and



•

if no Default or Event of Default shall have occurred and be continuing, the acquisition of any Indebtedness of the Issuer or a Subsidiary Guarantor that is subordinate or junior in right of payment to the notes or such Subsidiary Guarantor's Guarantee, as the case may be, the incurrence of which was not in violation of the indenture, solely in exchange for shares of Qualified Capital Stock of the Issuer.

Limitation on Asset Sales

        The Issuer may not, and may not cause or permit any of its Subsidiaries to, consummate an Asset Sale unless the consideration received is at least equal to the fair market value of the assets sold or otherwise disposed of, as determined in good faith by the Issuer's Board of Directors or senior management of the Issuer, and at least 95% of the consideration received is cash or Cash Equivalents and is received at the time of such disposition.

        The Issuer will be required to apply Net Cash Proceeds received from any Asset Sale to Pay Down Debt.

        If at any time any consideration (other than cash or Cash Equivalents) received in connection with any Asset Sale is converted into or sold or otherwise disposed of for cash, then such conversion or

86

disposition shall be treated like an Asset Sale and the Net Cash Proceeds will be applied as described above.

        The Issuer may defer the action to Pay Down Debt until there is an aggregate Available Proceeds Amount equal to or in excess of $500,000 resulting from one or more Asset Sales (at which time the entire unutilized Available Proceeds Amount, and not just the amount in excess of $500,000, will be applied as required pursuant to this paragraph).

        All Collateral Proceeds delivered to the Trustee will constitute Trust Moneys, and all Collateral Proceeds will be delivered by the Issuer:

•

so long as any Indebtedness under the Senior Credit Agreement or any Qualified Senior Affiliate Indebtedness remains outstanding, to the Senior Credit Facility Representative; and



•

otherwise to the Trustee and all Collateral Proceeds delivered to the Trustee will be deposited in the Collateral Account in accordance with the indenture. These Collateral Proceeds may be withdrawn from the Collateral Account for application by the Issuer as set forth above or otherwise pursuant to the indenture as summarized in "Deposit; Use and Release of Trust Moneys."

        In the event of the transfer of substantially all (but not all) of the consolidated assets of the Issuer as an entirety to a Person in a transaction permitted under the covenant described in "Merger, Consolidation and Sale of Assets," the successor corporation will be deemed to have sold the consolidated assets of the Issuer not so transferred and must comply with the provisions of this covenant as if it were an Asset Sale. In addition, the fair market value of the consolidated assets of the Issuer deemed to be sold will be deemed to be Net Cash Proceeds.

        The Issuer will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with the repurchase of notes as a result of an action to Pay Down Debt.

Limitation on Dividend and Other Payment Restrictions Affecting Subsidiaries

        The Issuer may not, and may not cause or permit any of its Subsidiaries to, directly or indirectly, create or otherwise cause or permit to exist or become effective any encumbrance or restriction (each, a "Payment Restriction") on the ability of any Subsidiary to:

•

pay dividends or make any other distributions on or in respect of its Capital Stock;



•

make loans or advances, or to pay any Indebtedness or other obligation owed, to the Issuer or any other Subsidiary;



•

guarantee any Indebtedness or any other obligation of the Issuer or any Subsidiary; or



•

transfer any of its property or assets to the Issuer or any other Subsidiary.

87

        The preceding will not apply, however, to encumbrances or restrictions existing under or by reason of the following (which are excluded from the term "Payment Restriction"):

        (1)   applicable law;

        (2)   the indenture, the Senior Credit Agreement, any security document or any of the security documents entered into in connection with the Senior Credit Agreement, and any document or instrument evidencing, governing or securing any of the Qualified Senior Affiliate Indebtedness;

        (3)   customary non-assignment provisions of any contract or any lease governing a leasehold interest of any Subsidiary;

        (4)   any instrument governing Acquired Indebtedness, which encumbrance or restriction is not applicable to such Subsidiary, or the properties or assets of such Subsidiary, other than the Person or the properties or assets of the Person so acquired;

        (5)   agreements existing on the Issue Date to the extent and in the manner such agreements were in effect on the Issue Date;

        (6)   customary restrictions with respect to a Subsidiary pursuant to an agreement that has been entered into for the sale or disposition of Capital Stock or assets of such Subsidiary to be consummated in accordance with the terms of the indenture solely in respect of the assets or Capital Stock to be sold or disposed of;

        (7)   any instrument governing a Permitted Lien, to the extent and only to the extent such instrument restricts the transfer or other disposition of assets subject to such Permitted Lien; or

        (8)   an agreement governing Refinancing Indebtedness incurred to Refinance the Indebtedness issued, assumed or incurred pursuant to an agreement referred to in clause (2), (4) or (5) above; provided, however, that the provisions relating to such encumbrance or restriction contained in any such Refinancing Indebtedness are no less favorable to the holders in any material respect as determined by the Board of Directors of the Issuer in its reasonable and good faith judgment than the provisions relating to such encumbrance or restriction contained in the applicable agreement referred to in such clause (2), (4) or (5).

Limitation on Preferred Stock of Subsidiaries

        The Subsidiaries may not issue any Preferred Stock (other than to the Issuer or to a Wholly Owned Subsidiary) or permit any Person (other than the Issuer or a Wholly Owned Subsidiary) to own any Preferred Stock of any Subsidiary.

Limitation on Liens

        The Issuer may not, and may not cause or permit any of its Subsidiaries to, directly or indirectly, create, incur, assume or permit or suffer to exist or remain in effect any Liens upon any properties or assets of the Issuer or of any of its Subsidiaries, whether owned on the Issue Date or acquired after the Issue Date, or on any income or profits therefrom, or assign or otherwise convey any right to receive income or profits thereon, other than Permitted Liens.

Merger, Consolidation and Sale of Assets

        The Issuer shall not, in a single transaction or series of related transactions;

•

consolidate or merge with or into any Person,



•

or sell, assign, transfer, lease, convey or otherwise dispose of (or cause or permit any Subsidiary to sell, assign, transfer, lease, convey or otherwise dispose of) all or substantially all of the assets

88

owned directly or indirectly by the Issuer (determined on a consolidated basis for the Issuer and its Subsidiaries), whether as an entirety or substantially as an entirety to any Person,

        unless:

•

either

        (A)  the Issuer shall be the surviving or continuing corporation, or

        (B)  the Person (if other than the Issuer) formed by such consolidation or into which the Issuer is merged or the Person which acquires by sale, assignment, transfer, lease, conveyance or other disposition the assets of the Issuer and its Subsidiaries substantially as an entirety (the "Surviving Entity")

(i)

shall be a corporation organized and validly existing under the laws of the United States or any state thereof or the District of Columbia; and



(ii)

shall expressly assume, by supplemental indenture (in form and substance satisfactory to the Trustee), executed and delivered to the Trustee, the due and punctual payment of the principal of, premium, if any, and interest on all of the notes and the performance of every covenant of the notes, the indenture, and the security documents on the part of the Issuer to be performed or observed;



•

immediately after giving effect to such transaction and the assumption contemplated above (including giving effect to any Indebtedness incurred or anticipated to be incurred and any Lien granted in connection with or in respect of such transaction), the Issuer or such Surviving Entity, as the case may be,

        (A)  shall have a Consolidated Net Worth equal to or greater than the Consolidated Net Worth of the Issuer immediately prior to such transaction, and

        (B)  both (i) the Issuer's or such Surviving Entity's (calculated as if such Surviving Entity was the Issuer), as the case may be, Consolidated EBITDA Coverage Ratio is at least equal to 2.5 to 1.0; and (ii) the Issuer's or such Surviving Entity's (calculated as if such Surviving Entity was the Issuer), as the case may be, Adjusted Consolidated Net Tangible Assets are equal to or greater than 150% of the aggregate consolidated Indebtedness of the Issuer and its Subsidiaries;

•

immediately before and immediately after giving effect to such transaction and the assumption contemplated above (including, without limitation, giving effect to any Indebtedness incurred or anticipated to be incurred and any Lien granted in connection with or in respect of the transaction), no Default or Event of Default shall have occurred or be continuing; and



•

the Issuer or the Surviving Entity, as the case may be, shall have delivered to the Trustee an officer's certificate and an opinion of counsel, each stating that such consolidation, merger, sale, assignment, transfer, lease, conveyance or other disposition and, if a supplemental indenture is required in connection with such transaction, such supplemental indenture comply with the applicable provisions of the indenture and that all conditions precedent in the indenture relating to such transaction have been satisfied.

        For purposes of the foregoing, the transfer (by lease, assignment, sale or otherwise, in a single transaction or series of transactions) of all or substantially all of the assets of one or more Subsidiaries the Capital Stock of which constitutes all or substantially all of the assets of the Issuer, shall be deemed to be the transfer of all or substantially all of the assets of the Issuer.

        Upon any consolidation or merger or any transfer of all or substantially all of the assets of the Issuer in accordance with the foregoing, in which the Issuer is not the continuing corporation, the successor Person formed by such consolidation or into which the Issuer is merged or to which such

89

transfer is made shall succeed to, and be substituted for, and may exercise every right and power of, the Issuer under the indenture and the notes and thereafter (except in the case of a lease), the Issuer will be relieved of all further obligations and covenants under the indenture and the notes.

        Each Subsidiary Guarantor (other than any Subsidiary Guarantor whose Guarantee is to be released in accordance with the terms of the Guarantee and the indenture in connection with any transaction complying with the provisions of the indenture described under "Merger, Consolidation and Sale of Assets") may not, and the Issuer may not cause or permit any Subsidiary Guarantor to, consolidate with or merge with or into any Person other than the Issuer or another Subsidiary Guarantor that is a Wholly Owned Subsidiary unless:

•

the entity formed by or surviving any such consolidation or merger (if other than the Subsidiary Guarantor) is a Person organized and existing under the laws of the United States or any state thereof or the District of Columbia (or if such Subsidiary Guarantor was formed under the laws of Canada or any province or territory thereof, such Surviving Entity shall be a Person organized and validly existing under the laws of Canada or any province or territory thereof);



•

such entity assumes by execution of a supplemental indenture all of the obligations of the Subsidiary Guarantor under its Guarantee;



•

immediately after giving effect to such transaction, no Default or Event of Default shall have occurred and be continuing; and



•

immediately after giving effect to such transaction and the use of any net proceeds therefrom on a pro forma basis, the Issuer could satisfy the Consolidated Net Worth and Consolidated EBITDA Coverage Ratio and Adjusted Consolidated Net Tangible Assets tests set forth above.

        Any merger or consolidation of a Subsidiary Guarantor with and into the Issuer (with the Issuer being the Surviving Entity) need only comply with the officer's certificate and opinion of counsel provisions set forth above.

Limitations on Transactions with Affiliates

        The Issuer may not, and may not cause or permit any of its Subsidiaries to, directly or indirectly, engage in any transaction or series of related transactions (including, without limitation, the purchase, sale, lease or exchange of any property, the guaranteeing of any Indebtedness or the rendering of any service) with any of its Affiliates unless:

•

such transaction or series of related transactions is not otherwise prohibited by the terms of the indenture and is on terms that are fair and reasonable to the Issuer or the applicable Subsidiary and are no less favorable to the Issuer or the applicable Subsidiary than would have been obtained in a comparable transaction at such time on an arm's-length basis from a Person that is not an Affiliate; and



•

with respect to a transaction or series of related transactions involving aggregate payments or other property with a fair market value in excess of $250,000, the Issuer obtains Board approval which is evidenced by a resolution stating that the Board has determined that such transaction complies with the foregoing provisions.

        In addition, if the transaction or series of related transactions involves an aggregate fair market value of more than $2,000,000, the Issuer must, prior to the consummation thereof, obtain a favorable opinion as to the fairness of such transaction or series of related transactions to the Issuer or the relevant Subsidiary, as the case may be, from a financial point of view, from an Independent Advisor and file the same with the Trustee.

90

        The foregoing shall not apply to:

•

reasonable fees and compensation paid to and indemnity provided on behalf of, officers, directors, employees or consultants of the Issuer or any Subsidiary as determined in good faith by the Board of Directors or senior management of the Issuer or such Subsidiary, as the case may be;



•

transactions exclusively between or among the Issuer and any of its Subsidiaries or exclusively between or among such Subsidiaries if such transactions are not otherwise prohibited by the indenture; and



•

Restricted Payments permitted by the indenture, or any guarantee or assumption by the Issuer or any of its Subsidiaries of Indebtedness of the Issuer or any of its Subsidiaries if the incurrence of such Indebtedness was not prohibited by the indenture.

Additional Subsidiary Guarantees

        All Subsidiaries of the Issuer shall be Subsidiary Guarantors. If any Subsidiary of the Issuer is formed after the Issue Date, or if a Person otherwise becomes a Subsidiary of the Issuer after the Issue Date, the Issuer shall cause such Subsidiary to:

•

execute and deliver to the Trustee a supplemental indenture in form reasonably satisfactory to the Trustee pursuant to which such Subsidiary shall unconditionally guarantee all of the Issuer's obligations under the notes and the indenture on the terms set forth in the indenture;



•

grant to the Trustee a second priority Lien (subject to certain Permitted Liens) on all of the current and future Oil and Gas Assets of such Subsidiary, and substantially all of its other current and future assets using applicable security documents substantially in the same form as those executed and delivered on January 23, 2003; and



•

deliver to the Trustee an opinion of counsel and an officers' certificate, stating that no event of default shall occur as a result of such supplemental indenture or security documents, that each such instrument complies with the terms of the indenture and that each such instrument has been duly authorized, executed and delivered by such Subsidiary and constitutes a legal, valid, binding and enforceable obligation of such Subsidiary.

        Thereafter, such Subsidiary shall be a Subsidiary Guarantor for all purposes of the indenture.

Limitation on Impairment of Security Interest

        Neither the Issuer nor any of its Subsidiaries may take or omit to take any action which would have the result of adversely affecting or impairing the security interest in favor of the Trustee, on behalf of itself and the holders, with respect to the Collateral, and neither the Issuer nor any of its Subsidiaries may grant to any Person, or suffer any Person (other than the Issuer and its Subsidiaries) to have (other than to the Trustee on behalf of the Trustee and the holders) any interest whatsoever in the Collateral other than Permitted Liens. Neither the Issuer nor any of its Subsidiaries may enter into any agreement or instrument that by its terms requires the proceeds received from any sale of Collateral to be applied to repay, redeem, defease or otherwise acquire or retire any Indebtedness, other than Indebtedness under the Senior Credit Agreement, Qualified Senior Affiliate Indebtedness, and the security documents entered into in connection therewith, and other than pursuant to the indenture and the security documents.

91

Limitation on the Sale or Issuance of Capital Stock of Subsidiaries

        The Issuer may not, and may not permit any Subsidiary to, sell or otherwise dispose of any shares of Capital Stock of any Subsidiary, and shall not permit any of its Subsidiaries, directly or indirectly, to issue or sell or otherwise dispose of any of its Capital Stock except:

•

to the Issuer or a Wholly Owned Subsidiary; or



•

if all shares of Capital Stock of such Subsidiary owned by the Issuer and its Subsidiary are sold or otherwise disposed of.

        In connection with any sale or disposition of Capital Stock of any Subsidiary, the Issuer will be required to comply with the covenant described under the caption "Limitation on Asset Sales."

Limitation on Conduct of Business

        The Issuer will not, and will not permit any of its Subsidiaries to, engage in the conduct of any business other than the Crude Oil and Natural Gas Business.

Reports to Holders

        The Issuer will deliver to the Trustee within 15 days after the filing of the same with the SEC, copies of the quarterly and annual reports and of the information, documents and other reports, if any, which the Issuer is required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act. Notwithstanding that the Issuer may not be subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, the Issuer will file with the SEC, to the extent permitted, and provide the Trustee and Holders with such annual reports and such information, documents and other reports specified in Sections 13 and 15(d) of the Exchange Act. The Issuer will also comply with the other provisions of Section 314(a) of the Trust Indenture Act.

        The reports and information delivered pursuant to the preceding paragraph shall include quarterly financials, including details regarding sources and uses of cash or of any assets of the Issuer and its Subsidiaries. Such financials will provide details on both a consolidated and unconsolidated basis.

Waiver of Stay, Extension or Usury Laws

        The Issuer and each Subsidiary Guarantor will covenant (to the extent that they may lawfully do so) that they will not at any time insist upon, plead, or in any manner whatsoever claim or take the benefit or advantage of, any stay or extension law or any usury law or other law that would prohibit or forgive the Issuer or such Subsidiary Guarantor from paying all or any portion of the principal of or interest on the notes as contemplated herein, wherever enacted, now or at any time hereafter in force, or which may affect the covenants or the performance of the indenture; and (to the extent that they may lawfully do so) the Issuer and each Subsidiary Guarantor will expressly waive in the indenture all benefit or advantage of any such law, and covenant that they will not hinder, delay or impede the execution of any power herein granted to the trustee, but will suffer and permit the execution of every such power as though no such law had been enacted.

Leverage Covenant

        The Issuer must not allow the Issuer's Consolidated EBITDA to Cash Interest Expense Ratio, as of the last day of any calendar quarter after the Issue Date, to be less than 3.0:1, except on the last day of the first calendar quarter of 2003, at which time this ratio must not be less than 2.0:1.

92

Excess Cash Flow and Excess Cash

        Without duplication with respect to the requirement to Pay Down Debt set forth in the next paragraph, within 30 days after the last day of each calendar quarter ending after the Issue Date, the Issuer must apply an amount to Pay Down Debt equal to 90% of the Excess Cash Flow of the Issuer for such calendar quarter.

        Without duplication with respect to the requirement to Pay Down Debt set forth in the previous paragraph, with respect to each calendar quarter ending after the Issue Date and on the same date that the Issuer applies an amount to Pay Down Debt pursuant to the preceding paragraph with respect to such calendar quarter, and on a date that is 7 days after the Issue Date, the Issuer must apply an amount to Pay Down Debt equal to all cash of the Issuer and its Subsidiaries as of such date (each such date a "Cash Sweep Payment Date"), after the application of an amount to Pay Down Debt pursuant to the preceding paragraph, on that date (provided that if there is no Excess Cash Flow with respect to such calendar quarter, the Cash Sweep Payment Date with respect to such calendar quarter shall be the first business day that is 30 days after the last day of such calendar quarter), minus

•

$2.5 million,



•

Restricted Cash as of such Cash Sweep Payment Date,



•

the amount of Capital Expenditures the Issuer is permitted to make pursuant to the terms of the indenture during the next calendar quarter pursuant to the covenant described below under the heading "Limitations on Capital Expenditures," minus amounts available for making Capital Expenditures under any revolving credit facility under the Senior Credit Agreement as of such Cash Sweep Payment Date,



•

cash of the Issuer as of such Cash Sweep Payment Date otherwise applied or required to be applied to Pay Down Debt, and



•

without duplication with respect to the previous bullet point, any such cash of the Issuer and its Subsidiaries as of the Cash Sweep Payment Date constituting proceeds of any equity offering by the Issuer or proceeds of any Subordinated Indebtedness of the Issuer or any of its Subsidiaries complying with the provisions of the indenture described below under "Proceeds from Issuances of Equity and Subordinated Debt."

        The Issuer will manage the cash of the Issuer and its Subsidiaries in the ordinary course of business consistent with past practices and in compliance with the terms of the Senior Credit Agreement.

Limitation on Expenditures for Selling, General and Administrative Expenses

        The Issuer must observe the following covenants with respect to expenditures by the Issuer and its Subsidiaries on SG&A:

•

The amount expended by the Issuer and its Subsidiaries on SG&A in any calendar quarter ending after the Issue Date shall not exceed the applicable SG&A Quarterly Amount, subject, however, to the following carryforward and carryback provisions:



•

to the extent the SG&A in any one quarter (excluding the amount of SG&A due to any Rollover Increase because of a prior quarter's SG&A Deficit Amount) exceeds the applicable SG&A Quarterly Amount, the SG&A Quarterly Amount for the two succeeding quarters shall be reduced in the aggregate by an amount equal to the applicable SG&A Excess Amount, and



•

to the extent the SG&A in any one quarter (excluding the amount of SG&A due to any Rollover Decrease because of a prior quarter's SG&A Excess Amount) is less than the

93

applicable SG&A Quarterly Amount, the SG&A Quarterly Amount for the two succeeding quarters shall be increased in the aggregate by an amount equal to the applicable SG&A Deficit Amount,

•

In no event shall the amount expended by the Issuer and its Subsidiaries on SG&A in any calendar year ending after the Issue Date exceed the SG&A Annual Amount.

Limitations on Capital Expenditures

        The Issuer must observe the following covenants with respect to Capital Expenditures by the Issuer and its Subsidiaries:

•

For the first calendar quarter in 2003, Capital Expenditures of the Issuer and its Subsidiaries shall not exceed the Q1-2003 CapEx Amount, and for each other calendar quarter in 2003, Capital Expenditures of the Issuer and its Subsidiaries shall not exceed the Q2,3,4-2003 CapEx Amount, subject, however, to the following carryforward and carryback provisions:



•

to the extent Capital Expenditures in the first calendar quarter of 2003 (excluding the amount of Capital Expenditures due to any Rollover Increase because of a prior quarter's CapEx Deficit Amount) exceed the Q1-2003 CapEx Amount or to the extent Capital Expenditures in any other calendar quarter of 2003 (excluding the amount of Capital Expenditures due to any Rollover Increase because of a prior quarter's CapEx Deficit Amount) exceed the Q2,3,4-2003 CapEx Amount, as applicable, the CapEx Quarterly Amount for the two succeeding quarters shall be decreased in the aggregate by an amount equal to the applicable CapEx Excess Amount, and



•

to the extent Capital Expenditures in the first calendar quarter of 2003 (excluding the amount of Capital Expenditures due to any Rollover Decrease because of a prior quarter's CapEx Excess Amount) fall below the Q1-2003 CapEx Amount or to the extent Capital Expenditures in any other calendar quarter of 2003 (excluding the amount of Capital Expenditures due to any Rollover Decrease because of a prior quarter's CapEx Excess Amount) fall below the Q2,3,4-2003 CapEx Amount, as applicable, the CapEx Quarterly Amount for the two succeeding quarters shall be increased in the aggregate by an amount equal to the applicable CapEx Deficit Amount.



•

In no event shall the Capital Expenditures of the Issuer and its Subsidiaries for calendar year 2003 exceed the 2003 CapEx Amount.



•

For each calendar quarter in calendar year 2004 and each calendar quarter in any following calendar year, Capital Expenditures of the Issuer and its Subsidiaries shall not exceed the applicable 2004-Plus CapEx Quarterly Amount, subject, however, to the following carryforward and carryback provisions:



•

to the extent Capital Expenditures in any such quarter (excluding the amount of Capital Expenditures due to any Rollover Increase because of a prior quarter's CapEx Deficit Amount) exceed the applicable 2004-Plus CapEx Quarterly Amount, the 2004-Plus CapEx Quarterly Amount for the two succeeding quarters shall be decreased in the aggregate by an amount equal to the applicable CapEx Excess Amount, and



•

to the extent the Capital Expenditures in any such quarter (excluding the amount of Capital Expenditures due to any Rollover Decrease because of a prior quarter's CapEx Excess Amount) fall below the applicable 2004-Plus CapEx Quarterly Amount, the 2004-Plus CapEx Quarterly Amount for the two succeeding quarters shall be increased in the aggregate by an amount equal to the applicable CapEx Deficit Amount.

94

•

In no event shall the Capital Expenditures of the Issuer and its Subsidiaries for calendar year 2004 or any following calendar year exceed the 2004-Plus CapEx Annual Amount.

        With respect to the limitations on Capital Expenditures set forth above, the Issuer will be allowed to reallocate capacity for making up to an aggregate of $3 million of Capital Expenditures which are to be used for satisfying capital calls with respect to non-operating mineral interests of the Issuer and its Subsidiaries for development expenses with respect to such non-operating mineral interests as follows:

•

any such reallocation will increase the annual permissible Capital Expenditures by the amount of such reallocation for the calendar year to which such reallocation was made, and will decrease the annual permissible Capital Expenditures by the amount of such reallocation for the calendar year from which such reallocation was made;



•

the amount reallocated to a calendar year must be allocated by the Issuer to the calendar quarters within that calendar year to increase the permissible Capital Expenditures for such calendar quarters, and the amount reallocated from a calendar year must be allocated by the Issuer to the calendar quarters within that calendar year to decrease the permissible Capital Expenditures for such calendar quarters.



•

any amount reallocated to a particular period (i.e., to a particular calendar year or a particular calendar quarter) can be used only for Capital Expenditures to satisfy capital calls with respect to non-operating mineral interests of the Issuer and its Subsidiaries for development expenses with respect to such non-operating mineral interests

Limitation on Tax Sharing Arrangements

        Neither the Issuer nor any of its Subsidiaries may enter into any agreement, arrangement or understanding with respect to liability for payment or sharing of any other Person's taxes, including any tax sharing or similar arrangement, except to the extent of any covenant pursuant to which funds or money actually paid or transferred to or from the Issuer or its Subsidiary, as the case may be, are thereupon actually used to pay the applicable taxes.

Limitation on Uses of Cash

        The indenture provides that the Issuer and its Subsidiaries will make cash expenditures only for the following and only to the extent not otherwise prohibited by the terms of the indenture:

•

Qualified Lease Operating Costs, SG&A costs, taxes (e.g., income, severance, ad valorem, franchise) in each case not prohibited by the terms of the indenture;



•

cash interest requirements;



•

Capital Expenditures not prohibited by the terms of the indenture;



•

any oil and gas hedge settlements requiring a cash payment from the Issuer pursuant to oil and gas hedge agreements entered into (a) pursuant to approval by the Board of Directors of the Issuer, (b) in the ordinary course of business, and (c) to provide protection against oil and gas price fluctuations with respect to reasonably anticipated oil and gas production of the Issuer and its Subsidiaries and not for the purpose of speculating;



•

any payment to reduce debt to the extent such payment is not prohibited by the terms of the indenture, provided that the average days outstanding for payables paid shall not be less than the greater of (a) 45 days and (b) the industry standard therefor, subject to adjustment by the Board of Directors of the Issuer;

95

•

payments due to the settling of a natural gas balancing deficiency not to exceed $45,000 in the aggregate in any calendar year unless a higher amount is approved by the Board of Directors of the Issuer;



•

payment of judgments rendered by a court of law;



•

assessments issued by any governmental entity;



•

additional cash expenditures not to exceed $2 million in the aggregate in any calendar year; provided, however, that the Issuer and its Subsidiaries may make aggregate cash expenditures in excess of $2 million in any calendar year under this provision if the Board of Directors of the Issuer approves such expenditures;



•

obligations under the Senior Credit Agreement and Qualified Senior Affiliate Indebtedness including, but not limited to, fees and expenses incurred in connection therewith and fees related to any amendment, waiver, consent or similar actions taken by the agent and lenders related thereto (the payment of which obligations will not be prohibited by the terms of the indenture); and



•

payment of any Stark Fees.

Proceeds from Issuances of Equity and Subordinated Debt

        The Issuer may issue common equity, or preferred equity with no maturity or required or allowed cash dividend, at any time and may use the net proceeds from any such issuance in any manner consistent with other provisions of the indenture. Such net proceeds will not be included in the calculation of Excess Cash Flow.

        The Issuer may also issue preferred equity with a maturity or required or allowed cash dividends if such issuance complies with the following requirements:

•

no portion of any such equity may be redeemed or repurchased or, except as permitted pursuant to the third bullet point, have any other cash distribution or dividend until the notes are completely repaid,



•

at least 50% of the proceeds of such issuance must immediately be used to Pay Down Debt, and



•

no cash dividends can be paid on such equity unless:



•

at least 75% of such proceeds are used to Pay Down Debt,



•

the cash dividend payable to the holders of such equity does not exceed the Cash Coupon on the notes, and



•

the holders of the notes receive in cash (in full) current interest payments due and payable.

        The Issuer and its Subsidiaries may also incur Subordinated Indebtedness that complies with the following requirements (such Indebtedness is referred to as "Permitted Subordinated Indebtedness"):

•

no portion of any principal of any such Subordinated Indebtedness may be repaid, or refinanced if such refinancing results in a shorter Weighted Average Life to Maturity or in the terms of such Subordinated Indebtedness being less favorable to the holders of the notes, until the notes are completely repaid,



•

at least 50% of the proceeds of such issuance must immediately be used to Pay Down Debt, and



•

no cash interest can be paid on such Subordinated Indebtedness unless:



•

at least 75% of such proceeds are used to Pay Down Debt,

96

•

the cash portion of any interest payable to the holders of such Subordinated Indebtedness does not exceed the Cash Coupon on the notes, and



•

the holders of the notes receive in cash (in full) current interest payments due and payable.

Accounting

        The Issuer will keep its financial accounts in accordance with GAAP and, except as GAAP may require, consistent with past practices.

Farmouts

        The indenture provides that the Issuer and its Subsidiaries will be able to enter into and perform with respect to farmouts covering any of their undeveloped wells and properties, provided that the Issuer must, prior to any properties being transferred pursuant to such farmout, obtain written confirmation from F. John Stark, III stating that such farmout is in the best interests of the holders of the notes, and file the same with the Trustee, further provided that such written confirmation will not be required for any farmout with a farmout value (as determined as provided below) of less than $100,000, but the total aggregate farmout value of farmouts so exempted from the written confirmation requirement cannot exceed $500,000 in any twelve calendar month period. For the purposes of this provision, the value of a farmout will be the portion of the capital commitments made by the farmee(s) under the farmout relating to the interests of the Issuer or its Subsidiaries being farmed out. The Issuer anticipates entering into a retainer arrangement with F. John Stark, III in connection with his services with respect to such written confirmations, with such retainer arrangement calling for the payment to him of fees for his services with respect to such written confirmations (the "Stark Fees"), with the Stark Fees being excluded from the calculation of SG&A.

        In addition, the indenture provides that the Issuer and its Subsidiaries will be able to enter into and perform farmouts not complying with the preceding paragraph if consent to such farmout is obtained from the holders of not less than a majority of the principal amount of the then outstanding notes issued under the indenture.

        Furthermore, the indenture provides that the farmouts referenced in the Purchase and Sale Agreement dated November 21, 2002 between the Issuer, as seller, and PrimeWest Gas Inc., as purchaser, as the Farmout Agreement and included as Schedule P in such agreement, are permitted farmouts under the indenture.

        Farmouts permitted by the preceding three paragraphs are referred to as "Permitted Farmout Agreements." The following shall apply to each Permitted Farmout Agreement:

•

the applicable portions of Liens of the security documents securing the notes will be released with respect to the undeveloped wells and/or properties that are subject to such Permitted Farmout Agreement, provided that all retained interests of the Issuer and the Subsidiaries in such wells and/or properties will remain subject to such Liens;



•

such Permitted Farmout Agreement will be deemed not to be an Asset Sale, including, but not limited to, the purchase options in the farmout agreements referenced above in connection with the November 21, 2002 Purchase and Sale Agreement with PrimeWest Gas Inc.;



•

obligations of the Issuer and its Subsidiaries under such Permitted Farmout Agreement that constitute Indebtedness will be Permitted Indebtedness so long as any such Indebtedness is non-recourse with respect to the Issuer and its Subsidiaries and their properties and assets other than the wells and/or properties that are the subject of such Permitted Farmout Agreement; and



•

to the extent such Permitted Farmout Agreement would constitute an Investment by the Issuer or any of its Subsidiaries, such Investment will be a Permitted Investment.

97

CEO Note Options

        The Issuer may issue to its Chief Executive Officer (the "Issuer's CEO") options to purchase notes ("CEO Note Options") as follows:

•

Issuance to the Issuer's CEO on the Issue Date of options to purchase $750,000 principal amount of notes for the market price therefor at the Issue Date;



•

Issuance to the Issuer's CEO of options to purchase $250,000 principal amount of notes for the market price therefor at the Issue Date if the notes trade for greater than 70% of the face amount thereof for 60 consecutive trading days, with the first of such consecutive 60 days being in January of 2003;



•

Issuance to the Issuer's CEO of options to purchase $500,000 principal amount of notes for the market price therefor at the Issue Date if the notes trade for greater than 70% of the face amount thereof for any 60 consecutive trading days during the first 365 calendar days after the Issue Date; and



•

Issuance to the Issuer's CEO of options to purchase $250,000 principal amount of notes for the market price therefor at the Issue Date if the notes trade for greater than 90% of the face amount thereof for any 60 consecutive trading days during the 365 calendar day period commencing on the 366th day after the Issue Date, provided that if the condition set forth in the previous bullet point is not achieved, the amount applicable for this bulletin point shall be increased from $250,000 to $750,000.

        For determining consecutive trading days with respect to the notes, a trading day will be a day on which there are at least $500,000 in aggregate principal amount of notes traded and either Jefferies & Company, Inc., or its successor, or Imperial Capital, LLC, or its successor, (as long as they did not execute the trade) confirms to the Issuer that the trade was in the context of the market.

Limitation on Abraxas Wamsutter, Ltd.

        So long as the Issuer continues to have a partnership interest in Abraxas Wamsutter, Ltd., the Issuer will not permit Abraxas Wamsutter, Ltd. to be an operating entity.

Conduct of Business in the Interim Period

        The Issuer shall have conducted, and shall have caused its Subsidiaries to conduct, business consistent with past practices during the interim period between the date that the Offer to Exchange was made and the Issue Date.

Calculation of Original Issue Discount

        The Issuer will file with the Trustee promptly at the end of each calendar year (a) a written notice specifying the amount of original issue discount accrued on the outstanding notes as of the end of such year and (b) such other specific information relating to such original issue discount as may then be relevant under the Internal Revenue Code or applicable U.S. Treasury regulation.

98

Events of Default

        Each of the following is an "Event of Default":

•

the failure to pay interest on any notes when the same becomes due and payable;



•

the failure to pay the principal on any notes, when such principal becomes due and payable, at maturity, upon redemption or otherwise (including the failure to make a payment to purchase notes tendered pursuant to a Change of Control Offer or to Pay Down Debt in connection with an Asset Sale);



•

a default in the observance or performance of any other covenant or agreement contained in the indenture which default continues for a period of 30 days after the Issuer or any Subsidiary Guarantor receives written notice specifying the default (and demanding that such default be remedied) from the Trustee or the holders of at least 25% of the outstanding principal amount of the notes (except in the case of a default with respect to observance or performance of any of the terms or provisions of the covenants described above under "Change of Control" or "Merger, Consolidation and Sale of Assets" or "Limitation on Asset Sales" which will constitute an Event of Default with such notice requirement but without such passage of time requirement);



•

a default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness of the Issuer or of any Subsidiary (or the payment of which is guaranteed by the Issuer or any Subsidiary), whether such Indebtedness now exists or is created after the Issue Date, which default:



(A)

is caused by a failure to pay principal of or premium, if any, or interest on such Indebtedness after any applicable grace period provided in such Indebtedness (a "payment default"), or



(B)

results in the acceleration of such Indebtedness prior to its express maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a payment default or the maturity of which has been so accelerated, aggregates at least $2,000,000;                 

•

one or more judgments in an aggregate amount in excess of $2,000,000 (unless covered by insurance by a reputable insurer as to which the insurer has acknowledged coverage) are rendered against the Issuer or any of its Subsidiaries and such judgments remain undischarged, unvacated, unpaid or unstayed for a period of 60 days after such judgment or judgments become final and non-appealable;



•

certain events of bankruptcy; or



•

any of the Guarantees or any of the security documents ceases to be in full force and effect or any of the Guarantees or any of the security documents is declared to be null and void or invalid and unenforceable or any of the Subsidiary Guarantors denies or disaffirms its liability under its Guarantees (other than by reason of release of a Subsidiary Guarantor in accordance with the terms of the indenture) or any obligor or any Related Person denies or disaffirms its liability under any security document to which it is a party.

        If any Event of Default (other than the Event of Default relating to certain events of bankruptcy) occurs and is continuing, the Trustee or the holders of at least 25% in principal amount of outstanding notes may declare the principal of, premium, if any, and accrued and unpaid interest on all the notes to be due and payable by notice in writing to the Issuer and the Trustee specifying the Event of Default and that it is a "notice of acceleration", and the same shall become immediately due and payable. If an

99

Event of Default relating to certain events of bankruptcy occurs and is continuing, then all unpaid principal of, and premium, if any, and accrued and unpaid interest on all of the outstanding notes will be immediately due and payable without any declaration or other act on the part of the Trustee or any holder.

        After a declaration of acceleration with respect to the notes as described in the preceding paragraph, the holders of a majority in principal amount of the notes may rescind and cancel such declaration if:

•

the rescission would not conflict with any judgment or decree;



•

all existing Events of Default have been cured or waived except nonpayment of principal or interest that has become due solely because of such acceleration;



•

to the extent the payment of such interest is lawful, interest on overdue installments of interest and overdue principal, which has become due otherwise than by such declaration of acceleration, has been paid;



•

the Issuer has paid the Trustee its reasonable compensation and reimbursed the Trustee for its expenses, disbursements and advances; and



•

the Trustee shall have received an officer's certificate and an opinion of counsel that such Event of Default has been cured or waived in the event of the cure or waiver of an Event of Default relating to certain events of bankruptcy.

        No such rescission shall affect any subsequent Default or impair any right consequent thereto.

        Prior to the declaration of acceleration of the notes, the holders of a majority in principal amount of the notes may waive any existing Default or Event of Default under the indenture, and its consequences, except a default in the payment of the principal of or interest on any notes.

        Holders of the notes may not enforce the indenture or the notes except as provided in the indenture and under the Trust Indenture Act. During the existence of an Event of Default, the Trustee is required to exercise such rights and powers vested in it under the indenture and use the same degree of care and skill in its exercise thereof as a prudent man would exercise or use under the circumstances in the conduct of his own affairs. Subject to the provisions of the indenture relating to the duties of the Trustee, whether or not an Event of Default shall occur and be continuing, the Trustee is under no obligation to exercise any of its rights or powers under the indenture at the request, order or direction of any of the holders, unless such holders have offered to the Trustee reasonable indemnity. Subject to all provisions of the indenture, the Intercreditor Agreement and applicable law, the holders of a majority in aggregate principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or exercising any trust or power conferred on the Trustee.

        The Issuer is required to provide an officer's certificate to the Trustee promptly upon any such officer obtaining knowledge of any Default or Event of Default (provided that such officers shall provide such certification at least annually whether or not they know of any Default or Event of Default) that has occurred and, if applicable, describe such Default or Event of Default and the status thereof.

Possession, Use and Release of Collateral

        Unless an Event of Default shall have occurred and be continuing, the Issuer and the Subsidiary Guarantors will have the right to remain in possession and retain exclusive control of the Collateral securing the notes (other than any cash, securities, obligations and Cash Equivalents constituting part of the Collateral and deposited with the Trustee in the Collateral Account or with the Senior Credit

100

Facility Representative and other than as set forth in the security documents), to freely operate the Collateral and to collect, invest and dispose of any income thereon.

Release of Collateral

        Upon compliance by the Issuer with the conditions set forth below in respect of any sale, transfer or other disposition, the Trustee will release the Released Interests (as defined below) from the Lien of the indenture and the security documents and reconvey the Released Interests to the Issuer or the grantor of the Lien on such property. The Issuer will have the right to obtain a release of items of Collateral (the "Released Interests") subject to any sale, transfer or other disposition, or owned by a Subsidiary the Capital Stock of which is sold in compliance with the indenture such that it ceases to be a Subsidiary, or that is the subject of a farmout allowed by the terms of the indenture, upon compliance with the condition that the Issuer deliver to the Trustee the following:

•

a notice from the Issuer requesting the release of Released Interests:

        (A)  describing the proposed Released Interests,

        (B)  specifying the value of such Released Interests or such Capital Stock, as the case may be, on a date within 60 days of the Issuer notice (the "Valuation Date"),

        (C)  stating that the consideration to be received is at least equal to the fair market value of the Released Interests, provided that this clause (C) is not applicable with respect to a release to be given in connection with a farmout permitted pursuant to the indenture,

        (D)  stating that the release of such Released Interests will not interfere with the Trustee's ability to realize the value of the remaining Collateral and will not impair the maintenance and operation of the remaining Collateral,

        (E)  confirming the sale or exchange of, or an agreement to sell or exchange, such Released Interests or such Capital Stock, as the case may be, is a bona fide sale to or exchange with a Person that is not an Affiliate of the Issuer or, in the event that such sale or exchange is to or with a Person that is an Affiliate, confirming that such sale or exchange is made in compliance with the provisions summarized in the description of certain covenants under "Limitation on Transactions with Affiliates," provided that this clause (E) is not applicable with respect to a release to be given in connection with a farmout permitted pursuant to the indenture,

        (F)  in the event there is to be a contemporaneous substitution of property for the Collateral subject to the sale, transfer or other disposition, specifying the property intended to be substituted for the Collateral to be disposed of; and

        (G)  with respect to a release to be given in connection with a farmout permitted pursuant to the indenture stating that the farmout to which the released interests are (or are to be) subject complies with the indenture;

•

an officer's certificate of the Issuer stating that:

        (A)  such sale, transfer or other disposition complies with the terms and conditions of the indenture, including the provisions summarized in the description of certain covenants under "Limitation on Asset Sales," "Limitation on Transactions with Affiliates," "Farmouts" and "Limitation on Restricted Payments" above, to the extent any of the foregoing are applicable,

        (B)  all Net Cash Proceeds from the sale, transfer or other disposition of any of the Released Interests or such Capital Stock, as the case may be, will be applied pursuant to the provisions of the indenture in respect of the deposit of proceeds into the Collateral Account or with the Senior Credit Facility Representative as contemplated by the indenture and in

101

respect of Asset Sales, to the extent applicable, provided that this clause (B) is not applicable with respect to a release to be given in connection with a farmout permitted pursuant to the indenture,

        (C)  there is no Default or Event of Default in effect or continuing on the date thereof or the date of such sale, transfer or other disposition,

        (D)  the release of the Collateral will not result in a Default or Event of Default under the indenture,

        (E)  upon delivery of such officer's certificate, all conditions precedent in the indenture relating to the release in question will have been complied with,

        (F)  such sale, transfer or other disposition is not between the Issuer or any Subsidiary or between Subsidiaries, provided that this clause (F) is not applicable with respect to a release to be given in connection with a farmout permitted pursuant to the indenture, and

        (G)  such sale, transfer or other disposition is not a sale, transfer or other disposition that is excluded from the definition of "Asset Sale" because it was a sale, lease, conveyance, disposition or other transfer of all or substantially all of the assets of the Issuer in a transaction which was made in compliance with the provisions of the covenants described under "Merger, Consolidation and Sale of Assets," provided that this clause (G) is not applicable with respect to a release to be given in connection with a farmout permitted pursuant to the indenture; and

•

all documentation required by the Trust Indenture Act, if any, prior to the release of Collateral by the Trustee and, in the event there is to be a contemporaneous substitution of property for the Collateral subject to such sale, transfer or other disposition, all documentation necessary to effect the substitution of such new Collateral.

        Notwithstanding the provisions described above, so long as no Event of Default shall have occurred and be continuing, the Issuer may, without satisfaction of the conditions described above, dispose of Hydrocarbons or other mineral products for value in the ordinary course and engage in any number of ordinary course activities in respect of the Collateral, in limited dollar amounts specified by the Trust Indenture Act, upon satisfaction of certain conditions. For example, among other things, subject to certain dollar limitations and conditions, the Issuer would be permitted to:

•

sell or otherwise dispose of any property subject to the Lien of the indenture and the security documents, which may have become worn out or obsolete;



•

abandon, terminate, cancel, release or make alterations in or substitutions of any leases or contracts subject to the Lien of the indenture or any of the security documents;



•

surrender or modify any franchise, license or permit subject to the Lien of the indenture or any of the security documents which it may own or under which it may be operating;



•

alter, repair, replace, change the location or position of and add to its structures, machinery, systems, equipment, fixtures and appurtenances;



•

demolish, dismantle, tear down or scrap any obsolete Collateral or abandon any portion thereof; and



•

grant leases or sub-leases in respect of real property to the extent the foregoing does not constitute an Asset Sale.

102

Deposit; Use and Release of Trust Moneys

        The Net Cash Proceeds associated with any Asset Sale and any Net Cash Proceeds associated with any sale, transfer or other disposition of Collateral, to the extent such sale, transfer or other disposition is not an Asset Sale by virtue of clause (F) of the definition thereof, insurance proceeds with respect to any Collateral and condemnation (or similar) proceeds with respect to any Collateral shall be deposited so long as any Indebtedness under the Senior Credit Agreement or any Qualified Senior Affiliate Indebtedness remains outstanding, with the Senior Credit Facility Representative and otherwise into a securities account maintained by the Trustee at its corporate trust offices or at any securities intermediary selected by the Trustee having a combined capital and surplus of at least $250,000,000 and having a long-term debt rating of at least "A3" by Moody's and at least "A—" by S&P styled the "Abraxas Collateral Account" (such account being the "Collateral Account") which shall be under the exclusive dominion and control of the Trustee. All amounts on deposit in the Collateral Account shall be treated as financial assets and cash funds on deposit in the Collateral Account may be invested by the Trustee, at the direction of the Issuer, in Cash Equivalents. The Issuer will not have the right to withdraw funds or assets from the Collateral Account except in compliance with the terms of the indenture and all assets credited to the Collateral Account shall be subject to a Lien in favor of the Trustee and the holders.

        Any funds deposited with the Trustee may be released to the Issuer by its delivering to the Trustee an officer's certificate stating:

•

no Event of Default has occurred and is continuing as of the date of the proposed release;



•

if:

        (A)  such Trust Moneys represent Collateral Proceeds in respect of an Asset Sale, that such funds are otherwise being applied in accordance with the covenant "Limitation on Asset Sales" above, or

        (B)  such Trust Moneys represent proceeds in respect of a casualty, expropriation or taking, such funds will be applied to repair or replace property subject of a casualty or condemnation or reimburse the Issuer for amounts spent to repair or replace such property and that attached thereto are invoices or other evidence reflecting the amounts spent or to be spent, or

        (C)  such Trust Moneys represent proceeds derived from any other manner, that such amounts are being utilized in connection with business of the Issuer and its Subsidiaries in compliance with the terms of the indenture; and

•

all conditions precedent in the indenture relating to the release in question have been complied with; and



•

all documentation required by the Trust Indenture Act, if any, prior to the release of such Trust Moneys by the Trustee has been delivered to the Trustee.

        Notwithstanding the foregoing,

•

if the maturity of the notes has been accelerated, and the acceleration has not been rescinded as permitted by the indenture, the Trustee shall apply the Trust Moneys credited to the Collateral Account, subject to the rights of the Senior Credit Facility Lenders under the Intercreditor Agreement, to pay the principal of, premium, if any and accrued and unpaid interest on the notes to the extent of such Trust Moneys;



•

if the Issuer so elects, by giving written notice to the Trustee, the Trustee shall apply Trust Moneys credited to the Collateral Account to the payment of interest due on any interest payment date; and

103

•

if the Issuer so elects, by giving written notice to the Trustee, the Trustee shall apply Trust Moneys credited to the Collateral Account to Pay Down Debt.

Legal Defeasance and Covenant Defeasance

        As long as the Issuer takes steps to make sure that holders will receive all of their payments under the notes and are able to transfer the notes, the Issuer can elect to legally release itself and any of the Subsidiary Guarantors for any Obligations on the notes (called "Legal Defeasance") other than:

•

the rights of holders to receive payments from the trust described below in respect of the principal of, premium, if any, and interest on the notes when such payments are due;



•

the Issuer's obligations with respect to the notes to issue temporary notes, register notes, replace mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payments;



•

the rights, powers, trust, duties and immunities of the Trustee; and



•

the Legal Defeasance provisions of the indenture.

        In addition, the Issuer may, at its option and at any time, elect to have the obligations of the Issuer and the Subsidiary Guarantors, if any, released with respect to certain covenants that are described in the indenture ("Covenant Defeasance"). In the event Covenant Defeasance occurs, certain events (other than non-payment, bankruptcy, receivership, reorganization and insolvency events and maintenance of the Guarantees) described under "Events of Default" will no longer constitute an Event of Default with respect to the notes. The occurrence of either Legal Defeasance or Covenant Defeasance would result in a release of all Collateral from the Lien of the indenture and the security documents.

        In order to exercise either Legal Defeasance or Covenant Defeasance:

•

the Issuer must irrevocably deposit with the Trustee, in trust, for the benefit of the holders cash in U.S. dollars and/or non-callable U.S. government obligations in such amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, premium, if any, and interest on the notes at maturity or redemption, as the case may be:



•

in the case of Legal Defeasance, the Issuer must deliver to the Trustee an opinion of counsel in the United States reasonably acceptable to the Trustee confirming that:

        (A)  the Issuer has received from, or there has been published by, the Internal Revenue Service a ruling, or

        (B)  since the Issue Date, there has been a change in the applicable federal income tax law,

in either case to the effect that the holders will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

•

in the case of Covenant Defeasance, the Issuer must deliver to the Trustee an opinion of counsel in the United States reasonably acceptable to the Trustee confirming that the holders will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

104

•

no Default or Event of Default shall have occurred and be continuing on the date of such deposit or insofar as Events of Default from bankruptcy or insolvency events are concerned, at any time in the period ending on the 91st day after the date of deposit;



•

such Legal Defeasance or Covenant Defeasance shall not result in a breach or violation of, or constitute a default under the indenture or any other agreement or instrument to which the Issuer or any of its Subsidiaries is a party or by which the Issuer or any of its Subsidiaries is bound;



•

the Issuer must deliver an officer's certificate to the Trustee stating that the deposit was not made by the Issuer with the intent of preferring the holders over any other creditors of the Issuer or with the intent of defeating, hindering, delaying or defrauding any other creditors of the Issuer or others;



•

the Issuer must deliver an officer's certificate and an opinion of counsel to the Trustee, each stating that all conditions precedent provided for or relating to the Legal Defeasance or the Covenant Defeasance, as the case may be, have been complied with; and



•

the Issuer must deliver an opinion of counsel to the Trustee to the effect that after the 91st day following the deposit, the trust funds will not be subject to the effect of any applicable bankruptcy, insolvency, reorganization or similar laws affecting creditors' rights generally.

Satisfaction and Discharge

        The Issuer and the Subsidiary Guarantors will have no further obligations under the indenture, the security documents and the Guarantees as to all outstanding notes, other than surviving rights of registration of transfer or exchange of the notes, when:

•

either

        (A)  all the notes have been delivered to the Trustee for cancellation except for (i) lost, stolen or destroyed notes which have been replaced or paid, and (ii) notes for whose payment money has been deposited in trust by the Issuer or segregated and held in trust by the Issuer and thereafter repaid to the Issuer or discharged from such trust, or

        (B)  all notes not theretofore delivered to the Trustee for cancellation have become due and payable, or are to become due and payable within 180 days, and the Issuer has deposited with the Trustee funds sufficient to pay and discharge the entire Indebtedness on such notes at maturity or redemption, as the case may be;

•

the Issuer has paid all other sums payable under the indenture by the Issuer; and



•

the Issuer has delivered to the Trustee an officer's certificate and an opinion of counsel stating that the Issuer has complied with all conditions precedent under the indenture relating to the satisfaction and discharge of the indenture.

Modification of the Indenture

        From time to time, the Issuer, the Subsidiary Guarantors and the Trustee, without the consent of the holders, may amend the indenture, the notes, the Guarantees, the Intercreditor Agreement or any security document for certain specified purposes, including curing ambiguities, defects or inconsistencies, to comply with any requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act or to make any change that would provide any additional benefit or rights to the holders or that does not adversely affect the rights of any holder. In formulating its opinion on such matters, the Trustee will be entitled to rely on such evidence as it deems appropriate, including, without limitation, solely on an opinion of counsel.

105

        Other modifications and amendments of the indenture, the notes, the Guarantees, the Intercreditor Agreement or any security document may be made with the consent of the holders of not less than a majority of the principal amount of the then outstanding notes issued under the indenture, except that, without the consent of each holder affected thereby, no amendment may:

•

reduce the amount of notes whose holders must consent to an amendment;



•

reduce the rate of or change or have the effect of changing the time for payment of interest, including defaulted interest, on any notes or reduce the amount of liquidated damages payable under the registration rights agreement;



•

reduce the principal of or change or have the effect of changing the fixed maturity of any notes, or change the date on which any notes may be subject to redemption or repurchase, or reduce the redemption or repurchase price therefor;



•

make any notes payable in a currency other than that stated in the notes;



•

make any change in provisions of the indenture, the notes, the Guarantees, the Intercreditor Agreement or any security document protecting the right of each holder to receive payment of principal of and interest on such note on or after the due date thereof or to bring suit to enforce such payment, or permitting holders of a majority in principal amount of notes to waive Defaults or Events of Default;



•

amend, change or modify in any material respect the obligation of the Issuer to make and consummate a Change of Control Offer in the event of a Change of Control or to Pay Down Debt with respect to any Asset Sale that has been consummated or modify any of the provisions or definitions with respect thereto;



•

modify or change any provision of the indenture, the notes, the Guarantees, the Intercreditor Agreement, any security document or the related definitions affecting ranking of the notes or any Guarantee in a manner which adversely affects the holders; or



•

release any Subsidiary Guarantor from any of its obligations under its Guarantee, in any case otherwise than in accordance with the terms of the indenture.

        Also, the indenture will provide that a farmout not otherwise qualifying as a Permitted Farmout Agreement is a Permitted Farmout Agreement if consent to such farmout is obtained from the holders of not less than a majority of the principal amount of the then outstanding notes issued under the indenture.

        The provisions of the Intercreditor Agreement may not be amended without the consent of the Senior Credit Facility Representative.

Governing Law

        The indenture, the notes, the Guarantees and the security documents are governed by, and construed in accordance with, the laws of the State of New York, except to the extent the laws of another jurisdiction may be mandatorily applicable to certain matters under the security documents.

Concerning the Trustee

        U.S. Bank, N.A. acts as Trustee. Its address is 180 East Fifth Street, Saint Paul, Minnesota 55101, attn: Corporate Trust Department.

        Except during the continuance of an Event of Default, the Trustee will perform only such duties as are specifically set forth in the indenture. During the existence of an Event of Default, the Trustee will exercise such rights and powers vested in it by the indenture, and use the same degree of care and skill

106

in its exercise as a prudent man would exercise or use under the circumstances in the conduct of his own affairs.

        The indenture and the provisions of the Trust Indenture Act incorporated by reference into the indenture contain certain limitations on the rights of the Trustee, should it become a creditor of the Issuer or any Subsidiary Guarantor, to obtain payments of claims in certain cases or to realize on certain property received in respect of any such claim as security or otherwise. Subject to the Trust Indenture Act, the Trustee is permitted to engage in other transactions. If the Trustee acquires any conflicting interest as described in the Trust Indenture Act after a Default has occurred and is continuing, it must eliminate such conflict or resign.

Certain Definitions

        Set forth below is a summary of certain of the defined terms that are used in the indenture. Reference is made to the indenture for the full definition of all such terms, as well as any other terms used herein for which no definition is provided.

        "2003 CapEx Amount" equals the lesser of $15 million and the 2003 CapEx Annual Budget.

        "2003 CapEx Annual Budget" equals the 2003 Closing CapEx Ratio multiplied by Total Assets at December 31, 2003.

        "2003 Closing CapEx Ratio" equals, for calendar year 2003, (a) $15 million or such lower amount budgeted prior to the Issue Date by the Issuer for Capital Expenditures for such calendar period, divided by (b) Total Assets at the end of the calendar quarter in which the Issue Date occurs.

        "2004-Plus CapEx Annual Amount" equals for any annual calendar period, the lesser of $10 million and the 2004-Plus CapEx Annual Budget.

        "2004-Plus CapEx Annual Budget" equals, for any annual calendar period, 2004-Plus Closing CapEx Ratio multiplied by the Total Assets at the start of such calendar period.

        "2004-Plus CapEx Quarterly Amount" equals, the lesser of $2.5 million and one quarter of the 2004-Plus CapEx Annual Amount.

        "2004-Plus Closing CapEx Ratio" equals, for any annual calendar period starting January 1, 2004, (a) $10 million or such lower amount budgeted prior to the Issue Date by the Issuer for Capital Expenditures for such calendar period, divided by (b) the Total Assets at the end of the calendar quarter in which the Issue Date occurs.

        "Acquired Indebtedness" means Subordinated Indebtedness of a Person or any of its Subsidiaries the incurrence of which does not violate the terms of the indenture:

        (1)   existing at the time such Person becomes a Subsidiary of the Issuer or at the time it merges or consolidates with the Issuer or any of its Subsidiaries, or

        (2)   which becomes Indebtedness of the Issuer or any of its Subsidiaries in connection with the acquisition of assets from such Person.

        Acquired Indebtedness does not include Indebtedness incurred in connection with, or in anticipation or contemplation of, such Person becoming a Subsidiary of the Issuer or such acquisition, merger or consolidation.

        "Adjusted Consolidated Net Tangible Assets" means (without duplication), as of the date of determination the sum of:

        (1)   Discounted future net revenues from the proved oil and gas reserves of the Issuer and its Subsidiaries, calculated in accordance with SEC guidelines, but before any state or federal income

107

tax, as estimated by a nationally recognized firm of independent petroleum engineers as of a date no earlier than the date of the Issuer's latest annual consolidated financial statements.

        Discounted future net revenues will be increased under clauses (a) and (b) below and decreased under clauses (c) and (d) below, as of the date of determination, by the estimated discounted future net revenues, calculated in accordance with SEC guidelines but before any state of federal income taxes and utilizing the prices utilized in the Issuer's year-end reserve report, from:

        (a)   estimated proved oil and gas reserves acquired since the date of the Issuer's year-end reserve report;

        (b)   estimated oil and gas reserves attributable to upward revisions of estimates of proved oil and gas reserves since the date of the Issuer's year-end reserve report due to exploration, development or exploitation activities,

        (c)   estimated proved oil and gas reserves produced or disposed of since the date of the Issuer's year-end reserve report; and

        (d)   estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since the date of the Issuer's year-end reserve report due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions.

        In the case of each of the determinations made under clauses (a) through (d), all increases and decreases will be as estimated by the Issuer's petroleum engineers, except that in the event that there is a Material Change as a result of acquisitions, dispositions or revisions, then the discounted future net revenues utilized for purposes of this clause will be confirmed by a nationally recognized firm of independent petroleum engineers.

        (2)   The capitalized costs that are attributable to the oil and gas properties of the Issuer and its Subsidiaries to which no proved oil and gas reserves are attributable, based on the books and records of the Issuer and its Subsidiaries as of a date no earlier than the date of the Issuer's latest annual or quarterly financial statements.

        (3)   The Net Working Capital plus cash of the Issuer and its Subsidiaries on a date no earlier than the date of the Issuer's latest consolidated annual or quarterly financial statements.

        (4)   The greater of

        (a)   the net book value of other tangible assets of the Issuer and its Subsidiaries on a date no earlier than the date of the Issuer's latest consolidated annual or quarterly financial statements, or

        (b)   the appraised value, as estimated by independent appraisers, of other tangible assets of the Issuer and its Subsidiaries as of a date no earlier than the date of the Issuer's latest audited financial statements.

Minus the sum of

        (1)   Minority interests; and

        (2)   Any gas balancing liabilities as reflected in the Issuer's latest audited financial statements.

108

        Calculations of "Adjusted Consolidated Net Tangible Assets" will also give effect, on a pro forma basis, to:

•

Any Investment in another Person that becomes Subsidiary and which is not prohibited by the indenture, to and including the date of the transaction for which the calculation is necessary.



•

The acquisition, to and including the date of the transaction, of any business or assets, including Permitted Industry Investments.



•

Any sales or other dispositions of assets permitted by the indenture (except for sales of Hydrocarbons or other mineral products in the ordinary course of business) occurring on or after the date of the transaction.

        "Adjusted Issue Price" means an amount for the most recent accrual period equal to the initial issue price of the notes increased by the amount of original issue discount previously includable in the gross income of a holder, reduced by the amount of any payment previously made on the notes other than a payment of qualified stated interest on the notes.

        "Affiliate" of any specified Person means,

        (1)   any other Person who directly or indirectly through one or more intermediaries controls, or is controlled by, or under common control with, such specified Person; and

        (2)   any Related Person of such Person.

        For purposes of this definition, the term "control" means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise.

        "Asset Acquisition" means:

        (1)   an Investment by the Issuer or any Subsidiary in any other Person in which such Person becomes a Subsidiary, or merges with the Issuer or any Subsidiary; or

        (2)   the acquisition by the Issuer or any Subsidiary of the assets of any Person (other than a Subsidiary) which constitute all or substantially all of the assets of such Person or comprise any division or line of business of such Person or any other properties or assets of such Person other than in the ordinary course of business.

        "Asset Sale" means any sale, issuance, conveyance, transfer, exchange, lease (other than operating leases entered into in the ordinary course of business consistent with past practices), assignment or other transfer for value by the Issuer or any Subsidiary to any Person other than the Issuer or any Subsidiary of:

        (1)   any Capital Stock of any Subsidiary; or

        (2)   any other property or assets of the Issuer or any Subsidiary and any interests therein, including any disposition by a merger, consolidation or similar transaction.

        For purposes of this definition, the term "Asset Sale" does not include:

        (A)  the sale, lease, conveyance, disposition or other transfer of all or substantially all of the assets of the Issuer in a transaction which is made in compliance with the provisions of the covenant described in "Merger, Consolidation and Sale of Assets;"

        (B)  disposals or replacements of obsolete equipment in the ordinary course of business;

        (C)  the sale, lease, conveyance, disposition or other transfer of assets or property to the Issuer or one or more Wholly Owned Subsidiaries;

109

        (D)  any disposition of Hydrocarbons or other mineral products for value in the ordinary course of business;

        (E)  the abandonment, surrender, termination, cancellation, release, lease or sublease of undeveloped oil and gas properties in the ordinary course of business or oil and gas properties which are not capable of production in economic quantities;

or

        (F)  the sale, lease, conveyance, disposition or other transfer by the Issuer or any Subsidiary of assets or property in the ordinary course of business if the total fair market value of all the assets and property sold, leased, conveyed, disposed or transferred since the Issue Date under this exception does not exceed $200,000 in any one year.

        "Available Proceeds Amount" means:

        (1)   The sum of all Collateral Proceeds and all Non-Collateral Proceeds remaining after application to repay any Indebtedness secured by the assets that are the subject of the Asset Sale giving rise to such Non-Collateral Proceeds.

        (2)   For the purpose of determining whether the Issuer must Pay Down Debt in connection with an Asset Sale and for determining the amount of such offer an amount equal to the amount set forth under clause (1) above minus the total amount of all of those Asset Sale proceeds previously spent in compliance with the terms of the section described under "Deposit; Use and Release of Trust Moneys."

        "CapEx Deficit Amount" equals, in any calendar quarter, the amount by which the Capital Expenditures in any such calendar quarter (excluding the amount of Capital Expenditures due to any Rollover Decrease because of a prior quarter's CapEx Excess Amount) is less than the applicable CapEx Quarterly Amount.

        "CapEx Excess Amount" equals, in any calendar quarter, the amount by which Capital Expenditures in any such quarter (excluding the amount of Capital Expenditures due to any Rollover Increase because of a prior quarter's CapEx Deficit Amount) exceed the applicable CapEx Quarterly Amount.

        "CapEx Quarterly Amount" means the Q1-2003 CapEx Amount, the Q2,3,4-2003 CapEx Amount or the 2004-Plus CapEx Quarterly Amount, as applicable.

        "Capital Expenditures" means, for any period, any direct or indirect expenditure made in such period, in each case, whether expensed or capitalized, in respect of the use of assets, including all Drilling Expenditures, and shall include all investments and cash expenses and other cash outflows of the Issuer and its Subsidiaries related to any Permitted Investments including but not limited to those relating to joint ventures, royalty arrangements, off-balance sheet financing, and farmout expenditures made by the Issuer or its Subsidiaries, and expenditures made in such period in any Investment other than Investments in cash equivalents or government backed securities, but excluding from the definition of "Capital Expenditures" any expenditures by the Issuer or any of its Subsidiaries to the extent the source of funds for which expenditures was the proceeds of an equity offering by the Issuer consummated after the Issue Date or the proceeds of any Subordinated Indebtedness incurred by the Issuer or any of its Subsidiaries after the Issue Date in compliance with the terms of the indenture, and further excluding from the definition of "Capital Expenditures" any expenditures by the Issuer or any of its Subsidiaries to the extent such expenditures constitute SG&A not prohibited by the terms of the indenture, and further excluding from the definition of "Capital Expenditures" any expenditures by the Issuer or any of its Subsidiaries for Qualified Lease Operating Costs.

110

        "Capitalized Lease Obligation" means the discounted present value of the rental obligations under a lease or similar agreement that is required to be classified and accounted for as a capital lease under GAAP.

        "Capital Stock" means:

        (1)   with respect to a corporation, any and all shares, interests, participations or other equivalents of corporate stock, including each class of common stock and Preferred Stock and including any warrants, options or rights to acquire any of the foregoing and instruments convertible into any of the foregoing, and

        (2)   with respect to any Person that is not a corporation, any and all partnership or other equity interests of such Person.

        "Cash Coupon" means 11¹/2% or such higher coupon payable in cash to the holders of the notes pursuant to the indenture.

        "Cash Equivalents" means:

        (1)   marketable direct obligations issued by, or unconditionally guaranteed by, the United States Government or issued by one of its agencies and backed by the full faith and credit of the United States, in each case maturing within one year from the date of acquisition;

        (2)   marketable direct obligations issued by any state of the United States of America or any of its political subdivisions or public instrumentalities maturing within one year from the date of acquisition and, at the time of acquisition, having one of the two highest ratings obtainable from either S&P or Moody's;

        (3)   commercial paper maturing no more than one year from its date of creation and, at the time of acquisition, having a rating of at least A-1 from S&P or at least P-1 from Moody's;

        (4)   certificates of deposit or bankers' acceptances maturing within one year from the date of acquisition issued by any domestic bank or any United States branch of a foreign bank having capital and surplus of at least $250,000,000;

        (5)   repurchase obligations with a term of not more than seven days for underlying securities of the types described in clause (1) above entered into with any bank meeting the qualifications specified in clause (4) above; and

        (6)   money market mutual or similar funds having assets in excess of $100,000,000.

        "Change of Control" means the occurrence of any of the following:

        (1)   any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Issuer to any Person or group of related Persons for purposes of Section 13(d) of the Exchange Act;

        (2)   the adoption of any plan or proposal for the liquidation or dissolution of the Issuer;

        (3)   any Person or group becomes the owner, directly or indirectly, beneficially or of record, of shares representing more than 35% of the aggregate ordinary voting power represented by the issued and outstanding Capital Stock of the Issuer; or

        (4)   the replacement of a majority of the Board of Directors of the Issuer over a two-year period from the directors who constituted the Board of Directors of the Issuer at the beginning of such period with directors whose replacement was not approved by a vote of at least a majority of the Board of Directors of the Issuer then still in office who either were members at the beginning of such period or whose election as a member was previously so approved.

111

        "Closing SG&A Ratio" means, for any applicable calendar period, (a) $5 million or such lower amount budgeted prior to the Issue Date by the Issuer for SG&A for such calendar period divided by (b) the Total Assets at the end of the calendar quarter in which the Issue Date occurs.

        "Collateral" means, collectively, all of the property and assets (including Trust Moneys) that are from time to time subject to, or purported to be subject to, the Lien of the indenture or any of the security documents.

        "Collateral Proceeds" means any Net Cash Proceeds received from an Asset Sale of Collateral.

        "Consolidated EBITDA" means, for any period, the sum (without duplication), on a consolidated basis and determined in accordance with GAAP, of:

        (1)   Consolidated Net Income, and

        (2)   to the extent Consolidated Net Income has been reduced thereby,

        (a)   all income taxes paid or accrued by the Issuer or any Subsidiary in accordance with GAAP for such period except for income taxes attributable to extraordinary, unusual or nonrecurring gains or losses or taxes attributable to sales or dispositions outside the ordinary course of business,

        (b)   Consolidated Interest Expense,

        (c)   the amount of any Preferred Stock dividends paid by the Issuer, and

        (d)   Consolidated Non-cash Charges, less any non-cash items increasing Consolidated Net Income for such periods.

        "Consolidated EBITDA Coverage Ratio" means the ratio of:

        (1)   Consolidated EBITDA during the four full fiscal quarters for which financial information is available (the "Four Quarter Period") ending on or prior to the date of the transaction giving rise to the need to calculate the Consolidated EBITDA Coverage Ratio (the "Transaction Date") to;

        (2)   Consolidated Fixed Charges for the Four Quarter Period.

        For purposes of this definition, "Consolidated EBITDA" and "Consolidated Fixed Charges" will be calculated after giving effect, without duplication, on a pro forma basis for the calculation period to:

        (1)   the incurrence or repayment of

        (a)   Indebtedness giving rise to the need to make such calculation, and

        (b)   other Indebtedness, other than the incurrence or repayment of Indebtedness in the ordinary course of business for working capital purposes pursuant to working capital facilities,

occurring during the Four Quarter Period or at any time subsequent to the last day of the Four Quarter Period and on or prior to the Transaction Date, as if such incurrence or repayment, as the case may be, occurred on the first day of the Four Quarter Period, and

        (2)   any Asset Sales or Asset Acquisitions occurring during the Four Quarter Period or at any time subsequent to the last day of the Four Quarter Period and on or prior to the Transaction Date, as if such Asset Sale or Asset Acquisition occurred on the first day of the Four Quarter Period. If the Issuer or any Subsidiary guarantees Indebtedness of a third Person, the preceding sentence will give effect to the incurrence of such guaranteed Indebtedness as if the Issuer or such Subsidiary had directly incurred or otherwise assumed such guaranteed Indebtedness.

112

        In addition, in calculating "Consolidated Fixed Charges" for purposes of determining the denominator (but not the numerator) of the Consolidated EBITDA Coverage Ratio:

        (1)   interest on outstanding Indebtedness determined on a fluctuating basis as of the Transaction Date and which will continue to be so determined thereafter shall be deemed to have accrued at a fixed rate equal to the rate of interest on such Indebtedness in effect on the Transaction Date;

        (2)   if interest on any Indebtedness actually incurred on the Transaction Date may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a Eurocurrency interbank offered rate, or other rates, then the interest rate in effect on the Transaction Date will be deemed to have been in effect during the Four Quarter Period;

        (3)   notwithstanding clauses (1) and (2) above, interest on Indebtedness determined on a fluctuating basis, to the extent such interest is covered by agreements relating to Interest Swap Obligations, will be deemed to accrue at the rate per annum resulting after giving effect to the operation of such agreements.

        "Consolidated EBITDA to Cash Interest Expense Ratio" means, with respect to the last day of a particular fiscal quarter of the Issuer, the ratio of:

        (1)   Consolidated EBITDA during such fiscal quarter to;

        (2)   Consolidated Interest Expense paid in cash for such fiscal quarter.

        For purposes of this definition, "Consolidated EBITDA" and "Consolidated Interest Expense" will be calculated after giving effect, without duplication, on a pro forma basis for the calculation period to:

        (1)   the incurrence or repayment of Indebtedness, other than the incurrence or repayment of Indebtedness in the ordinary course of business for working capital purposes pursuant to working capital facilities, occurring during the relevant fiscal quarter as if such incurrence or repayment, as the case may be, occurred on the first day of the relevant fiscal quarter, and

        (2)   any Asset Sales or Asset Acquisitions occurring during the relevant fiscal quarter as if such Asset Sale or Asset Acquisition occurred on the first day of the relevant fiscal quarter. If the Issuer or any Subsidiary guarantees Indebtedness of a third Person, the preceding sentence will give effect to the incurrence of such guaranteed Indebtedness as if the Issuer or such Subsidiary had directly incurred or otherwise assumed such guaranteed Indebtedness.

        In addition, in calculating "Consolidated Interest Expense" for purposes of determining the denominator (but not the numerator) of the Consolidated EBITDA to Cash Interest Expense Ratio:

        (1)   interest on outstanding Indebtedness determined on a fluctuating basis as of the last day of the relevant fiscal quarter of the Issuer and which will continue to be so determined thereafter shall be deemed to have accrued at a fixed rate equal to the rate of interest on such Indebtedness in effect on such day;

        (2)   if interest on any Indebtedness actually incurred on the last day of the relevant fiscal quarter of the Issuer may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate, or other rates, then the interest rate in effect on such day will be deemed to have been in effect during the relevant fiscal quarter; and

        (3)   notwithstanding clauses (1) and (2) above, interest on Indebtedness determined on a fluctuating basis, to the extent such interest is covered by agreements relating to Interest Swap Obligations, will be deemed to accrue at the rate per annum resulting after giving effect to the operation of such agreements.

113

        "Consolidated Fixed Charges" means the sum, without duplication, of:

        (1)   Consolidated Interest Expense including any premium or penalty paid in connection with redeeming or retiring Indebtedness prior to the stated maturity, and

        (2)   the product of

        (a)   the amount of all dividend payments on any series of the Issuer's Preferred Stock (other than dividends paid in Qualified Capital Stock) paid, accrued or scheduled to be paid or accrued during such period, times

        (b)   a fraction, the numerator of which is one and the denominator of which is one minus the then current effective consolidated federal, state and local income tax rate of such Person, expressed as a decimal.

        "Consolidated Interest Expense" for a period means the sum, without duplication, of:

        (1)   the total interest expense of the Issuer and its Subsidiaries for such period determined on a consolidated basis in accordance with GAAP, including

        (a)   any amortization of original issue discount,

        (b)   the net costs under Interest Swap Obligations,

        (c)   all capitalized interest, and

        (d)   the interest portion of any deferred payment obligation;

plus

        (2)   the interest component of Capitalized Lease Obligations paid, accrued and/or scheduled to be paid or accrued by the Issuer and its Subsidiaries during such period, as determined on a consolidated basis in accordance with GAAP.

        "Consolidated Net Income" means, with respect to the Issuer for any period, the aggregate net income (or loss) of the Issuer and its Subsidiaries for such period on a consolidated basis, determined in accordance with GAAP. The following will, however, be excluded from such calculation:

        (1)   after-tax gains from Asset Sales or abandonments or reserves relating thereto,

        (2)   after-tax items classified in accordance with GAAP as extraordinary or nonrecurring gains,

        (3)   the net income of any Person acquired in a "pooling of interests" transaction accrued prior to the date it becomes a Subsidiary or is merged or consolidated with the Issuer or any Subsidiary,

        (4)   the net income of any Subsidiary to the extent that the declaration of dividends or similar distributions by that Subsidiary of that income is restricted by charter, contract, operation of law or otherwise,

        (5)   the net income of any Person in which the Issuer or any Subsidiary has an interest, other than a Subsidiary, except to the extent of cash dividends or distributions actually paid to the Issuer or any Subsidiary by such Person,

        (6)   income or loss attributable to discontinued operations (including, without limitation, operations disposed of during such period whether or not such operations were classified as discontinued), and

114

        (7)   in the case of a successor to the Issuer by consolidation or merger or as a transferee of the Issuer's assets, any net income of the successor corporation prior to such consolidation, merger or transfer of assets.

        "Consolidated Net Worth" of any Person as of any date means

        (1)   the consolidated stockholders' equity of such Person, determined on a consolidated basis in accordance with GAAP, less (without duplication)

        (2)   amounts attributable to Disqualified Capital Stock of such Person.

        "Consolidated Non-cash Charges" means, for any period, total depreciation, depletion, amortization and other non-cash expenses reducing Consolidated Net Income for such period, determined on a consolidated basis in accordance with GAAP, but excluding any such charges constituting an extraordinary item or loss or any such charge which requires an accrual of or a reserve for cash charges for any future period.

        "Consolidation" means, with respect to any Person, the consolidation of the accounts of the Subsidiaries of such Person with those of such Person, all in accordance with GAAP.

        "Crude Oil and Natural Gas Business" means:

        (1)   the acquisition, exploration, development, operation and disposition of interests in oil, gas and other hydrocarbon properties located in North America, and

        (2)   the gathering, marketing, treating, processing, storage, selling and transporting of any production from such interests or properties of the Issuer or those of others.

        "Crude Oil and Natural Gas Hedge Agreements" means any oil and gas agreements and other agreements or arrangements entered into by a Person in the ordinary course of business and that is designed to provide protection against oil and natural gas price fluctuations.

        "Crude Oil and Natural Gas Properties" means all Properties, including equity or other ownership interests in those Properties, owned by any Person which have been assigned "proved oil and gas reserves" as defined in Rule 4-10 of Regulation S-X of the Securities Act as in effect on the Issue Date.

        "Crude Oil and Natural Gas Related Assets" means any Investment or capital expenditure (but not including additions to working capital or repayments of any revolving credit or working capital borrowings) by the Issuer or any Subsidiary which is related to the business of the Issuer and its Subsidiaries as it is conducted on the date of the Asset Sale giving rise to the Net Cash Proceeds to be reinvested.

        "Currency Agreement" means any foreign exchange contract, currency swap agreement or other similar agreement or arrangement designed to protect against fluctuations in currency values.

        "Default" means an event or condition that is, or with the lapse of time or the giving of notice or both would be, an Event of Default.

        "Disqualified Capital Stock" means any Capital Stock which, by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or is mandatorily redeemable at the sole option of the holder thereof, in whole or in part, in either case, on or prior to the final maturity of the notes.

        "Drilling Expenditures" means any direct or indirect expenditure, in each case, whether expensed or capitalized, in respect of drilling.

        "Eastside Coal" means Eastside Coal Company, Inc., a Colorado corporation.

115

        "Excess Cash Flow" means, for any period, Consolidated EBITDA of the Issuer and its Subsidiaries for such period, minus any increase in the Net Working Capital of the Issuer and its Subsidiaries from the beginning of such period to the end of a such period or plus any decrease in the Net Working Capital of the Issuer and its Subsidiaries from the beginning of such period to the end of a such period (as the case may be), minus Capital Expenditures made by the Issuer and its Subsidiaries during that period to the extent such Capital Expenditures did not reduce Consolidated EBITDA, minus any cash interest paid by the Issuer and its Subsidiaries during that period, minus any cash taxes paid by the Issuer and its Subsidiaries during that period, minus any amount applied by the Issuer and its Subsidiaries to Pay Down Debt during that period, minus (to the extent included in Consolidated EBITDA) any proceeds received during that period from any equity offering by the Issuer or from any Subordinated Indebtedness of the Issuer or any of its Subsidiaries.

        "Equity Offering" means an offering of the Issuer's Qualified Capital Stock.

        "Fair market value" means, with respect to any asset or property, the price which could be negotiated in an arm's-length, free market transaction, for cash, between an informed and willing seller and an informed and willing buyer, neither of whom is under undue pressure or compulsion to complete the transaction. Fair market value shall be determined by the Board of Directors of the Issuer acting reasonably and in good faith; provided, however, that if the aggregate non-cash consideration to be received by the Issuer or any Subsidiary from any Asset Sale shall reasonably be expected to exceed $5,000,000, then fair market value shall be determined by an Independent Advisor.

        "GAAP" means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board as of any date of determination.

        "Hydrocarbons" means oil, gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products processed therefrom.

        "Indebtedness" means with respect to any Person, without duplication:

        (1)   all Obligations for borrowed money,

        (2)   all Obligations evidenced by bonds, debentures, notes or other similar instruments,

        (3)   all Capitalized Lease Obligations,

        (4)   all Obligations for the deferred purchase price of property, all conditional sale obligations and all Obligations under any title retention agreement but excluding trade accounts payable,

        (5)   all Obligations for the reimbursement of any obligor on a letter of credit, banker's acceptance or similar credit transaction,

        (6)   guarantees and other contingent obligations in respect of Indebtedness referred to in clauses (1) through (5) above and clause (8) below,

        (7)   all Obligations of any other Person of the type referred to in clauses (1) through (6) above which are secured by any Lien on any property or asset of such Person, the amount of such Obligation being deemed to be the lesser of the fair market value of such property or asset or the amount of the Obligation so secured,

        (8)   all Obligations under Currency Agreements and Interest Swap Obligations,

        (9)   all Disqualified Capital Stock issued by such Person with the amount of Indebtedness represented by such Disqualified Capital Stock being equal to the greater of its voluntary or

116

involuntary liquidation preference and its maximum fixed redemption price or repurchase price; and

        (10) all Obligations in respect of production payments and forward sales.

        For purposes of this definition:

        (1)   the "maximum fixed repurchase price" of any Disqualified Capital Stock which does not have a fixed repurchase price shall be calculated in accordance with the terms of such Disqualified Capital Stock as if it were purchased on any date on which Indebtedness shall be required to be determined pursuant to the indenture, and if such price is based upon, or measured by, the fair market value of the Disqualified Capital Stock, the fair market value shall be determined reasonably and in good faith by the Board of Directors of the Issuer.

        (2)   The "amount" or "principal amount" of Indebtedness at any time will be:

        (a)   for any Indebtedness issued at a price that is less than its principal amount at maturity, the face amount of the liability,

        (b)   for any Capitalized Lease Obligation, the amount determined in accordance with its definition above,

        (c)   for any Interest Swap Obligations included in the definition of Permitted Indebtedness, zero,

        (d)   for all other unconditional obligations, the amount determined in accordance with GAAP, and

        (e)   for all other contingent obligations, the maximum liability at such date of such Person.

        "Independent Advisor" means a reputable accounting, appraisal or nationally recognized investment banking, engineering or consulting firm which:

        (1)   does not, and whose directors, officers and employees or Affiliates do not, have a direct or indirect material financial interest in the Issuer, and

        (2)   in the judgment of the Board of Directors of the Issuer, is otherwise disinterested, independent and qualified to perform the task for which it is to be engaged.

        "Intercreditor Agreement" means the Intercreditor Agreement to be dated on or about the Issue Date entered into by the Senior Credit Facility Representative and the Trustee and also acknowledged by the Issuer and certain Subsidiaries of the Issuer, or any successor or replacement agreement, as such agreement has been or may be amended (including any amendment and restatement thereof), supplemented, replaced, restated or otherwise modified from time to time.

        "Interest Swap Obligation" means obligations under interest rate swaps, caps, floors, collars and similar agreements, whereby, directly or indirectly, a Person is entitled to receive payments calculated by applying either a floating or a fixed rate of interest on a stated notional amount in exchange for payments made by another Person calculated by applying a fixed or a floating rate of interest on the same notional amount.

        "Investment" by a Person means any direct or indirect:

        (1)   loan, advance or other extension of credit (including a guarantee) or capital contribution to others,

        (2)   purchase or acquisition of any Capital Stock, bonds, notes, debentures or other securities or evidences of Indebtedness issued by another Person,

117

        (3)   guarantee or assumption of the Indebtedness of another Person (other than the guarantee or assumption of Indebtedness of the Person or a Subsidiary of the Person which is made in compliance with the provisions of "Certain Covenants—Limitation on Incurrence of Additional Indebtedness" above), and

        (4)   other items that would be classified as investments on a balance sheet of such Person prepared in accordance with GAAP.

        Notwithstanding the foregoing, "Investment" excludes extensions of trade credit on commercially reasonable terms in accordance with the normal trade practices of the Issuer and its Subsidiaries. The amount of any Investment will not be adjusted for increases or decreases in value, or write-ups, write-downs or write-offs with respect to that Investment. If the Issuer or its Subsidiaries sell or otherwise dispose of any Capital Stock of any Subsidiary such that, after giving effect to any such sale or disposition, it ceases to be a Subsidiary of the Issuer, the Issuer will be deemed to have made an Investment on the date of any such sale or disposition equal to the fair market value of the Capital Stock of such Subsidiary not sold or disposed of.

        "Issue Date" means the date of original issuance of the notes.

        "Issuer" means Abraxas Petroleum Corporation, a Nevada corporation.

        "Issuer Properties" means all Properties, and equity, partnership or other ownership interests therein, that are related or incidental to, or used or useful in connection with, the conduct or operation of any business activities of the Issuer or any of its Subsidiaries, which business activities are not prohibited by the terms of the indenture.

        "Lien" means any lien, mortgage, deed of trust, pledge, security interest, floating or other charge or encumbrance of any kind (including any conditional sale or other title retention agreement, any lease in the nature thereof and any agreement to give any security interest).

        "Material Change" means an increase or decrease of more than 10% during a fiscal quarter in the discounted future net cash flows (excluding changes that result solely from changes in prices) from proved oil and gas reserves of the Issuer and its Subsidiaries (before any state or federal income tax); provided, however, that the following will be excluded from the calculation of Material Change:

        (1)   any acquisitions during the quarter of oil and gas reserves that have been estimated by independent petroleum engineers and on which a report or reports exist,

        (2)   any disposition of properties existing at the beginning of such quarter that have been disposed of as provided in "Limitation on Asset Sales," and

        (3)   any reserves added during the quarter attributable to the drilling or recompletion of wells not included in previous reserve estimates, but which will be included in future quarters.

        "Mortgage" means a mortgage or deed of trust dated as of the Issue Date granted by the Issuer or any Subsidiary for the benefit of the Trustee and the holders, as the same may be amended, supplemented or modified from time to time in accordance with the terms thereof and of the indenture.

        "Net Cash Proceeds" means the proceeds in the form of cash or Cash Equivalents including payments in respect of deferred payment obligations when received in the form of cash or Cash Equivalents received by the Issuer or any Subsidiary from any Asset Sale, sale, transfer or other disposition net of:

        (1)   reasonable out-of-pocket expenses and fees relating to such Asset Sale, sale, transfer or other disposition (including, without limitation, legal, accounting and investment banking fees and sales commissions),

118

        (2)   taxes paid or payable after taking into account any reduction in consolidated tax liability due to available tax credits or deductions and any tax sharing arrangements,

        (3)   appropriate amounts (determined by the Chief Financial Officer of the Issuer) to be provided by the Issuer or any Subsidiary, as the case may be, as a reserve, in accordance with GAAP, against any post closing adjustments or liabilities associated with such Asset Sale, sale, transfer or other disposition and retained by the Issuer or any Subsidiary, as the case may be, after such Asset Sale, sale, transfer or other disposition, including pension and other post-employment benefit liabilities, liabilities related to environmental matters and liabilities under any indemnification obligations associated with such Asset Sale, sale, transfer or other disposition (but excluding any payments which, by the terms of the indemnities will not, be made during the term of the notes), and

        (4)   the aggregate amount of cash and Cash Equivalents so received which is used to retire any then existing Indebtedness (other than Indebtedness under the Senior Credit Agreement, Qualified Senior Affiliate Indebtedness or the notes) which is secured by a Lien on the property subject of the Asset Sale, sale, transfer or other disposition.

        "Net Working Capital" means:

        (1)   all current assets of the Issuer and its Subsidiaries, minus

        (2)   all current liabilities of the Issuer and its Subsidiaries, except current liabilities included in Indebtedness, minus

        (3)   all cash of the Issuer and its Subsidiaries,

in each case as set forth in the Issuer's financial statements prepared in accordance with GAAP.

        "Obligations" means any principal, premium, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness.

        "Oil and Gas Assets" means the Crude Oil and Natural Gas Properties and natural gas processing facilities of the Issuer and/or any of its Subsidiaries.

        "Pay Down Debt" means:

•

first, making a payment under the Senior Credit Agreement with a permanent reduction of the indebtedness outstanding under the Senior Credit Agreement to the extent making a payment on the Senior Credit Agreement with a permanent reduction of the indebtedness outstanding under the Senior Credit Agreement is required under the terms of the Senior Credit Agreement and/or the Intercreditor Agreement,



•

second, making a payment of principal and/or accrued interest on, or redeeming, exchanging, discharging, defeasing, or purchasing and retiring, notes in whole or in part, to the extent permitted by the Senior Credit Agreement and the Intercreditor Agreement,



•

third, (i) first, making scheduled or mandatory paydowns on Indebtedness under the Senior Credit Agreement and paying down any term loans under the Senior Credit Agreement to the extent permitted by the Senior Credit Agreement, whether or not then due and payable ("Term Loan Paydowns"), and if all Term Loan Paydowns are made (the "Term Loan Amounts") so that such outstanding amounts under the Senior Credit Agreement have been paid down completely, then (ii) second, any amount remaining after payment of the Term Loan Amounts will be applied to outstanding amounts under any revolving credit tranche under the Senior Credit Agreement for permanent reduction of the commitment under the revolving credit tranche, and

119

if no amounts are outstanding under any such revolving credit tranche, then at that time the Issuer will terminate that credit facility, and

•

fourth, making a payment of principal and/or accrued interest on, or redeeming, exchanging, discharging, defeasing, or purchasing and retiring, notes in whole or in part.

        "Permitted Indebtedness" means, without duplication, each of the following:

        (1)   Indebtedness under the notes, the indenture, the Guarantees and the security documents;

        (2)   Obligations under Interest Swap Obligations covering Indebtedness if these Interest Swap Obligations are entered into to protect against fluctuations in interest rates on Indebtedness incurred in accordance with the indenture to the extent the notional principal amount of such Interest Swap Obligations is not greater than the principal amount of the Indebtedness to which such Interest Swap Obligation relates;

        (3)   Indebtedness of a Subsidiary to the Issuer or to a Wholly Owned Subsidiary for so long as such Indebtedness is held by the Issuer or a Wholly Owned Subsidiary, in each case subject to no Lien held by a Person other than the Issuer or a Wholly Owned Subsidiary; provided, however, that if as of any date any Person other than the Issuer or a Wholly Owned Subsidiary owns or holds any such Indebtedness or holds a Lien in respect of such Indebtedness, such date shall be deemed the incurrence of Indebtedness not constituting Permitted Indebtedness by the issuer of such Indebtedness;

        (4)   Indebtedness of the Issuer to a Wholly Owned Subsidiary for so long as such Indebtedness is held by a Wholly Owned Subsidiary, in each case subject to no Lien; provided, however, that

        (a)   any Indebtedness of the Issuer to any Wholly Owned Subsidiary that is not a Subsidiary Guarantor is unsecured and subordinated, pursuant to a written agreement, to the Issuer's Obligations under the indenture and the notes, and

        (b)   if as of any date any Person other than a Wholly Owned Subsidiary owns or holds any such Indebtedness or holds a Lien in respect of such Indebtedness, such date shall be deemed the incurrence of Indebtedness not constituting Permitted Indebtedness by the Issuer;

        (5)   Indebtedness arising from a bank or other financial institution inadvertently honoring a check, draft or similar instrument (except in the case of daylight overdrafts) drawn against insufficient funds in the ordinary course of business; provided, however, that such Indebtedness is extinguished within two Business Days of incurrence;

        (6)   Indebtedness of the Issuer or any of its Subsidiaries represented by letters of credit for the account of the Issuer or any such Subsidiary, as the case may be, in order to provide security for workers' compensation claims, payment obligations in connection with self-insurance or similar requirements in the ordinary course of business;

        (7)   Capitalized Lease Obligations and Purchase Money Indebtedness not exceeding $2,000,000 at any one time outstanding;

        (8)   Permitted Operating Obligations in an aggregate amount at any time outstanding not to exceed $750,000;

        (9)   Obligations arising in connection with Crude Oil and Natural Gas Hedge Agreements with financial institutions (excluding forward sales and production payments);

120

        (10) Indebtedness under Currency Agreements with financial institutions; provided, however, that in the case of Currency Agreements which relate to Indebtedness, such Currency Agreements do not increase Indebtedness of the Issuer and its Subsidiaries outstanding other than as a result of fluctuations in foreign currency exchange rates or by reason of fees, indemnities and compensation payable thereunder;

        (11) Additional Indebtedness in an aggregate principal amount at any time outstanding not to exceed $500,000;

        (12) Indebtedness outstanding on the Issue Date except to the extent the Indebtedness thereunder was taken up by the notes;

        (13) Indebtedness under the Senior Credit Agreement (including (i) any fees and expenses incurred by the Issuer or any of its Subsidiaries incurred in connection with the Senior Credit Agreement (including, but not limited to, those owed to any Person not affiliated to the Issuer or any of its Subsidiaries) in connection with any amendment (including any amendment and restatement thereof), supplement, replacement, restatement or other modification from time to time, including any agreements (and related instruments and documents) extending the maturity of, refinancing, replacement or other restructuring of all or any portion of the Indebtedness under such Senior Credit Agreement (and related instruments and documents) or any successor or replacement agreements (and related instruments and documents) and (ii) any capitalized interest, fees, or other expenses incurred by the Issuer or any of its Subsidiaries whether or not charged to a loan account or any similar account created under the Senior Credit Agreement (clauses (i) and (ii), the "Related Indebtedness")); provided, that the principal amount of the Indebtedness under the Senior Credit Agreement (excluding the Related Indebtedness and excluding any Qualified Senior Affiliate Indebtedness) shall not at any time exceed the sum of (a) $50 million less the aggregate amount applied from time to time by the Issuer or any of its Subsidiaries to repay the Senior Credit Agreement Indebtedness which is accompanied by a corresponding permanent reduction of the Revolver Commitment under the Senior Credit Agreement plus (b) (x) $15 million, if the then applicable Revolver Commitment under the Senior Credit Agreement is $25 million or greater, (y) $10 million, if the then applicable Revolver Commitment under the Senior Credit Agreement is less than $25 million and greater than or equal to $15 million or (z) $5 million, if the then applicable Revolver Commitment under the Senior Credit Agreement is less than $15 million ("Indebtedness under the Senior Credit Agreement"); provided further that, the aggregate amount that has been applied by the Issuer or any of its Subsidiaries to repay the Indebtedness under the Senior Credit Agreement which was accompanied by a corresponding permanent commitment reduction can be established by the Issuer at any time by providing the Trustee with an officer's certificate of the Issuer stating such amount;

        (14) Qualified Senior Affiliate Indebtedness; and

        (15) Permitted Subordinated Indebtedness.

        "Permitted Industry Investments" means:

        (1)   capital expenditures, including acquisitions of Issuer Properties and interests therein;

        (2)   (a)    operating agreements, joint ventures, working interests, royalty interests, mineral leases, unitization agreements, pooling arrangements or other similar or customary agreements, transactions, properties, interests or arrangements, and Investments and expenditures in connection with such agreements, interests or arrangements, in each case made or entered into in the ordinary course of the oil and gas business,

121

        and

        (b)   exchanges of Issuer Properties for other Issuer Properties of at least equivalent value as determined in good faith by the Board of Directors of the Issuer; and

        (3)   Investments of operating funds on behalf of co-owners of Crude Oil and Natural Gas Properties pursuant to joint operating agreements.

        "Permitted Investments" means:

        (1)   Investments by the Issuer or any Subsidiary in any Person that (i) is or will become immediately after such Investment a Subsidiary or that will merge or consolidate into the Issuer or a Subsidiary, and (ii) is not subject to any Payment Restriction;

        (2)   Investments in the Issuer by any Subsidiary; provided, however, that any Indebtedness evidencing any such Investment held by a Subsidiary that is not a Subsidiary Guarantor is unsecured and subordinated, pursuant to a written agreement, to the Issuer's Obligations under the notes and the indenture;

        (3)   Investments in cash and Cash Equivalents;

        (4)   Investments made by the Issuer or its Subsidiaries as a result of consideration received in connection with an Asset Sale made in compliance with "Certain Covenants—Limitation on Asset Sales" above;

        (5)   Permitted Industry Investments; and

        (6)   Investments in any Person so long as such Investments are made on an arm's-length basis.

        "Permitted Liens" means:

        (1)   Liens arising under the indenture or the security documents;

        (2)   Liens securing the notes;

        (3)   Liens arising under the Senior Credit Agreement or the guarantees and security documents entered into in connection with the Senior Credit Agreement, and Liens securing Qualified Senior Affiliate Indebtedness;

        (4)   Liens securing the Guarantees;

        (5)   Liens for taxes, assessments or governmental charges or claims that are either

        (a)   not delinquent or

        (b)   contested in good faith by appropriate proceedings and as to which the Issuer has set aside on its books such reserves as may be required pursuant to GAAP;

        (6)   statutory and contractual Liens of landlords to secure rent arising in the ordinary course of business to the extent such Liens relate only to the tangible property of the lessee which is located on such property and Liens of carriers, warehousemen, mechanics, builders, suppliers, materialmen, repairmen and other Liens imposed by law incurred in the ordinary course of business for sums not yet delinquent or being contested in good faith, if such reserve or other appropriate provision, if any, as shall be required by GAAP shall have been made in respect thereof;

        (7)   Liens incurred on deposits made in the ordinary course of business:

        (a)   in connection with workers' compensation, unemployment insurance and other types of social security, including any Lien securing letters of credit issued in the ordinary course of business consistent with past practice in connection therewith, or

122

        (b)   to secure the performance of tenders, statutory obligations, surety and appeal bonds, bids, leases, government contracts, performance and return-of-money bonds and other similar obligations (exclusive of obligations for the payment of borrowed money);

        (8)   easements, rights-of-way, zoning restrictions, restrictive covenants, minor imperfections in title and other similar charges or encumbrances in respect of real property not interfering in any material respect with the ordinary conduct of the business of the Issuer and its Subsidiaries;

        (9)   any interest or title of a lessor under any Capitalized Lease Obligation not prohibited by the terms of the indenture; provided that such Liens do not extend to any Property which is not leased Property subject to such Capitalized Lease Obligation;

        (10) Liens securing reimbursement obligations, not to exceed $100,000 in the aggregate at any time outstanding, with respect to commercial letters of credit which encumber documents and other property relating to such letters of credit and products and proceeds thereof;

        (11) Liens encumbering deposits made to secure obligations arising from statutory, regulatory, contractual, or warranty requirements, including rights of offset and set-off;

        (12) Liens securing Interest Swap Obligations which Interest Swap Obligations relate to Indebtedness that is otherwise permitted under the indenture and Liens securing Crude Oil and Natural Gas Hedge Agreements;

        (13) statutory Liens on pipeline or pipeline facilities, Hydrocarbons or Properties which arise out of operation of law;

        (14) royalties, overriding royalties, net profit interests, reversionary interests, operating agreements and other similar interests, properties, arrangements and agreements, all as ordinarily exist with respect to Properties of the Issuer and its Subsidiaries or otherwise as are customary in the oil and gas business, and all as relate to mineral leases and mineral interests of the Issuer and its Subsidiaries;

        (15) any

        (a)   interest or title of a lessor or sublessor under any lease,

        (b)   restriction or encumbrance that the interest or title of such lessor or sublessor may be subject to (including, without limitation, ground leases or other prior leases of the demised premises, mortgages, mechanics' liens, builders' liens, tax liens, and easements), or

        (c)   subordination of the interest of the lessee or sublessee under such lease to any restrictions or encumbrance referred to in the preceding clause (b);

        (16) Liens in favor of collecting or payor banks having a right of setoff, revocation, refund or chargeback with respect to money or instruments on deposit with or in possession of such bank;

        (17) judgment and attachment Liens not giving rise to an Event of Default;

        (18) Liens securing Acquired Indebtedness incurred in accordance with "Certain Covenants—Limitation on Incurrence of Additional Indebtedness" above; provided, however, that

        (19) such Liens secured such Acquired Indebtedness at the time of and prior to the incurrence of such Acquired Indebtedness by the Issuer or a Subsidiary and were not granted in connection with, or in anticipation of, the incurrence of such Acquired Indebtedness by the Issuer or a Subsidiary, and

        (20) such Liens do not extend to or cover any property or assets of the Issuer or of any of its Subsidiaries other than the property or assets that secured the Acquired Indebtedness (and the proceeds of such property and assets) prior to the time such Indebtedness became Acquired

123

Indebtedness of the Issuer or a Subsidiary and are no more favorable to the lienholders than those securing the Acquired Indebtedness prior to the incurrence of such Acquired Indebtedness by the Issuer or a Subsidiary.

        (21) Liens existing on the Issue Date;

        (22) Liens securing Refinancing Indebtedness which is incurred to Refinance any Indebtedness permitted under the indenture and which has been secured by a Lien permitted under the indenture and which has been incurred in accordance with the provisions of the indenture; provided, however, that such Liens

        (a)   are no less favorable to the holders and are not more favorable to the lienholders with respect to such Liens than the Liens in respect of the Indebtedness being Refinanced and

        (b)   do not extend to or cover any Property of the Issuer or any of its Subsidiaries that would not have secured the Indebtedness so Refinanced under the terms of the documents governing the Liens securing the Indebtedness being Refinanced;

        (21) Liens securing Indebtedness of the Issuer or any Subsidiary in an aggregate principal amount at any time outstanding not to exceed the sum of $500,000; and

        (22) Permitted Farmout Agreements.

        "Permitted Operating Obligations" means Indebtedness of the Issuer or any Subsidiary in respect of one or more standby letters of credit, bid, performance or surety bonds, or other reimbursement obligations, issued for the account of, or entered into by, the Issuer or any Subsidiary in the ordinary course of business consistent with past practices (excluding obligations related to the purchase by the Issuer or any Subsidiary of Hydrocarbons for which the Issuer or any Subsidiary has contracts to sell), or in lieu of any thereof or in addition to any thereto, guarantees and letters of credit supporting any such obligations and Indebtedness (in each case, other than for an obligation for borrowed money, other than borrowed money represented by any such letter of credit, bid, performance or surety bond, or reimbursement obligation itself, or any guarantee and letter of credit related thereto).

        "Person" means an individual, partnership, corporation, unincorporated organization, limited liability company, trust, estate, or joint venture, or a governmental agency or political subdivision thereof.

        "Preferred Stock" of any Person means any Capital Stock of such Person that has preferential rights to any other Capital Stock of such Person with respect to dividends or redemptions or upon liquidation.

        "Property" or "property" means, with respect to any Person, any interests of such Person in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including, without limitation, Capital Stock, partnership interests and other equity or ownership interests in any other Person.

        "Purchase Money Indebtedness" means Indebtedness the net proceeds of which are used to finance the cost (including the cost of construction) of property or assets acquired in the normal course of business by the Person incurring such Indebtedness.

        "Q1-2003 Budget" equals the Q1-2003 Closing Budget Ratio multiplied by the Total Assets at March 31, 2003.

        "Q1-2003 CapEx Amount" equals the lesser of $8 million and the Q1-2003 Budget.

        "Q1-2003 Closing Budget Ratio" equals (a) $8 million or such lower amount budgeted prior to the Issue Date by the Issuer for Capital Expenditures for the first calendar quarter of 2003 divided by (b) Total Assets at the end of the calendar quarter in which the Issue Date occurs.

124

        "Q2,3,4-2003 Budget" equals, for each of the last three calendar quarters of 2003, the applicable Q2,3,4-2003 Closing Budget Ratio multiplied by the Total Assets at the start of the applicable calendar quarter in 2003.

        "Q2,3,4-2003 CapEx Amount" equals, for each of the last three calendar quarters of 2003, the lesser of $2.5 million and the Q2,3,4-2003 Budget.

        "Q2,3,4-2003 Closing Budget Ratio" equals, for each of the last three calendar quarters of 2003, (a) $2.5 million or such lower amount budgeted prior to the Issue Date by the Issuer for Capital Expenditures for such calendar quarter divided by (b) Total Assets at the end of the calendar quarter in which the Issue Date occurs.

        "Qualified Capital Stock" means any Capital Stock that is not Disqualified Capital Stock.

        "Qualified Senior Affiliate Indebtedness" means Indebtedness of the Issuer to the Senior Credit Facility Representative, any Senior Credit Facility Lender or any Affiliate of the Senior Credit Facility Representative or any such lender in connection with (x) hedging activities (i.e., Indebtedness under Hedge Agreements) or (y) cash management services entered into in the ordinary course of business with any such Person (i.e., Indebtedness under Bank Products Agreements).

        "Qualified Lease Operating Costs" means lease operating costs reasonably incurred in the ordinary course of business consistent with past practices and industry standards pursuant to a budget approved by the Board of Directors of the Issuer and relating to proved developed oil and gas properties.

        "Refinance" means, in respect of any security or Indebtedness, to refinance, extend, renew, refund, repay, prepay, redeem, defease or retire, or to issue a security or Indebtedness in exchange or replacement for, such security or Indebtedness in whole or in part.

        "Refinancing Indebtedness" means any Indebtedness that is the result of Refinancing by the Issuer or any Subsidiary of Indebtedness incurred in accordance with the covenant described in "Limitation on Incurrence of Additional Indebtedness" above (other than pursuant to clause (1) (2), (3), (4), (5), (6), (7), (8), (9), (10), (11), (12), or (15) of the definition of Permitted Indebtedness), in each case that does not:

        (1)   result in an increase in the total principal amount of Indebtedness of the Issuer or such Subsidiary as of the date of such proposed Refinancing (other than increases from any premium required to be paid under the terms of the instrument governing such Indebtedness, capitalized interest, and the amount of reasonable expenses incurred by the Issuer or such Subsidiary in connection with such Refinancing, all of which are included in the term "Refinancing Indebtedness"), or

        (2)   create Indebtedness with

        (a)   a Weighted Average Life to Maturity that is less than the Weighted Average Life to Maturity of the Indebtedness being Refinanced or

        (b)   a final maturity earlier than the final maturity of the Indebtedness being Refinanced;

provided, however, that

          (i)  if such Indebtedness being Refinanced is Indebtedness solely of the Issuer or a Subsidiary Guarantor or is Indebtedness of the Issuer and any Subsidiary Guarantor or Subsidiary Guarantors, then such Refinancing Indebtedness shall be Indebtedness solely of the Issuer or such Subsidiary Guarantor or of the Issuer and such Subsidiary Guarantor or Subsidiary Guarantors, as the case may be, and

         (ii)  if such Indebtedness being Refinanced is subordinate or junior to the notes or a Guarantee, then such Refinancing Indebtedness shall be subordinate to the notes or such

125

Guarantee, as the case may be, at least to the same extent and in the same manner as the Indebtedness being Refinanced.

        "Related Person" of any Person means any other Person directly or indirectly owning 10% or more of the outstanding voting common stock of such Person (or, in the case of a Person that is not a corporation, 10% or more of the equity interest in such Person).

        "Restricted Cash" means, at any time, the lesser of (i) $5 million and (ii) the minimum amount of cash required to be maintained at that time by the Issuer pursuant to the terms of the Senior Credit Agreement.

        "Rollover Decrease" means, for a particular calendar quarter, the amount of reduced availability of SG&A or Capital Expenditures, as the case may be, due to any a prior quarter's SG&A Excess Amount or CapEx Excess Amount.

        "Rollover Increase" means, for a particular calendar quarter, the amount of increased availability of SG&A or Capital Expenditures, as the case may be, due to any a prior quarter's SG&A Deficit Amount or CapEx Deficit Amount.

        "Sandia" means Sandia Oil and Gas Company, a Texas corporation.

        "Sandia Operating" means Sandia Operating Corp., a Texas corporation, and Wholly-Owned Subsidiary of Sandia.

        "Sale and Leaseback Transaction" means any direct or indirect arrangement with any Person or to which any such Person is a party, providing for the leasing to the Issuer or any Subsidiary of any property, whether owned by the Issuer or such Subsidiary at the Issue Date or later acquired which has been or is to be sold or transferred by the Issuer or any Subsidiary to such Person or to any other Person from whom funds have been or are to be advanced by such Person on the security of such property.

        "Security documents" means, collectively, the Mortgages and all security agreements, mortgages, deeds of trust, collateral assignments or other instruments evidencing or creating any security interests in favor of the Trustee in all or any portion of the Collateral, in each case as amended, supplemented or modified from time to time in accordance with their terms and the terms of the indenture.

        "Senior Credit Agreement" means the Loan and Security Agreement, dated as of January 22, 2003, entered into by the Issuer and certain Subsidiaries of the Issuer, and the lenders named therein, or any successor or replacement agreements, whether with the same or any other lender, group of lenders, trustee, agent, note holder or group of note holders, together with the related documents thereto (including, without limitation, any promissory notes, guarantee agreements, security documents), in each case as such agreements, instruments and documents have been or may be amended (including any amendment and restatement thereof), supplemented, replaced, restated or otherwise modified from time to time, including any agreements (and related instruments and documents) extending the maturity of, refinancing, replacing or otherwise restructuring all or any portion of the Indebtedness under such agreements (and related instruments and documents) or any successor or replacement agreements (and related instruments and documents).

        "Senior Credit Facility Lenders" means any holders of any Indebtedness under the Senior Credit Agreement.

        "Senior Credit Facility Representative" means the Person designated in the Intercreditor Agreement as the Senior Credit Facility Representative with respect to the Senior Credit Agreement.

126

        "SG&A" means, for any period, amounts expended by the Issuer and its Subsidiaries on selling, general and administrative expenses (as determined in accordance with GAAP consistent with past practices), but excluding (without duplication with respect to such exclusions):

•

costs and expenses of the Issuer incurred in connection with (i) issuing the notes and shares of common stock contemporaneously issued by the Issuer, (ii) obtaining the loan evidenced by the Senior Credit Agreement, and (iii) the sale of stock described under the discussion above entitled "Business—Recent Developments—Financial Restructuring—Sale of Stock of Canadian Abraxas and Old Grey Wolf,"



•

legal and accounting fees not to exceed $40,000 in any calendar year incurred by the Issuer in connection with preparing and filing the reports, information and documents required to be delivered to the Trustee as described above in the discussion entitled "Reports to Holders,"



•

bonuses paid to officers and employees of the Issuer to the extent not in violation of the covenant described below in the discussion entitled "Transactions with Affiliates";



•

expenditures with respect to any non-cash compensation to officers and employees of the Issuer and its Subsidiaries;



•

amounts expended by the Issuer and its Subsidiaries on selling, general and administrative expenses for Canadian Abraxas and Old Grey Wolf; and



•

the Stark Fees.

        "SG&A Annual Amount" equals, for any annual calendar period, the lesser of $5 million and the SG&A Budget.

        "SG&A Budget" means, for any annual or quarter calendar period, as the case may be, Closing SG&A Ratio multiplied by the Total Assets at the start of such calendar period.

        "SG&A Deficit Amount" means, for any calendar quarter, the amount by which the SG&A in any such quarter (excluding the amount of SG&A due to any Rollover Decrease because of a prior quarter's SG&A Excess Amount) is less than the applicable SG&A Quarterly Amount.

        "SG&A Excess Amount" means, for any calendar quarter, the amount by which SG&A in any such quarter (excluding the amount of SG&A due to any Rollover Increase because of a prior quarter's SG&A Deficit Amount) exceeds the applicable SG&A Quarterly Amount.

        "SG&A Quarterly Amount" means, for any calendar quarter, the lesser of (a) $1.5 million and (b) one quarter of the SG&A Budget.

        "Subordinated Indebtedness" means Indebtedness of the Issuer or a Subsidiary Guarantor that is subordinated or junior in right of payment to the notes, the relevant Guarantee and the security documents, as applicable, under a written agreement to that effect.

        "Subsidiary" means, with respect to any Person:

        (1)   any corporation of which the outstanding Capital Stock having at least a majority of the votes entitled to be cast in the election of directors under ordinary circumstances shall at the time be owned, directly or indirectly, by such Person, or

        (2)   any other Person of which at least a majority of the voting interests under ordinary circumstances is at the time, directly or indirectly, owned by such Person, or

        (3)   any other Person required to be consolidated with such Person for financial reporting purposes under GAAP.

127

        "Subsidiary Guarantor" means Sandia, Wamsutter, Sandia Operating, Western Associated, Eastside Coal and New Grey Wolf and each of the Issuer's Subsidiaries that in the future executes a supplemental indenture in which such Subsidiary agrees to be bound by the terms of the indenture as a Subsidiary Guarantor; provided, however, that any Person constituting a Subsidiary Guarantor as described above shall cease to constitute a Subsidiary Guarantor when its Guarantee is released in accordance with the terms of the indenture.

        "Total Assets" means, as of any date, total assets of the Issuer and its Subsidiaries as reflected on the Issuer's consolidated balance sheet as of such date prepared in accordance with GAAP.

        "Trust Moneys" means all cash or Cash Equivalents received by the Trustee:

        (1)   upon the release of Collateral from the Lien of the indenture and the security documents, including investment earnings thereon; or

        (2)   pursuant to the provisions of any Mortgage; or

        (3)   as proceeds of any other sale or other disposition of all or any part of the Collateral by or on behalf of the Trustee or any collection, recovery, receipt, appropriation or other realization of or from all or any part of the Collateral pursuant to the indenture or any of the security documents or otherwise; or

        (4)   for application under the indenture as provided for in the indenture or the security documents, or whose disposition is not elsewhere specifically provided for in the indenture or in the security documents;

provided, however, that Trust Moneys shall not include any property deposited with the Trustee pursuant to any Change of Control Offer, a payment to Pay Down Debt or redemption or defeasance of any notes.

        "Western Associated" means Western Associated Energy Corporation, a Texas corporation.

        "Wamsutter" means Wamsutter Holdings, Inc., a Wyoming corporation.

        "Weighted Average Life to Maturity" means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

        (1)   the then outstanding aggregate principal amount of such Indebtedness into

        (2)   the sum of the total of the products obtained by multiplying:

        (a)   the amount of each then remaining installment, sinking fund, serial maturity or other required payment of principal, including payment at final maturity, in respect thereof, by

        (b)   the number of years (calculated to the nearest one-twelfth) which will elapse between such date and the making of such payment.

        "Wholly Owned Subsidiary" means any Subsidiary of which all the outstanding voting securities normally entitled to vote in the election of directors are owned by the Issuer or another Wholly Owned Subsidiary.

128

DESCRIPTION OF CAPITAL STOCK

Common Stock

        Abraxas is currently authorized to issue up to 200,000,000 shares of common stock, par value $.01 per share.

        As of July 27, 2004 there were 36,227,151 shares of Abraxas common stock issued and outstanding. Holders of the common stock are entitled to cast one vote for each share held of record on all matters submitted to a vote of stockholders and are not entitled to cumulate votes for the election of directors. Holders of common stock do not have preemptive rights to subscribe for additional shares of common stock issued by Abraxas.

        Holders of the common stock are entitled to receive dividends as may be declared by the Board of Directors out of funds legally available therefore. Under the terms of the first lien notes indenture and the second lien notes indenture, Abraxas may not pay dividends on shares of its common stock. In the event of liquidation, holders of the common stock are entitled to share pro rata in any distribution of Abraxas' assets remaining after payment of liabilities, subject to the preferences and rights of the holders of any outstanding shares of preferred stock. All of the outstanding shares of the common stock are fully paid and nonassessable.

        References herein to Abraxas' common stock include the common share purchase rights distributed by Abraxas to its stockholders on November 17, 1994, as long as they trade with the common stock. See "—Stockholder Rights Plan" beginning on page 131.

Preferred Stock

        Abraxas' Articles of Incorporation authorize the issuance of up to 1,000,000 shares of preferred stock, par value $.01 per share, in one or more series. The Board of Directors is authorized, without any further action by the stockholders, to determine the dividend rights, dividend rate, conversion rights, voting rights, rights and terms of redemption, liquidation preferences, sinking fund terms and other rights, preferences, privileges and restrictions of any series of preferred stock, the number of shares constituting any such series, and the designation thereof. The rights of the holders of common stock will be subject to, and may be adversely affected by, the rights of holders of any preferred stock that may be issued in the future.

Warrants

        Abraxas has warrants outstanding to purchase an aggregate of 950,000 shares of Abraxas common stock. Basil Street Company has warrants to purchase 750,000 shares at an exercise price of $3.50 per share and Jesup & Lamont Holdings, TNC, Inc. and Charles K. Butler (collectively "Jesup, et al") have warrants to purchase 200,000 shares at $3.50 per share. Basil Street and Jesup, et al have certain registration rights with respect to shares of the Abraxas common stock issued pursuant to the exercise of such warrants.

        All outstanding warrants contain provisions that protect Basil Street and Jesup, et al against dilution by adjusting the price at which the warrants are exercisable and the number of shares of the Abraxas common stock issuable upon exercise thereof upon the occurrence of certain events, including payment of stock dividends and distributions, stock splits, recapitalizations, reclassifications, mergers or consolidations. A holder of warrants has no rights as a stockholder of Abraxas until the warrants are exercised. All warrants are currently exercisable, although none have been exercised as of the date hereof.

        Under the terms of their warrants, Basil Street and Jesup, et al have the right to unlimited piggyback registrations. Abraxas has agreed to pay all expenses in connection with piggyback

129

registrations by Basil Street and Jesup, et al, provided, however, all underwriting discounts and selling commissions shall be borne by Basil Street and Jesup, et al. The registration statement of which this prospectus forms a part fulfills Abraxas' registration obligations with respect to the holdings of Basil Street and Jesup, et al.

Option Plans

        Pursuant to the ISO Plan, the 1993 Plan and the LTIP, Abraxas grants to employees and officers (including Abraxas' directors who are also employees) incentive stock options and non-qualified stock options. The ISO Plan, the 1993 Plan, and the LTIP are administered by the compensation committee which, based upon the recommendation of the Chief Executive Officer, determines the number of shares subject to each option. As of May 28, 2003, there were options to purchase 3,293,302 shares of Abraxas common stock outstanding, of which 2,215,788 were fully vested at an average exercise price of $0.99 per share.

        Effective as of the closing date of the exchange offer and subject to any requirements under applicable law, the Abraxas Board of Directors has approved a reduction in the exercise price of one-half of the options to purchase Abraxas common stock held by Mr. Watson (320,282 options), and a reduction in the exercise price of all of stock options previously issued to other Abraxas employees (approximately 1.8 million options). The exercise price on such options will be reduced to the price at which a share of Abraxas common stock is trading on the American Stock Exchange at 11:00 a.m. New York time on that date.

Anti-takeover Effects of Certain Provisions of the Articles of Incorporation and Bylaws

        Abraxas' Articles of Incorporation and Bylaws provide for the Board of Directors to be divided into three classes of directors serving staggered three-year terms. As a result, approximately one-third of the Board of Directors will be elected each year. The Articles of Incorporation and Bylaws provide that the Board of Directors will consist of not less than three nor more than twelve members, with the exact number to be determined from time to time by the affirmative vote of a majority of directors then in office. The Board of Directors, and not the stockholders, has the authority to determine the number of directors. This provision could prevent any stockholder from obtaining majority representation on Abraxas' Board of Directors by enlarging the Board of Directors and by filling the new directorships with the stockholder's own nominees. In addition, directors may be removed by the stockholders only for cause.

        The Articles of Incorporation and Bylaws provide that special meetings of stockholders of Abraxas may be called only by the Chairman of the Board, the President or a majority of the members of the Board of Directors. This provision may make it more difficult for stockholders to take actions opposed by the Board of Directors.

        The Articles of Incorporation and Bylaws provide that any action required to be taken or which may be taken by holders of Abraxas common stock must be effected at a duly called annual or special meeting of such holders, and may not be taken by any written consent of such stockholders. These provisions may have the effect of delaying consideration of a stockholder proposal until the next annual meeting unless a special meeting is called by the persons set forth above. The provisions of the Articles of Incorporation and Bylaws prohibiting stockholder action by written consent could prevent the holders of a majority of the voting power of Abraxas from using the written consent procedure to take stockholder action and taking action by consent without giving all the stockholders of Abraxas entitled to vote on a proposed action the opportunity to participate in determining such proposed action.

130

Stockholder Rights Plan

        On November 17, 1994, the Board of Directors of Abraxas adopted a stockholder rights plan (the "Stockholder Rights Plan"). Under the terms of the Stockholder Rights Plan, the Board of Directors of Abraxas declared a dividend of one common share purchase right ("Stockholder Right") on each share of the Abraxas common stock outstanding on November 17, 1994. Each Stockholder Right entitles the holder thereof to buy one share of Abraxas common stock at an exercise price of $40 per share, subject to adjustment.

        The Stockholder Rights are not exercisable until the occurrence of specified events. Upon the occurrence of such an event (which events are generally those which would signify the commencement of a hostile bid to acquire Abraxas), the Stockholder Rights then become exercisable (unless redeemed by the Board of Directors) for a number of shares of Abraxas common stock having a market value of four times the exercise price of the Stockholder Right. If the acquirer were to conclude the acquisition of Abraxas, the Stockholder Rights would then become exercisable for shares of the controlling/surviving corporation having a value of four times the exercise price of the Stockholder Rights. If the Stockholder Rights were exercised at any time, significant dilution would result, thus making the acquisition prohibitively expensive for the acquirer. In order to encourage a bidder to negotiate with the Board of Directors, the Stockholder Rights Plan provides that the Stockholder Rights may be redeemed under prescribed circumstances by the Board of Directors.

        The Stockholder Rights are not intended to prevent a takeover of Abraxas and will not interfere with any tender offer or business combination approved by the Board of Directors. The Stockholder Rights Plan is intended to protect the stockholders in the event of (a) an unsolicited offer to acquire Abraxas, including offers that do not treat all stockholders equally, (b) the acquisition in the open market of shares constituting control of Abraxas without offering fair value to all stockholders and (c) other coercive takeover tactics which could impair the Board's ability to fully represent the interests of the stockholders.

Anti-Takeover Statutes

        The Nevada General Corporation Law (the "Nevada GCL") contains two provisions, described below as "Combination Provisions" and the "Control Share Act," that may make more difficult the accomplishment of unsolicited or hostile attempts to acquire control of a corporation through certain types of transactions.

        Restrictions on Certain Combinations Between Nevada Resident Corporations and Interested Stockholders. The Nevada GCL includes certain provisions (the "Combination Provisions") prohibiting certain "combinations" (generally defined to include certain mergers, disposition of assets transactions, and share issuance or transfer transactions) between a resident domestic corporation and an "interested stockholder" (generally defined to be the beneficial owner of 10% or more of the voting power of the outstanding shares of the corporation), except those combinations which are approved by the board of directors before the interested stockholder first obtained a 10% interest in the corporation's stock. There are additional exceptions to the prohibition, which apply to combinations if they occur more than three years after the interested stockholder's date of acquiring shares. The Combination Provisions apply unless the corporation elects against their application in its original articles of incorporation or an amendment thereto, or in its bylaws. Abraxas' Articles of Incorporation and Bylaws do not currently contain a provision rendering the Combination Provisions inapplicable.

        Nevada Control Share Act. Nevada's Control Share Acquisition Act (the "Control Share Act") imposes procedural hurdles on and curtails greenmail practices of corporate raiders. The Control Share Act temporarily disenfranchises the voting power of "control shares" of a person or group ("Acquiring Person") purchasing a "controlling interest" in an "issuing corporation" (as defined in the Nevada GCL) not opting out of the Control Share Act. In this regard, the Control Share Act will apply to an

131

"issuing corporation" unless, before an acquisition is made, the articles of incorporation or bylaws in effect on the tenth day following the acquisition of a controlling interest provide that it is inapplicable. Abraxas' Articles of Incorporation and Bylaws do not currently contain a provision rendering the Control Share Act inapplicable.

        Under the Control Share Act, an "issuing corporation" is a corporation organized in Nevada which has 200 or more stockholders, at least 100 of whom are stockholders of record (which for this purpose includes registered and beneficial owners) and residents of Nevada, and which does business in Nevada directly or through an affiliated company. The status of Abraxas at the time of the occurrence of a transaction governed by the Control Share Act (assuming that Abraxas' Articles of Incorporation or Bylaws have not theretofore been amended to include an opting out provision) would determine whether the Control Share Act is applicable.

        The Control Share Act requires an Acquiring Person to take certain procedural steps before he or it can obtain the full voting power of the control shares. "Control shares" are the shares of a corporation (1) acquired or offered to be acquired which will enable the Acquiring Person to own a "controlling interest," and (2) acquired within 90 days immediately preceding that date. A "controlling interest" is defined as the ownership of shares which would enable the Acquiring Person to exercise certain graduated amounts (beginning with one-fifth) of all voting power of the corporation. The Acquiring Person may not vote any control shares without first obtaining approval from the stockholders not characterized as "interested stockholders" (as defined below).

        To obtain voting Rights in control shares, the Acquiring Person must file a statement at the principal office of the issuer ("Offeror's Statement") setting forth certain information about the acquisition or intended acquisition of stock. The Offeror's Statement may also request a special meeting of stockholders to determine the voting Rights to be accorded to the Acquiring Person. A special stockholders' meeting must then be held at the Acquiring Person's expense within 30 to 50 days after the Offeror's Statement is filed. If a special meeting is not requested by the Acquiring Person, the matter will be addressed at the next regular or special meeting of stockholders.

        At the special or annual meeting at which the issue of voting rights of control shares will be addressed, "interested stockholders" may not vote on the question of granting voting rights to control the corporation or its parent unless the articles of incorporation of the issuing corporation provide otherwise. Abraxas' Articles of Incorporation do not currently contain a provision allowing for such voting power.

        If full voting power is granted to the Acquiring Person by the disinterested stockholders, and the Acquiring Person has acquired control shares with a majority or more of the voting power, then (unless otherwise provided in the articles of incorporation or bylaws in effect on the tenth day following the acquisition of a controlling interest) all stockholders of record, other than the Acquiring Person, who have not voted in favor of authorizing voting rights for the control shares, must be sent a notice advising them of the fact and of their right to receive "fair value" for their shares. Abraxas' Articles of Incorporation and Bylaws do not provide otherwise. By the date set in the dissenter's notice, which may not be less than 30 nor more than 60 days after the dissenter's notice is delivered, any such stockholder may demand to receive from the corporation the "fair value" for all or part of his shares. "Fair value" is defined in the Control Share Act as "not less than the highest price per share paid by the Acquiring Person in an acquisition."

        The Control Share Act permits a corporation to redeem the control shares in the following two instances, if so provided in the articles of incorporation or bylaws of the corporation in effect on the tenth day following the acquisition of a controlling interest: (1) if the Acquiring Person fails to deliver the Offeror's Statement to the corporation within 10 days after the Acquiring Person's acquisition of the control shares; or (2) an Offeror's Statement is delivered, but the control shares are not accorded full voting rights by the stockholders. Abraxas' Articles of Incorporation and Bylaws do not address this matter.

132

REGISTRATION RIGHTS; LIQUIDATED DAMAGES

Shelf Registration

        Pursuant to the registration rights agreement that we entered into with Jefferies & Company, Inc., acting on behalf of the holders of the notes and shares of common stock covered by this prospectus, we have filed a shelf registration statement of which this prospectus is a part, covering resales of the notes, any additional notes issued in lieu of cash interest payments and the shares of Abraxas common stock issued in the financial restructuring exchange offer. We will be permitted to withdraw the registration statement upon the soonest of (1) the passage of two years following the date of closing of this exchange offer, (2) the date on which all tendering noteholders have disposed of all of the securities covered by such shelf registration statement, or (3) the date that Jefferies & Company receives an opinion of counsel to Abraxas and the guarantors that all of the securities covered by such shelf registration statement may be sold under the provisions of Rule 144 without limitation as to volume or manner of sale.

        If the registration statement of which this prospectus is a part ceases to be effective or usable in connection with exchange or resales of the notes, any additional notes issued in lieu of cash interest payments, and the common stock during the periods specified in the registration rights agreement (and as qualified by the exceptions described in such agreement), or if we fail to meet other obligations under the registration rights agreement, then, as liquidated damages for such default under the registration rights agreement, the interest rate on the notes and any additional notes issued in lieu of cash interest payments, with respect to the first 90 day period immediately following the occurrence of such default under the registration rights agreement will increase, by 3.5% per annum and will increase by an additional 0.5% per annum with respect to each subsequent 30 day period until all such defaults have been cured, up to a maximum per annum interest rate on such notes of 18% with respect to all defaults under the registration rights agreement. All accrued liquidated damages will be paid by Abraxas in the same manner and at the same time as payments of interest on the notes and any additional notes issued in lieu of cash interest payments. Following the cure of all defaults under the registration rights agreement, the accrual of liquidated damages will cease. No liquidated damages will be payable to holders of the common stock who do not otherwise hold notes.

        With respect to the shelf registration statement of which this prospectus is a part, holders of any securities to be covered by such registration statement are required to deliver information to be used in connection with the registration statement in order to have their securities included in the registration statement and to benefit from the provisions regarding liquidated damages set forth above, to the extent applicable. We are not responsible for the failure of a selling security holder to provide accurate information in connection with this prospectus.

Exchange Offer Registration

        Pursuant to the registration rights agreement, we have also filed with the SEC a registration statement with respect to an offer to exchange the notes covered by this prospectus and any additional notes issued in lieu of cash interest payments for a new issue of notes registered under the Securities Act, with terms identical in all material respects to those of the outstanding notes. We have agreed that if we are not permitted to consummate the exchange offer or if fewer than all of the outstanding notes are successfully exchanged in the exchange offer, that we will use our reasonable best efforts to maintain the effectiveness of the shelf registration statement of which this prospectus is a part to cover the resales of such notes remaining outstanding. To the extent that outstanding notes are exchanged in the exchange offer for registered notes, such outstanding notes will be removed from this prospectus.

        This summary of the registration rights agreement is subject to, and is qualified in its entirety by reference to, all the provisions of the registration rights agreement, a copy of which is filed as an exhibit to the shelf registration statement of which this prospectus is a part.

133

CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

Scope and Limitations

        The following general discussion summarizes certain United States federal income tax aspects of the ownership of the notes and Abraxas common stock. This discussion is a summary for general information purposes only, and does not purport to describe all of the United States federal income tax consequences resulting from the acquisition, ownership and disposition of notes and Abraxas common stock nor does it describe United States federal income tax consequences resulting to Non-U.S. Holders, except as expressly indicated. This summary deals only with notes and Abraxas common stock that are held as capital assets by a purchaser and does not deal with special situations, such as those of brokers, dealers in securities or currencies, financial institutions, tax-exempt entities, insurance companies, persons liable for alternative minimum tax, United States persons whose "functional currency" is not the U.S. dollar, persons holding the notes as part of a hedging, integrated, conversion or constructive sale transaction or a straddle, and traders in securities that elect to use a mark-to-market method of accounting for their securities holdings. The following summary does not address any state, local or non-United States tax consequences or United States federal tax consequences (e.g., estate or gift tax) other than those pertaining to the income tax.

        Furthermore, this discussion is based on provisions of the Internal Revenue Code of 1986, as amended (the "Code"), the Treasury Regulations promulgated thereunder, and administrative and judicial interpretations of the foregoing, all as in effect as of the date hereof and all of which are subject to change, possibly with retroactive effect. This discussion will not be binding in any manner on the Internal Revenue Service (the "IRS") or the courts. No ruling has been or will be requested from the IRS on any of the matters relating to holding the notes and Abraxas common stock, and no assurance can be given that the IRS will not successfully challenge certain of the conclusions set forth below. If a partnership holds the notes and/or Abraxas common stock, the tax treatment of a partner will generally depend upon the status of the partner and the activities of the partnership. Partners of partnerships that hold notes and/or Abraxas common stock, should consult their own tax advisors.

        As used herein, the term "U.S. Holder" means a holder of notes or Abraxas common stock that is, for United States federal income tax purposes:

(1)

an individual who is a citizen or resident of the United States;



(2)

a corporation or partnership created or organized in or under the law of the United States or of any political subdivision thereof;



(3)

an estate, the income of which is includible in gross income for United States federal income tax purposes regardless of its source; or



(4)

a trust if (a) a United States court is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust, or (b) the trust was in existence on August 20, 1996, was treated as a United States person prior to that date, and elected to continue to be treated as a United States person.

        For purposes of this discussion, the term "non-U.S. Holder" means any person other than a U.S. Holder.

EACH U. S. HOLDER, NON-U.S. HOLDER, PROSPECTIVE U.S. HOLDERS AND PROSPECTIVE NON-U.S. HOLDERS SHOULD CONSULT THEIR TAX ADVISORS REGARDING THE PARTICULAR U.S. FEDERAL INCOME TAX CONSEQUENCES TO SUCH HOLDER OR PROSPECTIVE HOLDER OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF THE NOTES AND/OR ABRAXAS COMMON STOCK, AS WELL AS ANY TAX CONSEQUENCES THAT

134

MAY ARISE UNDER THE LAWS OF ANY OTHER RELEVANT FOREIGN, STATE, LOCAL OR OTHER TAXING JURISDICTION.

Tax Consequences to U.S. Holders

        Original Issue Discount On The Notes.    In general, subject to a de minimis rule, a debt obligation will be treated as being issued with original issue discount ("OID") if the "stated redemption price at maturity" of the instrument exceeds that instrument's "issue price"(as described below in "Issue Price").

        The stated redemption price at maturity of a debt obligation is the aggregate of all payments due to the U.S. Holder under that debt obligation at or prior to its maturity date, other than interest that is actually and unconditionally payable in cash or property (other than debt instruments of the issuer) at a single fixed (or a qualified floating) rate (or a permitted combination of the two) at least annually ("QSIPs"). Interest on the notes will be payable in cash, except that Abraxas may, subject to certain conditions, pay the interest due on any interest payment date through and including the maturity date of the notes by the issuance of additional notes ("PIK notes"). Because the interest on the notes due on any payment date may be paid through the issuance of additional PIK notes, none of the interest payments on the notes will qualify as QSIPs. Thus, the stated redemption price at maturity of the notes will include all payments of principal and all of the interest required under the notes. Furthermore, under the regulations issued pursuant to the OID provisions of the Code (the "OID Regulations"), a note and any PIK notes issued with respect thereto are treated as part of the same debt instrument. Accordingly, the adjusted issue price of the combined note and PIK note will not be reduced upon the issuance of the PIK note, and the stated redemption price at maturity of the combined note and PIK note will not change upon the issuance of the PIK note and will include the interest payable under the PIK note.

        Since the stated redemption price at maturity of the notes exceeds their issue price, the notes were issued with OID. A U.S. Holder of notes, subject to the adjustments discussed below, will be required to include in gross income for federal income tax purposes the sum of the daily portions of OID for each day during the taxable year or portion thereof during which the U.S. Holder holds the notes, whether or not the U.S. Holder actually receives a payment relating to OID in such year. The daily portion is determined by allocating to each day of the relevant "accrual period" a pro rata portion of an amount equal to (a) the product of (1) the "adjusted issue price" of the notes at the beginning of each accrual period, multiplied by (2) the yield to maturity of the notes (determined by semi-annual compounding) less (b) the sum of any QSIPs during the accrual period. The "adjusted issue price" of a note at any given time is its issue price increased by all accrued OID for prior accrual periods (without regard to the acquisition premium rules) and decreased by the amount of any payment previously made on the notes other than a QSIP. As discussed above, only a portion of the interest payments on the notes will qualify as QSIPs.

        A U.S. Holder of a note will be required to include OID in income as such OID accrues, regardless of the U.S. Holder's method of accounting and regardless of when such U.S. Holder receives cash payments relating to the OID. A U.S. Holder's tax basis in a note will be increased by the amount of OID included in the U.S. Holder's income and reduced by the portion of all interest payments not qualifying as QSIPs (other than payments in the form of PIK notes) received on the notes.

        The computation of OID and adjusted issue price with respect to the combined notes and PIK notes will take into account accruals and payments with respect to both instruments, with the result that the U.S. Holder of a note generally will be required to include in income as OID the portion of interest that accrues under the note that does not give rise to QSIPs and the interest that accrues under any PIK note issued in respect thereof, regardless of whether any cash payments are received.

135

Each U.S. Holder of a note will be required to include in income cash payments of stated interest qualifying as QSIPs in accordance with their regular method of accounting.

        Upon a disposition of a note or a PIK note issued in respect thereof, the U.S. Holder will be required (unless it disposes of a note together with all PIK notes issued in respect thereof) to allocate adjusted issue price, stated redemption price at maturity and acquisition premium (discussed below), if any, of the combined note and PIK note among the instruments retained and the instruments disposed of in order to determine OID with respect to the retained instruments. Although it is not clear, it is likely that the adjusted tax basis and adjusted issue price of a note would be allocated between such note and any PIK notes issued with respect thereto at the time of such issuance, based on their respective principal amounts. OID on the PIK notes will accrue in the same manner as described above in respect of the notes.

        A purchaser of a note who purchases the note at a cost less than the remaining stated redemption price at maturity but greater than its adjusted issue price (a purchase at an "acquisition premium") also will be required to include in gross income the sum of the daily portions of OID on that note. (For purposes of these rules, a "purchase" is any acquisition of a debt instrument.) In computing the daily portions of OID for such a purchaser, however, the daily portion is reduced by the amount that would be the daily portion for such day (computed in accordance with the rules set forth above) multiplied by a fraction, the numerator of which is the amount, if any, by which the purchaser's basis in the note on the date of purchase exceeds the adjusted issue price of the note at that time, and the denominator of which is the sum of the daily portions for that notes for all days beginning on the day after the purchase date and ending on the maturity date.

        Abraxas will furnish annually to the IRS, and to each U.S. Holder of notes to whom Abraxas is required to report, information relating to the OID accruing during the calendar year. U.S. Holders will be required to determine for themselves whether, by reason of the rules described above, they are eligible to report a reduced amount of OID for federal income tax purposes.

        Pursuant to the OID Regulations, U.S. Holders of debt instruments are permitted to elect to include all interest, discount (including de minimis market discount) and premium on a debt instrument in income currently on a constant yield to maturity basis. Such election would constitute an election to include market discount currently in income on all market discount bonds held by such U.S. Holders. U.S. Holders of notes are urged to consult their own tax advisors regarding the availability and advisability of making such an election.

        Issue Price.    The "issue price" of the notes was determined by reference to the fair market value of the second lien notes and old notes for which they were exchanged pursuant to the exchange offer. The fair market value of the second lien notes and old notes was allocated based upon the relative fair market value of the consideration received by Holders pursuant to the exchange offer. Information regarding the issue price of the notes may be obtained by sending a request in writing addressed to the Chief Financial Officer of Abraxas Petroleum Corporation at 500 North Loop 1604, Suite 100, San Antonio, Texas 78232.

        Sale, Exchange Or Redemption Of Notes.    As noted above, the OID Regulations treat a note and any PIK notes issued with respect thereto as a part of the same debt instrument. If, however, a U.S. Holder disposes of a note or a PIK note separately, in order to determine the amount of its gain or loss recognized, the U.S. Holder will be required to allocate adjusted issue price and acquisition premium of the combined note and the PIK notes issued with respect thereto among the debt instruments retained and disposed of, as described above. See "—Original Issue Discount on the Notes" above.

        Under the OID Regulations, an unscheduled payment made on a debt instrument such as a note prior to maturity that results in a substantially pro rata reduction of each payment of principal and

136

interest remaining on the instrument is treated as a payment in retirement of a portion of the instrument, which may result in gain or loss to the U.S. Holder. The gain or loss is calculated by treating the debt obligation as consisting of two instruments, one that is retired and one that remains outstanding, and by allocating the adjusted issue price and the U.S. Holder's adjusted basis between the two instruments based upon the relative principal amount of the portion of the obligation that is treated as retired by the pro rata prepayment. The stated redemption price at maturity of and the OID on the remaining instrument will be determined according to the same principles discussed above. See "—Original Issue Discount on the Notes" above.

        Except as discussed above, upon the sale, exchange or retirement of a note, a U.S. Holder generally will recognize taxable gain or loss equal to the difference between the amount realized on the sale, exchange or retirement of the note (other than amounts representing accrued and unpaid interest) and such U.S. Holder's adjusted tax basis in the note. A U.S. Holder's adjusted tax basis in a note generally will equal such U.S. Holder's initial investment in the note increased by any original issue discount included in income and any accrued market discount included in income, decreased by the amount of any payments that are not deemed qualified stated interest payments and amortizable bond premium applied to reduce interest with respect to such note. Such gain or loss generally will be long term capital gain or loss if the note has been held for more than one year at the time of such sale, exchange or retirement.

        Accrued Market Discount.    A debt instrument has "market discount" if its stated redemption price at maturity exceeds its tax basis in the hands of the U.S. Holder immediately after its acquisition, unless a statutorily defined de minimis exception applies. Any gain recognized on the maturity or disposition of a note will be treated as ordinary income to the extent that such gain does not exceed the accrued market discount on such note. Alternatively, a U.S. Holder of a note may elect to include market discount in income currently over the life of the note. Such election shall apply to all debt instruments with market discount acquired by the electing U.S. Holder on or after the first day of the first year to which the election applies and may not be revoked without the consent of the IRS.

        Amortizable Bond Premium.    Generally, a U.S. Holder of a note has "amortizable bond premium" to the extent that the purchase price of a note exceeds the note "s stated redemption price at maturity. Such a note will not be treated as issued with OID. If the U.S. Holder makes (or has made) a timely election under Section 171 of the Code, such U.S. Holder may amortize the bond premium, on a constant yield basis, by offsetting the interest income from the notes.

        If the U.S. Holder of a note makes an election to amortize bond premium, the tax basis of the debt instrument must be reduced by the amount of the aggregate amortization deductions allowable for the bond premium. Any such election to amortize bond premium would apply to all debt instruments held or subsequently acquired by the electing U.S. Holder and cannot be revoked without permission from the IRS.

        Backup Withholding.    A U.S. Holder of a note may be subject to backup withholding at the rate of 31% with respect to "reportable payments," which include payments in respect of interest or accrued OID, and the proceeds of a sale, exchange or redemption of a note. Abraxas will be required to deduct and withhold the prescribed amount if (a) the U.S. Holder fails to furnish a taxpayer identification number ("TIN") to Abraxas in the manner required, (b) the IRS notifies Abraxas that the TIN furnished by the U.S. Holder is incorrect, (c) there has been a failure of the U.S. Holder to certify under penalty of perjury that the U.S. Holder is not subject to withholding under Section 3406(a)(1)(C) of the Tax Code, or (d) the U.S. Holder is notified by the IRS that he or she failed to report properly payments of interest and dividends and the IRS has notified Abraxas that he or she is subject to backup withholding.

137

        Amounts paid as backup withholding do not constitute an additional tax and will be credited against the U.S. Holder's U.S. federal income tax liabilities, so long as the required information is provided to the IRS. Abraxas will report to the U.S. Holders of notes and to the IRS the amount of any "reportable payments" for each calendar year and the amount of tax withheld, if any, with respect to payments on such notes to any noncorporate U.S. Holder other than an "exempt recipient."

THE TAX RULES GOVERNING INSTRUMENTS ISSUED WITH OID AND THE DISCUSSION ABOVE UNDER "—ORIGINAL ISSUE DISCOUNT ON THE NOTES," "SALE, EXCHANGE AND RETIREMENT OF NOTES," "ACCRUED MARKET DISCOUNT" AND "AMORTIZABLE BOND PREMIUM" ARE COMPLEX AND THEIR APPLICATION TO A U.S. HOLDER WILL DEPEND UPON SUCH U.S. HOLDER'S INDIVIDUAL SITUATION. U.S. HOLDERS ARE URGED TO CONSULT THEIR TAX ADVISOR ABOUT THE APPLICATION OF THESE RULES TO THE THEM.

Tax Consequences of Holding Common Stock

        Rules Generally Relating to Distributions with Respect to Stock.    When a corporation makes a distribution with respect to its capital stock, the amount of the distribution received by the stockholder will be treated as a dividend which will be taxable to the stockholder as ordinary income, to the extent it is paid from the current or accumulated earnings and profits of the corporation. The amount of a distribution made in property other than cash is the fair market value of that property at the time of the distribution. U.S. Holders that are corporations are entitled to a dividends-received deduction subject to certain limitations. Earnings and profits for this purpose consists of an amount based on the taxable income of the corporation as adjusted by the application of detailed rules set forth in Treasury Regulations. A distribution will be treated as a dividend even though we have an overall deficit in our earnings and profits to the extent we have positive earnings and profits in the year in which we make the distribution (i.e., current earnings and profits). If the amount of a distribution exceeds the current and accumulated earnings and profits of the corporation, the excess will be treated first as a tax-free return of investment up to the basis of the stock, and this amount will reduce the stockholder's tax basis in the stock. If the distribution exceeds the current and accumulated earnings and profits, and the stockholder's tax basis in the stock, this excess amount will be treated as capital gain to the stockholder. If the stockholder is a U.S. corporation, the stockholder would generally be able to claim a deduction equal to a portion of the amount of the distribution treated as a dividend, subject to certain requirements under the Code, in accordance with the foregoing rules.

        Redemption of Common Stock.    Upon redemption of the common stock by Abraxas for cash or property other than capital stock, the redemption should be treated as a sale or exchange under Section 302 of the Code and the tendering holder should recognize capital gain or loss to the extent the redemption proceeds are greater or less than the holder's adjusted tax basis in the common stock if the redemption proceeds received in exchange for the common stock:

•

are not essentially equivalent to a dividend distribution;



•

are substantially disproportionate with respect to the tendering holder;



•

completely terminate the holder's equity interest in Abraxas; or



•

are distributed to an individual U.S. Holder as part of a partial liquidation of shares (as defined in Section 302 of the Code).

        In determining whether a cash redemption qualifies for sale or exchange treatment under Section 302 of the Code, a tendering U.S. Holder must take into account shares of Abraxas stock that are actually owned by the tendering holder and, in certain situations, shares that such U.S. Holder is deemed to own through a related person or entity.

138

        If the redemption does not qualify for sale or exchange treatment under Section 302 of the Code, the redemption proceeds will be treated as a distribution with respect to the common stock. The distribution will be taxable as a dividend to the extent of current or accumulated earnings and profits. The amount of the distribution in excess of current or accumulated earnings and profits will be treated as a tax-free return of basis to the extent of the tendering U.S. Holder's basis in its common stock and as capital gain to the extent the distribution exceeds its basis in the common stock.

        Sale of Common Stock.    U.S. Holders will generally recognize capital gain or loss on a sale or exchange of common stock. The gain or loss will equal the difference between the proceeds received and the adjusted tax basis in the stock. The gain or loss recognized by a U.S. Holder on a sale or exchange of stock will be long-term capital gain or loss if the holding period for the stock is more than one year.

Non-U.S. Holders

        Subject to the discussion of backup withholding below, the interest income and gains that a non-U.S. Holder derives in respect of holding notes and Abraxas common stock generally will be exempt from United States federal income taxes, including withholding tax.

        Payments of interest or principal in respect of the notes by Abraxas or the paying agent to a holder that is a non-U.S. Holder will not be subject to withholding of United States federal income tax, provided that, in the case of payments of interest (including OID):

(1)

the income is effectively connected with the conduct by such non-U.S. Holder of a trade or business carried on in the United States and the non-U.S. Holder complies with applicable identification requirements (described below under "Backup Withholding and Information Reporting"); or



(2)

the non-U.S. Holder and/or each securities clearing organization, bank, or other financial institution that holds the notes on behalf of such non-U.S. Holder in the ordinary course of its trade or business, in the chain between the non-U.S. Holder and the paying agent, complies with applicable identification requirements (described below under "Backup Withholding and Information Reporting") to establish that the holder is a non-U.S. Holder and in addition, that the following requirements of the "portfolio interest" exemption under the Code are satisfied:



•

the non-U.S. Holder does not actually or constructively own 10% or more of the voting stock of Abraxas;



•

the non-U.S. Holder is not a controlled foreign corporation with respect to Abraxas; and



•

the non-U.S. Holder is not a bank whose receipt of interest on the notes is described in Section 881(c)(3)(A) of the Code.

        Any gain realized by a non-U.S. Holder on the sale or exchange of the notes, or Abraxas common stock generally will be exempt from U.S. federal income tax, including withholding tax, unless:

(1)

such gain is effectively connected with the conduct of a trade or business in the United States (or if a tax treaty applies, such gain is attributable to a permanent establishment of the non-U.S. Holder);



(2)

in the case of a non-U.S. Holder that is an individual, such non-U.S. Holder is present in the United States for 183 days or more during the taxable year in which such sale, exchange, or other disposition occurs; or



(3)

in the case of gain representing accrued interest, the requirements of the portfolio interest exemption are not satisfied.

139

        If the interest income (including OID) paid on the notes or gain recognized from a sale or exchange of the notes, or Abraxas common stock, is effectively connected with the conduct of a trade or business in the United States by a non-U.S. Holder, such non-U.S. Holder will generally be taxed under the same rules that govern the taxation of a U.S. Holder. In addition, if such holder is a foreign corporation, it may be subject to an additional branch profits tax.

Backup Withholding and Information Reporting

        Payment of the proceeds of a sale of a note or payment of interest (including original issue discount) will be subject to information reporting requirements and backup withholding tax unless the beneficial owner certifies its non-United States status under penalties of perjury or otherwise establishes an exemption provided that the paying agent does not actually know, or has reason to know, that the holder is actually a U.S. Holder). Recently promulgated Treasury Regulations provide certain presumptions under which a non-U.S. Holder will be subject to backup withholding and information reporting unless such holder certifies as to its non-U.S. status or otherwise establishes an exemption. In addition, the recent Treasury Regulations change certain procedural requirements related to establishing a holder's non-United States status. Non-U.S. Holders should consult with their tax advisors regarding the above issues.

        Any amounts withheld from a payment to a non-U.S. Holder under the backup withholding rules will be allowed as a credit against the holder's United States federal income tax liability and may entitle the holder to a refund, provided that the required information is furnished to the Internal Revenue Service.

        Applicable identification requirements generally will be satisfied if there is delivered to a securities clearing organization either directly, or indirectly, by the appropriate filing of a Form W-8IMY:

(1)

IRS Form W-8BEN signed under penalties of perjury by the non-U.S. Holder, stating that such holder of the notes is not a United States person and providing such non-U.S. Holder's name and address;



(2)

with respect to non-U.S. Holders of the notes residing in a country that has a tax treaty with the United States who seek an exemption or reduced tax rate (depending on the treaty terms), Form W-8BEN. If the treaty provides only for a reduced rate, withholding tax will be imposed at that rate unless the non-U.S. Holder qualifies under the portfolio interest rules set forth in the Code and files a W-8BEN; or



(3)

with respect to interest income "effectively connected" with the conduct by such non-U.S. Holder of a trade or business carried on in the United States, Form W-8ECI;

        provided that in any such case:

•

the applicable form is delivered pursuant to applicable procedures and is properly transmitted to the United States withholding agent, otherwise required to withhold tax; and



•

none of the entities receiving the form has actual knowledge or reason to know that the holder is a U.S. Holder.

140

LEGAL MATTERS

        The validity of the issuance of the notes and the Abraxas common stock covered by this prospectus has been passed upon for Abraxas by Cox & Smith Incorporated, San Antonio, Texas.

EXPERTS

        The consolidated financial statements of Abraxas as of December 31, 2002, and for each of the two years in the period ended December 31, 2002, included in this prospectus have been audited by Deloitte & Touche LLP, independent registered public accounting firm, as stated in their report dated March 10, 2003, July 18, 2003 as to Note 19 and the first paragraph of "New Accounting Pronouncements" in Note 1, appearing herein (which report expresses an unqualified opinion and includes two explanatory paragraphs referring to subsequent events described in Note 2 and the restatement described in Note 19), and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

        The consolidated financial statements of Abraxas as of December 31, 2003 and for the year ended December 31, 2003, included in this prospectus have been audited by BDO Seidman, LLP, independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion and includes a paragraph referring to a change in accounting method), and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

        The historical reserve information prepared by DeGolyer and MacNaughton and McDaniel and Associates Consultants Ltd. included in this prospectus has been included herein in reliance upon the authority of such firm as experts with respect to matters contained in such reserve reports.

WHERE YOU CAN FIND MORE INFORMATION

        Abraxas and the guarantors of the notes have filed the registration statement regarding the notes and Abraxas common stock with the SEC. This prospectus does not contain all of the information included in the registration statement. Any statement made in this prospectus concerning the contents of any other document is not necessarily complete. If we have filed any other document as an exhibit to the registration statement, you should read the exhibit for a more complete understanding of the document or matter. Each statement regarding any other document does not necessarily contain all of the information important to you.

        Abraxas files annual, quarterly and special reports, proxy statements and other information with the SEC. Our SEC filings are available to the public over the Internet at the SEC's website at http://www.sec.gov. You may also read and copy any document Abraxas files at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. You may obtain information on the operation of the SEC's public reference room in Washington, D.C. by calling the SEC at 1-800-SEC-0330.

141

GLOSSARY OF TERMS

        Unless otherwise indicated in this prospectus, natural gas volumes are stated at the legal pressure base of the State or area in which the reserves are located at 60 degrees Fahrenheit. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs.

        The following definitions shall apply to the technical terms used in this prospectus.

Terms used to describe quantities of crude oil and natural gas

        "Bbl"—barrel or barrels.

        "Bcf"—billion cubic feet.

        "Bcfe"—billion cubic feet equivalent.

        "BoE"—barrels of

        "BOPD"—barrels of crude oil per day.

        "MBbl"—thousand barrels.

        "Mcf"—thousand cubic feet.

        "Mcfe"—thousand cubic feet equivalent.

        "MMBbls"—million barrels.

        "MMBTU"—million British Thermal Units.

        "MMBTUpd"—million British Thermal Units per day.

        "MMcf"—million cubic feet.

        "MMcfe"—million cubic feet equivalent.

        "MMcfpd"—million cubic feet per day.

Terms used to describe our interests in wells and acreage

        "Developed acreage" means acreage which consists of acres spaced or assignable to productive wells.

        "Gross" natural gas and crude oil wells or "gross" wells or acres is the number of wells or acres in which we have an interest.

        "Net" natural gas and crude oil wells or "net" acres are determined by multiplying "gross" wells or acres by our working interest in such wells or acres.

        "Undeveloped acreage" means leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless whether or not such acreage contains proved reserves.

Terms used to assign a present value to or to classify our reserves

        "PV-10" means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.

        "Proved reserves" or "reserves" means natural gas and crude oil, condensate and NGLs on a net revenue interest basis, found to be commercially recoverable.

142

        "Proved undeveloped reserves" includes those proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Terms used to describe costs

        "DD&A" means depletion, depreciation and amortization.

        "LOE" means lease operating expenses and production taxes.

Terms used to describe types of wells

        "Development well" means a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of stratigraphic horizon (rock layer or formation) known to be productive for the purpose of extraction of proved crude oil or natural gas reserves.

        "Dry hole" means an exploratory or development well found to be incapable of producing either crude oil or gas in sufficient quantities to justify completion as a crude oil or natural gas well.

        "Exploratory well" means a well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil or natural gas in another reservoir, or to extend a known reservoir.

        "Productive wells" mean producing wells and wells capable of production.

        "Service Well" is a well used for water injection in secondary recovery projects or for the disposal of produced water.

Other terms

        "Charge" means an encumbrance, lien, claim or other interest in property securing payment or performance of an obligation.

        "EBITDA" means earnings from before income taxes, interest expense, DD&A and other non-cash charges.

        "NGL" means natural gas liquid.

        "NYMEX" means the New York Mercantile Exchange.

143

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Abraxas Petroleum Corporation

        We have audited the accompanying consolidated balance sheet of Abraxas Petroleum Corporation (the "Company") as of December 31, 2003, and the related consolidated statements of operations, stockholders' deficit, and cash flows and other comprehensive income for the year ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audit in accordance with auditing standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Abraxas Petroleum Corporation at December 31, 2003, and the results of its operations and its cash flows for the year ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 1 to the consolidated financial statements, as of January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

/s/BDO Seidman, LLP
Dallas, Texas
February 13, 2004

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Abraxas Petroleum Corporation

        We have audited the accompanying consolidated balance sheet of Abraxas Petroleum Corporation and Subsidiaries (the "Company") as of December 31, 2002, and the related consolidated statements of operations, stockholders' deficit, and cash flows and other comprehensive income for each of the two years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2002, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 2 to the financial statements, on January 23, 2003, the Company sold all of the outstanding common stock of two wholly owned subsidiaries, Canadian Abraxas Petroleum Limited and Grey Wolf Exploration, Inc., repaid certain debt, and also entered into an agreement to exchange cash, new debt and common stock of the Company for certain other debt.

        As discussed in Note 19 to the financial statements, the accompanying 2001 and 2002 financial statements have been restated.

/s/DELOITTE & TOUCHE LLP
San Antonio, Texas
March 10, 2003 (July 18, 2003, as to Note 19 and the first paragraph of "New Accounting Pronouncements" in Note 1)

F-3

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

ASSETS

					December 31
					2002		2003
					(Dollars in thousands)
Current assets:
	Cash				$	4,882	$	493
	Accounts receivable:
			Joint owners			2,215		1,360
			Oil and gas production sales			7,466		5,873
			Other			364		1,090
						10,045		8,323
	Equipment inventory					1,014		782
	Other current assets					1,240		572
		Total current assets				17,181		10,170
Property and equipment:
		Oil and gas properties, full cost method of accounting:
			Proved			521,995		325,222
			Unproved, not subject to amortization			7,052		4,304
		Other property and equipment				44,189		4,540
				Total		573,236		334,066
		Less accumulated depreciation, depletion, and amortization				422,842		222,503
			Total property and equipment—net.			150,394		111,563
Deferred financing fees net						5,671		4,410
Deferred income taxes						7,820		—
Other assets						359		294
	Total assets				$	181,425	$	126,437

See accompanying notes to consolidated financial statements

F-4

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS (CONTINUED)

LIABILITIES AND STOCKHOLDERS' DEFICIT

			December 31
			2002			2003
			(Dollars in thousands)
Current liabilities:
	Accounts payable		$	9,687		$	6,756
	Joint interest oil and gas production payable			2,432			2,290
	Accrued interest			6,009			2,340
	Other accrued expenses			1,162			1,228
	Current maturities of long-term debt			63,500			—
		Total current liabilities		82,790			12,614
Long-term debt				236,943			184,649
Future site restoration				3,946			1,377
Stockholders' equity (deficit):
	Common stock, par value $.01 per share—authorized 200,000,000 shares; issued 30,145,280 and 36,024,308 at December 31, 2002 and 2003 respectively			301			360
	Additional paid-in capital			136,830			141,835
	Receivables from stock sale			(97	)		(97	)
	Accumulated deficit			(269,621	)		(213,701	)
	Treasury stock, at cost, 165,883 shares			(964	)		(964	)
	Accumulated other comprehensive income (loss)			(8,703	)		364
Total stockholders' deficit				(142,254	)		(72,203	)
	Total liabilities and stockholders' deficit		$	181,425		$	126,437

See accompanying notes to consolidated financial statements

F-5

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

		Year Ended December 31
		2001			2002			2003
		(In thousands except per share data)
Revenues:
	Oil and gas production revenues	$	73,201		$	50,862		$	38,105
	Gas processing revenues		2,438			2,420			133
	Rig revenues		756			635			663
	Other		848			403			118
			77,243			54,320			39,019
Operating costs and expenses:
	Lease operating and production taxes		18,616			15,240			9,599
	Depreciation, depletion, and amortization		32,484			26,539			10,803
	Proved property impairment		2,638			115,993			—
	Rig operations		702			567			609
	General and administrative		6,445			6,884			5,360
	Stock-based compensation		(2,767	)		—			1,106
			58,118			165,223			27,477
Operating income (loss)			19,125			(110,903	)		11,542
Other (income) expense:
	Interest income		(78	)		(92	)		(30	)
	Amortization of deferred financing fees		2,268			2,095			1,678
	Interest expense		31,523			34,150			16,955
	Financing costs		—			967			4,406
	Loss on sale of equity investment		845			—			—
	Gain on sale of foreign subsidiaries		—			—			(68,933	)
	Other		207			201			774
			34,765			37,321			(45,150	)
Income (loss) before cumulative effect of accounting change and taxes			(15,640	)		(148,224	)		56,692
Income tax expense (benefit):
	Current		505			—			—
	Deferred		1,897			(29,697	)		377
Minority interest in income of foreign subsidiary (2001 prior to purchase)			1,676			—			—
Cumulative effect of accounting change			—			—			395
Net income (loss)		$	(19,718	)	$	(118,527	)	$	55,920
Basic earnings (loss)per common share:
	Net earnings (loss)	$	(0.76	)	$	(3.95	)	$	1.59
	Cumulative effect of accounting change		—			—			(0.01	)
Net income (loss) per common share—basic		$	(0.76	)	$	(3.95	)	$	1.58
Diluted earnings (loss) per common share:
	Net earnings (loss)	$	(0.76	)	$	(3.95	)	$	1.56
	Cumulative effect of accounting change		—			—			(0.01	)
Net income (loss) per common share—diluted		$	(0.76	)	$	(3.95	)	$	1.55

See accompanying notes to consolidated financial statements

F-6

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT

(In thousands except share amounts)

				Common Stock			Treasury Stock										Accumulated Other Comprehensive Income (Loss)
											Additional Paid-In Capital			Accumulated Deficit						Receivables From Stock Sale
				Shares	Amount		Shares	Amount															Total
Balance at December 31, 2000				22,759,852	$	227	165,883	$	(964	)	$	130,409		$	(131,376	)	$	(4,799	)	$	(97	)	$	(6,600	)
	Comprehensive income (loss):
	Net loss			—		—	—		—			—			(19,718	)		—						(19,718	)
		Other comprehensive income:
			Hedge loss	—		—	—		—			—			—			(566	)		—			(566	)
			Foreign currency translation adjustment	—		—	—		—			—			—			(8,196	)		—			(8,196	)
	Comprehensive income (loss)																							(28,480	)
	Stock-based compensation expense			—		—	—		—			(2,767	)		—			—			—			(2,767	)
	Issuance of common stock for contingent value rights			3,386,488		34	—		—			(34	)		—			—			—			—
	Issuance of common stock and stock options for acquisition of minority interest in Old Grey Wolf Exploration, Inc.			3,990,565		40	—		—			9,206			—			—			—			9,246
	Stock options exercised			8,375		—	—		—			16			—			—			—			16
Balance at December 31, 2001				30,145,280	$	301	165,883	$	(964	)	$	136,830		$	(151,094	)	$	(13,561	)	$	(97	)	$	(28,585	)
	Comprehensive income (loss):
	Net loss			—		—	—		—			—			(118,527	)		—			—			(118,527	)
		Other comprehensive income:
			Hedge income	—		—	—		—			—			—			566			—			566
			Foreign currency translation adjustment	—		—	—		—			—			—			4,292			—			4,292
	Comprehensive income (loss)																							(113,669	)
Balance at December 31, 2002				30,145,280	$	301	165,883	$	(964	)	$	136,830		$	(269,621	)	$	(8,703	)	$	(97	)	$	(142,254	)
	Comprehensive income (loss):
	Net income			—		—	—		—			—			55,920						—			55,920
		Other comprehensive income (loss):
			Foreign currency translation adjustment	—		—	—		—			—			—			9,067			—			9,067
	Comprehensive income																							64,987
	Stock-based compensation expense			—		—	—		—			1,106			—			—			—			1,106
	Stock options exercised			129,352		1	—		—			84			—			—			—			85
	Stock issued for acquisition of Wind River Resources			106,977		1	—		—			91			—			—			—			92
	Stock issued in connection with exchange offer			5,642,699		57	—		—			3,724			—			—			—			3,781
Balance at December 31, 2003				36,024,308	$	360	165,883	$	(964	)	$	141,835		$	(213,701	)	$	364		$	(97	)	$	(72,203	)

See accompanying notes to consolidated financial statements.

F-7

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

			Years Ended December 31
			2001			2002			2003
			(In thousands)
Operating Activities
Net income (loss)			$	(19,718	)	$	(118,527	)	$	55,920
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
	Minority interest in income of foreign subsidiary			1,676			—			—
	Loss on sale of equity investment			845			—			—
	(Gain) on sale of foreign subsidiaries			—			—			(68,933	)
	Depreciation, depletion, and amortization			32,484			26,539			10,803
	Non-cash interest and financing cost			—			—			16,422
	Proved property impairment			2,638			115,993			—
	Deferred income tax expense (benefit)			1,897			(29,697	)		377
	Amortization of deferred financing fees			2,268			2,095			1,678
	Stock-based compensation			(2,767	)		—			1,106
	Changes in operating assets and liabilities:
		Accounts receivable		12,693			(2,247	)		(1,446	)
		Equipment inventory		(76	)		201			78
		Other		(106	)		126			295
		Accounts payable		(14,848	)		(2,775	)		3,417
		Accrued expenses		(723	)		(44	)		4,133
Net cash provided by (used) in operations				16,263			(8,336	)		23,850
Investing Activities
Capital expenditures, including purchases and development of properties				(57,056	)		(38,912	)		(18,349	)
Proceeds from sale of oil and gas properties				28,938			33,876			—
Acquisition of minority interest				(2,679	)		—			—
Proceeds from sale of foreign subsidiaries				—			—			85,810
Net cash provided by (used) in investing activities				(30,797	)		(5,036	)		67,461
Financing Activities
Proceeds from issuance of common stock				16			—			177
Proceeds from long-term borrowings				29,995			20,551			43,342
Payments on long-term borrowings				(9,326	)		(8,176	)		(138,544	)
Deferred financing fees				—			(1,539	)		(597	)
Net cash (used in) provided by financing activities				20,685			10,836			(95,622	)
Increase (decrease) in cash				6,151			(2,536	)		(4,311	)
Effect of exchange rate changes on cash				(550	)		(187	)		(78	)
Increase (decrease) in cash				5,601			(2,723	)		(4,389	)
Cash at beginning of year				2,004			7,605			4,882
Cash at end of year			$	7,605		$	4,882		$	493

F-8

Supplemental Disclosures
Supplemental disclosures of cash flow information:
	Interest paid	$	31,752		$	34,154	$	4,279
	Taxes paid	$	505		$	—	$	—
Supplemental schedule of non-cash investing and financing activities:
In May 2001 the Company issued 3,386,488 shares of common stock upon the expiration of the CVRs issued in connection with the December 1999 exchange.
In September 2001 the Company issued 3,990,565 shares of common stock and options and paid $2,679,000 million in cash in connection with the acquisition of the minority interest in Old Grey Wolf. (See Note 4.)
Decrease in oil and gas properties and other assets		$	(2,925	)
Decrease in deferred income tax liability		$	1,091
Increase in stockholders equity		$	(9,246	)
Decrease in minority interest in foreign subsidiary		$	13,759

See accompanying notes to consolidated financial statements.

F-9

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)

			Years Ended December 31,
			2001			2002			2003
			(In thousands)
	Net income (loss)		$	(19,718	)	$	(118,527	)	$	55,920
	Other Comprehensive income (loss):
	Hedging derivatives (net of tax)—See Note 16			(566	)					—
		Reclassification adjustment for settled hedge contracts, net of taxes		—			2,556			—
		Change in fair market value of outstanding hedge positions net of taxes		—			(1,990	)		—
				—			566			—
	Foreign currency translation adjustment
		Reclassification of foreign currency translation adjustment relating to the sale of foreign subsidiaries		—			—			4,632
		Effect of change in exchange rate		—			—			4,435
Other comprehensive income (loss)				(8,762	)		4,858			9,067
Comprehensive income (loss)			$	(28,480	)	$	(113,669	)	$	64,987

See accompanying notes to consolidated financial statements.

F-10

ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.     Organization and Significant Accounting Policies

Nature of Operations

        Abraxas Petroleum Corporation (the "Company" or "Abraxas") is an independent energy company engaged in the exploration for and the acquisition, development, and production of crude oil and natural gas primarily along the Texas Gulf Coast, in the Permian Basin of western Texas and in western Canada. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

        The consolidated financial statements include the accounts of the Company and its wholly-owned foreign subsidiary, Grey Wolf Exploration Inc. ("New Grey Wolf"). In January 2003, the Company sold all of the common stock of its wholly-owned foreign subsidiaries, Canadian Abraxas Petroleum Limited ("Canadian Abraxas") and Grey Wolf Exploration Inc. ("Old Grey Wolf"). Certain oil and gas properties were retained and transferred into New Grey Wolf which was incorporated in January 2003. The operations of Canadian Abraxas and Old Grey Wolf are included in the consolidated financial statements through January 23, 2003.

        New Grey Wolf's assets and liabilities are translated to U.S. dollars at period-end exchange rates. Income and expense items are translated at average rates of exchange prevailing during the period. Translation adjustments are accumulated as a separate component of shareholders' equity.

Use of Estimates

        The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Management believes that it is reasonably possible that estimates of proved crude oil and natural gas revenues could significantly change in the future.

Concentration of Credit Risk

        Financial instruments, which potentially expose the Company to credit risk consist principally of trade receivables and crude oil and natural gas price swap agreements. Accounts receivable are generally from companies with significant oil and gas marketing activities. The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers.

Cash and Equivalents

        Cash and cash equivalents includes cash on hand, demand deposits and short-term investments with original maturities of three months or less.

Accounts Receivable

        Accounts receivable are reported net of an allowance for doubtful accounts of approximately $77,000 and $11,000 at December 31, 2002 and 2003, respectively. The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible.

F-11

Equipment Inventory

        Equipment inventory principally consists of casing, tubing, and compression equipment and is carried at cost.

Oil and Gas Properties

        The Company follows the full cost method of accounting for crude oil and natural gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized crude oil and natural gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of crude oil and natural gas properties, as adjusted for asset retirement obligations, less related deferred taxes, are limited, by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Excess costs are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of crude oil and natural gas properties, except in unusual circumstances.

        Unproved properties represent costs associated with properties on which the Company is performing exploration activities or intends to commence such activities. These costs are reviewed periodically for possible impairments or reduction in value based on geological and geophysical data. If a reduction in value has occurred, costs being amortized are increased. The Company believes that the unproved properties will be substantially evaluated in six to thirty-six months and it will begin to amortize these costs at such time. During 2001, 2002 and 2003 the Company capitalized $164,000, $152,000 and $49,000 of interest expense respectively, based on the cost of major development projects in progress.

Other Property and Equipment

        Other property and equipment are recorded on the basis of cost. Depreciation of other property and equipment is provided over the estimated useful lives using the straight-line method. Major renewals and betterments are recorded as additions to the property and equipment accounts. Repairs that do not improve or extend the useful lives of assets are expensed.

Hedging

        The Company periodically enters into agreements to hedge the risk of future crude oil and natural gas price fluctuations. Such agreements are primarily in the form of price floors and collars, which limit the impact of price fluctuations with respect to the Company's sale of crude oil and natural gas. The Company does not enter into speculative hedges. Gains and losses on such hedging activities are recognized in oil and gas production revenues when hedged production is sold. The net cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If the hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production required by the contract is delivered.

        Statement of Financial Accounting Standards, ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," was effective for the Company on January 1, 2001. SFAS 133, as amended and interpreted, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. All derivatives, whether designated in hedging relationships or not, will be required to be recorded on the balance sheet at fair value. If the derivative is designated a fair-value hedge, the changes in the fair

F-12

value of the derivative and the hedged item will be recognized in earnings. If the derivative is designated a cash-flow hedge, changes in the fair value of the derivative will be recorded in other comprehensive income (OCI) and will be recognized in the income statement when the hedged item affects earnings. SFAS 133 defines new requirements for designation and documentation of hedging relationships as well as ongoing effectiveness assessments in order to use hedge accounting. For a derivative that does not qualify as a hedge, changes in fair value will be recognized in earnings.

Stock-Based Compensation

        The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees," (APB No. 25) and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount an employee must pay to acquire the stock.

        Effective July 1, 2000, the Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions Involving Stock Compensation," an interpretation of APB No. 25. Under the interpretation, certain modifications to fixed stock option awards which were made subsequent to December 15, 1998, and were not exercised prior to July 1, 2000, require that the awards be accounted for as variable until they are exercised, forfeited, or expired. In March 1999, the Company amended the exercise price to $2.06 on all options with an existing exercise price greater than $2.06. The Company recognized a credit of $2.8 million during 2001 as stock-based compensation. The credit for the year ended December 31, 2001 was due to a decline in the Company's common stock price. There was no stock based compensation for the year ended December 31, 2002. In January 2003, in connection with the restructuring (see note 2), the Company amended the exercise price to $0.66 on certain options with an existing exercise price greater than $0.66. The Company recognized stock-based compensation expense of approximately $1.1 million during 2003.

        Pro forma information regarding net income (loss) and earnings (loss) per share is required by SFAS 123, "Accounting for Stock-Based Compensation, (SFAS 123)" which also requires that the information be determined as if the Company has accounted for its employee stock options granted subsequent to December 31, 1995 under the fair value method prescribed by SFAS No. 123. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 2001, 2002 and 2003, risk-free interest rates of 3.5%, 1.50% and 1.5%, respectively; dividend yields of -0—%; volatility factors of the expected market price of the Company's common stock of .35, and a weighted-average expected life of the option of ten years.

        The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options.

F-13

        For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The Company's pro forma information follows:

		Year Ended December 31
		2001			2002			2003
Net income (loss) as reported		$	(19,718	)	$	(118,527	)	$	55,920
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects			(2,767	)		—			1,106
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(1,284	)		(670	)		(228	)
Pro forma net income (loss)		$	(23,769	)	$	(119,197	)	$	56,798
Earnings (loss) per share:
	Basic—as reported	$	(0.76	)	$	(3.95	)	$	1.58
	Basic—pro forma	$	(0.92	)	$	(3.98	)	$	1.61
Diluted—as reported		$	(0.76	)	$	(3.95	)	$	1.55
Diluted—pro forma		$	(0.92	)	$	(3.98	)	$	1.57

Foreign Currency Translation

        The functional currency for Canadian Abraxas and Grey Wolf (Old and New) is the Canadian dollar ($CDN). The Company translates the functional currency into U.S. dollars ($US) based on the current exchange rate at the end of the period for the balance sheet and a weighted average rate for the period on the statement of operations. Translation adjustments are reflected as accumulated other comprehensive income (loss) in the consolidated financial statement of stockholders' deficit.

Fair Value of Financial Instruments

        The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the book value. The Company assumes the book value of those financial instruments that are classified as current approximates fair value because of the short maturity of these instruments. For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments.

Restoration, Removal and Environmental Liabilities

        The Company is subject to extensive Federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

        Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable.

F-14

Revenue Recognition

        The Company recognizes crude oil and natural gas revenue from its interest in producing wells as crude oil and natural gas is sold from those wells, net of royalties. Revenue from the processing of natural gas is recognized in the period the service is performed. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, income is recorded based on the Company's net revenue interest in production taken for delivery. The Company had no material gas imbalances at December 31, 2003.

Deferred Financing Fees

        Deferred financing fees are being amortized on a level yield basis over the term of the related debt arrangements.

Income Taxes

        The Company records deferred income taxes using the liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.

New Accounting Pronouncements

        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 gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of such mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Company would be required to reclassify approximately $3.1 million and $4.2 million at December 31, 2002 and December 31, 2003, respectively, out of oil and gas properties and into a separate intangible assets line item. The Company's 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 full-cost accounting rules.

        In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 is effective for us January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements.

        The Company adopted SFAS 143 effective January 1, 2003. For the year ended December 31, 2003 the Company recorded a charge of $395,341 for the cumulative effect of the change in accounting principle and a liability of $1.3 million. During 2003, the Company charged approximately $379,000 to

F-15

expense related to the accretion of the liability. The impact on each of the prior periods was not material.

        The following table summarizes the Company's asset retirement obligation transactions during the following years:

	2003			2002			2001
Beginning asset retirement obligation	$	3,946		$	4,056		$	4,305
Additions related to new properties		973			196			—
Deletions related to property disposals		(3,921	)		(306	)		(249	)
Accretion expense		379			—			—
Ending asset retirement obligation	$	1,377		$	3,946		$	4,056

        In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). Effective January 1, 2002, the Company adopted SFAS 144. SFAS 144 retains the requirement to recognize an impairment loss only where the carrying value of a long-lived asset is not recoverable from its undiscounted cash flows and to measure such loss as the difference between the carrying amount and fair value of the asset. SFAS 144, among other things, changes the criteria that have to be met to classify an asset as held-for-sale and requires that operating losses from discontinued operations be recognized in the period that the losses are incurred rather than as of the measurement date. This new standard had no impact on the Company's consolidated financial statements for the year ended December 31, 2003.

        In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS 146). SFAS 146 requires costs associated with exit of disposal activities to be recognized when they are incurred rather than at the date of commitment to an exit or disposal plan. The Company is currently evaluating the impact the standard will have on its results of operations and financial condition. The effective date of this standard has not been determined by the FASB.

        In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 149, among other things, clarifies the circumstances under which a contract with an initial net investment meets the characteristic of a derivative and amends the definition of an "underlying" to conform it to language used in FIN 45. SFAS 149 is effective for contracts entered into or modified after June 30, 2003. The Company adopted this statement effective July 1, 2003. Implementation of this new standard did not have an effect on the Company's consolidated financial position or results of operations.

        In November 2002 the FASB issued FASB Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees that it has issued, including loan guarantees such as standby letters of credit. It also requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligations it has undertaken in issuing the guarantee. The Interpretation does not specify the subsequent measurement of the guarantor's recognized liability over the term of the related guarantee. The guidance in FIN 45 does not apply to certain guarantee contracts, such as those issued by insurance companies or for a lessee's residual value guarantee embedded in a capital lease. The provisions related to recognizing a liability at inception of the guarantee for the fair value of the guarantor's obligations would not apply to product warranties or to guarantees accounted for as derivatives. The initial recognition and initial measurement provisions

F-16

apply on a prospective basis to guarantees issued or modified after December 31, 2002, regardless of the guarantor's fiscal year-end. FIN 45 specifies additional disclosures effective for financial statements of interim or annual periods ending after December 15, 2002. This new standard did not have an effect on the Company's consolidated financial position or results of operations.

        In January 2003 the FASB issued FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable-Interest Entities (VIEs".) FIN 46 establishes the definition of VIEs to encompass a broader group of entities than those previously considered special-purpose entities (SPEs). FIN 46 specifies the criteria under which it is appropriate for an investor to consolidate VIEs; in order for an investor to consolidate a VIE, the entity must fall within the definition of VIE and the investor must fall within the definition of primary beneficiary, both newly defined terms under this interpretation. The revised effective date of FIN 46 for public companies with VIEs meeting certain conditions will be the end of the first interim or annual period ending after December 15, 2003. In December 2003 the FASB issued FASB Interpretation no. 46(R), which expanded and clarified the guidelines of FIN 46. This new standard did not have an effect on the Company's consolidated financial position or results of operations.

        In May 2003, the FASB issued SFAS No. 150, entitled "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" (SFAS 150). This statement is effective for financial instruments entered into or modified after May 31, 2003, and is otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The Company has no financial instruments affected by SFAS 150, therefore adoption by the Company as of July 1, 2003 will not impact the Company's financial statements.

2.     Restructuring transactions

        In January 2003, the Company completed the following restructuring transactions:

•

The closing of the sale of the capital stock of Canadian Abraxas Petroleum and Old Grey Wolf, to a Canadian royalty trust for approximately $138 million.



•

The closing of a new senior credit agreement consisting of a term loan facility of $4.2 million and a revolving credit facility of up to $50 million with an initial borrowing base of $49.9 million, of which $42.5 million was used to fund the exchange offer described below and the remaining availability will be used to fund the continued development of our existing crude oil and natural gas properties.



•

The closing of an exchange offer, pursuant to which Abraxas paid $264 in cash and issued $610 principal amount of new 11¹/2% Secured Notes due 2007, Series A, referred to herein as New Notes, and 31.36 shares of Abraxas common stock for each $1,000 in principal amount of the outstanding 11¹/2% Senior Secured Notes due 2004, Series A, and 11¹/2% Senior Notes due 2004, Series D, issued by Abraxas and Canadian Abraxas, which were tendered and accepted in the exchange offer. An aggregate of approximately $179.9 million in principal amount of the notes were tendered in the exchange offer and the remaining $11.1 million of notes not tendered were redeemed.



•

The repayment of Abraxas' 12? % Senior Secured Notes due 2003, principal amount of $63.5 million, plus accrued interest.



•

The repayment of Old Grey Wolf's senior secured credit facility with Mirant Canada Energy Capital Ltd. (Mirant Canada Facility) in the amount of approximately $46.3 million.

        On February 23, 2004, the Company entered into an amendment to our existing senior credit agreement providing for two revolving credit facilities and a new non-revolving credit facility as described below. Subject to earlier termination on the occurrence of events of default or other events,

F-17

the stated maturity date for these credit facilities is February 1, 2007. In the event of an early termination, we will be required to pay a prepayment premium, except in the limited circumstances described in the amended senior credit agreement.

        First Revolving Credit Facility.    Lenders under the amended senior credit agreement have provided Abraxas a revolving credit facility with a maximum borrowing base of up to $20 million. The Company's current borrowing base under this revolving credit facility is the full $20.0 million, subject to adjustments based on periodic calculations and mandatory prepayments under the senior credit agreement. The Company has borrowed $6.6 million under this revolving credit facility, which was used to refinance principal and interest on advances under it's preexisting revolving credit facility under the senior credit agreement, and to pay certain fees and expenses relating to the transaction. Outstanding amounts under this revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 1.125%.

        Second Revolving Credit Facility.    Lenders under the amended senior credit agreement have provided a second revolving credit facility, with a maximum borrowing of up to $30 million. This revolving credit facility is not subject to a borrowing base. The Company has borrowed $30.0 million under this revolving credit facility, which was used to refinance principal and interest on advances under our preexisting revolving credit facility, and to pay certain transaction fees and expenses. Outstanding amounts under this revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 3.00%.

        Non-Revolving Credit Facility.    The Company has borrowed $15.0 million pursuant to a non-revolving credit facility, which was used to repay the preexisting term loan under it's senior credit agreement, to refinance principal and interest on advances under the preexisting revolving credit facility, and to pay certain transaction fees and expenses. This non-revolving credit facility is not subject to a borrowing base. Outstanding amounts under this credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 8.00%.

        Covenants.    Under the amended senior credit agreement, we are subject to customary covenants and reporting requirements. Certain financial covenants require us to maintain minimum ratios of consolidated EBITDA (as defined in the amended senior credit agreement) to adjusted fixed charges (which includes certain capital expenditures), minimum ratios of consolidated EBITDA to cash interest expense, a minimum level of unrestricted cash and revolving credit availability, minimum hydrocarbon production volumes and minimum proved developed hydrocarbon reserves. In addition, if on the day before the end of each fiscal quarter the aggregate amount of our cash and cash equivalents exceeds $2.0 million, we are required to repay the loans under the amended senior credit agreement in an amount equal to such excess. The amended senior credit agreement also requires us to enter into hedging agreements on not less than 40% or more than 75% of our projected oil and gas production. We are also required to establish deposit accounts at financial institutions acceptable to the lenders and we are required to direct our customers to make all payments into these accounts. The amounts in these accounts will be transferred to the lenders upon the occurrence and during the continuance of an event of default under the amended senior credit agreement.

        In addition to the foregoing and other customary covenants, the amended senior credit agreement contains a number of covenants that, among other things, restrict our ability to:

•

incur additional indebtedness;



•

create or permit to be created liens on any of our properties;



•

enter into change of control transactions;



•

dispose of our assets;

F-18

•

change our name or the nature of our business;



•

make guarantees with respect to the obligations of third parties;



•

enter into forward sales contracts;



•

make payments in connection with distributions, dividends or redemptions relating to our outstanding securities, or



•

make investments or incur liabilities.

        Security.    The obligations of Abraxas under the amended senior credit agreement continue to be secured by a first lien security interest in substantially all of Abraxas' assets, including all crude oil and natural gas properties.

        Guarantees.    The obligations of Abraxas under the amended senior credit agreement continue to be guaranteed by Abraxas' subsidiaries, Sandia Oil & Gas, Sandia Operating, Wamsutter, Grey Wolf, Western Associated Energy and Eastside Coal. The guarantees under the amended senior credit agreement continue to be secured by a first lien security interest in substantially all of the guarantors' assets, including all crude oil and natural gas properties.

        Events of Default.    The amended senior credit agreement contains customary events of default, including nonpayment of principal or interest, violations of covenants, inaccuracy of representations or warranties in any material respect, cross default and cross acceleration to certain other indebtedness, bankruptcy, material judgments and liabilities, change of control and any material adverse change in our financial condition.

        The following presents the summarized results of operations for the years ended December 31, 2001, 2002, and for the period ended January 23, 2003, for the Canadian properties which were not retained after the transaction in January 2003.

	Year ended December 31,
	2001			2002			2003
Total revenue	$	41,468		$	32,013		$	3,275
Income (loss) from operations before income tax		(102	)		(87,378	)		1,250
Income tax expense (benefit)		1,897			(29,697	)		377
Minority interest in income		(1,676	)		—			—
Income (loss) from operations	$	(3,675	)	$	(57,681	)	$	873

F-19

        Assets and liabilities related to the Canadian properties which were not retained after the January 2003 transaction:

	December 31, 2002
Assets:
Cash	$	4,325
Accounts receivable		4,016
Net property and equipment		54,468
Other		11,438
	$	74,247
Liabilities:
Accounts payable and accrued liabilities	$	7,320
Long-tern debt		45,964
Other		3,413
	$	56,697

        Included in the loss from operations shown above is interest expense of $7.6 million and $9.5 million, and general and administrative expense of $1.5 million and $1.7 million for the years ended December 31, 2001 and 2002, respectively. The interest expense represents the amounts relating to an Old Grey Wolf senior credit facility which was repaid in conjunction with the transactions described above and the amounts related to the balance of certain notes (approximately $52.6 million) which had historically been reflected by Canadian Abraxas.

3.     Long-Term Debt

        As described in Note 2, the First Lien Notes were redeemed in January 2003. The Old Notes and the Second Lien Notes were either redeemed or exchanged for cash, common stock and New Notes in January 2003. Additionally, the 9.5% Mirant Canada Energy Capital, Ltd. credit facility, with a balance outstanding at December 31, 2002 of $45.9 million, was repaid in connection with the sale of the common stock of Old Grey Wolf in January 2003.

F-20

        The following is a brief description of the Company's debt as of December 31, 2002 and 2003, respectively:

	December 31
	2002		2003
	(in thousands)
11.5% Senior Notes due 2004 ("Old Notes")	$	801	$	—
12.875% Senior Secured Notes due 2003 ("First Lien Notes")		63,500		—
11.5% Second Lien Notes due 2004 ("Second Lien Notes")		190,178		—
9.5% Senior Credit Facility ("Grey Wolf Facility") providing for borrowings up to approximately US $96 million (CDN $150 million). Secured by the assets of Old Grey Wolf and non-recourse to Abraxas		45,964		—
11.5% Secured Notes due 2007 ("New Notes")		—		137,258	(a)
Senior Credit Agreement		—		47,391
		300,443		184,649
Less current maturities		63,500		—
	$	236,943	$	184,649

(a)

After the transactions described in Note 2, for financial reporting purposes, the New Notes were reflected at the carrying value of the Second Lien Notes and Old Notes prior to the exchange of $191.0 million, net of the cash offered in the exchange of $47.5 million and net of the fair market value related to equity of $3.8 million offered in the exchange transaction. The face amount of the New Notes is $120.5 million at December 31, 2003 including $10.8 million in new notes issued for interest.

        Old Notes.    Interest on the Old Notes was payable semi-annually in arrears on May 1 and November 1 of each year at the rate of 11.5% per annum. The Old Notes were redeemable, in whole or in part, at the option of the Company.

        First Lien Notes.    Interest on the First Lien Notes was payable semi-annually in arrears on March 15 and September 15 of each year at the rate of 12.875% per annum. Second Lien Notes. Interest on the Second Lien Notes was payable semi-annually in arrears on May 1 and November 1, commencing May 1, 2000 at the rate of 11.5% per annum.

        New Notes—11¹/2% Secured Notes.    The New Notes accrue interest from the date of issuance, at a fixed annual rate of 11¹/2%, payable in cash semi-annually on each May 1 and November 1, commencing May 1, 2003, provided that, if we fail, or are not permitted pursuant to our new senior secured credit agreement or the intercreditor agreement between the trustee under the indenture for the New Notes and the lenders under the new senior secured credit agreement, to make such cash interest payments in full, we will pay such unpaid interest in kind by the issuance of additional New Notes with a principal amount equal to the amount of accrued and unpaid cash interest on the New Notes plus an additional 1% accrued interest for the applicable period. Upon an event of default, the New Notes accrue interest at an annual rate of 16.5%.

        The New Notes are secured by a second lien or charge on all of our current and future assets, including, but not limited to, all of our crude oil and natural gas properties. All of Abraxas' current subsidiaries, Sandia Oil & Gas, Sandia Operating (a wholly-owned subsidiary of Sandia Oil & Gas), Wamsutter, New Grey Wolf, Western Associated Energy and Eastside Coal, are guarantors of the New Notes, and all of Abraxas' future subsidiaries will guarantee the New Notes. If Abraxas cannot make payments on the New Notes when they are due, the guarantors must make them instead.

F-21

        The New Notes and related guarantees

•

are subordinated to the indebtedness under the senior credit agreement;



•

rank equally with all of Abraxas' current and future senior indebtedness; and



•

rank senior to all of Abraxas' current and future subordinated indebtedness, in each case, if any.

        The New Notes are subordinated to amounts outstanding under the new senior secured credit agreement both in right of payment and with respect to lien priority and are subject to an intercreditor agreement.

        Abraxas may redeem the New Notes, at its option, in whole at any time or in part from time to time, at redemption prices expressed as percentages of the principal amount set forth below. If Abraxas redeems all or any New Notes, it must also pay all interest accrued and unpaid to the applicable redemption date. The redemption prices for the New Notes during the indicated time periods are as follows:

Period	Percentage
From January 24, 2004 to June 23, 2004	97.1674	%
From June 24, 2004 to January 23, 2005	98.5837	%
Thereafter	100.0000	%

        Under the indenture, we are subject to customary covenants which, among other things, restrict our ability to:

•

borrow money or issue preferred stock;



•

pay dividends on stock or purchase stock;



•

make other asset transfers;



•

transact business with affiliates;



•

sell stock of subsidiaries;



•

engage in any new line of business;



•

impair the security interest in any collateral for the notes;



•

use assets as security in other transactions; and



•

sell certain assets or merge with or into other companies.

        In addition, we are subject to certain financial covenants including covenants limiting our selling, general and administrative expenses and capital expenditures, a covenant requiring Abraxas to maintain a specified ratio of consolidated EBITDA, as defined in the agreements, to cash interest and a covenant requiring Abraxas to permanently, to the extent permitted, pay down debt under the new senior secured credit agreement and, to the extent permitted by the new senior secured credit agreement, the New Notes or, if not permitted, paying indebtedness under the new senior secured credit agreement.

        The indenture contains customary events of default, including nonpayment of principal or interest, violations of covenants, inaccuracy of representations or warranties in any material respect, cross default and cross acceleration to certain other indebtedness, bankruptcy, material judgments and liabilities, change of control and any material adverse change in our financial condition.

        Senior Credit Agreement.    In connection with the financial restructuring, Abraxas entered into a new senior credit agreement providing a term loan facility and a revolving credit facility which was

F-22

amended in February 2004. A summary description of the senior credit agreement as amended, is set forth in Note 2.

4.     Acquisitions and Divestitures

Acquisition of Minority Interest in Old Grey Wolf

        In September 2001, the Company completed a tender offer for the minority interest in Old Grey Wolf, acquiring the approximately 52% of capital stock that was not previously owned by the Company. The Company issued 3,990,565 common shares and 588,916 stock options, valued together at approximately $9.2 million. Additionally, the Company incurred direct costs of approximately $2.7 million related to the acquisition. The elimination of the minority interest through an acquisition at a purchase price less than Old Grey Wolf's book value in the Company's consolidated financial statements had the effect of reducing the property and other assets balances by $2.9 million and deferred income taxes by $1.1 million.

5.     Property and Equipment

        The major components of property and equipment, at cost, are as follows:

		December 31
	Estimated Useful Life
		2002		2003
	Years	(In thousands)
Land, buildings, and improvements	15	$	331	$	331
Crude oil and natural gas properties	—		529,047		329,526
Natural Gas Processing	18		38,735		—
Equipment and other	7		5,123		4,209
		$	573,236	$	334,066

F-23

6.     Stockholders' Equity

Common Stock

        In 1994, the Board of Directors adopted a Stockholders' Rights Plan and declared a dividend of one Common Stock Purchase Right ("Rights") for each share of common stock. The Rights are not initially exercisable. Subject to the Board of Directors' option to extend the period, the Rights will become exercisable and will detach from the common stock ten days after any person has become a beneficial owner of 20% or more of the common stock of the Company or has made a tender offer or Exchange Offer (other than certain qualifying offers) for 20% or more of the common stock of the Company.

        Once the Rights become exercisable, each Right entitles the holder, other than the acquiring person, to purchase for $40 a number of shares of the Company's common stock having a market value of two times the purchase price. The Company may redeem the Rights at any time for $.01 per Right prior to a specified period of time after a tender or Exchange Offer. The Rights will expire in November 2004, unless earlier exchanged or redeemed.

Treasury Stock

        In March 1996, the Board of Directors authorized the purchase in the open market of up to 500,000 shares of the Company's outstanding common stock, the aggregate purchase price not to exceed $3,500,000. During the year ended December 31, 2000, 38,800 shares with an aggregate cost of $78,000 were purchased. During the years ended December 31, 2001, 2002 and 2003, the Company did not purchase any shares of its common stock for treasury stock.

7.     Stock Option Plans and Warrants

Stock Options

        The Company grants options to its officers, directors, and other employees under various stock option and incentive plans.

        During 2001, the Company's stockholders approved an amendment to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan to increase the number of shares of Abraxas common stock reserved for issuance under the plan to 5,000,000 shares. The additional shares were necessary to accommodate the grant of Abraxas options to Old Grey Wolf option holders in connection with the acquisition of the minority interest in Old Grey Wolf in September 2001 (see Note 4), and for the re-issuance of outstanding options granted under the Abraxas Petroleum Corporation 2000 Long Term Incentive Plan, which was terminated in 2001. The options were re-issued at the same exercise price and term as the original issuances.

        The Company's various stock option plans have authorized the grant of options to management, employees and directors for up to approximately 5.7 million shares of the Company's common stock. All options granted have ten year terms and vest and become fully exercisable over three to four years of continued service at 25% to 33% on each anniversary date. At December 31, 2003 approximately 2.3 million options remain available for grant.

F-24

        A summary of the Company's stock option activity, and related information for the three years ended December 31, follows:

	2001				2002				2003
	Options (000s)		Weighted- Average Exercise Price		Options (000s)		Weighted- Average Exercise Price(1)		Options (000s)		Weighted- Average Exercise Price
Outstanding—beginning of year	4,042		$	3.37	4,942		$	3.28	3,305		$	1.85
Granted	918			2.81	521			0.68	360			0.68
Exercised	(8	)		1.95	—			—	(129	)		0.66
Forfeited/Expired	(10	)		1.79	(2,158	)		4.84	(172	)		1.61
Outstanding—end of year	4,942		$	3.28	3,305		$	1.85	3,364		$	0.90
Exercisable at end of year	2,259		$	2.65	2,136		$	1.91	2,331		$	0.95
Weighted-average fair value of options granted during the year			$	1.19			$	0.63			$	0.38

(1)

In September 2001, the Abraxas Petroleum Corporation 2000 Long Term Incentive Plan was terminated, and options granted under the plan were reissued under the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan at the same option price and term.

        The following table represents the range of option prices and the weighted average remaining life of outstanding options as of December 31, 2003:

	Options outstanding				Exercisable
Exercise price	Number outstanding	Weighted average remaining life	Weighted average exercise price		Number exercisable	Weighted average exercise price
$0.50 - 0.97	2,761,160	6.0	$	0.71	1,886,043	$	0.69
$1.01 - 1.63	259,900	7.8		1.22	123,050		1.40
$2.06 - 2.21	311,958	2.1		2.07	305,979		2.06
$3.39 - 4.83	31,407	6.9		4.77	16,406		4.71

        In January 2003, in connection with the financial restructuring discussed in Note 2, approximately 1.9 million options with a strike price greater that $0.66 were re-priced to $0.66.

Stock Awards

        In addition to stock options granted under the plans described above, the 1994 Long-Term Incentive Plan also provides for the right to receive compensation in cash, awards of common stock, or a combination thereof. There were no awards in 2001, 2002 or 2003.

        The Company also has adopted the Restricted Share Plan for Directors which provides for awards of common stock to non-employee directors of the Company who did not, within the year immediately preceding the determination of the director's eligibility, receive any award under any other plan of the Company. There were no direct awards of common stock in 2001, 2002 or 2003.

Stock Warrants

        In 2000, the Company issued 950,000 warrants in conjunction with a consulting agreement. Each is exercisable for one share of common stock at an exercise price of $3.50 per share. These warrants have a four-year term beginning July 1, 2000. The Company paid cash compensation of $191,000 during 2001 under the consulting agreement.

F-25

        At December 31, 2003, the Company has approximately 3.3 million shares reserved for future issuance for conversion of its stock options, warrants, and incentive plans for the Company's directors, employees and consultants.

8.     Income Taxes

        Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company's deferred tax liabilities and assets are as follows:

		December 31
		2002			2003
		(In thousands)
Deferred tax liabilities:
	U.S. full cost pool	$	—		$	4,835
Total deferred tax liabilities			—			4,835
Deferred tax assets:
	U.S. full cost pool		2,168			—
	Capital loss carryforward		—			12,895
	Original issue discount on certain debt obligations		—			22,453
	Canadian full cost pool		9,787			2,971
	Depletion		2,778			4,856
	Net operating losses ("NOL")		58,811			35,218
	Investment in foreign subsidiaries		32,038			—
	Other		1,364			2,575
Total deferred tax assets			106,946			80,968
Valuation allowance for deferred tax assets			(99,126	)		(76,133	)
Net deferred tax assets			7,820			4,835
Net deferred tax liabilities (assets)		$	(7,820	)	$	—

        Significant components of the provision (benefit) for income taxes are as follows:

		2001		2002		2003
Current:
	Federal	$	505	$	—	$	—
	Foreign		—		—		—
		$	505	$	—	$	—
Deferred:
	Federal	$	—	$	—	$	—
	Foreign		1,897		29,697		377
		$	1,897	$	29,697	$	377

        At December 31, 2003 the Company had, subject to the limitation discussed below, $100.6 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire from 2003 through 2022 if not utilized. In connection with the January 2003 transactions described in Note 2, certain of the loss carryforward may be utilized.

        At December 31, 2002, the Company was no longer permanently reinvested with respect to its foreign subsidiaries, see Note 2. As a result, the Company recorded net deferred tax assets of

F-26

$32.0 million related to its investment in foreign subsidiaries, offset by an equivalent valuation allowance due to uncertainties as to the future utilization of these amounts.

        In addition to the Section 382 limitations, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, the Company has established a valuation allowance of $99.1 million and $71.3 million for deferred tax assets at December 31, 2002 and 2003, respectively.

        The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:

	December 31
	2001			2002			2003
	(In thousands)
Tax (expense) benefit at U.S. statutory rates (35%)	$	5,318		$	51,878		$	(19,842	)
(Increase) decrease in deferred tax asset valuation allowance		(4,907	)		(59,456	)		22,993
Write-down of non-tax basis assets		(2,194	)		(7,009	)		—
Higher effective rate of foreign operations		(136	)		7,349			(2,835	)
Percentage depletion		596			683			—
Investment in foreign subsidiaries		—			35,604			—
Other		(1,079	)		648			(693	)
	$	(2,402	)	$	29,697		$	(377	)

9.     Related Party Transactions

        Accounts receivable—Other includes approximately $51,211 and $35,558 as of December 31, 2002 and 2003, respectively, representing amounts due from officers relating to advances made to employees.

        On July 29, 2003 the Company acquired all of the shares of the capital stock of Wind River Resources Corporation which owned an airplane. The sole shareholder of Wind River was the Company's President. The consideration for the purchase was 106,977 shares of Abraxas common stock and $35,000 in cash. Simultaneously with this transaction, the airplane was sold. The airplane had previously been made available to Abraxas' employees for business use.

        The Company paid Wind River a total of $314,000, $345,000 and $132,000 in 2001, 2002 and 2003, through July 29, respectively, for Wind River's operating cost associated with the Company's use of the plane.

10.   Commitments and Contingencies

Operating Leases

        During the years ended December 31, 2001, 2002 and 2003 the Company incurred rent expense related to leasing office facilities of approximately $519,000, $236,000 and $464,000 respectively. Future minimum rental payments are as follows at December 31, 2003.

2004	$	416,000
2005		412,000
2006		223,000
2007		161,000
Thereafter		161,000
	$	1,373,000

F-27

Litigation and Contingencies

        In 2001 the Company and a partnership were named in a lawsuit filed in U.S. District Court in the District of Wyoming. The claim asserts breach of contract, fraud and negligent misrepresentation by the Company related to the responsibility for year 2000 ad valorem taxes on crude oil and natural gas properties sold by the Company and the Partnership. In February 2002, a summary judgment was granted to the plaintiff in this matter and a final judgment in the amount of $1.3 million was entered. The Company has filed an appeal. The Company believes these charges are without merit. The Company has established a reserve in the amount of $845,000, which represents the Company's interest in the judgment. In 2002 the Company recorded $201,000 in other expense representing its share of the ongoing legal cost related to this matter.

        In 2003, Abraxas and Leam Drilling Systems each filed suit against the other relating to certain drilling services that Leam contracted to provide Abraxas. Abraxas believes that the services were provided in a grossly negligent manner and that Leam committed fraud. Leam has asserted that Abraxas failed to pay approximately $639,000 for services rendered. The cases are pending in Bexar County and Ward County, Texas.

        Additionally, from time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At December 31, 2003, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on the Company.

11.   Earnings per Share

        Basic earnings (loss) per share excludes any dilutive effects of options, warrants and convertible securities and is computed by dividing income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings (loss) per share are computed similar to basic, however diluted earnings per share reflects the assumed conversion of all potentially dilutive securities.

F-28

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

			2001			2002			2003
Numerator:
	Net income (loss) before effect of accounting change		$	(19,718,000	)	$	(118,527,000	)	$	56,315,000
	Cumulative effect of accounting change			—			—			(395,000	)
			$	(19,718,000	)	$	(118,527,000	)		55,920,000
Denominator:
	Denominator for basic earnings per share—weighted-average shares			25,788,571			29,979,397			35,364,363
	Effect of dilutive securities:
		Stock options and warrants		—			—			711,928
	Dilutive potential common shares
		Denominator for diluted earnings per share—adjusted weighted-average shares and assumed conversions		25,788,571			29,979,397			36,076,291
Basic earnings (loss) per share:
	Net income (loss) before cumulative effect of accounting change		$	(0.76	)	$	(3.95	)	$	1.59
	Cumulative effect of accounting change			—			—			(0.01	)
Net income (loss) per common share			$	(0.76	)	$	(3.95	)	$	1.58
Diluted earnings (loss) per share:
	Net income (loss) before cumulative effect of accounting change		$	(0.76	)	$	(3.95	)	$	1.56
	Cumulative effect of accounting change			—			—			(0.01	)
		Net income (loss) per common share—diluted	$	(0.76	)	$	(3.95	)	$	1.55

        For the year ended December 31, 2001 and 2002, 4.3 million shares and 5.9 million shares respectively, were excluded from the calculation of diluted earnings per share since their inclusion would have been anti-dilutive.

12.   Quarterly Results of Operations (Unaudited)

        Selected results of operations for each of the fiscal quarters during the years ended December 31, 2002 and 2003 are as follows:

		1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
		(In thousands, except per share data)
Year Ended December 31, 2002
	Net revenue	$	11,807		$	14,235		$	11,061		$	17,217
	Operating income (loss)		(735	)		(115,879	)		490			5,221
	Net income (loss)		(8,699	)		(95,690	)		(8,438	)		(5,700	)
	Net income (loss) per common share—basic and diluted	$	(0.29	)	$	(3.19	)	$	(0.28	)		(0.19	)
Year Ended December 31, 2003
	Net revenue	$	13,111		$	8,430		$	8,430		$	9,048
	Operating income (loss)		5,646			1,927			2,694			1,275
	Net income (loss)		62,702			(2,346	)		(2,702	)		(1,734	)
	Net income (loss) per common share—basic	$	1.83		$	(0.07	)	$	(0.08	)	$	(0.05	)
	Net income (loss) per common share—diluted	$	1.82		$	(0.07	)	$	(0.08	)	$	(0.05	)

F-29

        During the second quarter of 2002, the Company incurred a ceiling limitation write-down of approximately $116.0 million.

13.   Benefit Plans

        The Company has a defined contribution plan (401(k)) covering all eligible employees of the Company. The Company did not contribute to the plan in 2002 or 2003. The employee contribution limitations are determined by formulas, which limit the upper one-third of the plan members from contributing amounts that would cause the plan to be top-heavy. The employee contribution is limited to the lesser of 20% of the employee's annual compensation or $11,000 in 2002 and $12,000 in 2003.

14.   Guarantor Condensed Consolidation Financial Statements

        The following table presents condensed consolidating balance sheets of Abraxas, as a parent company, and its significant subsidiaries, Canadian Abraxas and Old Grey Wolf, as of December 31, 2002 and 2003 and the related consolidating statements of operations and cash flows for the years ended December 31, 2001, 2002 and 2003. Canadian Abraxas was a guarantor of the First Lien Notes ($63.5 million) and jointly and severally liable with Abraxas for the Second Lien Notes ($190.2 million) and the Old Notes ($801,000). Old Grey Wolf was a non-guarantor with respect to the First Lien Notes and the Old Notes.

        The First Lien Notes and the Second Lien Notes were retired in connection with the financial restructuring transactions which occurred in January 2003. New Grey Wolf is a guarantor of the New Notes, there are no non-guarantor subsidiaries, accordingly, condensed consolidating balance sheets of Abraxas, as parent and its subsidiary New Grey Wolf are presented as of December 31, 2003 and the related consolidating statements of operations and cash flows for the year ended December 31, 2003.

F-30

Condensed Consolidating Parent Company and Subsidiaries Balance Sheet

December 31, 2003

(In thousands)

				Abraxas Petroleum Corporation Inc. Parent Company(1)			Subsidiary (New Grey Wolf)		Reclassifications and eliminations			Abraxas Petroleum Corporation and Subsidiaries
Assets:
	Cash			$	—		$	493	$	—		$	493
	Accounts receivable, less allowance for doubtful accounts				14,101			903		(6,681	)		8,323
	Equipment inventory				782			—		—			782
	Other current assets				418			154		—			572
			Total current assets		15,301			1,550		(6,681	)		10,170
Property and equipment—net					76,021			35,542		—			111,563
Deferred financing fees, net					4,410			—		—			4,410
Deferred income taxes and other assets					27,551			—		(27,257	)		294
	Total assets			$	123,283		$	37,092	$	(33,938	)	$	126,437
Liabilities and Stockholders' deficit:
Current liabilities:
	Accounts payable			$	7,075		$	8,652	$	(6,681	)	$	9,046
	Accrued interest				2,340			—		—			2,340
	Other accrued expenses				1,228			—		—			1,228
		Total current liabilities			10,643			8,652		(6,681	)		12,614
Long-term debt					184,649			—		—			184,649
Future site restoration					776			601		—			1,377
					196,068			9,253		(6,681	)		198,640
Stockholders' equity (deficit)					(72,785	)		27,839		(27,257	)		(72,203	)
Total liabilities and stockholders' equity (deficit)				$	123,283		$	37,092	$	(33,938	)	$	126,437

(1)

Includes amounts for insignificant U.S. subsidiaries, Sandia Oil and Gas, Sandia Operating, Western Energy Associates, East Side Coal and Wamsutter, which are guarantors of the New Notes.

F-31

Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet

December 31, 2002

(In thousands)

				Abraxas Petroleum Corporation Inc. Parent Company(2)			Restricted Subsidiary (Canadian Abraxas)			Non- Guarantor Subsidiary (Old Grey Wolf)		Reclassifications and eliminations			Abraxas Petroleum Corporation and Subsidiaries
Assets:
Current assets:
	Cash			$	557		$	2,188		$	2,137	$	—		$	4,882
	Accounts receivable, less allowance for doubtful accounts				4,482			4,782			11,938		(11,157	)		10,045
	Equipment inventory				860			142			12		—			1,014
	Other current assets				316			682			242		—			1,240
			Total current assets		6,215			7,794			14,329		(11,157	)		17,181
Property and equipment—net					74,435			38,858			37,101		—			150,394
Deferred financing fees, net					2,970			688			2,013		—			5,671
Deferred income taxes and other assets					108,558						7,820		(108,199	)		8,179
	Total assets			$	192,178		$	47,340		$	61,263	$	(119,356	)	$	181,425
Liabilities and Stockholders' deficit:
Current liabilities:
	Accounts payable			$	15,928		$	766		$	6,398	$	(10,973	)	$	12,119
	Accrued interest				5,000			1,009			—		—			6,009
	Other accrued expenses				1,162			—			—		—			1,162
	Current maturities of long-term debt				63,500			—			—		—			63,500
		Total current liabilities			85,590			1,775			6,398		(10,973	)		82,790
Long-term debt					138,350			52,629			45,964		—			236,943
Future site restoration					—			3,171			775		—			3,946
					223,940			57,575			53,137		(10,973	)		323,679
Stockholders' equity (deficit)					(31,762	)		(10,235	)		8,126		(108,383	)		(142,254	)
Total liabilities and stockholders' equity (deficit)				$	192,178		$	47,340		$	61,263	$	(119,356	)	$	181,425

(2)

Includes amounts for insignificant U.S. subsidiaries, Sandia Oil and Gas, Sandia Operating, Western Energy Associates, East Side Coal and Wamsutter, which are guarantors of the First and Second Lien Notes. Sandia is also a guarantor of the Old Notes. Additionally, these subsidiaries are designated as Restricted Subsidiaries along with Canadian Abraxas.

F-32

Condensed Consolidating Parent Company and Subsidiary Statement of Operations

For the year ended December 31, 2003

(In thousands)

		Abraxas Petroleum Corporation Inc. Parent Company(1)			Subsidiary (New Grey Wolf)		Reclassifications and eliminations		Abraxas Petroleum Corporation and Subsidiaries
Revenues:
	Oil and gas production revenues	$	29,710		$	8,395	$	—	$	38,105
	Gas processing revenues		—			133		—		133
	Rig revenues		663			—		—		663
	Other		7			111		—		118
			30,380			8,639		—		39,019
Operating costs and expenses:
	Lease operating and production taxes		8,342			1,257		—		9,599
	Depreciation, depletion, and amortization		7,608			3,195		—		10,803
	Rig operations		609			—		—		609
	General and administrative		3,995			1,365		—		5,360
	Stock-based compensation		1,106			—		—		1,106
			21,660			5,817		—		27,477
Operating income (loss)			8,720			2,822		—		11,542
Other (income) expense:
	Interest income		(30	)		—		—		(30	)
	Amortization of deferred financing fees		1,630			48		—		1,678
	Interest expense		16,323			632		—		16,955
	Financing costs		4,406			—		—		4,406
	Gain on sale of foreign subsidiaries		(68,933	)		—		—		(68,933	)
	Other		100			674		—		774
			(46,504	)		1,354		—		(45,150	)
Income (loss) before income tax and cumulative effect of accounting change			55,224			1,468		—		56,692
Income tax expense (benefit)			—			377		—		377
Cumulative effect of accounting change			395			—		—		395
Net income (loss)		$	54,829		$	1,091	$	—	$	55,920

F-33

Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations

For the year ended December 31, 2002

(In thousands)

		Abraxas Petroleum Corporation Inc. Parent Company(2)			Restricted Subsidiary (Canadian Abraxas)			Non- Guarantor Subsidiary (Old Grey Wolf)			Reclassifications and eliminations		Abraxas Petroleum Corporation and Subsidiaries
Revenues:
	Oil and gas production revenues	$	20,835		$	14,726		$	15,301		$	—	$	50,862
	Gas processing revenues		—			1,955			465					2,420
	Rig revenues		635			—			—			—		635
	Other		71			152			180			—		403
			21,541			16,833			15,946			—		54,320
Operating costs and expenses:
	Lease operating and production taxes		7,639			3,751			3,850			—		15,240
	Depreciation, depletion, and amortization		9,194			10,633			6,712			—		26,539
	Proved property impairment		28,178			60,501			27,314			—		115,993
	Rig operations		567			—			—			—		567
	General and administrative		4,045			1,312			1,527			—		6,884
			49,623			76,197			39,403			—		165,223
Operating income (loss)			(28,082	)		(59,364	)		(23,457	)		—		(110,903	)
Other (income) expense:
	Interest income		(92	)		—			—			—		(92	)
	Amortization of deferred financing fees		1,325			366			404			—		2,095
	Interest expense		24,689			6,665			2,796			—		34,150
	Other		1,168			—			—			—		1,168
			27,090			7,031			3,200			—		37,321
Income (loss) before income tax			(55,172	)		(66,395	)		(26,657	)		—		(148,224	)
Income tax expense (benefit)			—			(18,522	)		(11,175	)		—		(29,697	)
Net income (loss)		$	(55,172	)	$	(47,873	)	$	(15,482	)	$	—	$	(118,527	)

F-34

Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations

For the year ended December 31, 2001

(In thousands)

		Abraxas Petroleum Corporation Inc. Parent Company(2)			Restricted Subsidiary (Canadian Abraxas)			Non- Guarantor Subsidiary (Old Grey Wolf)		Reclassifications and eliminations			Abraxas Petroleum Corporation and Subsidiaries
Revenues:
	Oil and gas production revenues	$	34,934		$	24,308		$	13,959	$	—		$	73,201
	Gas processing revenues		—			2,008			430		—			2,438
	Rig revenues		756			—			—		—			756
	Other		85			471			292		—			848
			35,775			26,787			14,681		—			77,243
Operating costs and expenses:
	Lease operating and production taxes		9,302			6,836			2,478		—			18,616
	Depreciation, depletion, and amortization		12,336			14,707			5,441		—			32,484
	Proved property impairment		—			2,638			—		—			2,638
	Rig operations		702			—			—		—			702
	General and administrative		3,742			1,720			983		—			6,445
	General and administrative (Stock- based Compensation)		(2,767	)		—			—		—			(2,767	)
			23,315			25,901			8,902		—			58,118
Operating income (loss)			12,460			886			5,779		—			19,125
Other (income) expense:
	Interest income		(1,242	)		—			—		1,164			(78	)
	Amortization of deferred financing fees		1,907			361			—		—			2,268
	Interest expense		25,086			7,117			484		(1,164	)		31,523
	Other		1,052			—			—		—			1,052
			26,803			7,478			484		—			34,765
Income (loss) before income tax			(14,343	)		(6,592	)		5,295		—			(15,640	)
Income tax expense (benefit)			505			(80	)		1,977		—			2,402
Minority interest in income of consolidated foreign subsidiary			—			—			1,676		—			1,676
Net income (loss)		$	(14,848	)	$	(6,512	)	$	1,642	$	—		$	(19,718	)

F-35

Condensed Consolidating Parent and Subsidiary Statement of Cash Flow

For the year ended December 31, 2003

(In thousands)

			Abraxas Petroleum Corporation Inc.—Parent Company(1)			Subsidiary (New Grey Wolf)			Reclassifications and eliminations			Abraxas Petroleum Corporation and Subsidiaries
Operating Activities
Net income (loss)			$	54,829		$	1,091		$	—		$	55,920
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Gain on sale of foreign subsidiaries			(68,933	)		—			—			(68,933	)
	Depreciation, depletion, and amortization			7,608			3,195			—			10,803
	Non-cash interest and financing costs			16,422			—			—			16,422
	Deferred income tax (benefit) expense						377			—			377
	Amortization of deferred financing fees			1,630			48			—			1,678
	Stock-based compensation			1,106			—			—			1,106
	Changes in operating assets and liabilities:
		Accounts receivable		(7,850	)		394			6,010			(1,446	)
		Equipment inventory		78			—			—			78
		Other		295			—			—			295
		Accounts payables and accrued expenses		6,294			7,266			(6,010	)		7,550
Net cash provided by (used in) operations				11,479			12,371			—			23,850
Investing Activities
Capital expenditures, including purchases and development of properties				(9,194	)		(9,155	)		—			(18,349	)
Proceeds from sale of foreign subsidiaries				85,810			—			—			85,810
Net cash provided (used) by investing activities				76,616			(9,155	)		—			67,461
Financing Activities
Proceeds from issuance of common stock				177			—			—			177
Proceeds from long-term borrowings				43,051			291			—			43,342
Payments on long-term borrowings				(131,283	)		(7,261	)		—			(138,544	)
Deferred financing fees				(597	)		—			—			(597	)
Net cash provided (used) by financing activities				(88,652	)		(6,970	)		—			(95,622	)
Effect of exchange rate changes on cash				—			(78	)		—			(78	)
Increase (decrease) in cash				(557	)		(3,832	)		—			(4,389	)
Cash at beginning of year				557			4,325			—			4,882
Cash at end of year			$	—		$	493		$	—		$	493

F-36

Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow

For the year ended December 31, 2002

(In thousands)

			Abraxas Petroleum Corporation Inc.—Parent Company(2)			Restricted Subsidiary (Canadian Abraxas)			Non- Guarantor Subsidiary (Old Grey Wolf)			Reclassifications and Eliminations			Abraxas Petroleum Corporation and Subsidiaries
Operating Activities
Net income (loss)			$	(55,172	)	$	(47,873	)	$	(15,482	)	$	—		$	(118,527	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Depreciation, depletion, and amortization			9,194			10,633			6,712			—			26,539
	Proved property impairment			28,178			60,501			27,314			—			115,993
	Deferred income tax (benefit) expense			—			(18,522	)		(11,175	)		—			(29,697	)
	Amortization of deferred financing fees			1,325			366			404			—			2,095
	Changes in operating assets and liabilities:
		Accounts receivable		18,088			(3,187	)		1,114			(18,262	)		(2,247	)
		Equipment inventory		201			—			—			—			201
		Other		381			(177	)		(78	)		—			126
		Accounts payables and accrued expenses		(47	)		479			(3,251	)		—			(2,819	)
Net cash provided by (used in) operations				2,148			2,220			5,558			(18,262	)		(8,336	)
Investing Activities
Capital expenditures, including purchases and development of properties				(5,070	)		(4,926	)		(28,916	)		—			(38,912	)
Proceeds from sale of oil and gas properties				9,725			21,789			2,362			—			33,876
Net cash provided (used) by investing activities				4,655			16,863			(26,554	)		—			(5,036	)
Financing Activities
Proceeds from long-term borrowings				—			—			20,551			—			20,551
Payments on long-term borrowings				(8,176	)		(18,262	)		—			18,262			(8,176	)
Deferred financing fees				(1,663	)		146			(22	)		—			(1,539	)
Net cash provided (used) by financing activities				(9,839	)		(18,116	)		20,529			18,262			10,836
Effect of exchange rate changes on cash				—			(24	)		(163	)		—			(187	)
Increase (decrease) in cash				(3,036	)		943			(630	)		—			(2,723	)
Cash at beginning of year				3,593			1,245			2,767			—			7,605
Cash at end of year			$	557		$	2,188		$	2,137		$	—		$	4,882

F-37

Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow

For the year ended December 31, 2001

(In thousands)

			Abraxas Petroleum Corporation Inc.—Parent Company(2)			Restricted Subsidiary (Canadian Abraxas)			Non- Guarantor Subsidiary (Old Grey Wolf)			Reclassifications and Eliminations		Abraxas Petroleum Corporation and Subsidiaries
Operating Activities
Net income (loss)			$	(14,848	)	$	(6,512	)	$	1,642		$	—	$	(19,718	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Minority interest in income of foreign subsidiary			—			—			1,676			—		1,676
	Loss on sale of equity investment			845			—			—			—		845
	Depreciation, depletion, and amortization			12,336			14,707			5,441			—		32,484
	Proved property impairment			—			2,638			—					2,638
	Deferred income tax (benefit) expense			—			(80	)		1,977			—		1,897
	Amortization of deferred financing fees			1,907			361			—			—		2,268
	Stock-based compensation			(2,767	)		—			—			—		(2,767	)
	Changes in operating assets and liabilities:
		Accounts receivable		28,804			(9,721	)		(6,390	)		—		12,693
		Equipment inventory		(76	)		—			—			—		(76	)
		Other		(281	)		—			175			—		(106	)
		Accounts payables and accrued expenses		(12,915	)		(2,254	)		(402	)		—		(15,571	)
Net cash provided (used) by operating activities				13,005			(861	)		4,119			—		16,263
Investing Activities
Capital expenditures, including purchases and development of properties				(19,126	)		(15,313	)		(22,617	)		—		(57,056	)
Proceeds from sale of oil and gas properties				9,677			15,882			3,379			—		28,938
Acquisition of minority interest				(2,679	)		—			—			—		(2,679	)
Net cash provided (used) by investing activities				(12,128	)		569			(19,238	)		—		(30,797	)
Financing Activities
Proceeds form issuance of common stock				16			—			—			—		16
Proceeds from long-term borrowings				11,700			—			18,295			—		29,995
Payments on long-term borrowings				(9,326	)		—			—			—		(9,326	)
Net cash provided (used) by financing activities				2,390			—			18,295			—		20,685
				3,267			(292	)		3,176			—		6,151
Effect of exchange rate changes on cash				—			(141	)		(409	)		—		(550	)
Increase (decrease) in cash				3,267			(433	)		2,767			—		5,601
Cash at beginning of year				326			1,678			—			—		2,004
Cash at end of year			$	3,593		$	1,245		$	2,767		$	—	$	7,605

F-38

15.   Business Segments

        The Company conducts its operations through two geographic segments, the United States and Canada, and is engaged in the acquisition, development, and production of crude oil and natural gas in each country. The Company's significant operations are located in the Texas Gulf Coast, the Permian Basin of western Texas, and Canada. Identifiable assets are those assets used in the operations of the segment. Corporate assets consist primarily of deferred financing fees and other property and equipment. The Company's revenues are derived primarily from the sale of crude oil, condensate, natural gas liquids, and natural gas to marketers and refiners and from processing fees from the custom processing of natural gas. As a general policy, collateral is not required for receivables; however, the credit of the Company's customers is regularly assessed. The Company is not aware of any significant credit risk relating to its customers and has not experienced significant credit losses associated with such receivables.

        In 2003, three customers accounted for approximately 67% of consolidated oil and natural gas production revenue. Three customers accounted for approximately 80% of United States revenue and three customer accounted for approximately 91% of revenue in Canada. In 2002, four customers accounted for approximately 79% of consolidated oil and natural gas production revenue. Three customers accounted for approximately 77% of United States revenue and one customer accounted for approximately 80% of revenue in Canada. In 2001, three customers accounted for approximately 41% of oil and natural gas production revenues. Three customers accounted for approximately 76% of United States revenue and five customers accounted for approximately 76% of revenue in Canada.

        Business segment information about the Company's 2001 operations in different geographic areas is as follows:

		U.S.		Canada		Total
		(In thousands)
Revenues		$	35,775	$	41,468	$	77,243
Operating profit		$	13,795	$	6,665	$	20,460
General corporate							(1,335	)
Net interest expense and amortization of deferred financing fees							(33,713	)
Other expense							(1,052	)
Loss before income taxes						$	(15,640	)
Identifiable assets at December 31, 2001		$	124,993	$	174,063	$	299,056
Corporate assets							4,560
	Total assets					$	303,616

F-39

        Business segment information about the Company's 2002 operations in different geographic areas is as follows:

		U.S.			Canada			Total
		(In thousands)
Revenues		$	21,541		$	32,779		$	54,320
Operating loss		$	(23,677	)	$	(82,821	)	$	(106,498	)
General corporate									(4,405	)
Net interest expense and amortization of deferred financing fees									(36,153	)
Other expense									(1,168	)
Loss before income taxes								$	(148,224	)
Identifiable assets at December 31, 2002		$	81,025		$	94,059		$	175,084
Corporate assets									6,341
	Total assets							$	181,425

        Business segment information about the Company's 2003 operations in different geographic areas is as follows:

		U.S.		Canada		Total
		(In thousands)
Revenues		$	30,380	$	8,639	$	39,019
Operating income		$	14,001	$	2,822	$	16,823
General corporate							(5,281	)
Net interest expense, financing cost and amortization of deferred financing fees							(23,009	)
Gain on sale of foreign subsidiaries							68,933
Other income (expense)—net							(774	)
Cumulative effect of accounting change							(395	)
Income before income taxes						$	56,297
Identifiable assets at December 31, 2003		$	84,228	$	37,092	$	121,320
Corporate assets							5,117
	Total assets					$	126,437

16.   Hedging Program and Derivatives

        On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" SFAS 133 as amended by SFAS 137 "Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB 133" and SFAS 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities. Gains and losses on hedging instruments related to accumulated Other Comprehensive Income (Loss) and adjustments to carrying amounts on hedged production are included in natural gas or crude oil production revenue in the period that the related production is delivered. The Company has not elected hedge accounting for the floors that are in place as of December 31, 2003, accordingly, adjustments to the carrying value of the instruments are recognized in oil and gas income in the current period.

        Under the terms of the Company's senior credit agreement, the Company is required to maintain hedging agreements with respect to not less than 25% nor more than 75% of it crude oil and natural

F-40

gas production for a rolling six month period. The credit agreement was amended in February 2004, see Note 2, increasing the minimum hedged position to 40% of our estimated production. As of December 31, 2003 the Company's hedging positions were as follows:

Time Period	Notional Quantities	Price
March 1, 2003 - February 29, 2004	5,000 MMBtu of natural gas production per day	Floor of $4.50
March 1, 2004 - April 30, 2004	2,000 MMBtu of natural gas production per day	Floor of $4.00
March 1, 2004 - April 30, 2004	500 Bbl of crude oil production per day	Floor of $22.00
May 2004	2,000 MMbtu of natural gas production per day	Floor of $4.00
May 2004	500 Bbls of crude oil production per day	Floor of $22.00
June 2004	800 Bbls of crude oil production per day	Floor of $22.00
July 2004	2,000 MMbtu of natural gas production per day	Floor of $4.00
July 2004	500 Bbl of crude oil production per day	Floor of $22.00

        All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are effective in offsetting changes in cash flows of hedged items.

        The fair value of the hedging instrument was determined based on the base price of the hedged item and NYMEX forward price quotes. As of December 31, 2003, a commodity price increase of 10% would have resulted in an unfavorable change in the fair market value of approximately $2,000 and a commodity price decrease of 10% would have resulted in a favorable change in fair market value of approximately $2,000.

17.   Proved Property Impairment

        In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the end of the year, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the Company's financial statements. As of December 31, 2001, the Company's net capitalized costs of oil and gas properties exceeded the present value of its estimated proved reserves by $71.3 million ($38.9 million on the U.S. properties and $32.4 million on the Canadian properties). These amounts were calculated considering 2001 year-end prices of $19.84 per barrel for oil and $2.57 per Mcf for gas as adjusted to reflect the expected realized prices for each of the full cost pools. The Company did not adjust its capitalized costs for its U.S. properties because subsequent to December 31, 2001, oil and gas prices increased such that capitalized costs for its U.S. properties did not exceed the present value of the estimated proved oil and gas reserves for its U.S. properties as determined using increased realized prices on March 22, 2002 of $24.16 per Bbl for oil and $2.89 per Mcf for gas. During the second quarter of 2002, the Company had a ceiling limitation write-down of approximately $116.0 million. At December 31, 2003, the net capitalized cost of crude oil and natural gas properties did not exceed the present value of our estimated reserves, as such, no write-down was recorded.

F-41

18.   Supplemental Oil and Gas Disclosures (Unaudited)

        The accompanying table presents information concerning the Company's crude oil and natural gas producing activities as required by Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities." Capitalized costs relating to oil and gas producing activities are as follows:

			Years Ended December 31
			2002									2003
			Total			U.S.			Canada			Total			U.S.			Canada
			(In thousands)
Proved crude oil and natural gas properties			$	521,995		$	279,401		$	242,594		$	325,222		$	288,559		$	36,663
Unproved properties				7,052			—			7,052			4,304			—			4,304
	Total			529,047			279,401			249,646			329,526			288,559			40,967
Accumulated depreciation, depletion, and amortization, and impairment				(420,344	)		(205,181	)		(215,163	)		(219,404	)		(212,609	)		(6,795	)
		Net capitalized costs	$	108,703		$	74,220		$	34,483		$	110,122		$	75,950		$	34,172

        Cost incurred in oil and gas property acquisitions, exploration and development activities are as follows:

		Years Ended December 31
		2001						2002						2003
		Total		U.S.		Canada		Total		U.S.		Canada(1)		Total		U.S.		Canada
		(In thousands)
Property acquisition costs:
	Proved	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
	Unproved		—		—		—		—		—		—		—		—		—
		$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Property development and exploration costs		$	56,694	$	18,867	$	37,827	$	38,560	$	4,944	$	33,616	$	18,313	$	9,158	$	9,155

(1)

Canadian costs in 2002 were primarily for exploratory purposes.

        The results of operations for oil and gas producing activities for the three years ending December 31, 2001, 2002 and 2003, respectively are as follows:

	Years Ended December 31
	2001									2002									2003
	Total			U.S.			Canada			Total			U.S.			Canada			Total			U.S.			Canada
	(In thousands)
Revenues	$	73,201		$	34,934		$	38,267		$	50,862		$	20,835		$	30,027		$	38,105		$	29,710		$	8,395
Production costs		(18,616	)		(9,302	)		(9,314	)		(15,240	)		(7,639	)		(7,601	)		(9,599	)		(8,342	)		(1,257	)
Depreciation, depletion, and amortization		(32,124	)		(11,976	)		(20,148	)		(26,224	)		(8,879	)		(17,345	)		(9,410	)		(7,428	)		(1,982	)
Proved property impairment		(2,638	)		—			(2,638	)		(115,993	)		(28,178	)		(87,815	)		—			—			—
General and administrative		(1,565	)		(1,073	)		(492	)		(1,836	)		(1,011	)		(825	)		(1,339	)		(998	)		(341	)
Income taxes (expense) benefit		(2,419	)		—			(2,419	)		—			—			—			(377	)		—			(377	)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	15,839		$	12,583		$	3,256		$	(108,431	)	$	(24,872	)	$	(83,559	)	$	17,380		$	12,942		$	4,438
Depletion rate per barrel of oil equivalent, before impact of impairment	$	8.81		$	6.96		$	10.45		$	8.52		$	7.55		$	8.94		$	7.13		$	7.24		$	6.74

F-42

Estimated Quantities of Proved Oil and Gas Reserves

        The following table presents the Company's estimate of its net proved crude oil and natural gas reserves as of December 31, 2001, 2002, and 2003. The Company's management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared by independent petroleum reserve engineers.

			Total				United States				Canada
			Liquid Hydrocarbons		Natural Gas		Liquid Hydrocarbons		Natural Gas		Liquid Hydrocarbons		Natural Gas
			(Barrels)		(Mcf)		(Barrels)		(Mcf)		(Barrels)		(Mcf)
			(In Thousands)
Proved developed and undeveloped reserves:
	Balance at January 1, 2001		8,844		191,327		6,081		114,908		2,763		76,419
		Revisions of previous estimates	(628	)	2,944		(688	)	3,318		60		(374	)
		Extensions and discoveries	1,064		26,329		354		4,886		710		21,443
		Production	(732	)	(17,495	)	(416	)	(7,823	)	(316	)	(9,672	)
		Sale of minerals in place	(1,746	)	(14,348	)	(924	)	(6,821	)	(822	)	(7,527	)
	Balance at December 31, 2001		6,802		188,757		4,407		108,468		2,395		80,289
		Revisions of previous estimates	(798	)	(29,701	)	(63	)	(15,248	)	(735	)	(14,453	)
		Extensions and discoveries	522		19,166		—		—		522		19,166
		Production	(534	)	(15,453	)	(264	)	(5,472	)	(270	)	(9,981	)
		Sale of minerals in place	(1,387	)	(23,937	)	(843	)	(9,553	)	(544	)	(14,384	)
	Balance at December 31, 2002		4,605		138,832		3,237		78,195		1,368		60,637
		Revisions of previous estimates	310		5,564		268		6,760		42		(1,196	)
		Extensions and discoveries	654		4,474		44		28		610		4,446
		Production	(288	)	(6,190	)	(229	)	(4,781	)	(59	)	(1,409	)
		Sale of minerals in place	(1,146	)	(46,396	)	—		—		(1,146	)	(46,396	)
	Balance at December 31, 2003		4,135		96,284		3,320		80,202		815		16,082
Proved developed reserves:
	December 31, 2001		5,047		111,243		2,892		40,514		2,155		70,729
	December 31, 2002		3,004		90,374		1,754		34,776		1,250		55,598
	December 31, 2003		2,314		52,398		1,887		39,371		427		13,027

F-43

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

        The following disclosures concerning the standardized measure of future cash flows from proved crude oil and natural gas are presented in accordance with SFAS No. 69. The standardized measure does not purport to represent the fair market value of the Company's proved crude oil and natural gas reserves. An estimate of fair market value would also take into account, among other factors, the recovery of reserves not classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

        Under the standardized measure, future cash inflows were estimated by applying period-end prices at December 31, 2003 adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis of the properties. Operating loss carryforwards, tax credits, and permanent differences to the extent estimated to be available in the future were also considered in the future income tax calculations, thereby reducing the expected tax expense.

        Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.

        Set forth below is the Standardized Measure relating to proved oil and gas reserves for the three years ending December 31, 2001, 2002 and 2003

	Years Ended December 31
	2001									2002									2003
	Total			U.S.			Canada			Total			U.S.			Canada			Total			U.S.			Canada
	(In thousands)
Future cash inflows	$	607,375		$	313,640		$	293,735		$	686,055		$	389,061		$	296,994		$	621,290		$	512,797		$	108,493
Future production and development costs		(220,613	)		(138,296	)		(82,317	)		(225,068	)		(158,507	)		(66,561	)		(204,537	)		(179,036	)		(25,498	)
Future income tax expense		—			—			—			—			—			—			—			—			—
Future net cash flows		386,762			175,344			211,418			460,987			230,554			230,433			416,756			333,761			82,995
Discount		(177,096	)		(98,157	)		(78,939	)		(206,134	)		(120,238	)		(85,896	)		(199,933	)		(172,177	)		(27,756	)
Standardized Measure of discounted future net cash relating to proved reserves	$	209,666		$	77,187		$	132,479		$	254,853		$	110,316		$	144,537		$	216,823		$	161,584		$	55,239

F-44

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

        The following is an analysis of the changes in the Standardized Measure:

		Year Ended December 31
		2001			2002			2003
		(In thousands)
Standardized Measure, beginning of year		$	775,534		$	209,666		$	254,853
Sales and transfers of oil and gas produced, net of production costs			(54,585	)		(35,622	)		(28,506	)
Net changes in prices and development and production costs from prior year			(613,325	)		111,087			62,074
Extensions, discoveries, and improved recovery, less related costs			39,982			46,803			21,819
Sales of minerals in place			(96,096	)		(33,808	)		(120,150	)
Revision of previous quantity estimates			(2,474	)		(36,007	)		9,061
Change in future income tax expense			230,987			—			—
Other			(147,910	)		(28,232	)		(7,813	)
Accretion of discount			77,553			20,966			25,485
	Standardized Measure, end of year	$	209,666		$	254,853		$	216,823

19.   Restatement

        In January 2003, the Company sold its wholly owned Canadian subsidiaries, Old Grey Wolf and Canadian Abraxas as part of a series of transactions related to a financial restructuring—see Note 2 for additional information regarding an exchange offer, redemption of certain notes and a new credit agreement. Subsequent to the issuance of its consolidated financial statements for the year ended December 31, 2002, the Company's management determined that the wholly owned Canadian subsidiaries should not have been presented as discontinued operations. As a result, the accompanying consolidated balance sheets as of December 31, 2002, and the related consolidated statements of operations, and cash flows for each of the two years in the period ended December 31, 2002 have been restated to present the assets and liabilities, results of operations, and cash flows as components of continuing operations.

F-45

        A summary of the significant effects of the restatement is as follows (In thousands):

			For the years ended December 31,
			2001						2002
			As Previously Reported			As Restated			As Previously Reported			As Restated
Revenues:
	Oil and gas production revenue		$	34,934		$	73,201		$	21,601		$	50,862
		Gas processing revenue		—			2,438			—			2,420
		Rig revenue		756			756			635			635
		Other		85			848			71			403
				35,775			77,243			22,307			54,320
Operating costs and expenses:
		Lease operating and production taxes		9,302			18,616			7,910			15,240
		Depreciation, depletion and amortization		12,336			32,484			9,654			26,539
		Proved property impairment		—			2,638			32,850			115,993
		Rig operations		702			702			567			567
		General and administrative		4,937			6,445			5,082			6,884
		General and administrative (Stock-based compensation)		(2,767	)		(2,767	)		—			—
				24,510			58,118			56,063			165,223
Operating income (loss)				11,265			19,125			(33,756	)		(110,903	)
Other (income) expense:
		Interest income		(78	)		(78	)		(92	)		(92	)
		Amortization of deferred financing fees		1,907			2,268			1,325			2,095
		Interest expense		23,922			31,523			24,689			34,150
		Financing costs		—			—			967			967
		(Gain) loss on sale of equity investment		845			845			—			—
		Gain on debt extinguishment(1)		—			—			—			—
		Other		207			207			201			201
				26,803			34,765			27,090			37,321
Income (loss) before income tax				(15,538	)		(15,640	)		(60,846	)		(148,224	)
Income tax expense (benefit):
		Current		505			505			—			—
		Deferred		—			1,897			—			(29,697	)
Minority interest in income of consolidated foreign subsidiary				—			1,676			—			—
Loss from discontinued operations				(3,675	)		—			(57,681	)		—
Extraordinary item: gain on debt extinguishment(1)
Net income (loss)			$	(19,718	)	$	(19,718	)	$	(118,527	)	$	(118,527	)

F-46

				December 31, 2002
				As Previously Reported			As Restated
Current Assets:
Cash				$	557		$	4,882
Accounts receivable:
	Joint owners				516			2,215
	Oil and gas production sales				5,292			7,466
	Other				221			364
					6,029			10,045
Equipment inventory					1,021			1,014
Other current assets					316			1,240
					7,923			17,181
Assets held for sale					74,247			—
	Total current assets				82,170			17,181
Property and equipment:
		Oil and gas properties:
		Proved			298,972			521,995
			Unproved		7,052			7,052
		Other property and equipment			2,713			44,189
			Total		308,737			573,236
		Less accumulated depreciation, depletion and amortization			212,811			422,842
			Total property and equipment—net		95,926			150,394
Deferred financing fees					2,970			5,671
Deferred income taxes					—			7,820
Other					359			359
		Total assets		$	181,425		$	181,425
Current Liabilities:
Accounts payable				$	4,171		$	9,687
Joint interest oil and gas production payable					1,637			2,432
Accrued interest					5,000			6,009
Other accrued expenses					1,162			1,162
Hedge liability					—			—
Current maturities of long-term debt					63,500			63,500
					75,470			82,790
Liabilities related to assets held for sale					56,697			—
		Total current liabilities			132,167			82,790
Long-term debt					190,979			236,943
Deferred income taxes					—			—
Future site restoration					533			3,946
Stockholders' equity (deficit)					(142,254	)		(142,254	)
		Total liabilities and stockholders' deficit		$	181,425		$	181,425

F-47

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets

(in thousands)

				March 31, 2004			December 31, 2003
				(Unaudited)
Assets:
Current assets:
	Cash			$	1,393		$	493
	Accounts receivable, net:
			Joint owners		548			1,360
			Oil and gas production		4,309			5,873
			Other		318			1,090
					5,175			8,323
	Equipment inventory				790			782
	Other current assets				544			572
		Total current assets			7,902			10,170
Property and equipment:
	Oil and gas properties, full cost method of accounting:
		Proved			330,292			325,222
		Unproved, not subject to amortization			2,247			4,304
	Other property and equipment				5,202			4,540
			Total		337,741			334,066
		Less accumulated depreciation, depletion, and amortization			225,432			222,503
		Total property and equipment—net			112,309			111,563
Deferred financing fees, net					5,536			4,410
Other assets					294			294
	Total assets			$	126,041		$	126,437
Liabilities and Stockholders' Deficit
Current liabilities:
	Accounts payable			$	4,129			6,756
	Oil and gas production payable				2,449			2,290
	Accrued interest				5,288			2,340
	Other accrued expenses				1,414			1,228
			Total current liabilities		13,280			12,614
Long-term debt					186,971			184,649
Future site restoration					1,618			1,377
			Total liabilities		201,869			198,640
Stockholders'deficit:
	Common Stock, par value $.01 per share—authorized 200,000,000 shares; issued, 36,291,602 and, 36,024,308 at March 31, 2004 and December 31, 2003 respectively				363			360
	Additional paid-in capital				143,817			141,835
	Receivable from stock sale				(97	)		(97	)
	Accumulated deficit				(219,259	)		(213,701	)
	Treasury stock, at cost, 101,989 shares				(525	)		(964	)
	Accumulated other comprehensive (loss) income				(127	)		364
			Total stockholders' deficit		(75,828	)		(72,203	)
Total liabilities and stockholders' deficit				$	126,041			126,437

See accompanying notes to condensed consolidated financial statements

F-48

Abraxas Petroleum Corporation

Condensed Consolidated Statements of Operations

(Unaudited)

(in thousands except per share data)

		Three Months Ended March 31,
		2004			2003
Revenue:
	Oil and gas production revenues	$	10,732		$	12,772
	Gas processing revenue		—			132
	Rig revenues		175			181
	Other		28			26
			10,935			13,111
Operating costs and expenses:
	Lease operating and production taxes		3,367			2,726
	Depreciation, depletion and amortization		3,035			3,142
	Rig operations		145			166
	General and administrative		1,342			1,395
	Stock-based compensation		2,063			36
			9,952			7,465
Operating income			983			5,646
Other (income) expense
	Interest income		(6	)		(10	)
	Interest expense		5,119			5,164
	Amortization of deferred financing fees		445			377
	Financing cost		971			3,601
	Gain on sale of foreign subsidiaries		—			(66,960	)
	Other		11			—
			6,540			(57,828	)
Earnings (loss) before cumulative effect of accounting change and taxes			(5,557	)		63,474
Cumulative effect of accounting change			—			(395	)
Earnings (loss) before taxes			(5,557	)		63,079
Income tax expense			—			377
Net earnings (loss)		$	(5,557	)	$	62,702
Basic earnings (loss) per common share:
	Net earnings (loss)	$	(0.15	)	$	1.84
	Cumulative effect of accounting change		—			(0.01	)
Net earnings (loss) per common—basic		$	(0.15	)	$	1.83
Diluted earnings (loss) per common share:
	Net earnings (loss)	$	(0.15	)	$	1.83
	Cumulative effect of accounting change		—			(0.01	)
Net earnings (loss) per common share—diluted		$	(0.15	)	$	1.82

See accompanying notes to condensed consolidated financial statements

F-49

Abraxas Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

		Three Months Ended March 31,
		2004			2003
Cash flows from Operating Activities
Net income (loss)		$	(5,557	)	$	62,702
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization			3,035			3,142
Deferred income tax expense (benefit)			—			377
Amortization of deferred financing fees			445			377
Non-cash interest and financing cost			3,010			2,159
Accretion of future site restoration			256			414
Stock-based compensation			2,063			36
Gain on sale of foreign subsidiaries			—			(66,960	)
Changes in operating assets and liabilities:
	Accounts receivable		3,252			(1,160	)
	Equipment inventory		(8	)		162
	Other		(21	)		1,650
	Accounts payable and accrued expenses		563			(154	)
Net cash provided by operations			7,038			2,745
Cash flows from Investing Activities
Capital expenditures, including purchases and development of properties			(4,230	)		(4,589	)
Proceeds from sale of foreign subsidiaries			—			85,824
Net cash provided by (used) in investing activities		$	(4,230	)	$	81,235
Cash flows from Financing Activities
Proceeds from long-term borrowings			1,312			43,189
Payments on long-term borrowings			(2,000	)		(130,903	)
Issuance of common stock in connection with exchange			—			3,651
Issuance of common stock for compensation			170			—
Exercise of stock options			190			5
Deferred financing fees			(1,571	)		(2,529	)
Net cash (used) in provided by financing activities			(1,899	)		(86,587	)
Effect of exchange rate changes on cash			(9	)		235
Increase (decrease) in cash			900			(2,372	)
Cash, at beginning of period			439			4,882
Cash, at end of period		$	1,393		$	2,510
Supplemental disclosures of cash flow information:
Interest paid		$	1,098		$	3,029
Non-cash items:
Future site restoration		$	43		$	(3,116	)

See accompanying notes to condensed consolidated financial statements

F-50

Abraxas Petroleum Corporation

Notes to CondensedConsolidated Financial Statements

(Unaudited)

(tabular amounts in thousands except per share data)

Note 1. Basis of Presentation

        The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the "Company" or "Abraxas") are set forth in the notes to the Company's audited financial statements in the Annual Report on Form 10-K filed for the year ended December 31, 2003. Such policies have been continued without change. Also, refer to the notes to those financial statements for additional details of the Company's financial condition, results of operations, and cash flows. All the material items included in those notes have not changed except as a result of normal transactions in the interim, or as disclosed within this report. The accompanying interim consolidated financial statements have not been audited by independent accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. The results of operations for the three months ended March 31, 2004 are not necessarily indicative of results to be expected for the full year.

        The consolidated financial statements include the accounts of the Company and its wholly-owned foreign subsidiary, Grey Wolf Exploration Inc. ("New Grey Wolf"). In January 2003, the Company sold all of the common stock of its wholly-owned foreign subsidiaries, Canadian Abraxas Petroleum Limited ("Canadian Abraxas") and Grey Wolf Exploration Inc. ("Old Grey Wolf"). Certain oil and gas properties were retained and transferred into New Grey Wolf which was incorporated in January 2003. The operations of Canadian Abraxas and Grey Wolf are included in the consolidated financial statements through January 23, 2003.

        New Grey Wolf's assets and liabilities are translated to U.S. dollars at period-end exchange rates. Income and expense items are translated at average rates of exchange prevailing during the period. Translation adjustments are accumulated as a separate component of shareholders' equity.

        Certain prior year balances have been reclassified for comparative purposes.

Note 2. Income Taxes

        The Company records income taxes using the liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.

        For the period ended March 31, 2004, no current taxes have been provided due to operating losses for tax purposes. Deferred tax expense of $377,000 related to Canadian operations for the period ended March 31, 2003 has been provided for.

Note 3. Recent Events

        On February 23, 2004, the Company entered into an amendment to our existing senior credit agreement providing for two revolving credit facilities and a new non-revolving credit facility as described below. Subject to earlier termination on the occurrence of events of default or other events, the stated maturity date for these credit facilities is February 1, 2007. In the event of an early termination, we will be required to pay a prepayment premium, except in the limited circumstances described in the amended senior credit agreement.

F-51

        First Revolving Credit Facility.    Lenders under the amended senior credit agreement have provided Abraxas a revolving credit facility with a maximum borrowing base of up to $20 million. The Company's current borrowing base under this revolving credit facility is the full $20.0 million, subject to adjustments based on periodic calculations and mandatory prepayments under the senior credit agreement. The Company has borrowed $6.6 million under this revolving credit facility, which was used to refinance principal and interest on advances under it's preexisting revolving credit facility under the senior credit agreement, and to pay certain fees and expenses relating to the transaction. Outstanding amounts under this revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 1.125%.

        Second Revolving Credit Facility.    Lenders under the amended senior credit agreement have provided a second revolving credit facility, with a maximum borrowing of up to $30.0 million. This revolving credit facility is not subject to a borrowing base. The Company has borrowed $30.0 million under this revolving credit facility, which was used to refinance principal and interest on advances under our preexisting revolving credit facility, and to pay certain transaction fees and expenses. Outstanding amounts under this revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 3.00%.

        Non-Revolving Credit Facility.    The Company has borrowed $15.0 million pursuant to a non-revolving credit facility, which was used to repay the preexisting term loan under its senior credit agreement, to refinance principal and interest on advances under the preexisting revolving credit facility, and to pay certain transaction fees and expenses. This non-revolving credit facility is not subject to a borrowing base. Outstanding amounts under this credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 8.00%.

        Covenants.    Under the amended senior credit agreement, we are subject to customary covenants and reporting requirements. Certain financial covenants require us to maintain minimum ratios of consolidated EBITDA (as defined in the amended senior credit agreement) to adjusted fixed charges (which includes certain capital expenditures), minimum ratios of consolidated EBITDA to cash interest expense, a minimum level of unrestricted cash and revolving credit availability, minimum hydrocarbon production volumes and minimum proved developed hydrocarbon reserves. In addition, if on the day before the end of each fiscal quarter the aggregate amount of our cash and cash equivalents exceeds $2.0 million, we are required to repay the loans under the amended senior credit agreement in an amount equal to such excess. The amended senior credit agreement also requires us to enter into hedging agreements on not less than 40% or more than 75% of our projected oil and gas production. We are also required to establish deposit accounts at financial institutions acceptable to the lenders and we are required to direct our customers to make all payments into these accounts. The amounts in these accounts will be transferred to the lenders upon the occurrence and during the continuance of an event of default under the amended senior credit agreement.

        In addition to the foregoing and other customary covenants, the amended senior credit agreement contains a number of covenants that, among other things, restrict our ability to:

•

incur additional indebtedness;



•

create or permit to be created liens on any of our properties;



•

enter into change of control transactions;

F-52

•

dispose of our assets;



•

change our name or the nature of our business;



•

make guarantees with respect to the obligations of third parties;



•

enter into forward sales contracts;



•

make payments in connection with distributions, dividends or redemptions relating to our outstanding securities, or



•

make investments or incur liabilities.

        Security.    The obligations of Abraxas under the amended senior credit agreement continue to be secured by a first lien security interest in substantially all of Abraxas' assets, including all crude oil and natural gas properties.

        Guarantees.    The obligations of Abraxas under the amended senior credit agreement continue to be guaranteed by Abraxas' subsidiaries, Sandia Oil & Gas Corporation, Sandia Operating Corp. (a wholly-owned subsidiary of Sandia Oil & Gas), Wamsutter Holdings, Inc., New Grey Wolf, Western Associated Energy Corporation and Eastside Coal Company, Inc. The guarantees under the amended senior credit agreement continue to be secured by a first lien security interest in substantially all of the guarantors' assets, including all crude oil and natural gas properties.

        Events of Default.    The amended senior credit agreement contains customary events of default, including nonpayment of principal or interest, violations of covenants, inaccuracy of representations or warranties in any material respect, cross default and cross acceleration to certain other indebtedness, bankruptcy, material judgments and liabilities, change of control and any material adverse change in our financial condition.

Note 4. Long-Term Debt

        Long-term debt consisted of the following:

	March 31 2004		December 31 2003
	(In thousands)
11.5% Secured Notes due 2007 ("new notes")	$	137,258		137,258
Senior Secured Credit Agreement		49,713		47,391
		186,971		184,649
Less current maturities		—		—
	$	186,971	$	184,649

        New Notes.    In connection with the financial restructuring completed in January 2003, Abraxas issued $109.7 million in principal amount of it's 11¹/2% Secured Notes due 2007, Series A, or new notes, in exchange for our 11¹/2% Senior Notes due 2004 tendered in the exchange offer. The new notes were issued under an indenture with U.S. Bank, N. A. In accordance with SFAS 15, the basis of the new notes exceeds the face amount of the new notes by approximately $19.0 million. Such amount will be amortized over the term of the new notes as an adjustment to the yield of the new notes.

F-53

        The new notes accrue interest from the date of issuance, at a fixed annual rate of 11¹/2%, payable in cash semi-annually on each May 1 and November 1, commencing May 1, 2003, provided that, if we fail, or are not permitted pursuant to our senior credit agreement or the intercreditor agreement between the trustee under the indenture for the new notes and the lenders under the senior credit agreement, to make such cash interest payments in full, we will pay such unpaid interest in kind by the issuance of additional new notes with a principal amount equal to the amount of accrued and unpaid cash interest on the new notes plus an additional 1% accrued interest for the applicable period. Upon an event of default, the new notes accrue interest at an annual rate of 16.5%.

        The new notes are secured by a second lien or charge on all of our current and future assets, including, but not limited to, all of our crude oil and natural gas properties. All of Abraxas' current subsidiaries, Sandia Oil & Gas, Sandia Operating, Wamsutter, New Grey Wolf, Western Associated Energy and Eastside Coal Company are guarantors of the new notes, and all of Abraxas' future subsidiaries will guarantee the new notes. If Abraxas cannot make payments on the new notes when they are due, the guarantors must make them instead.

        The new notes and related guarantees

•

are subordinated to the indebtedness under the senior credit agreement;



•

rank equally with all of Abraxas' current and future senior indebtedness; and



•

rank senior to all of Abraxas' current and future subordinated indebtedness, in each case, if any.

        The new notes are subordinated to amounts outstanding under the senior credit agreement both in right of payment and with respect to lien priority and are subject to an intercreditor agreement.

        Abraxas may redeem the new notes, at its option, in whole at any time or in part from time to time, at redemption prices expressed as percentages of the principal amount set forth below. If Abraxas redeems all or any new notes, it must also pay all interest accrued and unpaid to the applicable redemption date. The redemption prices for the new notes during the indicated time periods are as follows:

Period	Percentage
From January 24, 2004 to June 23, 2004	97.1674	%
From June 24, 2004 to January 23, 2005	98.5837	%
Thereafter	100.0000	%

        Under the indenture, the Company is subject to customary covenants which, among other things, restricts our ability to:

•

borrow money or issue preferred stock;



•

pay dividends on stock or purchase stock;



•

make other asset transfers;



•

transact business with affiliates;



•

sell stock of subsidiaries;



•

engage in any new line of business;

F-54

•

impair the security interest in any collateral for the notes;



•

use assets as security in other transactions; and



•

sell certain assets or merge with or into other companies.

        In addition, we are subject to certain financial covenants including covenants limiting our selling, general and administrative expenses and capital expenditures, a covenant requiring Abraxas to maintain a specified ratio of consolidated EBITDA, as defined in the indenture, to cash interest and a covenant requiring Abraxas to permanently, to the extent permitted, pay down debt under the senior credit agreement and, to the extent permitted by the senior credit agreement, the new notes or, if not permitted, paying indebtedness under the senior credit agreement.

        The indenture contains customary events of default, including nonpayment of principal or interest, violations of covenants, inaccuracy of representations or warranties in any material respect, cross default and cross acceleration to certain other indebtedness, bankruptcy, material judgments and liabilities, change of control and any material adverse change in our financial condition.

        Senior Credit Agreement.    In connection with the financial restructuring, Abraxas entered into a new senior credit agreement providing a term loan facility and a revolving credit facility which was amended in February 2004. A summary description of the senior credit agreement, as amended, is set forth in Note 3.

Note 5. Stock-based Compensation

        The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount an employee must pay to acquire the stock.

        Effective July 1, 2000, the Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions Involving Stock Compensation", an interpretation of APB No. 25. Under the interpretation, certain modifications to fixed stock option awards which were made subsequent to December 15, 1998, and were not exercised prior to July 1, 2000, require that the awards be accounted for as variable until they are exercised, forfeited, or expired. In January 2003, the Company amended the exercise price to $0.66 on certain options with an existing exercise price greater than $0.66. The Company recognized approximately $36,000 and $2.1 million in expense during the quarters ended March 31, 2003 and 2004, respectively, as Stock-based compensation expense in the accompanying consolidated financial statements.

        Pro forma information regarding net income (loss) and earnings (loss) per share is required by SFAS 123, "Accounting for Stock-Based Compensation" (SFAS 123), which also requires that the information be determined as if the Company has accounted for its employee stock options granted subsequent to December 31, 1995 under the fair value method prescribed by SFAS 123. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the quarters ended March 31, 2004 and 2003, risk-free interest rates of 1.5%; dividend yields of -0-%; volatility factor of the expected market price of the Company's common stock of .35; and a weighted-average expected life of the option of ten years.

F-55

        The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options.

        In October 2002, the FASB issued Statement No. 148 "Accounting for Stock-Based Compensation-Transition and Disclosure", (SFAS No. 148), providing alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. SFAS No. 148 also amends the disclosure requirement of SFAS No. 123, "Accounting for Stock-Based Compensation" to include prominent disclosures in annual and interim financial statements about the method of accounting for stock-based compensation and the effect of the method used on reported results. The Company adopted the disclosure provisions of SFAS No. 148 on December 31, 2002.

        Had the Company determined stock-based compensation costs based on the estimated fair value at the grant date for its stock options, the Company's net income (loss) per share for the three months ended March 31, 2004 and March 31, 2003 would have been:

		Three Months Ended March 31,
		2004			2003
Net income (loss) as reported		$	(5,557	)	$	62,702
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects			2,063			36
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(37	)		(67	)
Pro forma net income (loss)		$	(3,531	)	$	62,671
Earnings (loss) per share:
	Basic—as reported	$	(0.15	)	$	1.84
	Basic—pro forma	$	(0.10	)	$	1.84
	Diluted—as reported	$	(0.15	)	$	1.83
	Diluted—pro forma	$	(0.10	)	$	1.82

F-56

Note 6. Earnings (Loss) Per Share

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

		Three Months Ended March 31,
		2004			2003
Numerator:
Numerator for basic and diluted earnings per share Net earnings (loss) before cumulative effect of accounting change (in thousands)		$	(5,557	)	$	63,097
Cumulative effect of accounting change			—			(395	)
Numerator for basic and diluted earnings per share Net earnings (loss) available to common stockholders (in thousands)		$	(5,557	)	$	62,702
Denominator:
Denominator for basic earnings per share—weighted-average shares			36,011,657			34,181,118
Effect of dilutive securities:
	Stock options and Warrants		—			319,472
Denominator for diluted earnings per share—adjusted weighted-average shares and assumed Conversions			36,011,657			34,500,590
Basic earnings (loss) per share:
	Net earnings (loss) before cumulative effect of accounting change	$	(0.15	)	$	1.84
	Cumulative effect of accounting change		—			(0.01	)
Net earnings (loss) per common share—basic		$	(0.15	)	$	1.83
Diluted earnings (loss) per share:
	Net earnings (loss) before cumulative effect of accounting change	$	(0.15	)	$	1.83
	Cumulative effect of accounting change		—			(0.01	)
Net earnings (loss) per common share—diluted		$	(0.15	)	$	1.82

        For the three months ended March 31, 2004, none of the shares issuable in connection with stock options or warrants are included in diluted shares. Inclusion of these shares would be antidilutive due to losses incurred in the period. Had there not been losses in this period, dilutive shares would have been 1,952,370 shares for the three months ended March 31, 2004.

Note 7. Hedging Program and Derivatives

        On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" SFAS 133 as amended by SFAS 137 "Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB 133" and SFAS 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities". Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. As of March 31, 2004, the derivatives that the Company had in

F-57

place were not designated as hedges, accordingly, changes in the fair value of the derivatives are recorded in current period oil and gas revenue.

        Under the terms of our amended senior credit agreement, we are required to maintain hedging positions with respect to not less than 40% nor more than 75% of our crude oil and natural gas production for a rolling six month period

        The following table sets forth the Company's current hedge position:

Time Period	Notional Quantities	Price
May 2004	500 Bbls of crude oil production per day	Floor of $22.00
June 2004	4,500 MMbtu of production per day 800 Bbls of crude production per day	Floor of $4.25 Floor of $22.00
July 2004	2,000 MMbtu of production per day 4,500 MMbtu of production per day 500 Bbls of crude oil production per day	Floor of $4.00 Floor of $4.25 Floor of $22.00
August 2004	7,100 MMbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $24.00
September 2004	7,100 MMbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $24.00
October 2004	7,100 MMbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $24.00
November 2004	7,100 MMbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.25 Floor of $24.00
December 2004	7,100 MMbtu of production per day 400 Bbls of crude oil production per day	Floor of $4.50 Floor of $25.00

Note 8. Contingencies—Litigation

        In 2001, Abraxas and Abraxas Wamsutter L.P. were named as defendants in a lawsuit filed in U.S. District Court in the District of Wyoming. The claim asserts breach of contract, fraud and negligent misrepresentation by Abraxas and Abraxas Wamsutter, L.P. related to the responsibility for year 2000 ad valorem taxes on crude oil and natural gas properties sold by Abraxas and Abraxas Wamsutter, L.P. In February 2002, a summary judgment was granted to the plaintiff in this matter and a final judgment in the amount of $1.3 million was entered. Abraxas has filed an appeal. We believe these charges are without merit. We have established a reserve in the amount of $845,000, which represents our estimated share of the judgment.

        In 2003, Abraxas and Leam Drilling Systems each filed suit against the other relating to certain drilling services that Leam contracted to provide Abraxas. Abraxas believes that the services were provided in a grossly negligent manner and that Leam committed fraud. Leam has asserted that Abraxas failed to pay approximately $639,000 for services rendered. The case is pending in Bexar County, Texas.

        Additionally, from time to time, we are involved in litigation relating to claims arising out of its operations in the normal course of business. At March 31, 2004, we were not engaged in any legal

F-58

proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our operations.

Note 9. Comprehensive Income

        Comprehensive income includes net income (losses) and certain items recorded directly to Stockholders' Deficit and classified as Other Comprehensive Income.

        The following table illustrates the calculation of comprehensive income (loss) for the quarters ended March 31, 2004 and 2003:

			Three Months Ended March 31
			2004			2003
Net Income (loss)			$	(5,557	)	$	62,702
Other Comprehensive income:
	Hedging derivatives (net of tax)
		Change in fair market value of outstanding hedge positions		—			102
	Foreign currency translation adjustment			(491	)		5,427
Other comprehensive income (loss)				(491	)		5,529
Comprehensive income (loss)			$	(6,048	)	$	68,231

Note 10. Business Segments

        Business segment information about our first quarter operations in different geographic areas is as follows:

		Three Months Ended March 31, 2004
		U.S.		Canada		Total
		(In thousands)
Revenues		$	7,783	$	2,949	$	10,732
Operating profit		$	3,712	$	407	$	4,119
General corporate							(3,136	)
Interest expense, financing cost and amortization of deferred financing fees							(6,529	)
Other							(11	)
Loss before income taxes						$	(5,557	)
Identifiable assets at March 31, 2004		$	82,068	$	37,741	$	119,809
Corporate assets							6,232
	Total assets					$	126,041

F-59

	Three Months Ended March 31, 2003
	U.S.		Canada		Total
	(In thousands)
Revenues	$	8,799	$	4,312	$	13,111
Operating profit	$	4,736	$	2,243	$	6,979
General corporate						(1,333	)
Interest expense and amortization of deferred financing fees						(9,132	)
Gain on sale of foreign subsidiary						66,960
Cumulative effect of accounting change						(395	)
Income before income taxes					$	63,079

Note 11. Recent Accounting Pronouncements

        In March 2004, the Emerging Issues Task Force ("EITF") reached a consensus that mineral rights, as defined in EITF Issue No. 04-2, "Whether Mineral Rights Are Tangible or Intangible Assets," are tangible assets and that they should be removed as examples of intangible assets in SFAS No. 141, "Business Combinations" and No. 142, "Goodwill and Other Intangible Assets". The FASB has recently ratified this consensus and directed the FASB staff to amend SFAS Nos. 141 and 142 through the issuance of FASB Staff Position FAS Nos. 141-1 and 142-1. Historically, the Company has included the costs of such mineral rights as tangible assets, which is consistent with the EITF's consensus. As such, EITF 04-02 has not affected the Company's consolidated financial statements.

Note 12. Accounting Change

        The Company adopted SFAS 143 effective January 1, 2003. For the quarter ended March 31, 2003 the Company recorded an additional liability of $711,732, and a charge of $395,341 for the cumulative effect of the change in accounting principal. There was no impact in the first quarter of 2004.

F-60

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

        The following table sets forth the expenses (other than underwriting discounts and commissions) in connection with the offering described in this Registration Statement, all of which shall be paid by us. All of such amounts (except the SEC Registration Fee) are estimated.

SEC Registration Fee	$	5,995
Federal Taxes	$	—
State and Local Taxes	$	—
Trustee and Transfer Agent Fees	$	10,000
Printing and Mailing Costs	$	26,000
Legal Fees and Expenses	$	335,000
Accounting Fees and Expenses	$	125,000
Miscellaneous	$	15,000

Item 14. Indemnification of Directors and Officers

        Abraxas' Articles of Incorporation contain a provision that eliminates the personal monetary liability of directors and officers to Abraxas and its stockholders for a breach of fiduciary duties to the extent currently allowed under the Nevada General Corporation Law (the "Nevada Statute"). If a director or officer of Abraxas were to breach his fiduciary duties, neither Abraxas nor its stockholders could recover monetary damages, and the only course of action available to Abraxas' stockholders would be equitable remedies, such as an action to enjoin or rescind a transaction involving a breach of fiduciary duty. To the extent certain claims against directors or officers are limited to equitable remedies, this provision of Abraxas' Articles of Incorporation may reduce the likelihood of derivative litigation and may discourage stockholders or management from initiating litigation against directors or officers for breach of their duty of care. Additionally, equitable remedies may not be effective in many situations. If a stockholder's only remedy is to enjoin the completion of the Board of Director's action, this remedy would be ineffective if the stockholder did not become aware of a transaction or event until after it had been completed. In such a situation, it is possible that the stockholders and Abraxas would have no effective remedy against the directors or officers.

        Liability for monetary damages has not been eliminated for acts or omissions which involve intentional misconduct, fraud or a knowing violation of law or payment of an improper dividend in violation of section 78.300 of the Nevada Statute. The limitation of liability also does not eliminate or limit director liability arising in connection with causes of action brought under the Federal securities laws.

        The Nevada Statute permits a corporation to indemnify certain persons, including officers and directors, who are (or are threatened to be made) parties against all expenses (including attorneys' fees) actually and reasonably incurred by, or imposed upon, him in connection with the defense by reason of his being or having been a director or officer if he acted in good faith and in a manner which he reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful, except where he has been adjudged by a court of competent jurisdiction (and after exhaustion of all appeals) to be liable for gross negligence or willful misconduct in the performance of his duty. The Bylaws of Abraxas provide indemnification to the same extent allowed pursuant to the foregoing provisions of the Nevada Statute.

II-1

        Nevada corporations also are authorized to obtain insurance to protect officers and directors from certain liabilities, including liabilities against which the corporation cannot indemnify its directors and officers. Alberta Business Corporation Act corporations are permitted to obtain such insurance also, except for liability relating to the failure to act honestly and in good faith with a view to the best interests of the corporation. Abraxas currently has a directors' and officers' liability insurance policy in effect providing $3.0 million in coverage and an additional $1.0 million in coverage for certain employment related claims.

        Abraxas has entered into indemnity agreements with each of its directors and officers. These agreements provide for indemnification to the extent permitted by the Nevada Statute.

Item 15. Recent Sales of Unregistered Securities

        Since January 2000, we have issued and sold the following unregistered securities:

        (a)   On August 1, 2000, Abraxas issued a warrant to purchase 750,000 shares at an exercise price of $3.50 per share. The warrant was issued pursuant to Section 4(2) of the Securities Act of 1933, as amended.

        (b)   On January 23, 2003, Abraxas issued $109,523,000 principal amount of 11¹/2% Secured Notes due 2007, Series A and 5,633,291 shares of Abraxas common stock. These securities were issued pursuant to Section 4(2) of the Securities Act of 1933, as amended.

        (c)   On July 29, 2003, Abraxas issued 106,977 shares of Abraxas common stock in connection with the acquisition of Wind River. These securities were issued pursuant to Section 4(2) of the Securities Act of 1933, as amended.

        (d)   On April 20, 2004, Abraxas issued a total of 58,808 shares of Abraxas common stock as part of certain bonuses paid to officers. These securities were issued pursuant to Section 4(2) of the Securities Act of 1933, as amended.

Item 16. Exhibits and Financial Statement Schedules

3.1	Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to Abraxas' Registration Statement on Form S-4, No. 33-36565).
3.2	Articles of Amendment to the Articles of Incorporation of Abraxas dated October 22, 1990 (Filed as Exhibit 3.3 to Abraxas' Registration Statement on Form S-4, No. 33-36565).
3.3	Articles of Amendment to the Articles of Incorporation of Abraxas dated December 18, 1990 (Filed as Exhibit 3.4 to Abraxas' Registration Statement on Form S-4, No. 33-36565).
3.4	Articles of Amendment to the Articles of Incorporation of Abraxas dated June 8, 1995 (Filed as Exhibit 3.4 to the Abraxas' Registration Statement on Form S-3, No. 333-00398 (the "1995 S-3 Registration Statement")).
3.5	Articles of Amendment to the Articles of Incorporation of Abraxas dated as of August 12, 2000 (Filed as Exhibit 3.5 to Abraxas' Annual Report on Form 10-K filed April 2, 2001).
3.6	Articles of Incorporation of Sandia Oil & Gas (Filed as Exhibit 3.7 to Abraxas and Canadian Abraxas' Registration Statement on Form S-4, No. 333-79349 (the "1999 Exchange Offer Registration Statement")).
*3.7	Articles of Incorporation of Sandia Operating Corp.
3.8	Articles of Incorporation of Wamsutter Holdings, Inc. (Filed as Exhibit 3.7 to the Abraxas, Sandia Oil & Gas Corporation and New Cache Petroleums Ltd. Registration Statement on Form S-1, No. 333-95281 (the "2000 S-1 Registration Statement")).

II-2

*3.9	Articles of Incorporation of Western Associated Energy Corporation.
*3.10	Articles of Incorporation of Eastside Coal Company, Inc.
*3.11	Certificate of Incorporation of Grey Wolf Exploration Inc.
3.12	Amended and Restated Bylaws of Abraxas (Filed as Exhibit 3.6 to Abraxas' Annual Report on Form 10-K filed April 5, 2002).
*3.13	Amended and Restated By-Laws of Sandia Oil & Gas Corporation.
*3.14	By-Laws of Sandia Operating Corp.
3.15	By-Laws of Wamsutter Holdings, Inc. (Filed as Exhibit 3.11 to the 2000 S-1 Registration Statement).
*3.16	By-Laws of Western Associated Energy Corporation.
*3.17	By-Laws of Eastside Coal Company, Inc.
*3.18	By-Laws of Grey Wolf Exploration Inc.
4.1	Specimen Common Stock Certificate of Abraxas (Filed as Exhibit 4.1 to Abraxas' Registration Statement on Form S-4, No. 33-36565).
4.2	Specimen Preferred Stock Certificate of Abraxas (Filed as Exhibit 4.2 to Abraxas' Annual Report on Form 10-K filed on March 31, 1995).
4.3	Rights Agreement dated as of December 6, 1994 between Abraxas and First Union National Bank of North Carolina ("FUNB") (Filed as Exhibit 4.1 to Abraxas' Registration Statement on Form 8-A filed on December 6, 1994).
4.4	Amendment to Rights Agreement dated as of July 14, 1997 by and between Abraxas and American Stock Transfer and Trust Company (Filed as Exhibit 1 to Amendment No. 1 to Abraxas' Registration Statement on Form 8-A filed on August 20, 1997).
4.5	Second Amendment to Rights Agreement as of May 22, 1998, by and between Abraxas and American Stock Transfer & Trust Company (Filed as Exhibit 1 to Amendment No. 2 to Abraxas' Registration Statement on Form 8-A filed on August 24, 1998).
4.6	Indenture dated as of January 23, 2003, among Abraxas, as Issuer, the Subsidiary Guarantors party thereto, and U.S. Bank, N.A., as Trustee, relating to Abraxas' 111/2% Secured Notes due 2007 (the "Indenture") (Filed as Exhibit 4.1 to Abraxas' Current Report on Form 8-K filed February 6, 2003).
4.7	Registration Rights Agreement dated as of January 23, 2003 by and among Abraxas, Sandia Oil & Gas Corporation, Sandia Operating Corp., Wamsutter Holdings, Inc., Grey Wolf Exploration Inc. and Jefferies & Company,  Inc. (Filed as Exhibit 10.4 to Abraxas' Current Report on Form 8-K filed February 6, 2003).
4.8	Form of 111/2% Secured Note due 2007 (Filed as Exhibit A to the Indenture).
*5.1	Opinion of Cox & Smith Incorporated.
*5.2	Opinion of Osler, Hoskin & Harcourt LLP.
+10.1	Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan, as amended and restated (Filed as Exhibit 10.7 to Abraxas' Annual Report on Form 10-K filed April 14, 1993).
+10.2	Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan, as amended and restated (Filed as Exhibit 10.8 to Abraxas' Annual Report on Form 10-K filed April 14, 1993).

II-3

+10.3	Abraxas Petroleum Corporation 1993 Key Contributor Stock Option Plan (Filed as Exhibit 10.9 to Abraxas' Annual Report on Form 10-K filed April 14, 1993).
+10.4	Abraxas Petroleum Corporation 401(k) Profit Sharing Plan (Filed as Exhibit 10.4 to Abraxas' Registration Statement on Form S-4, No. 333-18673 (the "1996 Exchange Offer Registration Statement)).
+10.5	Abraxas Petroleum Corporation Director Stock Option Plan (Filed as Exhibit 10.5 to 1996 Exchange Offer Registration Statement).
+10.6	Abraxas Petroleum Corporation Restricted Share Plan for Directors (Filed as Exhibit 10.20 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994).
+10.7	Abraxas Petroleum Corporation 1994 Long Term Incentive Plan (Filed as Exhibit 10.21 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994).
+10.8	Abraxas Petroleum Corporation Incentive Performance Bonus Plan (Filed as Exhibit 10.24 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994).
10.9	Common Stock Purchase Warrant dated August 11, 1993 between Abraxas and Associated Energy Managers, Inc. (Filed as Exhibit 10.37 to Abraxas' and Canadian Abraxas' Registration Statement on Form S-1, Registration No. 33-66446).
10.10	Form of Indemnity Agreement between Abraxas and each of its directors and officers (Filed as Exhibit 10.30 to Abraxas' and Canadian Abraxas' Registration Statement on Form S-1, Registration No. 33-66446).
+10.11	Employment Agreement between Abraxas and Robert L. G. Watson (Filed as Exhibit 10.19 to the 2000 S-1 Registration Statement).
+10.12	Employment Agreement between Abraxas and Chris E. Williford (Filed as Exhibit 10.20 to the 2000 S-1 Registration Statement).
+10.13	Employment Agreement between Abraxas and Stephen T. Wendel (Filed as Exhibit 10.26 to the 1995 S-3 Registration Statement).
+10.14	Employment Agreement between Abraxas and Robert W. Carington, Jr (Filed as Exhibit 10.22 to the 2000 S-1 Registration Statement).
10.15	Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and Basil Street Company (Filed as Exhibit 10.15 to Abraxas Annual Report on Form 10-K filed on April 2, 2001).
10.16	Common Stock Purchase Warrant dated September 1, 2000 between Jessup & Lamont Holdings (Filed as Exhibit 10.16 to Abraxas Annual Report on Form 10-K filed on April 2, 2001).
10.17	Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and TNC, Inc. (Filed as Exhibit 10.17 to Abraxas Annual Report on Form 10-K filed on April 2, 2001).
10.18	Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and Charles K. Butler (Filed as Exhibit 10.17 to Abraxas Annual Report on Form 10-K filed on April 2, 2001).
10.19	Agreement of Limited Partnership of Abraxas Wamsutter L.P. dated as of November 12, 1998 by and between Wamsutter Holdings, Inc. and TIFD III-X Inc. (Filed as Exhibit 10.2 to Abraxas' Current Report on Form 8-K filed November 30, 1998).
10.20	Farmout Agreement between Grey Wolf Exploration Limited and PrimeWest Energy, Inc. (Previously filed as Exhibit 10.2 to Abraxas' Current Report on Form 8-K/A filed on December 9, 2002).

II-4

10.21	Farmout Agreement between Grey Wolf Exploration Limited and PrimeWest Energy, Inc. (Previously filed as Exhibit 10.3 to Abraxas' Current Report on Form 8-K/A filed on December 9, 2002).
10.22	Amendment No. 2 dated as of February 23, 2004 to Loan And Security Agreement, by and among Abraxas, as Borrower, the Subsidiaries of Abraxas that are Signatories thereto, as Guarantors, the Lenders that are Signatories thereto, as Lenders, and Wells Fargo Foothill, formerly known as Foothill Capital Corporation, as the Arranger and Administrative Agent (Filed as Exhibit 10.1 to Abraxas' Current Report on Form 8-K filed February 26, 2004).
10.23	Intercreditor and Subordination Agreement dated as of January 23, 2003, by and among Foothill, in its capacity as agent (in such capacity, together with any successor in such capacity, the "Senior Agent") for the lenders who are from time to time parties to the Loan Agreement (the "Senior Lenders"), U.S. Bank, N.A., a national banking association in its capacity as trustee (in such capacity, together with any successor in such capacity, the "Trustee") for the holders of the 111/2% Secured Notes Due 2007, issued under the Indenture. (Filed as Exhibit 10.6 to Abraxas' Current Report on Form 8-K filed February 6, 2003).
16.1	Letter addressing change in certifying accountant (Filed on Abraxas' Form 8-K filed on August 22, 2001).
*21.1	Subsidiaries of Abraxas.
**23.1	Consent of BDO Seidman, LLP
**23.2	Consent of Deloitte & Touche LLP
**23.3	Consent of DeGolyer and MacNaughton.
*23.4	Consent of McDaniel & Associates Consultants, Ltd.
*23.5	Consent of Cox & Smith Incorporated (Included in Exhibit 5.1).
*23.6	Consent of Osler, Hoskin & Harcourt LLP.
*24.1	Power of Attorney of Craig S. Bartlett, Jr.
*24.2	Power of Attorney of Franklin Burke.
*24.3	Power of Attorney of Frederick M. Pevow, Jr.
*24.4	Power of Attorney of James C. Phelps.
*24.5	Power of Attorney of Joseph A. Wagda.
**24.6	Power of Attorney of Harold D. Carter
**24.7	Power of Attorney of Barry J. Galt
**24.8	Power of Attorney of Dennis E. Logue
*25.1	Statement of eligibility of trustee for the Indenture.
27.1	Financial Data Schedule (Omitted pursuant to Regulation S-K, Item 601(c)).

*

Previously filed.

**

Filed herewith.

+

Management Compensatory Plan or Agreement.

II-5

Item 17. Undertakings

        A.    The undersigned registrants hereby undertake:

        (1)   To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

          (i)  To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

         (ii)  To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement.

        (iii)  To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

        (2)   That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

        (3)   To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

        B.    Each of the undersigned registrants hereby undertakes that, for purposes of determining any liability under the Securities Act of 1933, each filing of the registrant's annual report pursuant to Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

        C.    Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of each of the registrants pursuant to the foregoing provisions, or otherwise, the registrants have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrants of expenses incurred or paid by a director, officer or controlling person in the successful defense of any action, suit or proceedings) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrants will, unless in the opinion of their counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by either of them is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

II-6

SIGNATURES

        Pursuant to the requirements of the Securities Act, the undersigned registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of San Antonio, Texas, on July 30, 2004.

ABRAXAS PETROLEUM CORPORATION
By:	/s/  ROBERT L. G. WATSON Chairman of the Board, Chief Executive Officer and President

II-7

        Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities and on the date indicated.

Signature	Name and Title	Date
/s/  ROBERT L.G. WATSON Robert L.G. Watson	Chairman of the Board, President, Chief Executive Officer (Principal Executive Officer) and Director of Abraxas	July 30, 2004
/s/  CHRIS E. WILLIFORD Chris E. Williford	Executive Vice President, Treasurer, and Chief Financial Officer (Principal Financial and Accounting Officer) of Abraxas	July 30, 2004
/s/  ROBERT W. CARINGTON Robert W. Carington, Jr.	Executive Vice President of Abraxas	July 30, 2004
* Craig S. Bartlett, Jr.	Director of Abraxas	July 30, 2004
* Franklin A. Burke	Director of Abraxas	July 30, 2004
* Harold D. Carter	Director of Abraxas	July 30, 2004
Ralph F. Cox	Director of Abraxas	July 30, 2004
* Barry J. Galt	Director of Abraxas	July 30, 2004
* Dennis E. Logue	Director of Abraxas	July 30, 2004
* James C. Phelps	Director of Abraxas	July 30, 2004
* Joseph A. Wagda	Director of Abraxas	July 30, 2004

*By:
/s/  CHRIS E. WILLIFORD Chris E. Williford
Attorney-in-fact

II-8

SIGNATURES

        Pursuant to the requirements of the Securities Act, the undersigned registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of San Antonio, Texas, on July 30, 2004.

SANDIA OIL & GAS CORPORATION
By:	/s/  ROBERT L.G. WATSON President

II-9

        Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities and on the date indicated.

Signature	Name and Title	Date
/s/  ROBERT L.G. WATSON Robert L.G. Watson	President (Principal Executive Officer) and Director of Sandia Oil & Gas Corporation	July 30, 2004
/s/  CHRIS E. WILLIFORD Chris E. Williford	Vice President (Principal Financial and Accounting Officer) and Director of Sandia Oil & Gas Corporation	July 30, 2004
/s/  ROBERT W. CARINGTON Robert W. Carington, Jr.	Vice President and Director of Sandia Oil & Gas Corporation	July 30, 2004

II-10

SIGNATURES

        Pursuant to the requirements of the Securities Act, the undersigned registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of San Antonio, Texas, on July 30, 2004.

SANDIA OPERATING CORP.
By:	/s/  ROBERT L.G. WATSON President

II-11

        Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities and on the date indicated.

Signature	Name and Title	Date
/s/  ROBERT L.G. WATSON Robert L.G. Watson	President (Principal Executive Officer) and Director of Sandia Operating Corp.	July 30, 2004
/s/  CHRIS E. WILLIFORD Chris E. Williford	Vice President (Principal Financial and Accounting Officer) and Director of Sandia Operating Corp.	July 30, 2004
/s/  ROBERT W. CARINGTON Robert W. Carington, Jr.	Vice President and Director of Sandia Operating Corp.	July 30, 2004

II-12

SIGNATURES

        Pursuant to the requirements of the Securities Act, the undersigned registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of San Antonio, Texas, on July 30, 2004.

WAMSUTTER HOLDINGS, INC.
By:	/s/  ROBERT L.G. WATSON President

II-13

        Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities and on the date indicated.

Signature	Name and Title	Date
/s/  ROBERT L.G. WATSON Robert L.G. Watson	President (Principal Executive Officer) and Director of Wamsutter	July 30, 2004
/s/  CHRIS E. WILLIFORD Chris E. Williford	Vice President (Principal Financial and Accounting Officer) and Director of Wamsutter	July 30, 2004
/s/  ROBERT W. CARINGTON Robert W. Carington, Jr.	Vice President and Director of Wamsutter	July 30, 2004

II-14

SIGNATURES

        Pursuant to the requirements of the Securities Act, the undersigned registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of San Antonio, Texas, on July 30, 2004

WESTERN ASSOCIATED ENERGY CORPORATION
By:	/s/  ROBERT L.G. WATSON President

II-15

        Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities and on the date indicated.

Signature	Name and Title	Date
/s/  ROBERT L.G. WATSON Robert L.G. Watson	President (Principal Executive Officer) and Director of Western Associated Energy Corporation	July 30, 2004
/s/  CHRIS E. WILLIFORD Chris E. Williford	Vice President (Principal Accounting Officer) and Director of Western Associated Energy Corporation	July 30, 2004
/s/  ROBERT W. CARINGTON Robert W. Carington, Jr.	Vice President and Director of Western Associated Energy Corporation	July 30, 2004

II-16

SIGNATURES

        Pursuant to the requirements of the Securities Act, the undersigned registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of San Antonio, Texas, on July 30, 2004

EASTSIDE COAL COMPANY, INC.
By:	/s/  ROBERT L.G. WATSON President

II-17

        Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities and on the date indicated.

Signature	Name and Title	Date
/s/  ROBERT L.G. WATSON Robert L.G. Watson	President (Principal Executive Officer) and Director of Eastside Coal Company, Inc.	July 30, 2004
/s/  CHRIS E. WILLIFORD Chris E. Williford	Vice President (Principal Accounting Officer) and Director of Eastside Coal Company, Inc.	July 30, 2004
/s/  ROBERT W. CARINGTON Robert W. Carington, Jr.	Vice President and Director of Eastside Coal Company, Inc.	July 30, 2004

II-18

SIGNATURES

        Pursuant to the requirements of the Securities Act, the undersigned registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of San Antonio, Texas, on July 30, 2004.

GREY WOLF EXPLORATION INC.
By:	/s/  ROBERT L.G. WATSON President

II-19

        Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities and on the date indicated.

Signature	Name and Title	Date
/s/  ROBERT L.G. WATSON Robert L.G. Watson	President (Principal Executive Officer) and Director of Grey Wolf Exploration Inc.	July 30, 2004
/s/  CHRIS E. WILLIFORD Chris E. Williford	Vice President (Principal Financial and Accounting Officer) of Grey Wolf Exploration Inc.	July 30, 2004

II-20

EXHIBIT INDEX

Exhibit Number:
23.1	Consent of BDO Seidman, LLP
23.2	Consent of Deloitte & Touche LLP
23.3	Consent of DeGolyer & MacNaughton
24.6	Power of Attorney of Harold D. Carter
24.7	Power of Attorney of Barry J. Galt
24.8	Power of Attorney of Dennis E. Logue